Text

Forwards Info Which Identifies Development Schedule & Preparation/Input Responsibilities for Plant,Units 1 & 2 SALP Covering Period 930620-941105
	ML20134C704
Person / Time
Site:	Salem
Issue date:	10/04/1994
From:	Jason White; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:	; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
Shared Package
ML20134C519	List: ML20134C503; ML20134C579; ML20134C588; ML20134C595; ML20134C609; ML20134C616; ML20134C641; ML20134C644; ML20134C650; ML20134C653; ML20134C658; ML20134C704; ML20134C773; ML20134C800; ML20134C814; ML20134C829; ML20134C839; ML20134C853;
References
	FOIA-96-351 NUDOCS 9702040012
	Download: ML20134C704 (530)
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[% S NUCLEAR REGULATORY COMMISSION E REGION I t3 O KING OF PR SS A, NP S LVAN A 19406-1415 October 4, 1994 MEMORANDUM 70: Distribution FROM: John R. White, Chief '

Project Section 2A Division of Reactor P ojec

SUBJECT:

SALEM SALP MILESTONES The following identifies the development schedule and preparation / input i

responsibilities for the Salem Unit I and 2 SALP. The period of this report (50-272[311]/93-99) is June 20, 1993 through November 5, 1994. The supplement dated June 30, 1993, to Regional Instruction 1440.1, Revision 4, pertains and provides the necessary guidance for this SALP effort.

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Milestone DB2 J

Bulletized Feeders to Functional October 21, 1994 Area Coordinators and Responsible SALP Board Members (Action:

Designated Feeder Writers)

. Functional Area and Safety November 4, 1994 Assessment / Quality Verification (SALP End Date:

Bullets to DRP Section Chief (White) November 5,1994)

Action: Cooper, Wiggins, Stolz,

Hehl)

Supporting Data Package Assembled November 4, 1994 and to SC (Action: Barber) .

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Briefing Packages Distributed to November 11, 1994 Board Members (Action: White)

SALP Board Meeting November 17, 1994 (Action: Cooper, Wiggins, Stolz, Hehl)

Develop Functional Area Writeups November 23, 1994 (Cooper, Hehl, Wiggins, and Stolz) and Cover Letter (Cooper), and J

Distribute Among Board Membership (Action: Cooper)

Contact:

G. S. Barber, DRP 610-337-5232 9702040012 970116 "

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2 Resolve Comments, Develop Final December 1, 1994 Writeups and Cover Letter, Distribute to DRP-SC/PE l (White / Barber) (Action: Cooper, I

Stolz, Hehl, Wiggins)

Assemble Final Report; Provide to December 5, 1994 Chair and Members (Action:

White / Barber)

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Provide SALP to RA; Brief RA and DRA December 8, 1994 (Action: Cooper) i Issue SALP report; Inform Licensee December 14, 1994 j Management (Action: Cooper / Martin)

SALP Management Meeting with December 28, 1994 .

Licensee (Action: Cooper, et al) i The designate Functional Area Managers, Coordinators, and support staff are as follows: ,

Functional Area Coordinators Feeder Innut Assianments OPERATIONS DRP/ Barber DRP/Marschall l R. Cooper, DRP NRR/01shan/ Stone Chairman DRS/Calvert/Moy MAINTENANCE NRR/01shan DRP/Marschall J. Stolz, NRR DRS/Calvert/Moy NRR/ Stone ENGINEERING DRS/Calvert DRP/Marschall J. Wiggins, DRS NRR/01shan/ Stone

' DRS/Moy PLANT SUPPORT DRSS/Keinig NRR/ Stone /01shan W. Hehl, DRSS DRP/Marschall i

DRS/Moy/Calvert i DRSS/Peluso,Noggle, Keinig, McCabe FORMAT:

Writers / reviewers are reminded to keep writeups brief, concise, and in the format described in the supplement to Regional Instruction 1440.1, Rev. 4.

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Distribution RI Division Directors Ri Deputy Division Directors J. Stolz, NRR J. Stone, NRR L. 01shan, NRR RI Branch Chiefs ,

RI Section Chiefs C. Marschall, DRP J. Calvert, DRS D. Moy, DRS L. Peluso, DRSS R. Keinig, DRSS E. McCabe, DRSS J. Noggle, DRSS S. Barber, DRP J. White, DRP i

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SALEK NDCLEAR GENERATING #fAYICK

SALP CTCrJ JJ RERDRCENBET 30nrarmar i

NUMBER / SEVERITY OF VIOLATIONS 4

Functional Areas Level III Level IV Plant Operations 2 3 Maintenance / Surveillance 1 3

Engineering / Technical Support 2 3

Plant Support 2 TOTALS 5 11 j

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o SALEN NUCLEAR GENERATING STATION BALP CYCLE 13 ENTORCEMENT DETAILB REPORT ISSUED SEVERITY M DESCRIPTION 1

94-18 I/TS Inadequate 125V battery acceptance 9/7/94 IV i criteria.

94-16 6/30/94 IV P/s Access Control of vehicles.

No. 23 auxiliary feedwater pump

94-14 9/19/94 IV M/S maintenance.

Failure to establish measures for 94-13 10/5/94 IV E/TS configuration control of certain parts and j

components. (PORVs AIT) 1 94-13 10/5/94 IV PS Specified information regarding the event

' description was not communicated to the NRC i

within 60 minutes.

OPS Inadequate training, guidance and i 94-13 10/5/94 III

" procedures were provided to the operators j

to cope with plant transients resulting from grass intrusion events. (CP -

$150,000)

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i 94-13 10/5/94 III OPS Shift management failure to maintain i control room command functions. (CP -

$50,000) 94-13 10/5/94 III E Failure to complete safety evaluation and update FSAR for steam generator PORV I modifications. (CP - $150,000) 94-13 10/5/94 III E Failure to identify and correct cause of

' spurious high steam flow signals resulting in an unnecessary safety injection. (CP -

$150,000) l 94-07 6/29/94 IV E/TS No written safety evaluation,1A-460V vital bus transformer.

94-06 4/26/94 IV OPS Failure to comply with TSAS regarding PORVs.

94-01 3/16/94 IV OPS Changed Modes from 4 to 3 contrary to i Technical specifications with an inoperable

' no. 23 auxiliary feedwater pump.

93-82 11/30/93 IV M/S Failure to follow station procedure for measuring battery cell voltages.

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e 93-27 2/10/94 IV M/S Inadequate control of troubleshooting and

' corrective actions regarding RHR check I valve leakage.

4 93-23-02 1/10/94 IV M/S Failure to perform adequate diesel a generator surveillances.

J 93-23-01 3/9/94 III M/S Failure to follow maintenance procedures.

(Work control) (CP - $50,000) 93-21 OPS Failure to initiate a timely shutdown of 11/3/93 IV

-Unit 1 following failed surveillance test.

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i BALEE EALPy 6/20/93=I1/0L <

4 REGINEERING AND TRCE 80PPORT BTRENGIW3s i

Current engineering design work appears good. (NRC Performance Assessment of sales).

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Good engineering coordination with Westinghouse during failed fuel inspection at salem unit 1. Also, strict procedure compliance, good attention to detail and radiological control practices. (In 94-01)

Good oversight and analysis of speed oscillation in unit 1 AFW pump during l startup. (IR 94-01)

subsequent to initial questionable safety perspective with regard to the 2C EDG CAD liner failure, the licensee conservatively declared the 15 EDG inoperable. (IR 93-27)

After shatting unit 2 down for the 2C CAD liner failure, the licensee initiated a significant Event Response Team. (IR 93-27)

The licensee properly completed package no. 6 of a DCP to improve independence and reliability of the sales switchyard. The DCP provided connection between two new off site power sources and the new Unit 1 Circulating Water switchgear. The licenses properly controlled the i switchyard modification and safely completed package no. 6. (In 93-27)

Procedures Upgrade Project (PUP) closed out with 99% procedures upgraded; 4 remaining 1% transferred to Procedures Maintenance Group. Inspectors concluded that PUP had been a good initiative and effective in improving procedure quality. (IR 93-21)

Engineering developed and implemented appropriate corrective actions in response to the April 3, 1993 inadvertent discharge of a carbon dioxide

, fire protection system. The inadvertent discharge, a result of water intrusion into a junction box, did not result from inadequate design. (IR 93-21) h j

Reactor engineering support during unit 2 startups was a notable strength;

- the reactor engineers were extremely knowledgeable of reactor physics, professional in their duties, and in proper control of the startup; good communication and coordination between reactor engineering and operations.

(IR 93-19)

The licensee determined that the service water system did not share the circulation water system vulnerability to debris induced trips. (IR 93-19)

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Updated URI on EDG fuel injection stude; operability and 10 CFR 21 reportability evaluations were appropriate. (IR 93-19)

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Engineering properly and conservatively evaluated an emergency diesel b.

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! generator cooling water flow setpoint error. (Closed URI) (IR 93-20) l I VEAKNESBRBs 8 Engineering has not demonstrated the ability to proactively seek out and l

correct system and component deficiencies (e.g., circulating water system,

- rod position indication, excessive cooldown) (NRC Performance Assessment I of Sales).

Engineering work priorities not driven by the needs of the plant. l j (NRC Performance Assessment of Sales).

8 NOV for sustained unit 2 operation at approximately 102.5% power. This resulted from inaccurate feedwater flow instrumentation (indicated flow j lower than actual) . Affected setpoints steam Flow SI, OTdeltaT, OTdeltaF, l NI high flux trip. Although the setpoints were non-conservative, j subsequent engineering evaluation concluded that operating at up to 104.5%

power did not invalidata any of the conclusions in the accident analysis.

, Engineering had the opportunity to identify the degraded feedwater flow I

j instrument accuracy at the time it initially occurred, but did not due to

lack of rigorous root cause analysis. (IR 94-24) l TSD (IR 94-24) l

Repetitious problems with main feedwater pump control Oil Power Unit j filters presented several challenges to operators. (IR 94-19) l

' The licensee continued to rely on short term corrective actions in I response to a long history of problems with the RDG sir start systems.

(IR 94-19) t 5

Marginal control air system performance continued to pose challenges to j

} uneventful Sales operation. (IR 94-19) 1 i

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In response to March 31, 1994, Salem unit 2 Safety Injection relief valve

< 1eakage, the licensee did not perform a detailed root cause analysis, nor I did they perform engineering calculations to evaluate the impact of i j possible SI flow diversion to the Pressuriser Relief Tank. The licensee !

did not perform a thorough operability determination until questioned by j the inspectors. (IR 94-13) l

' The licensee failed to ensure that the specified replacement parts were j

installed in the unit 2 PORVs during the seventh refueling outage (spring i I

i 1993). (IR 94-13)

Low RCS temperature coincident with spurious high steam flow signals l l

j caused the initial Safety Injection actuation on April 7, 1994. On three l l

previous occasions, the licensee had noted the spurious high steam flow I

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signals, caused by pressure waves traveling up and down the steam line following a turbine trip. The licensee did not properly identify and correct the spurious steam flow signals on those previous occasions. (IR 94-13) i

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I generator cooling water flou setpoint error. (Closed URI) (IR 93-20)

VEARNESSE8s

Engineering has not demonstrated the ability to proactively seek out and correct systes and component deficiencies (e.g., circulating water system, rod position indication, excessive cooldown) (NRC Performance Assessment of sales).

Engineering work priorities not driven by the needs of the plant. (NRC Performance Assessment of sales).

NOV for sustained unit 2 operation at approximately 102.5% power. This resultad from inaccurate feedwater flow instrumentation (indicated flow lower than actual) . Affected setpoints steam Flow SI, OTdeltaT, OTdeltaP, NI high flux trip. Although the setpoints were non-conservative, subsequent engineering evaluation concluded that operating at up to 104.5%

power did not invalidate any of the conclusions in the accident analysis.

Engineering had the opportunity to identify the degraded feedwater flow instrument accuracy at the time it initially occurred, but did not due to lack of rigorous root cause analysis. (IR 94-24)

TED (IR 94-24)

Repetitious problems with main feedwater pump control Oil Power Unit filters presented several challenges to operators. (IR 94-19)

The licensee continued to rely on short term corrective actions in response to a long history of problems with the EDO air start systems.

(IR 94-19)

Marginal control air systes performance continued to pose challenges to l uneventful salen operation. (IR 94-19) i f

In response to March 31, 1994, salem unit 2 safety Injection relief valve leakage, the licensee did not perform a detailed root cause analysis, nor

did they parform engineering calculations to evaluate the impact of i possible SI flow diversion to the Pressuriser Relief Tank. The licensee l did not perform a thorough operability determination until questioned by the inspectors. (IR 94-13)

' The licensee failed to ensure that the specified replacement parts were l

installed in the unit 2 PORVs during the seventh refueling outage (spring

{ 1993). (IR 94-13)

Iow RCs temperature coincident with spurious high steam flow signals a caused the initiL1 Safety Injection actuation on April 7, 1994. On three

, previous occasions, the licensee had noted the spurious high steam flow signals, caused by pressure waves traveling up and down the steam line following a turbine trip. The licensee did not properly identify and l

l correct the spurious steam flow signals on those previous occasions. (IR 94-13) l l

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In March 1977, the licensee modified controls for the main steam atmospheric relief valves (us-10s). In performing the modification, the j licensee rendered the valves incapable of responding properly to

! increasing steam pressure and preventing challenges to the main steam code safety valves. As a result, on April 7, 1994, a code safety lifted causing as RCS cooldown and a second safety Injection actuation. To correct MS-10 operation, the licensee restored the circuit to its original

configuration, and adjusted gain and timing circuits. These adjustments l could have been conducted in 1977 to improve valve performance. In

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addition, although aware of the mis-operation of the Ms-10s, the licensee did not take immediate action to correct the identified problem. (IR 94-l 13)

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' In 11 months following issuance of NRC Information Notice 93-37; May 19, j 1993, salem had not completed inspection of Move to identify eyebolts for removal and replacement. The eyebolt material is questionable, and the j eyebolto receive the thrust load during valve closing. The Move inside

containment had not been inspected during the unit 1 outage. None of the identified eyebolts had been replaced with hex head bolts. The inspectors concluded that PSEGG response was not timely. (IR 94-11) )

After a plant trip caused by an EHC power supply failure, inspectors noted l superf!cial troubleshooting of EHC power supply f ailures; in four previous fallures the licensee either reset or replaced the power supply without determining the fundamental root cause of the failure. (IR 94-06) j

sustained operation of salem unit 2 in excess of licensed thermal power is

an unresolved ites. (IR 94-01)

Lack of comprehensive knowledge of governor design hampered resolution of the problems (required NOED). (IR 94-01) i

The licensee initially planned to replace the failed 2C EDG CAD liner within LCO time and remain at power without completing a root cause determination of the liner failure. Discovery of suspected crack j indications in the engine block forced the decision to shut unit 2 down.

(IR 93-27)

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NOV (level III, $50k CP) for failure to control maintenance and

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surveilla,nce activities. Examples included contractors removing spare

came for auxiliary feedwater control valves without proper authorization; workers performing wiring changes in a MOV for cooling supply to the spent fuel pool heat exchanger without proper written guidance, and without i properly documenting the work accomplished; workers engaged in removal of SW piping without a work package at the job site. (IR 93-23)

Degraded voltage protective relays for 4KV buses set non-conservatively; i I

4 an unresolved item. (IR 93-19/19/18) a

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' Failure to establish aggressive quality oversight of the salem facility.

(NRC Perfsrmance Assessment of Sales).

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Effective engineering oversight of vendor designed modifications not always apparent. (NRC Performance Assessment of sales).

Management allowed equipment problems to exist that made opera *, ions difficult for plant operators. The equipment problems in conjunction with the resultant challenges to operators and operator errors prada=inantly caused the transient on 4/7/94. (IR 94-80/80) (AIYp 4/8-2s/94) Raamples include

Automatic rod control system not in service for a month preceding I the event, requiring manual operator action to restore Tave during f 4/7/94 event.

short duration high steam flow signal previously identified on three ;

occasions not properly resolved, caused spurious safety Injection. I i

Automatic controls for the steam generator atmospheric reliefs (N5-10s) were not maintained. As a result of Ms-10s failing to operate, a code safety lifted causing a cooldown of tha solid Rcs, and a ,

second SI on low pressuriser pressure. The MS-10s were known to be 1

deficient since a modification in the late 1970s; modifications were planned but had not been implemented. j

The circulating water system was vulnerable to periodic grass l intrusions. The licensee had documented this vulnerability over a period of several years.

The licensee took appropriate action to address feedwater nossle weld

problems and thermal sleeve erosion. (IR 94-19)

Overall, the program to meet the requirements of 10 CFR 50.59 was considered adequate. Bowever, inspectors were concerned that, in performing 50.59 reviews, engineers did not consider completed modifications not yet reflected in FSAR updates. (IR 94-19) j

The licensee took appropriate in determining the root cause of a fire in october 1993. The fire resulted from grinding, that ignited pipe insulation. corrective actions were appropriate. (IR 94-14) l 0 Analysis of the higher than expected number of reactor trips (174 actual /170 expected for unit 1, 122/120 for unit 2) concluded that the high rate resulted from operation during 1977-1981 for unit 1, and 1981-1986 for unit 2. Since then the units have had significantly reduced trip rate (less than the 10/ year assumed in the design). The licensee response was reasonable and appropriate. (IR 94-14) i

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BALEN BALPJ 6/20/93 - 11/5/94 J

20RCED BEUTDOWEB ,

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R832 RDOT CA03E EVECTIOEAD AREA d

4 September 22, 1994 Component failure Engineering / tech support 3rlef Description The licensee commenced a shutdown of Unit 2 to comply with l

Technical specifications (Ts) after detecting high vibration in the speed I

increaser for the no. 21 centrifugal charging pump. The pump had previously been 4

out of service for scheduled maintenance and the speed increaser repairs could not be accomplished within the Ts allowed outage time.

August 29, 1994 Component failure Maintenance / surveillance I Brief Descripticas Operators comunenced a rapid shutdown from 75% power in response to extensive damage to the condensate suction header pipe supports and

expansion joints.

! June 24, 1994 Design Engineering / technical j support l Brief Description sales management took both units off-line to perform dredging l operations in front of the circulating water intake structures in order to remove grass and river debris buildup.

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February 4, 1994 Design Engineering / technical I support

! Erlef Descriptions operators rapidly reduced power on both units and entered i Mode 2 in response to a massive build-up of sea grass and river ice on the station's circulating water traveling screens. (long-standing problem)

December 3, 1993 Component failure Maintenance / surveillance Erlef Descriptions The maintenance staff discovered that an emergency diesel generator (EDG) cylinder liner flange had broken off from the remainder of the cylinder liner. Based on the potential that the liner indications could be cracks in the engine block, plant management concluded that plant staf f could not 4

complete repairs to the EDG within the remainder of the Technical specification allowed outage time. Plant management ordered operators to conduct an orde.ly

! shutdown of Unit 2.

October 12, 1993 Personnel error Maintenance / surveillance I

. Brief Descriptions Chemistry reported steam generator (SG) blowdown sodium !

concentration of 900 ppb. This was caused when a heater drain pump was not properly flushed prior to being returned to service. operators commenced a power reduction at 1% per minute in accordance with chemistry's recommendation.

Operators stabilized reactor power at 6%. Chemistry determined that, at that i power level, sufficient cleanup of the impurities occurred. Based on the chemistry staf f recommendation, operations determined that a shutdown to hot r

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e shutdown was not required.

August 24, 1993 Component failure Maintenance / surveillance Brief Descriptions The licensee initiated a Technical specification required shutdown of Unit 1 in response to an inoperable 1C battery. The licensee identified a weak battery cell during a quarterly surveillance test. The NRC exercised enforcement discretion based upon evaluation of the licensee's request and associated justification for continuing operations. Based upon this enforcement discretion, the licensee did not complete the unit shutdown.

July 11, 1993 Component failure Maintenance / surveillance Erlef Descriptions The licensee comunenced a Technical specification required shutdown due to an inoperable relay which controls main feedwater isolation for the no.13 and no.14 steam generators. The licensee discovered the f ailed relay during the performance of slave relay testing.

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BALAE NOCIAAR GENERATING STATIDW SALP CYCLE RJ EJCREBEE EVRET REPORT BRENAeT*

UNIT 1 g.- u r by Enc canam Codes **

Functional Area f g Q Q g g Subtotal

1. Plant Operations 1 2 0 0 0 0 3

2. Maintenance 5 7 0 0 1 0 13

3. Eng/ Tech Support 1 4 1 0 1 0 7

4. Plant Support 0 1 0 0 0 0 1 TOTALS 7 14 1 0 2 0 24

LERs reviewed: 93-11 to 93-20; 94-01 to 94-14

- Root Cause Codes:

A. Personnel Error B. Design, Manufacturing or Installation C. Unknown or External Cause D. Procedural Inadequacy E. Component Failure X. Other i/I a

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BALsN NUCLEAR GENERATING SFAYICW BALP CYCLE JJ LICsusas srarr marcar arrArms i REZZ I

&gg_d g3 Egg maMMtFED EDOF CADBX 93-11 3-C River debris caused high differential pressure (d/p) ,

i across circulating water system (CWS) traveling screens. )

j High d/p led to manual and automatic tripping of four of j

+ six CWs pumps, that caused a main turbine trip on low !

d condenser vacuum and in turn caused an automatic t reactor.

4 93-12 3-A An error by a maintenance technician caused a vital bus l f to sense an undervoltage condition that resulted in an j automatic start and blackout loading of the associated emergency diesel generator. !

l 93-13 2-A A maintenance supervisor failed to realize the affect of lifting a lead associated with a relay in the solid

state- protection system (inadequate review of troubleshooting procedure). The lifted lead caused

! components in the feedwater system to fail closed, causing a steam flow /feedflow mismatch coincident with low level in a steam generator. This condition caused ,

i an automatic reactor trip. l j 93-14 3-B The licensee determined the dropout setpoint for vital j bus undervoltage protection might not fully protect J l

certain motors powered by the bus.

93-15 3-B The licensee entered TS 3.0.3 due to inoperability of no. 12 boric acid storage tank (BAST) level indication with no. 11 BAST out of service.

l l 5,3-16 2-A Personnel error associated with maintenance activities 1

' within vital bus switchgear caused automatic starting and blackout loading of two emergency diesel generators.

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93-17 2-A Personnel error and an inadequate test procedure caused !

an infeed breaker to a vital bus to fail to close, resulting in automatic starting and blackout loading of

{ the associated emergency diesel generator.

93-18 3-5 The licensee discovered that Vendor Manual Instructions used to develop test and surveillance procedures for containment spray were inadequate.

1 93-19 4-5 The waste gas system was open for modifications i resulting in the oxygen concentration exceeding the TS limit for more than the Ts allowed time.

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I 93-20 2-5 The licensee discovered inaccuracies in the original scaling methodology used to determine reactor coolant i safety injection accumulator level.

i 94-01 2-5 The licensee intentionally entered TS 3.0.3 to permit l calibrating the analog rod position indicator (ARPI) modules associated with certain control rods, l

i 94-02 1-B operators manually tripped the reactor trip breakers

]j when group demand position indicators for two shutdown Bank groups did not agree.

I f 94-03 2-E Three circuit cards associated with the feedwater

! regulating circuitry for a steam generator failed, f resulting in low water level in the steam generator and subsequent automatic reactor trip.

! 94-04 2-3 See LER 94-01 1

94-05 2-A Methods used during design and installation of the main I turbine electrohydraulic control (EHC) system resulted in minimum margin between the overvoltage protection j setpoints and normal EHC power supply voltage. This condition resulted in a main turbine trip and subsequent j automatic reactor trip.

{ 94-06 2-3 See LER 94-01 l

j 94-07 1-A Following a rapid downpower, initiated in response to l

severe debris fouling of the traveling water screens, j operators improperly monitored reactor power while 2 withdrawing rods to maintain Tave. Reactor power exceeded the low power trip setpoint (25%) and,

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, consequently, the reactor tripped automatically. Two j safety injections occurred in the next forty minutes, i.

l 94-08 2-A The licensee discovered that a quarterly channel

] functional test of posit',tn indication for the power

! operated relief valves had been performed late on i several occasions.

I j 94-09 3-E An internal ground fault on one of the main turbine j potential transformers caused a main turbine trip and j subsequent automatic reactor trip.

94-10 2-3 see LER 94-01 94-11 3-5 A lightning strike caused all operating circulating 1 water (cW) pumps to trip, requiring the operators to manually trip the reactor in anticipation of a main turbine trip on low vacuum. A time delay in the cw pump protective circuitry had not been installed during the recent switchyard upgrade. The relay would have

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94-12 2-B see LER 94-01 1

94-13 1-B The licensee discovered that a design change package had eliminated the temporary source of power for

$ instrumentation necessary to perform automatic containment isolation during pressure relief evolutions 94-14 2-B See LER 94-01 i

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BALEE EUCLEAR GENERATING BTATIOW

, BALP CYCLE 13 LICENBEE EYRET REPORT SUREART*

UNIT 2 a

v. u- by rac cause coden**

Functional Ares & R G Q g g Subtotal

1. Plant operations 2 1 0 0 0 1 4

2. Maintenance 2 4 0 1 0 0 7

.I 3. Eng/ Tech support 0 4 0 0 1 0 5

, 4. Plant Support 1 0 0 0 0 1 2 TOTALS 5 9 0 1 1 2 18 i

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LERs reviewed: 93-07 to 93-14; 94-01 to 94-10 l

- Root Cause Codes l A. Personnel Error B. Design, Manufacturing or Installation l C. Unknown or External Cause i D. Procedural Inadequacy

{ E. Component Failure X. Other t

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ALEN #pCLEAR GNERATING #fAFION BALF CTCLE 13 U W F REPQaf D3fArgg arIr 2 inER_f IEMIEE REFGETED RODf CAD 88 93-07 3-5 A degraded signal in the rod control system caused all rode in a control bank group to drop into the core.

operators manually tripped the reactor in response.

93-08 3-B The licensee postulated a single failure concern l involving the rod control design basis.

l 93-09 4-A Inadequate control during maintenance testing of the domineraliser system allowed a sufficient pressure transient to occur in the feed system such that both j

t feed pumps tripped, causing both motor driven auxiliary feedwater pumps to start.

l 93-10 2B The licensee intentionally entered TS 3.0.3 to permit l

calibrating the ARPI associated with certain control l rods.

93-11 4-X The licensee discovered that the standard source decay tables used for the liquid effluent radiation monitoring i system incorporated an incorrect half-life for Ba-133.

93-12 3-B The licensee intentionally entered TS 3.0.3 when level f

indication for no. 21 BAST became inoperable at the time l

no. 22 BAST was already inoperable.

93-13 2-8 Cracking in a diesel generator cylinder liner, l unrepairable in the time allowed by Ts, caused the operators to shut down the reactor.

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93-14 2-D A defective procedure failed to indicate that operation of a certain test switch during solid state protection j system testing would cause a reactor coolant safety injection accumulator actuation. ,

I 94-01 2-B See LER 93-10 94-02 1-X Licensee review of the fuel cycle calorimetric and reactor coolant flow calculations indicated that PSE&G may have operated the reactor above its thermal limit.

94-03 1-3 See LER 93-10 94-04 1-A operations personnel incorrectly interpreted an administrative requirement regarding the emergency diesels. The misinterpretation resulted in a ato declaration of diesel inoperability and consequently,

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late performance of the action required by TS.

94-05 2-A Inadequate communication between Maintenance and Planning resulted in a late surveillance of a power range instrument channel.

94-06 1-A operators failed to declare the power operated relief valves inoperable once their respective block valves were closed.

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94-07 2-A During a monthly test of the safeguards actuation I system, a technician opened an incorrect switch, causing l automatic starting and blackout loading of the emergency l diesels.

94-08 3-B Feedwater flow, aggravated by cycling of the running feed pump recirculation valve, caused a high water level condition in one steam generator, causing the operating feed pump to trip, resulting in low water level in another steam generator, thus causing an automatic l reactor trip. Subsequent investigation determined that improper gain settings caused unstable feedwater controller operation.

94-09 2-8 See LER 93-10 94-10 3-I The licensee was unable to complete corrective l

maintenance on no. 21 charging pump within the time I

allowed by Ts (72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ). Consequently, the licensee shut down the reactor.

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T' BALEE BALF1 6/20/93 - 11/5/94 NAINTREANCE/BURVEILLANCE sTRsNoruss

AIT found that the planning, control and performance of troubleshooting activities were very good and resulted in the thorough validation of the root causes for the unexpected equipment responses. AIT Report 50-272 and 311/94-80 (4/8-24/94)

Region I material inspectors observed key portions of a RCP seal flar.ge l

1eak repair, including the disassembly of the leaking flange and I installation of the blank flange. The inspectors noted effe:tive control of the repair. (IR 50-272/94-14)

The maiatoaaace organisation did a good job at prioritising work, disseminating operating experience feedback information, identifying l

equipeest problems, and general plant housekeeping. NRC Filot Team Sales Assessment (7/11/94 - 8/25/94)

A technician, using a good quality procedure, carefully performed a high risk surveillance that adequately demonstrated the operability of the 5 reactor trip breaker. (IR 50-272/94-01)

Procedure quality and craftsman skill resulted in good control of a safety-related service water pump replacement. (IR 50-272/94-01)

Control rod troubleshooting, during July / August 1993, was well planned, properly supervised, and methodically executed. (IR 50-272/93-20) l WEAKEEBRE8s

Filot team noted over reliance on generic troubleshooting procedures, ineffective use of the procedure feedback process, inadequate post-maintenance testing training, the inexperience of back shift personnel, and procedural adequacy and adherence concerns. NRC Pilot Team Sales (

l Assessment (7/11/94 - 8/25/94) )

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' Concern exists regarding the control and oversight of the auserous groups j and organisations that perform maintenance and modification work on site.

i NRC Filot Team Sales Assessment (7/11/94 - 8/25/94)

' The licensee's performance indicators showed that the sales station has a considerably higher recurrent equipment failure rate than that of similar plants. The NRC team considered the continuing recurrent equipment failures to be indicative of the licensee's inability to resolve longstanding equipment and system deficiencies. (Radiation monitoring, rod control system, analog rod position indication, main feedwater controllers) NRC Filot Team Sales Assessment (7/11/94 - 8/25/94)

Maintenance staff adequately controlled repairs to damaged pipe supports and expansion jolats in portions of the Unit 1 condensate suction header.

The inspector noted direct involvement of system engineering and quality assurance personnel throughout the event review, cause analysis, and

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Y restoration activities. (IR 50-272/94-19)

The inspectors concluded that lack of supervisory oversight contributed to maintenance-induced problems on the No. 23 auxiliary feedwater pump.

Additionally, the licensee failed to provide the training necessary to assure that mechanice effectively performed an oil change on the No. 23 auxiliary feedwater pump. (IR 50-272/94-14) (violation Level Iv]

The inspectors concluded that, although the licensee did not escoed the Technical specification diesel generator allowed outage time, plant staff unnecessarily extended a diesel generator outage due to inadequate preparation for the troubleshooting activity. (IR 50-272/94-13)

The inspector concluded that, for a service water butterfly valve replacemont, the work planning process die not include sufficient consideration of not safety benefit compared with the increased risk associated with unavailable safety-related equipment. (IR 50-272/94-13)

The licensee was initially prepared to accept the pressuriser PORVs without a visual emaalaation of the valve internals. While this activity l was noted as weak by the AIT, this was not indicative of the licensee's generally very good troubleshooting efforts. AIT Report 50-272 and 311/94-80 (4/8-26/94)

Management allowed equipment problems (e.g., Ms10 controllers, manual rods control, steam flow spiking) to exist that made operations difficult for plant operators. AIT Report 50-272 and 311/94-80 (4/8-26/94)

The AIT concluded that earlier licensee assessment of indicated high steam l

flow after turbine trips was inadequate in that it failed to identify the l actual cause, a stop valve closure induced pressure wave, and therefore I the probles remained uncorrected. AIT Report 50-272 and 311/94-80 (4/8-26/94)

The AIT found that the automatic controls for the steam generator atmosphere relief valves (Ms10s) were not maintained. The control system for the Ms10s was known to be deficient. Modifications had seen planned, but never implemented to correct these conditions and operators had been l expected, through training, to make up for the control deficiencies by manual actions. AIT Report 50-272 and 311/94-80 (4/8-24/94)

The AIT determined that the grass intrusion event of April 7 was very severe; however, the vulnerability of the design was previously recognised and modifications to improve the system had not yet been implemented. AIT Report 50-271 and 311/94-80 (4/8-26/94)

A controls technician sistaksuly mispositioned an undervoltage test switch while performing a vital bus undervoltage functional test. This personnel error resulted la the temporary de-energisation of the vital busses, start of the emergency diesel generators, and complete blackout loading of the busses. (IR 50-272/94-11)

Inspectors determined that previous troubleshooting and root cause analyses of electrohydraulic control (IHC) power supply failures appeared 1

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superficial because in four previous failures the licensee appeared to either reset or replace the failed power supply without determining the fundamental root causes for the situation. (IR 50-272/94-06)

PSE&G managner. CP m y positive steps to address poor troubleshooting

,. mtices n Salt. -4 instituted good programmatic controls of troubleshooting activt .es. However, problems continued despite the new controls. Examples L.icluded operations, the performance of troubleshooting on the residual heat removal system check valves without a procedure; Mechanical Maintenance, the removal of a failed emergency diesel generator (EDG) cylinder liner without a troubleshooting procedure, and the weak control of troubleshooting performed on an EDG air-start system check valves and I&C Maintenance, the less than adequate i troubleshooting which resulted in an inadvertent steam dump transient.

(IR 50-272/94-06) 1

The inspector noted a lack of timeliness in reviewing NRC Information Notice (IN) 93-38, Inedequate Testing of Engineered Safety Tekture Actuation Systems. Six months af ter receiving the IN, a Salem system l engineer determined that both Salem Unit 1 and 2 solid state protection system (SSPS) containment spray (CS) system testing exhibited inadequacies siullar to those described in the IN. (IR 50-272/93-27)

A surveillance procedure deficiency resulted in the inadvertent discharge of a safety injection accumulator into the reactor coolant system while at low peessure. (IR 50-272/93-27)

A weakness was noted in the licensee's operabilit; determination process during the performance of a reactor coolant system pressure iaolation valve leakage test. The licensee failed to declare equipment iaoperable when difficulties experienced during the surveillance test provided some basis to gaastion operability. (IR 50-272/93-27) ;

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In an effort to correct leakage past check valves forming the pressure l boundary between the reactor coolant system and the residual heat removal system, operators operated safety-related valv& without using a procedure or without prior documonted training for this 6.ctivity. [Violat!or Level

! H) (IR 50-272/93-27)

Maintenance identified radial cracks in a diesel generator cylinder linar i fla.7qe . Initially, the licensee considered replacing the failed lir.c in

an ef fort to maintain plant operation. After further consideratier, the licenere elected to shut down the plant to perform a comprehensive assessment of the liner failure. (IR 50-272/93-27)

Inspectors noted numerous examples of failure to follow procedures relative to the control of maintenance work activities. (IR 50-272/03-23)

[ Violations Level III) i

The licensee's failure to assess previcus occurrences, determine root

. cause and establish appropriate corrective measures to prevent recurrence contributed to repeated instances of failure to control work activities.

(IR 50-272/93-23) 1

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Inspectors found that the licensee performed inadequate surveillances required by Technical specifications in that they failed to demonstrate the capability of the diesel generators to start on any pair of air start motors. [Violatione Level IV) (In 50-272/93-23)

Inspectors noted a weakness in station management's ability to clearly determine battery operability on August 25, 1993, following installation of a new cell in a 125 volt battery. (IR 50-272/93-20)

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RALEE BALP1 6/20/93 - 11/5/94 OPERATIONE 4

ETRREarmb's 5

Inspectors acted improvements in the conduct of operations in the control

rooms. (NRC performance Assessment of Sales)

On August 30, Unit 2 operators responded well to a condenser waterbox

manway failure and reduced power to 75%. (IR 94-19) i

On August 29, Unit 1 operators performed a safe, deliberate shutdown from 75% power in response to extensive damage to condensate suction header pipe supports and expansion joints. (IR 94-19) 1

On August 22, Unit 2 operators took prompt and appropriate actions in response to a trip of one of teso operating turbine auxiliaries cooling i pump. (IR 94-19)

On June 27, Unit 1 operators responded appropriately to a lightning

)

j induced loss of all circulating water pumps and manually tripped the i reactor. (IR 94-14)

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On June 10, Unit 1 operat demonstrated appropriate e - mad and control

]

in response to as automati., June 10 trip caused by the failure of a main generator potential transformer. (tR 94-13)

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In June, plant staff performed a methodical, controlled, safe Unit 1 startup following the April 7 trip. The licensee made a conservative decision to delay the startup in order to repair small leaks in the reactor head vents and a pressuriser safety valve. (IR 94-13)

Cn February 13, Unit 1 operators demonstrated skill in their quick and t

effective response when steam dumps opened unexpectedly. (IR 94-01)

' on October 26, the licensee appropriately declared an Unusual Event when a potentially contaminated worker was transported off site. (IR 93-23)

Unit 1 operators correctly determined that the isolation of steam generator blowdown and steam generator blowdown sampling, that occurred l

during maintenance on an auxiliary feedwater pump, was not reportable.

, (IR 93-21)

On october 16 Unit 1 operators completed core offload with full regard for 4

j safety and quality control. (IR 93-21) t

] On October 12, Unit 2 operators took appropriate actions in response to

, steam generator sodium intrusion. (IR 93-21)

On Jul; ' Unit 2 operators took appropriate actions in response to an 1 automatic sntrol rod inward movement. (IR 93-19)

On July 11, Unit 1 operators performed well in response to a reactor trip that resulted when a technician caused a feedwater transient. (IR 93-19) l

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On June 28, Unit 2 operators performed a well controlled, deliberate, and safe startup following resolution of rod control systems failures. (IR 50-272&311/93-19) i ysammasssse i

Inspectors acted weaknesses in management oversight of operational j sahancements and resolution of operational workarounds. (NRC Performance l

, Assessnest of sales) I

During August and September, over a five week period, Unit 1 reduced power twice and Unit 2 reduced power six times la response to balance of plant equipment problems resulting in unacceptably high potential for challenges to safe plant operation. (IR 94-19)

During the Unit 1 startup initiated on May 14, inspectors noted that operators made repeated estries into the Ts LCO for pressuriser vent path in response to minor leakage through two head vent valves. The operators re-initialised the time for the LCO sack time. (IR 94-13)

In June, plant staf f operability determination regarding safety injection pump discharge relief valve leakage was not very thorough prior to the f inspectors requesting a basis for the deterafnation. (IR 94-13) i

In April, and with the plant shut down (Mode 5), Unit 1 operators were not attentive to the reactor vessel level indication system, RVLIS. While there was no requirement to monitor .WLIS in Mode 5, when the inspector asked operators why RVLIS indicated level was 934, they initially challenged RVLIs accuracy in Mode 5 vice believing the indication was valid. (IR 94-11)

On April 7, an exceptionally severe river grass intrusion at Unit I caused operators to rapidly reduce power. Inappropriate operator actions led to an automatic reactor trip and two safety injection actuations. (AIT Report 50-272/94-80)

During grass intrusion event, shift management personnel did not remain free to survey and analyse all ops-ating parameters, and for a short period lost control and perspective of the overall operations. (HIT Report 94-80)

The licensee provided inadegaata training, guidance and procedures to the cperators to cope with plant transients resulting from grass intrusion events, events that had previously occurred frequently at Salem and that had caused safety system challenges, reactor trips, and significant conditions adverse to quality. (AIT Report 94-80)

On March 25, Unit 2 operators closed the block valves for the power operated relief valves (PORVs), but failed to recognise that such action made the PORVs inoperable; and did not comply with Technical Specifications. VIO 50-311/94-06-01.

' on February 14, lack of aggressive resolution of a failed hotwell level control system on Unit I resulted in water backflowing from the condenser

p1 e

into both steam generator feed pump lube oil reservoirs.

While starting up the plant, operators placed Unit 2 into Mode 3 with an auxiliary feedwater pump inoperable and subject to constraints of Ts 3.7.1.2 (violation 50-272 and 311/93-15-01)

The licensee's reasonable expectation of system operability and pursuit of problem identification and timely resolution regarding the July 11 relay testing of Unit 1 solid state Protection system was not commensurate with guidance of section 4.0 of NRC Generic Letter 91-18. Operator weak assessment resulted in violation of Technical specification for an automatic actuation logic channel. (Violation 50-272&311/93-21)

OTBERs

Plant staf f dealt adequately with degraded performance of 1A emergency diesel, though operations personnel did not initially have sufficient basis for their determination of operability. (IR 94-19)

' on June 29, the Unit 2 reactor tripped automatically due to a low steam generator condition caused by cycling of the steam generator feedwater pump recirculation valve. Operator response was appropriate. (IR 94-14)

On June 14, grass fouling of the circulating water traveling screens forced Unit 2 operators to reduce power to 70%, and eventually forced PsE&G to take both units off line (Mode 2) to support dredging operations in front of the intake structures. (IR 94-13)

' on February 11, Unit 1 operators discovered control switches for both diesel generator starting air compressors for 18 emergency diesel in the off position. (IA 94-01)

On February 10, Unit 1 tripped automatically in response to a loss of 15 VDC power to the main turbine control system. (IR 94-01)

l. On February 4, sea grass and river ice collected on circulating water !

screens requiring operators for both units to reduce power, remove the I turbine generators from the electrical grid, and place the units in Mode

2. (IR 94-01)

, On Unit 1, January 27, a component mal netion in control circuitry for a l feedwater regulating valve caused a low water level condition in a steam i generator, resulting in an automatic trip. (IR 94-01)

The licensee initiated disciplinary action for an operator trainee, and constructive disciplinary action for two licensed operators and a supervisor for being involved in listening to World series baseball games while on shift in the control room. (IR 93-23)

' on October 22, the licensee initiated appropriate actions to address procedural shortcomings following an overflow of Unit 2 spent fuel pool.

(IR 93-23) i e

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i On August 24, Unit 1 operator actions to correct a safety injection i accumulator high level were prompt even though the safety significance of j the high level (65.1% vs 65% required) was minimal. (IR 93-20) i i

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' BALEE BALPt 6/20/93 - 11/5/94 i PLANT BUPPORT (fire protection, rad pro, security, enerpeacy preparedness)

FIRE PROTBCTIOE 1 i

i BTRRECTBBt

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Fire department response to a March 9 simulated fire was well executed.

i (IR 94-04'

'

In February PSEGO completed fire damper modifications that resulted in

safe, high quality improvements to the fire protection system. (IR 94-01) i

Licensee response to a November 2 fire in a turbine building lightning transformer was appropriate. (IR 93-23)

The fire department responded very well to a pipe insulation fire on l October 13 in No. 12 service water piping penetration bay. (IR 93-21)

RADIATIOE PROTRCTIOE i BTRREQT838

The licensee responded promptly and appropriately in response to elevated radiation readings in containment. (2R11A in Naraing -30,000 cym.) The l licensee took appropriate steps to identify the source of the leak. (IR 50-272/94-19)

The NRC team noted that management safety focus was ap"ropriate and that i

management and supervisors were involved in plant support activities. NRC i Pilot Team sales Assessment (7/11/94 - 8/25/94)

Ber.lth physics organisation appears to have implemented proactive and effective problem identification and resolutioa programs, as shown by a lack of recurring problems. NRC Pilot Team salem Assessment (7/11/94 -

8/25/94)

In reviewing the salem radiou ical protection program for 1993, the inspector noted that PSE&T mages and controls personnel exposure and contamination very well and maintains an aggressive as-low-as-reasonably-achievable policy for their staff. l

Salem chemistry and Radiological Protection Department personnel consistently demonstrated good performance in implementing chemistry and l radiation protection programe.

EMiGVE38E8t

The licensea discovered the t' nit 2 liquid radwaste effluent line (2R18) radiation monitor in the blocked position while a liquid release was in progress. The inspector determined that the release was less thaa

O i

allowable and provided no additional risk to public health and safety.

Non-cited violation. (IR 50-272/94-14)

On one occasion, the Radiation Protection Department failed to document the free release of a potentially contaminated valve from the RCA as required by procedure. (This was included as one of eight examples of the licensee's failure to follow procedures in the conduct of work activities.

(violation 93-23-01) (IR 50-272/93-23)

BBCETKETT, musa n CT PREPAREDEEDS STREEQ1EBs

Plant support of emergency preparedness, fire protection, security, and health physics continue to perform strongly. (NRC Performance Assessment of sales)

Management and communications within the various plant support organisations were acted to be effective. (NRC Performance Assessment of sales)

Problem identification was proactive and effective, and programs and procedures were good. (NAC Performance Assessnest of Sales)

security, la spite of some incidents, has aggressively pursued identified

issues. (NRC Performance Assessment of Sales)

Team review of the emergency preparedness facilities was favorable. (NRC I Performance Assessment of sales)

!

Response to Appendix R fire protection issues was also acceptable. (NRC i Performance Aaressment of Sales)

Operator use of emergency procedures was good. (IR 94-80/80) l

' Declaration of the NOUE was timely and in accordance with sales Emergency l Action Levels. (TR 94-80/80) l

The emergency coordinator prudently decided to declare an Alert to obtain

! technical assistance when BOPS did not provide clear guidance for recovery l from solid RCs conditions. (IR 94-80/80) i

! TBD (IR 94-24/24) i l Mose with respect to security or EP (IR 94-19/19)

Inspectors observed good performance by security personnel in performing l routine activities, such as control of access to the plant and

! impleneatation of the security plan. (IR 94-14/14)

The plaats were very clean, wil painted and lighted, with the exception of two of the four salem service water bays, and the sales turbine

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4 building basement. The licensee planned to address these areas as part of the Sales revitalisation project. (IR 94-14/14)

No plant support observations (IR 94-13/13)

No EP or security observations. (IR 94-11/11)

Licensee methodology for testing emergency battery powered lighting was acceptable and, with one exception, the emergency lighting functioned adequately. (IR 94-06/06)

The TSEEG implemented the access authorisation continual behavioral observation program well to assure that personnel with unescorted access -

to Sales (and Hope Creek) maintain proper reliability and trustworthiness.

(IR 94-01/01)

No IP og security observations (IR 93-27/27)

Despite initially weak inter-departmental communication, the licensee took comprehensive action to insure readiness for a possible security union labor action. (IR 93-23/23) t

on November 2,1993, operators appropriately declared an Unusual Event in !

response to a fire lasting 14 minutes. (IR 93-23/23) ;

On october 26, 1993, operators appropriately declared an Unusual Event when a potentially contaminated worker was transported to the Salem Hospital.(IR 93-23/23)

During a practice Emergency Preparedness drill, the EP staff appropriately identified areas for improvement. The drill provided good practice for the emergency response participants and the EP staff. (IR 93-21/21)

Operator appropriately declared an Unusual Event on October 13, 1993, in l anticipation of State interest in a short duration fire in the service ,

j water penetration area. (IR 93-21/21) l

Inspectors noted good coordination between PSEGG Engineering and Site I

j Protection during installation of a new Sales no. 2 fire pump. Testing of l l

the pump was satisfactorily performed. (IR 93-20/20) l l

1

During the annual emergency plan exercise at Salem, the licensee properly i l

declared and responded to an actual Unusual Event which resulted from an

! ammonia leak. (IR 93-19/19)

When the fire pumps were declared inoperable, PSEGG properly implemented j the necessary compensatory measures until a Sales fire pump could be

! returned from service. Compensatory measures included varifying the j availability of the Hope Creek fire water supply by tagging open the cross j i connect between Salem and Hope Creek. (IR 93-19/19) l WEARNESSENs e 1111 .tifi..ti . . .R. did t v., .f.r ti ~t t

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complications wars associated with the event. This was the subject of an l NOV for the April 7, 1994 event, and was cited as a Severity Level IV i violation. (IR 94-80/80)

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SALBE SALPs 6/20/93 - 12/5/94

'Jrr TR198 Rbtg 200T Cn0A. FUECTICEAL AREA September 29, 1994 Personnel error operations Erlef Descriptions operators manually tripped the Unit 2 reactor following an operator's inadvertent closing of two main steam isolation valves while at 30%

power.

July 14, 1994 Design / installation Engineering / tech support Erlef Descriptions Unit 1 operators manually tripped the reactor from 100% power in response to decreasing condenser vacuum caused by the loss of all circulating water (CW) pumps. The licensee determined that a design inadequacy, lack of a time delay in the undervoltage (UV) pickup circuitry of the CW pump switchgear, resulted in unnecessary UV relay actuation following a lightning-induced voltage drop.

June 29, 1994 Design Engineering / tech support Erlef Descripticas Unit 2 reactor automatically tripped, during power escalation, due to a low-low steam generator water level. The licensee determined that feedwater recirculation valve cycling at low feedwater flow rater caused rapid changes in feedwater header pressure and steam generator feedwater flow. Subsequent investigation determined that improper gain settings caused unstable feedwatar controller operation.

June 10, 1994 component failure Engineering / tech support 3rief Descriptions While operating at 974 power, Unit I reactor automatically

tripped following a main generator trip. The licensee determined that a

potential transformer failed, causing the main generator output breakers to open l

resulting in a turbine trip and subsequent reacter trip.

April 7, 1994 Personnel error operations f

Erlef Descriptions The Unit I reactor tripped from 254 power as a result of loss j of circulating water to the main condensar. Region I initiated an AIT because

of the complexity of the events, the uncertainty of the root causes of some of I i the conditions and equipment problems that had been encountered during the -

i events, and possible generic implications. (AIT Report No. 50-272/94-80)

February 10, 1994 Personnel error Maintenance /svrveillance l Brief Descripticar Unit 1 automatically tripped :from 994 power in response to j a main turbine trip. The licensee determined that a voltage spike tripped l

protective relays in the 15 VDC power supplies to the main turbine electrohydraulic system. In addition, the licensee had not properly calibrated

! the over-voltage devices and multiple high resistances contributed to higher than normal operating voltages.

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January 27, 1994 component failure Maintenance / surveillance Brief

Description:

The Unit I reactor automatically tripped free los power in response to a low water level in No.14 steam generator. The licensee determined that the cause of the trip was a level error controller in the control circuit for No. 14 steam generator feedwater regulating valve.

July 11, 1993 Personnel error Maintenance / surveillance Brief Description While shutting down Unit 1 to comply with a Technical a specification Action statement for an inoperable solid state protection relay, I the main feedwater regulating valve for the No.14 steam generator inadvertently closed as a result of personnel error. Licensee review of planned troubleshooting did not adequately identify the effects of lifting the lead.

This closure resulted in water level dropping low enough to cause a reactor trip.

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SALEM SALP; 6/20/93-11/05/94 RNGINEERING AND TECH SUPPORT atae perfor==-=e n --- - -- - t of malan 17/11/94-0125/94)

STRRE0 TEDS

Current engineering design work appears good.

VEAREsssmE:

Engineering has not demonstrated the ablity to proactively seek out and correct system and componest deficiencies (e.g., circulating water system, rod position indication, excessive cooldown)

' Eagineering work priorities not drivies by the the needs of the plant.

OTEsar

Failure to establish aggessive quality oversight of the salem facility.

Effective engineering ovesight of vendor desigsad modifications not always apparent.

94-80/80 tarts 410-26/94)

BTREEQTERs NEAREERSEEt 01EERs

Management ahowed equipment problems to esist that made operations difficult for plant operators. The equipment problems la conjunction with the resultant challenges to operators and operator errors predoniaantly caused the transiest os 4/7/94 Examples include

Automatic rod control system act is service for a month preceding the event, requiring manual operator action to restore Tave during 4/7/94 L event.

short duration high steam flow signal previously identified on three l

! occasions not properly resolved, caused spurious safety Injection.

Automatic controls for the steam generator atmospheric reliefs (MS-10s)

I were act maintained. As a result of Ms-10s failing to operate, a code l safety lifted causing a cooldown of the solid RCS, and a second SI on low pressuriser pressure. The MS-10s were known to be deficient since a modification in the late 1970s; modifications were planned but had not i been implemented .

i

The circulating water system was vulnerable to periodic grass intrusions.

The licensee had documented this vulnerability over a period of several l

l years.

! 94-24/24 (9/18-11/5/94)

BTRENOSW8t

, EEAKEEBSEEs

NOV for sustained unit 2 operation at approximately 102.5% power. This i resulted from inaccurate feedwater flow instrumentation (indicated flow

( lower than actual) . Af facted setpoints steam Flow SI, OTdeltaT, OTCeltaP,

EI high flus trip. Although the setpoints were non-conservative,

, subsequent engineering evaluation concluded that operating at up co 104.5%

l power did not invalidate any of the conclucions in the accident analysis.

[

Engineering had the opportunity to identify the degraded feedwater flow i

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i instrument accuracy at the time it ialtially occurred, but did not due to lack of rigorous root cause analysis.

Tan OTEERs 94-19/19fs/71-9/17/94)

BrRREdTER:

FEAREEESESs

Repet(tious problems with mais feedwater pump control 011 Power Unit filters presented several challenges to operators

The licensee continued to rely om shcrt term corrective actions in response to a long history of problems with the EDG air start systems. L

Marginal control air system performance continued to pose challenges to j uneventful sales operation.

9 OTEER:

' The licensee took appropriate action to address feedwater nossle weld problems and thermal sleeve erosion.

! ' overall, the program to meet the requirements of 10 CFR 50.59 was considered adequate. However, inspectors were concerned that, in f consider completed l performing 50.59 reviews, engineers did not

modifications not yet reflected in FSAR updates.

i.

j 94-14/14ts/26/-8/6/941 j

$ srasEarzss i

t EEAREESSES:

)

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The licensee took appropriate in determining the root cause of a fire in i October 1993. The fire resulted free griading, that ignited pipe i insulation. Corrective actions were appropriate. l

Analysis of the higher than espected number of reactor trips (174 l l l actual /170 espected for unit 1, 122/120 for unit 2) concluded that the !

high rate resulted from operation during 1977-1981 for unit 1, and 1941- I i 1986 for unit 2. since them the units have had significantly reduced trip I rate (less than the 10/ year assumed in the desiga). The 1 N asee response ,

l was reasonable and appropriate.

1 i 16-U/12 ts/1-6/25/94) ,

l NYAENGTES: l 5 1 l BEAKEEssEss l

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In response to March 31, 1994, sales unit 2 safety Injection relief valve i j leakage, the licensee did not perform a detailed root cause analysis, nor did the perform engineering calculations to evaluate the inspct of 1 l possible SI flow diversion to the Pressuriser Relief Tank. The licensee l did not perform a thorough operability determination until questioned by l

! the inspectors. l l The licensas failed to insure that the specified replacement parts wwre l installed is the unit 2 PORVs during the sevasth refueling outage (spring ,

l 1993). l

Imw RCs temperature coincident with spurious high steam flow signals

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caused the initial

Afety Injectica actuation on April 7,1994. On three previous occasions, the licensee had acted the spurious high steam flow

' signals, caused by pressure waves traveling up and down the steam line following a turbine trip, on three occasions previous to the April 7, event. The licensee did not properly identifiy and correct the spurious steam flow signals on those previous occasions.

In March 1977, the licensee rodified controls for the mais steam 4

atmospheric relief valves (MS-10s). In performing the modification, the licensee readered the valves incable of responding properly to increasing steam pressure ast preventing challenges to the main steam code safety valves. As a result, on A;pril 7, 1954, a code safety lifted causing as RCS cooldown and a second safety Injection actuation. To correct Ms-10 operation, the licensee restored the circuit to its original

configuration, and adjusted gain and timing circuits. These adjustments could have been Maducted in 1971 to improve valve performance. In addition, although aware of the mis-operation of the Ms-10s, the licensee did not take immediate action to correct the identified problem.

OTEEns i

94-11/11 f3/27-4/30/94) i ETARE0193s 1

vsAKEssssss j

In 11 months following May 19, 1993, issuance of NRC Information Notice 93-37, sales had not completed inspection of MOVs to identify eyebolts for

! removal and replacement. The eyebolt material is questionable, and the

eyebolta receive the thrust load during valve closing. The Move inside

! containment had not been inspected during the unit 1 outage. None of the j identified eyebolts had been replaced with hex head bolts. The inspectors concluded that PSIGG response was not timely. I i OTEERs 4

l 94-06/06 (2/20-3/26/941

$ BTRRE0TERs ,

l FEAKKEBRE8s

After a plant trip caused by an EHC power supply f ailure, inspectors noted superficial troubleshooting of EHC power supply failures; in four previous failures the licensee either reset or replaced the power supply without determining the fundamental root cause of the failure, i OTNERs l

94-01/01 f1/16-2/19/94) )

BTREWQTEBs

Good engineering coordination with Westinghouse during failed fuel inspection at salem unit 1. Also, strict procedure compliance, good attention to detail and radiological control practices.

f,ood oversight and analysis of speed oscillation in unit 1 AFW pump during l startup. ,

WEAKWEBBERs

sustained operation of Salem unit 2 at in excess of licensed thermal power ,

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4.

5 an unresolved item.

Lack of comprehensive knowledge of governor design hampered resolution of the problems (required NOED).

OTERRs 93-27/27 f 11/28/93-1/15/941 BTERE01EEs

Subsequent to initial questionable safety perspective wet to the 2C EDG CAD liner failure, the licensee conservatively declared the IB EDG inoperable.

After shutting unit 2 down for the 2C CAD liner failure, the licensee initiated a Significant Event Response Team.

The licensee properly completed package no. 6 of a DCP to improve independence and reliability of the sales switchyared. The DCP provided connection between two new offsite power sources and the new Unit 1 circulating Water switchgear. The modification properly controlled the switchyard and safely completed package no. 6.

WEAKEEBBEst

The licensee initially planned to replace the failed 2C EDG CAD liner within LCo time and remein at power without completing e root cause determination of the liner failure. Discovery of suspected crack indications in tle engine block forced the decision to shut unit 2 down.

OTERRs 93-23/23 (10/17-11/27/931 BTRRE0xwBs i W1GutusssEs:

i

NOV (level III, $50k CP) for failure to control maintenance and surveillance , activities. Examples included contractors removing spare came for auxiliary feedwater control valves without proper authorization; workers performing wiring changes in a MOV for cooling supply to the spent 7

fuel pool heat exchanger without proper written guidance, and without i properly documenting the work accomplished; workers engaged in removal of SW piping without a work package at the job site.

02WEAa l

93-21/21/21 l9/5-10/16/93)

BTRREQTEBs

Procedures Upgrade Project closed out with 994 procedures upgraded; remaining it transferred to Procedures Maintenance Group. Inspectors conclued that PUP had been a good initiative and effective in improving

' procedure quality.

l

Engineering developed and implemented appropriate corrective actions in response to the 4-3-93 inadvertent discharge of a carbon dioxide fire protection system. The inadvertent discharge, a result of water intrusion into a junction box, did not result from inadequate des.gn.

WEAKEEEEEEs E

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011VEns 93-19/19/18 ff/6/-7/24/931 BTRRE0tEms

Reactor engineering support during unit 2 startupe was a notable strength; the reactor engineers were extremely knowledgeable of reactor physics, professional in their duties, and in proper control of the startup; good communication and coordination between reactor engineering and operations.

The licensee determined that the service water system did not share the cire water system vulnerability to debris induced trips

Updated URI on EDG fuel injection studs; operability and 10 CFR 21 reportability evaluations were appropriate.

EnAKEssssas

Degraded voltage protective relays for 4KV bues:a set non-conservatively; an unresolved item.

OYEER 93-20/20 f7/25-9/4/931 STRBE0TERs

Engineering properly and conservatively evaluated an ergency diesel generator cooling water flow setpoint error. (closed URI)

WEAJGVEBREDs OtERRs i

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SAlmt BALPy 6/20/93 - 11/5/94 VIO MIOWs

(50-272/93-21-03) Violation of Technical specification (Ts) Action Statement 3.3.2.1 (EsF actuation system instrumentation channel). The solid State Protection System Train B feedwater isolation circuit at salem Unit i failed a surveillance test, and operatore did not initiate a plant shutdown, due to the inoperable channel, within the required tLee.

(Level IV)

(50-272&311/93-23-01) Violation of TS 6.8.1.a. Multiple examples of (1) performances of maintenance on equipment, including electrical breakers, without appropriate tagging of the equipment to ensure it was safe to I work on; (2) improper removal of tags that should have been maintained; and/or (3) failure to adhere to written work orders or instructions l

relative to the performance of the work. (CP - $50,000) (Level III) l

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8 (50-272&311/93-23-02) violation of TS 4.8.1.1.2.a.2. The licensee j performed inadequate surveillances required by TS 4.8.1.1.2.a.2, in that they failed to demonstrate the capability of tt* EDG's to start on any pair of air start motors, as required by the Ts definition of operability and the UFSAR description of the air start system. (Level IV) l 8 (50-272&311/93-27-01) violation of Ts 6.8.1.a., Level IV. Violation of TS 6.8.1.a, requiring the licensee to Laplement procedures for control f

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4 p

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of safety-related activities roccamended in Regulatory Guide 1.33. In )

l an effort to correct leakage past check valves forming the pressure l l

boundary between the reactor coolant system and the residual heat removal system, operators operated safety-related valves without using a j i

procedure or without prior documented training for this activity.

I

)

8 (50-311/94-06-01) violation, Level IV. salem Unit 2 operators violated i I

TS 3.4.5. Operators closed the power operated relief valves (PORVs),

making the PORVs inoperable, but did not properly remove power from the 4 PORV block valves as required by TSs.

i 8 (50-272 and 311/94-14-02) violation, Level IV. Violation of 10 CFR 50,

{ Appendix B, Criterion II, requiring the licensee to provide training of personnel performing activities affecting quality. The licensee did not provide training necessary to assure suitable proficiency for personnel J l

assigned to change the oil in the governor gearbox for the sales Unit 2 j No. 23 auxiliary feedwater pump.

[ April 7 violation) l I

nn. Irlp During Startup, on 14 SG 94-03 low-Low level 1/27/% 2/25/94 E 1 C

~15 3.0.3 Entry; Flanned Inop. of 94-06 94-04 ARP1 Sys. to Support Maintenance Troubleshooting 1/31/94 3/2/94 B 1 C 94-06 Turbine Trip Due to loss of Direct 94-05 Current Control Pwr. to EHC System 2/10/94 3/11/94 B 1 C 94-06 TS 3.0.3 Entry; Planned Inop. of _

94-06 ARP1 Sys to Support Mat. Trblshoot. 2/21/94

, 3/16/94 B~ 2 C 94-11 Rx. Trip From 257. Pwr/2 sis, Manuall y 94-07 94-07-01 5/10/94 Init. Main Stm. 1sc. ? Dg e g gl. 4/7/94 5/6/94 AJ 1 C 94-13 94-08 Turbine /Rx. Trip Due to Main Generatc .r 94-09 Ground Fault Protec. Actuation 6/10/94 6/29/94 B 1 94-14' TS 3.0.3 Entry: More Than 1 Inoperabl e 94-10 Analog Bod Position Indicator Per Bank 6/25/94 94-14; 7/13/94 B 2 C FUNCTIONAL AREAS 1 - OPERATIONS CAUSE CODE $

2 - MNT./SURV. A - PERSONNEL ERROR J .nmEEMENT 3 - ENGINEERING a - DESIGN, MANUF., CONSTR., INSTALL.

K - KNOWLEDGE 9ENT 4 - *LANT SUPPORT (RC, SEC, EP) C - CXTERNAL L - LAX D - PROCEDURES E - COMPONENT FAILURE I - DTNER

,- =,

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9 EAlmt BALPs 6/20/93 - 11/5/94 PLANT BUPPORT (fire protection, rad pro, security, emergency preparedness)

FIRE PROTECTIDW BTRENGTEBs

Fire department response to a March 9 simulated fire was well executed.

(IR 94-06)

In February PSE&G completed fire dampar modifications that resulted in safe, high quality improvements to the fire protection system. (IR 94-01)

Licensee response to a Novers - 2 fire in a turbine building lightning transformer was appropriate. .A 53-23)

The fire department responded very well to a pipe insulation fire on October 13 in No. 12 service water piping penetration bay. (IR 93-21) i RADIATION PROTECTIOE ETRRNGTEDs

The inspector determined that the licensee responded promptly and appropriately la response to elevated radiation readings in contain= mat.

(2R11A in Naraing -30,000 cym.) The licenses took appropriate steps to identify the source of the leak. (IR 50-272/94-19)

The F"C team acted that managensat safety focus was appropriate and that man: eent and supervisors were involved in plant support activities. NRC Fj foaa Salem Assessment (7/11/94 - 8/25/94) l

Eealth physics organisation appears to have implemented proactive and

! effective problem identification and resolution programs, as shown by a f lack of recurring problems. NRC Filot Team Sales Assessment (7/11/94 -

8/25/94)

In reviewing the salem radiological protection program for 1993, the 7

inspector noted that PSEGO manages and controle personnel exposure and

contamination very well and maintains an aggressive as-low-as-reasonably-

' achievable policy for their staff.

'

Protection Department personnel Salem Chemistry and Radiological

consistently demonstrated good performance in implementing chemistry and i radiation protection programs.

WEAKWE38E8s i

The licensee discovered the Unit 2 liquid radwaste affluent line (2R18) radiation monitor la tha blocked position while a liquid release was in i

1 I

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3 progress. The inspector determined that the release was less than allowable and provided no additional risk to public health and safety.

Non-cited violation. (IR 50-272/94-14)

On one occasion, the Radiation Protection Department failed to document the free retsase of a potentially contaminated valve frosa the RCA as required by procedure. (This was included as one of eight examples of the licensee's failure to follow procedures in the conduct of work activities.

(violation 93-23-01) (IR 50-272/93-23)

SECURITY, ENERGENCY FREPAREDNESS ETAKE0TEBs

Plant support of emergency preparedness, fire protection, security, and health physics continue to perform strongly. (NRC Performance Assessment of salesi)

Management and communications within the various plant support organisations were noted to be effective. (NRC Performance Assessment of sales)

Problem identification was proactive and effective, and programs and procedures were good. (NRC Performance Assessment of Salem)

security, in spite of some incidents, has aggressively pursued identified issues. (NRC Performance Assessment of Sales)

Team review of the emergency preparedness facilities was favorable. (NRC Performance Assessment of Sales)

Response to Appendix R fire protection issues was also acceptable. (NRC l Performance Assessment of Sales)

Operator use of emergency procedures was good. (IR 94-80/80)

{

8 Declaration of the NOUE was timely and in accordance with sales Emergency Action Levels. (IR 94-80/80)

The emergency coordinator prudently decided to declare an Alert to obtain technical assistance when EOFs did not provide clear guidance for recovery l from solid RCS conditions. (IR 94-80/80)

I TBD (IR 94-24/24) l r

None with respect to security or EP (IR 94-19/19)

{

' Inspectors observed good performance by security personnel in performing l routine activities, such as control of access to the plant and implementation of the security plan. (IR 94-14/14)

1 t

i ' The plants were very clean, well painted and lighted, with the exception l

of two of t.he four sales service water bays, and the sales turbine building basement. The licensee planned to address these areas as part of the sales revitalisation project. (IR 94-14/14)

No plant support observations (IR 94-13/13) i No EP or security observations. (IR 94-11/11) 1

Licensee methodology for testing emergency battery powered lighting was 4 acceptable and, with one exception, the emergency lighting functioned adequately. (IR 94-06/06)

The PSE&G implemented the access authorization continual behavioral observation program well to assure that personnel with unescorted access to Salem (and Hope Creek) maintain proper reliability and trustworthiness.

4 (IR 94-01/01)

, No EP or security observations (IR 93-27/27) 1

Despite initially weak inter-departmental communication, the licenses took comprehensive action to insure readiness for a possible security union labor action. (IR 93-23/23)

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During a practice Emergency Preparedness drill, the EP staff appropriately 1 identified areas for improvement. The drill provided good practice for the emergency response participants and the EP staff. (IR 93-21/21)

I

Inspectors noted good coordination between PSE&G Engineering and Site ]

Protection during installation of a new sales no. 2 fire pump. Testing of the pump was satisfactorily performed. (IR 93-20/20)

During the annual emergency plan exercise at Salem, the licensee properly I declared and responded to an actual Unusual Event which resulted from an ammonia laak. (IR 93-19/19)

When the fire pumps were declared inoperable, PSEGG properly implemented the necessary mpensatory measures until a Salem fire pump could be returned from service. Compensatory measures included verifying the availability of the Hope Creek fire water supply by tagging open the cross connect between Salem and Hope Creek. (IR 93-19/19)

FRAKNEBBBBt

Initial notification to the NRC did not convey information that complications were associated with the event. This was the subject of an NOV for the April 7, 1994 event, and was cited as a Severity Level IV violation. (IR 94-40/80)

BAE.EN BMay 6/2/0/93 - 11/5/94 XTENTS l At 11:00 a.m. on April 7, 1994, the licensee declared an Unusual Event based on an automatic emergency core cooling system actuation with a discharge to the vessel. At 1:16 p.m. on April 7, the licensee declarad an Alert voluntarily to assure activation of the salem Technical support conter (TSC) to provide operators with only technical assistance that would be required as they cooled down the plant.

'b

On November 2, 1993, operators declared an Unusual Event due to a fire in a 230 volt lighting transformer in the turbine building.

}-$

on October 26, 1993, the Senior Nuclear Shift Supervisor declared an l

Unusual Event when an ambulance transported a pctentially contaminated l

i worker t.o the Salem Hospital.

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'q # On October 13, 1993, operators declared an Unusual Event due to a fire in the No. 12 service water piping penetration bay.

On July 10, 1993, Unit 1 declared an Unusual Event in response to an ammonia leak discovered in Unit 1 turbine building.

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1 SALEE BALF) 6/29/93 - 12/3/94 l 25 tips 1,

ce september 29, 1994, operators manually tripped the Unit 2 reactor following an operator's inadvertest closing of two mais steam isolation i

valves while at 304 power.

i

! 8 ca July 14, 1994, Unit 1 operators manually tripped the reactor from 100% power la response to decreasing condenser vacuum caused by the loss 1

of all circulating water (CW) pumps. The licensee determined that a design inadequacy, lack of a time delay la the undervoltage (UV) pickup I

circuitry of the cw pump switchgear, resulted La unnecessary UV relay actuaties following a lightning-induced voltage drop.

i

ca June 29, 1994, Unit 2 reactor automatically tripped, during power escalaties, due to a low-low steam generator water level. The licensee determined that feedwater recirculation valve cycling at low feedwater flow rates caused rapid changea la feedwater header pressure and steam

! generator fefedwater flow.

i j 9 ca June 10, 1994, while operating at 976 power, Unit i reactor automatically tripped following a asia generator trip. The licensee dotarained that a potential transformer failed, causing the main generator output breakers to opes resulting in a turbine trip and subsequest react: trip.

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. 1 l' I e on April 7, 1994, the Unit i reactor tripped from 254 power as a result of loss of circulating water to the main condenser. Region I initiated ,

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an AIT because of the complexity of the events, the uacertainty of the root causes of some of the conditions and equipment problems that had been encountered during the events, and possible generic implications.

[ AIT Report No. 50-272/94-801 i

l e On February 10, 1994, Unit 1 automatically tripped from 994 power in response to a main turbine trip. The licensee determined that a voltage spike tripped protective relays in the 15 VDC power supplies to the main turbine electrohydraulic system.

I

on January 27, 1994, the Unit i reactor automatically tripped from 10%

power in response to a low water level in No. 14 steam generator. The liconees determined that the cause of the trip was a level error controller in the control circuit for No. 14 steam generator feedwater regulating valve.

on July 11, 1993, while shutting down Unit 1 to comply with a Technical specification Action Statement for an inoperable solid state protection

< relay, the main feedwater regulating valve for the No. 14 steam generator inadvertently cloeed as a result of personnel error. This closure resulted in water level dropping low enough to cause a reactor i

trip.

o o

I SALEM 3ALPI 6/20/93 - 11/5/94 PLANT SUPPORT FIJts PaorscTroer

[ *)

e Fire department response to a March 9 simulated fire was well executed.

(IR 94-06)

In February PSEE4 completed fire damper modifications that resulted in !

safe, high quality improvements to the fire protection system. (IR 94-01) l 4

Licensee esponse to a November 2 fire in a turbine building lightning transformer was appropriate. (IR 93-23) l e The fire dspartment responded very well to a pipe insulation fire on October 13 in No. 12 service water piping penetration bay. (IR 93-21) l l

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l RADIA2106 PROTBCTIOE STRENGHT3s

The inspector determined that the licensee responded promptly and appropriately la response to elevated radiation readings in containment.

(2R11A in Naraing -30,000 cym.) The licensee took appropriate steps to j identify the source of the leak. (IR 50-272/94-19) i' # The NRC team acted that manageneat safety focus was appropriate and that management and supervisors were involved in plant support activities. NRC Pilot Team sales Assessment (7/11/94 - 8/25/94) l

Eealth physics organisation appears to have implemented proactive and ef fective problem identificatica and resolution programs, as shows, by a ,

lack of recurring problems. NRC Pilot Team Salem Assessment (7/11/94 -

8/25/94)

In reviewing the sales radiological protection program for 1993, the inspector noted that P5EEG manages and controls personnel exposu:ce and contamination very well and maintains an aggressive as-low-as-reasonably-l achievable policy for their staff.

salem chemistry and Radiological Protection Department personnel consistently demonstrated good performance in implementing chemistry and radiation protection programs.

i VEAKNESSE3s

The licensee discovered the Unit 2 liquid radweste affluent line (2R18) radiation monitor la the blocked position while a liquid release was in progress. The inspector determined that the release was less than allowable and provided so additional risk to public health and safety.

Non-cited violation. (IR 50-272/94-14)

On one occasion, the Radiation Protection Department failed to document i

the free release of a potentially contaminated valve from the RCA as required by procedure. (This was included as one of eight examples of the licensee's f ailure to follow procedures in the conduct of work activities.

4 (Violation 93-23-01) IR 50-272/93-23 i

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SEEM SEPT 6/20/93 - 11/5/94 ,

OPERATIOND STREEQTES

On August 30, Unit 2 operators respnaded well to the sudden f_silure_of a l <

condesser waterbox manway g and reduced power to 75%. (IR 94-19)

On August 29, Unit 1 operators performed a safe, deliberate shutdown from

! . 75% power is response to extensive damage to condensate , suction header

! pipe supports and espansion lloints. (IR 94-19)

On August 22, Unit 2 operators took prompt and appropriate actions in response to a_ trip of one of two operating turbine auxiliaries cooling Pump. (IR 94-19)

' # On June 27, Unit 1 operators responded appropriately to a lightning induced losa_ of all circulating water pumps and manually tripped the

~ ~ ~ ~

~ ~ ~ ~ ~ ~

reactor. (IR 94-14)~

Unit 1 operators demonstrated appropriate c-=d and control in response

to as automatic oJune 10 trip _ caused by the failure of a main generator j potential transformer.- (IR 94-13)

In June, plant staff performed a methodical, controlled, safe _ Unit 1 startup following the April 7 trip. The licensee made' a conservative d

decision to delay the startup is order to repair small leaks in the i reactor head weats and a pressuriser safety valve. (IR 94-13)

Unit 1 operatore demonstrated skill in their quick and effective response i when steam dumps opened unexpectedly on February 13. (IR 94-01)

on october 26, the licensee appropriately declared an Unusual Event when a potentially contaminated worker was transported off site. (IR 93-23) l 8 Unit 2 declaration of an Unusual Event and subsequent operator response to l

a November 2 fire in a turbine building lighting transformer was appropriate. (IR 93-23) 4 I

Unit 1 operators correctly determined the isolation of steam generator )

blowdown and steam generator blowdown sampling, that occurred during

' maintenance on an auxiliary feedwater pump, was not reportable. (IR 93-21) l # Unit 1 operators declaration of an Unusual Event and subsequent actions in

. response to an insulation fire on October 13 in No. 12 service water piping penetration bay were appropriate. (IR 93-21)

on October 16 Unit 1 operators completed core offload with full regard for safety and quality control. (IR 93-21)

on October 12, Unit 2 operators took appropriate actions in response to steam generator sodium intrusion. (IR 93-21)

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4 4 i e e operators took appropriate actions in response to an automatic control rod inward rod movement that occurred on Unit 2 on July 18. (IR 93-19)

]

On July 11, Unit 1 operators performed well in response to a reactor trip caused when a technician lifted an improper lead and caused a feedwater

! isolation of No. 14 steam generator. (IR 93-19) l e Licensee personnel responded well to a July 10 inadvertent anunonia release i in Unit 1 turbine building. operators declared an Unusual Event, quickly determined the cause, corrected the cause, and properly implemented the l Emergency Plan. (IR 93-19)

The June 28, Unit 2 startup following resolution of rod control system failures was well controlled, deliberate and safe. (IR 50-272&311/93-19) l FKAJGFESSES:

I

! # During August and September, over a five week period, Unit 1 reduced power j twice and Unit 2 reduced power sin times is response to balance of plant {

equipment problems resulting in unacceptably high potential for challenges

)

to safe plant operation. (IR 94-19)

}

e During the Unit 1 startup initiated on May 14, inspectors noted that operators made repeated estries into the TS LCO for pressuriser vest path is response to minor leakage through two head went valves. The operators

, re-initialised the time for the 240 each time. (IR 94-13)

In June, plant staff operability determination regarding safety injection I pump discharge relief valve leakage was not very thorough prior to the inspectors requesting a basis for the determe=mtion. (IR 94-13) l' e In April, and with the plant shut down (Mode 5), Unit 1 operators, while not required to monitor vessel level, were not attentive to level (reactor

vessel level indication system, RVLIS) and initially challenged RVLIS accuracy in Mode 5 in response to inspector observations of low vessel level. (IR 94-11)

I

e On April 7, an exceptionally severe river grass intrusion at Unit 1 caused l operators to rapidly reduce power. Inappropriate operator actions led to i an automatic reactor trip and two sr.foty injection actuations ( AIT Report 50-272/94-80). l 1 1 l

i # on March 25, Unit 2 operators closed the block valves for the power ;

i operated relief valves (PORVs), but failed to recognize that such action i made the PORVs inoperable; VIO 50-311/94-06-01. l

On February 14, lack of aggressive resolution of a failed hotwell level

control system on Unit i resulted in water backflowing from the condenser into both steam generator feed pump lube oil reservoirs.

While starting up the plant, operators placed Unit 2 into Mode 3 with an auxiliary feedwater pump inoperable and subject to constraints of TS 3.7.1.2 (Violation 50-272 and 311/93-15-01) 1 4

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I a # The licensee's reasonable expectation of system operability and timely j pursuit of problem identification and resolution regarding the July 11

relay testing of Unit 1 Solid State Protection System was not coamensurate with guidance of Section 4.0 of NRC Generic Letter 91-18. operator weak i assessment resulted in violation of Technical specification for an j automatic actuation logic channel. (Violation 50-272&311/93-21)

OtEERs

Plant staff dealt adequately with degraded performance of 1A emergency

diesel, though operations personnel did not initially have sufficient 1 basis for their determination of operability. (IR 94-19) l

on June 29, the Unit 2 reactor tripped automatically due to a low steam generator condition caused by cycling of the steam generatoc feedwater j pump recirculation valve. Operator response was appropriate. (IR 94-14) i # On June 14, grass fouling of the circulating water traveling screens I forced Unit 2 operators to reduce power to 70%, and eventually forced FSE&# to take both units off line (Isods 2) to support dredging operations

]" in front of the intake structures. (IR 94-13)

on February 11, Unit 1 operators discovered control switches for both

diesel generator starting air compressors for la emergency diesel in the

] off position. (IR 94-01) d j # On February 10, Unit 1 tripped automatically in response to a loss of 15 ,

j VDC power to the main turbine control system. (IR 94-01) I I

j # On February 4, sea grass and river ice collected on circulating water screens requiring operators for both units to reduce power, remove the j turbine generators from the electrical grid, and place the units in Mode

2. (IR 94-01)

# On Unit 1, January 27, a component malfunction in control circu. +/ for a feedwater regulating valve caused a low water level condition in a steam j generator, resulting in an automatic trip. (IR 94-01)

The licensee initiated disciplinary action for an operator trainee, and I constructive disciplinary action for two licensed operators and a supervisor for being involved in listening to World Series baseball games while on shift in the control room. (IR 93-23)

The licensee initiated appropriate actions to address procedural

, shortcomings following an overflow of Unit 2 spent fuel pool on October

22. (IR 93-23)

I # On August 24, operator actions to correct safety injection accumulator high level on Unit 1 were prompt even though the safety significance of 1 the high level (65.1% vs 65% required) was minimal. (IR 93-20) 1 i

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! SALEM SALP; 6/20/93 - 11/5/94

! MAINTENANCE / SURVEILLANCE STRENGTH 3s i # AIT found that the planning, control and performance of troubleshooting activities were very good and resulted in the thorough validation of the root causes for the unexpected equipment responses. AIT Report 50-272 and

} 311/94-80 (4/8-24/94)

Regios I material inspectors observed key portions of a RCP seal flange leak repair, including the disassembly of the leaking flange and installation of the blank flange. The inspectors noted effective control of the repair. (IR 50-272/94-14)

J

The maintenance organisation did a good job at prioritising work,

> disseminating operating experience feedback information, identifying j equipment problems, and general plant housekeeping. NRC Filot Team sales l Assessnest (7/11/94 - 8/25/94) )

i

A technician, using a good quality procedure, carefully performed a high risk surveillance that adequately demonstrated the operability of the B l reactor trip breaker. (IR 50-272/94-01) 8 Procedure quality and craftsman skill resulted in good control of a l

j safety-related service water pu:np replacement. (IR 50-272/94-01)

) # Control rod troubleshooting, during July / August 1993, was well plagned, j properly supervised, and methodically executed. (IR 50-272/93-20) j WEAKNESSESt t

l 8 over reliance on generic troubleshooting procedures, ineffective use of

. the procedure feedback process, inadequate post-maintenance testing training, the inesperience of back shift persommel, and procedural j adequacy and adherence concerns. NRC Filot Team Sales Assessment (7/11/94

- 8/25/94)

Concera exists regarding the control and oversight of the numerous group and organisations that perform maintenance and modification work on site.

l NRC Pilot Team Sales Assessment (7/11/94 - 8/25/94) 1

The licensee's performance indicators showed that the Sales station has a considerably higher recurrent equipment failure rate than that of similar l Plants. The NRC team considered the continuing recurrent equipment i failures to be indicative of the licensee's inability to resolve longstanding equipment and system deficiencies. (Radiation monitoring, rod control system, analog rod position indication, main feedwater controllers) NRC Filot Team Salem Assessment (7/11/94 - 8/25/94) ,

8 Maintenance staff adequately controlled repairs to damaged pipe supports and expansion joints in portions of the Unit 1 condensate suction header.

I The inspector noted direct involvement of system engineering and quality 1

l l0 3

i assuranc6 personnel ' throughout the event review, cause analysis, and restoration activities. (IR 50-272/94-19)

# The insportors concluded that lack of supervisory oversight contributed to l maintenas,ce-induced problems on the No. 23 ausiliary feedwater pump.

Additionally, the licensee failed to provide the training accessary to d assure that mechanics effectively performed an oil change on the No. 23 i ausiliary feedwater pump. (IR 50-272/94-14) (violatina hval IV) i

) # The inspectors concluded that, although the licensee did not escoed the l Technical specification diesel generator allowed outage time, plaat staff l unnecessarily extended a diesel generator outage due to inadequate

! preparation for the troubleshooting activity. (IR 50-272/94-13) e The inspector concluded that, for a service water butterfly valve i replacement, the work planning process did not include sufficient j consideration of not safety benefit compared with the increased risk

associated with unavailable safety-related equipment. (IR 50-272/94-13) 1 I # The licensee was initially prepared to accept the pressuriser PORVs

! without a visual examiantion of the valve internals. While this activity i was acted as weak by the AIT, this was not indicative of the licensee's I generally r ary good troubleshooting offorts. AIT Report 50-272 and

} 311/94-80 (4/8-26/94) l e Management allowed equipment problems to exist that made operations

! difficult for plant operators. AIT Report 50-272 and 311/94-80 (4/8-l 26/94) e The AIT concluded that earlier licensee assessment of indicated high steam flow after turbine trips was inadequate is that it failed to identify the actual cause, a stop valve closure induced pressure wave, and therefore l the problem remained uncorrected. AIT Report 50-272 and 311/94-80 (4/8-

! 26/94) 1 l 8 The AIT found that the automatic controls for the steam generator j atmosphere relief valves (Ms10s) were not maintained. The control system I j for the Ms10s was known to be deficient. Modifications had been planned, l but never implemented to correct these condtions and operators had been

! espected, through training, to make up for the control deficiencies by manual actions. AIT Report 50-272 and 311/94-80 (4/8-26/94)

]

e The AIT determined that the grass intrusion event of April 7 was very i severe; however, the vulnerability of the design was previously recognised i and modifications to improve the system had not yet been implemented. AIT Report 50-272 and 311/94-80 (4/8-26/94)

J l

i # A controls techniciaa mistakenly mispositioned an undervoltage test switch I while performing a vital bus undervoltage functional test. This personnel error resulted in the temporary de-energisation of the vital busses, start

, of the emergency diesel generators, and complete blackout loading of the 1 busses. (IR 50-272/94-11) i

l .

Inspectors determined that previous troubleshooting and root cause analyses of electrohydraulic control (EHC) power supply failures appeared I superficial because in four previous failures the licensee appeared to

' either reset or replace the failed power supply without determining the fundamental root causes for the situation. (IR 50-272/94-06) e PsE&C management took many positive steps to address poor troubleshooting practices at sales and instituted good programmatic controls of j troubleshooting activities. However, problems continued despite the new controls. Examples included: Operations, the performance of troubleshooting on the residual heat removal system check valves without a procedure; Mechanical Maintenance, the removal of a failed emergene) diesel generator (EDG) cylinder liner without a troubleshooting procedure, and the weak control of troubleshooting performed on an EDG air-start system check valves and I&C Maintenance, the less than adequate troubiwshooting which resulted in an inadvertent steam dump transient.

1 (IR 50-272/94-06)

Lack of timeliness in reviewing NRC Information Notice (IN) 93-38, Inadequate Testing of Engineered Balety feature Actuation Bystems. Six months after receiving the IN, a sales system engineer determined that l both salem Unit 1 and 2 solid state protection system (SSPS) containment spray (cs) system testing exhibited inadequacies similar to those i described in the IN. (IR 50-272/93-27) e A surveillance procedure deficiency resulted in the inadvertent discharge ,

of a safety injection accumulator into the reactor coolant system while at (

low pressure. (14 50-272/93-27) i l # A weakness was noted in the licensee's operability determination process during the performance of a reactor coolant system pressure isolation i valve leakage test. The licensee failed to declare equipment inoperable

, when difficulties experienced during the surveillance test provided some i basis to question operability. (IR 50-272/93-27) e In an effort to correct leakage past check valves forming the pressure boundary between the reactor coolant system and the residual heat removal system, operators operated safety-relata,d valves without using a procedure or without prior documented training for this activity. [ Violation Level IE) (IR 50-272/93-27)

Maintenance identified radial cracks in a diesel generator cylinder liner flange. Initially, the licensee considered replacing the f ailed 3 ': in an effort to maintain plant operation. After further consideration, the licensee elected to shut down the plant to perform a comprehensive assessment of the liner failure. (IR 50-272/93-27)

Inspectors noted numerous examples of failure to follow procedures relative to the control of maintenance work activities. (IR 50-272/93-23)

(Violations Level III)

The licensee's failure to assess previous occurrences, determine root cause and establish appropriate corrective measures to prevent recurrence

contributed to repeated instances of failure to control work activities.

(IR 50-272/93-23)

Inspectors found that the licensee performed inadequate surveillances required by Technical specificatione in that they failed to demonstrate ,

the capability of the diesel generators to start on any pair of air start {

motors. [ Violations Level IV) (IR 50-272/93-23) e Inspectors noted a weakness in station management's ability to clearly determine battery operability on August 25, 1993, following installation of a new cell in a 125 volt battery. (In 50-272/93-20) !

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!$ lW MRC Five-Day Look-Ahead (4:00-7:00 PM -Salem GM's Conference Room unicss otherwise noted) l- Date l Time i Topic l Presenter l Thursday, August 10 4.00 Salem Facilitics Renovations Steve Maginnis 4:15 Dleed Steam Matt Unicelle 4.45 Safeguards Eqt Cabinet Dominic Shea 5:15 FW Condensate / Boiler Feed W. Lowry/S.Robitzski 5:45 Unit 2 Turbine Rotors Bill Schultz 6:00 MRC Chaner Revisions Dana Cooley _,,,,,,,_ ,,,,,,,,,,,,,,

Friday, August i1 4.00 RMS Issues John Cicconi 4:30 115 VAC Bruce Focht 5:00 Circulation Water Bob Swartzwclder :

5:30 125/28 VDC System _

J. Schubert Monday, August 14 4:00 Diesel Generator D.Kolansiriski/R.McLaughlin 4:30 Post Accident Sampling Sam Speer l 5:00 Fuel Handling Lisa Ford i 5:30 Turbine Building Fan Issues ,,,,,,,,, George Boghosian i Tuesday, August 15 4.00 Containment Painting Ul/U2 Bill Hunkele 4:15 Safetyinjection John Erhard 4:45 FuelHandling Building Vent Gulshan Pahwa 5:15 Controlled Air / Compressed Ai,r,,,,_ Bill Rodgers _ _ _ _ _ _ _ , _ , , , , , , , , , , , , , , _ _

Wednesday, August 16 4.00 Appendix"R" Issues B. McDevitt/M.Burszteln 4:30 Main Generators UI/U2 Paul Morakinyo 5:00 Residual Heat Removal John Erhard 5.30 Containment Building & Pen Alan Johnson I

l l

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NRC/PSE&G MEETING :

AUGUST 10,1995 :'

LIST OF PRINCIPLE ATTENDEES PSEAG SENIOR MANAGEMENT .i

- LEON ELIASON CHIEF NUCLEAR OFFICER &

PRESIDENT- NUCLEAR BUSINESS UNIT

LOUIS (LOU) STORZ SENIOR VICE PRESIDENT - NUCLEAR OPERATIONS i j ELBERT (BERT) SIMPSON SENIOR VICE PRESIDENT - NUCLEAR ENGINEERING

{ JOSEPH (JOE) HAGAN VICE PRESIDENT - NUCLEAR BUSINESS SUPPORT ;

CLAY WARREN GENERAL MANAEER- SALEM OPERATIONS i JEFFERY(JEFF) BENJAMIN DIRECTOR- QA & NUCLEAR SAFETY REVIEW l MICHAEL (MIKE) RENCHECK SYSTEM ENGINEERING MANAGER- SALEM i;

PSE&G SUPPORT I i

$ I 3

MARK REDDEMANN GENERAL MANAGER - HOPE CREEK OPERATIONS l BRUCE PRESTON MANAGER- SALEM ENGINEERING !

. ERNIE HARKNESS STATION PLANNING MANAGER - SALEM 1 LEE CATALFOMO OPERATIONS MANAGER- SALEM

! LEN RAJKOWSKI MAINTENANCE MANAGER - CONTROLE (Acting)

GREG SUEY CHEMISTRY MANAGER l MIKE METCALF MAINTENANCE MANAGER-MECHANICAL i

, ERIC KATZMAN RADIATION PROTECTION MANAGER l TERRY CELLMER STATION SELF-ASSESSMENT MANAGER FRANK THOMSON MANAGER - NUCLEAR LICENSING & REGULATION i

i j NRC i

TIM MARTIN REGIONAL ADMINIS'ITATOR- REGION I JAMES LIEBERMAN DIRECTOR, OFFICE OF EhTORCEMENT JAMES LINVILLE CHIEF - REACTOP. PROJEC.tS BRANCH 3, DRP

! JAMES MILHOAN DEPUTY EXECU TIVE DIRECTOR FOR NUCLEAR REACTOR

REGULATION, REGIONAL OPERATIONS & RESEARCH l JOHN WHITE CHIEF, REACTOR PROJECTS GECTION 2A, DRP

!' WILLIAM DEAN REGIONAL COORDINATOR, OSDO JOHN STOLZ DIRECTOR, PROJECTS DIRECTORATE I-2, NRR

, EUGENE KELLY CHIEF, PLANT SYSTEMS SECTION, DRS LEONARD OLSHAN LICENSING PROJECT MANAGEF.- SALEM SCOTT BARBER PROJECT ENOWEER, REACTOR PROJECTS SECTION 2A CHARLES MARSCHALL SENIOR RESIDENT INSPECTOR- SALEM

, MJCHAEL CALLAHAN OFFICE OF CONGRESSIONAL AFF AIRS 1

6

-y e - , , ,_

Artschment 1 ,

MANAGEMENT REVIEW COMMITTEE RESTART WORKSCOPE/ WORK ITEM DISPOSITION FORM (Initiator - Fill in all unshaded boxes)

Item ID l l Initiator: l M. C. Annon j System Index/ Group ID l l System Designator l l Applicability: Unit I l . l Unit 2 l l Common l X l Recommend: Include / Add l X l Exclude / Delete l l See Attachment l l Action Owner: l M. C. Annon l Date: l 7/28/95 l Responsii;1e Manager: l B. Preston l Date: l l Item / Group

Description:

HAGAN CONTROLS - Initial Presentation (Limited to NUS Module replacements)

~

me Specific)

Reasons for Outage Scope Inclusion / Addition or Exclusion / Deletion:

The proposed actions are part of resolving the overall Hagan Controls concerns which meet Level 2, Criteria 3, 4, 7, and 9 l

1 I

(Reference appropnate Restart Screenmg Cnteria - see reverse)

List Attachments or Applicable Reference Documents (e.g., NAP-55 Form)

See attached sheets for more details. l apr (When proposing several items or a group)

MRC Decision Date:- <

Meeting No: 3 Chair:1 w y , ,,s '

v

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4 :95; j5S .* -

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i 3

HAGAN CONTROLS REFURBISHMENT & REPLACEMENT (R&R) PROJECT 4

INITIAL MRC PRESENTATION August 1, 1995 TODAY'S DISCUSSION WILL COVER E Overview of Hagan Controls R&R Project Scope & Status l

E An Immediate Issue Requiring MRC Concurrence / Direction 1 E What's Currently Being Accomplished / Planned BACKGROUND There have been several, interrelat'ed but often independent, l efforts, initiated by various PSE&G organizations over the last few years, that are related to Hagan Reactor Proteccion &

Controls equipment. While these efforts have included both engineering and maintenance activities, they have not been able to achieve the desired results of having a plant protection and control system that operates reliability and without creating challenges to uneventful plant operation. While progress has been ,

made by various PSE&G organizations involved in addressing many '

of the Hagan Controls engineering and maintenance issues, over the several months, there are still many issues required to be resolved to avoid continuing to have less than acceptable system performance.

Wn11e eacn of the past incidents, involving the Hagan Controls, has a rational explanation for the incident occurring, the i collective significance of these occurrences may imply that serious shortcomings do possibly exist within the Hagan Control System, the implementation of programs associated with the Hagan Control System, the training of personnel being used, and/or combinations of these issues.

A

l HAGAN CONTROLS REFURBISHMENT & REPLACEMENT (R&R) PROJECT (con't)

HAGAN CONTROLS R&R PROJECT SCOPE The current scope of the Hagan Controls Refurbishment and Replacement (R&R) Project consists of identifying, addressing and resolving, in an integrated and coordinated effort, any and all issues.related to the equipment within the Hagan Controls Protection and Controls Cabinets. The Project's prime goal is to allow Salem Units 1&2 to restart and continue to operate without the Hagan Control System creating challenges to uneventful plant .

operation. -

The Hagan Control System consists of the following physical ,

equipment: l

~30 Racks of Protection & Control Cabinets per Unit !

-200 Instrumentation Loops, with -800 modules, per unit

~370 modules included as spares or being repaired This Project also includes the overall coordination and

implementation of the following programs and/or previously 1 initiated activities: 1

Fuse Inspection Program i I

- Hagan Module Refurbishment

!

NUS Module Replacement of Hagan Modules -

Hagan Controls Related Configuration Control Issues

Hagan Controls Parts Availability

Controller Relay & Drain Circuit Inspection

{

Hagan Qualified Technician Training j'

Integration of " Lessons L' earned" from other Utilities i

Identification / Assessment of viable options for PSE&G l

Development of a strategy / action plan, including cost benefits and associated risk analysis, to achieve an

acceptable state of readiness for Hagan Controls upon

restart 4

Development of near-term and long-term

, strategies / action plans to achieve the desired results j of a plant protection and control system that operates

reliability and without creating challenges to

uneventful plant operation i

j The Project also has significant interface and/or integration responsibilities with:

Advanced Digital Feedwater Implementation @ Units 1&2 i

Reg. Guide 1.97 0 Unit 1 System Readiness Review Support /Results Implementation I

1 i

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4

o HAGAN CONTROLS REFURBISHMENT & REPLACEMENT (R&R) PROJECT (con't)

CURRENT STATUS Efforts during the weeks of July 17 & 24 have been focused on:

Identifying the tasks and activities related to Hagan Controls to support defining the Project's scope

Interfacing with the affected PSE&G organizations, in order to get their support and agreement with the Project's approaches to dealing with the issues

Identifying the items / support needs deemed " Project Critical" (i.e., requiring management decisions / commitments within the next two weeks). These l I

items currently include: (a) Funding and/or MRC approval for the Hagan Project, in general; (b) MRC approval for a commitment to NUS for up to Sl.3M for replacement modules; (c) MRC approval for a commitment to Westinghouse /Rosemount for potentially up to $0.5M for I/V modules; (d) access to short-term resource needs, both people and space

[ NOTE: Only item (b) is proposed to be discussed, in

- detail, at this 8/1/95 MRC Meeting]

Supporting and participating in the Reactor Controls &

Protection (RCP) and Solid State Protection (SSP)

System Readiness Reviews.

A significant amount of information and effort has been spent in developing data and plans to improve the Hagan Controls related problems. However, at the present time, the basis for a well-founded recommendation as to "the best way" to proceed, is not available. Such a recommendation will be developed by the end of this month. (A Milestone Schedule is provided later). The complexity of the interrelationships between the currently on-going Hagan Controls related programs and activities, coupled within the need for additional factual data, has precluded developing a well-founded integrated recommendation prior to this MRC meeting.

i RAGAN CONTROLS REFURBISHMENT & REPLACEMENT (R&R) PROJECT (con't)

RECOMMENDATIONS In order to retain several viable options to support the Unit 1 &

2 Restart schedules to the maximum extent possible, while an integrated short-term recommendation (action plan) is being developed, we recommend the following actions:

E Replacement of the'Hagan Summator & Isolator Modules be authorized, in a phased approach, to allow for us to reduce, by as much as 6-9 weeks, the time that would be required if these modules had to be refurbished.

(NOTE: This is the only item that we are seeking specific concurrence from the MRC, at this meeting.]

E The Hagan Module Refurbishment Program continue, with emphasis on the modules needed to support other related restart activities. Refurbishment will not be done on modules being replaced by Digital Feedwater modifications or NUS replacements.

E The Hagan Controls R&R Project continues with it's assessment of the programs and practices related to the current (and currently planned) engineering and maintenance activities and programs.

E Aggressively pursue cost and schedule information for any viable option, while associated cost-benefit and risk analyses are being developed in parallel.

l i

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'5 ,

HAGAN CONTROLS REFURBISHMENT & REPLACEMENT (R&R) PROJECT (con't) l 4

SUMMATOR & ISOLATOR MODULES

Previous Maintenance & Engineering Efforts Have Resulted in Identifying Need for 407 additional Moquies. A total of 248 Isolators & 159 Summators for both Units.

4 t

Recommendation to replace the existing modules was made to

make significant reduction in opportunities for challenges

! to uneventful operation. The recommendation was primarily based on a combination of a review of Previous Work History 4

-that these modules had a high incidence of work required

, coupled with the fact that these types of modules represent j > 1/4 of the Total Numbers of Modules currently installed.

l (Summators represent ~12% of total population of Hagan Modules; Isolators represent -15%)

l Based on recent interactions with the replacement module !

supplier (NUS), a commitment is needed immediately l 4

(originally requested by end of July) to allow for purchase l l of long-lead items and to reserve production capacity.

Use of new NUS modules is projected to save between 6-9 weeks over refurbishment approach, -

I/V MODULES

Previous Maintenance & Engineering Efforts Have Resulted in Identifying the Potential Need for ~400 additional Modules to replace the existing I/V modules to resolve previously .

identified issues with components and associated F calibration /setpoint issues (i.e., input impedance matching); as well as, to prevent potential technical problems learned from other utilities.

l 6

l l

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s-

' 6' HAGAN CONTROLS REFURBISHMENT & REPLACEMENT (R&R) PROJECT (con't)

MILESTONE SCHEDULE Week of 7/24 - Define Hagan Controls R&R Project Scope Define Responsibilities & Integrated Approach (es) with Significant Interface Activities

Week of 7/31 - Define Viable Short-Term Options for Restart Finalize Key Milestones & Level 1 Schedule Week of 8/7 - Recommend Viable Near-Term /Long Term Options to Pursue & Short-Term Action Plan to Follow Week of 9/4 - Provide Recommendations for Near-Term /Long-Term Options (Modify Short-Term Action Plan, If Necessary) -

Week of 9/25 - Provide Draft of Integrated Long-Term Hagan R&R Plan Week of 10/30- Fina,lize Thtegrated Long-Term Hagan Controls R&R Plan

t i

I

- Restart Screening Criteria y

The Salem restart issue screening evaluation will be performed in two levels to the enteria desenbed below. This will allow station management to focus on those issues important to safe plant restart and subsequent event-free operation.

Level 1 Screenlar - The proposed action resolves a safety or operability issue. (These automatically require resolution prior to plant startup.)

Level 2 Screenlan - Although not a safety or operability issue, the proposed action:

1. Eliminates a component failure, deficacy or condition that could result in operation or entry lato as LCO action statessent.

2. Resolves deficiencies or conditions that

a. would result in failure or inability ta performs a required surveillance test during the current outage or the following operating cycle in accordance with the plant technical specifications,

b. would increase the risk to operation or safety associated with perfonsing a surveillance, or

c. would result in the failure to meet a license requiressent or a comunitment to an outside agency.

3. Restores degraded critical components or conditions that r nsid result la a plant transiest, derate or shutdown.

, 4. Resolves conditions that have resulted in .W;M safety systems or power block equipment failures.

5. Restores licensing basis deficiencies to confonning conditions (e.g., EQ, Appendix R seismic,

environmental).

6. Corrects design basis deficia-lee i.e., deficiencies in safety related equipment or other Technical Specification equipment not in conformance with design basis documents such as the UFSAR.

i

7. Corrects deficiencies la configuration managenest programs, processes, engineering analysis codes or documentation that have a reasonable probabdity of affecting equipment operability.

8. Eliminares conditions that may create an unacceptable potential for perwesel radiation 3

exposure, an unplanned radioactivity release to the envirosraest or discharge of effluent in

excess of limits.

9. Reduces cumulative deficiencies, backlogs or coedstions that, in aggregate, could have 4 significant negative impact on safety, operability or rehable plant operation. (Not applicable to 1

individual work items)

Revision 0 July 1,1995

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's SENT BY: 8- 7-35 ; 2:17PM : PSE&G Ltc & REG, :9 2/ 2

,i t

NRC SENIOR MANAGEMENT PLANT TOUR OF SALEM AUGUST 9,1995 e i 9:30 - 11:30 NRC Management tour with C. Marschall

) ,

J. Milhoan T. Martin W. Dean J. White J. Linville

. 11:30 - 1:00 NRC Management lunch with Residents 1:00 - 3:30 INTERVIEWS - To be conducted by J. Milhoan and T. Martin j Chemistry Conf. Room i

1:00 - 1:30 J. Benjamin Director OA/NSR i

1:30- 2:00 C. Warren GM Salem Operations 2:00 - 2:30 L. Storz Sr. VP - Nuclear Operations 2:30 3:00 E. Simpson Sr. VP - Nuc! ear Engineering

, 3:00 - 3:30 L. Ellason CNO & President NBU 3:30 - 4:30 PSE&G Management Debrief - Chemistry Conf. Room J. Benjamin C. Warren L. Storz E. Simpson L. Elisson J. Hagan F. Thomson PAM S/7/95

,, SENT BY: 8- 8-95 : 4:51PM : PSE&G LIC & & ;8 1/14 4 I l

i O PSFg Licensing & Regulation FAX # (609) 339-1448 Number of Pages (including cover sheet) /

DATE:

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. SENT BY: 8- 8-95 : 4:51PM : PSE&G LIC & REG-. ;* 2/14 4

i PUBLIC SERVICE ELECTRIC AND GAS COMPANY

, 1 ORGANIZATION CHARTS AND BIOGRAPHIES AUGUST 8,1995 REVISED l

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SEhT BY: 8- 8-85 . 4:53PM , PSE&G LIC & REG-' ;# 9/14 i

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O PSEG Nuclear Business Unit Louis F. Storz h Senior Vice President-j ,

Nuclear Operations ]

1 l Louis F. Storz was named senior vice president-l .

! nuclear operations in July 1995. He has overall i {

l responsibility for all nuclear operations of Salem i

and Hope Creek Generating Stations. -

Prior to joining PSE&G Storz served as vice t

j president-nuclear generation at Niagara j l Mohawk in New York. He was also general I j manager at Davis Besse Generating Station, and

)

I i

was promoted to vice president-nuclear of i

, Toledo Edison Company, which operates Davis '

1 Besse. Storz also served as assistant plant man-

} sger at Louisiana Power & Light Company's Waterford Generating Station and assistant plant i

manager for operations at South Carolina Power & Light Company's V.C. Summer Generating i

' Station. He has held a number of technical and managerial positions including superintendent of j

operations at the Point Beach Nuclear Generating Station operated by Wisconsin Electric Power j

Company. Stop, participated in INPO's (Institute of Nuclear Power Operations) Utility Loan l Program and has held engineering positions with Babcock and Wilcox Corporation and PPG l Industries. He served in the United States Navy's nuclear submarine program from 1960 67.

Storz holds a bachelor of science degree in mechanical engineering firom Purdue University.

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. SEhT BY: 8- 8-35 : 4:54PM : PSE&G LIC & REG- :s10/14 i

. O PSIEG Nuclear Business Unit l Clay C. Warren '

.: GeneralManager-Salem Generating Station Clay C. Warren was named General Manager-

! Salem Operations in July 1995. He has direct responsibility for the operation of Salem Gener-l ating Station.

i I

,l.

Warren previously served as General Plant

./

l Manager of Carolina Light and Power's Brunswick Nuclear Plant where he was respon.

[ i' sible for all aspects of plant operations, mainte-

7 -,. -

nance and outage management. He also served as maintenance manager at Arkansas Nuclear ~ l ?/B ' One, and consulting deputy outage manager at Boston Edison Company's Pilgrim Station. Prior to thr.t position, Warren spent five years as a senior inspector for the Nuclear Regulatory Commission at three different nuclear plants. He began his career in the nuclear industry in the United States Nuclear Navy. When he left in 1979, he was the Leading Petty Officer in the Reactor Controls Division. He holds a bachelors degree in natural science from Louisiana State University and received l Senior Reactor Operation License training in 1985 i l i i h

                          = toe 4 I

l I

l

SENT BY: 8- 8-95 4:55PM . PSE&G LIC & REG- 811/14

                        ;             O PSIsG        Nuclear Business Unit Elbert C. Simpson

l Senior Vice President- . .

                                                                                                                                        )~E-                                     1 NuclearEngineering Elbert C. Simpson was named senior vice presi-i dent-nuclear engineering in June 1995. He

i oversees all engineering activities for Salem and Hope Creek Stations and the Nuclear Business Unit l

1 Simpson was vice president-nuclear support for '- -. . Arizona Public Service Company, which oper- ... ates the three-unit Palo Verde Nuclear Generat- h

ing Station, prior tojoining PSE&G. He over-saw nuclear engineering, construction and ,

j , support in this position. Simpson also held a - 1 g ,. number ormanagerial positions with Florida - ) Power Corporation, including ! director-nuclear operations engineering and projects, director-nuclear operations site sup-i port, and director - nuclear operations engineering and licensing. ( j Simpson holds bachelor of science degrees in electrical engineering and nuclear engineeri from University of Florida. t i l l I i l P i P

   ,. . . - - . . ~ . _           ,-.                     _
                                                                                ~ ,

                     ,            SENT BY:                                           8- 8-95 : 4:55PM ,                               PSE&G LIC & REG-                       tet2/14 O PSMG                       Nuclear Business Unit Jeffrey A. Benjamin                                                                                      I DirectoMuality Assessment
                           ,               and Nuclear Safety Review                                                                -

s ,. i Jeffrey A. Benjamin was named director-quality assessment and nuclear safety review in

                                                                                                                                            ',, j ' Y; e i
                                                                                                                                                    .,   t December 1994. As director, Benjamin is re.

sponsible for overall management of quality TQ. . I . assurance and nuclear safety review programs at ' r / Salem Units 1 and 2. Hope Creek Station and all supporting departments. He also serves as chairman of the Nuclear Review Board and ,

%(

oversees licensing and regulation. i Benjamin had been manager of quality assess- - I ment fbr the Washington Power Supply System in Richland, Washington. While at WNP-2, Benjamin successfully completed the BWR Man-agement Certification program. Prior to assuming his position at the WPPSS, Benjamin served as quality control manager, quality audit supersor and nuclear safety engmeer at the Trojan Nuclear Plant in Oregen. In addition, he worked as a reactor engineer at the Hanford Nuclear Reservation. Benjamin received his bachelor of science degree with honors in nuclear engineermg from Oregon State University and is a candidate for a master's degree in nuclear engineering from the ' same institution. l l l l l l , m **8 . i i

             ,               SEAT BY:                                 8- 8-83 ; 4:56PM :           PSE&G LIC & REG-                                        813/14 1
  )

l f

                     .                 O             PSIBG Nuclear Business Unit 4

li I Joseph J. Hagan

  '                                    Vice President--Nuclear                                                             '?

l Business Support i 3. I . . .r. . t 4 i Joseph J. Hagan was named vice president of ' 1 - -E nuc! car business support in July 1995. He has

                                                                                                                                            ?q 
  !                                   overall responsibility for the following support                                                    1~

l functions: budget and strategic planning, infor-mation systems, external affairs, medical and in- -

!                                     Processing.                                                                                                        '

1 Haganjoined PSEAG in 1970 and has held a y . :* . ww spy. i ql . .M , g number of supervisory and senior management 9, i " k SEst i j positions, including vice president of nuclear operations, general manager of Hope Creek

                                                                                                $                  Q                  Th'$

[ operations and general me. nager of Salem operations, maintenance manager and station planning manager at Hope Creek Generating j Station, and senior maintenance supervisor a.t Salem Generating Station. Prior to joining the j Nuclear Business Unit, he was a supervisor at Mercer Generating Station and spent several years

in the Electric Transmission and Distribution Department of PSE&G.

l Hagan holds a bachelor of science degree in electrical engineering and a master of science degree l l in engineering management from Drexel University. He has completed the program for Manage-i ment Development at the Harvard Business School, the Advanced Management Course at Rutgers University anc was licensed by the Nuclear Regulatory Commission as a senior reactor operator for Hope Creek Generating Station. In addition, he holds a boiling water certification from General Physics. i I

                                    &gan serves as campaign chairman for the Salem County March of Dimes WalkAmerica.

} l i 4 I am, sees l l [

    ,     SEST BY:                                                                              8- 8-95 . 4:56PM     PSE&G LIC & REG-                                                      814/14 I

O PSEG Nuclear Business Unit Leon R. Eliason l L 7

      ,              Chief Nuclear Officer &                                                                     :z~                                           #.                      n.

President-Nuclear Business Unit : ~-? ; ' es -

g

                                                                                                                 ;y d

j C:::.- ;;';; . ._ T; ~~'~""

!                    Leon R. Eliason was named chief nuclear officer                                             = . "Z~.                                                       TC=""
 )                   and president of the Nuclear Business Unit in                                               =~~-.                                            -

FM.- - October 1994. He is responsible for all operational ?~:u - d and support activities for the two unit Salem Gener. . { ating Station and Hope Creek Generating Station. _ A.

)                    As CNO and president. Eliason reports to Public                                                        - ,                       E Service Enterprise Group CEO E. James Ferland.                                                                                   I l                    Ehason came to PSE&G's Nuclear Business Unit i                    aner servmg as president-generation for Northem States Power (NSP) in Mmnesota, where he oversaw the operation of fossil and nuclear power generatmg plants and related activities. He previously served at NSP as vice president--nuclear generatum, general manager-nuclear plants, Monticello plant manager and as a radiation protection engmeer

} He has been involved in the nuclear industry for more than 25 years. t l Eliason holds a bachelor of science degree in mechanical engineering from the South Dakota School of Mines and Technology, and is a graduate of the University of Minnesota Management Institute. i He is cunently active in the following professional groups: !

Association of Edison Electric Illuminating Companies' Power Generation Committee i e Insutute of Nuclear Power Operations' National Nuclear Accrediting Board

' He was chairman of the New York Power Authority Advisory Group, and was a member of the j following industry organizations: l e Washington Public Power Supply Corporate Safety Review Board j e NRG Energy. Inc. j e American Nuclear Society ! Elinson also served on the Board of Directom of the St. Croix (Minn.) Catholic Consolidated j Schools, and is a member of the Stillwater (Minn.) Knights of Columbus and the Metropolitan j Economic Development Board. l l l fee 1994 t i I l

FRIDAY m ,m, ,,,,

ua l

        @I   !j  MRC approves much of Unit 1 outage scope i        l              Several actions are under way in the                        review and approve:

l NE Salem Restart Plan following seven meetings a work scope to be performed during

of the Management Review Committee unit outages; 1 (MRC). The committee performs a critical

inclusion of emergent issues in the j function in the Restart Plan, noted Jerry outage scope; Ranalli, MRC vice chair, in an FYI yester- = department and programmatic readi-

! day. The group is led by Lee Catalfomo and ness determined by self-assessments; } in addition to Ranalli includes Tom Spencer,

affirmations ofnear-term IMPACT Frank Thomson, Greg Suey and Dana action plan completion; and l Cooley. The MRC " exercises oversight and a closure of all items affecting startup,

{ approval of work scope necessary to ensure a assuring system and integrated j safe, uneventful restart of Salem Units 1 and station readiness for restart.

!               2, followed by reliable, long-term runs,"                                  A large portion of the Unit 1 outage

{ wrote Ranalli. scope has been approved, including The first step of the Restart Plan is to 3,300 work orders. Ninety-two work i evaluate plant issues and proposed actions orders, primarily dealing with service j according to the established restart screening water, have been excluded. Typical Unit ! criteria. (A complete list of the criteria was 1 outage work scope inclusions are: I distributed with the FYI.) The MRC will = corrective and preventive mainte-nance; e^k climi"^ tion;

!                              The Bottom Line I                      N          Plant stats obtained from                                  = valve and pump rework; Daily Status Reports                                     . calibrations, surveillances and 4

certam mspections; Salem: Unit i: forced outage day 58

                                                                                            . limit switch adjustments;

! Days of Event-Free Operation - 12 (See MRC,page 2) ! Unit 2: forced outage

day 37 Days of Event-Free Operation = 10 Hope Creek: rorced outage Plant update Days of Event Free Operation = 17 Peach Bottom 2: 100 %, i.140 Mw

;                                               o ,iin, m 4,y,                             continue today at Salem Unit 1. No.

r. Peach Bottom 3: 73%. 758 Mw; end of fbcl 22 residual heat removal pump E'iYneYoU troubleshooting continues at Unit 2.

Peak Work on B residual heat re-Yesterday's PSEG peak 8.537 Mw moval room coolers was completed

O Today's estimated peak 8.965 M* yesterday at Hope Creek station.

i Stock Replacement of the A circulating DPggg- -~ 28

                                                               -1/8 water pump and repairs on the A control room chiller continue today.

pi

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SENT BY: 8- 7-95 : 8:15AM CNO & PRESIDENT-NBLH ;* 1/ 1 NRC Senior Management Plant Tour of Sales August 9, 1995 9:30 - 11:30 NRC Management tour plant with C. Marschall 11:30 - 1:00 Lunch with Residents 1:00 - 3:30 Interviews 1:00 - 1:30 J. Benjamin Director - QA/NSR 1:30 - 2:00 C. Warren GM Salem Operations 2:00 - 2:30 L. Storz Sr. VP - Nuclear Operations 2:30 - 3:00 E. Simpson Sr. VP - Nuclear Engineering 3:00 - 3:30 L. Eliason CNO & President NBU l 3:30 - 4:30 PSE&G Mangement de-briefing l l 1
/
Y i i l
; MRC Five-Day Look-Ahead (4:00-7:00 PM - Salem GM's Conference Room j unless otherwise noted) l I
l Date l Topies lPsesenter l 1 l { Friday, August 4 Diesel Generator System D. K+da#'M. Ranch + l 1 Turbine Bypass System Craig Johnson /M. Rencheck ' Ashok Moudgill & Project Monday, August 7 Outage DCPs (SG01 turbine :
runback, HEBA/MEBA, Managers j Feed Ring &J-tube Mods, , l Non-Safety 14 AWG Cable, i and 10 Others)
Operator Workarounds JeffBeattie l 13KV System Vijay Bhatia/M. Rencheck System Readiness Review TBD Tuesday, August 8 Configuration Walkdown George Englert Plawsmg , j DEF ReviewPlaning Craig Lambert ! l ControlRoom Annun/Indic. Len Rajkowski j System Readiness Review TBD .
-'^ System RM-Review TBD' d 1
Wednesday, August 9 Unit 2 Turbine Rotors BiH Schuhz ' f, A,Ww "R" Issues Biu McDevitt/M. Bursztein System Readiness Review TBD ' Systeun Readiness Review TBD Thurssday, August 10 4 ' Mech Maint ATS Items Mike Metcalf < System BM- Review TBD System Readiness Review TBD
Friday, August 11 RMS Issues John Cicconi i System Readiness Review TBD

System Readiness Review TBD I
P
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"***d r, --
f 1 8/4/95 3 09 PM )
i Systim ust - .4 ( i ? SYSTEM CODE VALUE NOT AVAILABLE (ATESI TO PROVIDE CODE VALUE)
ABD ,
'A' BUILDING y ABV AUX 1LIARY BUILDING VENTILATION SYSTEM (SALEM)
ACM ADMINISTRATION BUILDING j ADV j AF ADMINISTRATION BUILDING VENTILATION SYSTEM (SALEM) AUXILIARY FEEDWATER (SALEM) ANN
} ANNUNCIATOR (SALEM)
AR AIR REMOVAL, CONDENSER (SALEM) AUX AUXtLIARY BUILDING l BBD
'B' BUILDING l BBV I 'B' BUILDING VENTILATION BD '
d _ BUILDING AND EQUIPMENT DRAINS (CONVENTIONAL) (SALEM) l BR , BORIC ACID RECOVERY (CVC) (SALEM) BRB BREAKER REPAIR BUILDING
y BS BLEED STEAM AND HEATER DRAINS (SALEM) y CA CONTROL AIR (SALEM)
CAN Y CONTAINMENT BUILDING AND ELECTRICAL / MECHANICAL PENETRATIONS
/ CAV CONTROL AREA AIR CONDITIONING & VENT SYSTEM (SALEM) / CBV CONTAINMENT BUILDING VENTILATION SYSTEM (SALEM) y CBY d4062:. t&V CONTAINMENT PRESSURE VACUUM RELIEF SYSTEM (SALEM) y CC <
COMPONENT COOLING WATER SYSTEM (SALEM) _ gg d / /7 CARBON DIOX1DE, BULK SUPPLY (SALEM) CF I 1 f'1 V 0-(Wh b CHEMICAL TREATMENT (FEEDWATER CHEMICAL) (SALEM) , COOUNG GLYCOL SALEM j$CM j CH CHILLED WATER (SALEM) CL Page1 1 w
s Systzm ust CHLORINATION (SALEM) CM' COMMUNICATIONS (PUBLIC ADDRESS AND TELEPHONE)(SALEM) y CN STEAM GENERATOR FEED AND CONDENSATE SYSTEM (SALEM)
COM -
COMPUTER (SALEM) [ CP CONDENSATE POLISHING (SALEM) CPB CONDENSATE POUSHING BUILDING CPS CATHODIC PROTECTION (SALEM) CRN CRANES
y. CS
, CONTAINMENT SPRAY SYSTEM (SALEM) y CVC CHEMICAL & VOLUME CONTROL SYSTEM (SALEM) l y CW CIRCULATING WATER (SALEM)
CWH l CENTRALIZED WAREHOUSE CWI CIRCULATING WATER INTAKE STRUCTURE CWV CIRCULATING WATER INTAKE VENT (SALEM) I y DF FUEL OIL (DIESEL, GAS TURBINE, AND HOUSE HTG BLR) SALEM Y
" ESEL DI GENERATORS (SALEM)
DIK SHORELINE DIKE ! DM 1 DEMINERALIZED WATE.R SYSTEM (TURBINE AREA. RESTRICTED AREA) , '/ EHC ELECTRO HYDRAULIC CONTROLS SYGTEM (SALEM) ERD EMERGENCY RESPONSE DATA COMPUTER (NRC) FBR FIRE BARRIER (SALEM) FH FUEL HANDLING SYSTEM (SALEM) FHB FUEL HANDLING BUILDING FHT FUEL HANDLING TOOLS y FHV FUEL HANDLING BUILDING VENTILATION SYSTEM FLB 2 Page 2
- .-~ ,
SystIm List FLOOD BARRIER FO FUEL OIL SYSTEM (SALEM) FP FIRE PROTECTIQfJ SYSTEM (SALEM). FPH ' FIRE PUMP HOUSE' FS FILTER HANDL.G SYSTEM (SALEM) FW FRESH WATER SYSTEM (SALEM) GAS ARTIFICIAL ISLAND GAS STATION GBD STEAM GENERATOR DRAINS & BLOWDOWN SYSTEM (SALEM) GCS
' CABINET GENERIC CONTROL SYSTEMS (SALEM) y GEN MAIN GENERATOR (SALEM)
GHV GUARD HOUSE VENTILATION SYSTEM (SALEM) j GS ; Gl.AND SEALING STEAM & LEAK OFF (TURBINE) SYSTEM (SALEM) , y GT l GA6 TURBINE (SALEM) HBR l HBR/HELB BARRIER. l HHB HOUSE HEATING BOILER (SALEM) l y HSD HOT SHUTDOWN SYSTEM (SALEM) HT { HEAT TRACING SYSTEM (SALEM) i HVD HEATER VENTS & MISC. DRAINS (SALEM) HW HEATING WATER / HEATING STEAM (HEATING BOILER) SYSTEM ( HY HYDROGEN, BULK SUPPLY (SALEM) INS SEISMIC INSTRUMENTATION SYSTEM (SALEM) IPA INNER PENETRATION AREA ISt INSERVICE INSPECTION ACTIVITY j JET GAS TURBINE (UNIT #3) LPM LOOSE PARTS MONITORING SYSTEM (SALEM) i i Page 3 1 1
p. I I
L
SystIm List LTS LIGHTING & DISTRIBUTION, PLANT (SALEM) LW LIQUID WASTE (NON-RADIOACTIVE) (SALEM) MBR MBR-MELS BARRIOR. MC MISCELLANEOUS CONDENSATE (SALEM) MET METEOROLOGICAL TOWER SYSTEM (SALEM) y MS MAIN STEAM SYSTEM (SALEM) + pWid MM MSR MOISTURE SEPARATOR REHEATER STEAM & DRAIN SYSTEM (SALEM) MSV _ MACHINE SHOP VENTILATION SYSTEM (SALEM) N/A l N/A (SALEM) l NDA NUCLEAR DEPT. ADMIN. BUILDING Y NIS NUCLEAR INSTRUMENTATION SYSTEM (INCORE EXCORE) (SALEM) NSF , NUCLEAR SITE FACILITY OPA OUTER PENETRATION AREA PAR l PROCESS ALARM INTERFACE RACK (SALEM)
'/ PAS POST ACCIDENT SAMPLING (SALEM)
PB PLUMBING SYSTEM (SALEM) PC PENETRATION AREA COOLING SYSTEM (SALEM) Y PL VM actu!fE Fa=O STEAM GENERATOR FEED PUMP & TURBINE LUBE OlL SYSTEM (SALEM) PSB I PROCESSING BUILDING y RC REACTOR COOLANT SYSTEM (SALEM) y RCP REACTOR CONTROL & PROTECTION (SALEM)
} RCS ROD CONTROL (SALEM)
RG REFRIGERANT GASSES
')f RHR RESIDUAL HEAT REMOVAL SYSTEM (SALEM)
RM Page 4
Syst:;m List RADIATION MONITORING SYSTEM (SALEM) y RVL REACTOR VESSEL LEVEL INDICATION (SALEM) RXC REACTIVITY COMPUTER MONITORING SYSTEM y SA COMPRESSED AIR (INCLUDING PENETRATION COOLING)(SALEM) SBV SERVICE BUILDINGS VENTILATION SYSTEM (SALEM) y SEC SAFEGUARD EQUIPMENT CONTROL SYSTEM (SALEM) SF
]
SPENT FUEL COOLING SYSTEM (SALEM) SJ Y SAFETY INJECTION SYSTEM (SALEM) SQE SEQUENCE OF EVENTS SPD SAFETY PARAMETERS DISPLAY (SALEM) SPL STATUS PANEL (SALEM) SS SAMPLING SYSTEM (SALEM) SSP { SOLID STATE PROTECTION SYSTEM (SALEM) STP SEWAGE TREATMENT PLANT STY SECURITY SYSTEM (SALEM) SVB SERVICE BUILDING y SW SERVICE WATER SYSTEM (SALEM) y SWI SERVICE WATER INTAKE STRUCTURE y SWV SERVICE WATER INTAKE VENTILATION SYSTEM (SALEM) , SWY ) I SWITCH YARD TAC TURBINE AUXILIARIES COOLING SYSTEM (SALEM) TBv TURBlNE BUILDING VENTILATION SYSTEM (SALEM) TD TURBINE DRAINS SYSTEM (SALEM) TGA TURBINE BUILDING f TL TURBINE LUBE OIL, MAIN (SALEM) TRS Page 5
O SystGm List 4 TURBlNE MAIN TURNING GEAR AND ROTOR JACKING PUMP (SALEM) TSC TECHNICAL SUPPORT CENTER TV TELEVISION SYSTEM (SALEM) VC VISITOR'S CENTER WD BUILDING AND EQUIPMENT DRAINS AND VENTS (CONTAMINATED) WG WASTE GAS SYSTEM (RADIOACTIVE) (SALEM) WL WASTE LIQUID SYSTEM (RADIOACTIVE) (SALEM) WS WASTE SOLID SYSTEM (SALEM) YRD YARD AREA ZZ NO SYSTEM APPLICABLE 115 Y 115V AC SYSTEM (SALEM) y 125 , 125V DC SYSTEM (SALEM) [ 13 13KV AC, INCLUDING STATION POWER TRANSFORMER (SALEM)
/ 230 230V AC SYSTEM (SALEM) 250 250V DC SYSTEM (SALEM)
[ 28D 28V DC SYSTEM (SALEM) y 4KV . 4160V AC SYSTEM, INCLUDING AUXlLIARY POWER TRANSFORMER (SALEM) y 460 460V AC SYSTEM (SALEM) 500 Y 500KV AC SYSTEM, INCLUDING MAIN POWER TRANSFORMER (SALEM) bILY MCI-$ Ch 6 2Woches. Page 6
was round out hem depart mg s-nas Depamnant Supervisors staff moodng with Claymanager Wamss Gen La FaJkowski. This informadoc owing inforna wa 1 sneedng the sarne day.~' ,
=
eral 'Idanager Salem Station. Its was obtained by Len at hia t Plants are in a bad predicament also rolled out in a shop i
shutdownJim Ferland and the Board #
'Ibo above is a viable opdon dhe '. to the profitt
currently. Aho

a anem

The longnote People rangethat gainwith is tho' tho strengthrecord heat this sums Percepdon is wsean to have a "never-ne cf Salem fora profit" w.e e are not in an ostageer land" outlook on the stadon mer there have been u s. n We must raise production. WeSaturday have bnot ee a
c zoode. This past ng lot % Saturday a.fternoon. , Augu
-
w ks. since orders UNSAT1.Weneed the system walkdown susas 300 out 130 complete erland -
It willget a lot uglier and complete s hav worse e started bef per week. Our eekbacklog the' last 3 h ManagesnenuSupervison or. Itimprovep,. z r ses 1000 w ork v team, planning,u System walWWe have a lack n .a ', e . . a
. .g may remain ars 230 and 280.W, Engineers are goins to.a aifdaysf 10 h "-~~"'
s .e. Cire Water, etc.) WIN W
,'.;p:12bbsi'sicheduldTnis ours'piin.
ra n ng " schedule. A11that. woulsbe d.
. Clay willment sees with the shop.'..f stewards Sunday today. '-) Thursday and .
T
departments you are m' support organh tionly 2 de ..~ . - sauntisy.' We-
- ue the product we need, get "someon~e ons and Maintenance.
solving the problem.Ajobwhonot a on. Ifthe do it. support will working due organization to ae partsdo i 6s.i Ifo ss e s unacceptable.
not give n Im willnot say we did not work parts. We bener be gmting the part an g Clay has a couple of pet
1. h,,'s peetes job due to not having from pisn:Ing or the pack Cleanliness e wants 2 because yo/tooi. us to be aware of:
Working attire: control - Keep track of your tools D Seniors u lost yours or someone walked . o not order offnew with ones ours. Supervisors willbe in slacks and aand above willbe s rt and a tie.
' department Technicians need shirts toonalipresent image. - _ a professicollared present..the positive eima ..
s IR.m does not want to seege or offensive (i.e. any shirts th also. He willbe discussing
" Big Jobason,," shirts) with 4
at can be construed as har !
~
RECtlut0 F R 0 ri 3"9 777* 8. 3.1995 17826 p. 3
! l i l 1 1 i - l General Manager - Salem Operations - i
Clay Warren 4
l TOPIC: Restart Meeting with NRC 8/8/95 i l On Thursday, August 10. representatives from the Nuclear Regulatory Commission (NRC) will meet l with NBU senior managers in the Processing Center to discuss our plans for Salem Station Restart. Although this meeting is open for public observation, my expectation is that PSE&G employees will not l attend unless specifically notified by their managers. Given the importance of this meeting to the future i of Salem station, it is expected tb attract a significant amount of media attention. Therefore, we must ensure that adequate space is available for seating. Any significant information from the meeting will be communicated to NBU employees. In addition, the meeting will be videotaped and those tapes should be available next week if employees are interested. Attendees for the meeting will be as follows: Leon Eliason, Lou Storz, Bert Simpson, Jeff Benjamin, l Joe Hagan, Bruce Preston and myself. I would also like my direct reports to attend. i ! I appreciate your cooperation. a 4 4 i (
,. C ! )l i <
I
l 'I l i SALEM SALP; 6/20/93-11/05/94 . ENGINEERING AND TECH SUPPORT l sinmorgss l I
current engineering design work appears good. NRC Performance Assessnest ;
of sales. i 4 I J
Good engineering coordination with Westinghouse during failed fuel inspection at salem unit 1. Also, strict procedure compliance, good
< attention to detail and radiological control practices. (IR 94-01/01) 4
Good oversight and analysis of speed oscillation in unit 1 AFW pump during I startup. (IR 94-01/01)
Subsequent to initial questionable safety perspective wrt to the 2C EDG ) CAD liner failure, the licensee conservatively declared the 15 EDG (IR 93-27/27) inoperable. I
After shutting unit 2 down for the 2C CAD liner failure, the licensee initiated a significant Event Response Team. (IR 93-27/27) l i

The licensee properly completed package no. 6 of a DCP to improve l
independence and reliability of the SalrAn switchyared. The DCP provided l connection between two new offsite power sources and the new Unit 1 4
Circulating water switchgear. The sodification properly controlled the switchyard and safely completed package no. 6. (IR 93-27/27) 4
Procedures Upgrade Project closed out with 994 procedures upgraded; remaining it transferred to Procedures Maintenance Group. Inspectors 1
conclued that PUP had been a good initiative and effective in improving (IR 93-21/21/21) procedure quality.
Engiacering developed and implemented appropriate corrective actions in i response to the 4-3-93 inadvertent discharge of a carbon dioxide fire protection system. The inadvertent discharge, a result of water intrusion l into a junction box, did not result from inadequate design. (IR 93-a 21/21/21)
Reactor engineering support during unit 2 startups was a notable strength; the reactor engineers were extremely knowledgeable of reactor physics, professional in their duties, and in proper control of the startup; good
! communication and coordination between reactor engineering and operations.
(IR 93-19/19/18)
The licensee determined that the service water system did not share the cire water system vulnerability to debris induced trips. (IR 93-19/19/18)
Updated URI on EDG fuel injection studs; operability and 10 CFR 21 l reportability evaluations were appropriate. (IR 93-19/19/16)
Engineering properly and conservatively evaluated an ergency diesel
't i
I i . . .
]
} generator cooling water flow setpoint error. (Closed URI) (IR 93-20/20) i FEARN558ES: i
Engineering has not demonstrated the ablity to proactively seek out and I correct system and componest deficiencies (e.g., circulating water system, l rod position indication, excessive cooldows) NRC Performance Assessnest of Sales.
l l L i
Engineering work priorities not drivies by the the needs of the plant.
NRC Performance Assessment of sales.
NOV for sustained unit 2 operation at approximately 102.5% power. This ]
3 resulted from inaccurate feedwater flow instrumentation (indicated flow i lower than actual) . Affected setpoints steam Flow SI, OTdeltaT, OTdeltaP, NI high flus trip. Although the setpoints were aca-conservative, ] j subsequent engineering evaluation concluded that operating at up to 104.5% l power did not invalidate any of the conclusions in the accident analysis. j Engineering had the opportunity to identify the degraded feedwater flow instrument accuracy at the time it initially occurred, but did not due to
lack of rigorous root cause analysis. (IR 94-24/24)
* 'Tso (z# 14 -44@4) ' Repetitious problems with mais feedwater pump control Oil Power Unit i filters presented several challenges to operators. (IR 94-19/19) 2 1
'
The licensee contiamed to rely on short term corrective actions in response to a long history of problems with the EDs air start systems.
l (IR 94-19/19) s l l 1
Narginal control air system performance continued to pose challenges to l
! uneventful salem operation. (IR 94-19/19) j
In response to March 31, 1994, sales unit 2 safety Injection relief valve
! leakage, the licensee did not perform a detailed root cause analysis, nor l did the perform engineering calculations to evaluate the inapct of } possible SI flow diversion to the Pressuriser Relief Tank. The licensee i did not perform a thorough operability deter =1=mtion until questioned by 4 the inspectors. (IR 94-13/13) I
' The licensee failed to insure that the specified replacement parts were j l
installed in the unit 2 PORVs during the seventh refueling outage (spring l
. 1993). (IR 94-13/13) i-
Low RCs temperature coincident with spurious high steam flow signals l j caused the initial safety Injection actuation on April 7, 1994. Da three
{ previous occasions, the licensee had noted the spurious high steam flow signals, caused by pressure waves traveling up and down the steam line following a turbias trip, on three occasions previous to the April 7, j event. The licensee did not properly identifiy and correct the spurious steam flow signals on those previous occasions. (IR 94-13/13) i i i a i
---e-.- . - . , , , , , _
l 4 ii 4 , 4 j
In March 1977, the licensee modified controls for the main steam
. atmospheric relief valves (MS-10s). In performing the modification, the i licensee readered the valves incable of responding properly to increasing 4 steam pressure and preventing challenges to the mais steam code safety i vaJves. As a result, os April 7, 1994, a code safety lifted causing am j W,s cooldown and a seceed safety Injection actuation. To correct Ms-10 eperation, the licensee restored the circuit to its original j sonfiguration, and adjusted gain and timing circuits. These adjustments t ould have been conducted in 1977 to improve valve performance. In l
- uddition, although aware of the mis-operation of the Ms-10s, the licensee l did not take immediate action to correct the identified problem. (IR 94-13/13)
In 11 months following May 19, 1993, issuance of NRC Information Notice l 93-37, sales had not completed inspection of MOVs to identify eyebolts for removal and replacement. The eyebolt material is questionable, and the
eyebolts receive the thrust load during valve closing. The MOVs inside

containment had not been inspected during the unit 1 outage. None of the
.i identified eyebolts had been replaced with hex head bolts. The inspectors j concluded that PSEEG response was not timely. (IR 94-11/11) i After a plant trip caused by an EHC power supply failure, inspectors noted superficial troubleshooting of EHC power supply failures; in four previous ] failures the licensee either reset or replaced the power supply without i determining the fundamental root cause of the failure. (IR 94-04/04) 1 sustained operation of Salem unit 2 at in excess of licensed thermal power an unresolved item. (IR 94-01/01)
Lack of comprehensive knowledge of governor design hampered resolution of l
the problems (required NOED). (IR 94-01/01)
The licensee initially planned to replace the failed 2C EDG CAD liner
[ 4 within LCO time and remain at power without completing a root cause ! determination of the liner failure. Discovery of suspected crack j indications in the engine block forced the decision to shut unit 2 down.
(IR 93-27/27) i NOV (level III, $50k CP) for failure to control maintenance and surveillance activities. Examples included contractors removing spara j came for auxiliary feedwater control valves without proper authorization;
} workers performing wiring changes in a MOV for cooling supply to the spent { fuel pool heat exchanger without proper written guidance, and without , l l properly documenting the work accomplished; workers engaged in removal of i sw piping without a work package at the job site. (IR 93-23/23) t Degraded voltage protective relays for 4KV buses set non-conservatively; . an unresolved ites. (IR 93-19/19/18) . OINER: 1 i i * ' Failure to establish aggessive quality oversight of the salem facility. NRC Performance Assessment of sales. i s l 4
t l i
! O sffective engineering ovesight of vendor designed modifications not always i apparest. NRC Performance Assessnest of Sales.
i Management allowed equipment problems to esist that made operations i difficult for plant operators. The equipment problems in conjunction with
! the resultaat challenges to operators and operator errors prada=i===tly l caused the transiest on 4/7/94. (IR 94-80/80) (AIFp 4/8-2s/94) Esemples include Automatic rod control system not la service for a month preceding ! the event, requiring manual operator action to restore Tave during j 4/7/94 ovest.
short duration high steam flow signal previously identified on three
]
; occasions not properly resolved, caused spurious safety Injection.
j ' Automatic controls for the steam generator staospheric reliefs (Ns-l 10s) were not maintained. As a result of MS-10s faillag to operate, l a code safety lifted causing a cooldown of the solid RCS, and a ] second SI os low pressuriser pressure. The NS-10s were known to be j deficient since a modif acation in the late 1970s; modifications were i plammed but had not been implemented. The circulating water system was vulnerable to periodic grass l intrusions. The licensee had documented this vulnerability over a period of several years. l The licensee took appropriate action to address feedwater nossle weld j problems and thesaal sleeve erosion. (IR 94-19/19) l 4 l Overall, the program to meet the requirements of 10 CFR 50.59 was
ocusidered adequate. Bowever, inspectors were concerned that, is performing 50.59 reviews, engineers did not consider completed j modifications not yet reflected im FSAR updates. (IR 94-19/19) l The licensee took appropriate is determining the E M cause of a fire la
! October 1993. The fire resulted from grinding, that ignited pipe insulation. Corrective actions were appropriate. (IR 94-14/14) Analysis of the higher than espected number of reactor trips (174 l actual /110 espected for unit 1, 122/120 for unit 2) concluded that the i high rate resulted from operation during 1977-1981 for unit 1, and 1981- l 1 1984 for unit 2. Since then the units beve had significantly reduced trip l 1 rate (less than the 10/ year assumed in tas desiya). The licensee response l was reasonable and appropriate. (IR 94-14/14) J t 1 ! l l I d e ,o- -- _ _ _ _
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Page of l Salem Unit 1/2 OD-21-A-1 Rev. 5 i

SALEM GENERATING STATION UNIT 3 *h} OPERATIONS LOG 1 CONTROL ROOM NARRATIVE LOG DATE T!ME [ SYSTEM REMARKS { im (z 'skn i 4015 4Aa 6els . I nss LL nfCo /% rfaugh , A%lon l neb Ace . 8eS ' 64 hit 5 cin ShoHb ?I%uJ ,5bar+r l Nssp' B.'enev Whn P9sde'ni ACS- A10h AWI~ 100 cps' Atll kh n: < / / I / a 9enerttbrs c /trblite N.4 i 2005 Tl& &bkb a;ufoable urb'an 62.ZC-STMP-drg69 )$sr . n /a, Z.}C <S}od oAL Il Ik tm k ch Tb P4 )Nerm.hile bs/k b<M . i ' . 62.Tf-37 STh-0007[G.) do b<nve S Th.h ne.,e ab. s c;f ' 4 J Yorb -br 3 / papa C&. kCSCR'9 ac W ppa k7A 6 *abi'TDDn DM T!0. Arb/e'oS kn% e Sd 2T' -S~TSSP &o70 $ SG The NCO need onb.y sign'the log once immediately following his last entry at Shift Relief. Salem Unit 1/2 OD-21-A-1 Rev. 5 J

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TIME SYSTEM REMARKS & Clan < (m . '/Y ~ A, af///96 wrAsun . <b.$ " , , 4 ,l &As 9D u. m k < (.9% ~0 h AfW AJA h,,a E nd n>$xie Al -sexs si -m e o,n., , , , - ), M:r' 0/6 OH Ob #4 AYs xxA/. no el ss 46 ,,,,/N / JL eAsc) Afa3 xrAJ &/u KFAJ d 9. /d An/. A,m ///A :~;d d,ey 6m x-o rm n E,AJ rsxs san M x -sus A.,,L.j j /r/o DA cas 44 - f /~ J /L.cp J mr oA ss ed % /A s 9 TJAC $ n,l>A r l TJAJ tfA// Ar 47 QA O/f, Ux7L JMd A/ rA7s GA,zwo , nnm oaN r M A/ c;t1Aje xamo m ns, e>bsei-l /7// 4 11 Cm: abel di,h uW swba.re 22 ,2f1S4f _ / 73 3 O L) r}$A 0Y /7s<f VC. tJ% erb] A cu)l nee u n/e~e A - , W$ fff6 V '- b QblM bw7 })A/CS /Yf//fp The NCO need only sign the log once immediately following his last entry at Shift Relief. Page 4/ of Salem Unit 1/2 OD-21-A-1 , Rev. 5 . . - ~ SALEM GENERATING STATION UNIT I OPERATIONS LOG 1 CONTROL ROOM NARRATIVE LOG DATE - i TIME SYSTEM REMARK:3 /100 X t ysAs l i s aJS /M. dw.a r 7 l 4 Nsi sr. //iss s/ . A/cd Ditto.4oa g A l~ n Msv ' feo % 4 ,) /f'lc/fewo' en /rrex ////t1//S STA. sontss a Af3s P bew Phl4M * /d17*rs slo /Z 1T[ Ac'S s* O 'i'= 2Mr# 1 /11L Z/c (% sm 21i s'? 1 2 1 sc. J o rt. est- z /9y$* C t- C7nie7 :llns cc p SId/ .2/ CC PJwoi" bro tax ep t3st . i n rs */c cal.m n n r cas S J. 0r a. nwco a 2 L. 7939 23 % b/t e y L' po o L. S$/ L,s& 2 i r c-19 2eH &&B - bu rx. con S2 ~ct'sr T"st A wu( TcT;e s. .,e r+[ ?/6V tL Eti ka,sbreu /W71M of-ST- ra,tb erai r,.st ea m +-/76r k / SE s / f//' MOO STATUS %[he s'er/ ft- (le oes Mrwes ' Movlm fe hbp < b e~rrn vo h A f ,f The NCO need only sign the log once immediately following his last entry at Shif t Relief. Page [ of Salem Unit 1/2 OD-21-A-1 Rev. 5 I l * , i , cc - :- i SALEM GENERATING STATION UNIT ggg ~ ^ OPERATIONS LOG 1 CONTROL ROOM NARRATIVE LOG DATE ) TIME SYSTEM REMARKS t'306 X-sh4-t soss (norrie I mss Nea/y Simpn sTA ossf eco> ken - ras 5u Ab/mes txc Ne;neiser . Msylan % < n3 /20 manoQ nea Arens an ,. Mi rone I j ce /%'thos ,, LohK S~l'ATUS nene 8 A16 P AJO T ExTn,b hPrA - Y A/) rnds j Jaseded antaw&veu Grovo bemand a m w l s ' . ! ,oroblems : 21 + '14 sw P,os - h LI A wac5A l 2'18 e tres- %s ! 2616 cia 138 cwe Ws doe -bo h r*eh . screes i olf/u 1S3) cia 23 8 circ - % 604'l rc % c+ s2 . rt-r-- t . A)is - 0012 (G h 2 tJ3 z fu~ ne_ .

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~~O - 21 SALEM GENERATING STATION UNIT 7[;n ,~~

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~~OD - 21 SALEM GEE% TING STATION UNIT %_~~

~~OPERATIONS LOG 1 CCNTROL ROOM NARRATIVE LOG DATE O~/d3 TIME SYSTEM REMARKS~~

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~~Page d of 10~~

, Salem Unit 1/2 - OD-21-A-1 Rev. 5 n 1 .. l 1

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A.S. , i dyVO$46 /kcomiecta 2 5p / - SAX O'l42 14C D r'StoivwnYeD fSD 2 forc RPJ Ab 37/6TNsrl' l=AiTc? 7 f.A.F. : 6419 Vc 9 yoppeo c'onrs,wi,,,- r Bee rf f&et. o 4 91 EnaM ffat7eb 2D bleSe/ - /Hz S4ieV /E w-6S/S GMdM 4 vhtHf/9/VizfO 2BDi erel 70 Gk.'D 0615 fSdM $f3Da'sSef-6fffibo. Cl/K Cfc p/ cower.en / Sh z - EX17 % 9. o.S. OdM thtRr48 fB (JieSe/ ~dO. MF51% 4 i l i i The NCO need only sign the log once immediately following his last entry at Shift Relief. Page [- of b Salem Unit 1/2 OD-21-A-1 Rev. 5 l .# OD - 21 SALEM GENERATING STATION UNIT CONTROL ROOM NARRATIVE LOG DATE M ~ OPERATIONS LOG 1 TIME ' SYSTEM REMARKS l r 01 0 o WSMR facs Gm-a - . tvs< -Preteille m ' 5 in Rod :nN . N c n's Sn noo<a . [a I i - -r Neds Rdl '. P ./uniI ' cm [h A v.eet , <+L na o . Naf ner. M~ i / Iws~ 5 ' ll M C Yno *< I/t-i . DIask. i .'b a , + M ci t e 1 C l9 c < I)<7 1 osio Ib cL- caLo 4?,e Scs Em- : m o t. , & c-s.a. 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II It FH B V 12 YA 8 Crh m, A + T l F H a ra,on/c Ls _ o/< h nc III9 ?b$v%h FiM rkhaDI+ 2IFMA nohh Lx [k M I4dd 3 131 3i sfe, LvL c A ' 'Tb L 4.,,,/ 13 0 c ~en d.fl \ 1 6 < 4 90 G-8 I? u Tnc ) rio euE al /QG oJ n 7nc oc //g o ~ci 40m/c# ll tac oc o#/< I3D AP n Auv SA n o V<l 'g,, ~ ST AF 0021 . ace T.C . comoided hkG L r k 11 L & ,,tal 31 T3 h< exde) T3kh 2.3 2 & od .L 3 x - 5%d fh u-59r IKo cA% RLC Sonoa /669 Ista c're s RLs hs /6 73 \G % Nw RLC k u _lL 7 o AF o/( Kv4 31_Apf Is u dw P2R u. s it kL The NCO need only sign the log once immediately following his last cntry at Shift Relief. .Page of (n Salem Unit 1/2 OD,-21-A-1 'Rev. 5 - . . = . .-. 4 OC - 21 SALEM GENERATING STATION UNIT 9 b - V-Y ? ^ OPERATIONS LOG 1 CONTROL ROOM NARRATIVE LOG DATE TIME SYSTEM REMARKS YQ$ SY4 C b o LJ 0920 $O CLJ AD 9 hea.c1 -lv x +; ve 17e5 .s%k, < cidaled : w ed:L' asAs do hk He ~ ua & -e wh 3. T h.V T 6.P R nit <1+k e a ll adu1 hd<s in oeleb . ckM insedi- <Ld dow e h a k< . us:4 ll 'yheJe 3 ; weleJ . ; ~1 % skk alt AdAwal>sda ~ nm ALc Ry 4 a.'o ale'R < roer - wll<J Tshs 2.Jo 3 ; IIWg 1 & rJa A F' J:m br2A,me / I a t - 96 . .D - 9'o . ' i l J - 14 - CY' n - Tvo . ~ nm &F h r s:o{~ h v - esp- la' To F I4tv Tsn s ex,Vd $ 4 +s 2.t lI och W11 a}n3'l 04I h o The NCO heed only sign the log once immediately following his last entry at Shift Relief. Page of h Salem Unit 1/2 OD-21-A-1 Rev. 5 + . CD - 21 SALEM GENERATING STATION UNIT I OPERATIONS LOG 1 CONTROL ROOM NARRATIVE LOG DATE S-Y - TIME SYSTEM REMARKS 1900 33 OLud $ NosD4 tL \ e[- Id NE0 MUNV f359 d C, var 0;n dLO i T4X SO s L W W Nerd &s .NWf DN $ctLw'Gk ., hm v3 o.alsQ Fsv\aaa-Nds Wird 3, 85 ho SV7 F , 2234 Au6. ALL vd . % .\55, css S.'v m . tn ! zc sta po r/s ALL 0to kuuDk 226 - % 1940 Si l- z xAl vedwdd2 -4:e %dk Ms Asocmrw8u7 J2va veed44v conoudotr I l ir S w olR ve.S u.1 -% EL I % N opM _ ' Zool cheert E.7_. E d 5T~ 21\\ SN C. - & LL Loon ~TMclbT FA, zl l C Vb 8d 4. - hve2A VL [R . v 9s- c,ec Lo,uoA mo M thx kss -b 70* zom/L 69.3# c,n evnMo l cca sol ct 7 Z.L7 Y C. - Oc b A (4- . 2.~4 53 dN 4 72 CN d on - 40f c do. b g (QAltC.- OQ o_t DN o on / The NCO need only sign the log once immediately fo ast entry at Shift Relief. Page h of (n l OD-21-A-1 Rev. 5 Salem Unit 1/2 1 . \ / b noo .: ROD CONTROL SYSTEM - FAILED COMPONENTS STATUS. DESCRIPTION WSN PRESENT REMARKS STATUS (REPAIR & INTALLATION) SUPERVISORY DATA 183 A114 5/16/93 - REMOVED FROM A113. LOGGING REPAIRED ??? (LOGIC CABINET) 5/31/93,13:00 - INSTALLED IN A114. 13:30 - CBA GRP 2 NOT MOVING, REPLACED Z3. REINSTALLED TO A114. 6/3/93 3:50 AM - P/A CONVERTER AND PLANT COM.PUTER FAILED TO INDICATED FOR CBB, SBB, j REPLACED Z13. RETEST SAT. ! SUPERVISORY DATA 216 I&C 5/16/93 - INSTALLED IN A114 LOGGING SHOP REPLACED Z3. ! (LOGIC CABINET) 5/27/93, 8:40AM - REMOVED i FROM A114, REPLACED Z2,25, ; 23. 15:30 - REINSTALLED TO A114. 5/31/93, 10:45 - REMOVED l FROM A114 AND BENCH i TESTED, REPLACED Z3. SUPERVISORY DATA 217 ??? 5/16/93 - INSTALLED IN A113. LOGGING REPLACED Z8, 29, Z12. (LOGIC CABINET) 5/24/93 - REMOVED FROM A113. i REPAIR ???? 9 9 8 l, - ~ SUPERVISORY DATA 6014 A113 5/24/93 - INSTALLED IN A113 LOGGING 5/26/93 - REMOVED FROM A113 (LOGIC CABINET) REPLACED Z3 & 26. INTALLED BACK TO A113. REPLACED Z2, , 25 & Z8. REINSTALLED TO A113. REMOVED FROM A113, REPLACED Z2,25 & 26. REINSTALLED TO A113. REMOVED FROM A113 AND-TAKEN TO TRAINING CENTER FOR TESTING. FOUND Z3 BAD. REPLACED Z3, RETEST SAT. 5/27/93 - INSTALLED IN A113. RESTEST SAT. MOVE CBA, CBC GRP1 NO PULSE. REPLACED 23 & 26. REINSTALLED TO A113. 5/31/93, 10:45 REMOVED FROM A113 AND BENCH TESTED, 1 REPLACED Z3 & 25, RETEST I SAT. REINSTALLED TO A113. 13:30 - CBA GRP2 NOT MOVING, REPLACED 23. REINSTALLED TO A113. FAILED AGAIN, REPLACED Z3 RETEST SAT. l l PG 2 . l ~- . l I SUPERVISORY DATA 0039 l&C 5/2(i/93 - INSTALLED IN A113. LOGGING SHOP REMOVED FROM A113, (LOGIC CABINET) REPLACED Z3, 22, 28. INSTALLED IN A113 AGAIN. REPLACED Z2. ' Fall AGAIN, REPLACED Z2 & Z3. INSTALLED IN A113, REMOVED FROM A113 AND TAKEN TO TRAINING CENTER FOR TESTING, FOUND Z3 BAD. REPLACED Z3, RETEST SAT. 5/27/93 - REINSTALLED IN A113. FAILED AGAIN, REMOVED FROM A113 REPLACED Z3. INSTALLED IN A114, MOVE ROD FOR CBB NO PULSE, REPLACED Z3. RETEST SAT. 15:30 - REMOVED FROM A114, REPLACED Z3. l/O RELAY DRIVERS 132 l&C 5/16/93 - REMOVED FROM A713. (LOGIC CABINET) SHOP 5/28/93 - BENCH TESTED FOUND CR1, CR5, & CR9 SHORTED. REPLACED THE SHORTED DIODES, RETEST - SAT. 1/O RELAY DRIVER 139 l&C 5/16/93 - REMOVED FROM A714. l (LOGIC CABINET) SHOP 5/28/93 - BENCH TESTED FOUND CR1 SHORTED - REPLACED CR1, RETEST - SAT. 1/0 RELAY DRIVER 120 l&C 5/16/93 - INSTALLED IN A713. (LOGIC CABINET) SHOP 5/26/93 - REMOVED FROM A713. 23:50 - INSTALLED IN A713. 5/27/93 5:00 AM - REMOVED FROM A713. SUSPECTED BAD INPUT DIODE. 5/28/93 - BENCH TESTED FOUND CR1, CR9, CR17 SHORTED. REPLACED SHORTED DIODES, RETEST - SAT. PG 3 l .. l ~ 1/O RELAY DRIVER 133 l&C 5/16/93 - INSTALLED IN A71'4. (LOGIC CABINET) SHOP 5/26/93 - REMOVED FROM A714. SUSPECTED BAD INPUT DIODE. 6/9/93 - BENCH TESTED FOUND Q10 OPEN. l/O RELAY DRIVER 695 l&C 5/26/93, 2:OOAM - NEW FROM (LOGIC CABINET) SHOP FOLIO, INSTALLED TO A714. 8:00 AM - REMOVED FROM s A714. INSTALLED IN A714. 23:50 - REMOVED FROM A714. SUSPECTED BAD INPUT DIODE. 5/28/93 - BENCH TESTED FOUND CR1 SHORT, REPLACED CR1 - RETEST SAT. 1/0 RELAY DRIVER 681 I&C 5/26/93 - NEW FROM FOLIO, (LOGIC CABINET) SHOP INSTALLED TO A714. SWAPPED WITH S/N 695 - NO CHANGE. RESTORED TO A714. REMOVED FROM A714 AND INSTALLED IN A713. 23:50 - INSTALLED IN A714. 5/27/93, 5:00 AM - REMOVED FROM A714. SUSPECT BAD INPUT DIODE. 5/28/93 - BENCH TESTED FOUND CRS, CR17 SHORTED. REPLACED CRS, CR17 - RETEST SAT. 1/O RELAY DRIVER 701 l&C 5/26/93, 8:00 AM - NEW FROM (LOGIC CABINET) SHOP FOLIO, INSTALLED TO A713. REMOVED FROM A713. SUSPECTED BAD INPUT DIODE. 5/28/93 - BENCH TESTED FOUND CR1 SHORT. REPLACED CR1, RETEST SAT. 1/O RELAY DRIVER 845 A713 RETRIEVED FROM TRAINING (LOGIC CABINET) CENTER, AND INSTALLED TO A713. PG 4 o .- 1/O RELAY DRIVER 342 A714 RETRIEVED FROM TRAINING'. (LOGIC CABINET) CENTER AND INSTALLED TO A714. SLAVE CYCLER 0079 TB2 5/28/93 2:26 AM - REMOVED STATIONARY FROM A501, TESTED BAD ON DECODER - GO2 TEST RIG. (LOGIC CABINET) SLAVE CYCLER 0083 A501 5/28/93 - BENCH TESTED SAT. STATIONARY INSTALLED IN A501 (22AC DECODER - GO2 STATIONARY). (LOGIC CAB) SLAVE CYCLER 0080 TB2 5/28/93 - REMOVED FROM A511, MOVABLE DECODER TESTED BAD ON TEST RIG. GO3 (LOGIC CAB) SLAVE CYCLER 0072 A511 5/28/93 - BENCH TESTED SAT. MOVABLE DECODER INSTALLED IN A511 (22BD GO3 SLAVE DECODER MOVABLE. (LOGIC CAB) FIRING CARD 0395 I&C 5/30/93 - REMOVED FROM SLOT (POWER CAB) SHOP D1 OF POWER CABINET. INTERMITTENT FAILURE. FIRING CARD 6120 POWER 5/30/93 - NEW FROM FOLIO, (POWER CAB) CAB D1 BENCH TESTED SAT. INSTALLED IN SLOT D1. l PHASE CONTROL 366 I&C 5/30/93 - REMOVED FROM SLOT (POWER CAB) SHOP E1. PART OF THE INTERMITTENT FAILURE CIRCulT. REPLACED FOR RELIABILITY. PHASE CONTROL 364 POWER 5/30/93 - NEW FROM FOLIO,

~~(POWER CAB) CAB E1 BENCH TESTED SAT. INSTALLED IN SLOT E1.~~

i t' PG 5 ~ REGULATION 297 l&C 5/30/93 - REMOVED FROM SLOT ~ CIRCUlT GRIPPER SHOP F1. 'PART OF THE INTERMITTENT (POWER CAB) FAILURE CIRCUIT. REPLACED FOR RELIABILITY. REGULATION 6053 POWER 5/30/93 - NEW FROM FOLIO, CIRCUlT GRIPPER CAB F1 BENCH TESTED SAT. INSTALLED (POWER CAB) IN SLOT F1. 1/0 AC AMPLIFIER 372 I&C 5/30/93 - REMOVED FROM A803. (LOGIC CAB) SHOP l/O AC AMPLIFIER 144 ?? 5/30/93, 2:45 AM - BENCH (LOGIC CAB) TESTED SAT. INSTALLED IN A803. 19:51 - REMOVED FROM A803, REPLACED Q13, Q14 - STILL DEFECTIVE. REPAIRED ??? l/O AC AMPLIFIER 122 A803 5/30/93, 20:40 - INSTALLED TO (LOGIC CAB) A803.(THIS CARD WAS PRIVOUSLY REPAIRED BY VARTEK). 1/0 AC AMPLIFIER 146 77 5/30/93 - SPARE CARD, TESTED (LOGIC CAB) UNSAT. l/O AC AMPLIFIER 142 A814 5/30/93 - BENCH TESTED FOUND (LOGIC CAB) DEFECTIVE, REPAIRED. REINSTALLED TO A814. 1/0 AC AMPLIFIER 147 A808 5/30/93 - BENCH TESTED FOUND (LOGIC CAB) DEFECTIVE, REPAIRED.

~~REINSTALLED TO A808.~~

I/O AC AMPLIFIER 149 A812 5/30/93 - REMOVED FROM A812 l (LOGIC CAB) BENCH TESTED FOUND DEFECTIVE, REPAIRED. ! REINSTALLED TO A812. l/O AC AMPLIFIER 150 A813 5/30/93 - REMOVED FROM A813, (LOGIC CAB) BENCH TESTED FOUND DEFECTIVE, REPAIRED. , REINSTALLED TO A813. l 1 r PG 6 1/0 RECEIVER 28 A809 5/30/93 - REMOVED FROM 809,' (LOGIC CAB) bet 4CH TESTED FOUND l DEFECTIVE, REPLACED Q12. REINSTALLED TO A809. SLAVE CYCLER 80 I&C 5/31/93 21:35 - REMOVED FROM , LOGIC (LOGIC CAB) SHOP A514, BENCH TESTED UNSAT. l FOUND PIN 8 LOW, SHOULD BE I HIGH (12.5 - 15 VDC). SLAVE CYCLER 82 A514 5/31/93 - BENCH TESTED SAT. LOGIC INSTALLED IN A514. (LOGIC CAB) P/O BANK OVERLAP 14 l&C 6/01/93 19:10 - REMOVED FROM LOGIC SHOP A207, BENCH TESTED UNSAT. (LOGIC CAB) FOUND PIN 10 LO SHOULD BE HIGH (12.5 - 15 VDC). P/O BANK OVERLAP 81 A207 6/01/93 19:16 - BENCH TEST LOGIC SAT. 'lNSTALLED IN A207. (LOGIC CAB) POWER SUPPLY 5/26/93 - REPLACED 100VDC (LOGIC CAB) AUX POWER SUPPLY FUSES 5/30/93 - REPLACED 2 FUSES, (POWER CABINET) F11,F6. 6/9/93 - BENCH TESTED INCONCLUSIVE. AUCTIONEER DIODE 5/30/93 - REPLACED 1 NEGATIVE (LOGIC CAB) 15 VDC AUCTIONEER DIODE

~~(SHORTED).~~

6/9/93 - BENCH TESTED FOUND } AUCTIONEER DIODE SHORTED. LOW VOLTAGE 5/30/93 - REPLACED 2 FILTERS, POWER SUPPLY A16 FL1 & FL2 FILTERS NOTE: The spare parts, chips and diodes (1N4148), are availalble in the l&C shop for replacement. PG 7 p pages 8 STEP COUNTERS' MODEL SERIAL PRESEN COMMENTS WHITTAKER NO T STATUS 127FD100A *2072 I&C NEW ARRIVED FROM S/3 1 SHOP COMMONWEALTH ED. 6/9/93 - CONTINUITY CHECK FOUND: ADD COIL 600 OHMS, SUB COIL 600 OHMS, RESET COIL 83 OHMS, ADD +SUB 1.2 K OHMS 127FD100A 20698 l&C 5/16/93 - NEW ARRIVED S/3 SHOP FROM FLORIDA POWER & LIGHT, INSTALLED TO CBS GRP1. 5/25/93 - REMOVED FROM CBB GRP 1. 6/9/93 - CONTINUITY CHECK FOUND : ADD COIL 629 OHM, j SUB COIL 605 OHMS, RESET COIL 81.5 OHMS, ADD +SUB COILS 1.2 K OHMS 127FD110A '8795 I&C 6/9/93 - CONTINUITY CHECK . S/3 SHOP FOUND: ADD +SUB 3.4 M . OHMS, RESET COIL 86.4 OHM, COMMON OPEN. 127FD100A 8831 l&C 5/14/93 - REMOVED FROM S/3 SHOP CBB GRP 1. 6/9/93 - CONTINUITY CHECK FOUND: ADD COIL 913 ; OHMS, SUB COIL 914 OHM, RESET COIL 87.4 OHMS, AD+SUB COIL 1.8 K OHMS I , pages 9 127FD100A 20702 I&C 5/16/93 - NEW ARRIVED , S/3 SHOP FROM FLORIDA POWER & LIGHT, INSTALLED IN CBC j GRP 1 . l 6/9/93 - CONTINUITY CHECK i i FOUND: AD CDIL 816.6 OHMS, SUB COIL OPEN, RESET COIL 81.6 OHMS, l 127FD100A 8818 I&C 5/14/93 - REMOVED FROM S/3 SH'iP SBA GRP 2. , 6/9/93 - CONTINUITY CHECK FOUND: ADD COIL 902.5 Il OHMS, SUB COIL 909 OHMS, RESET COIL 84.9 OHMS. 127FD110A

~~I&C 6/9/93 - CONTINUITY CHECK S/3 20183 SHOP FOUND: ADD COIL 820 OHMS, SUB COIL 813 OHMS, RESET 81.5 OHMS.~~

~~127FD100A 20719 I&C 6/9/93 - CONTINUITY CHECK S/3 SHOP FOUND: ADD COIL 627.7 OHMS, SU3 COIL 608.7 OHMS, RESET COIL 81.5. 127FD110A~~

~~l&C 6/9/93 - CONTINUITY CHECK l S/3 20182 SHOP FOUND: ADD COIL 806.2 OHM, SUB COIL 812.4 OHMS, RESET COIL 81 OHMS.~~

127FD100A 20696 CONTR 5/16/93 - NEW ARRIVED j S/3 CONSOL FROM FLORIDA POWER & E LIGHT, INSTALLED IN CBA GRP 1. 127FD110A 20730 CNTR 5/16/93 - NEW FROM FOLIO S/3 CNSOL 37-7001, INSTALLED TO SBA ' GRP 2. 127FD100A 8830 CNTR 5/14/93 - REMOVED FROM S/3 CNSOL CBB GRP 1. 5/25/93 - INTALLED BACK TO CBB GRP 1. pages 10 127FD100A 8837 CNTR 5/14/03 - RMOVED FORM S/3 CNSOL CBC GRP 1. 5/25/93 - INTALLED BACK TO CBS GRP 2.

~~These counters have a problem with lable.~~

I i i 1 l , l -aa- .- 4-. . _. * * ._a .e .. e n em m a #=*4.#--%*. 4-w - - - - - m--- , . s. , O i O GENERIC ASSESSMENT OF 'THE SALEM EVENT E 'fNRC PRESENTATION t 1 w i T JUNE 14,1993 i ? 2 7 ll __ _ _ _ _ . _ ____ . .= _ _ _ _ _ - __ _ ___ _._ ._ _ ._ _ _ _ _ )* 4

~~GENEHIC ASSESSMENT OF SALEM EVENT i~~

1 I INTRODUCTION l r PURPOSE j i :

~~Meeting at NRC's Request l~~

~~i l l OBJECTIVE F l~~

~~To provide an open forum in which !~~

~~! to; discuss the issues surrounding l the Bad Control System Event. l~~

~~To updete the NRC on the latest~~
~~status of the W/WOG evaluations of I l this issue.~~

~~i i e To address NRC questions with ! respect to plant safety and operability. l !~~

~~To outline W/WOG future actions.~~

~~I j suou wren J 1 !~~

GENERIC ASSESSMENT OF SALEM EVENT l l AGENDA !

Overview and Status (WOG/WD !

1 - Objective Newton l Meeting l l - Agenda Review Newton - Status Newton - WOG RRG Activity Newton .y e Background Liparulo - Overview of the Rod Fowler ; Control? System - Descripti'on of the Carrier Salem Event - Failure Analysis Fowler EUDt.5 wW13

lo

' ' GENERIC ASSESSMENT OF SALEM EVENT * . Westingho'use Technical Evaluation l 4 i j - Regulatory Bases Lang i \

~~- Classification of Vertes Postulated Events~~

~~! - Analysis of Postulated Johansen~~

~~Events~~

~~- Equipment Performance Closky l History l j - Safety Assessment Vertes I i 3~~

~~Operability Assessment Newton~~

~~Action Plan Newton j~~

~~SUOU WWte I 2 l:- ' ' GENERIC ASSESSMENT OF SALEM EVENT i l STATUS i l~~

~~The Salem plant-specific j evaluation is underway. '~~

~~1 i~~

~~Westinghouse and the WOG are l l continuing to evaluate the generic~~
~~aspects of the event.~~
~~The Westinghouse Reasonable~~

! Assurance of Safe Operation (RASO) ! "e adequately addresses concerns l regarding plant operability and the ; j health and safety of the public. !

~~e All plants should continue operation ,~~

l and/or start up. i i l 4 suots ww5 - GENERIC ASSESSMENT OF SALEM EVENT WOG RRG ACTUATION 6/7 Mon. PM W Notify WOG Chairman of Event at Salem Details Limited 6/8 Tues. AM A. Thadani Request WOG Chairman that RRG be Activated 2 5 Questions Faxed to WOG Chairman i (RRG Chairman Unavailable) 4 l 6/9 Wed. AM WOG Chairman RRG Vice President Hold i Event Review Meeting I AM - Telecon with RRG Chairman and Other Members 6/10 Thurs. AM RRG Officially Activated First Full RRG

~~Briefing and Responses. WOG Chairman and WOG Vice Chairman' at W for Review and Evaluation .~~

l PM Conference Call with NRC, WOG, W and i Salem Site Reps Discussion of Rod Control System - Safety Evaluation - Event Probability. Fax NRC W Draft Customer Advisory Letter ~ 1:00 a.m. t 'WOG Chairman is a member of RRG also SUDES WMIT GENERIC ASSESSMENT OF SALEM EVENT WOG RRG ACTUATION 671.1 Fri. AM 2nd RRG Conference Call Review and Evaluation W Customer Advisory Letter PM Conference Call with NRC, WOG, W, and Salem Site Reps Discussing l Advisory Letter and Monday 6/14 Meeting Agenda o : ( h l e l l : i suou wnn GENERIC ASSESSMENT OF SALEM EVENT ROD CONTROL SYSTEM OVERVIEW l 1 i Tine Rod Control System positions rods in response to demands for motion from either the Reactor Operator or the Reactor Control System. The Rod Control System is a Non-Class 1E system. 1 1 System

~~Description:~~
~~s A Control Rod Drive Mechanism (CRDM): i - Normal withdrawal sequence Normal insert sequence k Response to reactor trip t~~
~~Control rod arrangement:~~
l - Rod banks, shutdown and control Rod groups 3 Control bank overlap e Rod Control System cabinets e Slave cycler description 4 .i SUDEA WPFff 4
l.- GENERIC ASSESSMENT OF SALEM EVENT A FIGURE 1 ! ' CONTROL ROD DRIVE MECHANISM i i i
~-
~~5 Guide Tube N Lif t Pole ,~~
Lif t Coiil l l' - Flux Ring Lif t Armature Mouuthe i Coil ] f Movable Gripper 4
~~, '0) o ~~~
~~o _I - Movable Gripper~~
~~f a g Armature~~
-g
~~_- (Shown Open) 3 ! Q{ fir g~~
~~- Stationary Flux % Pole Stammany # :~~
l , ' i f o BN i " " Stationary Gripper
~~.i Armature i~~
a ,, Stationary Gripper ! DriveRod : 4 l
i
~~; GENERIC ASSESSMENT OF SALEM EVENT~~
! FIGURE 2 i CONTROL ROD ARRANGEMENT i i I l i~ Shutdown Banks S 8 Rods' A SB ' 8 l E2E E S c lilEEEW 4 w ,
~~, 22E22 S D !!!!!!!!!!$!!!!!!!!!!!!! 4 l~~
~~If,j!! " { . ljy SE M1\i 4 m = n a Em en~~
~~i vi i i Ix i i Control Banks~~
~~' ~~~
~~Z M4 Rods A~~
~~~ ~ E ~~~
E _1E _2 E B 7/////M 8 ' \ c lW677A 8 i D l$in$$$15 i I 4 i 4 e -- + , - r--- -
i - GBiERIC ASSESSMENT OF SALEM EVENT .
~~FIGURE 3 l BANK OVERLAP l~~
JV[f*
~~! Full - -~~
~~l Out erlab - Overlap Overlap l y iiFiii jy!!! Roc i Travi .fLi, i~~
~~?! ,~~
wi
Bank Bank Bank

Full f s B C D in . _
l i I 128 228 256 356 384 484 612 i S1 S2 S3 S4 SS S6 Total Step Count l. 1 .l
I GENERIC ASSESSMENT OF SALEM EVENT FIGURE 4 ROD CONTROL SYSTEM BLOCK j i DIAGRAM i' t 1 i i : 200 VAC CROM
~~/A - -~~
~~M otor I G8" (1 Of * )~~
~~%8 - MII - Generator KRS Reactor l %C - - (1 of 2) _g r Protection I~~
i Reactor Trip Trip Signals ! I Bkrs l ON To DC Logic ' I Hold 2: XFMR , m ,,
~~! Cabinet -~~
Lift Cabinet l Power Cabinet l Current (1 of 5) J { Main 120VAC Current Commands _ j * ' ~ Movable l Group Select _ Current l I . . I I I l
~~' .l~~
! *Auxelary l ! 120VAC " "" DC ""*"' ! Hold I l I Cabinet " 125 VDC i or ,
~~7~~
Control , PA Converter : Control Bank Height I Bank Steps ^ to Process Control i e f i i l I
9 GENERIC ASSESSMENT OF SALEM EVENT ROD CONTROL SYSTEM OVERVIEW : System Operation from Startup to Full Power:
~~Startup tests i e Individual bank operation~~
~~e Manual operation with bank overlap h + /f% .~~
e Automatic aperation: Response to changing Tavg i g i - Response to changing load o Operator interaction e Rod Motion Surveillance Tests o l Rod Control System response to a reactor trip: } .
e AC power removed from Power Cabinets

e Current removed from CRDMs e CRDMs release rods A reactor trip signal overrides all Rod Control System signals.
suou wwe
p GENERIC ASSESSMENT OF SALEM EVENT
~~; ROD CONTROL SYSTEM INDICATIONS AND ALARMS 6~~
~~4 l RoslPositionqnd Movement Indications:~~
* (Aw6l*3/
~~e Individual Rod Position Indication (IRPI)~~
* ' Group step counters j i !
~~e IN/OUT demand lights~~
Rod Insertion Limit (RIL) recorder l

Rod Bottom lights Alms m s:
~~f I e Rod Control Urgent Alarm i !~~
~~Rod Control Nonurgent Alarm l~~
~~i * . Rod Deviation Alarm~~

~~Rod Insertion Limit Alarms x~~
~~.** Rod Bottom Alarm~~
~~Control Bank D Withdrawal Alarm s~~
suou =,.. t i
L .. GENERIC ASSESSMENT OF SALEM EVENT i DESCRIPTION OF SALEM EVENT l I TheBeactor Operator demanded outward motion of shutdown l bamik'A: ) [ $* SBA step counters read 20 steps l

~~Mb rod movement observed on IRPI i .'~~
~~Theitmactor Operator demanded in motion of shutdown bank A: i~~
~~With step counters at 6,1SA3 indicated 8 steps j ee ENth step counters at 0,1SA3 indicated 15 steps~~
)* <* AW other rods indicated 0 steps J RodPosition indication was verified by voltage checks. ISA3 stationary gripper fuse was pulled to insert rod. 1 i Lift coil disconnects were opened to prevent rod movement i , l Recaudings were made of Shutdown Bank A current orders. i Distorted wave forms were identified. i t
~~! Twocircuit board failures were identified. )~~
~~i The technical investigation is continuing. j suou wwn:~~
)
GENERIC ASSESSMENT OF SALEM EVENT FAILURE ANALYSIS Two circuit failures were located in the Logic Cabinet slave cycism. Teneeffect on the slave cycler current orders, both singly and in confination, would have the following effects: FAE.1)RE IN ONLY OUT ONLY BOTH (SALEM) IMMAND IN OUT IN OUT IN OUT 1RDT10N IN NONE NONE OUT NONE NONE MND (NORMAU OR OR (NORMAU OR OR OUT OUT OUT OUT CMUSIONS: i
~~Save cycler current orders sent to all CRDMs in rod i poup~~
~~! e CRDMs may respond with outward motion j e CRDMs cannot respond with inward motion .~~
Rods cannot move in both directions simultaneously

The failura .annot create a motion demand e The failure has no effect on bank overlap e The failure CANNOT prevent a reactor trip SuDSS WM(13 i l
~~- GENERIC ASSESSMENT OF SALEM EVENT l ACCIDENT ANALYSIS !~~
~~4 CONSIDERATIONS .~~
~~1 i~~
i so IIEGULATORY BASES i ! i em CLASSIFICATION OF POSTULATED l EVENTS i*
~~Jo ANALYSIS OF POSTULATED l EVENTS l~~
~~j - LIMITING SCENARIOS l i - ASSUMPTIONS i~~
~~- RESULTS l ~..~~
SUOES WFF118
1 GENERIC ASSESSMENT OF SALEM EVENT
~~' CONCLUSIONS :~~
l Bandahh failures in control systems are i motassumed nor required to be i assumed concurrent with an Anficipated Operational Occurrence , 1(ADD) or Design Basis' Accident (DBAD
~~- Consequences of postulated failure (sD in 1thernal control system do not exceed endinangical release acceptance criteria 1~~
Nhed for ANS Condition 111 events l Snfrequent Faults) i i l All pinants should continue operation l and/or start up. l . i I l l
GENERIC ASSESSMENT OF SALEM EVENT CURRENT REGULATORY BASES 8 [EEE-279
)
i
tlEE-379 l 1

iMUREG-0800 (SRP)
~~~ . )~~
~~a l I l i I i i suots wastis~~
?
~~I l. GENERIC ASSESSMENT OF SALEM EVENT I i IEEl 279-1971 i J l~~
~~Section 4.2 Single Failure I~~
Any sipgle failure within the j sprotection system A GI not prevent ; j~ aproper protective action at the j j : system, level when required." 1 I I i i i i i SUDESW Mitt
l GENERIC ASSESGMENT OF SALEM EVENT i ) . IEEE 379-1977 l, l Single Failure Criterion for Nuclear Power l ! , Generating Station Class 1E Systems l 1 l
"The protection system shall be capable of l g performing the protective actions required to

j accomplish a protective function in the presence i of any single detectable failure within the system

g concurrent with all identifiable but nondetectable j g failures, all failures occurring as a result of the l- g single failure, and all failures which would be i caused by the design basis event requiring the l g protective function."
~~i r j fondetectable Failures i i e~~
~~... A failure which cannot be detected by specific~~
~~} , system tests is nondetectable." l i~~
~~... In the analysis of the effect of each single failure, all identified nondetectable failures shall be~~
~~) assumed to occur."~~
~~l 6U055 wNitt i~~
~ GENERIC ASSESSMENT OF SALEM EVENT I
~~NUREG-0800 STA'NDARD REVIEW PLAN i OERPTS FROM SRP SECTION 15.2.7 i~~
~~! ww=ce of events from initiation until a stabilized inlidon iis; reached is reviewed to ascertain:~~
~~F The exalent to which normally operating plant~~
~~.iinstnserientation and controls are assumed to~~
~~functinsi.~~
The extent to which plant and reactor protection syM- are required to function. ! The credit taken for the functioning of normally l operating plant systems. i 1 j The operation of engineered safety systems that is
~~wsquired.~~
l l l k
GSEBIC ASSESSMENT OF SALEM EVENT ACCEPTED ANALYSIS ASSUMPTIONS
~~; AND CONTROL SYSTEM OPERATING ASSUMPTIONS~~
~~RandomEingle Failure in Protection System~~
~~'Assuned Concurrent with initiating Event~~
Random Failure in Control System Assumed as initiating,1 Event 8

Contrali8ystem Operating Assumptions During
~~" Anticipated Operational Occurrence (AOO) or DesignBasis Accident (DBA) w t~~
~~e e Assdmed to be in Manual Mode F~~
l or l l ve i Assdmed to Operate Normally in Automatic l : Mode Dependent on Which Assumption Results in j Most Severe Consequences i e No Random Failures Assumed (Other than ! Initiating Event) in Control Systems Concurrent l with AOO or DBA i wou wmn ) l
GENERIC ASSESSMENT OF SALEM EVENT l ) ASYMNIETRIC RCCA WITHDRAWAL l PROBABILITY OF OCCURRENCE i i e DETECTABCE I l Bud movement during normal operation lung-shily surveillance ;
~
~~l l l~~

~~OPERA'UNG HISTORY ;~~
~~i l 1~~
~~INITIAL JESSESSMENT INDICATES LOW PROBABILITY~~
~~. OF CDNTEDL SYSTEM CARD FAILURES RESULTING l j k"u"s"c*inETEON ll"'FRE"$*CY 2~~

~~LIMITING ASYMMETRIC RCCA WITHDRAWAL i SCEMARID HAS LOWER PROBABILITY OF~~
~~OCC1REE!BICE '~~
i l 7M 4 i
GENERIC ASSESSMENT OF SALEM EVENT l l 3 APPLICABLE i GENERAL DESIGN CRITERIA i 10 CFR PART 50 APPENDIX A
hry design and performance requirements for l sysemus;& components to provide reasonable assurance j tiustilhe facility can be operated without undue risk to the health and safety of the public.
D l GDC 25 i PROTECTION SYSTEM REO.UIREMENTS 7DR%1EACTIVITY CONTROL MALFUNCTIONS i #- E l %1molection system shall be designed to assure that
^
speciiHed aEceptable fuel desian limits are not exceeded for l q' any siingle malfupction of the Reactivity Control Systems, i such las actidental withdrawal of control rods." ! E pvo S Q '8S itd in. biell l
l l y GENERIC ASSESSMENT OF SALEM EVENT , iSAFETY ANALYSIS CLASSIFICATION ' , DESIGN PHILOSOPHY l
~~Most probable occurrence should yield least radiological risk to the public~~
*E Situations having the potential for the greatest risk to the i
~~! T public should be those least likely to occur l i 4 ANSEONDITION 11 ! MODERATE FREQUENCY (> 10 2 /YR) i !~~
~~Minimum Design DNBR Limit~~
~~! s. i ANS CiONDITION 111 4 j INFREQUENT FAULT (10 -102 /YR) s I~~
~~Small Fraction of Failed Fuel I ANS. CONDITION IV~~
~~LIMITING FAULT (< 10" /v9)~~
~~10 CFR 100 Dose Limits e Maintain Core Coolability 5~~
~~GENERIC ASSESSMENT OF SALEM EVENT _ I POSTULATED PLANT EVENT: LOAD REJECTION W/ i (CONDITION 1) j CONTROL SYSTEMS ASSUMED TO NORMALLY~~
~~' OPERATE: . STEAM DUMP PRESSURIZER POWER-OPERATED RELIEF VALVES (PORV)~~
~~ROD CONTROL SYSTEM CONSEQUENCES OF POSTULATED CONTROL SYSTEM~~
~~# FAILURE (S):~~
h
STEAM DUMP FAILS OPEN BOUNDED BY STEAM LINE BREAK ANALYSES

PRESSURIZER PORV FAILS OPEN ,
~~BOUNDED BY RCS DEPRESSURIZATION/LOCA ANALYSES~~
~~ROD CONTROL SYSTEM MALFUNCTION BOUNDED BY RCCA WITHDRAWAL ANALYSES '~~
supu WMt23
GENERIC ASSESSMENT OF SALEM EVENT l CONTROL SYSTEM FAILURE AND OPERATING ASSUMPTIONS e Periodic Surveillance of Control Systems per the Technical Specifications
~~Capability of Operator to Detect Abnormal i Control System Operation Based on Control !~~
~~Board Indications and Control Limit Alarms i s-~~
Any Postulated Failure that is Not Detectable Via Surveillance or Control Board Indication Assumed Concurrent with AOO or DBA

Resultant Low Probability of Random Control System Failure Concurrent with an AOO or DBA ;
1 SUDEA WMr24
i car 4UC ASSESSMENT OF SALEM EVENT l I WITH: RESPECT TO THE SALEM EVENT: i i
~~Th ilures is:1he Logic Cabinet should have caused all l Si iwnllank A rods to either move out or remain st;- :ary l~~
)
~~Sc othercumulition may have caused only one CRDM ;~~
~~to iond. !~~
TI- chnicalimurestigation is ongoing.

Tb squency of these combined effects classifies it as a Co- ion Ell esamt.

lti propeiinae to demonstrate compliance with the ac ancecriemria for a Condition 111 event (small fra 1 ofimited fuel). l l

Th setstineintent of GDC 25 for meeting acceptable I fue sign dimits.
i i
GENERIC ASSESSMENT OF SALEM EVENT hSYMMETRIC RCCA WITHDRAWAL AT POWER r l Event Dedcription: >
~~d banks operate within rod insertion limits in normal mundap i.~~
t e Operator or automatic rod control demand for RCCA immertion AND postulated failure lead to RCCA withdrawal u o Amy combination of 2 or more RCCAs from inserted canigol banks (D, D + C, or C + B) withdraw partially or
~~'fuhr from core T~~
i. Is 5 1 1
GENERIC ASSESSMENT OF SALEM EVENT
~
~~POSTULATED EVENTS~~
Single RCCA Withdrawal at Power k

Single RCCA Withdrawal from Subcritical

Uncontrolled RCCA Bank Withdrawal at Power

Uncontrolled RCCA Bank Withdrawal from Subcritical

Asymmetric RCCA Withdrawal at Power .
~~.7 7~~
p
~~Asymmetric RCCA Withdrawal from Subcritical l~~
~~% N~ f n~~
EUDER WPFf31
GENERIC ASSESSMENT OF SALEM EVENT l i ASYMMETRIC RCCA WITHDRAWAL I ; l l
~~Assessed to have a' low probability of occurrence I commensurate with Condition 111 Infrequent Fault i~~
~~l i e Ailowance of a small amount of fuel damage is ! consistent with the design philosophy i l~~
~~Eonservative generic bounding evaluation of limiting J scenarios indicates that a small percentage of the rods arould be predicted to experience a calculated DNBR~~
~~! Ablow the limit value. Little or no actual fuel failure is l_ 4~~
~~.guredicted.~~
~~i i e No undue risk to the public health and safety D~~
~~, (Ybe r~~
i % GBEERIC ASSESSMENT OF SALEM EVENT 1 ASYMMETRIC RCCA WITHDRAWAL AT POWER i Possible mesense int-dH due to asymmetric RCCA withdrawal j compared 1m single 1tCCA withdrawal DyYb' 'N Limiting Seenario '
~~FuE mistuiravuei 6f 2 or 3 adjacent D-bank rods (frone sfEEerentyoups) g W6,P l .~~
~~9 )~~
~~Resnaisiing D4mak RCCAs at insertion limit j~~
e
',
100%wer A Fewer ttum1% additibnal rods found to be below DNBR limit j value cW tofuniting single RCCA withdrawal case g cfr i Current Waidead tiesigns show a maximum of 1.5% of rods t.Y y\
below DNBRiimitfor single RCCA withdrawal at power event t i Margin existsto accommodate any additional rods below DNBR limit due to snultiple RCCA withdrawal and still satisfy Condition ill criteria
~~. Little or no fuel damage will occur due to postulated event i~~
1 suoso wwas
GENERIC ASSESSMENT OF SALEM EVENT ASYMMETRIC RCCA WITHDRAWAL FROM SUBCRITICAL Event
~~Description:~~
4
Reactor in STARTUP MODE with K-eff = 1.0 a

Shutdown banics are withdrawn from core

RCCA banks aperate in normal overlap -

Operator demand, in manual control mode, for RCCA
~~insertion AND. postulated failure lead to RCCA withdrawal~~
~
~~c s~~

~~Any combination of 2 or more RCCAs from inserted j control banks (A, A + B, B + C, C + D) withdraw partially l or fully from crue 1~~
l
. GENERIC ASSESSMENT OF SALEM EVENT ASYMMETRIC RCCA WITHDRAWAL FROM SUBCRITICAL Typical rod speed in manual mode is 48 steps per minute Operator action limits maximum misalignment o 48 steps ,e impact on peaking factors is limited
~~[Ug5 e Reactivity insertion rate is low j(>~~
~.
Use of currently approved methods expected to demons nuanber of fuel rods below DNBR limit will be limited small h( fraction of core g7, Use of 3-D kinetics methods expected to demonstrateJnoJuel row ~ below DNBR limit f % Little o no/ fuel damage will oicur due to p tulated event
~
~~W-1 W~~
~
~~y. pi A / .~~
~~.t.~~
~~Wa $s ENT OF SALEM EVENT EQ IPMENT PERFORMANCE REVIEW INITIAL REVIEW CONDUCTED~~
~~To identify failures of components located in the rod control system logic cabinet e Using three available data bases Nuclear Plant Reliability Data System (NPRDS)~~
Licensee Event Reports (LERS) Nuclear Power Experience l l 4 i d j
GENERIC ASSESSMENT OF SALEM EVENT 4
^
l
~~, EQUIPMENT PERFORMANCE REVIEW i~~
RESULTS Total of 34 logic cabinet component failures identified 24 no rod movement or no rod movement with urgent alarm 2 step counter driver failures 1 card failure identified subsequent to a reactor trip and unrelated w l 5 rod drop events 2 rod group misalignment events l l t l i 4
1 GENERIC ASSESSMENT OF SALEM EVENT EQUIPMENT PERFORMANCE REVIEW CDNCLUSIONS e No reported failure events occurred where a single rod became misaligned (similar to Salem event) I i
~~Estimated frequency of misalignment confirms that event l is a Condition 111 event I g,~~
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53 i
GENERIC ASSESSMENT OF SALEM EVENT
~~AGING CONSIDERATIONS BASED ON INITIAL REVIEW I~~
~~e The distribution of reported failures by years of plant operation shows no aging~~
e. The distribution of reported failures by calendar year Shows no aging i

e. Consideration is being given to the collection of additional
~~. data l~~
~~1 I 1 i 4 4~~
~~$UD(& WM43~~
~~!~ GENERIC ASSESSMENT OF SALEM EVENT i.~~
~~SAFETY ASSESSMENT 1 l Meet ANS Condition ill Acceptance)) l Criteria i~~
;
~~Minimal or No Actual Fuel Damage T~~
~~! will Occur as a Result of Postulated j l i Failure Scenarios i 1 i~~

~~No Challenge to the Integrity of the}~~
~~l Reactor Coolant System or !" Containment i n l~~
~~No Undue Risk to Public Health and j Safety~~
~~! N All plants should continue operation )~~
~~and/or startup.~~
l i suce3 wwese
GENERIC ASSESSMENT OF SALEM EVENT
)
4
~
~~SYSTEM OPERABILITY i i~~
~~Operability of the Rod Control System will continue to be determined through Tech Spec requirements and normal~~
~~plant operations~~
~~! 5~~
~~! *~ Current assessment is that the Rod Control System is operable ; 1 i t 4 I l J j~~
==
SUDES WM43
GENERIC ASSESSMENT OF SALEM EVENT NRC QUESTIONS FOR REGULATORY RESPONSE GROUP
~~1. How many plants and which plants have a rod y control system similar to that at Salem?~~
Answer All domestic Westinghouse plants except Connecticut Yankee have a similar Rod Control System O l i ) } l 4 suoss ww :
GENERIC ASSESSMENT oF SALEM EVENT
~~? 'NRC QUESTIONS FOR REGULATORY RESPONSE GROUP~~
~~2. Are these plants susceptible to the single failure experienced at Salem which results in uncontrolled rod withdrawals?~~
AllfSWER l' Since the plants have a similar Rod Control System, similar Rod Control System failures could occur. The expected response to the single failure is a RCCA group or bank withdrawal. We do not believe g , that the rod withdrawal is uncontrolled since the t i resulting rod motion is detectable. l
~~3. What are the consequences of rod withdrawals caused by such failures? Is there a potential for common cause failures which can cause multiple rod withdrawals because of this system?~~
~~! AMSWER l The RCCA bank withdrawal is a Condition 11 event ! I and is analyzed in current plants' FSARs with the l~~
~~l result being no predicted occurrence of DNB.~~
l Single or asymmetric rod withdrawal are treated as l l Condition 111 events and only a small fraction of rods i (less than 5%) are predicted to experience DNB. This meets the acceptance criteria for a Condition ill . event. i To date, either at Salem or at other plants, no common cause failures have been identified. NNM
GENERIC ASSESSMENT OF SALEM EVENT , REC QUESTIONS COR REGULATORY RESPONSE GROUP
~~4. 'What interim actions or operating restrictions are mecessary to ensure the plants remain within their~~
~~. design bases?~~
ANSWER The plants are operating within their design basis; the recommended actions, provided in NSAL 1 lD07, emphasize that attention be given to specific voutine operating practices.
~
~~f i 't 4 e SUDES WMidt~~
)
~~GENERIC ASSESSMENT OF SALEM EVENT l AIRC QUESTIONS FOR REGULATORY RESPONSE GROUP~~
~~5. .What longer term acticas are contemplated to l assolve this issue? l I~~
~~ANSWER t The evaluation already underway of the Salem event ; sinould continue. The WOG will collect data on~~
~~'EqHFrating events and Continue to interact with the MtC during the evaluation period.~~
W l t i J r i l f I suots wrvso l
GENERIC ASSESSMENT OF SALEM EVENT WOG FUTURE ACTIONS l
* .NRC updates on status * .. Update full Owners Group (6/16/93)
Address NRC comments resulting from this meeting

Iontinue to participate in the evaluation of the root cause ;
~~determination of the event.~~
~~Meet with NRC to discuss evaluations (August)~~
* .4WOG to continue to investigate Rod Control System !
~~performance history (TBD) + l l suoss wwm~~
i
~~, /~~
4 4 *.. , . L PAGE1 JUNE 7,1993 FRIDAY MAY 14,1993 WESTINGHOUSE IDENTIFIED PROBLEM WITH 4 STEP COUNTERS ( CBA GRP 1, CBS - GRP 1, CBC - GRP1, SBA - GRP 2) DURING WESTINGHOUSE MAINTENANCE SERVICE. REPLACED WITH NEW COUNTERS. DURING RETEST OF THE NEW COUNTERS, THE FOLLOWING CARDS WITH SERIAL NO WERE INSTALLED: A113 S/N 183, A114 S/N , 216, A713 S/N 132, A714 S/N 139. WESTINGHOUSE IDENTIFIED PROBLEM WITH THE COUNTER CIRCUIT CARDS: A113,& . A114 IN THE LOGIC CABINET. REPAIR A114 WSN 216 ( REPLACED 23 CHIP), REPLACED A113 WSN 217, A713 WSN 120, A714 WSN 133. DURING TROUBLESHOOTING REPAIRED A113 AGAIN (REPLACED z8, z9, z12). WESTINGHOUSE RETEST OF STEP PULSES FULL 228 COUNTS WITH RECORDER TRACES FOR CONTROL BANKS A,B,C,D AND SHUTDOWN BANKS A & B. NOTE: THESE CARDS WERE NOT BENCH TESTED WITH WESTINGHOUSE CARD TESTER A101 CARD PULLED AND PUT ON EXTENDER FOR OBTAINING O VOLT COMMON AS PER PROCEDURE STEP. MONDAY MAY 24,1993 DURING OPERATION SURVEILLANCE, CBA GRP 2 DID NOT MOVE ON DEMAND AND G AVE I AN URGENT FAILURE ALARM, CBC GRP 1 STEP COUNTER STEPPED IN BUT NOT OUT. . R1 IN MULTIPLEXING CIRCUIT BLOWN IN 22AC POWER CABINET. THIS RESISTOR FAILURE WAS CAUSED BY A SHORT LIGHT BULB (GROUP A SELECT LIGHT). DURING
. WESTINGHOUSE MAINTENANCE, GROUP A SELECT LIGHT SOCKET WAS REPLACED WITH A WRONG TYPE. CORRECT TYPE OF LIGHT SOCKET WAS REPLACED 6/2/93. THE SUPERVISORY DATA LOGGING CARD, A113 REPLCED WSN 217 WITH WSN 6014 FOR A113 CARD FROM FDLIO NOT BENCH TESTED. RETEST CBA, CBC, SBA GROUP
~~COUNTERS - SAT. 1 J~~
~~TUESDAY MAY 25,1993 DURING IRPI CAUBRATION OPERATION IDENTIFIED PROBLEM WITH CBB GRP 1 & 2 STEP COUNTERS.~~
STEP COUNTERS REMOVED AND BENCH TESTED. REPLACED CBB COUNTERS WITH THE OLD COUNTERS THAT WERE TAKEN OUT BY WESTINGHOUSE A WEEK EARLIER. RETEST tf o / M [/e (
. 1 i O
~~l l~~
o a I PAGE2 -l f GROUP COUNTERS - SAT. 4 NOTE: ORIGINAL COUNTERS DURING SURVIELLANCE TESTING OF 228 STEPS i WERE -1 STEP AND -2 STEPS WITHING TOLERANCE, BUT REPLACED AS A PROACTIVE STEP. l l l I l i 1 l b l l'
P PAGE3, WEDNESDAY MAY 26,1993 02:00 AM CBC GRP 1 FAILED TO STEP OUT. REMOVED THE COUNTER AND BENCH TESTED - SAT. PULSES NOT AVAILABLE AT THE CONTROL BOARD DURING ROD MOTION. ; REMOVED THE FAILURE DETECTOR CARDS AND JUMPER THE ALARM CARD IN THE FIVE POWER CABINETS TO OVERRIDE THE URGENT ALARMS DURING TROUBLESHOOTING. OPEN LIFT DISCONNECT FOR CBA, CBC, SBA. AT LOGIC CABINET, REMOVED AND PLACED A714 ON EXTENDER. MEAL *1 RED THE OUTPUT PULSE OF A714 - NO PULSE. SWAPPED A714 WSN 133 WITH A713 WSN 120, PROBLEM SHIFTED FROM CBC GRP1 TO CBC GRP2. OBTAINED NEW RELAY DRIVER FROM FOLIO AND INSTALLED WSN 695 IN A714 SLOT. VERIFIED OPERATION FOR CBC GRP 1 - SAT. CBC GRP 2 DID NOT STEP IN EITHER DIRECTIONS. (OUT STEP IS ELECTRICAL PROBLE, IN STEP IS MECHANICAL PROBLEM) CYCLING LIGHT FOR 22AC POWER CABINET INDICATED - SAT. MEASURED OUTPUT VOLTAGE AT A714 PINS 29, 30, 33, 34: AND A713 PINS 29, 30,33,34. I CONNECTED RECORDER TO A109 TP4 (UP PULSE), A113 TP4 & TPS, AND A714 PIN 4 30, TO MONITOR INPUT AND OUTPUT PULSES OF THE DATA LOGGING CIRCUIT - NO OUTPUT PULSE. 08:00 AM / REPLACED A113 WSN 6014 WITH WSN 0039 FROM FOLIO (MODEL NO 3361CO8G01) CONNECTED RECORDER TO MONITOR THE +/- 15 VDC POWER SUPPLIES. REMOVED RELAY DRIVERS A714, A713, CYCLE ROD MOTION FOR CBC , MONITOR OUTPUT OF A113 - SAT. ,
6 . (( t PAGE4, INSTAU.ED A714, A713, MEASURED OUTPUT VOLTAGE FOR A713, A714, INDICATED LO. REPLACED A713 WSN 120, A714 WSN 695 WITH NEW CARDS FROM FOLIO A713 WSN 701, A714 WSN 681. REPLACED 100VDC AUX POWER SUPPLY. CYCLE ROD MOTION, CBC, SBA, CBA GRP 1 - SAT, CBA GRP 2 NOT STEPPING. SWAPPED A714 WSN 0681 WITH SPARE WSN 0695 - NO CHANGE. RESTORED WSN 0681 TO A714 SLOT. f A113 CARD Fall AGAINI
~~-bf REPAIRED SPARE WSN 6014, REPLACED Z3 & Z6 CHIPS.~~
INSTAU.ED WSN 6014 IN A113, CYCLE ROD MOTION FOR CBC, CBA, SBA WITH THE RELAY DRIVERS A714 & A713 REMOVED. MONITOR A113 OUTPUTS, SUSPECT Z8, 25 & Z2 CH!PS ARE SAD. REPAIRED WSN 6014, REPLACED Z2,25 & Z8. WSN 0039 REPLACED Z3, Z2,28 d INSTALLED WSN 6014 IN A113, CYCLING ROD MOTION WITHOUT A713 & A714 INSTALLED - CHECK SAT. REPEAT WITH WSN 0039 - CHECK SAT. PERFORMED A VISUAL INSPECTION OF ALL TERMI POINTS AND TERMINAL STRIP FOR LOOSE CONNECTIONS, ABNORMAL ... - CHECK SAT. INSTALLED WSN 0039 IN A113 SLOT, WSN 701 TO A713, WSN 681 TO A714. I WITH RECORDER CONNECTED, CYCLING ROD MOTION FOR SBA - SAT. CYCLING ROD MOTION FOR CBA WITH A713, A714 INSTALLED, CBA GRP 1 NOT STEP i IN. ] I REMOVED WSN 039 FROM A113. REPLACED Z2. REINSTALLED WSN 0039 TO i A113, MEASURED OUTPUT VOLTAGE FOR PIN 11-14, 21 SAT. 1 4 INSTALLED WSN 681 TO A713, WSN 695 TO A714. CYCLE CBA OUT/IN GRP 1 - SAT. GRP 2 NO PULSE NOR COUTER STEPPING. SUSPECT Z3, Z2 OF A113 BAD AGAINI REPLACED Z3, 22 CHIPS.
l i i., , PAGES : i . l l i i ! k b j THURSDAY MAY 27,1993 /
~~/h i~~
05

00 AM ;
j INSTALLED RELAY DRIVER CARDS FROM TRAINING CENTER WSN 5, 0342 TO j A713, A714 AND WSN 0039 IN A113. , .I MOVE 10 STEPS OUT THEN IN FOR GRP 1 SBA, CBA, CBC - SAT. GRP 2 j SBA, CBA - SAT. CBA GRP 2 NOT STEP IN - UNSAT. ; i
CONNECTED RECORDER TO TB 42 PIN 1 &2 AND TB 42 4 & 5 - COIL TO !

STEP COUNTER 100 VDC

MOVE CBA GRP 2 UP - SAT, DOWN - NO CHANGE STILL UNSAT.
)I SWAPPED A713 WITH A714 THEN MOVE CBA OUT THEN IN 10 STEPS. ! SUSPECTED RELAY DRIVER CARD. PROBLEM STILL CBA GRP 2 NO "IN". l- FOUND PIN 34 OF A713 CARD CAGE SPREAD OPEN. CLOSED PIN.
~~REPLACED A113 WITH SPARE WSN 6014, MOVE CBA OUT GRP 1 & 2 -~~
SAT. i ) 08:40 AM PERFORMED OPERABILITY TEST FOR CBA, CBC, SBA - SAT. CBB DID NOT COUNT FOR OUT DIRECTION. REMOVED WSN 216 FROM j A114 SLOT. INSTALLED SPARE WSN 0039 IN A114 SLOT. MOVE CBD OUT-- 1 4 SAT. MOVE CBB OUT GRP1 - SAT. GRP 2 NOT COUNTING. MOVE SBB OUT THEN IN - SAT. REMOVE WSN 0039 FROM A114, REPLACED 23 WITH NEW CHIP. , j INSTALLED WSN 0039 IN A114, MOVE CBB OUT - GOOD PULSE. j i i i MOVE CBA, CBC OUT THEN IN, CBA GRP2 & CBC GRP2 NOT STEP IN NOR l OUT. SUSPECT.Z3 & 26 BAD. 4 j
PAGE5 23:50 INSTALLED WSN 0681 IN A714, WSN 0120 IN A713, WSN 0039 IN A113. MOVE CBA OlJT THEN IN WITH GRP 1 & 2 COUNTERS REMOVED. CBA GRP 1 NOT STEP IN, CBA GRP 2 OUT VOLTAGE REDUCED. SUSPECTED INPUT DIODE ON RC A WER CARDS BAD. REMOVED WSN 0039 FROM A1i JT. REPLACED Z2 & 23 ON WSN 0039. 22, 25, 26 ON WSN 6014. TAKE WSN 0039, 6014 TO TRAINING CENTER FOR TESTING. TESTED WSN 0039, WSN 6014 REPLACED ONE CHIP RESTESTED Al.L BANKS SAT REMOVED TRAINING CENTER RELAY DRIVES A713, A714, AND TRANSPORTED TO STATION WITH WSN 0039 AND WSN 6014. THESE FOUR CARDS TESTED SAT AT THE TRAINING CENTER. I I 4 i i 5 e
. / b ' sY . i PAGE7, l REPLACED Z3 & Z6 ON WSN 6014. 13:05 CHECK INPUT DIODE FOR ALL RELAY DRIVER CARDS. FOUND 1 BAD DIODE (SHORTED), CR1 OF A710 SLOT. REPLACED DIODE. INSTALLED WSN 6014 IN A113, VERIFIED CBC OPERABLE - GOOD. 1 14:30 MOVE CBB OUT - GRP 1 SAT, GRP 2 STEP IN ONLY, GRP 2 OUT - UNSAT. l MOVE CBS IN CHECK OK. - l MOVE SBB OUT THEN IN - SAT. CCB GRP 2 STEP IN AT THE SAME TIME. l MOVE: CBD OUT THEN IN - SAT. CCB GRP 2 STEP IN AT THE SAME TIME. SUSPECT Z3 OF A114 BAD. 15:30 REMOVED WSNOO39 FROM A114 SLOT. INSTALLED WSN 216 IN A114 SLOT, WITH THE POWER DEENERGlZED. ENERGlZED THE POWER SUPPLIES, PERFORMED RETEST FOR ALL BANKS - SAT. REMOVED JUMPERS FROM ALARM CARDS AND REINSTALLED THE FAILURE DETECTOR CARDS IN THE FIVE POWER CABINET. 18:37 COMMENCED PULLING SHUTDOWN BANKS FOR STARTUP. 18:44 SHUTDOWN DANK A WITHDRAWN /NO MOVEMENT WITH 20 STEPS /STOP ! ROD WITHDRAWAL ! ROD INSERTED TO 6 STEPS /1SA3 OBSERVED INDiCATIONG 8 STEPS ON ARPI SHUTDOWN BANK A RODS INSERTED TO ZERO STEPS AS INDICATED ON - THE COUNTERS /1SA3 INDICATING 15 STEPS ROD 1SA3 VERIFIED AT 15 STEPS ON ARPl. ALL ROD BOTTOM LIGHTS STAYED LIT DURING THE WHOLE WITHDRAWAL AND INSERTION SEQUENCE. WHEN THE STEP COUNTER COUNTED FORM I
t p f Nb l 99 (1>N PAGE8 I f 1 TO ZERO ON FLASH - OFF ON - WAS OBSERVED ON THE ROD BOTTOM LIGHT ON RP3 FOR 1SA3. THE ROD FUSES WAS PULLED FOR 1SA3 TO ENSURED THE ROD IN THE BOTTOM. ALL LIFT Coll DISCONNECTS FOR SBA WERE OPENED TO ALLOW TF;OUBLESHOOTING OF ROD CONTROL. 21:30 SET UP MONITORING EQUIPMENT IN 1 AC AND 2AC POWER CABINETS. MONITORED COIL CURRENTS STATIONARY AND MOVABLE AND LIFT CURRENT ORDERS FOR 1 ROD IN 1 AC, SBA AND 1 ROD IN 2AC, SBA. FRIDAY MAY 28,1993 00:00 AM THE BUS DUCT DISCONNECT SWITCHES FOR CONTROL POWER CABINETS 21 AC AND 22AC WERE OPENNED TO ENSURED THAT ALL ROD WERE ON THE BOTTOM. CLOSED 3 PHASE BREAKERS ON 21 AC &22AC - NO CHANGE ON RPI INDICATION. DISABLE 21 & 22BD TO TEST CURRENT ORDERS. CONNECTED RECORDER TO 1SB1 AND 2SB1 TO MONITOR LIFT CURRENT ORDERS AND STATIONARY AND MOVABLE CURRENTS. OPENED DISCONNECT SWITCH FOR LIFT COILS IN CONTROL ROOM. COMPLETED CURRENT ORDER TEST ON SBB. TEST INDICATED CURRENT ORDER SAME INDICATIONS AS SHUTDOWN BANK A. 02:26 CONNECTED RECORDER TO 1SA3 AND 2SA3 TO MONITOR CURRENT ORDERS. RESULT SAME AS SBB. CONNECTED RECORDER TO GATING FOR IN/OUT MOTION FOR SLAVE CYCLERS. A109 TP4, A108 TP2, A108 TP3, A108 TP5. TEST INDICATES TEST POINTS 2&3 NOT CORRECT. TOOK VOLTAGE READINGS ON A108 PIN 11 & A109 PIN 23 TO ELEIMINATE TERMI POINT PROBLENI - SAT.
~~-- . .. .- - .~ ~ ~ - . . - - . - - - - . _ _ _ _ _ - - -~~
y v (# PAGE9, REMOVED AND PLACE 8 ON EXTENDER CARD. MONITOR DNSP DOWN GATE TAGE - NO CHANGE, INDICATED LOW SHOULD BE HIGH. l REMOVED AND REINSERTED SLAVE CYCLER DECODERS ONE AT A TIME. A501 -SLAVE CYCLER DECODE STATIONARY 22AC CAUEING LOW VOLTAGE ON DOWN GATE. REMOVED WSN 0079 FROM A501 - TESTED BAD ON TEST R!G. l l REPLACED WSN 0079 WITH WSN 0083 INSTALLED IN A501.
~~- l MONITOR TP108 PIN 2&3, TP108 PIN 5 AND TP109 PIN 4. UPSP NOT GOING HIGH.~~
REMOVED WSN 0021 FROM A108. BENCH TESTED - GOOD REMOVED AND PLACED A109 ON EXTENDER CARD. JUMPERED PIN 23 ON A109 TO SET UP HIGH ON A108 DOWN PULSE. FOUND A511 WSN 0080 SLAVE DECODER MOVABLE 22BD BAD REPLACED WITH WSk 0072. REINSTALLED A109. CONNECTING RECORDER TO CHECK UP/ OWN PULSE
~~- SAT.~~
~~PERFORMED A CURRENT ORDERS TRACE FOR 21 AC, 22A , 21BD, 22BD - d GOOD.~~
~~. As 11:00 AM f6 PERFORMED OSClLLATOR FAILURE CHECK, M TIPLEXING CHECK, SLAVE CYCLER ERROR FUNCTIONAL CHECK - SAT CONNECTED RECORDER TO l~~
MONITOR THE 15 VDC POWER SUPPLIES COMMENCE STARTUP. 9g a : i 4
PAGE10 ROD CONTROL COVERAGE SATURDAY MAY 29,1993 NO TIME PROVIDED
~~+ CONTROL BANK C GROUP 1 DROPPED - NO URGENT ALARM BANK SELECTOR SWITCH WAS IN MANUAL BANK OVERLAP SELECTED TO CBD BANK OVERLAP COUNTER AT 540.~~
NO OPERATOR INIT1ATED MOTION FOR UP TO 40 MIN PRIOR TO PROBLEM. ROB BOTTOM ALARM & LIGHTS TOOK STATIC VOLTAGE READINGS OPERATORS OPENED REACTOR TRIP BREAKERS THEN RECEIVED URGENT FAILURE ALARM. STATIONARY REGULATION FAILURES IN ALL CABINETS AND PHASE FAILURE STATIONARY GROUP C FOR 22AC POWER CABINET. MOVING REGULATION ERRORS IN ALL CABINETS. NO LOGIC ERROR ON ANY OF THE CABINETS. 21 AC MA SIGNAL READING 12.5 VAC. 21 AC CABINET STATIONARY CURRENT ORDERS WERE AT REDUCED CURRENTS ~ TOOK READING ON REG CARD TP2 FOR CONTROL C: 6.18V. TOOK READING ON REG CARD TP2 FOR CONTROL A: 6.2V. PULLED F1, 21 AC CONTROL C REG CARD - EXTENDED IT - TOOK READINGS: PINS 31 TO 19: 19.93 V (ZERO CURRENT ORDER) ; PINS 21 TO 19: 9.3 V (REDUCED CURRENT ORDER). PULLED C1, 21 AC CONTROL A REG CARD - EXTENDED IT -TOOK READINGS: PINS 31 TO 19: 19.1 V (ZERO CURRENT ORDER) PINS 21 TO 19: 9.3 V (REDUCED CURRENT ORDER).
~~JIGGLED A803 ' CARD WHILE READING 21 AC CONTROL C REG SIGNALS - NO CHANGE IN VOLT READING -SAME AS ABOVE.~~
PAGE11 , , PULLED Fall DET CARDS - INSTALLED INTERLOCK JUMPERS - REISERTED CARDS IN ALL 5 POWER CABINETS. REINSTALLED C1, 21 AC STATIONARY REG CARD - REMOVED F1, STATIONARY REG CARD FOR 21 AC, 22AC - EXTENDED IT. ; 1 RAN TRACES ON Rr AND Rz (1 ORDERS) IN CONTROL BANK C GROUPS 1 & 2. Rz - NOT CLOSE TO CHARACTERISTIC AC WAVEFORM. Rr - REDUCED AMPLITUDE. NOTE: TEST INDICATES FIRING CIRCUIT CARD NO GOOD. PULLED FIRING CARDS D1 FOR 21 AC AND 22AC AND EXTENDED - REINSTALLED F1, REG CARDS (NOT EXTENDED). LOGIC ERRORS IN BOTH AC CABINETS - DUE TO PULLING FIRING CARDS - AFTER EXTENDED RESET IN BOTH CABINETS. RAN TRACES ON Rr & Rz WITH SAME RESULTS AS ABOVE. l RAN TRACE ON TPS AND TP6 ON FIRING CARDS (SWITCHING AMP OUTPUTS) - CONTROL BANK C STATIONARY FIRING CARDS FOR 1 AC AND 2AC: RESULTS: 1 AC - TP5 FLAT LINED TP6 SAW AC 2AC - AC ON BOTH TP5 AND TP6. l RAN TRACE ON TP7 (OSCILLATOR OUTPUT) AND TP5 IN 1 AC AND 2AC CONTROL BANK C.
~~RESULTS~~

~~1 AC - TP5 FLAT LINED 1 AC - TP7 AC 2AC - TP5 AND TP7 AC READJUSTED RECORDER TO OBTAIN A HIGH SPEED MEMORY TRACE. RESULTS:~~
~~1 AC TP5 FLATLINE 1 AC TP7 AND 2AC TP5 AND TP7 LOOKED SATISFACTORY.~~
1
1 l ! l PA,GE12, PULLED 1 AC FIRING CARD (#395) GR B STATIONARY AND TOOK TO ! LAB FOR BENCH TESTING. l RESULTS: ' OSCILLATOR AND SWITCHING AMP SECTIONS TESTED SAT. REINSTALLED 1 AC FIRING CARD - EXTENDED. , NOTED FILTER WAS ON FOR 1 AC TP5 VISICORDER CH 1. l RECONNECTED TO TP5 AND TP7 FOR 1 AC AND 2AC. i TURNED OFF CH 1 FILTER ON VISICORDER AND NOTICED AN AC i SIGNAL ON CH 1. WHILE MONITORING INPUTS TO VISICORDER CH 1 - APPLIED HEAT TO FIRING CARD WITH HEAT GUN - SEVERAL MINUTES. RESULTS: AC AMPLITUDE DID NOT CHANGE. MONITORED Rr AND Rz AT THE FIRING CARD EDGE CONNECTOR WITH ROD MOTION. RESULTS: NOW READING AS EXPECTED. TURNED VISICORDER CH 1 FILTER BACK ON. RESULTS: WAVEFORM IS SMOOTHED BUT HAS CORRECT SHAPES AND IS NOT IDENTICAL TO 1ST SET OF TRACES THAT WERE RUN. I PERFORMED SAME SEQUENCE IN 2AC WITH THE SAME RESULTS. VOLTAGE READINGS (1 ORDER SIGNALS) WITH CONTROL BANK C ! SELECTED. 1 TB# SIG NAME 21 AC 22AC 19 4,5 S1A 1.67 VAC 1.74 VAC 19 7,8 S1B 12.7 12.44 20 1,2 S2A 1.66 1.73 20 4,5 S2B 12.73 12.33 i 20 10,11 S3A 1.67 1.8 21 1,2 S3B 12.72 12.56 21 7,8 MA 12.9 12.8C D I t
l , PAGE13, 23 4,5 LA 12.54 14.03 23 7,8 LB 12.59 15.03 VOLTAGE READINGS (1 ORDER SIGNALS WITH CONTROL BANK D SELECTED. TB# SIG NAME 21 AC 22AC 19 4,5 S1A 1.67 VAC- 1.74 VAC i 19 7,8 S1B 12.69 12.44 l 20 1,2 S2A 1.66 1.73 l 20 4,5 S2B 12.73 12.34 ' 20 10,11 S3A 1.68 1.81 21 1,2 S3B 12.75 12.58 i 21 7,8 MA 12.91 12.86 i 23 4,5 LA , 12.54 14.03 23 7,8 LB 12.59 15.04
~~- SELECTED TO CONTROL BANK D AND IN 1 AC - LIFTED INCOMING ZERO I ORDER (TB20-1).~~
RESULT: i LOGIC ERROR ALARM DID NOT LIGHT. SELECTED TO CONTROL BANK C AND IN 1 AC - LIFTED INCOMING ZERO I ORDER LEAD (TB20-1). RESULT: LOGIC ERROR ALARM LIT. LOGIC ERROR CIRCUlTS CHECK: REMOVED FOLLOWING CIRCUIT CARDS IN 21 AC: D1 - GR B FIRING #0395 E1 - GR B PHASE CONTROL #0366 F1 - GR B REGULATION #0297 CONNECTED RECORDER TO 15 VDC POWER SUPPLYS SHOWED SPIKING OF 30 TO 40 MV, PRIOR TO REMOVING A803. REMOVED FROM' LOGIC CABINET: 1/0 AC AMP A803 CARD #0872
~
PAGE14, 15 VDC SUPPLIES WITH SPIKE WENT. AWAY (NO SPIKES). REMOVED D1 CARD FROM EXTENDER AND REINSERTED IT BACK IN D1 SLOT WITHOUT EXTENDER (IN 22AC) SO IT WOULDN'T BE DAMAGED BY PASSERS-BY. 18:25 1 REMOVED FORM FOLIO FIRING CARD S/N 6120 INSTALLED IN TEST RIG. 19:05 RECEIVED NEW CIRCUlT CARD REGULATION GRIPPER S/N 6053, 6052 FROM FOLIO. BENCH TESTED NEW CARD - SAT. MONITORED THE WESTINGHOUSE TESTER POWER SUPPLY FOR MIN AND MAX VOLTAGE READING WITH FLUKE 45 METER - READING SAT.
~~) . .- j i ~'~~
~~PAGE15, 1 l l 1 i~~
ROD CONTROL COVERAGE SUNDAY MAY 30,1993 00

00 TO 12:00 l
~~i 02:40 A.M.~~
~~+ IN CABINET 21 AC - PERFORMED THE FOLLOWING WORK:~~
INSTALLED THREE CARDS 'l FIRING CARD - SLOT D1, NEW SERIAL # 6120 PHASE CARD - SLOT E1, NEW SERIAL # 0364 REGULATOR CARD - SLOT F1, NEW SERIAL # 6053 02:45 A.M.
~~+ IN THE LOGIC CABINET REPLACED ONE CARD 1/0 AC AMP CARD, SLOT A803, NEW SERIAL # 0144.~~
~~02:55 A.M.~~
~~+ ALL CARDS CHECKED FOR POTENTIAL TENSION PROBLEMS (CIRCUIT CARDS ARE TIGHT IN CAGE CHASSIS GUIDES ARE ADJUSTABLE),~~
ADJUSTMENTS WERE MADE TO THE FOLLOWING CARD CAGE GUIDES: CAB. 21 AC, SLOTS A1, B2, 02, 02. CAB. 22AC, SLOTS A1, A2, K1. CAB. 21BD, SLOTS A1, E1, F1, G1, H1,11, J1, K1, A2, B2, C2,12, J2, K2. CAB. 22BD, SLOTS A1, B1,11, J1, K1, A2, B2, E2, J2, K2. 4
i 9
/
~~g3 63 -~~
~~. D PAGE16 03:00 A.M.~~
1 + DISCOVERED FUSES FU11 & FU6 BLOWN ON THE 100 VDC POWER SUPPLY CIRCUlT. THE TECHS WERE PREVIOUSLY HOOKING UP A WESTINGHOUSE l TEST BOX FOR SIMULATING ROD MOTION. THIS INVOLVED SNAKING TEST
LEADS FROM THE FRONT TO THE BACK OF THE CABINET. THE HELPER l WHEN ASKED LATER REMEMBER SEEING THE TWO FUSES COME IN AND HEARING CUCKING NOISE, ASSUMED RELAYS. FURTHER INVESTIGATION I REVEALED THAT THREE FUSES HAD BLOWN. THE ONE FUSE DID NOT
~~! PROVIDE INDICATION IT WAS BLOWN BECAUSE IT WAS ON THE NEUTRAL.~~
J THIS INFORMATION WILL BE VERIFIED VIA INTERVIEWS ON THE MIDNIGHT l TO NOON SHIFT. 3/31 02:00 A.M. TOM MCKEE WAS NOT SURE IF THEY I ]
WERE PASSING LEADS THROUGH THE CABINET OR GETTING READY TO

WHEN HIS HELPER SHERMAN WOOD BROUGHT TO HIS ATTENTION THE TWO BLOWN FUSES.
i i + REVIEW OF THE DRANER RECORDER SHOWED THAT A TRANSIENT ! OCCURRED AT 2:22 A.M., THE NEGATIVE 15 VDC POWER SUPPLY DIPPED l TO 12.8 VDC, NOTE THIS IS AN ABSOLUTE VALUE. THE (-) 15VDC WAS l ALSO SHOWN TO BE PROVIDING 15.8 VDC INSTEAD OF 15.0 VDC.. THE j CHANGE IN THE (-) 15 VDC OUTPUT GCCURRED APPROX. 2:25 A.M.. AN 4 INVESTIGATION INTO THIS WILL CONSIDERED SEEING IF THE ONE OF THE l AUCTIONEERING DIODES SHORTED..
~~+ THE POWER SUPPLIES IN THE LOGIC CABINET WERE CHECKED OUT,~~
! PRIMARY TO GROUND - OPEN, VERirlED NO SHORTS. l BOTH 100 VDC OUTPUT TO GROUND > 500 OHM - GOOD. ! I i INSTALLED NEW FUSES 6 AMPS FAST ACTING.
+ FOUND A SLIGHTLY LOOSE OV BUS MAIN FEED CONNECTOR IN CAB. 21 AC, IT WAS TIGHTENED. THE OV BUS MAIN FEEDS WERE TIGHTENED / CHECKED IN ALL POWER CABINETS. l l 07:00 A.M. + HOOKED UP A RECORDER TO THE FOLLOWING POINTS IN CAB. 21 AC:
~~i i~~
~~CH.1 S2A TB20-1 TB20-2~~
. CH.2 S2B TB20-4 TB20-5 l 4 4_ -. ._ . - , . . - , , . - -
f I PAGE17 CH.3 LA TB23-4 TB23-5 CH.4 LB TB23-7 TB23-8 CH.5 MA. TB212-7 TB21-8 CH.6 SvREF F1-TP2 OV BUS ! CH.7 LvREF F2-TP2 OV BUS CH.8 MvREF C2-TP2 OV BUS PERFORMED A FUNCTIONAL ON BANK C - RAN COUNTERS OUT TO 730 COUNTS WITHOUT ANY PROBLEMS INDICATED ON THE TRACES. WILL LEAVE RECORDER HOOKED-UP T BANK C WHILE RUNNING OUT THE OTHER BANKS. ALL OTHER BANKS OPERATED SATISFACTORY. 10:51 AM POWER SUPPLY CHECKS CHECK AUCTIONEERING DIODES FOR 100 VDC POWER SUPPLIES: AUX - DC OUT 105.3, AC IN 122.1, 300 MV RIPPLE MAIN - DC OUT 98.26, AC IN 108.65, 182.2 MV RIPPLE 100 V AUCT10NEERING DIODE CHECKS A26A35CR1 -183 MV; A26A35CR2 -7.1VDC 15 VDC: MAIN - TP68 DC OUT 15.796 WITH .15 MV RIPPLE (UNFILTERED) AUX - TP66 DC OUT 15.8, .15 MV RIPPLE. 11:20 AUX - A25, CR127.8 MV, CR2 4.8 MV AUX 100VDC SUPPLY, DEENERGlZED MAIN POWER SUPPLY, CR1.63 DEENERGlZE AUX, CR2.623 11:21 MEASURED OUTPUT OF AUX SUPPLY 105.2 VDC WITH 325 MV AC RIPPLE. MEASURED CR1,63 AUCTIONEERING DIODE. 11:25 REENERGIZED MAIN AND DEENERGlZED AUX. 11:27
~~i. '~~
~~i PAGE18 _ MAIN POWER SUPPLY OUTPUT 98.1 VDC WITH 217 MV AC RIPPLE.~~
~~; MEASURED CR2 0.623 VDC AUCTIONEERING DIODE.~~
11:29 I l REENERGlZED AUX POWER SUPPLY i l l 11:30 i TURNED OFF MAIN 15 VDC SUPPLY I AUX -15VDC POWER SUPPLY -15.795 WITH .16 MV AC RIPPLE MAIN POWER SUPPLY DEENERGlZED CR1 +.823.VDC, CR2 -0.18 MVDC 1 1 r MAIN -15VDC POWER SUPPLY -15.795 WITH .15 MV AC RIPPLE WITH AUX SUPPLY DEENERGlZED ;
~~; CR1 -16.1 VDC, CR2 4.87 MV (SHORTED) !~~
~~1 i REENERGlZED 15 VDC SUPPLY. NOTE: MEASUREMENTS WITH FLUKE 45.~~
+ THE (-) 15 VDC AUCTIONEERING DIODE WAS FOUND SHORTED ON THE j MAIN POWER SUPPLY. A NEW DIODE WILL BE INSTALLED. + RON HEATON WILL HAVE THE CARD SOCKETS INSPECTED ON THE CARDS
~~THAT WERE REPLACED. THE INTENT IS TO ENSURE THAT A LOOSE i CONNECTION WAS NOT RESPONSIBLE FOR THE PREVIOUS FAULTS.~~
1
~~REPLACED A16 FL1, AND A16 FL2 LO VOLTAGE POWER SUPPLY FILTERS.~~
4
)
i
PAGE19 ROD CONTROL COVERAGE SUNDAY MAY 30,199312:00 TO 24:00 13:15
~~-+ TROUBLESHOOTING OF 100 V AND +/- 15 VOLT POWER SUPPLIES IN PROGRESS.~~
~~13:40 WITH +15 VDC CHECKS AUX ENERGtZED ONLY, CR10.83 VDC, CR215.1 VDC MAIN ENERGlZED ONLY, CR1 15.3 VDC, CR2.84 VDC. 15:15~~
+ -15 V POWER SUPPLY AUCTIONEERING DIODE REPLACED. POWER SUPPLY TROUBLESHOOTING DONE WITH NO OTHER COMPONENTS REPLACED. THE MAIN 100 V PS RUNS AT 98.3 V,182 MV RIPPLE, WHILE THE AUX RUNS AT 105.3 V, 300 MV RIPPLE.
16:30 i + INVESTIGATING CURRENT SIGNALS TO POWER CABINETS. ON RECOVERY OF THE 15 VOLT POWER SUPPLIES, IT WAS SEEN THAT THE CURRENT i ORDERS WERE NOT CORRECT.1/0 AC AMP A803 S/N 0144 WILL CORRECT ITS OUTPUT SIGNALS WHEN IT IS JOGGLED OR WHEN CERTAIN i TRANSISTORS (A13 & Q14) ARE TOUCHED. THIS IS AN INDICATION OF FAULTY TRANSISTOR CIRCUITS.
~~17:00~~
~~+ REMOVED S/N 0144 FROM SLOT A803.~~
~~_. . PLACED S/N 0660 FROM SLOT A805 IN SLOT A803. a a 5~~
~~. . _ - . . . - + _. . . . , _ . , _ . , _ ,- _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _~~
~ PAGE20 PLACED S/N 0144 IN SLOT A805. WITH THIS CONFIGURATION, THE CURRENT ORDERS WERE S ATISFACTORY (ON THE RECORDER) FROM THE SLOT A803. (BY DVM THE OTHER ORDERS WERE REVIEWED WITH INCONSISTENT RESULTS, SO IT WAS DECIDED TO REMOVE AND TEST ALL OF THE 1/0 AC AMP CARDS. REMOVED THE FOLLOWING FROM THE LOGIC CABINET FOR INSPECTION ON THE TEST RIG: REMOVED S/N 0144. REMOVED S/N 0660. REMOVED S/N 0121 FROM SLOT A801. REMOVED S/N 0107 FROM SLOT A802. REMOVED S/N 0108 FROM SLOT A804. 19:51
~~+ S/N 0144 TRANSISTORS Q13 AND Q14 REPLACED AND STILL DEFECTIVE.~~
~~20:40~~
~~+ REMOVED THE FOLLOWING FROM THE LOGIC CABINET FOR INSPECTION ON THE TEST RIG:~~
~~REMOVED S/N 0147 FROM SLOT A808. REMOVED S/N 0149 FROM SLOT A812. REMOVED S/N 0150 FROM SLOT A813. REMOVED S/N 0142 FROM SLOT A814. 20:40~~
~~+ RETURNED THE FOLLOWING TO THE LOGIC CABINET:~~
~~S/N 0121 TO SLOT A801. S/N 0107 TO SLOT A802. S/N 0122 TO SLOT A803. S/N 0108 TO SLOT A804. S/N 0660 TO SLOT A805. S/N 0122 IS A CARD PREVIOUSLY REPAIRED BY VARTEK. A l l~~
\
~~- - - - - . . . . - . _ - - ~ _ . .-. .--. _ - - - _ - - _. . - . - . _ .~~
l i , 1 PAGE21 S/N O146, A SPARE CARD, FAILS TEST ON TEST RIG. IT WAS PREVIOUSLY TESTED SAT AT NTC ON 3-24-88 AND BY WESTINGHOUSE ON 3-6-91. ALL CAGE AND CARD EDGE CONNECTORS EXAMINED FOR CORRECT PIN ALIGNMENT. 22:20
~~+ S/N 0142 FOUND DEFECTIVE ON TEST RIG.~~
S/N 0147 FOUND DEFECTIVE ON TEST RIG. S/N 0149 FOUND DEFECTIVE ON TEST RIG. , S/N 0150 FOUND DEFECTIVE ON TEST RIG. S/N 0144 REPAIRED. S/N 0372 OK ON TEST RIG. THIS IS S/N REMOVED PREVIOUSLY ON 5-30-93 AT 02:45. 23:30
~~+ S/N 0142 REPAIRED.~~
RECORDERS ARE IN PLACE TO MONITOR THE STATIONARY COIL SIGNALTO ONE OF EACH GROUP. PLANS BEING REVIEWED INCLUDE: DETERMINING HOW MANY OTHER CARDS IN THE LOGIC CABINET MUST BE i TESTED DUE TO THE 15 VOLT POWER SUPPLY PROBLEM. DETERMINING CONTENT OF RETESTING WHICH PRESENTLY INCLUDES CYCLING OF POWER CABINETS WITH MOTION TEST BOX CONNECTED AND 260 VAC TAGGED OUT AND THEN POWERING UP THE SYSTEM AND MOVING RODS (LEAVING RECORDERS IN PLACE). !
L PAGE22 ROD CONTROL COVERAGE MONDAY MAY 31,1993 00:00.TO 12:00 02:30 A.M. l
~~'+ INSTALLED 1/0 AC AMP CARDS IN LOGIC CABINET S/N 0144 - SLOT A814 S/N 0142 - SLOT A813 ,~~
~~S/N 0872 - SLOT A812 : S/N 0149 - SLOT A808 S/N 0150 - SLOT A805 S/N 0147 - SLOT A804 S/N 0146 - SLOT A803 02:40 A.M. I~~
~~+ PULLED THE RELAY DRIVERS FROM LOGIC CABINET TO TEST S/N 0135 - SLOT A705 l S/N 0680 - SLOT A706 j S/N 0402 - SLOT A707~~
~~! S/N 0136 - SLOT A709 l S/N 0370 - SLOT A710 ! S/N 0134'- SLOT A711~~
S/N 0345 - SLOT A713 S/N 0342 - SLOT A714

02:45 A.M.
l
~~+ EVERY CARD ASSOCIATED WITH -15 VDC BUS WAS REMOVED FROM THE~~
! . LOGIC CABINET FOR INSPECTION IN THE WESTINGHOUSE CARD TESTER e f
PAGE23 EQUIPMENT. FAILURE DETECTORS CARDS S/N 0022 - SLOT A708 TESTED SAT 02:45 A.M. - CONTINUE , PULSE SHAPER CARD - SAT. S/N 0036 - SLOT A701 S/N 0040 - SLOT A702 1/0 RECEIVER CARDS S/N 0028 - SLOT A809 TESTED UNSAT, NO OUTPUT ON PIN 4, REPLACED TRANSISTOR Q12. S/N 0032 - SLOT A810 TESTED SAT PULSER OSC. CARD (MODIFIED TEST) S/N 0147 - SLOT A314 TESTED SAT , S/N 0194 - SLOT A101 TESTED SAT 03:30 A.M.
~~+ PULLED AND BENCHED THE FOLLOWING CARDS FROM THE LOGIC CABINET.~~
THIS WAS PROBABLY DONE ON PREVIOUS SHIFT, HOWEVER THE TURNOVER NOTES DID NOT INDICATE CLEARLY THAT THESE CARDS TESTED SAT. THEREFORE IT WAS DECIDED TO RUN THEM THROUGH THE TEST RIG AGAIN. ALL CARDS TESTED SAT. S/N 0121 - SLOT A801 S/N 0107 - SLOT A802 S/N 0122 - SLOT A803 S/N 0108 - SLOT A804 S/N 0660 - SLOT A805 i B
u t - PAGE24 04:45 4 RELAY DRIVERS WERE TESTED SAT 07:15
~~+ ALL CARDS REINSTALLED AND SETTING UP RECORDERS FOR FUNCTIONAL TEST OF ALL CURRENT ORDERS. THE RECORDERS WERE CONNECTED TO THE FOLLOWING POINTS IN EACH GROUP:~~
STATIONARY COIL A VREF STATIONARY COIL B VREF , STATIONARY COIL C VREF ! MOVING COIL VREF l LIFTING COIL VREF l 08:15 i l
+ STARTED TRACES, ALL TRACES LOOK SAT. FINISHED AT 08:30 08:40 j + THE COUNTERS ON CONTROL BANK A (GRP 2), CONTROL B (GRP2),
AND CONTROL BANK C (GRP 1) DID NOT COUNT IN THE OUT DIRECTION. SUBSEQUENT TESTING VERIFIED THEY WOULD COUNT i IN THE IN DIRECTION. i CBD STEPPING COUNTER GRP 1 & GRP2 - SAT I RECORDER TRACE FOR 22BD SHOWS SBB MOVING WHEN CONTROL D SHOULD BE MOVING. . MULTIPLEXING SIGNALS AT POWER CAB ARE CORRECT FOR CBD. 09:00
~~+ OVERLAP TEST, PROBLEM WITH MXR2 RELAY NOT PICKING UP, TRACED TO SPREAD PIN (PIN 12) ASSOCIATED WITH SIGNAL PROCESSOR CARD (WSN 81) IN SLOT J2, CAB. 22BD. !~~
~~L .~~
~~,, . , . , , , _ T', ?- --- ,_- --~~
~~- - - - - - . - . - .- .- . . . - . - . _ . -- . ..- .- - - .. . - ._ - ._ . . - . - _ .._=~~
~~l PAGE25 !~~
~~+ RETEST OF MXR2 RELAY SAT .~~
~~10:45~~
~~+ REMOVED THE FOLLOWING CARDS TO TEST IN THE WESTINGHOUSE TEST JIG:~~
S/N 0216 - SLOT A114 - Z3 BAD (TRACE LIFTED DURING SOLDERING). S/N 6014 - SLOT A113 - 23 AND 25 BAD, REPAIRED SAT S/N 0345 - SLOT A713 , S/N 0342 - SLOT A714 S/N 0183 - REPLACES S/N 0216. (S/N 0183 WAS REPAIRED) ROD CONTROL COVERAGE MONDAY 31,1993 12:00 TO 24:00 , 13:00 CHECK THE FOLLOWING CARDS ON THE TEST RIG: WSN 6014 IN A113 WSN 01.13 IN A114 WSN 0345 IN A713 WSN 0342 IN A714 THE ABOVE CARDS TEST SAT. CALLED CONTROL ROOM FOR TESTING. STARTUP RESET, SAT CBA GROUP 2 NO OUT MOTION - SUSPECT CHIP Z3 OF A113 CBB GROUP 2 NO IN OR OUT MOTION - SUSPECT CHIP Z3 OF A114 l CBC GROUP 1 & 2 TEST SAT . CBD GROUP 1 & 2 TEST SAT i TRIED CBA AGAIN, GROUP 2 NO OUT MOTION ! 13:30 3 BENCH TEST OF A113 AND A114, REPLACED Z3 FOR BOTH CARDS. BENCH TEST RELAY DRIVERS A713, A714 INPUT DIODES - SAT. l WSN 0183 - SUPERVISORY DATA LOGGING CARD AVAILABLE FOR SPARE
~~- FEMALE PIN 33 & 35 ON A713 SLIGHTLY OPEN, CLOSED THE PINS (NO t~~
i
PAGE26 l . ! EFFECT) ,, { I l
~~/ g j 15:10 REINSTALLED THE FOLLOWING:~~
~~WSN 6014 IN A113 WSN d@45 IN A713~~
~~WSN 0183 IN A114 WSN 0342 IN A714 ;~~
I STARTUP RESET SAT l 5 SELECTED CBA, NO GROUP 2 OUT , IN WORKING CBS GROUP 2 NO IN OR OUT CBC GROUP 1 & 2 SAT RELAY DRIVER INPUT DIODES CHECKED SAT OM BENCH I WSN 113 CHECKED SAT ON BENCH
WSN 6014 Z3 REFAILED, REPLACED Z3 - TESTED SAT l CHECKED OUTPUT DIODES ON RELAY DRIVERS A713, A714 JUMPERED TERM STRIP 100VDC TO STEP COUNTERS CBB IN, OUT GROUP 2, CBA IN, 0UT GROUP 2 I 1938 PUT A713 ON CARD EXTENDER WITH A713 CARD EXTENDER PULLEDINPUT i IN 32 THEN 31 TO O VOLT BUS, MONITOR OUTPUT PINS WITH METER AND j STEPPED GROUP COUNTERS.
~ (DEENERGlZED THE POWER SUPPLIES DURING CARD INSTALLTION). l INSTALLED WSN 6014 IN A113, WSN 0183 IN A114, WSN 0342 IN A714. i 1 REENERGlZED THE 120 VAC TO LOGIC CABINET POWERING UP DC l SUPPLIES. I 20:00 START UP RESET. CBB GROUP 1 AND 2 TEST SAT. J CBA GROUP 1 AND 2 NOT CYC[J !; URGENT ALARM FAILURE. DS1 ON j' SCL2AC LIT. 22BD GROUP CYCLING LIGHT GREEN UP EQCO. IN LOGIC CABINET, SWAP THE FOLLOWING (21 AC SLAVE CYCLER CARDS , WITH 22 AC SLAVE CYCLER CARDS): A505 WITH A405, A504 WITH A404, A503 WITH A403, A502 WITH A402, ; ' ~ ~ A501 WITH A401, A506 WITH A406. CYCLE ROD MOTION, NO CHANGE. 1
PAGE27 ( 20:45 ~ REINSTALLED THE SLAVE CYCLER CARDS TO THE ORIGINAL LOCATION. 21:05 REPLACED MASTER CYCLER SELECTOR A106 FOR POSSIBLE "GO" SIGNAL PROBLEM. IN 22BD POWER CABINET, SWAPPED SIGNALING PROCESS CARD AND LIFT FIRING CARD, PROBLEM WITH SOLID CYCLING LIGHT STILL EXIST. SIGNAL MUST BE COMING FROM LOGIC CABINET. IN LOGIC CABINET, SWAPPED A514 WITH A414, SOLID GREEN CYCLING LIGHT TRANSFERRED TO 21BD. SWAPPED A514 AND A414 TO ORIGINAL ! LOCATION (A514 SLAVE CYCLER LOGIC). i 21:35 ! REMOVED WSN 0080 FROM A514 SLOT AND TESTED THIS CARD ON THE ! TEST RIG. CARD TESTED BAD. f BENCH TESTED SPARE WSN 0082 - SAT. INSTALLED THIS CARD IN A514. PROBLEM WITH GREEN CYCLING LIGHT IN 22BD RESOLVED. l 23:45 i PLACED A406 AND A506 ON CARD EXTENDER WITH RECORDER CONNECTED TO MONITOR THE "GO" PULSE. SELECT CBA, CYCLING ROD MOTION, 21 AC INDICATED PULSES, 22AC NO PULSE. l l SWAPPED A405 WITH A 504, NO CHANGE. ) i i INSPECTED PINS ON A505 AND A504 - SAT. , l l l l I 1 I I - l
j i PAGE28 , ROD CONTROL COVERAGE TUESDAY 6/1/93 0000 - 1200 ; 0050 PLACED A406 AND A506 ON EXTENDER CARD. MONITORED PIN 5 OF A406 AND PIN 8 OF A506. CYCLE ROD MOTION. PROBLEM STILL EXISTS. PLACED A106 ON EXTENDER CARD MONITOR PIN 13 AND 15 - GOOD. RETURN A406, A106, AND A506 TO ITS ORIGINAL LOCATION. PLACED A104 ON EXTENDER CARD. MONITORED PIN 8 (UP PULSE) AND PIN 12 (DWN PULSE), TP1, TP2, TP4 ALL INDICATED GOOD PULSES. REMOVED CARD FROM A504,A505, A506 LOT, CHECK PINS AND SOCKET FOR BAD CONNECTION. PERFORMED CONTINUITY CHECK BETWEEN A505 PIN 8 AND A506 PIN 22 - GOOD. 0330 BENCH TESTED A504 WSN 232, A505 WSN 226, A506 WSN 079. TESTED SAT. 0440 SWAPPED A512, A513, A514 WITH A504, A505 A506. CYCLING ROD MOTION - NO CHANGE. REINSTALLED THE ABOVE CARDS TO THE I ORIGINAL LOCATIONS. , REQUESTED CONTROL ROOM TO SELECT CBB, CYCLING ROD IN/OUT- SAT. f 0530 REMOVED THE FOLLOWING ANDTOOK TO TRAINING CENTER FOR TESTING: A101 WSN 194 A110 WSN 0108 A106 WSN 0016 A104 0225 A111 0039 A108 0021 ! A105 0023 A112 0180 A109 0023 A113 6014 A114 0183 i
~~' 0605 TRAINING CENTER INSTALLED THE A100'S IN THE LOGIC CAB, CYCLING V~~
L. _ . _ . _ .- - _ . _ _ _ . _ _ ._- _ . _ .. -
PAGE.29 ROD MOTION FOR ALL 8 BANKS, INDICATED GOOD. CHECK A113 AND A114, CYCLE ROD MOTION, CBA GROUP 2 NOT COUNTING UP, SUSPECTED Z3 OF A113 BAD. CBB GROUP NOT COUNTING UP, SUSPECTED Z3 OF A114 BAD. REPLACED NEW 23 CHIPS ON BOTH A113 AND A114. THINGS TO DO WHEN RETURN TO PLANT: CHECK INPUT DIODE OF A713. CHECK PIN SOCKETS FOR LOCATION LOT A101 - A114. DEENERGl2E THE POWER SUPPLIES DURING THE CARDS INSTALLATION. CONTINUITY CHECKS: CHECK CONTINUITY BETWEEN OV BUS TO GROUND - 499 OHM.
~~+15V TO O V BUS - 277 OHM (POWER DEENERGlZED, CARDS INSTALLED) -15 V TO O BUS - 730 OHM (POWER OF CARDS INSTALLED)~~
~~+15 TO 100V BUS >300 KOHM j -15 TO 100V BUS >300 KOHM l~~
~~+100 TO 9V BUS 315 KOHM l~~
~~1 I i J J I 4 e~~
==
) -
PAGE30 i ROD CONTROL COVERAGE TUESDAY 6/1/931600 - 2400 1556 SWAPPED 2AC AND 2BD SLAVE CYCLER CARDS (5 CARDS EACH) 1600 PULLED FOLLOWING CARDS TO ISOLATE / DISCONNECT INTERFACES TO THE SLAVE CYCLER CARDS. A804 A805 A207 1807 PULLED A106 CARD - EXTENDED IT TO TRACE THE GO PULSES PIN 13 - 1 AC PIN 15 - 2AC RESULT: PIN 15 SHOWING A LOT OF NOISE 1615 PULLED A506 AND EXTENDED IT TO SEE IF NOISE PRESENT AT EXIT OF [ CARD ON PIN 25. 1617 NOISE DETERMINED TO BE FROM RECORDER LEADS. GO PULSES OK l 1631 MODULE A506 PIN 4 (D2, STRETCH PULSE) VERIFIED SIGNAL INSIDE THE CARD. 1645 REINSTALLED A804, A805, A106, A207 AND TOOK SET OF READINGS ON j CARD EDGE CONNECTOR. (A506 STILL EXTENDED). READINGS TAKEN ON A506 CONNECTOR TO COMPARE TO ANOTHER GOOD CARD / SET OF READINGS. .I 1651 TOOK SET OF READINGS WITH CARD A506 REMOVED BUT EXTENDER IN l PLACE - READ CARD EXTENDER POINTS.
~
~~1655 REINSERTED CARD A506 i~~
~~-1v ,. - _ - . - , - - - - - , - , - - - - , - - -, --- ,--- - - , - - , - - - -n , , - -. ,~~
_ _ _ _ _ _ _ _ _ . _. . . _ _ _ _ . ___w. _ . . _ - - .- _ _ PAGE31 EXTENDED CARD A406 . TOOK SET OF READINGS ON CARD EDGE CONNECTOR (WITH CARD CONN ON END OF EXTENDER). 1703 TOOK SET OF READINGS WITH CARD A406 REMOVED BUT EXTENDER IN PLACE - READ CARD EXTENDER POINTS. 1725 WESTINGHOUSE DOING WIRING LIST TO CHECK CONNECTOR WIRING ON A506 SLOT. DAVE BEST AND ELWOOD ROBINSON RE-EXAMINING TRACES TO DETERMINE NEXT STEP. f 1 1815 RECOMMENCED DOING TRACES OF SLAVE CYCLER (SLOT A506) - VERIFYING OPERATION OFINPUTS AND OUTPUTS AND SIGNALS ON CARD. l 1830 PULLED BOARDS A804 AND A805 TO DISCONNECT OUTPUTS / INTERFACES FROM A506. 1835 PULLED BOARDS A501, A502 A503 TO DISCONNECT OUTPUTS / INTERFACES. 1840 TRACING INPUTS AND OUTPUTS OF Z9B (CHIP)- R2ACX SIGNAL (PIN 23 ON A506) SHOULD BE GOING HIGH BUT IS STAYING LOW. 1847 PULLED A504 AND A505 RAN TRACE AGAIN - SAME RESULTS. 1853 PULLED CARD A207 TO TEST ON TESTER (S/N 0014) 1910 CARD SN 0014 FOUND TO BE BAD - BANK OVERLAP LOGIC 2 - MODULE. PIN 9 PROBLEM. l; 1916 REPLACED CARD IN A207 WITH CARD SN 0081. (BANK OVERLAP LOGIC 2). INSERTED NEW CARD IN SLOT A207 - INSERTED A504 AND A505. ALSO i INSERTED A804 AND A805. 1 1918 RETEST SHOWED SLAVE CYCLER WORKING SAT. j 1936 READY TO BEGIN TESTING STEP COUNTERS.
.e
! 1940 BEGAN TESTING STEP COUNTERS. e i w w w. r+v i n
PAGE32 1944 ALL STEP COUNTERS WORKING PROPERLY (ALL STEPPED IN AND OUT AND l RESET TO ZERO). i-k 1953 SETTING UP FOR NEXT TEST: j RECORDING / TRACING Vref IN ALL POWER CABINETS WHILE SIMULATING j ROD MOTION WITH THE WESTINGHOUSE TEST BOX (Vref IF OFF THE REGULATION CARD). MOVING GROUPS 10 STEPS OUT AND IN. 2007 CONTROL BANK A OUT 2008 CONTROL BANK A IN 4 2011 CONTROL BANK C OUT (RECORDER OUT OF PAPER) 2015 CONTROL BANK C IN l 2016 SD BANK A OUT
~~! 2016 SD BANK A IN i~~
} 2120 ABOUT 2115 STARTED CYCLES ON SD BANK A TO 228 STEPS - STEP j COUNTERS GROUP 1 - 228 GROUP 2 - 228. ACTUAL STEPS 228. SAT. l STEPPED SD BANK B TO 228 STEPS. STEP COUNTERS GROUP 1 - 228, l f GROUP 2 - 228. ACTUAL STEPS 228. SAT. 9 i 2130 STEPPED SD BANK C TO 228 STEPS. NOTE: GROUP 2 STEP COUNTER ZERO OFFSET ABOUT A 1/2 NUMBER. i STEP COUNTER'S GROUP 1 - 228, GROUP 2 - 228 WITH ABOUT A 1/2 j NUMBER OFFSET. ACTUAL STEPS 228. SAT. j j 2140 STEPPED SD BANK D TO 228 STEPS. STEP COUNTER'S GROUP 1 - 228, l GROUP 2 - 229. ACTUAL STEPS 228. SAT. l 2150 STEPPED CONTROL BANK A TO 228 STEPS GROUP COUNTERS 1 - 228, j GROUP 2 - 228. ACTUAL STEPS 228. STEPPED BACK 28 IN. GROUP j COUNTERS SAT. 2155 STEPPED CONTROL BANK B TO 228 STEPS. STEP COUNTERS GROUP 1 - 228, GROUP 2 - 228. ACTUAL STEPS 228. STEPPED BANK IN 30 STEPS.
~~STEP COUNTER SAT.~~
2205 STEPPED CONTROL BANK C TO 228 STEPS. STEP COUNTERS - GROUP 1 - 228, GROUP 2 - 228. ' ACTUAL STEPS - 228. STEPPED BANK IN 28 STEPS. j - STEP COUNTERS SAT. i
PAGE33 2215 STEPPED CONTROL BANK D TO 228 STEPS. STEP COUNTERS GROUP 1 - 228, GROUP 2 -228. ACTUAL 228. STEPPED DANK IN 28 STEPS. STEP COUNTERS SAT. j l 222o STEPPED SD A IN AND OUT 30 STEPS. STEP COUNTERS SAT. 2222 STEPPED SD B IN AND OUT 30 STEPS. STEP COUNTERS SAT. ) l 2225 STEPPED SD C IN AND OUT 30 STEPS. STEP COUNTERS SAT. l J' NOTE: GROUP 2 COUNTER DIDN'T MOVE (MECHANICAL PROBLEM). RESET COUNTER, COUNTER MOVED. 1 l 2232 STEPPED SD D IN AND OUT 30 STEPS. STEP COUNTERS SAT. 2245 STEPPED CONTROL BANKS THRU BANK OVERLAP - VERIFIED BANKS OVERLAP AS REQUIRED - STEPPED DOWN TO VERIFY PROPEFi OPERATION - SAT. 2400 ELWOOD ROBINSON REPORTED ALL COUNTERS STEPPED 228 STEFS. CONTROL BANK C GROUP 2 COUNTER WASN'T FULLY REZEROED, BUT WORKED FINE AFTER REZEROING. TECH SPEC SURVEILANCE PORTION OF FUNCTIONAL FOR 228 STEPS COMPLETED SAT. l i I 1 1 4 k. l l d d
I i . . PAGE34
~~' ~~~
~~J 1 i l~~
CONTROL ROD COVERAGE WEDNESDAY, JUNE 2,1993 00

0012:00 s
O200 APPROX. REMOVED WESTINGHOUSE SPEED SIMULATOR, DRANETZ l VOLTAGE MONITOR. POWER CABINET'S ALARM CARDS ENABLED AND j JUMPERS REMOVED. i l 0230 CONNECTED RECORDERS TO 21 AND 22 AC CAB TO SA1 Vref SA2 Vref SA3 Vref MVref - (Vref TO MONITOR OUT/IN MOTION). 1 i 0346 CONTROL BANK A SELECTED - STEPPING TO 30 STEPS GROUP 1 - 29, GROUP 2 - 30. RECORDER STOPPED - MOVES BACK TO O. 0250 STEPPING TO 30 STEPS ON CONTROL BANK A - STEP COUNTERS - GROUP
~~1 - 29 1/2 , GROUP 2 - 30. RPI'S SAT. ROD BOTTOMS RESET SAT.~~
1 ACTUAL STEPS 30. STEPPING DOWN 20 STEPS - GROUP 1 STEP COUNTER 91/2, GROUP 2 - 10. j ROD BOTTOMS 2A2 AND 1 A1 NOT BACK , BAD BULBS. ARPI'S SAT. STEPPING BACK TO 30 STEPS - STEP COUNh.7S GROUP 1 - 30, GROUP 2 - i
~~30. RPI'S SAT. ROD BOTTOM LIGHTS OUT.~~
! STEPPING 130 STEPS ON CONTROL A TO ZERO - RPI'S SAT, GROUP 1 STEP COUNTER O. GROUP 2 - O. RDD BOTTOMS. j. ! 0308 CONTROL BANK C SELECTED. STEPPING TO 30 STEPS ON CONTROL BANK C. GROUP COUNTER 1 - 30, 2 - I
~~30. RPI'S SAT.~~
~~l 2C1 '- 1C3 ROD BOTTOMS NOT CLEAR - STEPPING TO 35 STEPS - ROD~~
~~BOTTOMS CLEAR. STEPPING IN 20 STEPS ON CONTROL BANK C. GROUP~~
! COUNTERS 1-15,2-15. RPI'S SAT. ROD BOTTOM ARE IN. STEPPING OUT . 20 STEPS. ROD BOTTOM LIGHTS CLEAR, RPI'S SAT. GROUP COUNTERS 1 - ! 35, 2 - 35.
~~u. .~~
~~- STEPPING CONTROL BANK C IN TO ZERO. GROUP COUNTERS 1 - O, 2 - O.~~
~~1 ..~~
^
l 1
PAGE35 RPI SAT. ROD BOTTOM LIGHTS ON. . i - 0325 SELECTING SD A STEPPING 30 STEPS OUT. STEP COUNTERS GROUP 1 - 30.
~~, GROUP _2 - NG. RIP'S SAT. ROD BOTTOMS NOT CLEAR.~~
~~STEPPING TO 35 STEPS. ROD BOTTOMS CLEAR. GROUP 1 - 35, 2 - NG.~~
~~~ STEPPING DOWN 20 STEPS. ROD BOTTOMS LIGHT ON. RPI'S SAT. GRGuP 1 - 15. GROUP 2 - NG.~~
NOTE: WHEN STATIONARY ORDER GOES TO ZERO SA1 Vref SHOWING NOISE IN CONTROL C AND SD C. INCREASED STEPPING TO 35 STEPS - RPI'S SAT. GROUP 1 - 35, 2 - NG. ROD BOTTOMS CLEAR. I STEPPING TO O STEPS. ROD BOTTOM LIGHT ON. RPI'S SAT. GROUP COUNTER 1 - O. GROUP 2 - NG. 0350 SELECTING SDC SD C STEPPING 35 STEPS. RECORDER ON WRONG SPEED. RODS BACK IN FOR REDO. SDC AT 35 STEPS ROD BOTTOMS CLEAR, GROllP COUNTERS SAT, IRPI'S SAT. IN 20 STEPS, IRPI'S SAT, GROUP COUNTERS SAT. 0358 SDC AT 15 STEPS. ROD BOTTOM SAT, BACK OUT AT 35, SAT. 0400 SDC AT O STEPS . ALL SAT. l 0403 SDD AT 35 STEPS. ROD BOTTOM 1SD2 NOT CLEAR. IRPI'S SAT. NOISE l ON STATIONARY GROUP A WHILE STEPPING GROUP B. STEPPING TO 40
~~MODULE OUT OF SPEC.~~
BISTABLE RUD BOTTOM CLEARED. l SDD AT 20. AL SAT IRPI'S, ROD BOTTOMS OFF. GROUP COUNTERS AT 40. l l 0410 SDD AT O. GROUP COUNTERS AT ZERO. ROD BOTTOMS UP. IRPI'S SAT. i i 0415 CONNECTING RECORDER TO 21 AND 22SD. SELECTED CONTROL BANK B. 21 BD SELECT LIGHT FOR GROUP A NOT LIT. OTHER NOT LIT. i STEPPED TO 35 SET - GROUP STEP COUNTER GROUP 1 - 35, GROUP 2 - 35. j RPI'S SAT. ROD BOTTOMS CLEAR. STEPPING DOWN TO 15 STEPS, GROUP 1 - 15, GROUP 2 - 15. ROD BOTTOMS ON , RPI SAT. STEPPED TO 35 STEPS - GROUP STEP COUNTERS GROUP 1 - 35, GROUP 2 - 4
~~35. ROD BOTTOM CLEAR.~~
y. 1 i
t PAGE36 , 1 STEPPING DOWN TO O. ROD BOTTOMS ON, RPI'S SAT, STEP COUNTER GROUP 1 - O, GROUP 2 - O. 0425 SELECTING CONTROL BANK D. STEPPING CONTROL BANK D TO 35 STEPS. GROUP STEP COUNTERS GROUP 1 - 35, GROUP 2 - 35. RPI'S SAT, ROD BOTTOMS CLEAR. STEPPING TO 15 STEPS - STEP COUNTERS GROUP 1 -15, GROUP 2 - 15. RPI'S SAT, ROD BOTTOM LIGHTS ON. STEPPING TO 35 STEPS, GROUP COUNTERS GROUP 1 -35, GROUP 2 - 35. RPI'S S %T, ROD BOTTOM LIGHTS CLEAR. l STEPPING TO ZERO STEPS. GROUP COUNTERS GROUP 1 -0, GROUP 2 - O, RPI'S SAT, ROD BOTTOM LIGHTS ON. l 0435 SELECTING SD BANK B. STEPPING TO 35 STEPS, GROUP COUNTERS GROUP 1 - 35, GROUP 2 - 35. RPI'S SAT, ROD BOTTOM LIGHTS CLEAR. STEPPING TO 15 STEPS, GROUP COUNTER GROUP 1 - 15, GROUP 2 - 15, RPI'S SAT, ROD BOTTOM LIGHTS ON. i STEPPING TO 35 STEPS. GROUP COUNTER GROUP 1 - 35, GROUP 2 - 35, RPI'S SAT, ROD BOTTOM LIGHTS CLEAR. STEPPING TO O STEPS, GROUP. COUNTERS GROUP 1 - O, GROUP 2 - O, RPI'S SAT, ROD BOTTOM LIGHTS ON. CAB 22BD CARD K2 (MUX ERROR DET) DS1 (GR A MUX ERROR) BULB BROKEN. OBSERVED NOISE ON SA1 Vref - SWAPPED RECORDER LEADS NOISE STILL THERE. 0510 CONNECTING RECORDER TO MONITOR EFFECTS OF NOISE. SAVref CH 1 - CONTROL BANK A Vref SCVref CH 2 - SD BANK A Vref TEST PT 51 - CH 4 CONTROL BANK A GROUP 1 ROD CURRENTS 52 - CH 5 " 53 - CH 6 " 50 - CH 3 "
l
. .. .. j 'l . l PAGE37 ):
1 I l 1 l 8 i 4 l THURSDAY JUNE 3,1993 0:00 TO 12:00 l DURING STARTUP PROCESS OPERATOR NOTES THE P/A CONVERTER AND THE Rll COMPUTER DID NOT PROVDED ANY INDICATONS DURING ROD MOTON. l TROUSLESHOOTING CBS & CBD PULSE TO P/A CONVERTER, AND RlL COMPUTER. ! 01:30 AM ! SETTING UP PREPARATONS AND APPROVAL OF TROU8LESHOOTING PROCEDURE. j CONNECTED TEST RECORDER TO MONITOR CBD UP PULSES. OUTPUT OF A114 CARD l AND OLTTPUT OF THE RELAY DRIVER CARD A711. A711, PIN 30,15 VDC INPUT & PIN 9,100 VDC OUTPUT. i I O2:06 AM CONNECTED RECORDER TO CBD BANK MOVED RODS 3 STEPS IN THEN OUT. NO [ CHANGE ON RECORDER. i 4 02:25 AM ' i MOVED RECORDER TO MONITOR CBS. NO CHANGE ON RECORDER WHEN CYCLE ROD MOTON OUT THEN IN 3 STEPS. 4 C2:45 AM
~~MOVED RECORDER TO MONITOR SBA, RECORDER PULSED BUT THE COMPUTER P250 l INDICATON REMAIN THE SAME.~~
~~i , 03:15 AM . 1~~
~~- _ _ _ - - . __ a~~
_ -_ .. .. .- - - . . - --- . . - . - . . - . . . - . . . . - - - .~ -. 6 i i ! I PAGE38 : CONNECTED RECORDER TO A114 TO TEST Z13 CHIP. A114 PIN 2 AND TP 1 AND ; A110 PIN 22. STEPPED RODS +/-3 STEPS. PIN 2 & A110 PIN 22 PULSED ON - RECORDER BUT TP1 DID NOT. 03:50 AM ! ALL ROOS IN REMOVING A114 CARD FOR TESTING. CONTROL ROOM STEP COUNTER ! SBA utSSED 10 STEPS WHEN DRIVEN IN. l BENCH TEST OF CARD A114 BAD, Z 3 CHIP FAILED TEST. REPLACED CHIP RETESTED CARD SAT RESULTS ON BENCH. REINSTALLED CARD FOR OPERATIONS TO RETEST. !
^
06:30 AM OPERATIONS WITHDREW ALL ROD BANKS +/- PULSE TO ANALOG SIGNALS ALL CONTROL BANKS SAT WITH P250 INDICATIONS. , 1 l 1 i e
0 o'
\
Temocrary p_tandina order Based on preliminary analysis, Engipeering has determined that the possibility of a single failure exists which could cause a single control rod to withdraw. This potential situation is contrary to the statements in the UFSAR Section 15.3.5.1. Since this problem could put us beyond the current design basis, certain actions must be taken by Operations to limit the possibility of a single rod withdrawing at power and thereby exceeding the radial power limits. Operations Actions , g
1. Operate Salem Unit 1 control rods in " Manual" until the Rod Insertion Limit alarms are changed to reflect the higher values.

2. Control rod insertion limits will be administrative 1y l controlled at greater than 205 steps at 100% power.

3. Operators will need to pay additional attention to any manual rod insertions, since the failure could cause the rods to withdraw instead.

4. During rapid load reductions, rods shall not be 4
placed in " Auto" as delineated in the abnormal or alarm response procedures. The control operator and supervisor will determine if the transient condition can be handled with the rod control in " Manual" and take the appropriate actions to stabilize the plant. ) If the transient results in challenging the safety l system setpoints, then the control operator and supervisor would be expected to initiate a manual reactor trip. These actions will be reviewed by every supervisor and control operator prior to assuming the watch. A curve will be provided by Reactor Engineering to delineate the rod insertion limits versus power. The Technical Specification limiting condition for operation will be entered and the action statement complied with, if the control rods are below the revised insertion limit curves. This standing order will be in effect until further notice. V-SHIFT SNSS NSS NSS NSSF NSSW NCol NCO2 NCO3 NC04 NCOS W-SHIFT SNSS NSS -uA/ NSS NSSF NSSW NCol NCO2 NCO3 NC04 NCOS X-SHIFT SNSS NSS NSS NSSF NSSW NC,01 NCO2 NCO3 NC04 NCO5 Y-SHIFT SNSS NSS NSS NSSF NSSW Nq01 NCO2 NCO3 NC04 NCOS Z-SHIFT SNSS .NSS NSS NSSF NSSW NC01 'NCO2 n NCO3 NC04 ECOS OPS-STAFF legL /fffpF r v s 4 13
o* . L.~ lo. 1 l JUNE 3,1993
~
~~\ MONDAY MAY 24,1993 DURING OPERATION SURVEILLANCE, CBA GRP 2 & CBC GRP 1 FAILED TO MOVE,~~
~
URGENT ALARM RECEIVED IN 22AC POWER CABINET. l l R1 IN MULTIPLEXING CIRCUIT BLOWN IN 22AC POWER CABINET. THIS RESISTOR FAILURE WAS CAUSED BY A SHORT LIGHT BULB (GROUP A SELECT LIGHT). DURING WESTINGHOUSE MAINTENANCE, GROUP A SELECT LIGHT SOCKET WAS REPLACED WITH A WRONG TYPE. CORRECT TYPE OF LIGHT SOCKET WAS REPLACED 6/2/93. THE SUPERVISORY DATA l.OGGING CARD, A113, WAS REPLACED. OPERABILITY TEST FOR CBA, CBC, SBA - SAT. TUESDAY MAY 25,1993 l DURING IRPI CALIBRATION OPERATION IDENTIFIED PROBLEM WITH CBS GRP 1 & 2 STEP COUNTERS. STEP COUNTERS REMOVED AND BENCH TESTED. REPLACED CBS COUNTERS WITH THE OLD COUNTERS THAT WERE TAKEN OUT BY WESTINGHOUSE A WEEK EARLIER. WEDNESDAY MAY 26,1993 ! 02:00 AM CBC GRP 1 FAILED TO STEP OUT. REMOVED THE COUNTER AND BENCH TESTED - SAT. PULSES NOT AVAILABLE AT THE CONTROL BOARD DUR6NG ROD MOTION. REMOVED THE FAILURE DETECTOR' CARDS AND JUMPER THE ALARM CARD IN THE FIVE POWER CABINETS TO OVERRIDE THE URGENT ALARMS DURING TROUBLESHOOTING. OPEN LIFT D!SCONNECT FOR CBA, CBC, SBA. AT LOG!C CABINET, REMOVED AND PLACED A714 ON EXTENDER. MEASURED THE OUTPUT PULSE OF A714 - NO PULSE. SWAPPED A714 WITH A713, PROBLEM SHIFTED FROM CBC GRP1 TO CBC GRP2. OBTAINED NEW RELAY DRIVER FROM FOLIO AND INSTALLED IN A714 SLOT. VERIFIED , OPERATION FOR CBC GRP 1 - SAT. CBC GRP 2 DID NOT STEP IN EITHER DIRECTIONS. CYCLING LIGHT FOR 22AC POWER CABINET INDICATED - SAT. '
~~MEASURED OUTPUT VOLTAGE AT A714 PINS 29, 30, 33, 34; AND A713 PINS 29, 30,33,34.~~
N
~~'.9~~
23:50 INSTALLED WSN 0681 IN A714, WSN 0120 IN A713, WSN 0039 IN A113. MOVE CBA OUT THEN IN WITH GRP 1 & 2 COUNTERS REMOVED. CBA GRP 1 NOT STEP IN, CBA GRP 2 OUT VOLTAGE REDUCED. REMOVED WSN 0039 FROM A113 SLOT. TAKE WSN 0039, 6014, 695, 120. 681,701 TO TRAINING CENTER FOR TESTING. REPLACED Z2 & Z3 ON WSN 0039. 22, ZC,26 ON WSN 6014. THURSDAY MAY 27,1993 05:00 AM INSTALLED RELAY DRIVER CARDS FROM TRAINING CENTER WSN 0845, 0342 TO A713, A714 AND WSN 0039 IN A113. MOVE 10 STEPS OUT THEN IN FOR SBA, CBA, CBA SBA, CBC - SAT. CBA l GRP 2 NOT STEP IN. CONNECTED RECORDER TO TB 42 PIN 1 &2 AND TB 42 4 & 5 - COIL TO STEP COUNTER 100 VDC; MOVE CBA GRP 2 UP, DOWN - NO CHANGE. SWAPPED A713 WITH A714 THEN MOVE CBA OUT THEN IN 10 STEPS. SUSPECTED RELAY DRIVER CARD. PROBLEM STILL CBA GRP 2 NO "lN". REPLACED A113 WITH SPARE WSN 6014, MOVE CBA OUT GRP 1 & 2 - SAT. l l l 08:40 AM PERFORMED OPERABILITY TEST FOR CBA, CBC, SBA - SAT. CBB DID NOT COUNT FOR OUT DIRECTION. REMOVED WSN 216 FROM A114 SLOT. INSTALLED SPARE WSN 0039 IN A114 SLOT. MOVE CBD OUT-SAT. MOVE CBB OUT GRP1 - SAT. GRP 2 NOT COUNTING. MOVE SBB OUT THEN IN - SAT. REMOVE WSN 0039 FROM A114, REPLACED Z3 WITH NEW CHIP. INSTALLED WSN 0039 IN A114, MOVE CBB OUT - GOOD PULSE. MOVE CBA, CBC OUT THEN IN, CBA GRP2 & CBC GRP2 NOT STEP IN NOR OUT. SUSPECT Z3 & Z6 BAD. REPLACED Z3 & 26 ON WSN 6014. l l
l i 13

05 i j CHECK INPUT DIODE FOR ALL RELAY DRIVER CARDS. FOUND 1 BAD DIODE' j . CR1 OF A710 SLOT. REPLACED DIODE. :
~~i l lNSTALLED WSN 6014 IN A113, VERIFIED CBC OPERABLE - GOOD. , 4~~
14

30 MOVE CBS OUT - GRP 1 SAT, GRP 2 STEP IN ONLY. '
l MOVE CBB - SAT. i MOVE SBB OUT THEN IN - SAT. CCB GRP 2 STEP IN AT THE SAME TIME. I MOVE CBD OUT THEN IN - SAT. CCB GRP 2 STEP IN AT THE SAME TIME. l SUSPECT Z3 OF A114 BAD. 4
15

30 REMOVED WSNOO39 FROM A114 SLOT. INSTALLED WSN 216 IN A114
! SLOT, WITH THE POWER DEENERGlZED. ENERGlZED THE POWER SUPPLIES, PERFORMED OPERABILITY FOR ALL BANKS - SAT. 1 18:37 COMMENCED PULLING SHUTDOWN BANKS FOR STARTUP. l 18:44 WHEN PULLING SBA IT WAS OBSERVED THAT 1RPI DID NOT INDICATE RODS WERE BEING STEPS ON THE STEP COUNTERS. ALL IRPI INDICATED ZERO STEPS. ROD INSERTION WAS STOPPED AT 6 STEPS INDICATED ')N THE t GROUP STEP COUNTERS. NO CHANGE WAS OBSERVED AS ALL IRPl'S l lNDICATED ZERO EXCEPT 1SA3 WHICH INDICATED 15 STEPS. ALL ROD
~~BOTTOM LIGHTS STAYED LIT DURING THE WHOLE WITHDRAWAL AND~~
'. INSERTION SEQUENCE. SBA WAS THEN INSERTED TO ZERO STEPS AS l lNDICATED ON THE GROUP STEP COUNTER. WHEN THE STEP COUNTER COUNTED FROM 1 TO ZERO ONE FLASH - OFF THEN ON - WAS OBSERVED l ON THE ROD BOTTOM LIGHT ON RP3 FOR 1SA3. i THE ROD FUSES WAS PULLED FOR 1SA3 TO ENSURED THE ROD IN THE i BOTTOM. ALL LIFT COIL DISCONNECTS FOR SBA WERE OPENED TO ALLOW TROUBLESHOOTING OF ROD CONTROL. e s
~~,4 ,-, - -. , , - . . -, -~~
~~._ - - - . .~ ~ . . .-~~
4 FRIDAY MAY 28,1993 00:00 AM THE BUS DUCT DISCONNECT SWITCHES FOR CONTROL POWER CABINETS 21 AC AND 22AC WERE OPENNED TO ENSURED THAT ALL ROD WERE ON THE BOTTOM. TROUBLESHOOTING IDENTIFIED TWO SLAVE CYCLER DECODERS, A511 (22BD MOVABLE) AND A501 (22AC STATIONARY) CARDS WERE BAD. REPALCED A501 AND A511 WITH NEW CARDS. PERFORMED OPERABILITY FOR SBA, CBA, CBC WITH A RECORDER CONNECTED TO MONITOR THE CURRENTS TRACE - SAT. 11:00 AM ,, PERFORMED' OSCILLATOR CHECK, MULTIPLEXING CHECK, SLAVE CYCLER ERROR FUNCTIONAL CHECK - SAT. CONNECTED RECORDER TO MONITOR THE 15 VDC POWER SUPPLIES. ; COMMENCE STARTUP. i s e 4 1
ROD CONTROL COVERAGE SATURDAY MAY 29,1993 NO TIME PROVIDED
~~+ CONTROL BANK C GROUP 1 DROPPED - NO URGENT ALARM BANK SELECTOR SWITCH WAS IN MANUAL BANK OVERLAP SELECTED TO MASTER STEP COUNTER AT 540.~~
NO OPERATOR INITIATED MOTION FOR UP TO 40 MIN PRIOR TO PROBLEM. ROB BOTTOM ALARM & LIGHTS TOOK STATIC VOLTAGE READINGS OPERATORS OPENED REACTOR TRIP BREAKERS THEN RECEIVED URGENT FAILURE ALARM. STATIONARY REGULATION FAILURES IN ALL CABINETS AND PHASE FAILURE STATIONARY FOR 22AC POWER CABINET. MOVING REGULATION ERRORS IN ALL CABINETS. NO LOGIC ERROR ON ANY OF THE CABINETS. 21 AC MA SIGNAL READING 12.5 VAC. ( 21 AC CABINET STATIONARY CURRENT ORDERS WERE AT REDUCED CURRENTS.TOOK READING ON REG CARD TP2 FOR CONTROL C: 6.18V. TOOK READING ON REG CARD TP2 FOR CONTROL A: 6.2V. PULLED 21 AC CONTROL C REG CARD - EXTENDED IT - TOOK READINGS: PINS 31 TO 19: 19.93 V (ZERO CURRENT ORDER) PINS 21 TO 19: 9.3 V (REDUCED CURRENT ORDER). , PULLED 21 AC CONTROL A REG CARD - EXTENDED IT -TOOK READINGS: PINS 31 TO 19: 19.1 V (ZERO CURRENT ORDER) PINS 21 TO 19: 9.3 V (REDUCED CURRENT ORDER). , i l JIGGLED A803 CARD WHILE READING 21 AC CONTROL C REG SIGNALS - NO CHANGE IN VOLT READING -SAME AS ABOVE. PULLED FAIL DET CARDS - INSTALLED INTERLOCK JUMPERS - REISERTED CARDS IN ALL 5 POWER CABINETS. 3 - REINSTALLED 21 A STATIONARY REG CARD - REMOVED 22C STATIONARY REG CARD - EXTENDED IT. !~ RAN TRACES ON Rr AND Rz (I ORDERS) IN CONTROL BACK C GROUPS
I . '., . t l ! 1 & 2. j Rz - NOT CLOSE TO CHARACTERISTIC AC WAVEFORM. i Rr - REDUCED AMPLITUDE. l PULLED FIRING CARDS AND EXTENDED - REINSTALLED REG CARD j (NOT EXTENDED). LOGIC ERRORS IN BOTH AC CABINETS - DUE TO PULLING FIRING CARDS - AFTER EXTENDED RESET IN BOTH CABINETS. RAN TRACES ON Rr & Rz WITH SAME RESULTS AS ABOVE.
~~; RAN TRACE ON TP5 AND TP6 ON FIRING CARDS (SWITCHING~~
~~! AMP OUTPUTS) - CONTROL BANK C STATIONARY FIRING CARDS 1 FOR 1 AC AND 2AC: RESULTS: 1 AC - TP5 FLAT LINED~~
~~- TP6 SAW AC 2AC - AC ON BOTH TP5 AND TP6.~~
RAN TRACE ON TP7 (OSCILLATOR OUTPUT) AND TP5 IN 1 AC AND 2AC CONTROL BANK C. RESULTS: 1 AC - TP5 FLAT LINED 1 AC - TP7 AC 2AC - TP5 AND TP7 AC READJUSTED RECORDER TO OBTAIN A HIGH SPEED MEMORY TRACE. RESULTS: 1 AC TPS FLATLINE 1 AC TP7 AND 2AC TPS AND TP7 LOOKED SATISFACTORY. PULLED 1 AC FIRING CARD (#395) GR B STATIONARY AND TOOK TO LAB FOR BENCH TESTING. RESULTS: OSCILLATOR AND SWITCHING AMP SECTIONS TESTED SAT. REINSTALLED 1 AC FIRING CARD - EXTENDED. s
~~NOTED FILTER WAS ON FOR 1 AC TP5 VISICORDER CH 1.~~
RECONNECTED TO TP5 AND TP7 FOR 1 AC AND 2AC. TURNED OFF CH 1 FILTER ON VISICORDER AND NOTICED AN AC
SIGNAL ON CH 1. WHILE MONITORING INPUTS TO VISICORDER CH 1 - APPLIED HEAT TO FIRING CARD WITH HEAT GUN - SEVERAL MINUTES. RESULTS: AC AMPLITUDE DID NOT' CHANGE. MONITORED Rr AND Rz AT THE FIRING CARD' EDGE CONNECTOR WITH ROD MOTION. RESULTS: NOW READING AS EXPECTED. TURNED VISICORDER CH '1 FILTER BACK ON. RESULTS: WAVEFORM IS SMOOTHED BUT HAS CORRECT SHAPES AND IS NOT IDENTICAL TO 1ST SET OF TRACES THAT WERE RUN. SELECTED TO CONTROL BANK D AND IN 1 AC - LIFTED INCOMING ZERO I ORDER (TB20-1). RESULT: LOGIC ERROR ALARM DID NOT LIGHT. SELECTED TO CONTROL BANK C AND IN 1 AC - LIFTED INCOMING ZERO 1 ORDER LEAD (TB20-1). RESULT: , LOGIC ERROR ALARM LIT. PERFORMED SAME SEQUENCE IN 2AC WITH THE SAME RESULTS. l VOLTAGE READINGS (1 ORDER SIGNALS) WITH CONTROL BANK C SELECTED. l I ! TB# SIG NAME 21AC 22AC l 19 4,5 S1A 1.67 VAC 1,74 VAC 19 7,8 S1B 12.7 12.44
20 1,2 S2A 1.66 1.73

20 4,5 S2B 12.73 12.33 20 10,11 S3A 1.67 1.8 >
21 1,2 S3B 12.72 12.56 t 21 7,8 MA 12.9 12.86 23 4,5 LA 12.54 14.03 l , 23 7,8 LB 12.59 15.03
CONNECTED RECORDER TO A109 TP4 (UP PULSE), A113 TP4 & TP5, AND A714 PIN 30, TO MONITOR INPUT AND OUTPUT PULSES OF THE DATA LOGGING CIRCulT - NO OUTPUT PULSE. 08:00 AM REPLACED A113 WSN 6014 WITH WSN 0039 FROM FOLIO (MODEL NO i 3361CO8G01) . CONNECTED RECORDER TO MONITOR THE +/- 15 VDC POWER SUPPLIES. CYCLE ROD MOTION, CBC, SBA, CBA GRP 1 - SAT, CBA GRP 2 NOT STEPPING. ; SWAPPED A714 WSN 0681 WITH SPARE WSN 0695 - NO CHANGE. RESTORED WSN 0681 TO A714 SLOT. ! A113 CARD FAIL AGAIN! REPAIRED SPARE WSN 6014, REPLACED Z3 & Z6 CHIPS. INSTALLED WSN 6014 IN A113, CYCLE ROD MOTION FOR CBC, CBA, SBA WITH THE RELAY DRIVERS A?14 & A713 REMOVED. MONITOR A113 OUTPUTS, SUSPECT Z8, Z5 & Z2 CHIPS ARE BAD. REPAIREo WSN 6014, REPLACED Z2, Z5 & Z8. WSN 0039 REPLACED Z3,22, Z8 lNSTALLED WSN 6014 IN A113, CYCLING ROD MOTION WITHOUT A713 & A714 INSTALLED - CHECK SAT. REPEAT WITH WSN 0039 - CHECK SAT. PERFORMED A VISUAL INSPECTION OF ALL TERN I POINTS AND TERMINAL STRIP FOR LOOSE CONNECTIONS, ABNORMAL ... - CHECK SAT. INSTALLED WSN 0039 IN A113 SLOT. : WITH RECORDER CONNECTED, CYCLING ROD MOTION FOR SBA - SAT. ' CYCLING ROD MOTICN FOR CBA WITH A713, A714 INSTALLED, CBA GRP 1 NOT STEP IN. REMOVED WSN 039 FROM A113. REPLACED Z2. REINSTALLED WSN 0039 TO A113, MEASURED OUTPUT VOLTAGE FOR PIN 11-14, 21 SAT. INSTALLED WSN 681 TO A713, WSN 695 TO A714. CYCLE CBA OUT/IN GRP 1 - SAT. GRP 2 NO PULSE NOR COUTER STEPPING. SUSPECT 23, Z2 OF A113 BAD AGAINI REPLACED Z3,22 CHIPS. i
i . VOLTAGE READINGS (1 ORDER SIGNALS WITH CONTROL BANK D SELECTED. i i TB# SIG NAME 21 AC 22AC 19 4,5 S1A 1.67 VAC 1.74 VAC l 19 7,8 S1B 12.69 12.44 20 1,2 S2A 1.66 1.73
20 4,5 S2B 12.73 12.34 j 20 10,11 S3A 1.68 1.81 j 21 1,2 S3B 12.75 12.58 j 21 7,8 MA 12.91 12.86 23 4,5 LA 12.54 14.03 l 23 7,8 LB 12.59 15.04 i
! REMOVED FOLLOWING CIRCUlT CARDS IN 21 AC: D1 - GR B FIRING #0395 ! E1 - GR B PHASE CONTROL #0366 , F1 - GR B REGULATION #0297 4 REMOVED FROM LOGIC CABINET: a 1/0 AC AMP A803 CARD #0872 i l REMOVED D1 CARD FROM EXTENDER AND REINSERTED INT BACK IN D1 SLOT WITHOUT EXTENDER (IN 22AC) SO IT WOULDN'T BE . DAMAGED BY PASSERS-BY. i a i e d l
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ROD CONTROL COVERAGE SUNDAY MAY 30,1993 00:00 TO 12:00 02:40 A.M. l 4 in Cabinet 21 AC - performed the following work: l Replaced three cards FIRING CARD - SLOT D1, OLD SERIAL # 0395, NEW SERIAL # 6120 l PHASE CARD - SLOT E1, OLD SERIAL # 0336, NEW SERIAL # 0364 REGULATOR CARD - SLOT F1, OLD SERIAL # O297, NEW SERIAL # 6053 - 02:45 A.M.
~~; + in the Logic Cabinet Replaced one card 1/O AC AMP CARD, SLOT A803, OLD SERIAL # 0872 or 0372, NEW SERIAL # 0144.~~
~~02:55 A.M.~~
~~+ ALL CARDS CHECKED FOR POTENTieiTENSION PROBLEMS, ADJUSTMENTS WERE MADE TO THE FOLLOWING CARDS~~

~~4 , CAB. 21 AC, SLOTS A1, B2, B2, D2. CAB. 22AC, SLOTS A1, A2, K1. CAB. 21 BD, SLOTS A1, E1, F1, G1, H1,11, J1, K1, A2, 82, C2,12, J2,~~
~~K2.~~
CAB. 22BD, SLOTS A1, 81,11, J1, K1, A2, B2, E2, J2, K2.
l l. !- 03:00 A.M.
+ DISCOVERED FUSES FU11 & FU6 BLOWN ON THE 100 VDC POWER SUPPLY CIRCUlT. THE TECHS WERE PREVIOUSLY HOOKING UP A WESTINGHOUSE TEST BOX FOR SIMULATING ROD MOTION. THIS INVOLVED SNAKING TEST LEADS FROM THE FRONT TO THE BACK OF THE CABINET. THE HELPER WHEN ASKED LATER REMEMBER SEEING THE TWO FUSES COME IN AND HEARING CLICKING NOISE, ASSUMED RELAYS. FURTHER INVESTIGATION REVEALED THAT THREE FUSES HAD BLOWN. THE ONE FUSE' DID NOT PROVIDE INDICATION IT WAS BLOWN BECAUSE IT WAS ON THE NEUTRAL.
THIS INFORMATION WILL BE VERIFIED VIA OF INTERVIEWS ON THE MIDNIGHT TO NOON SHIFT. 3/31 02:00 A.M. TOM MCKEE WAS NOT SURE IF THEY WERE PASSING LEADS THROUGH THE CABINET OR GETTING READY TO WHEN HIS HELPER SHERMAN WOOD BROUGHT TO HIS ATTENTION THE TWO BLOWi4 FUSES.
+ REVIEW OF THE DRANETZ RECORDER SHOWED THAT A TRANSIENT OCCURRED AT 2:22 A.M., THE 15 VDC POWER SUPPLY DIPPED TO 12.8 VDC, NOTE THIS IS AN ABSOLUTE VALUE. THE (-) 15VDC WAS ALSO SHOWN TO BE PROVIDING 15.8 VDC INSTEAD OF 15.0 VDC.. THE CHANGE IN THE (-) 15 VDC OUTPUT OCCURRED APPROX. 2:25 A.M.. AN m INVESTIGATION INTO THIS WILL CONSIDERED SEEING IF THE ONE OF THE AUCTIONEERING DIODES SHORTED. + IN GENERAL THERE WERE MANY OF PROBLEMS LOCATING RECORDER PAPER. EVENTUALLY A ROLL WAS CUT IN HALF ON THE BAND SAW TO USE IN THE DRANETZ. + THE POWER SUPPLIES IN THE LOGIC CABINET WERE CHECKED OUT, PRIMARY TO GROUND - OPEN, VERIFIED NO SHORTS. + FOUND A SLIGHTLY LOOSE OV BUS MAIN FEED CONNECTOR IN CAB. 21 AC, IT WAS TIGHTENED. THE OV BUS MAIN FEEDS WERE TIGHTENED / CHECKED IN ALL POWER CABINETS.
s e
07:00 A.M. .
~~+ HOOKED UP A RECORDER TO THE FOLLOWING POINTS IN CAB. 21 AC:~~
~~CH.1 S2A TB20-1 TB20-2 CH.2 S2B TB20-4 TB20-5 1 CH.3 LA TB23-4 TB23-5 CH.4 LB TB23-7 TB23-8 CH.5 MA TB212-7 TB21-8~~
; CH.6 SvREF F1-TP2 OV BUS l CH.7 LvREF F2-TP2 OV BUS i CH.8 MvREF C2-TP2 OV BUS PERFORMED A FUNCTIONAL ON BANK C - RAN COUNTERS OUT TO 730 i COUNTS WITHOUT ANY PROBLEMS INDICATED ON THE TRACES. WILL I LEAVE RECORDER HOOKED-UP T BANK C WHILE RUNNING OUT THE OTHER BANKS. ALL OTHER BANKS OPERATED SATISFACTORY.
3
+ THE (-) 15 VDC AUCTIONEERING DIODE WAS FOUND BLOWN ON THE MAIN POWER SUPPLY, ITS WAS INDICATING A DROP OF ONLY 4.68 mV. A NEW DIODE WILL BE INSTALLED. + RON HEATON WILL HAVE THE CARD SOCKETS INSPECTED ON THE CARDS 4
THAT WERE REPLACED. THE INTENT IS TO ENSURE THAT A LOOSE CONNECTION WAS NOT RESPONSIBLE FOR THE PREVIOUS FAULTS. i e t
l l l ROD CONTROL COVERAGE SUNDAY MAY 30,199312:00 TO 24:00 13:15
~~+ TROUBLESHOOTING OF 100 V AND +/- 15 VOLT POWER SUPPLIES IN PROGRESS.~~
~~15:15~~
+ -15 V POWER SUPPLY AUCTIONEERING DIODE REPLACED. POWER SUPPLY TROUBLESHOOTING DONE WITH.NO OTHER COMPONENTS REPLACED. THE MAIN 100 V PS RUNS AT 98.3 V,182 MV RIPPLE,WHILE THE AUX RUNS AT 105.3 V,300 MV RIPPLE.
~~16:30 l~~
+ INVESTIGATING CURRENT SIGNALS TO POWER CABINETS. ON RECOVERY OF THE 15 VOLT POWER SUPPLIES, IT WAS SEEN THAT THE CURRENT ORDERS WERE NOT CORRECT. 1/0 AC AMP CARD S/N O.144 IN LOGIC l CABINET SLOT A803 WILL CORRECT ITS OUTPUT SIGNALS WHEN IT IS -' JOGGLED OR WHEN CERTAIN TRANSISTORS ARE TOUCHED. THIS IS AN IN0lCATION OF FAULTY TRANSISTOR CIRCUITS.
~~17:00 l I~~
~~+ REMOVED S/N 0144 FROM SLOT A803. ;~~
PLACED S/N 0660 FROM SLOT A805 IN SLOT A803. PLACED S/N 0144 IN SLOT A805. WITH THIS CONFIGURATION, THE CURRENT ORDERS WERE SATISFACTOPY (ON THE RECORDER) FROM THE SLOT A803. (BY DVM THE OTHER ORDERS j WERE REVIEWED WITH INCONSISTENT RESULTS, SO IT WAS DECIDED TO l REMOVE AND TEST ALL OF THE l/O AC AMP CARDS. j
. I REMOVED THE FOLLOWING FROM THE LOGIC CABINET FOR INSPECTION ON THE TEST RIG: l l
~~REMOVED S/N 0144. REMOVED S/N 0660. REMOVED S/N 0121 FROM SLOT A801. REMOVED S/N 0107 FROM SLOT A802. j REMOVED S/N 0108 FROM SLOT A804.~~
)
l
t \- ! 19:51 - l
. + S/N 0144 TRANSISTORS Q13 AND Q14 REPLACED AND STILL DEFECTIVE. I 20

40 l
4
~~$ REMOVED THE FOLLOWING FROM THE LOGIC CABINET FOR INSPECTION ON i THE TEST RIG:~~
~~. REMOVED S/N 0147 FROM SLOT A808.~~
~~REMOVED S/N 0149 FROM SLOT A812.~~
REMOVED S/N 0100 FROM SLOT A813. REMOVED S/N 0142 FROM SLOT A814. ; 20:40 4 RETURNED THE FOLLOWING TO THE LOGIC CABINET: S/N 0121 TO SLOT A801. S/N 0107 TO SLOT A802. S/N 0122 TO SLOT A803. S/N 0108 TO SLOT A804. S/N 0660 TO SLOT A805. S/N 0122 IS A CARD PREVIOUSLY REPAIRED BY VARTEK. S/N 0146, A SPARE CARD, FAILS TEST ON TEST RIG. IT WAS PREVIOUSLY TESTED SAT AT NTC ON 3-24-88 AND BY WESTINGHOUSE ON 3-6-91. ALL CAGE AND CARD EDGE CONNECTORS EXAMINED FOR CORRECT PIN ALIGNMENT. 22:20
~~+ S/N 0142 FOUND DEFECTIVE ON TEST RIG.~~
S/N 0147 FOUND DEFECTIVE ON TEST RIG. S/N 0149 FOUND DEFECTIVE ON TEST RIG. S/N 0150 FOUND DEFECTIVE ON TEST RIG. 1 S/N 0144 REPAIRED. S/N 0372 OK ON TEST RIG. THIS IS S/N REMOVED PREVIOUSLY ON 5-30-93 AT 02:45. l
23:30 's
~~; + S/N 0142 REPAIRED.~~
~~i RECORDERS ARE IN PLACE TO MONITOR THE STATIONARY COIL SIGNAL TO~~
~~] ONE OF EACH GROUP. ~~~
PLANS BEING REVIEWED INCLUDE: 4 DETERMINING HOW MANY OTHER CARDS IN THE LOGIC CABINET MUST BE TESTED DUE TO THE 15 VOLT POWER SUPPLY PROBLEM. l DETERMINING CONTENT OF RETESTING WHICH PRESENTLY INCLUDES l STEPPING THE RODS IN AND OUT WITH THE SIMULATOR (PLACED IN THE f LOGIC CABINET) AND THEN POWERING UP THE SYSTEM AND MOVING RODS (LEAVING RECORDERS IN' PLACE). t e 1 a J i i i i , 4 i I 1 'i i 1 4 0 I 1 ! l 1 e (
l . r . . r ROD CONTROL COVERAGE MONDAY MAY 31,1993 00:00 TO 12:00 l 02:30 A.M.
+ INSTALLED 1/0 AC AMP CARDS IN LOGIC CABINET 1 S/N 0144 - SLOT A814 i S/N 0142 - SLOT A813 S/N 0872 - SLOT A812 S/N 0149 - SLOT A808 :
~~S/N 0150 - SLOT A805 S/N 0147 - SLOT A804 . S/N 0146 - SLOT A803 02:40 A.M.~~
+ PULLED THE RELAY DRIVERS FROM LOGIC CABINET TO TEST S/N 0135 - SLOT A705 S/N 0680 - SLOT A706 S/N 0402 - SLOT A707 S/N 0136 - SLOT A709 S/N 0370 - SLOT A710 S/N 0134 - SLOT A711 S/N 0345 - SLOT A713 S/N 0342 - SLOT A714 02:45 A.M. + EVERY CARD ASSOCIATED WITH -15 VDC BUS WAS REMOVED FROM THE LOGIC CABINET FOR INSPECTION IN THE WESTINGHOUSE CARD TEST 8R EQUIPMENT.
FAILURE DETECTORS CARDS S/N 0022 - SLOT A708 TESTED SAT \ l
l l 02:45 A.M. - CONTINUE PULSE SHAPER CARD l S/N 0036 - SLOT A701 1 S/N 0040 - SLOT A702 l I 1/0 REC. CARD S/N 0028 - SLOT A809 TESTED UNSAT, NO OUTPUT ON PIN 4, I 1 REPLACED TRANSISTOR Q12. S/N 0032 - SLOT A810 TESTED SAT l 1 PULSER OSC. CARD S/N 0147 - SLOT A314 TESTED SAT S/N 0194 - SLOT A101 TESTED SAT 03:30 A.M. a + PULLED AND BENCHED THE FOLLOWING CARDS FROM THE LOGIC CABINET. THIS WAS PROBABLY DONE ON PREVIOUS SHIFT, HOWEVER THE TURNOVER NOTES DID NOT INDICATE CLEARLY THAT THESE CARDS TESTED SAT. THEREFORE IT WAS DECIDED TO RUN THEM THROUGH THE TEST RIG AGAIN. ALL CARDS TESTED SAT. S/N 0121 - SLOT A801 S/N 0107 - SLOT A802 S/N 0122 - SLOT A803 S/N 0108 - SLOT A804 S/,N 0660 - SLOT A805 i 04:45
+ RELAY DRIVERS WERE TESTED SAT l 07:15 * + ALL CARDS REINSTALLED AND SETTING UP RECORDERS FOR FUNCTIONAL TEST OF ALL CURRENT ORDERS. THE RECORDERS WERE CONNECTED TO THE FOLLOWING POINTS IN EACH GROUP:
1
STATIONARY COIL A VREF STATIONARY COIL B VREF STATIONARY COIL C VREF MOVING COIL VREF LIFTING COLL VREF 08:15
~~+ STARTED TRACES, ALL TRACES LOOK SAT. FINISHED AT 08:30 08:40 + THE COUNTERS ON CONTROL BANK A (GRP 2), CONTROL B (GRP2),~~
AND CONTROL BANK C (GRP 1) DID DID NOT COUNT IN THE OUT DIRECTION. SUBSEQUENT TESTING VERIFIED THEY WOULD COUNT i IN THE IN DIRECTION. ! l 09:00 )
~~+ OVERLAP TEST, PROBLEM WITH MXR2 RELAY NOT PICKING UP, TRACED TO SPREAD PIN ASSOCIATED WITH SIGNAL PROCESSOR .., CARD IN SLOT J2, CAB. 22BD.~~
~~10:00~~
+ RETEST OF MXR2 RELAY SAT l 10:45 i + REMOVED THE FOLLOWING CARDS TO TEST IN THE WESTINGHOUSE TEST JIG:
I S/N 0216 - SLOT A114 TRASHED -Z3 BAD (TRACE LIFTED) S/N 6014 - SLOT A113 - Z3 AND 25 BAD, REPAIRED SAT S/N 0345 - SLOT A713 S/N 0342 - SLOT A714 4 S/N 0113 - REPLACES S/N 0216. (S/N 0113 WAS REPAIRED) 0 J I i
1 1 ROD CONTROL COVERAGE MONDAY 31,1993 12:00 TO 24:00 13:00 CHECK THE FOLLOWING CARDS ON THE TEST RIG: ! WSN 6014 IN A113 WSN 0113 IN A114 l
~~; WSN 0345 IN A713 WSN 0342 IN A714 l THE ABOVE CARDS TEST SAT.~~
~~CALLED CONTROL ROOM FOR TESTING. STARTUP RESET, SAT CBA GROUP 2 NO OUT MOTION - SUSPECT CHIP Z3 OF A113 CBB GROUP 2 NO IN OR OUT MOTION - SUSPECT CHIP 23 OF A114 I CBC GROUP 1 & 2 TEST SAT~~
~~CBD GROUP 1 & 2 TEST SAT TRIED CBA AGAIN, GROUP 2 NO OUT MOTION l~~
13:30 BENCH TEST OF A113 AND A114, REPLACED 23 FOR BOTH CARDS. I BENCH TEST RELAY DRIVERS A713, A714 INPUT DIODES - SAT. WSN 0183 - SUPERVISORY DATA LOGGING CARD AVAILABLE FOR SPARE FEMALE PIN 33 & 35 ON A713 SLIGHTLY OPEN, CLOSED THE PINS 4 15:10 REINSTALLED THE FOLLOWING: 4 WSN 6014 IN A113 WSN 0345 IN A713 , WSN 0113 IN A114 WSN 0342 IN A714 STARTUP RESET SAT SELECTED CBA, NO GROUP 2 OUT , IN WORKING CBB GROUP 2 NO IN OR OUT l CBC GROUP 1 & 2 SAT l RELAY DRIVER INPUT DIODES CHECKED SAT ON BENCH 2 I
~~MEASURE 260 AND 120 vac TO ROD CONTROL SYSTEM WSN 113 CHECKED SAT ON BENCH~~
I WSN 6014 Z3 REFAILED, REPLACED Z3 - TESTED SAT CHECKED OUTPUT DIODES ON RELAY DRIVERS A713, A714 - JUMPERED TERM STRIP 100VDC TO STEP COUNTERS CBS IN, OUT GROUP . 2, CBA IN, OUT GROUP 2 i 1938 PUT A713 ON CARD EXTENDER WITH A713 CARD EXTENDER PULLED INPUT PIN 32 THEN 31, MONITOR OUTPUT PINS WITH METER. INSTALLED WSN 6014 IN A114, WSN 0183 IN A114, WSN 0342 IN 1714 (DEENERGlZED THE POWER SUPPLIES DURING CARD INSTALLATION). 20:00 START UP RESET. CBB GROUP 1 AND 2 TEST SAT. - CBA GROUP 1 AND 2 NOT CYCLING, URGENT ALARM. FAILURE. DS2 ON SCL2AC LIT. - 22BD GROUP CYCLING LIGHT GREEN UP SOLID. IN LOGIC CABINET, SWAP THE FOLLOWING: A505 WITH A405, A504 WITH A404, A503 WITH A403, A502 WITH A402, , A501 WITH A401, A506 WITH A406. CYCLE ROD MOTION, NO CHANGE. 20:45 REINSTALLED THE SLAVE CYCLER CARD TO THE ORIGINAL LOCATION. 21:05 REPLACED MASTER CYCLER SELECTOR A106 FOR POSSIBLE "GO" SIGNAL PROBLEM. IN 22BD POWER CABINET, SWAPPED SIGNALING PROCESS CARD AND LIFT FIRING CARD, PROBLME WITH SOLID CYCLING LIGHT STILL EXIST. SIGNAL MUST BE COMING FROM LOGIC CABINET.
)
i IN LOGIC CABINET, SWAPPED A514 WITH A414, SOLID GREEN CYCLING LIGHT TRANSFERRED TO 21BD. SWAPPED A514 AND A414 TO ORIGINAL LOCATION. l 21:35 REMOVED WSN 0080 FROM A514 SLOT AND TESTED THIS CARD ON THE l TEST RIG. CARD TESTED BAD. BENCH TESTED SPARE WSN 0082 - SAT. INSTALLED THIS CARD IN A514. ! PROBLEM WITH GREEN CYCLING LIGHT IN 22BD RESOLVED.
23:45 PLACED A406 AND A506 ON CARD EXTENDER WITH RECORDER CONNECTED TO MONITOR THE "GO" PULSE. SELECT CBA, CYCLING ROD MOTION, 21 AC INDICATED PULSES, 22AC NO PULSE. SWAPPED A405 WITH A 504, NO CHANGE. 4 4 0
~~- . .- - - ~ . . _ . . ~ - . . ~ . . . . - - - . - . - - . - . -_ .. - . ~ . . . - . - . - - . - - . . ~ . - . - - . -~~
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. l i ! ROD CONTROL COVERAGE TUESDAY 6/1/93 0000 - 1200 l 0050 PLACED A406 AND A506 ON EXTENDER CARD. MONITORED PIN 5 OF A406 AND PIN 8 OF A506. CYCLE ROD MOTION. PROBLEM STILL EXISTS. ! PLACED A106 ON EXTENDER CARD MONITOR PIN 13 AND 15 - GOOD.
~~1 i RETURN A406, A106, AND A506 TO ITS ORIGINAL LOOATION.~~
~~1 1~~
i PLACED A104 ON EXTENDER CARD. MONITORED PIN 8 (UP PULSE) AND PIN ~ 12 (DWN PULSE), TP1, TP2, TP4. ALL INDICATED GOOD PULSES. 1 - REMOVED CARD FROM A505, A506 LOT, CHECK PINS AND SOCKET FOR BAD CONNECTION. PERFORMED CONTINUITY CHECK BETWEEN A505 PIN ! l 8 AND A506 PIN 22 - GOOD. 0330 BENCH TESTED A504 WSN 232, A505 WSN 226, A506 WSN 079. TESTED l SAT. i 0440 SWAPPED A512, A513, A514 WITH A504, A505 A506. CYCLING ROD MOTION - NO CHANGE. REINSTALLED THE ABOVE CARDS TO THE ORIGINAL LOCATIONS. REQUESTED CONTROL ROOM TO SELECT DBB, CYCLING ROD IN/OUT- SAT. ! 0530 REMOVED THE FOLLWOING AND TOOK TO TRAINING CENTER FOR TESTING: l A101 WSN 194 A110 WSN 0108 A106 WSN 0016 1 A104 0225 A1110039 A108 0021 i A105 0023 A112 0180 A109 0023 A113 6014 A114 0183 l 0605 TRAINING CENTER INSTALLED THE A100'S IN THE LOGIC CAB, CYCLING 1 ROD MOTION FOR ALL 8 BANKS, INDICATED GOOD. CHECK A113 AND A114, CYCLE ROD MOTION, CBA GROUP 2 NOT l COUNTING UP, S'.1">PECTED Z3 OF A113 BAD. CBBB GROUP NOT COUNTING UP, SUSPECTED Z3 OF A114 BAD. s REPLACED NEW Z3 CHIPS ON BOTH A113 AND A114. l
~~- s*~m - - - - , - --- we,m~~
a THINGS TO DO WHEN RETURN TO PLANT: CHECK INPUT DIODE OF A713. CHECK PIN SOCKETS FOR LOCATION LOT A101 - A114. DEENERGlZE THE POWER SUPPLIES DURING THE CARDS INSTALLATION. i h I l J k l
ROD CONTROL COVERAGE TUESDAY 6/1/931600 - 2400 1556 SWAPPED 2AC AND 2BD SLAVE CYCLER CARDS (5 CARDS EACH) 1600 PULLED FOLi.OWING CARDS TO ISOLATE / DISCONNECT INTERFACES TO THE SLAVE CYCLER CARDS. A804 A805 A207 1607 PULLED A106 CARD - EXTENDED IT TO TRACE THE GO PULSES PIN 13 - 1 AC PIN 15 - 2AC RESULT: PIN 15 SHOWING A LOT OF NOISE 1615 PULLED A506 AND EXTENDED IT TO SEE IF NOISE PRESENT AT EXIT OF CARD ON PIN 25. 1617 NOISE DETERM!NED TO BE FROM RECORDER LEADS. GO PULSES OK. 1631 MODULE 1506 PIN 4 (D2, STRETCH PULSE) VERIFIED SIGNAL INSIDE THE CARD. l 1
1645 REINSTALLED A804, A805, A1014, A207 AND TOOK SET OF READINGS ON I i I CARD EDGE CONNECTOR. (A506 STILL EXTENDED). READINGS TAKEN ON j A506 CONNECTOR TO COMPARE TO ANOTHER GOOD CARD / SET OF READINGS.
~~l 1651 TOOK SET OF READINGS WITH CARD A506 REMOVED BUT EXTENDER IN ! PLACE - READ CARD EXTdNDER POINTS. j 1655 REINSERTED CARD A506~~
~~EXTENDED CARD A406 TOOK SET OF READINGS ON CARD EDGE CONNECTOR (WITH CARD CONN~~
~~! ON END OF EXTENDER).~~
~~1703 TOOK SET OF READINGS WITH CARD A406 REMOVED BUT EXTENDER IN PLACE - READ CARD EXTENDER POINTS.~~
~~. 1725 WESTINGHOUSE DOING WlRING LIST TO CHECK CONNECTOR WIRING ON 1 A506 SLOT. DAVE BEST AND ELWOOD ROBINSON RE-EXAMINING TRACES TO DETERMINE NEXT STEP. l 3 i~~
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1815 RECOMMENCED DOING TRACES OF SLAVE CYCLER (SLOT A506) - VERIFYING OPERATION OFINPUTS AND OUTPUTS AND SIGNALS ON CARD.~ 1830 PULLED BOARDS A801 #.WD A805 TO DISCONNECT OUTPUTS / INTERFACES FROM AG06. 1835 PULLED BOARDS A501, A502 A503 TO DISCONNECT OUTPUTS / INTERFACES. 1840 TRACING INPUTS AND OUTPUTS OF Z9B (CHIP)- R2ACX SIGNAL (PIN 23 ON A506) SHOULD BE GOING HIGH BUT IS STAYING LOW. 1847 PULLED A504 AND A505 RAN TRACE AGAIN - SAME RESULTS. 1853 PULLED CARD A207 TO TEST ON TESTER (S/N 0014) - 1910 CARD SN OO14 FOUND TO BE BAD - BANK OVERLAP LOGIC 2 - MODULE. PIN 10 PROBLEM. 1916 REPLACED CARD IN A207 WITH CARD SN 0081. (BANK OVERLAP LOGIC 2). INSERTED liEW CARD IN SLOT A207 - INSERTED A504 AND A505. ALSO INSERTED A804 AND A805. 1918 RETEST SHOWED SLAVE CYCLER WORKING SAT. 1936 READY TO BEGIN TESTING STEP COUNTERS. 1940 BEGAN TESTING STEP COUNTERS. 1944 ALL STEP COUNTERS WORKING PROPERLY (ALL STEPPED IN AND OUT AND RESET TO ZERO). 1953 SETTING UP FOR NEXT TEST: RECORDING / TRACING Vref IN ALL POWER CABINETS WHILE EXERCISING THE RODS FROM THE WESTINGHOUSE TEST BOX (Vref IF OFF THE REGULATION CARD). MOVING GROUPS 10 STEPS OUT AND IN. 2002 CONTROL BANK A OUT 2008 CONTROL BANK A IN 2011 CONTROL BANK C OUT (RECORDER OUT OF PAPER) 2015 CONTROL BANK C IN 2016 SD BANK A OUT I 9
2016 SD BANK A IN 2120 ABOUT 2115 STARTED CYCLES ON SD BANK A TO 228 STEPS - STEP COUNTERS GROUP 1 - 228 GROUP 2 - 228. ACTUAL STEPS 228. SAT. ,
* ***THERE IS SOME DISCONTINUITY IN TIME RECORDS BETWEEN ENGINEERS' NOTES.
STEPPED SD BANK B TO 228 STEPS. STEP COUNTERS GROUP 1 - 228, GROUP 2 - 228. ACTUAL STEPS 228. SAT. 2130 STEPPED SD BANK C TO 228 STEPS. NOTE: GROUP 2 STEP COUNTER ZERO OFFSET ABOUT A 1/2 NUMBER. STEP COUNTER'S GROUP 1 - 228, GROUP 2 - 228 WITH ABOUT A 1/2 NUMBER OFFSET. ACTUAL STEPS 228. SAT. 2140 STEPPED SD BANK D TO 228 STEPS. STEP COUNTER'S GROUP 1 - 228, GROUP 2 - 229. ACTUAL STEPS 228. SAT. 2150 STEPPED CONTROL BANK A TO 228 STEPS GROUP COUNTERS 1 - 228, GROUP 2 - 228. ACTUAL STEPS 228. STEPPED BACK 28 IN. GROUP COUNTERS SAT. 2155 STEPPED CONTROL BANK B TO 228 STEPS. STEP COUNTERS GROUP 1 - 228, GROUP 2 - 228. ACTUAL STEPS 228. STEPPED BANK IN 30 STEPS. STEP COUNTER SAT. 2205 STEPPED CONTROL BANK C TO 228 STEPS. STEP COUNT":RS - GROUP 1 - 228, GROUP 2 - 228. ACTUAL STEPS - 228. STEPPED BANK IN 28 STEPS. STEP COUNTERS SAT. 2215 STEPPED CONTROL BANK D TO 228 STEPS. STEP COUNTERS GROUP 1 -
~~228, GROUP 2 -228. ACTUAL 228. STEPPED BANK IN 28 STEPS. STEP l COUNTERS SAT.~~
~~.* 2220 STEPPED SD A IN AND OUT 30 STEPS. STEi> COUNTERS SAT.~~
~~l 2222 STEPPED SD B IN AND OUT 30 STEPS. STEP COUNTERS SAT. i i l l~~
~~- -- - - - _ _ _ _ . _ _ - . - . - - . - - - - . - . - - - _ _ ~ . -m -- -- - - w- .- -~~
~~I i~~
)
2225 STEPPED SD C IN AND OUT 30 STEPS. STEP COUNTERS SAT. 1 NOTE: GROUP 2 COUNTER DIDN'T MOVE. RESET COUNTER, COUNTER MOVED. 2227 STEPPED SD D IN AND OUT 30 STEPS. STEP COUNTERS SAT. f 2245, STEPPED CONTROL BANKS THRU BANK OVERLAP - VERIFIED BANKS OVERLAP AS REQUIRED - STEPPED DOWN TO VERIFY PROPER OPERATION - SAT. 2400 ELWOOD ROBINSON REPORTED ALL COUNTERS STEPPED 228 STEPS. CONTROL BANK C GROUP 2 COUNTER WASN'T FULLY REZEROED, BUT 4 WORKED FINE AFTER REZEROING.
~~) TECH SPEC SURVEILANCE PORTION OF FUNCTIONAL FOR 228 STPES COMPLETED SAT.~~
i J ; i 5 i ) e a -_ _ _ _ ___-._ _---- - ----- --_. --
! CONTROL ROD COVERAGE WEDNESDAY, JUNE 2,1993 00:0012:00 ^ 0200 APPROX. REMOVED SPEED DRANETZ MONITOR. POWER CABINET'S l ALARMS ENABLED AND JUMPERS REMOVED. i 0230 CONNECTED RECORDERS TO 21 AND 22 AC CAB TO SA1 Vref SA2 Vref SA3 Vref MVref - (Vref TO MONITOR OUT/IN MOTION). j 0346 CONTROL BANK A SELECTED - STEPPING TO 30 STEPS GROUP 1 - 29, GROUP 2 - 30. RECORDER STOPPED - MOVES BACK TO 0. t 0250 STEPPING TO 30 STEPS ON CONTROL BANK A - STEP COUNTERS - GROUP 1 - 29 1/2 , GROUP 2 - 30. RPI'S SAT. ROD BOTTOMS RESET SAT.
~~. ACTUAL STEPS 30.~~
STEPPING DOWN 20 STEPS - GROUP 1 STEP COUNTER 91/2, GROUP 2 - 10. I ROD BOTTOMS 2A2 AND 1 A1 NOT BACK IN. BAD BULBS. ARPI'S SAT. ] STEPPING BACK TO 30 STEPS - STEP COUNTERS GROUP 1 - 30, GROUP 2 - ? 30. RPI'S SAT. ROD BOTTOM LIGHTS OUT. l STEPPING 130 STEPS ON CONTROL A TO ZERO - RPI'S SAT, GROUP 1 STEP f COUNTER 0. GROUP 2 - O. ROD BOTTOMS. i 1 0308 CONTROL BANK C SELECTED. l STEPFING TO 30 STEPS ON CONTROL BANK C. GROUP COUNTER 1 - 30, 2 -
~~30. RPI'S SAT.~~
l 2C1 - 1C3 ROD BOTTOMS NOT CLEAR - STEPPING TO 35 STEPS - ROD l BOTTOMS CLEAR. STEPPING IN 20 STEPS ON CONTROL BANK C. GROUP .' COUNTERS 1-15,2-15. RPI'S SAT. ROD BOTTOM ARE IN. STEPPING OUT * - 20 STEPS. ROD BOTTOM LIGHTS CLEAR, RPI'S SAT. GROUP COUNTERS 1 - 35, 2 - 35. l. 4 l STEPPING CONTROL BANK C IN TO ZERO. GROUP COUNTERS 1 - O, 2 - O. RPI SAT. ROD BOTTOM LIGHTS ON. l 0325 SELECTING SD A STEPPING 30 STEPS OUT. STEP COUNTERS GROUP 1 - 30. i GROUP 2 - NG. RIP'S SAT. ROD BOTTOMS NOT CLEAR. 3 STEPPING TO 35 STEPS. ROD BOTTOMS CLEAR. GROUP 1 - 35, 2 - NG. i STEPPING DOWN 20 STEPS. ROD BOTTOMS LIGHT ON. RPl'S SAT. GROUP 1 - 15. GROUP 2 - NG. i NOTE: WHEN STATIONARY ORDER GOES TO ZERO SA1 Vref SHOWING o NOISE IN CONTROL C AND SD C. I
i INCREASED STEPPING TO 35 STEPS - RPI'S SAT. GROUP 1 - 35, 2 - NG. ROD BOTTOMS CLEAR. STEPPING TO O STEPS. ROD BOTTOM LIGHT ON. RPI'S SAT. GROUP l COUNTER 1 - O. GROUP 2 - NG. l 0350 SELECTING SDC SD C STEPPING 35 STEPS. RECORDER ON WRONG SPEED.
~~RODS BACK IN FOR REDO.~~
SDC AT 35 STEPS ROD BOTTOMS CLEAR, GROUP COUNTERS SAT, IRPl'S j SAT. IN 20 STEPS, IRPl'S SAT, GROUP COUNTERS SAT. i 0358 SDC AT 15 STEPS. ROD BOTTOM SAT, BACK OUT AT 35, SAT. j 0400 SDC AT 0 STEPS . ALL SAT. ! 0403 SDD AT 35 STEPS. ROD BOTTOM 1SD2 NOT CLEAR. IRPI'S SAT. NOISE l ON STATIONARY GROUP A WHILE STEPPING GROUP B. STEPPING TO 40 j " MODULE OUT OF SPEC. l BISTABLE ROD BOTTOM CLEARED. j SDD AT 20. AL SATIRPI'S, ROD BOTTOMS OFF. GROUP COUNTERS AT 40. 0410 SDD AT 0. GROUP COUNTERS AT ZERO. ROD BOTTOMS UP. IRPI'S SAT. i '; 0415 CONNECTING RECORDER TO 21 AND 22SD. SELECTED CONTROL BANK B. ! 21 BD SELECT LIGHT FOR GROUP A NOT LIT. OTHER NOT LIT. ! STEPPED TO 35 SET - GROUP STEP COUNTER GROUP 1 - 35, GROUP 2 - 35. ! RPI'S SAT. ROD BOTTOMS CLEAR. STEPPING DOWN TO 15 STEPS, GROUP j 1 - 15, GROUP 2 - 15. RCD BOTTOMS ON , RPI SAT. STEPPED TO 35 STEPS - GROUP STEP COUNTERS GROUP 1 35, GROUP 2 -
~~35. ROD BOTTOM CLEAR.~~
STEPPING DOWN TO 0. ROD BOTTOMS ON, RPI'S SAT, STEP COUNTER GROUP 1 - O, GROUP 2 - O. 0425 SELECTING CONTROL BANK D. STEPPING CONTROL BANK D TO 35 STEPS. GROUP STEP COUNTERS GROUP 1 - 35, GROUP 2 - 35. RPI'S SAT, ROD BOTTOMS CLEAR. STEPPING TO 15 STEPS - STEP COUNTERS GROUP 1 -15, GROUP 2 - 15. RPI'S SAT, ROD BOTTOM LIGHTS ON. i STEPPING TO 35 STEPS, GROUP COUNTERS GROUP 1 -35, GROUP 2 - 35. RPl'S SAT, ROD BOTTOM LIGHTS CLEAR. STEPPING TO ZERO STEPS. GROUP COUNTERS GROUP 1 -0, GROUP 2 - O, RPl'S SAT, ROD BOTTOM LIGHTS ON.
arh-+ 4- _& '1--e---
~~- a .-m- 4 .-wA4 4- waA _. m a- - . -m.,__.m.a - ---- - - - - - - - - - - --~~
i ( 0435 SELECTING SD BANK B. ! STEPPING TO 35 STEPS, GROUP COUNTERS GROUP 1 - 35, GROUP 2 - 35. RPI'S SAT, ROD BOTTOM LIGHTS CLEAR. i STEPPING TO 15 STEPS, GROUP COUNTER GROUP 1 - 15, GROUP 2 - 15, RPI'S SAT, ROD BOTTOM LIGHTS ON. STEPPING TO 35 STEPS. GROUP COUNTER GROUP 1 - 35, GROUP 2 - 35, RPl'S SAT, ROD B01 TOM LIGHTS CLEAR. ! ! STEPPING TO O STEPS, GROUP COUNTERS GROUP 1 - O, GROUP 2 - O, RPI'S SAT, ROD BOTTOM LIGHTS ON. , CAB 22BD CARD K2 (MUX ERROR DET) DS1 (GR A MUX ERROR) BULB ' 4 BROKEN. - . CBSERVED NOISE ON SA1 Vref - SWAPPED RECORDER LEADS NOISE STILL
~~! THERE.~~
. 0510 CONNECTING RECORDER TO MONITOR EFFECTS OF NOISE. . SAVref CH 1 - CONTROL BANK A Vref SCVref CH 2 - SD BANK A Vref ! TEST PT 51 - CH 4 CONTROL BANK A GROUP 1 ROD CURRENTS 52 - CH 5 " l 53 - CH 6 " 50 - CH 3 " 1 END OF NOTES AVAILABLE AT THIS TIME. j I l l 1 . e S
~~;3 . . . . .~~
1 THURSDAY JUNE ,1993 0:00 TO 12:00 j During startup process operation notes the P/A converter and the Rll computer did not provided any indications during rod motion. i j Troubleshooting CBB & CBD pulse to P/A converter, and Rll computer. 01:30 AM Setting up preparations and approvalof troubleshooting procedure. Connected l test recorder to monitor CBD up pulses. Output of A114 card and output of the relay driver card A711. A711, pin 30,15 VDC input & pin 9,100 VDC output.
02:06 AM Connected recorderTO CBD bandk moved rods 3 steps in then out. No change j on recorder. l l 02:25 AM l Moved recorder to monitor CBB. No change on recorder when cycle rod motion
! out then in 3 steps. ! 02:45 AM l Moved recorder to monitor SBA, recorder pulsed but the computer P250 Indication remain the same. l 03:15 AM j Connected recorder to A114 to test Z13 chip. A114 pin 2 and TP 1 and A110 pin 22. Stepped rods +/-3 steps. Pin 2 & A110 pin 22 pulsed on recorder but TP1 did not. ! 03:50 AM
~~All rods in removing A114 card for testing. Control room step counter SBA j~~
missed 10 steps when driven in. ! Bench test of card A114 bad, Z13 chip failed test. Replaced chip retested card ii sat results on bench. Reinstalled card for operations to retest. ! 06:30 AM Operations withdrew all rod banks + /- pulse to analog signals all control banks i sat with P250 indicatione. d 4
~~,.. s 9 #~~
SIGNIFICANT EVENT RESPONSE TEAM ROD CONTROL SYSTEM INVESTIGATION SERT PLAN 1;0 PURPOSE 1.1 To conduct an independent assessment of the Salem Rod Control System failures. , 1.2 To provide a timely, unifonn, and comprehensive report of the events, including root cause determination and corrective action recommendations. 2.0 PLAN
~~+ Data collection 4 Quarantine of critical areas + Fact Finding Interviews of key individuals ;~~
i
+ Root Cause, Causal Factor and Failed Barriers investigation + Procedure adequacy and usage evaluation + Work method evaluation + Work Order / Activity review + Operating Experience Feedback (OEF) review + New OEF initiation 4 Administrative controls evaluation 4 Training program evaluation + Communication with vendors t
~~f'i Y T) {&.~~
~~.9 a~~
~~3.0 DATA TO BE EVALUATED~~
~~+ Operating logs l l + Event-related correspondence l + Inspection / surveillance records .~~
~~l l~~
+ Maintenance records / preventative maintenance data l l + Procedures and instructions l + Vendor manuals / drawings and specifications + Equipment history records / trends + Design basis information + FSAR/ Technical Specifications + Nuclear Plant Reliability Data System reports + Training lesson plans + SRG reports + LERs / Incident Reports ) + MMIS data i I + Testing Adequacy 4.0 ROOT CAUSE/ CAUSAL FACTOR /FATT En BARRIFR GUIDELINES 4.1 Types of Analysis (options) l + Human / Equipment Causal Factor Analysis ;
~~4 Event / Causal Factor Analysis~~
~~+ Hazan! Barrier Target Analysis i + Fault Tree Analysis j + Change Analysis l a~~
l l 1
ni O 4.2 Root Cause Possibilities - all to be assessed , 4 Human Performance: ,
+ Verbal Communication + Written Pmcedures and Documents 4 Man-Machine Interface + Envimamental Conditions + Work Schedule 4 Work Practices 4 Work Organization /Plarming + Supervisory Methods + Training / Qualification + Change Management + Resource Management + Managerial Methods + Equipment Performance: + Design Configuration and Analysis + Equipment Specification, Manufacture, and Construction 4 Maintenance Testing + Plant / System Operation + External 4.3 Validation + The pmblem would not have occurred if the cause had not been present. + The pmblem will not recur due to the same causal factors if the causes are corrected or eliminated. + Correction or elimination of the cause(s) will prevent occurrence of similar j conditions.
~~I 1 l l l. 1 e d~~
~~y. - , , , , = . ..x,. - - s a+ u _~~
~~<. e 5.0 SERT REPORT~~
+ Approvals Cover Sheet + Table of Contents + Executive Summary + Event Summary + Root Cause(s)/ Causal Factor (s)/ Failed Barrier (s) + Recommended Corrective Actions + Personnel Performance + Alternate Views + Short-Tenn Recommended Corrective Actions e Long-Term Recommended Corrective Actions + Interviewed Individuals + Testing 4 References + Other Issues / Data + Attachments
~~\ \~~
SIGNIFICANT EVENT RESPONSE TEAM REPORT NO. 92 - 05 DECEMBER 29,1992 SALEM UNIT 2 CONTROL ROOM OVERHEAD ANNUNCIATOR LOCK - UP OF DECEMBER 13,1992 ac I s G / b Y a" 0 0 1 D
S l 1 1 SERT Report 92-05 December 29, 1992 3 i l To the General Manager - Salem Operations SALEM UNIT 2 - CONTROL ROOM OVERHEAD ANNUNCIATOR LOCK-UP, 12/13/92 ELGNIFICANT EVENT RESPONSE TEAM REPORT i At your request, a Significant Event Response Team (SERT) was convened at 23:00 hours on December 14, 1992, to investigate and report on the captioned event. On December 13, 1992, at 21:22 hours, the Nuclear Control . Room Operator (NCO) for Salem Unit 2 received an alarm on the Auxiliary Alarm System (AAS) recording the restoration of the Chilled Water Expansion Tank Level Low to Normal. He then realized the overhead Annunciator (OHA) for the AAS typewriter had never alarmed, and the clock on the CRT, which displays alarms received by the OHA System, had stopped updating at 19:46 hours. The NCO determined that the OHA System was not functioning, and at 21:23 hours, he reset SER-B and SER-A in the Beta annunciator cabinet located in ; the Equipment Room. This action restored the functionality of the ! OHA System. 1 The SERT charter, as defined by the GMSO, was: ]
1) Independently determine the root cause of the event

2) Assess ECG classification and reportability

3) Determine if procedures were adequate and followed

4) Assess adequacy and design of the OHA System

5) Determine corrective actions l
l
SERT Report 92-05 The SERT consisted of* Craig Lambert Nuclear Engineering and Manager Project Services Dan Eskesen Salem - Operations Member Lou Miceli Salem - Technical Member Ken Moore Salem - Onsite Safety Review Member Scott Ward Salem - Station Quality Assurance Member Mike Reese Nuclear Training Center Member Wayne choromanski Reliability and Assessment Member Lyle Mayer Nuclear Electrical Engineering Member Dennis Connell Salem - GM Staff Member The information in this report is based on our investigation which concluded on December 24, 1992. The team was in operation for 10 days and involved approximately 800 man-hours of work. L 2 of 24
SERT Report 92-05 l Section Page { I. BACKGROUND INFORMATION 4 II. SYSTEM DESCRIPTION AND LICENSING BASIS 4 III. EVENT CHRONOLOGY 5 IV. EXPLANATION OF EQUIPMENT FAILURES 7 V. SAFETY SIGNIFICANCE OF THE FAILURE OF THE ANNUNCIATOR SYSTEM 7 VI. ASSESSMENT OF EVENT CLASSIFICATION GUIDE (ECG) CLASSIFICATION, IMPLEMENTATION AND REPORTABILITY 8
. VII. ASSESSMENT OF PERSONNEL PERFORMANCE 9 VIII. ANALYSIS OF FAILURE DETECTION OPPORTUNITIES 12 II. ASSESSMENT OF ADEQUACY AND IMPLEMENTATION OF PROCEDURES 14 X. TRAINING 16 XI. REVIEW AND ASSESSMENT OF NEW DESIGN 18 XII, REVIEW OF INDUSTRY EXPERIENCE 20 XIII. ROOT CAUSE ANALYSIS 21 XIV. GENERIC CONSIDERATIONS 22 XV. RECOMMENDATIONS 23 Attachment 1 SIMPLIFIED SYSTEM BLOCK DIAGRAM Attachment 2 DETAILED SEQUENCE OF EVENTS l
Attachment 3 EVENT AND CAUSAL FACTOR FLOW CHART i l 1 i I J i 3 of 24
~~.-_. -- .. - - . = . -- . _-~~
SERT Report 92-05 I. FACKGROUND INFORMATION Modifications were performed to Salem Unit 1 and 2 control consoles and annunciator systems to correct Human Engineering S Deficiencies in accordance with NUREG 0700, Guidelines for Control 4 Room Design Reviews. The OHA electronics were modified to replace the existing relay / logic system with a microprocessor based system provided by Beta Products Division of Hathaway Industries. The , alarm window displays were re-arranged, relabelled and system l 4 reflash capability was modified. On the control console, a CRT 1
; with keypad controls and new pushbutton/ switches were installed. l The modifications to Unit 2 were completed during outage 2R6 and l turned over to operations on March 26, 1992. The modifications to 1 ; Unit 1 were completed during outage 1R10 and turned over to Operations on June 12, 1992.
i II. SYSTEM DESCRIPTION AND LICENSING BASIS l A. System Description l I I The Control Room OHA System consists of the Betalog 4100, a high performance sequential events recording system, the Betalarm 1500, a microprocessor based serial input distributed annunciator system, and a Remote Control Workstation Computer (RCW). The OHA consists of ten (10) overhead boxes with forty eight (48) windows per box. The OHA is a non-safety related system. An annunciator CRT display and keypad are located on the control console to identify alarm points. J There are separate and independent pushbuttons located on the control console which the operator uses to silence, acknowledge and reset the OHA system alarms. A key-operated switch is
~~located on the control console to reset "first-out"~~
~~, indications. A test switch is located on the control console~~
for periodic testing of the system. ;

The OHA is powered by two independent 115 VAC, 60 Hz supplies.
~~Attachment 1 provides a simplified block diagram of the system. B. Licensing Basis 4~~
1. Safety Evaluation Report NRC review of the OHA System prior to issuance of an Operating License concluded that the design and safety classification for this system was acceptable. The Safety Evaluation Report did not discuss specific design details.

2. UFSAR UFSAR Section 7.7.2.10 provides a detailed description of 4 of 24
~~SERT Report 92-05 plant alarm and annunciator systems. The OHA System is classified as a non-safety system. Paragraph four (4) on page 7.7-16 states:~~
"Since Indication and Alarm Systems are not part of the Plant Protection System, and failures within these systems cannot affect the operation of the Protection System, there is no reason to impose limiting conditions for operation on the Alarm Systems. Alarm Systems cannot be considered as part of a safety related system, since they perform no function in the actuation of safety-related equipment.
Limiting conditions for operation are imposed on the Plant l Protection Systems and equipment to assure the safe j operation of the unit." l l Design of this system includes consideration of physical separation and electrical isolation between IE and non-1E circuits, Seismic II/I, Fire Protection, Appendix R l requirements and separate and redundant power supplies. l Information needed by the operator to respond to abnormal ' occurrences has been provided in accordance with Regulatory (Reg.) Guide 1.97. 1 1 i III. EVENT CHRONOLOGY All times provided are derived from the SER-B printout. On December 12, 1992 OHA A-45 (spare) alarmed and was cleared by resetting both SERs. OHA A-45 subsequently alarmed on December 13, 1992. The Nuclear Shift Supervisor (NSS) directed the NCOs not to clear the alarm as it was considered a nuisance alarm and he planned to notify the System Engineer of the problem the following
~~morning.~~
Between 18:00 and 18:45 hours on December 13th, the Desk NCO accessed the Beta RCW (Panel 115-1) to obtain information associated with the OHA A-45. The NCO performed several keystroke operations on the Beta System RCW keyboard before returning to the control room. Sometime after the Desk NCO left the RCW, the , Console NCO accessed the RCW in an attempt to identify the cause ; for the OHA A-45. 1 I At 19:46 hours, the Unit 2 Beta System clock on the CRT display, stopped updating. At 19:55 hours, the AAS printed " Chilled Water Expansion Tank Level Low", but the associated OHA, " AUX ALM SYS PRINTER" (A-41) did not alarm. The Desk NCO noticed the printout and then directed an equipment operator to fill the tank. At 20:08 hours, the NCOs performed a containment pressure vacuum / relief which caused radiation monitors 2R13A and 2R13B to alarm. These channels caused " RADIATION ALARM PROCESS" to alarm on 2RPl. The Desk NCO acknowledged the alarm on 2RP1, but neither NCO realized OHA A-6 "RMS TRBL" nad failed to annunciate. 5 of 24
SERT Report 92-05 At 21:22 hours, " Chilled Water Expansion Tank Level Low" alarm returned to Normal and printed on the AAS. The NCOs then recognized that OHA A-41 did not annunciate. The Console NCO noticed the clock on the OHA CRT was indicating 19:46 hours and not updating. At 21:23 hours, an NCO reset SER-B, then SER-A, in the Beta Annunciator Cabinet. After the SERs were reset, four OHAs were received in the control room:
~~= Annunciator Logic (A-9) e RMS Trouble (A-6) = 104 Panel Trouble (C-9) = AAS Printer (A-41).~~
The Console NCO verified these OHAs coincided with the CRT and ; that the CRT clock was updating, and notified the NSS. At 21:32 hours, the AAS printed " Plant Vent Heat Trace Trouble" and associated OHA A-41 alarms. The operators considered this as confirmation the annunciator system had been restored. The NSS informed the Senior Nuclear Shift Supervisor (SNSS) who began reviewing the Event Classification Guide (ECG) Section 10 a for classification /reportability requirements. At approximately 22:00 hours, the SNSS called the Operating Engineer (OE) and indicated 3 minutes (by Beta System 1 minute) had elapsed between the time the OHA system was discovered to be " locked-up" to the time the system was reset. Therefore, after SNSS and OE discussion of the event and review of ECG Section 10, an Alsyt and NRC One Hour Notification were not applicable. Subsequently, the NSS called the System Engineer (SE) and discussed the Beta OHA System. The NSS indicated the on duty technician was not qualified to work on the system. Therefore, he requested the SE to come in. At approximately 23:30 hours, the SE arrived and perfcrmed a l number of diagnostic tests on the system. These tests verified that SER-A and B were functioning properly. The SE reset SER-A and B to clear the printer error. The SE discussed the tect results with the NSS and indicated he planned to call the vendcr in the morning. See Attachment 2. " Detailed Sequence of Events" l l 6 of 24
SERT Report 92-05 IV. EXPLANATION OF EOUIPMENT FAILURES The SERT performed a thorough review of system failures and malfunctions from the time the system was installed until the system " locked-up" on December 13, 1992. The details associated with this review are included in the Sequence of Events contained in Attachment 2. Based on a special test performed by a System Engineer and BETA Products Field Engineer on December 18, 1992, the OHA window A-9 alarmed when the SER-A transferred system control to SER-B. The SER-A circuit board was removed and replaced with the temporary OHA circuit board used during system installation. On December 19, 1992, the removed SER-A circuit board was tested at BETA Products facilities and it was discovered that when
" Ctrl L" is entered twice at the RCW PC keyboard with the RCW in PROCOM PLUS and the " Black Box" is in RCW-A position, the SER " locked-up". That is, when the system saw the PROCOM PLUS command, all SER ports were turned of f, stopping CRT clock update and alarming valid overhead windows. Review of Salem Unit 2's RCW PC files revealed a file that was created at 19:47 hours on December 13, 1992.
~~The SERT has determined that the event was caused by a combination of entering " Ctrl L" twice, with the RCW in PROCOM PLUS and the~~
" Black Box" switch in RCW-A, rather than SER-A. When this occurs, the main controller will stop sending events to any display devices that are connected, and wait indefinitely for commands to be sent from the RCW.
V. SAFETY SIGNIFICANCE OF THE FAILURE OF THE ANNUNCIATOR SYSTEM The UFSAR states that the OHA System is not safety related. System alarms are r.ot part of the plant protection scheme and failures cannot affect protective system operation. Therefore, operation limits are not imposed on the plant. Technical Specifications (Units 1 and 2: 3.3.3.5, REMOTE SHUTDOWN INSTRUMENTATION, and 3.3.3.7, ACCIDENT MONITORING INSTRUMENTATION) and Control Room Evacuation, S1(2)-OP.SO-AB.CR-0001(Q), and Control Room Evacuation Due To Fire In The Control Room, Relay Room, or Ceiling of the 460/230V Switchgear Room, S1(2)-OP.SO-AB.CR-0002(Q) do not contain/ refer to any overhead annunciators to provide diagnostics or decision points for safe shutdown of the units. It is recognized industry-wide that the risk of a degraded plant condition going undetected increases when a majority of the OHAs are lost or unavailable; therefore, emergency declaration is appropriate. The necessary personnel to provide increased monitoring for continued safe operation of the affected unit (s) is
~~, accomplished by activation under the E-Plan implementation for 7 of 24~~
l i a ! SERT Report 92-05 ; this type of event. Clarification tc. ECG Section 10D or development of another IC/EAL for this section is in order. Ccnsider NUMARC/NESP-007,
" Methodology for Development of Emergency Action Levels. This is acceptable to the NRC as an alternative method for the development I of EALs. It is the result of an industry-wide effort to standardize criteria for classification of emergencies. ,
l Additionally, NESP-007 recognizes that certain loss of OHA ! scenarios can occur in which the option of calling extra personnel is given to the SNSS. The determination should be guided by Technical Specification OPERABILITY concerns or ability to enter and maintain control of the plant during abnormal or emergency i procedure operations. ! Consideration may be given to the system reliability perspective { as well. If the system is unreliable, excessive emergency declarations will occur. This is hichly undesirable! Therefore, the system needs adequate reliability / redundancy, without , unreasonable expense, to provide that assurance. : Since the OHA System is utilized to recognize abnormal conditions, ] the UFSAR needs to adequately describe its failure modes, as well < ac a description of its workings. An electric power loss to the system is described in the proposed FSAR change; however, system ground, computer logic and OHA/MCR Console CRT combination failures are not. VI. ASSESSMENT OF EVENT CLASSIFICATION GUIDE (ECGl CLASSIFICATION, IMPLEMENTATION AND REPORTABILITY Initial event analysis and classification was prompt and correct. The OHA loss event was classified according to NUREG 0654 Rev. 1. It specifies that emergency declaration is timed from discovery of the condition by the operators. During the OHA loss of December 13, 1992, operators recognized the event and corrected the cause prior to exceeding the 15 minute limit of ECG Section 10B. SERT concurs with the determination made at the time of the event by the SNSS and OE that an ALERT Declaration was not necessary. l Although classification under the ALERT class is not considered necessary for this occurrence, SERT believes for future events of this type, a courtesy call be made to the Emergency Notification Center informing them of the event. i 1 As dis 'tssed previously, the SNSS and OE reviewed ECG Section 10 for Reportability. Section 10 D. requires a one hour report should there be a major loss of emergency assessment capability, specifically loss of "Other Control Room indications or plant monitors necessary for accident assessment". The Annunciator System is not described as Accident Monitoring Instrumentation per 8 of 24
SERT Report 92-05 Technical Specification 3.3.3.7. SERT concurs with the position taken by the BNSS and OE on the evening of the event. At approximately 09:00 hours on December 14, 1992, the event was discussed with one of the Salem Resident NRC Inspectors. After details of the event were known and cause was still under investigation, it was determined by PSE&G Management that a non- ' emergency declaration was the prudent approach to take. VII. ASSESSMENT OF PERSONNEL PERFORMANCE Operator actions and suitability of the response to this event have been determined by reviewing narrative and plant logs, appropriate plant normal, alarm response, abnormal and emergency procedures along with interviewing involved operators, their supervisors and management personnel. A. LICENSED OPERATORS:
~~1. NCO-Console:~~
The Console NCO did not notice the loss of OHAs until the AAS Chilled Water Expansion Level Low alarm returned to Normal. Functional capability was lost for approximately 90 minutes. Three alarm conditions (two AAS alarms and one 2RP1 RMS alarm) were actuated over a 90 minute period. All could have given the NCO indication that the OHAs were not operating correctly. Factors that may have affected the identification of the OHA loss could be attributed to the ' l day and shift, Sunday 15:15-23:15. Also, relief for mealtime occurred at or about the time when the alarms were missed. The above conditions reinforce the need for increased awareness to corroborating indications and thorough temporary relief turnovers during reduced activity times in the Control Room. Upon recognizing the BETA system CRT not updating, the l Console NCO made a brief statement about the BETA System CRT l condition to the Desk NCO, then went to reset the BETA SERs according to an Operations Department Information Directive ] (ID) on the system. The NCO did not know what the condition i of the computer system was, but believed that the reset process would correct the condition. Upon resetting, the OHA system seemed to function correctly. Although the Console NCO did not perform an OHA test, he continued to monitor / compare subsequent OHAs with diverse corresponding Control Room indications to insure operation of the system. 9 of 24
SERT Report 92-05 Based on stated information, normal watchstanding activities require increased awareness. Actions to reset the system and follow up monitoring were considered prudent.
~~2. NCO-Desk:~~
At approximately 18:00 hours, an attempt was made to access the BETA RCW to identify the cause of A-45. Access to the computer system for historical data printout was ~ attempted utilizing operating procedure S2.OP-SO. ANN-0001(Q). For reasons unknown, the NCO did not place the " Black Box" switch in the proper position, as directed by the procedure. , Using computer prompts, several access attempts were made. l Upon arriving at a password protected option, several different passwords were tried, all of which were unsuccessful. Password use by operators is not required for operator functions and was not authorized by the procedure. Termination was attempted due to "not feeling comfortable", and the NCO was unsuccessful in gaining the desired ' information. l 1 Had the NCO been successful in gaining entry with a password, the software integrity could have been compromised. With the exception of password usage, operations performed at the BETA RCW were under directions of a procedure and computer prompts were agi supposed to result in the condition that occurred.
~~3. Generic:~~
~~These items are applicable to Console and Desk NCOs. j~~
a. The NCOs are responsible for continuous plant 1 monitoring from the Centrol Room. Close monitoring of l auxiliary indications, charts, computer printouts, etc. can assist in determining loss of primary ,
l indications / alarms, , b. Control Room Narrative Logs are the responsibility of ' l the NCO. Both NCOs were awbre of the significance of the loss of most or all OHA's. The events leading up to and details of events during the time when the . OHA's were not functional need to be detailed in the , narrative.
~~4. NSS:~~
The NSS, when apprised by the NCO, of the problem associated with the OHA System, notified the Senior Nuclear Shift Supervisor (SNSS) in a timely manner and confirmed that the , system appeared to be functioning properly. The NSS participated in the review of the ECG for applicability in ' y yp', his capacity as the Shift Technical Advisor (STA). p h '$ 10 of 24 i
i Report 93-05
~~5. SNSS:~~
Upon being informed of the condition, 2 , .on 10 was consulted. The SNSS and NSS/STA determin, i entry into any emergency classification was not appropria.s. The SNSS then telephoned the OE, and discussed the ECG Section 10. The OE concurred with the decision not to declare an emergency condition nor make the one hour notification. Based on the time of discovery and correction of the condition, it was appropriate not to enter into any emergency classification /reportability. The SNSS contacted the System Engineer to discuss the event and determine if any further actions related to system functionality were required. Contacting the system Engineer was considered prudent action.
~~6. OE on call:~~
After discussing the situation with the SNSS, the OE concurred with the SNSS decision not to declare an ALERT or make one hour notification at that time. Instructions were given to the SNSS to call back if the SE determined the OHA system incapable of carrying out its designed functions. With the information available to the OE, the decision on the Loss of Overhead Annunciators, was appropriate. B. NON-LICENSED OPERATOR: l l Not Applicable l C. SHIFT CONTROLS (I&C) TECHNICIAN: ! Not applicable - the Shift controls (I&C) Technician was not , .! qualified on the BETA System; no action, no involvement. l D. ENGINEER: The System Engineer responded promptly upon learning the Shift Controls (I&C) Technician was not qualified on the system. l His actions appeared to be correct for the information and indications available to him upon arrival on site. l 4 11 of 24 1
SERT Report 92-05 VIII. ANALYSIS OF FAILURE DETECTION OPPORTUNITIES buring the period of SER-A failure (19:46 to 21:23 hours), events occurred that might have afforded opportunities for detection of the SER-A " lock-up" which resulted in the failure of the control room CRT to update, and the failure of the OHA windows to indicate changing plant status / condition. These opportunities are listed below in the Order of Occurrence and are further discussed by Order of Potential for Detection. A. Order of Occurrence Time Source Parameter Condition '
1. 19:46* 2CC1 CRT CRT Time display Fails to update time

2. 19:55 AAS Print Chilled Water Expansion OHA A-41 does Tank Level Low - Alarm not annunciate for AAS print

3. 20:08 2RP1 RMS Radiation Alarm Process OHA A-6 does PNL not annunciate for 2R13A/B

4. 21:22 AAS Print Chilled Water Expansion OHA A-41 does Tank Level Low - Normal not annunciate for AAS print
Condition remains throughout period of failure B. Order of Potential for Detection EVENT At 20:08, Radiation monitors 2R13A and B alarmed upon of the initiation of containment pressure relief. This HIGHEST was expected and previously experienced. The 2R13s POTENTIAL entering alarm caused 2RP1 RMS Panel " RADIATION ALARM PROCESS" window to light. The alarm on 2RP1 RMS Panel !
should have driven OHA A-6 "RMS TROUBLE" to annunciate. I However, since the SER-A was " locked-up" this did not occur. In preparation for performing the containment pressure relief the Desk NCO went to the RMS Panel on 2RP1 and stood by while the Console NCO stroked the , pressure / vacuum relief valves open. As the valves i stroked open the 2R13 A and B Radiation Monitors entered alarm, the Desk NCO immediately acknowledged the RMS Panel alarm (approximately 1 second elapsed from alarm to acknowledgment) and both the Desk and Console NCOs failed to recognize that the OHA system j did not annunciate the alarm condition. l
~~' l This opportunity had the highest potential for detection since l 12 of 24 I~~
1
l . SERT Report 92-05 both NCOs were aware of the condition, as it occurred, which should have caused an OHA alarm. The operators may have been de- ! sensitised to this alarm, in that this condition has existed since November 23, 1992 (containment pressure reliefs are performed approximately once per shift). ~ The next two events, Chilled Water Expansion Tank Level Low Alarm and return to Normal, are similar in probability for detection when the condition exists by itself. Since the operators were expecting the expansion tank alarm to clear upon initiating 2 actions to fill the tank, the return to Normal had a higher l
~~! probability of OHA failure detection.~~
SECOND At 21:22, AAS printed return to Normal for Chilled HIGHEST Water Expansion Tank Level Low. This was detected POTENTIAL immediately by both NCOs and recognized that the OHA A-41 " AUX ALM SYS PRINTER" did not annunciate. After 1 j the AAS printing condition was realized, the 2CC1 CRT 7 was monitored and determined to be not updating since ! the time display still indicated 19:46. l . l The Console NCO took prompt action (at 21:23) to reset the Beta l System SER units. THIRD At 19:55, AAS printed Alarm for Chilled Water Expansion l HIGHEST Tank Level Low. Without expecting an alarming POTENTIAL condition on the AAS and the OHA A-41, the Chilled , Water Expansion Tank Level Low Alarm is logged unnoticed on the AAS printer. Detection of the alarm is eventually made during a routine review of the AAS printout. Both NCOs assumed the A-41 OHA had i o annunciated earlier but could not recall acknowledging and resetting the window. Normal recognition of AAS events are " forward progression": a parameter enters alarm, begins to print on the AAS printer,
initiates OHA A-41, the Console NCO notifies the Desk NCO of the AAS alarm, the Desk NCO evaluates the condition and reports it to the Console NCO, the Console and Desk NCOs determine the i' appropriate response and take corrective actions. If presented with a condition, they do not instinctively question whether there was an alarm. Instead the progression is picked up at the evaluation phase and continued to corrective action.
4 During this period the Desk and Console NCOs were relieved one at a time by the NSS. This could have contributed to the unnoticed AAS printout. LEAST The 2CC1 CRT time display failed to update after 19:46 i POTENTIAL and was a continuous indication of the " lock-up" of SER-A. This item, while being of long duration, provided the least probable detection method. This is based on the following 13 of 24
l SERT Report 92-05 ) . . i reasons:
~~1. NCOs received no OHA alarms to prompt referencing the CRT for additional information.~~
~~ii. NCOs were not trained to recognize the significance~~
~~' of a failure of the clock to update as an indication .~~
of an OHA System failure. l a 1 At 21:23 SER-B and SER-A were reset, CRT and OHA responded as l previously seen upon SER resets (i.e. time updates occurred on the l
~~CRT and the OHA Window lights cycled as described in S2.OP-SO. ANN-0001 - step 3. 5) .~~
IX. ASSESSMENT OF ADEOUACY AND IMPLEMENTATION OF PROCEDURES A. OPERATIONS Operations Department had the following procedures in place at the time of the event: a S2.OP-SO. ANN-0001 " OVERHEAD ANNUNCIATORS OPERATION" a S2.OP-SO. ANN-0002 " OVERHEAD ANNUNCIATORS GROUND DETECTION"
~~= OHA A WINDOW ALARM RESPONSE FOR WINDOWS A-1, A-9 AND A-17 Review of the Operations Department OHA responses and ground~~
~~f detection procedures revealed no inadequacies. )~~
Operations Procedure S2.OP-SO. ANN-0001(Q), Rev. O, " Overhead Annunciators Operation", was utilized during the events leading to the SER-A failure. This procedure is a " Category III" use procedure. Category III procedures allow the completion of the task from memory provided the user is familiar with its use. The operator should refer to the procedure as necessary to j perform the job correctly. He is responsible for performing the task in accordance with the procedure. Areas of concern in the operating procedure were identified during the SERT review for content and use during the event.
~~1. The procedure purpose stated at step 1.1.E indicates a section of this procedure is the response to an SER failure.~~
~~This is incorrect; the section details the operators response to I an SER Scanner failure.~~
~~2. Step 3.1, description of the " password protected" functions of the RCW, indicate that only " password protected" activities can affect Annunciator System operability.~~
14 of 24
SERT Report 92-05 This is not an accurate assessment as indicated by the event and supporting documentation from the vendor, describing the use of various keystroke combinations, with the six (6) position " Black Box" selected to the RCW "A" or "B" positions.
~~3. Step 3.5 indicates an SER transfer can be operator initiated at the RCW Computer.~~
~~This statement implies the " operators" can force this transfer, which is incorrect and prompts the following concerns:~~
= The directions to perform this transfer are not provided in the procedure. = It is not possible to cause a transfer from the RCW Computer. During the investigation the OHA System Engineer indicated it would be necessary to pull the SER card to force a transfer.
~~4. Section 5.4, RCW operation, directs the operator to ,~~
~~" ENSURE the " Black Box" Switch is in the SER-A l position". i~~
~ There is no step in the remainder of the section to return the switch position to RCW-A position. Leaving the switch in the SER-A position will cause the historical buffer to fill and the ' oldest data to be overwritten as the SER accumulates events beyond j 6000.
~~5. Section 5.4, RCW operation did not provide direction to the operator for all RCW configurations, i.e., the procedure assumes the computer was off at the time the l~~
~~4 operator enters Section 5.4. The computer was on at the i time the operator arrived.~~
~~It is SERT's understanding that the RCW computer is always on, and i the " Black Lox" switch is in RCW-A to allow automatically saving i~~
historical data to the hard drive to permit trending by the system Engineers. This may have added confusion to the operator as he attempted to access the system. l (NOTE: Section 5.4 concerns have been addressed. Revision 1 to this procedure has redefined this section and is now used for
~~" Resetting and Testing the OHA System". Steps manipulating the "31ack Box" and computer have been removed.)~~
~~6. The procedure, as provided, does not contain steps to reset the SERs should the need arise.~~
During the installation of the Beta OKA System, it was identified i that the system " locked-up" while performing an OHA test. This " lock-up" was addressed in two ways. The immediate response was to issue a letter to the Operations Manager from the Project 15 of 24 4
l l SERT Report 92-05 Team, describing the occurrence and requesting that operators not perform the test in the manner that led to the " lock-up". The letter also identified that operators on shift were shown hor to reset the SERs. The long term response was to make un "EPROM" change which world p rs m t recurrence of the " lock-up". l Operations response was to issue an Information Directive (ID) with the letter attached. The ID did not include specific instruction on how to perform the SER reset. During the procedure development the Procedure Upgrade Project (PUP) was not informed by the installation group nor Operations Department of the " lock-up" and need for procedure guidance for SER reset.
~~7. The procedure, as provided, does not contain guidance~~
~~- for system switch alignment required for operation.~~
~~8. The procedure, as provided, does not contain guidance for determination of proper system response / operation.~~
~~11 MAINTENANCE 1 No procedures have been developed to date.~~
~~C. SYSTEM ENGINEERING l~~
~~No formal procedures have been developed to date l l X. TRAINING < l A. OPERATOR TRAINING~~
~~1. LICENSED OPERATOR: l l~~
l Salem Licensed Operators received training on the ney BETA j System in Segment 3 of 1991/92 Licersed Operator Requal l Training during the period of January to March 1992. ! Licensed Operator training was adequate at the time it was l conducted. The training consisted of a briefing 1. the Simt.lator with demonstration of the functions of the rr.w CRT located en 2CCl. Additionally, the alarm buttons, overhead relocations and alarm horn modifications were demonstrated. Operator training included the operator interface with the system but did not include BETA System hardware and computer systems. Only system components located in the simulator control room were discussed. The RCW was not discussed because it is not planned for installation in the simulator. At that time, a trainee handout, containing a brief description of the system was provided. No further material development nor training has been accomplished since. Operator interface with the system is provided as part of the overall simulator training and in-plant training. 16 of 24
SERT Report 92-05
2. NON-LICENSED OPERATOR: Not Applicable

3. .9NGINEER:
With the exception of the designated System Engineer, formal training has not been provided to the Station Engineers. The System Engineering Training Core Course does not include Annunciator training, other than system operation demonstration during the simulator portion of their training. The System Engineer for the BETA system received training during March 1992, while attending the Nuclear Controls (I&C) Technician training.
~~4. NUCLEAR CONTROLS (I&C) TECHNICIAN:~~
Initial training was provided by a third party vendor to a group of nine individuals. The group included six Nuclear Controls (I&C) Technicians, two Maintenance Supervisors and the System Engineer. The three-day training course was conducted during the week of March 25, 1992. Training and reference material was provided by a third party vendor. Although the technician on shift the night of the event was not trained in the Beta System, SERT is not in a position to judge whether additional personnel should be trained or not. At the time training was conducted, no maintenance procedures had been issued. Training could have been more effective if the Procedure Upgrade Program group generating the procedures had aligned procedure issuance with the scheduled training. Additionally, the training did not contain any of the information on modifications to the system, nor the information contained in Operations Dept ID information, The 92-016, " Unit 2 Control Room OHA". - contained in a memo from the DCP Project Manager, was available. l Based on the above information, the training is considered l incomplete. A common deficiency appears to be a failure to communicate or transmit advanced installation information to end users in a timely manner, or sometimes, not at all. f The following are SERT recommendations for training that could further reduce the likelihood of future occurrences. For systems significant to plant operation (i.e.: Tech Spec 4 implications, ECG classifications, other identified license conditions, etc.): a Training prior to release of system / modification for operation. = Table-top review by the user group prior to turnover of system for operation. 17 of 24
I l SERT Roport 92-05
\
~~a Walk-thru with several different operators in the~~
~~" operator mode" of system operation. ,~~
1
= Evaluate methods for improving the interface with the I Nuclear Training Center for training requirements 1 associated with the DCP process. I 1
l l XI. REVIEW AND ASSESSMENT OF NEW DESIGN SERT review of SORC approved, Revision 0, Design Change Package (DCP) 2EC-3056 " Phase III Annunciator Modifications" was performed ' to determine if the DCP for the new OHA System could have contributed to the total loss of Unit 2's Control Room OHA System on December 13, 1992. The draft DCP was prepared and peer reviewed by an external Architectural Engineer (AE) with inputs from various PSE&G discipline groups, including Salem System Engineering. PSE&G provided final DCP approval. SERT's assessment of the D' s engineering design input and review { is as follows: A. ENGINEERING: This DCP was implemented to upgrade and replace the relay / logic ! OHA system with a microprocessor based OHA manufactured by BETA l Products. The objective was to utilize as much of the existing system configuration and hardware as possible, such as OHA panels, window boxes, cables, etc. BETA Product's 100 % redundant, OHA System was reconfigured such that a single failure in some components could result in a failure of the entire system. Less than 100 % redundancy was justified and accepted. SERT's review found that the DCP design analysis did not detail the system sof tware. For example, the BETA Products software was neither validated, or reviewed by the Nuclear Process j Computer Group. When the DCP was approved, NUREG CR-4640 ;
" Handbook'of Software Quality Assurance Techniques Applicable l to the Nuclear Industry" was invoked per Specification S-C-ANN- l CDS-0205. Procedure NC.NA-AP.ZZ-0064(Q) " Software Quality )
Assurance" was issued on November 7, 1990, but was not used for ' this DCP. Also a new Design / Engineering Administrative ! Procedure NC.NA-AP.ZZ-0052(Q) " Software Control", which was l issued at u e same period of DCP issuance, may have brought any potential wftware problem to light. l System performance requirements, needed to support the original J design basis, were not included in the design analysis section ] 18 of 24 1
SERT Report 92-05 to confirm if the new system met or exceeded the original
> requirements. For example, BETA's calculated Mean Time Between Failures (MTBF) is 8539 hours (failure of a single optical coupler on one scanner circuit board) or 1.03 failures per '
year. This predicted failure rate is greater than the actual performance of the original system. SERT's review of the OHA System design also found that the OHA operation could be impacted by a single failure of any one of the following components:
= Auto RS-232 Switch #1 ID 2XD16481 = Auto RS-232 Switch #2 ID 2XD16349 s Data Cables between Auto RS-232 Switches and Distributed Logic A & B and Control Room CRT respectively. = SER software /firmware. = Common Field Input Scanner / optical data link.
The DCP did not provide an alternate means to inform the NCO when the SER locked up and was incapable of alarming. SERT has concluded that there were precursors during the design and the installation phase, which, had they been pursued, could have precluded this event. B. MODIFICATION AND TESTING: A review of Section 9.0 Installation, Functional & Operational Testing indicated weaknesses:
~~= Test instructions were not provided to test system software /firmware in the field.~~
e Test instructions did not demonstrate SER-A transfer of control to SER-B in all possible scenarios. C. TURNOVER and CLOSEOUT: Review of this Section indicated weaknesses that may have contributed to the event as follows:
~~1. DCP Change Documents (CD) did not provide technical information to the Procedure Upgrade Project (PUP) group.~~
~~PUP developed operating and alarm response procedures based on Beta's operations manual.~~
~~2. The DCP Project Team did not provide adequate guidance to mitigate the potential of an SER " lock-up",~~
identification of abnormal OHA operation, and quick OHA recovery because of the following: 19 of 24
J :t
- SERT Report 92-05 e At the time of the initial system " lock-up", the Process Computer Group was not involved in the solution. Because they were not involved, they did not have the opportunity to participate in determining whether there were other failure modes.
e No requirements or technical information on how to 0 perform routine functional tests / checks to demonstrate f that the complete system is operational.
= No requirements or technical information for any corrective and preventive maintenance of equipment and software. = No requirements or technical guidance for abnormal operation of equipment and/or software operations.
XII. REVIEW OF INDUSTRY EXPERIENCE As part of the SERT investigation, a review and analysis was made to find industry events that may have been precursors to the December 13, 1992 event. This review used the "INPO" data base to recover all " annunciator" event incidents. This search generated 162 items. In addition the response to these documents were reviewed. Of the 162 items listed, two industry events were found to be similar to the Salem 2 event. The events which were similar were;
1. Significant Event Report 16-92 " Loss of Control Room Annunciators and Plant Monitoring Computer Functions" and OE 5358 " Loss of Non-safety Related Annunciators and Plant Computer" This Significant Event Report deals with the PALO VERDE 3 event i
on May 4, 1992. Most control room annunciators became inoperable due to a maintenance work activi*y. Over several hours, operations staff took corrective actisns to reduce power and take compensatory measures including declaring a plant ALERT. This Significant Event Report was presented to the Salem Operating Experience Feedback (OEF) meeting on September 30, 1992 and reviewed. It was determined that existing programs in place were sufficient (operation procedures, work standards program, etc.).
2. OE 5630 " Control Board Annunciators" and OE 5675 This incident occurred at the Callaway plant on October 16, 1992 causing a partial loss of OHA's. A failed field power supply was replaced under a work request. It was found on Octcber 19, 1992 that the OHA's were out of service for approximately 56 minutes.
This condition should have resulted in a plant ALERT on October 20 of 24
SERT Report 92-05 17, 1992. An AIT was dispatched to Callaway due to this event. This item was screened by Reliability & Assessment and sent to the Operations and Technical Managers at Salem and Hope Creek. The remaining items reviewed include such items as Plant Status's (ps), Design Engineering & Configuration Management (de), Emergency Planner Information Exchange (ep), Fire Protection & Plant Security (fs), Good Practices from INFO (gp), and Hot Line These were reviewed and determined not to be Items (hl). applicable to the evtut at Salem 2 or were covered in other reviewed documents. Several plants were contacted to discuss those events that seemed to be similar or of interest to this investigation. No items were found to be identical to the Salem 2 event of December 13, 1992. No information that was reviewed during this investigation would have given any significant information to alert operations personnel that a potential problem could present itself in the form of the type of failure experienced. A search of Nuclear Plant Reliability Database Search (NPRDS) was made and did not yield any failures to Beta equipment used at Salem. XIII. ROOT CAUSE ANALYSIS Attachment 3, Event and Causal Factor Chart provides a
~~& summary of significant events, inappropriate actions, causal factors and failed or inadequate barriers associated with this event.~~
~~The SERT determined the Root Causes of the Beta OHA System~~
~~" lock-up" as follows:~~
THE SOFTWARE ARCHITECTURE DID NOT CONTAIN ADEQUATE SECURITY TO PREVENT INADVERTENT ACCESS TO SOFTWARE CONTROL FUNCTIONS WHICH PLACED THE SYSTEM IN AN INDEFINITE " LOCK-UP" CONDITION. ; THE FAILURE TO FOLLOW OPERATING PROCEDURE S2.OP-SO. ANN-0001 (Q) BY NOT PLACING THE " BLACK BOX" SWITCH IN THE SER-A POSITION AND INADVERTENT ENTRY OF " CTRL L" CHARACTERS TWICE, WHERE THE PROCEDURE REQUIRED ENTRY OF " ALT L". There were multiple causal factors associat>sd with the Root Causes. The causal factors are as follows: A. Design specification S-C-ANN-CDS-0205 " Annunciator System" and Attachment F, "OHA Data Acquisition Data Monitoring" did not adequately specify software, software security and software testing requirements. B. The DCP as installed did not meet the Design Specification requirements, specifically the system design was to preclude a catastrophic failure. 21 of 24
SERT Report 92-05 C. The Project Team did not include an E&PB software specialist to provide design guidance, oversite and problem resolution. D. The DCP did not adegestely address procedure development and/or changes. E. Lack of a questioning attitude and insufficient follow-up by the Project Team related to the early system-failures during installation. F. Inadequate krtowledge of the Beta System by users of the system. G. The Operators did not receive training on some critical aspects of the system. H. The OHA System procedure, S2.OP-SO. ANN-0001(Q), contained incomplete requirements. I. The Operators were given misleading information relative to operating the RCW computer (operators were told they couldn't do anything wrong to the computer). XIV. GENERIC CONSIDERATIONS A. Proper Training Department Representation on the Project Team. The Training Department Representative assigned to the project team was not from the simulator group. This oversight prevented the Project Team comments from reaching the simulator group in a timely manner. B. Mean Time 3etween Failure Report i i Beta supplied an evaluation of the mean time between failure report (MTBF) .ach indicates that a "MTBF of 8539 < hours can be expected for a " soft" failure of the system d due to, in all probability, the failure of one optical coupler or one scanner circuit board. Such a failure is often identified as a " graceful degradation". l This failure rate is approximately equal to one failure per year per unit. Project teams need to be more cognizant of equipment failure rates and their potential for impacts to i station equipment. i C. Timely Revisions to Simulator
~~The design process requires that the training department be 22 of 24~~
~~i 1 SERT Report 92-05~~
. l notified that modifications may be necessary to the I simulator. It has been indicated that up to one year could l expire until the modification is upgraded to the simulator. !
l IV. RECOMMENDATIONS A. Add an independent circuit / component that monitors OHA operation without using the existing hardware and software , and provide a failure alarm in the control Room. B. Add an independent Verification Board that will periodically provide an input to spare field input terminals via a solid state relay and timing circuit for each window box group. The Verification Board would initiate and hold an alarm condition to allow sufficient time for the Console NCO to silence and acknowledge the spare window. Then the Verification Board would clear the alarm condition so the Console NCO can reset the spare window. C. Revise Operating Procedure S2.OP-SO. ANN-0001(Q) to provide instructions that describe possible System fault identification, and how the NCO can reset the SERs. D. Prepare and issua OHA System Preventive Maintenance and Corrective Maintenance procedures. E. Develop an OHA design change to provide 100 % OHA System redundancy. F. Clarify ECG Section 10D or develop another IC/EAL for this section. G. Provide multiple copies of current 10CFR to the Control Room area for reference. H. Review Hope Creek ECG/E-Plan Section 10 ICs and EALs as a result of the Salem OHA loss event. I. Revise UFSAR Change Notice for DCP 2EC-3056/PKG1, CD.I582 ; as follows:
~~1. Paragraph 3 and 5 on page 7.7-17 of the change was not ,~~
~~changed to reflect the new system configuration for the l Beta OHA system. 1~~
2. In paragraph 3, "A contact change of state or change in voltage level indicates an alarm condition until it i returns to its normal condition." In fact, the contact is !
~~momentary pulsed up in the "make" state and seals in the l alarm state, and the pulse down to " break" the condition. I~~
~~3. Update the UFSAR to address failure mechanisms that are i~~
23 of 24 , l
i l SERT Report 92-05 inherent to a microprocessor based system. j J. Reinforce that contract personnel are not authorized to l approvc "FSAR Change Notices' (for the responsible Department Manager). K. Have the responsible department manager approve the above UFSAR Change Notice revisions for DCP 2EC-3056/PKG1, CD.I582. L. Reinforce the need to maintain complete and detailed control room narratives. M. Proceduralize System Engineer manipulation of RCW computer where functions can affect the operability of the OFA System. N. For systems significant to plant operation (i.e.: Tech Spec implications, ECG classifications, other identified license conditions, etc.) provide training as follows:
1. Training prior to release of system / modification for operation;

2. Provide walk-thru with operators in system operation.
O. Evaluate methods for improving the interface with the Nuclear Training Center for training requirements associated with the DCP process. P. Establish Software Specialty Review in the DCP process for DCP's involving software and firmware modification / installation. Q. Perform test of " CTRL L" " CTRL L" on the Beta System during refueling 2R7 to verify results are as stated in the vendor supplied evaluation. Craig L be t SERT Manager 4 l 4 i 24 of 24 a
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SERT Report 92-05 Attachment 2 DETAILED )UENCE OF EVENTS 10/16/90 - Bid Design Specification issued, Rev. O. 12/12/90 - Bid Specification evaluated and awarded to Beta Products. 5/3/91 - ECG revised to clarify the Emergency Action Level for an Alert or Site Area Emergency when Control Room Annunciators are lost. 8/13/91 - Unit 2 Bid Specification, Rev. 1. 10/7/91 - Unit 2 Beta System Acceptance Test completed at the Beta Facility. 10/31/91 - DCP 2EC-3056, " Beta Annunciator System" (SER-4100) reviewed and approved by SORC. 11/1/91 - Station Manager approves DCP 2EC-3056. 12/31/91 - Licensed Operators complete training on ECG revision during Segment II. 1/92 - 3/92 - Unit 2 Beta Annunciator System (SER-4100) DCP installed and tested during 2R6.
~
2/23/92 - Unit 2 operators inadvertently " lock-up" the SER Computer and extinguish all alarms in window boxes "G", "H", "J", and "K" by activating OHA lamp test switch and depressing the OHA " silence" and " acknowledge" pushbuttons on the control console simultaneously d,uring the installation and testing phase. The
," lock-up" condition was cleared by depressing the reset buttons on SER Main and Aux controllers which returned the system to operation. Operators on shift at the time were instructed on the method of resetting the SER Main and Aux Controllers. - The System Engineer calls Kewaunee Station to learn they have a 100% redundant system and use interlock wiring change to RSA switches. - System Engineer requests project team to rewire I Salem's OHA RSA switches. - System Engineer informs Control Room Modification Group Project Team since there is 4
~ only one data line between SER-A & B and distributor boards a single data line (RS232) failure (P1), then OHA is not functional. 1 of 9 i
SERT Report 92-05 ' Attachment 2 2/24/92 - Operators inform Control Room Modification Group that 2 alarms in window box "A" were illuminated without cause. SER was reset, but several alarms in window box "A", "B", "E", and "F" remained illuminated. Found a " Checksum Error" on boards 3 and 9. Boards reset by removing then reinstalling associated fuses F1 and F2 on each board, followed by an SER reset returned the system to operation.
- Letter from Control Room Modification Group 2/25/92 Project Manager to Operations Manager recommending the operators refrain from depressing both pushbuttons simultaneously until a software change (EPROM) can be made.
3/5/92 - Operations informs Control Room Modification Group that 9 alarms in "F" window are illuminated without cause. " Checksum error" < found on board 18. Board reset by removing and l reinstalling associated fuses F1 and F2, then resetting the SERs, which returned the system I to operation. l 3/8/92 - Operations informs Control Room Modification l Group that several windows had not operated l properly during an I&C test over the weekend. I & C indicates window F-20 had not responded properly during I&C testing. Beta equipment receiving the alarm input, but gave no response. " Scanner #10 failure", scanner board reset by unplugging and reinstalling cables on scanner board #10 cleared the problem.
- Operations Manager issues an Information Directive (#92-016) to all operating shifts with the attached 2/25/92 letter from the Control Room Modification Project Manager, to refrain from depressing pushbuttons simultaneously until a software change can be ;
~~made. 3/11/92 - Letter from Project Manager to Beta Products expressing concern of 2/23, 2/24, 3/5, and 3/8 occurrences which had not been detected as a~~
~~" Logic Failure" on the OHA system.~~
Additionally, he indicates the loss of the OHA System for a period of time would put the station in the " ALERT" status requiring Local, State, and Federal (NRC) notifications. 2 of 9
I l SERT Report 92-05 Attachment 2 3/17/92 - Operating procedure \NN-1 & ANN-2 issued without information regarding requirements for criteria for functional capability or use of the " reset" pushbutton. 3/20/92 - Licensed Operators complete training on the new Unit 2 Beta Annunciator System during Segment III. The training was conducted on the simulator and included movement of the acknowledge pushbuttons and operation of the alarm CRT. 3/25/92 - Salem Maintenance Department I&C personnel complete a three-day training program on the new Beta Annunciator System. A System Engineer, 2 I&C Supervisors, and 6 technicians completed the course. 3/26/92 - Beta Annunciator System turned over to Operations with a two-page exceptions list which includes EPROM change to preclude system
~~" lock-up" during OHA lamp test.~~
~~4/9/92 - EPROM change from version 2.07 to 2.11 completed on distributed annunciator boards to preclude system " lock-up" during OHA lamp test using more that one pushbutton.~~
~~- EPROM change from version 1.14 to 1.15 on SER-A and B.~~
4/10/92 - Operators report 4 alarms in window box "E" (E-7, 15, 23, 47) illuminated that should not be, but the CRT display updates properly. The cause is attributed to "BLAISE ERROR MESSAGE" per Assistant Project Manager letter to Beta Products dated 4/15/92. However, SMD-IC indicated on WO# 920410120 they replaced logic board "E" and board "8". Found an " ECHO" problem in software and pulled fuses causing the problem to disappear. A satisfactory test was performed by the Test Group. 4/16/92 - System Engineer reports the first out windows were not coming up red. He runs tests to clear problem windows, but 2 alarms cleared that should have remained in alarm. He reser SER-A and B and the 2 windows re-alarm. Only had a "BLAISE ERROR MESSAGE". Beta trying to duplicate error problem at Dallas office. 5/28/92 -
~~" Checksum Error". Logic board replaced under WO #920528142.~~
3 of 9
SERT Report 92-05 Attachment 2 5/92 - 6/92 - DCP 1EC-3085, " Beta Annunciator System" design change installed and tested. 6/12/92 - Unit 1 Beta Annunciator System turned over to Operations. 8/14/92 - OHA "Annun Logic Failure" (A-9) albrms due to
~~" Checksum Error" on board 4. Under WO ; #920814137 SMD-I&C gives instructions to board '~~
4 to clear error and OHA A-9. 10/3/92 - Unit 2 CRT unit found broken. It is replaced by SMD-I&C under WO #920929183. 11/23/92 - Unit 2 backdraft damper leaking-by causing containment atmosphere to flow back through vacuum relief unit causing 2R13A to spike. A work request was written (#921123184) on 11/23/92, but the problem continues to cause RMS Trouble OHA to annunciate unnecessarily during containment pressure reliefs. Containment pressure reliefs are performed approximately once per shift, on average. 12/12/92 0 15:00 - Spare OHA window (A-45) in alarm when swing shift NCOs enter the Unit 2 control room.
~~- OHA " Lower Section Deviation Above 50% Power" alarms approximately 5,000 times. The cause was attributed to NIS contact chatter.~~
~~l t~~
@ 20:00 - NCO clears Spare OHA window (A-45) by resetting SEns in equipment room cabinet. ; @ 21:37 - OHA "21B-23B Screen Trouble" (G ,6) did not alarm @ 12" dp before 21B CW Pump emergency tripped at 10' dp. However, AAT printed "21B Traveling Screen Diff 10 Feet H20" 12/13/92 - OHA " Lower Section Deviation Above 50% Power" alarms and clears approximately 29,000 times throughout the day attributed to NIS contact chatter. i 0 01:00 - Spare OHA window (A-45) alarms a second time and the Console NCO acknowledges. - NSS notified by NCOs of alarming condition. - NCO clears OHA window (A-45) a second time. - Spare OHA window (A-45) alarms a third time and Console NCO acknowledges.
~~4 of 9 j~~
~~' l i~~
~~SERT Report 92-05~~
~~Attachment 2~~
~
~~04:00 - OHA " Condensate Return Tank Level Hi/ Low" (G-~~
~~45) alarmed and lit without supporting CRT l display.~~
~
12:00 - CHA G-45 cleared by operator in field with no CRT support for clearing. 9 15:00 - Console NCO informed at turnover the f acknowledge and reset OHA pushbuttons didn't ) work approximately 3 times during the day l shift.
- Console NCO asks NSS if he wants OHA A-45 l window cleared. ; - NSS directs NCO not to clear OHA A-45 because he plans to notify the System Engineer of the problem in the morning. @ 17:00 - OHA " Lower Section Deviation Above 50% Power" clears the final time. 1 @ 18:00 - Beta auto functional test completed SAT ~
~~18:00 - Desk NCO accesses Beta RCW (Panel 115-1) to obtain information associated with OHA A-45.~~
~~@ 18:18 - First " password" use attempted.~~
~~9 18:36 - Second "pessword" use attempted. 1~~
9 18

38 - "22 ABV Exhaust Fan Loss of 125 VDC" and
~~! associated OHA "AAS Printer" (A-41) alarms ,in the control room.~~
~~? - Console NCO accesses RCW in an attempt to identify cause for OHA A-45. l l~~
~~i 0 18:48 - OHA " Condensate Polisher Regeneration System~~
~~Trouble" (G-44) alarms. This is the last alarm received through the Beta Annunciator System prior to " locking-up".~~
~~h 9 19:00 - Beta auto functional test completed SAT l~~
~~@ 19:14 - Third " password" use attempted. ~~~
19:36 "RCW Error 1" archived three times. i 5 of 9
0 SERT Report 92-05 Attachment 2 t=0 min 0 19:46 - Beta Annunciator System clock on Overhead Annunciator Display (CRT) stops timing (i.e.,
~~" locks-up") due two CTRI-L characters with PROCOM Plus connected to BPA port (i.e., RCW-A position on switch above RCW computer).~~
~~t=9 min 0 19:55 - AAS prints " Chilled Water EXP. TK. Level Low", but the associated OHA "AAS Printer" (A-41) fails to alarm.~~
~~? - Desk NCO notices the printout and directs an NEO to fill the tank.~~
TAMS @ 19:56 - Console NCO exits control room area after being relieved by NSS.

TAMS @ 19:59 - Console NCO returns to control room area (Console NCO outside control area for 3 minutes) and Desk NCO leaves control room area.
~~t=20 min @ 20:06 - Desk NCO returns to control room area.~~
TAMS (Desk NCO outside control room area for 7 minu,es) t=22 min 0 20:08 - 2R13A & 2R13B alarm setpoint reached during a containment pressure relief causing associated i 2RP1 window (Radiation Alarm Process) to alarm.
~~OHA "RMS Trouble" (A-6) fails to alarm.~~
~~- Desk operator acknowledges the alarm on 2RP1, but Board Operator doesn't notice OHA "RMS Trouble" (A-6) does not alarm.~~
~~t=96 min 0 21:22 - Chilled Water EXP. TK. Level Low alarm returns to Normal and prints on AAS without associated OHA "AAS Printer" (A-41).~~
~~- NCOs notice associated OHA "AAS Printer" ( A-41) did not alarm. - NCOs notice the clock on the Overhead Annunciator Display (CRT) is not updating. It indicates 19:46 hours.~~
~~t=97 min @ 21:23 - NCO manually resets SER-B then SER-A in Beta Annunciator System cabinet in the equipment room.~~
~~- OHAs " Annunciator Logic Failure" (A-9), "RMS Trouble" (A-6), "104 Panel Trouble" (C-9), and "AAS Printer" (A-41) alarm after SERs reset. - Console NCO acknowledges the OHAs.~~
6 of 9
e SERT Report 92-05
', Attachment 2 t=106 min 9 21:32 - NCO verifies the clock on overhead Annunciator Display (CRT) begins updating. - NCOs verify AAS printouts coincide with OHA windows. - NCOs notify NSS . - AAS prints " Plant Vent Ht trace Trouble" and associated OHA "AAS Printer" (A-41) alarms, therefore the operators considers this as confirmation-the annunciator system has been restored. - NSS notifies SNSS - SNSS reviews the ECG 9 22:00 - SNSS calls Operating Engineer and indicates 3 minutes had elapsed between the time the Beta system was discovered to be " locked-up" to when the system was reset. Therefore, NRC notification was not required. ] - NSS calls the SE and discusses the Beta Annunciator System. NSS indicates the on-duty technician is not qualified to work on the system. Therefore, he requests the SE to come in.
0 22:05 - Fourth " password" use attempted. 9 23:30 - System engineer arrives and talks to NCO leaving control room. NCO asks if his use of RCW PC would cause system lock-up. System i engineer states 'no'. ! - System Engineer begins performing diagnostic
~~tests on the system.~~
0 23:45 - System engineer cannot log on RCW with password . for 20 minutes. I i 12/14/92 9 00:10 - System engineer down loads RCW PC to floppy disk for the past 4 days. i 4
~~@ 00:20 - SE revie's w SER-A and B alarm events.~~
- SE verifies SER-A and B are reading the same alarms using Alarm Summary (AS). Therefore, he concludes SER-A and B are logging the same

information.

7 of 9
SERT Report 92-05 Attachment 2 0 00:30 - SE uses RCW 'PROCOM PLUS" Program and performs SER diagnostics such as Functional Tests (PT), Alarm Summary (AS), Scanner Failures, Port Failures, Point Failures. 9 00:35 - At operator panel in the equipment room the SE 1 performs: FT, AS, and selected point statuses. SE prints historical buffer of SER-A for the last 400 events. 0 00:40 - SE leaves RCW in PROCOM PLUS because of printer i communication problem. RCW can not down load from SER-A and B in this mode.
~~@ 00:41 - OHA "H2 Purity Lo" alarms, but NCO can't acknowledge for 1 minute. SE repeats diagnostic tests which are SAT.~~
0 00:42 - SE tells NCO to issue WR for H2 purity alarm reset problem. 9 01:00 - SE performs "CONFIG" diagnostic program for the logic panels (i.e., overhead window box logic drivers). All logic tests are SAT. 0 01:15 - SE verifies: power supply LEDs are illuminated, no ground detection LEDs are
~~.; illuminated, primary LEDs are lit on auto RS- - 232 switch, bottom " Normal" illuminated on SER-A and B.~~
0 01:30 - SE returns RCW to RCW program and still finds a printer error. ; 9 01:45 - SE resets SER-A and B in an attempt to clear the printer error, but the printer error remains. 9 02:00 - NSS writes an Incident Report (#92-822) indicating the OHA system was effectively disabled for a period of approximately 90 minutes.
- SE and NSS discuss SE test results. SE staten OHA was not operating properly before the 21:23 l hours reset. NSS has serious operability Concerns. - SE said he will call vendor in morning. SE observes AAS and OHA working SAT and returns to his work area to review printouts. SE compares ]
his alarm printouts printed prior to 22:00 hrs. 1 on 12/13 and events coincide SAT. 8 of 9 l 1
I.
-1 SERT Report 02-05 Attachment 2 0 02:00 - SE review of SER printout did.not show AAS Alarms (A-41) at 19:55 and 21:22 on 12/13. No A-9 logic failure on OHA printout. SE aware of I clock stop at 19:46 hrs and informs ops that OHA was noc operating from 19:46 until Ops reset system. ~
~~09:00 - NRC Resident notified of event. 9 11:30 - SNSS contacts Emergency Preparedness to discuss ECG. 9 17:04 - SNSS declares an ECG 1 hour report in accordance with 10CRF50.72 (b) (1) (v) .~~
~~? - Night Order Book entry made by Operating ;~~
Engineer to take additional OHA system readings every 15 minutes. 9 20:30 - Unit 1 & 2 Operators begin taking readings every 15 minutes on Beta Annunciator System to verify functional capability. 12/15/92 9 11:00 - Incident Report written because the Acknowledge, Silence, and Reset pushbutton was lost.
~~, - Unit 2 Beta system will not acknowledge,~~
}' incoming or clear alarms. WO #921215105 written. ; 12/18/92 9 10:30 - SORC approves a Unit 2 Test procedure for the Beta System, i j 12/18/92 9 12:00 - Unit 2 Beta Annunciator System Testing f commenced. SER-A card removed to be tested in Dallas. l l 12/19/92 9 23:00 - SORC approves Unit 1 & 2 Justitication for Continued Operation.
~~TAMS computer time may deviate by as much as 5 minutes and 53 seconds from the Beta System times as used in this report.~~
i 1 4 9 of 9 1 s i
o s D NEW JERSEY DEPARTMENT OF ENVIRONMENTAL PROTECTION & ENERGY l
ENVIRONMENTAL SAFETY, HEALTH & ANALYTICAL PROGRAMS RADIATION PROTECTION PROGRAMS MAILING ADDRESS: CN 415 TRENTON, NEW JERSEY 08625 UTREET ADDRESS: 729 ALEXANDER ROAD PRINCETON, NEW JERSEY 085%0 PHONE: (609)987-2032 FAX (609)987-6354 TELECOPIER DATA TRANSHITTAL SHEET DOCUMENTSENTTO:hAj h Yu VJY71 Y A DOCUMENT SENT DY: [ Toned NUMDER OF PAGES: ,
~~TIME SENT: _ ,R : SC DATE BENT: ;-~~
~~/d </ 7 [d CONTACT PERSON TO CONFIRM DOCUMENT RECEIPT:~~
NAME $ o, ,/) , A __ _ TELEPHONE NUMBER k [-j o 3 S - COMMENTS: I 1 N . _ l _ - _ _ - _ _ _ - _ - - _ - . . - - - - - - - ----- - - - - - - - ^ - - - i
L- , \c What was the basis for concluding that the annunciators wsre
~~1. and~~
" fixed" within 3 minutes, declaring them operable, continuing operation at full power? At 10 PM Sunday night, how did the SRO Know that the problem would not recur? Itow do we know now that the problem will not recur? j
~~2. Is the system that failed original design?, was it modified?,~~
~~was it a backfit?~~
3. Is Salem Unit 1 or Hope Creek ausceptible to the same failure?

4. What was the potential for this problem to go unnoticed for a longer period of time? How long was possible?

5. Do existing operator training programs address this situation or acknowledge that it cou:d .appen?

6. Moo todA .ht dem noi MAL.,be aho k okel d a Me un pu. 3 birycdd

7. L ' Shu' k MS LA " A"Dee k huda (E&) Qwom 7 3, 23 a_ 90. ubM 3 l.
f
. 64- . 5duw- M~F fcirut l Win ils Ees kQL u pJ kbi~ b dL e es% L c&T ,L.) L & i Met y un g, *Q I?
~~f I & f. Q.2~~
~~.. . ea p p u.? l ? $% $W'W .~~
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~~...go.w.. .~~
~~4 8 STATEMENT OF AGREEMENT AND CONDITIONS OF NOTIFICATION~~
~
~~ARTIFICIAL ISLAND GENERATING STATIONS~~
Public Service Electric and Gas Company (hereafter called PSE&G) will provide notification to the state of New. Jersey, Division of State Police, Office of Emergency Management (hereafter called OEM) and the State of New Jersey, Department of Environmental Protection, Dureau of Nuclear Engineering (hereafter called BNE) in accordance with the conditions discussed below

I. NOTIFIgATION METHODS / LOCATION All notification calls will be made to the Communications Center of the New Jersey State Police in West Trenton, New Jersey. The primary means of communications will be the Artificial Island Nuclear Emergency Telecommunications System to the extension assigned to the Communications Bureau /OEM Operations Room. Normal commercial communications will be utilized as the secondary means of communications. The OEM and BNE will coordinate internal procedures ter ensuring that the appropriate cognizant officials of the OEM and BNE are subsequently notified by the New Jersey State Police Communications Bureau.
- II. NOTIFICATIONS TO BE PERFORMED A. Notification of any event declared as one of the Emergency Classes specified in either the Salem Generating Station or Hope Creek Generating Station Emergency Plans (or Artificial Island Emergency Plan when it s.persedes existing plans) will be provided within fifteen (15) minutes of the declaration of that event.
B. With the exception of paragraph 11. C below, a notification of any event declared in accordance with the guidelines contained in Title 10, Code of Federal Regulation (CFR) , Chapter 50, Paragraph 50.72 (b),
~~"Non-emergency events" will be provided within the first working day following the declaration of the event.~~
o i 8 C. For events classified in accordance with Title 10 CFR, Chapter 50, Paragraph 50.72 (b) (2) (vi) , which are not . i declared as an Emergency Class (as specified in i Paragraph II A above) notification will be provided within four (4) hours of tho declaration of the event, or prior to the issuance of a news release. III. CLARIFICATION OF CONDITIONS OF NOTIFICATIONS i A. It shall be understood that the notification requirement for any one event will;be fulfilled if that notification is performed in accordance with II A above. B. Follow-up notifications and communications for those events handled in accordanca with II A above shall be conducted as specified in the appropriate emergency plan and emergency plan procedures. C. Follow-up information for any event notification made in accordance with Paragraphs II B or II C above shall be requested through either the Manager - Licensing & Regulation, Nuclear Department, PSE&G, or the Emergency preparedness Manager, Nuclear Department, PSE&G. j i D. "Next Working Day", will be the next regularly schedule j PSE&G work day (8:00 a.m. - 4:30 p.m.) immediately following the event. This specifically excludes j weekends and PSE&G company holidays. 1 E.- A copy of each Licensee Event Report (or supplementary i Licensee Evont Report " associated with the event notification") will be provided to the BNE for all follow-up activities reported to the NRC. All substantive LER questions on behalf of the BHE shall be j directed in writing to the Manager - Licensing & i Regulation, Nuclear Department, PSE&G. l 1 l i IV. FINAL TMPLEMENTATION l This agreement shall be effective on the date of the last . signature on the document. ! l i ; i i
)
~~j i 4~~
~~IN WITNESS WHEREOF the parties have hereunto executed this Memorandum of Understanding.~~
~~l ( y fd b '~~
~~%$b I' Colo~odl Just,it J. Dintino //b/2~~
Judith A.. Yaskin [ Superintendent Commissi nor / j New/Jers y State' Department New Jersey State Police l of invi f
~~onmental ction Date: /o/5f[fd Date: 4'.<o n. bf~~
\
~~l 1~~
~~, Steven E. Riltenberger /~~
~~w Vic6 President-Nuclear Public service Electric~~
~~& Gas company i Dater /2 Y O e~~
~~g. i~~
*4 l
l 8 HEMORANDUM OF UNDERSTANDING : BETWEEN ! NEW JERSEY DIVISION OF STATE POLICE l NEW JERSEY DEPARTMENT OF ENVIRONMENIAL PROTECTION i AND i
~
PUBLIC SERVICE ELECTRIC G GAS COMPANY TO PROVIDE FOR THE IMPLEMEN'JATION OF THE STATE OF NEW JERSEY RADIOLOGICAL RESPONSE PLAN FOR NUCLEAR POWER PLANT , , i . I. PURPOSE: . The purpose of" this Homorandum of Understanding is to establish conditions upon which Public Service Electric E Gas Company (the utility) will notify the State Government of New Jersey (Commissioner of the N.J. Department of Environmental Protection and Superintendent of the N.J. Division of State Police) in the event of an accident which has the potential for radioactive exposure or contamination of members of the public of their property, Proper and timely flow of information throughout the duration of any such accident is assential in order for the Government of the State of New Jersey to discharge its obligation to maintain public health and safety by implementing protective actions as described in the State of New Jersey Radiological Emergency Response Plan for Nuclear Power Plants (NJRERP) or l , its successors. ) II. DEFINITIONS: l To minimize the possibility of communications breakdown, the definitions listed in the Stato of New Jersey Radiological Emergency Response Plan for Nuclear Power Plants (NJRERP) shall apply throughout this Memorandum of Understanding. III. AGREEMENT: The following terms shall be binding upon the State and the Utility: A. The Utility and State shall cooperate at all times in
~~.. developing, reviewing, and modifying protective action plans for accidents which endanger the public.~~
~~B. The State and Utility shall join in at least one annual exercise.~~
+ . C. The Utility shall provide and maintain a Nuclear ; Emergency Response Telephone System which is monitored 24 hours a day. This telephone is located in the Shift J Supervisor's office, the onsite Technical Support Center > ~
and the offsite Emergency operations Facility, which will have the sole purpose of maintaining communications with State Government in the event of a suspected or J, ; confirmed accident endangering the public.. The Division gJ - of State Police , in the communications Bureau, will provide an emergency telephone which' is monitored 24
~~j hours a day. The State will provide a telephone with an~~
~~; unlisted number in the office of the New Jersey State '~~
Department of Environmental Protoction, Bureau Nuclear Engineering (BNE). These telephone numbers will s of [ be exchanged by the State and the Utility. Both the 4 State and the utility further agree not to divulge the , unlisted numbers to any other party, i 1 The utility shall install and maintain, at each reactor sito; wind speed and direction Indicators to provide information for implementing protective actions. E. The utility shall notify the State as soon as possible ' but no later than fifteen minutes after the declaration of any incident defined in their utility's emergency
~~plan as an unusual event, alert, site area Emergency or 5~~
general emergency. In addition to the above conditions, i the Utility will notify the State of plant conditions which will generate public, government, or media concern ; i about ple.nt safety. At minimum, the State will receive i notificecion as stipulated in the appended Statement of Ac--%nent and Condations of Notification Artificial l 7 snd Generating Stations. The content of this section I shall not be construed to imply regulatory authority , supplanting or in addition to the Nuclear Regulatory ! ! Commission's (NPC) regulatory authority. l F. The Utility will provide the State with information needed to protect the public as soon as it is available. I G. The Utility shall furnish the State with two (2) copies
,, of its facility Emprgency Plan and amendments thereto as they are issued. The Stato shall furnish the Utility with (2) copies of its NJRERP and amendments thereto as i they are issued.
H. The Utility has the right and, in a case in which the Bureau of Nuclear Engineering personnel are unavailable, the duty to recommend protective action to the State of New Jersey,
O
I I. The notification shall be made by the Utility by telephone to New Jersey Stato Police by a format agreed to by both the Utility and the State. Technical information essential for evaluation and management of
~~~ the accident shall be given to designated NJ DEP Bureau of Nuclear Engineering personnel.~~
An accident shall be deemed to have terminated when, in J. the judgement of the State, there is 3 no longer need for consideration of further protective " actions as defined in the NJRERP. K. Throughout the emergency, the Utility will work closely with and coordinate all media news releases relating to i the status of the plant with the Governor's office, and the state Police, the State Department of Environmental Protection, and the Nuclear Regulatory Commission. The ' Utility will bear the responsibility for news releases relating to the status of the plant until the Governor declares a formal State of Emergency. With the declaration of formal State of Emergency, all news releases will be made jointly by the Governor or his t representative and the Utility after agreement is reached on content. All news releases issued by the utility during an emergency, prior to a declaration of a j formal state of emergency will be immediately hand ; delivered to State representatives at the Emergency News j Center and will be passed by telefacsimile to the State EOC and the BNE headquarters. All State releases will be hand delivered to PSEGG representative at the Emergency News Center and passed by telefacsimile to the Public Information Department at Artificial Island. l 3 L. This Hemorandum of Understanding supersedes and voids all previous Hemoranda of Undorstanding between the State Department of Environmental Protection, the Division of State Police end the Utility for the purpose ' of providing protection to the public in the event of accident threatening public life or property.
~~; M. This agreement shall be effective immediately upon ,, execution of the parties hereto, i~~
1
~~-+ca+=~~
ehe *p W -=>****e.**
~~j ' IN WITNESS WHEREOF the parties have hereunto executed this Statement of Agreement. luh. Y. '~~
~~'L&* L-Judith A./Yaskin ' Colon /1 Justin *J. Dintino Commissicher Super'intendent <~~
~~How Jersey State D art nt New Jersey' State Police of Environmental Pro ction Dato /C / #/ Id - Dato ' [#~~
/
~~g . ~ , staven E. Mil'tenberger vice President - Nuclear Public service Electric & Gas Company Drsto O "f A : l I to 9~~
~~" NUCTn R LICENSDIG WORK STANDARD~~
NRC TNSPEcr10N MANAGEMENT h ATTACHMENT 1

QUESTION AND ANSWER TRACKING FORM ITEM NUMBER: A 8 T"'O N A ** N.
~~SOURC NRC PSE&G (SELECT ONE) t DATE: . /&[P $N ) NRC CONTACT: ./2gj/ggd ggC QUESTION: pHg pkghQ kg/ I qO Y O"Nj '"~~
~~! Y DilkM SMMfC ctf.cchetf4n ces , wood AM( McthMfR) d4AM k/N & k I"N-!h Q A Chit, tk. cd, uou/d' //- 2e mauculOtoa) l i~~
~~PSEEG CONTACT: l M. ! LICENSING CONTACI. Ud(N l~~
~~PSE&G RESPONSE:~~
~~,$ g f/1circo ffdto A JC e.f 1~~
DATE: /1 ** NLR REVIE : YES / No (SELECT 0:lE) i RESPONSE ACCEPTED BY NRC: YES , !!O (SELECT ONE) I i INSPEC"0R'S NAME: O l DATE:
,/
~~1 \~~
~~'7 :: ;3 Revis:.cn 0 May ?. 1992 .~~
r 4 . > t J FAILURE OF A10 & A11 TO RESET l (Revised December 22, 1992) When restoring the containment pressure bistable, the associated windows A10 & A11, did not clear. This problem could not be duplicated during troubleshooting on Saturday, December 19,1992. The alarm was cycled three 1 times and cleared each time. Testing involved cycling the bistable and 1
! manually initiating a functional test simultaneously to duplicate the conditions. j When the incident occurred, the SER had received the signal that the bistable was restored and issued the command to the OHA system to clear the alarm.
This command was received by the CRT in the control room and transmitted i through the RCW to the printer. We have been unable to determine why the message was not received by the lampbox.
, The SER signal to alarm or clear a point consists of four distinct characters. If any of these characters are missing or wrong a communication error is generated inside the distributor board. Currently this information is only available by running a report from the computer memory. E&PB will include an external alrm for communication errors in our enhancement DCP. One theory 4
is that the signal was disrupted and a false character generated because the 1 - signal was generated during the 500 microsecond (.0005 second) functional test. This appears to be a discrete problem on the circuits for this window and does ! not affect the overall functionality of the OHA system if the problem recurs, it will be investigated. i l 1 1 I t
y e
*- NUCT.FAR LICENSING WORK STANDARD NRC INSPECTION MANAGEMENT ATTACHMENT 1 QUESTION AND ANSWER TRACKING FORM '
~~i ITEM NUMBER: /l tf-O MA "O 0 7 SOURCE: PSE&G (SELECT ONE) DATE: l7,fistf92 NRC CONTACT: [2c/ c,9 4LO~~
~~$"o"",i*O b s eossiea ce Ah s r ca A+>An> >' ' > n'"e s.,,nm , b,,~n eos.a c+aa e~c $s Pm iccc t~~
~~' PSEEG CONTACT: hfgj LICENSING CONTACT: gg7D - PSEEG RESPONSE:~~
~~$$ k l /$$Y N DATE: /[ 88!fD ,~~
~~NLR REVIEW: YES / NO (SELECT ONE) RESPONSE ACCEPTED BY NRC: YES / NO (SELECT ONE) INSPECTOR'S NAME: DATE: rS~~
/
~~er,~~
~~&E Ik May 29, 1992 17 of 18 Revision 0~~
~~4 e .~~
~~) /~~
There were several individual problems that occurred recently on the OHA System which caused the NRC to question the overall functionality of the OHA system. It has been determined that these were discrete problems and had no affect on the overall ; functionality of the system. A45 & G45 WINDOWS ILLUMINATED (Revised December 22,1992) Over the weekend of December 12 & 13,1992, a spare window, A45, lit up, also, the G45 window alarmed with no printout on the computer and no indication on the Control Room CRT. These windows were cleared during the event later Sunday night. The System Engineer and the vendor's representative have reviewed all the available information from the memories of the OHA System. They have confirmed there is no SER point number assigned to the A45 window, therefore the SER can not generate an alarm to the window. The pr!ntouts do not show any signals generated from the SER's to !!Iuminate the G15 window at the time of occurrence. Between the SER, the brains of the system, and the lampboxes are the distributor boards. The vendor's rep has
~~s;ated that the illumination of a spare window without an SER signal could be i a problem with noise in the system or with the distributor boards.~~
Troubleshooting of these windows on Sunday, December 20,1992 and Monday, December 21,1992, revealed a higher than desired level of noise on the cables and an increase in level whenever the light test was initiated. This level of noise,265 millivolts, could produce spurious actuations when a noise spike occurs. Rearranging of cables within the cabinet has reduced the background noise level to approximately 236 millivolts and eliminated the level shift. According to the vendor,it would be desirable to reduce the noise level further, therfore E&PB will be directed to add additional shielding or reroute of i cables. The existing cable routing was done to minimize the affects on the i digital cables. The transformers are mounted perpandicular to direct the flux lines away from the circuits. Most of the wiring is at right angles and parallel paths are minimized. The cable routing design has compromises because of the l need to retrofit the new OHA system into the existing cabinets. The problem l does not exist on Unit 1 because the cable routings are different. The reduced level of noise on Unit 2, 236 millivolts, is approximately the same noise level as exists on Unit 1 where we have not experienecd the problem. I Since this was a discrete problem that occurred downstream of the SER's, it is not a problem with overall functionality of the OHA system. J
4 N i To: Cal Vondra General Manager - Salem Station From: Michael Morroni Manager - Salem Technical Department
~~Subject:~~
Overhead Annunciator Our investigation into the lockup of the overhead annunciator on December 13, 1992 and the discrete annunciator window problems known to date is at a point that the compensatory actions identified in the justification for continued operation should be re-evaluated. It has been determined that the Unit #2 overhead annunciator operates in accordance with its present design based on the troubleshooting which was perf ormed via TS2.IC-ZZ.OHA-0001(O) REV. O on December 18, 1992. The SER A main controller card which was removed during the troubleshooting procedure was extensively tested at Hathaway/ Beta and found not to be at fault for the lockup condition. It has been concluded that the overhead annunciator locked up due to manipulations on the keyboard of the RCW workstation when the " Black Box" switch was in the RCW A position. This event was duplicated at the factory of Hathaway/ Beta. This conclusion is also concurred with by our engineering department. (See attachment "A") All of the discrete overhead annunciator window malfunctions have been investigated. The details of the troubleshooting, the causes identified and engineering judgements are included I in attachment "B". Although specific root causes have not been identified for each malfunction, it can be concluded that each of these malfunctions was a discrete window problem. These problems were readily identified by the operators who initiated corrective actions. Since these failures did not represent a complete annunciator failure, we conclude that the failures are random and overall annunciator l l functionality was maintained. The overhead annunciator system has been evaluated fur viruses by our Methods and Systems Department and found to be ; free of viruses. (See Attachment "C") ] 1 The keyboard for the engineering workstation has been disconnected from the RCW workstation and RED TAGGED for the Nuclear Shift Supervisor with instructions from the Technical Department to prevent people other than the System Engineer , from operating this keyboard. i- Based upon the above information it is concluded that the kl overhead annunciator system is fully functional and the I immediate corrective action to disconnect the PC keyboard will prevent the lockup failure from reccuring. It is also . 1 i
k e concluded that the compensatory actions put in place by the i Justification for Continued Operation are no longer required. Therefore we recommend that the compensatory actions be ; terminated. l N c.c. Vince Polizzi - Operations Manager ; 9 1 h r l l ) i I I 'l i
)
1
r
~~" '. "'- 12-21-uz : id:oz : r:uu tre- t,uu aan anna .u o 1~~
P. O PSEG Anemew T Public Semce Sectnc and Gas Company P.O. Box 236 Hancocks 8ndge. New Jersey 08038 Nuclear Department ELE-9 2- 0693 To: D. W. Lyons jf[ Technical Liaison to NRC Augmented Inspection Team Regarding Overhead Annunciator Lockup k FROM: M. L. Buraztein Nuclear Electrical Engineering Manager
~~SUBJECT:~~
ENGINEERING POSITION REGARDING SYSTEM LOCKUP DATE: December 21, 1992 Attached you will find two letters regarding the Nuclear l Electrical Engineering Department's position on the Overhead l Annunciator System. The first letter addresses the functional of the system and includes two support letters from the vendor, Hathaway/ Beta. The second letter discusses l our preliminary review of the system 8s ability to indicate and annunciate failures. l I concur with the position presented in the attached letters and expect that they will be of assistance to you in the development of your engineering evaluation regarding overhead Annunciator Lockup issue. If you have questions regarding the information provided herein, please do not hesitate to call myself at extension 1875 or Jack carey at extension 5080. JDC: sr-j C General Manager - Engineering & Plant Betterment Technical Manager - Salem k e t I , l %.r . l
12-21-32 1b:03 : IT E tAru- ous aos Zaum os u dth) ot* Avrumwr " A" TO: Moises L. Bursztein i Manager Nuclear Electrical Enginesring TKOM: John D. Carey, Jr. . 7 Salem IEC Supervis
~~SUBJECT:~~
Functional Status of the Salem Overhead Annunciator System DATE: Dec. 21, 1992 In a letter to myself from Mr. Michael van der Helm of Hathway/ Beta (ref attached), Mr van der Helm informs me that through testing at the factory in Carrollton, Tx., Beta has ! been able to repeat the lockup failure of our OHA through commands from the RCW while using "Procom Flus". Beta the personnel have been on site for a week troubleshooting and have system with station technical departmentare all reasonable potential investigated what they believe software and hardware problems. As a result of their efforts l to date, they have not identified any hardware or equipment.c__ problems with the system. It is now their opinion, based upon the repeatability of the forced lockup at the factory, j and the statements from the station operations personnel regarding their interfaces with the system just prior to the l event, that the transmission of the " Control L's" from the ! computer was the cause of the system lockup. Mr. Rossi McDade, Systems Engineering Manager for Bata, has stated to me that this is not a random failure (ref attached J letter from BETA dated 12-21-92), but rather an inadvertently induced tailure via keyboard operation that was corrected by l resetting the SERs. It is his opinion regarding the lockup q concern that the system is fully functional at this time, and the system's normal functional tests adequately demonstrate the performance on an hourly basis. He further believes that the system is not subject to additional lockups as long as the computer access is appropriately controlled. Based on the above explanation, the expert opinion of Mr. ! van der Helm and Mr. McDade, and on the information I am aware of regarding the design of the system and the events surrounding the occurrence. I believe that the OHA system is fully functional, regarding the potential for a lockup situation, and I do not see a need to continue the I do compensatory actions implemented by the station. recommend that strict controls be placed upon the use of the computer to interface with the OHA. In addition, I recommend that a system functional test-be performed after any use of , the computer keyboard and that test should be followed up with the initiation of an actual valid input such as opening: a cabinet door in thp-feTay~ rooj[> With these precautions. ; am confident that the operar.or will have adequately versfled the r Page 1 of 2 j
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xm u s . Az-et-uz . to.uo . t'2.m tat'n- 003 003 2/4ua 4/ u . 4 ie 4TTAct]M60T "A operation of the system. I have discussed these recommendations with Mr. McDade of BETA and Dave Herre11 of the computer group and they concur with these recommendations. I 1 l l
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dcas 08- 12-21-32 : 15:04 : PSEaG E&PB- 609 339 2749:s 5/ 3 t
~~(1 y kTTAcRMEM d l TO: J. D. Carey Salem I&C Supervisor FROM: R. L. McDade Engineering Manager Hathaway/Bata~~
~~SUBJECT:~~
FUNCTIONAL STATUS OF THE HATHAWAY/ BETA SER 4100R AND ; 1500 DISTRIBUTED ANNU..CIATOR j DATE: December 21, 1992 ! i The question po(\ed to Hathaway/ Beta concerning the operational ; status of the aBove referenced equipment is as follows: , Hathaway/ Beta has demonstrated at the factory that the gi1g anomalv experienced by PSE&G with the sequential events recorder and associated distributed lamp boxes is not a random failure, 3 nor an intermittent failure. We feel it is an inadvertent problem introduced by human intervention that caused the Main controller to go into a command mode and weit for additional ; instructions. While waiting for the additional instructions, the j
<- Main Controller was not outputting to the annunciator port. l Hathaway/ Beta has explained the theory of operation to PSE&G personnel and can say at this point, we fully declare the events recording system is fully operable and will perform its published capabilities and its design function. The statement is made conditionally upon the belief that strict and adequate controls will be implemented governing the access and use of the computer interface to the events recording system and related hardware.
Hathaway/ Beta is also prepared to suggest and help determine ways to best utilize the additional hardware and software diagnostic capabilities designed into the 4100R Events Recording System and 1500 Distributed Annunciator System. l
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a o ATrAcMHe4T 4 ! 1 . j Hathaway I i 1 To: Jack Carey PSE&G CC* Dave Lrons PSE&G l l 1 FrcT: Michael van der Helm Hathaway/ Beta j Date: 12/20/92 On 12/19/92, Hathaway/ Beta demonstrated that sending two control L's in a row from a PC attached to the system (in PSE&G's configuration ) to the RCWA port of, the SER/ Annunciator system could cause an anomaly similar to the one of 12/13/92 at Salem. Hathaway/ Beta was asked whetner the , annunciator system could be affected by the transmission of 1 Control characters to other ports of the SER system, whether l Control characters other than Control L would affect the RCWA i ( or RCWB ) port , and whether Control characters sent to other , PC accessible ports would affect the SER/ Annunciator system. l The first question can be answered by reviewing the system wiring diagram (PSE&G drawing no. 232977 8 4051-4). The anomaly is believed to have been caused by the transmission of Control L's from the computer while it was running the program *Procomm Plus". The system wiring diagram will shoW that the configuration port of the overhead annunciators, and four ports of the SER can be addressed by the computer. All other ports of the SER/ Annunciator system can not be addressed by the computer. The first of the five mentioned above, the annunciator configuration port ( Config. ), will only accept two control characters which it considers valid: Control M (which is Carriage Return) and Control C (which is used to abort from a configuration list). All other Control characters are ignored by the configuration port of the overhead annunciators. The four SER oorts which can be addressed by the computer are SERA, SERB, R CWA , and RCW8. The ports, SERA and SERB, are on different controllers but are the same type of port, and therefore will be discussed together. The same is true of the ports RCWA and RCWB. end so they will also be discussed together. The typical response of the SER to BETA PRODUCTS DIVISION 2029 McKenzie Drive #150. P.O. Box 115004. Canomon. 17 7501150o4
Yeleonone: 214 2412200

Fax: 214 2416752 l
~~i U to Mk < Control characters sent from procomm'plus to the SERA /5 ERB port isLas follows:~~
~~). !~~
~~pUBLIC SERVICE ELECTRIC'& GAS. UNIT 2 ANNUNCIATOR SYSTEM Station number 2 19 Dec 1992 17:08:25 m ,~~
. Improper entry l complete. !
The greater than sign '() ) is the cromot the SER issues to , indicate that a command may be entered. The period (.) j following the first orompt is the typical response of tne SER l when it receives a Control character. The remainder of the e text in the above example ( Station Name, Station Number, Time. Improper Entry, and Complete ) is typical for any input ; to this port, although if a valid entry has been entered, the
~~" Improper Entry" would be replaced by the command name and ,~~
~~the "Comolete" message would have the command name in front of it. i~~
?
The SERA / SERE oort is intanced to accept and responc to. i four Control characters: H ( Backspace ), M ( Carriage Return ), o ( X-On ), and S ( X-Off ). Of the remaining controi *
. characters, thirteen will generate a response like the one shown above, seven will generate a variation of the response shown above..and two will not generate any response. In all cases where an illegal Control character is sent to the SERA /SERS port, it does not cause the SER to lock up.
When procomm plus is connected to the RCWA/RCWB port, and two'of the following Control characters

J, K,L, 0, P. I, I
and V. are cent, the SER is affected. Characters J, P. and V will cause the SER to stou displaying events on the Color CRT and Annunciator windows for two to five minutes, but in all ; cases the SER times out and resets itself. The result of ) J this reset is that the overhead annunciator windows will be '
i. cleared and then re-alarmed, and the Color CRT screen will be re-painted with all the current alarms, The and result of sending two Control M's to the RCWA port is the same as above. but in this case the control of the evernead annunciator windows anc the color CRT will be transferred to the backuo main controller (Main Controller "B"). Then two to five minutes later, when the SER times out. the control of the overhead annunciators and color CRT will be re-assumeo by
~~. the crimary main controller (Main Controller "A"). sending two Control K's to the port RCWB, will cause the Main~~
, Controller "B" to stop displaying events ( provided it is connected =to's dispiar device ) for two to five minutes. before it times out and resets. 1 I . , , _ . , , . - ..,
~~-- -, .. .. . ...o...,., ..... .-_. . ..~~
e d Transmitting two Control O *s to the RCWA/RCWB port will cause that Main Controller ( A or B) to reset. A reset of Main Controller A- will result in the clearing and then re-alarmins of the overhead annunciators, and a re-painting of the color CRT screen. The transmission of two control **s to the RCWA/RCWB port will clear the 6000 point historical buffer resident on the Main controller ( A or S ). a' None of the results of the above six Control characters}}

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