IR 05000352/1987024
| ML20236V893 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 11/30/1987 |
| From: | Linville J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20236V885 | List: |
| References | |
| 50-352-87-24, IEB-87-001, IEB-87-1, IEIN-87-004, IEIN-87-030, IEIN-87-041, IEIN-87-30, IEIN-87-4, IEIN-87-41, NUDOCS 8712070152 | |
| Download: ML20236V893 (28) | |
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U. S.. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 87-24 l Docket No. 50-352 License No. NPF-39 Licensee: Philadelphia Electric Company
2301 Market Street
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Philadelphia, PA 19101 Facility: Limerick Generating Station, Unit 1 Inspection Period: , September 23 - October 31, 1987 Inspectors: E. M. Kelly, Senior Resident Inspector
! S. D. Kucharski, Resident Inspector Approved by: he[
apes Linville, Chief,VProjects Section 2A
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Summary: Routine daytime (197 hours0.00228 days <br />0.0547 hours <br />3.257275e-4 weeks <br />7.49585e-5 months <br />) and backshift (46 hours5.324074e-4 days <br />0.0128 hours <br />7.60582e-5 weeks <br />1.7503e-5 months <br /> including i weekends) inspections of Unit 1 by the resident inspectors consisting of:
l resolution of outstanding items including response to NRC Bulletin 87-01 on pipe wall thinning; walkdown of the RCIC system utilizing PRA guidance; plant tours; maintenance and. surveillance observations; and review of LERs and periodic reports. NRC allegation 87-A-0092 related to radiological controls on the refueling floor was resolve Events included: several reactor enclosure isolations during the period; EHC fluid leaks requiring power reductions on September 25 and 26; an Appendix R fire protection concern identified on October 2; and, a recirculation pump trip on October 1 Meetings attended included routine PORC, EHC evaluations, and an enforcement conference held on October 22 to discuss diesel fire suppression protective trip logic. A major corporate reorganization of the licensee's nuclear divisions was announced on October 9 that became effective on November 1 with implementation pending NRC approval. A plant tour by attorneys from the Department of Justice was conducted on October 27. Searches were made using i drug detection dogs as part of security investigations conducted on October 29 and 3 No violations were proposed. A self-identified violation involving startup of a recirculation pump on September ~ 5,1985, is discussed in Detail 5. Unresolved items were initiated for proceduralizing a control rod sequence to facilitate rapid plant shutdown (Detail 4.2), and a study of 480 volt safe-i SW Team Buajha l G
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guards load center breaker response (Detail 5.2.1) as described in LER 8N An example of the assurance of quality in the area of surveillance test p'.'an- '
ning is discussed in Detail fP s
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DETAILS ,
1.0 Principals Contacted
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Philadelphia Electric Company a .
J. Doering,-Superintendent of Operations R. Dubiel, Senior Health Physicist o G. Edwards, Technical Engineer t
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/' 4 J. Franz, Station Manager '~ $ '
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M.Gayagher,ReactorEngineer 1' N
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J. Grimb , Branch Engineer, Testing and Labs R. Kankus, Director of Emergucy Preparedness r J. Milito, Field Engineer D. Helwig, Mechanical Engineer ,
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W. Hannum, Corprate Investigad<or ,
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L. Perkoski, I&C Shop Foreman , >
J. Spencer, Supert raer. dent of Services ,
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Also during,this inspection period, the inspectors discusseif,phnt status and operationu with other supervisors and engineers in the ofMO. Bechtel q and General Electric organization '
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2.0 Followup on Unresolved Items 2.1 f, Closed) Unresolved Item 87-01-09; TSC Frisker Contamination Station h
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The inspector ooserved the licensee's;amerency cD111 practice con-ducted on, October 21. A previoLs finding fromt%C observation of the annual emergency exercises in April 1986 and Aanuary 1987 (Inspection was that no means had been e' stab)'aned in the technical d q.go-352/87-01)
u; port center (TSC) to set up a portable' Land-held frisker/ probe for contamination control in accardance with Ster 2.4..t.4 of emergency
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plan implementing procedure EP-330, Emergency Response Facility
Hab^i thbil i t During the October 21 practice session, the inspector x 1 ob.urvec appropriate establishment and utilization- of a frisker V (pdtnanently installed Eberline Model RM-20 probe, Serial No. 534)
S at the entry to the TSC display crea. The next full-scale annual k exeredse is scheduled for the wsk of April 4, 136 This item is th refore close , 2.2 (C h gd) Unresolved Items 87-01-01 and 87-01-02; EAL Event Bases
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, Re< bion 5 to emergency plan implementing proceduty EP-101, Classi-A ;" .. fication of Emergencies, wa , approved for issuance on October 28, 1987. The revision addressed, in part, two weaknesses associated with NRC observation of tie last annual emergency exercise in January 1987 associated with clas.iiication of emergency action levels (EAL).
Specifically, the EALs in 9-101 do not consider a main turbine casing penetration as an aleet condition, cs recommended in NU[EG 0654, Criteria for Evaluation nf Radiological Emergency Plans and
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-(1 Preparednes Examples in NUREG-0654 srecommer.ded as initiating condition!/whkh could constitute unusual events included turbine rotating component failures causing a rapid plant shutdown. An examole is also presented as an alert whereby a main turbine failure co&;, result in a casirg penetratio Tne EALs' recbmmerided by NUREG 0654 are symptomatically encompassed by existing concitinns specified in the Limerick EP-101 procedur For example, unusu'ai events and alerts are defined by specific
- radiological effluent releare rates which are, in turn, indicative i of abnormal plar.t shutdowr,s (such as reactor 1; crams due to Group I L isciations and turbine trips) that wuld dirictly truult from main . . _
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turbine casing penetrations.
l The licensee alsc- revised the EAL criteria related to loss of hot or cold shutdown capability. The revisions were. developed it: parallel with existing emergency operating proce e n to syniptomatically diagn w ctor coolant conditions 'comn,msurate with site area or gener41' emergency conditions. The changes to EP-101 address the f NRC's' findings, f-om observation during the January 1987 exercise, I-.
of operator difficulties in recognizing general plant conditions rather; than specific measurable parameters meeting this EAL. The new n!iteria correlates the EALs to reactor coolant temperatures, ( suppression pool temperatures, and reactor water leve :These) items are therefore close .1 NRC Bulletin No. 87-03: Pipe Wall Thinninj ,
in response to NW BcUstin 87-01, " Thinning of Npe Walls at Nuclear Pov e N nts", the licensee' developed a program to address th! .1:. sue of wall thinnini due to erosion or corrosic 1 under single and Wp phase how csditwns. The bulletin was generated as a resu% of tne 1986 Surry feedwater pipe break, and recommended a prograir to monitor the changes in the wall thickness of condensate, feedwater, steam and high' energy piping systems. The programs encompass all safety related and non-safety related piping systems fabricated of carh m steel. The inspection programs address carbon steel piping systems. An existicg program addresses system loca-tions subject to single phare ficw erosion / corrosion (E/C). A new program under development for two phase flow E/C will consist of reviewing system operating parameters and identifying locations of potentially significant pressure drops which could lead to flashing or cavita tion. '
The program for two phase systen,s .is as follows:
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locations where there are abrupt changes in the direction of f?ow (elbows, rees} immed utel) aunstre.rn of significant pressure crops (orifices, contro's valves) and at other fittings which coald cause flow perturbation \
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inspection frequency will be based upon prior inspection data:
systems exhibiting high E/C wear rates will be inspected more ofte 'utrasonic and visual examinations will be utilized.
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repair / replacement decisions will be based upon review of the data, estimating the erosion rate and comparing it to the design minimum wall requirements.
!- The single phase program consists of inspections of piping similar to the criteria described for two phase locations but operating in the temperature range of high E/C susceptibility. System selection is also based, in part, upon velocities and configuration including the spacing between fitting During the Unit I first refueling outage from May 15 to August 26, 1987, the licensee performed the detailed piping inspections described above utilizing manual ultrasonic test (UT) technique Inspectors were qualified in accordance with nondestructive test standard SNT-TC-1A, and inspection procedures were perpared by a qualified Level III inspector. The inspections were performed on single phase flow piping only. The two phase flow inspection program is currently under development since only one cycle of Unit 1 operating experience is availabl All pipe wall thicknesses exceeded minimum wall thickness requirements. No unacceptable conditions were identifie .4 (Closed) Unresolved Item 87-21-01; Diesel Protective Trips The inspector reviewed an August 10, 1987 memorandum from the licensee's risk assessmen. supervisor to the Unit 1 station manager which addressed the impact of diesel engine protective trips on reactor safet Specifically, the bypass of engine trips on a LOCA-start signal but not on dead bus conditions (or loss of offsite power) was examined in light of sensor / relay reliability and operator error probability. Also, the relative times requiring operator intervention for equipment problems in both LOCA and loss of power situations were compared. The licensee concluded that the calculated probability of an inadvertent engine trip resulting in long-term diesel unavailability during a loss of power was three orders of magnitude less than the statistically expected diesel engine failure j rate (0.01 per demand). False trips were found to be an insignifi- ;
cant contribution to overall engine unavailability, and long-term unavailability is therefore minimized with the protective trips not bypasse l
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. 6 The inspector attended an enforcement conference ~ held on October 22 in the NRC Region I office to discuss the deportability (under 10 CFR 50.55 (e)) of a related construction deficiency whereby all four diesel engines would be potentially prevented from automatically starting due to the common modc failure of non-safety related fire j suppression flew switches. The condition was identified in the NRC l l Construction Team Inspection No. 50-353/87-11 of Unit 2'in June-July l
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1987. Also discussed at the October 22 conference was a Unit 1 License Condition violation identified by the licensee on October 2 related to Appendix R safe shutdown analyses (see Detail 4.5) whereby 1 a fire in the emergency service water (ESW) pipe tunnel would affect l the same fire suppression flow switches, and could prevent initiation ,
of the diesel generator The Appendix R problem was the subject of l NRC Inspection No. 50-352/87-27 conducted on October 20. The licen-see presented an evaluation of the effect of the flow switch design on emergency diesel engine operation, including the bases for removal of the switches from the engine protection logic on October 21 (see Detail 9.1).
Because of the separate enforcement actions under consideration, as
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described above, and the permanent removal of the fire flow switches, item number 87-21-01 is considered resolved. No further concerns were identified by the inspecto .0 Plant Operations 3.1 Summary of Events Unit I was limited to operation at 85% power during the entire inspection period due to main turbine electrohydraulic control system instabilities. A recirculation pump trip occurred on October 13 during surveillance testing of the redundant reactivity control system logic (Detail 4.2).
3.2 Operational Safety Verification 3. Control Room Activities The inspectors toured the control room daily to verify proper manning, access control, adherence to procedures and compli-ance with technical specifications. The inspectors reviewed shift superintendent, control room supervision, and licensed operator logs and records covering the entire inspection period. On October 29 and 30, backshift inspections were performed between the hours of 2:00 am and 6:00 a The inspectors reviewed logs and records for completeness, abnormal conditions, and significant operating changes and trends. Other records reviewed included: Reactor Engineer- )
ing and STA books, night orders, radiation work permits, the locked valve log, maintenance request forms, temporary circuit
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L alterations, and ignition source control checklists. The inspectors also observed shift turnovers during the perio Operations activities were observed for conformance with Admin-istrative Procedure A-7. No unacceptable conditions were-note .2.2 Securi ty During entry to and egress from the Unit 1 protected area and vital areas,'the inspectors observed that access controls, security boundary integrity, search activities, escorting and badging were in accordance with Security Plan implementing procedures and guard force instructions. The inspectors also observed the availability and operability of security systems such as' search equipment, perimeter detection devices, and security computer alarms. The inspectors verified that the_
minimum number of armed guards required by the Security Plan to be onsite were present on selected shifts by review of duty rosters, discussion with licensee Shift Security Advisors, and observation of guard force turnover .2.2.1 Allegation RI-A-87-0083 The resident inspectors followed the investigation being conducted by the licensee's corporate security group regarding the subject allegation received by the NRC in July 1987. The inspectors verified that the licensee was appropriately implementing their fitness-for-duty program and that appropriate one-hour notifications were being considered or made in accordance with the newly issued (as of October 8)
10 CFR Part 73 requirement The senior resident inspector was notified on September 28 by security supervision of an individual who tested positively for marijuana use and was subsequently terminated. The individual had admitted to marijuana use during an interview conducted on September 2 The individual was a contract radwaste cleanup person who had been hired and badged for Unit 1 protected area access since October 16, 198 At the end of the inspection period, the licensee's investigation had been expanded to include testing of I additional station personnel on October 19. The test i results were negative. The licensee implemented the use of random inspections by drug detection dogs during the week of October 26. A small amount of what i was later confirmed to be marijuana was discovered on October 31 in a desk located inside of a structure in the turbine enclosur i j
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.,- 8 3.2.2.2 Drug Testing
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An anonymous allegation was received-by NRC Region personnel on October 5 relating to drug use by a con-tractor employed primarily for Unit 2 constructio The individual had bean badged for Unit 1 protected area access for approximately one year, although his assignment was at Unit 2. The individual's Unit I access was restricted on October 5. During an interview by corporate security investigators and construction management, the individual. admitted to useuof marijuana but declined to submit to a urin-alysis test. The individual's employment was terminateduon October The licensee's onsite security supervisor received an anonymous allegation on October 6 that two contract employees were using drugs. The individuals were Unit I carpenters badged for protected area access since February 1987. The individuals were interviewed and submitted to drug testing on October 6; one tested positively for cocaine and marijuana, and his employ-ment was terminated on October The inspectors concluded that the licensee's actions were in accordance with the PECO drug policy and fitness for duty program . Radiological Controls The inspectors observed the availability and use of radiation monitoring equipment, including portal monitors and portable friskers. The inspectors also observed health physics (HP)
supervision and technicians in plant activities involving potentially significant radiological conditions. Radiation 1 work permits (RWPs) were selectively reviewed to determine i that appropriate job controls, protective clothing, dosimetry and HP support were prescribed, in use, and understood by workers involve Radiological controls for the reactor water cleanup cubicles were assessed as part of review of RWPS-044-87-009 through 01 Proper surveys and contamination clothing were prescribe Radiological conditions were discussed with HP technician Proper locked high radiation area controls, including appro-priate and frequent surveys, were verified to be employe The inspector had no further concerns, and identified no violation !
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.- 9 3.2.3.1 Allegation RI-A-87-0092; Refuel Floor Contamination Control The senior resident inspector evaluated radiological controls applied to refueling floor activities during reassembly of the reactor vessel, and specifically for a contamination event which occurred on July 27 and '
was described to the inspector by a contract mainte-nance worker on July'28. The associated personnel contamination report was reviewed by.the inspector and found to be acceptable. The licensee revised refuel-floor practices related to face shield issuance and heat" stress management. Proper controls.and adherence to procedures were verified, no significant radiological contamination was experienced, and no violations were identifie .3 Station Tours The inspectors toured accessible areas of the plant throughout the inspection period, including: the Unit I reactor and turbine-auxiliary enclosures, the main control and auxiliary equipment rooms; battery, emergency switchgear and cable spreading rooms; diesel generator cubicles and the plant site perimeter. During these tours, observations were made of potential fire hazards, radiological conditions, housekeeping, tagging of equipment, ongoing maintenance and surveillance, and the availability of required equipment. No unacceptable conditions were identifie . Cold Weather Preparations The inspector assessed the status and verified completion of the licensee's program to prepare the plant for cold weather operatio This program is described in General Plant Pro-cedure GP-7, Cold Weather Preparation and Operation The program consists of valve and switch check-off lists which align: HVAC systems in critical areas, heat tracing for freeze protection for the condensate storage and refueling water storage tanks, and the circulating and service water systems to operate in their winter modes. The program also closes power block rollup doors, drains certain outside tankage, and provides temporary electric heaters in the spray pond pump house. The program is procedurally required to be completed before November 1 No unacceptable conditions were identifie .4 System Walkdown 3. Engineered Safeguards Features Verification
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The inspector performed a detailed walkdown of the reactor core isolation cooling (RCIC) system in order to independently l verify system operabilit The walkdown included review of the following:
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-- Technical Specifications 3/4.3.5 and 7.3, FSAR Section j 5.4.6, P& ids M-49 and 50, and Licensed Operator. Training i Plan-038 Inspection of RCIC equipment conditions and associated fire protection systems
-- System check-of f list S49.1. A and system operating proce-dures consistent with plant drawings. The inspector also noted that all operating procedures had been recently revised for human factors consideration Valving and switches properly aligned including appropriate locking devices
-- Instrumentation properly valved-in and operable, and proper keep-fill system (condensate transfer) piping pressure at 125 psi Satisfactory status of control room indicators and con-trols, including flow controller set to 600 gpm
-- Surveillance test procedures ST-6-049-230, 320, 200 and 202; and ST-1-049-202 appropriately completed at the required interval Also, RT-1-049-331-1 related to RCIC turbine overspeed trip test, was satisfactorily complete Modification 86-5040 completed and tested to improve throttling characteristics of the CST test return valve HV-1F022 to facilitate pump and valve flow testin Scheduled five year vendor-recommended maintenance overhaul of RCIC pump and turbine, completed on August 24, 1987, under maintenance form (MRF) 868-768 Within the scope of the inspection, no unacceptable conditions were note The inspectors discussed recent maintenance, modifications, and design concerns related to the RCIC system with responsible test engineers. Proper operation of the RCIC system was also verified as followup to the September 19 reactor scram even No unacceptable conditions were roted.
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3. PRA-Based System Inspections I The inspector performed selected system walkdowns utilizing methods prescribed in a study prepared for the NRC by Brook-haven National Laboratory using the Limerick Probabilistic Risk Assessment (PRA). The study, entitled PRA-Based System Inspection Plan and dated May 1986, provides inspection guidance by prioritizing plant safety systems with respect to fj their importance to ris The study incorporates abbreviated (
s.vstem checklists which contain components that are considered to have a high contribution to risk as determined in the PR The inspector verified the proper operability or configuration of the following RCIC system components on several occasions during the inspection period:
- pump suction from CST
-- lube oil cooling supply
-- steam supply isolation valves
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-- turbine exhaust vacuum breakers
-- overspeed trip logic
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No unacceptable conditions were note .0 Onsite Followup of Events The inspector performed onsite followup of the following events that occurred during the inspection period. The events were evaluated for proper notification of the NRC, reactor safety significance, licensee '
efforts to identify cause and propose effective corrective action, and verification of proper system design respons .1 Turbine EHC Oil Leak A small leak on the order of 1 gallon per minute was discovered on the morning of September 25 at the number 2 control valve servo unit supplying electrohydraulic control (EHC) oil for valve movemen A plant shutdown from full power was begun and, upon reducing power below 30% and within bypass valve capability, the main turbine was tripped and taken of f line three hours late The EHC leak was
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isolated and, with the reactor maintained on line at 22% power, the I servo unit was replaced and the oil spill was cleaned u The turbine was placed back in service approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> later that evenin The inspector noted that, in order to rapidly shutdown the reactor but still maintain an appropriate control rod sequence, the Unit 1 shutdown required approximately three hours and the presence of a reactor engineer. The technical difficulty encountered was that the rod sequence control system (RSCS) begins enforcing at 22 1/2% power
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I measured from turbine first stage pressure, but Technical Specifica- l tions Action Statement 3.1.4.2.a requires a scram with the RSCS inoperable (eg. rod pattern out of sequence).
The Unit 1 RSCS Group 9 control rods (21 rods total) are power-shaping rods targeted " deep" or typically inserted past notch 1 Currently, four of these rods are fully inserted, five others are partially inserted and the remaining 12 are fully withdrawn. The RSCS Group 9 rods must be fully inserted, and the next RSCS Group 10 (a total of 16 rods typically targeted " shallow" and currently fully withdrawn) must be anywhere from notches 48 to 12 in order to automatically satisfy the RSCS sequence. Procedurally, the rod worth minimizer (RWM) software and " pull-sheet" did not accomodate the quickest appropriate sequential insertion order to achieve a rapid power reduction to less than 25?; powe I Operational complexities in the 20-30?s power range are also encoun-tered, such as feedwater pump runbacks and xenon transients, when attempting to reduce power only with recirculation pump flow-reductions. Since general plant procedure GP-4, Rapid Plant Shutdown to Hot Shutdown, currently specifies reducing recirculation flow to minimum and then manually scramming the reactor, the objective of the shutdown on September 25 (to keep the reactor on-line and within the turbine bypass valve capacity of 27-30?; power) was not fully addressed by the procedure. To correct this problem and provide direction to
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control room operators for future similar situations, the licensee proposed a revision to the RWM software and sequence by changing the reactor engineering shutdown instructions implemented via procedure RE-201, Reactor Maneuvering Plans. The changes will allow for a more rapid reduction of reactor power to the preset RWM/RSCS enforcement level with only full insertion of all Group 9 rods. Pending approval of appropriate procedures, this issue is unresolved (50-352/87-24-01).
During power ascension on September 26, the Station Manager made an entry into the control valve area at approximately 1:00 pm and dis-covered a section of insulation that was shouldering and exhibiting flickers of flame. The insulation was sprayed with a dry chemical fire extinguisher, a power reduction was begun, the turbine was again taken off line and the unit remained at 12?s power through September 27 while the insulation was replaced and additional cleanup of the area was performed. An onsite meeting with engineering representa-tives was held on September 27 to determine EHC monitoring locations and parameters to determine the cause of the number 2 control valve vibrations. Closed circuit television coverage of the affected turbine enclosure areas was instituted and a fire watch was added as a precautio The generator was synchronized back to the grid on September 2 The licensee's evaluation of the effects on EHC performance of a recent modification to partial arc admission of steam to the turbine
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. 13 were inconclusive as of the end of the inspection period. A modifi-cation was being prepared to replace main steam line resonance compensation electronic circuit cards to reduce the amplification of high gain EHC control signals above 85% power. The inspectors will follow the licensee's solution to the turbine vibration prob-lems that limited reactor operation to below 85% power during the perio .2 Recirculation Pump Trip The ' A' recirculation pump tripped on October 13.during the perform-ance of a surveillance test. The test involved verifying the 'B'
logic of the redundant reactivity control system (RRCS). The I&C technician performing the test connected the leads to the wrong contacts ('A' contacts) which resulted in opening of the ATWS breaker to the ' A' recirculation pump. Reactor power was reduced from 82% to 32% by the pump trip. The 'A' pump was restarted within 30 minute The licensee subsequently decided to switch the lube oil pump on the
'B' recirculation pump to the same arrangement as the 'A' recircu-lation pump to check for vibration problems which had previously occurred. When attempting the switch, the lube oil pump failed to start causing the 'B' recirculation pump to trip. The licensee then started a backup lube oil pump in an attempt to start the 'B' recirc-ulation pump. The 'B' recirculation pump started, but then tripped due to low lube oil pressure. The second trip occurred due to a filter problem with the lube oil pump. The licensee changed the *
filter and successfully restarted the 'B' recirculation pum The inspectors verified proper adherence to procedures by operator .3 Reactor Enclosure Isolations On October 14 the auxiliary boilers tripped and removed the steam supply to the reactor enclosure ventilation heating coils, which caused the ventilation supply fans to trip, resulting in an isolation on low differential pressur The reactor enclosure recirculation system (RERS) and standby gas treatment system (SGTS)
initiated and functioned as designed. The licensee found that the
'B' boiler tripped because of a flame failure due to a bad torch ti The torch tip was replaced and the boilers were returned to service. The isolation was reset and normal ventilation was restore An isolation of the reactor enclosure occurred again on October 19, followed by expected initiation of the SGTS and RERS. The cause was a gradual loss of secondary containment differential pressure as a result of colder supply air. The colder air was due to a loss of heating steam to the supply fan coils because of trip of the auxil-iary boilers upon a momentary high steam flow. Reactor enclosure
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damper isolations and SGTS/RERS equipment functioned as designed,
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I' . 14 as did two suppression pool air space exhaust isolation valves which closed. A suppression pool purge was in process. The isola-l tions were reset and normal ventilation restored within 30 minute L A Unit 2 load center transformer failed on October 20, causing trips of a drywell chiller, fuel pool cooling pump, and auxiliary boilers. The reactor enclosure low differential pressure isolation signal was bypassed by operators until the auxiliary boilers could be restarted. Another reactor building isolation occurred on i October 23, due to a loss of instrument air pressure to the normal '
ventilation supply fan dampers. The loss of air pressure was caused by a leaking check valve on an instrument air compressor which had been blocked for maintenance. The isolation was reset and normal ventilation was restored within 10 minutes. All systems responded normall l A secondary containment isolation occurred at the end of the inspec- I tion period on October 29. The.cause was a loss of reactor building i differential pressure following a trip of the normal building venti-lation exhaust fans due to an erroneous isolation of the air supplies to the exhaust fan damper Equipment operators had been dispatched to change out filters on an-unrelated filter train for the equipment compartment exhaust system but, because instrument air valving was not labelled for either system, they traced-down the wrong air supply lines and isolated the wrong valves. The isolations were reset and normal ventilation was restored within 10 minutes. The event and recovery actions were witnessed by an NRC inspector who was perform-ing a backshift inspectio All of the above events were appropriately reported to the NRC via the emergency notification system (ENS). The inspectors discussed the high incidence of reactor enclosure isolations with station manap q q Although no common causes were identified, several corr e .- ,1ve act:9ns were proposed including: modifying auxilary boilers to improve their efficiency; completing a walk-down of the instrument air piping to complete an accurate labelling program for j all associated valving; improving upon the normal ventilation system design for reactor enclosure face and bypass dampers; and, tempo-rarily restricting energization of Unit 2 transformers or 'ew loads until evaluations of undervoltage trip relay settings or : guards load center circuit breakers are completed (see Detail .2.1). The licensee has also developed a new administrative guideline procedure AG-21, creating a plant incident tracking system to index significant i problems, particularly those of a repetitious nature, and more efficiently determine root cause in the POR ,
I The inspectors will follow the licensee's proposed corrective l actions as event reports (LERs) for the above events are issue l
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. 15 4.4 Control Room Ventilation Radiation Monitor Failure Control room ventilation was isolated and the emergency fresh air supply fans initiated on October 17. The cause was an electronic circuit board that had been unseated in the course of troubleshooting by I&C technicians for the "A" channel ventiation radiation monito The technicians were investigating a check-source alarm associated with the "A" monitor that had been received approximately three hours earlier. The isolation was reset following confirmation of the caus Within 10 minutes, normal ventilation was restored, and the NRC was subsequently notified via the EN The inspectors verified proper system operation and operator actions. No unacceptable conditions were identifie .5 Appendix R License Condition Violation
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An engineering evaluation was concluded on October 2 that identified an Appendix R postulated fire which potentially could disable or prevent automatic start of the four emergency diesel engine Non-safety related flow switches (three per engine) manufactured by Fluid Components Inc. (Model 12-64-4-SA) were found to have logic cable routed in a common conduit. The conduit traversed the service water pipe tunnel fire zon If a fire were to occur in the area, it could create multiple internal shorts in connections between the flow switches and time delay relays, resulting in trip signals for all four diesel engine The licensee disabled the flow switches on October 2 by applying temporary circuit alteration (TCA) numbers 1150 and 1159 to open the supply breaker to circuit 17 at non-safety related electrical panel 10Y202. The licensee also reported the potential discrepancy as a violation of Limerick Unit 1 License Condition 2.C(3), Fire Protec-tion, to the NRC via the ENS as required by Section 2.F of the full power license. The Fire Protection Evaluation Report (FPER)
assumes that offsite power is unavailable. Therefore, a fire in the service water pipe tunnel, where all 12 flow switches are located, could affect cable essential to all four safe shutdown methods utilizing one or more of the diesel engine The inspectors verified the application of the TCAs during the week of October 5, as well as the subsequent removal of the switch func-tions from the diesel start logic on October 21 (see Detail 9.1).
Following a management meeting held on.0ctober 8 between licensee ,
engineering representatives and NRC Region I personnel to discuss the I technical aspects of the flow switch design in question, NRC Inspec- l tion No. 50-352/87-27 was conducted on October 20 to specifically address the Appendix R concerns for fire protection and safe shutdown capability. The Appendix R discrepancy was discussed in an enforce-ment conference held on October 2 j i
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The inspectors noted that the engineering evaluation of the fire l suppression flow switches which has been an. issue for over two years, (_ centered primarily upon deportability as a construction deficiency l under 10 CFR 50.55 (e) (NRC Unit' 2 Inspection No. 50-353/87-11) but-i also upon the need for a failure modes and effects analysis of the
! design (NRC. Unit-1 Inspection No.. 50-352/85--09). The licensee's engineering management did not thoroughly evaluate the NRC's concerns for diesel -reliability, but rather exhibited a compliance-oriented
! approach'towards the resolution of those concern .
The inspector reviewed proposed changes to fire protection procedures' !
F-D-311A through D used to describe fire protection provisions in the diesel cubicles and adjoining fuel oil / lube oil rooms, as well as to specify fire fighting strategies in those area The changes will highlight shutdown of the diesel engine (if running) from the local control panel. The inspector had no further concerns, and will review the licensee's description of tnis event in LER Numbsr 87-55 in a future inspectio .0 Licensee Reports 5.1 In-Office Review of Licensee Event Reports The inspector reviewed Unit 1 LERs submitted to the NRC Region I office to verify that details of the event were clearly reported, including the accuracy of the description of the cause and the ade-quacy of the corrective action. Where multiple causes are suspect, or may be different than reported in the LER, this is indicated belo The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted on-site followup. The following LERs were reviewed:
LER Number Report Date Cause Subject 87-43 9/28/87 Cognitive error HPCI steam drain resulting in line snubber not incorrect serial visually inspected number in visual test procedure
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.87-44 9/21/87 Communications Failure to check
, failure between RCIC flow l site engineering controller opera-groups resulting
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bility from remote in an inadequate shutdown panel and procedure verify isolation of transfer switches 87-45 10/2/87 Unit 2 load center SGTS and RERS-transformer fault actuation from unknown cause 87-46 10/15/87 Moisture separator Reactor scram from level transmitter turbine trip (stop instrument air valve closure) at supply valves not 83% power upon fully open due to high moisture indeterminant separator level cause 87-47 10/14/87 Brief low Control room concentration of ventilation isola-chlorine in tion and CREFAS intake plenum from initiation by unknown source chlorine detection logic 87-48 10/19/87 Failure of defec- Reactor scram from tive EHC tubing turbine trip (stop socket weld valve closure) due by control to low EHC oil oscillations from pressure at 90%
conversion to power 4 partial-arc I admission 87-49 10/19/87 Cognitive error by Startup of licensed operator recirculation pump failing to compare without verifying coolant and idle vessel-loop piping recirculation loop temperature temperatures differential 87-50 10/19/87 Leak in instrument Secondary contain-air line supply ment isolation and from vibration- SGTS/RERS initia-induced wear of tion on low copper tubing reactor enclosure against clamp differential ,
mounting bolt pressure t
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, 18 87-51 10/22/87 Design deficiency Control room (detector probe ventilation electrolyte im- isolation'and balance) caused CREFAS initiation by rain water on false chlorin detection 87-52 10/22/87 Defective RWCU system differential . isolation valve temperature switch closure during (Riley Co. Model check of non-86 VTFF) regenerative heat exchanaer room temperature LER Nos. 87-46, 47, 48, 51 and 52 were previously addressed in Inspection Report 50-352/87-2 LER Nos. 87-45 and 49 are addressed in Detail 5.2 of this repor LER No. 87-44 is addressed in Inspection Report Nos. 50-352/87-19 and 2 .2 Onsite Followup of Licensee Event Reports For those LERs selected for onsite followup, the inspector verified that the reporting requirements of 10 CFR 50.73 and Technical Speci-fications had been met, that appropriate corrective action had been taken, that the event was appropriately reviewed by the licensee, and that continued operation of the facility was conducted in accordance with Technical Specification limit . LER No.87-045; Unit 2 Transformer Fault The standby gas treatment system (SGTS) initiated on August 30 due to low differential pressure in the reactor enclosure. The cause was a polyphase fault-to ground on Unit 2 load center transformer No. 224A. The transformer was being supplied from the common No. 10 startup bus in order to perform a Unit 2 lube oil flush. The fault caused a voltage drop on the No.101 startup feed to D11 and D13 4 kV safeguard buses. The depressed voltage propagated to the D114 and 0134 480 volt safeguard load i center The momentary voltage dip on the load centers caused the tripping of all rotating equipment fed from the buse '
f Loss of the load centers resulted in trips of the reactor enclosure supply and exhaust fans, which created a low dif- l ferential pressure condition in the secondary containmen l
[ Reactor enclosure dampers were isolated and the SGTS and I l l )
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reactor enclosure recirculation system (RERS) started as designed. . Immediately following the event, the 224A load center transformer was isolated from the bus. The cause.of the isolation was verified and isolations were reset.
b l: The cause of,the Unit 2 load center transformer failure was-unknown as oflthe end of the inspection: period. The trans-
" former was removed and returned to the manufacturer (ITE/ Brown'
Boveri) where it was. unwound and visually examined. Extensive damage: precluded a determination of specific. failure. L A ,
recommendation.was.made by the site field engineering group that the. licensee's corporate electrical engineering organi-zation review the undervoltage trip relay settings on th safeguard load center circuit breaker Based on a prelim-
~inary review,- a time delay is being considered to eliminate future trips. A detailed coordination study of the instan-taneous'undervoltage release devices used to isolate non-class 1E safeguards buses was being prepared at the end of the inspection perio The inspector concluded that while primary protective relays had properly responded, the undervoltage devices internal.to the load center breakers may react too. quickly (less than two cycles) in response to momentary faults on high and medium voltage buses. Discussions with licensee field engineers-indicated that an appropriate time delay.for 4 kV and 13 kV sources would be in excess of five to six cycles, a typical breaker clearing time. The inspector noted that the August 30 event occurred during a Unit I reactor startup, with the generator not yet on-line. This was the. first instance where the Unit 2 transformer number 224A was utilized, and had been energized for 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> prior to the fault. Although not considered to be a problem with respect to primary overcurrent protection or breaker coordination, the potential effect of Unit 2 loads cn Unit 1 operation, or more generally faults originating in offsite power distribution buses affecting Unit I safeguards load centers, needs to be promptly evaluated and corrected. This issue is unresolved (50-352/87-24-02) pending final review by the licensees engineering staf . LER No. 87-49; Startup of Idle Recirculation Loop A licensed operator failed to verify proper temperatures prior to a restart of the "A" recirculation pump on September 19, 1987, during a Unit I startup following a reactor scram. The operator incorrectly interpreted a procedural requirement to be not applicable (and therefore marked that step as "NA").
Shift supervision quickly discovered the operator's error, but calculated the temperature difference (using a reference temperature later found to be incorrect) to be in excess of i
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. 20 the 50 degree Technical Specification limi The licensee subsequently reported the event to the NRC via the ENS as a violation of Technical Specifications and began an investigatio The Unit 1 Technical Specifications require the temperature difference between the reactor coolant in the pressure vessel (i.e. steam dome temperature) and in the idle recirculation loop piping (i.e. pump suction temperature) to be less than or equal to 50 degrees farenheit. Surveillance test procedure (ST)-6-043-390-1, which is used to verify proper loop temperatures prior to recirculation pump restarts, was found to have incteporated an incorrect reference temperature since its originatio The ST had incorrectly specified bottom head temperature rather than steam dome temperatur Upon recalculation for the September 19, 1987 event, the licensee found the temperature differential to be 10 degree A review of all recirculation pump starts since original operation identified one instance on September 16, 1985, where the allowable temperature differential was exceeded. In this case the temperature differential,was calculated to be 98 degrees farenheit. The effect of the increased temperature differential was concluded to have insignificant impact on the fatigue usage factor for Unit I reactor recirculation components including vessel nozzles, piping, valves, recirculation pumps and jet pumps. The components were within the bounding analysis startup event; a 411 degree differential temperature (vessel temperature of 546 degrees and loop temperature of 135 degrees).
The September 16, 1985, startup was concluded by the licensee to be an acceptable one-time event with respect to the margin of design in the reactor vessel thermal cycle diagra The inspector reviewed an engineering evaluation dated October 22, 1987 of the recirculation loop thermal transient that occurred on September 16, 1985 during startup of a recircula-tion pump with both loops idl The inspector verified that appropriate procedural revisions were being incorporated into ST-6-043-390-1. The inspector concluded that no violation would be assessed since: the licensee had discovered and reported the event; corrective actions were timely and extensive; thorough evaluation of the technical significance was performed and found to have insignificant effect on reactor vessel components; and, the error was not a recurrent condition which should have been corrected by previous corrective actio The inspector had no further concerns on this self-identified
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violation (50-352/87-24-03).
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. 21 5.3 Review of Periodic and Special Reports Periodic or special reports submitted by the licensee were' reviewed by the inspector. The reports were reviewed to determine that the report included the required information, that results and/or supporting information were consister;t with design predictions and performance specifications, and whether any information in the report should be classified as an abnormal occurrenc The following reports were reviewed:
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Monthly operating report for September 1987
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PECO letter to NRC (Gallagher to Gallo) dated September 24, 1987; Decertification of Licensed Reactor Operator Following Medical Leave
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PECO letter to NRC (Gallagher to Wenzinger) dated September 18, ---
1987; Interim Status Report of Security Investigation (Allegation No. RI-87-A-0083).
, The inspector had no questions about the reports.
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6.0 Surveillance Testing 6.1 Test Observation The inspector observed the performance of and/or reviewed the results of the following tests:
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ST-6-107-590; Daily Surveillance Log
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ST-3-107-790-1; Control Rod Scram Timing
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ST-5-041-885-1; Weekly Dose Equivalent Iodine-131 Reactor Coolant Concentration Determination
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ST-2-042-607-1; Monthly ECCS and Reactor Level Calibration
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ST-6-092-311-1; Monthly D-11 Diesel Run ST-2-047-611-1; RPS Scram Discharge Volume High Water Level Functional
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ST-2-042-612-1; Division 1 Channel E, ECCS-High Drywell Pressure Test The tests were observed to determine that surveillance procedures conformed to Technical Specification Requirements; testing was being performed in accordance with Administrative Procedures A-43 and 47;
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proper. administrative controls and.tagouts were obtained prior t testing; testing was performed by qualified personnel in accordance with approved procedures and calibrated instrumentation; test data and results were accurate and in accordance with Technical 1 Specifications; and equipment was properly returned to service following testin No unacceptable conditions were note .2 Control Rod Scram Time Data The' inspectors reviewed the.results of data automatically compile by the scram control. rod insertion timing system (SCRITS) following the Unit.1' reactor scram'on September 19, 1987. The SCRITS is continually available and on-line to fulfill the Technical Specification (TS) surveillance requirement of timing 10% of the control rod drives every 120 days. .The data-for all 185 control rods was documented in procedure ST-3-107-790-1, and the data was concluded.to satisfactorily meet 'all rod scram time requirement Average scram times.from fully with' drawn. positions to.four progressively inserted notch positions were within TS limits with-considerable margin. .For the nine control rods not fully withdrawn at the time of the September 19' scram, the SCRITS provided extrapolated' scram time data to perform the averaging calculation All control rod scram times to notch five (90% inserted) were within
.the TS maximum value of seven seconds. Also, all combined two-by-two group average times (a total of 156 combinations discarding the slowest of the four) were within TS limits. . Finally, the slowest control rod was identified to be rod 22-31, with a 90%
insertion time of 4.097 seconds, and is scheduled for scram solenoid valve maintenance at the next available outage. The initial travel of rod 22-31 was slow; a typical diagnosis'of solenoid problem The inspectors discussed the September 19 SCRITS results with responsible reactor engineers, and independently concluded that all ,
control rod scram times were acceptable. No unacceptable findings ]
were identified, j 6.3 RPS/ECCS Testing During witnessing of surveillance testing on October 20 the i inspector observed a number of good practices which contribute to l assuring a high quality test program. The observations were based on performance of I&C technicians, review of test procedure content, q and discussions with the technicians and their supervision. The j tests observed were for reactor protection system (RPS) and j emergency core cooling system (ECCS) instrument J I
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, 23 The technicians work as two-man teams, and have been paired together for a period of I-2 months or more. The test assignments are routinely scheduled well ahead of required dates, and each team is limited to a specific area of testing (eg. one team performed all ECCS functional tests while another was limited to reactor protection system testing). Team assignments are typically rotated on a daily basis, so as not to restrict technician experience solely to one system or type of testing. The licensee also utilizes an "A-day /
B-day" test matrix to prevent full logic actuations. The number of tests during the shift was not so large that rushing or time cons-traints were introduced. Also, control room supervision reviewed the planned tests for this particular shift and, in some cases, deferred certain. testing because of unique plant problems or high risk ( scram potential).
During conduct of the testing, each team exhibited good communication between the main control and auxiliary equipment rooms using headset Control room operators were cognizant of testing underway and expected annunciator status, and promptly acknowledged alarms. In certain cases, a dedicated control room operator is assigned to a particular
. tes The ccrrect test procedure revisions were verified by I&C group supervisors, and test evolutions were discussed with technicians prior to signing in on shift to commence testin Following completion of testing, each team coordinated appropriate independent restoration steps with another team not directly involved in that tes I&C technicians were knowledgeable of proper calibration of test equipment and the bases for successful test result Test connection points were found to be accessibl The technicians were experienced on Unit 1 systems and qualified to Level II (ANSI)
requirements. Technicians stated that the procedures were workable, not confusing and contained " human factors" improvements including bold-type precautions and clear acceptance criteri The inspector concluded that: surveillance testing was well planned and supervised; test personnel were qualified, experienced and cooperative; and that testing the inspector observed was being effectively conducte .0 Maintenance The inspector observed selected maintenance activities on safety related equipment to ascertain that: the work was conducted in accordance with Administrative Procedures A-25, 26 and 27 using approved work instructions or procedures; proper equipment permits and tagging were administratively controlled; craft performing the work were appropriately qualified and supported; and return-to-service of equipment included adequate post-maintenance testing and operational verificatio _
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. 24 7.1 Work Observation Portions of the following work activities were observed or reviewed:
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MRF # 8707175; Excessive Vibration of ' A' SGTS Fan
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MRF # 8707276; Fan Set Screw Torque on 'B' SGTS 7.2 SGTS Fan Bearing Misalignment j On September 24, the "A" standby gas treatment system (SGTS) fan was l
removed from service because of high vibration readings on the moto Preliminary investigations revealed excessive end play of the fan wheel / motor housing and rubbing of the stationary fan vanes.
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The fan wheel had moved on the shaf t enough to strike the stationary vanes. The movement of the fan wheel was the result of a set screw loosening, caused by either improper torquing of the set screw when installed or loosening of the set screws from vibration during start-up balancing of the roto The repair of the fan was performed in accordance with work i instruction number 2251 and under maintenance request form (MRF)
87071175. The original set screws were reinstalled and torqued to 35 foot pounds. Additional set screws were installed on top of the existing screws to provide assurance that movement on the shaft would I
not recur. The additional set screws were approved by maintenance representatives, mechanical engineering, and the equipment manufacturer and were concluded to be a standard acceptable machinist practice that did not constitute a modification since no new holes were drilled.
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During the disassembly, repair and subsequent reassembly of 'A' SGTS fan, the inspector observed that maintenance personnel performing the work were knowledgeable of the work instructions and the methods utilized in performing the work. The inspector also noted QC involvement in monitoring the SGTS fan repair, and that the QC inspector was knowledgeable of his responsibilities and inspection requirement The maintenance department also checked the "B" SGTS fan under MRF 8707276 by performance of an internal inspection and confirmation of set screw torque. No abnormalities were found. The licensee plans to add an additional set of shaft screws for this fan (as on the 'A'
fan) during the next outag No unacceptable conditions were identifie .3 Diesel Engine Fuel Oil Crossover Tubing On September 2, the inspector witnessed the final replacement of the diesel fuel oil crossover tubing, as described in NRC Inspection
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- i 25 Report.No.'352/87-21. .Since the problem was of a generic. nature, the licensee submitted the crossover tubing to the corporate metallurgical laboratory to be analyzed. The failures were-
- concluded to be due to internal diameter erosion or. impingement attack from localized high velocity flow or cavitation. Th licensee provided the'results of the analysis.to Colt Industries,. l
. manufacturers of the diesels, for evaluation and recommendation for '
eliminating.the' proble Colt Industries' preliminary' recommendation was to replace the c_opper tubing with steel piping. The details and specifications on the piping are' expected to be supplied to the licensee in November 1987. Replacement.of the' tubing is being planned for the next
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refuel outag ,
.-No. additional concerns were indentifie '8.0' NRC Information Notices-
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-The following details.are based on followup of generic industry problems or plant. events that;have potential. safety significant concern for the Limerick Unit 1 design. The topics' selected are based on~NRC Information Notices, vendor. technical information letters, generic industry
' experiences and inspector judgemen . Information Notice 87-41, Brown Boveri Breakers The inspector reviewed the breaker opening and closing problems described for 4 kV Brown Boveri Type SHK equipment. The licensee
~had previously reported a deficiency with loose horizontal support bolts for the breaker spring charging motor inla 10 CFR 50.55 (e)
report'to the NRC'on August 24, 1984. The Unit 1 failures occurred during preoperational-testing, after an estimated.several hundred j operations of the breake Insufficient factory assembly torque on ,
the bolts was determined to:be the cause, and all Unit 1 breaker I bolts were inspected, cleaned, coated with Locktite and retorqued to 12 foot pounds. The inspector discussed the reliability of Unit 1 ;
safety-related breakers with responsible field engineers and determined that no failures have occurred since initial Unit I reactor operatio No additional concerns were identifie .2 Information Notice 87-30, GE Motor Brackets The inspector reviewed a safety evaluation prepared by General j Electric Company dated August 10, 1987 to support continued 1 operation of ECCS pump motors utilized in the residual heat removal (RHR) and core spray syste:ns and motors used in the RHR service water and emergency service water (ESW) systems. Large vertical GE motors have experienced through-thickness cracks in surge ring brackets and felt blocking used as part of the motor winding end-turn bracing. These conditions may lead to a reduction in !
insulation resistance and possible motor failure.
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The' licensee inspected lthe affected motors on Unit 1 in August 1987
, .to verify serial numbers and actual restraint design, and compared'
.this:information to that confirmed by GE from original design
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documents. The: surge ring restraint brackets for the Limerick RHR n ' pump mot. ors are~different from the 90-degree bend design susceptible to cracking, and were therefore unaffected. The licensee concluded
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that the ESW motors were not expected to be susceptible because the bracket' design incorporates sufficient' bend-radiu The RHR service water motors were found'to have a tight bend radiu where the.. brackets are welded between the ring and. frame attachment legs and, as;such, could be susceptible to failure. . However, based ,
on a service-life comparison between Limerick and.the plant which
' experienced the motor failures, as well as environmental operating characteristics, the motors were concluded to be reliable for continued Cycle 2. operatio ~
The Limerick' core spray pump motor brackets have tight-radius bend and'are similar to motors which were found to have cracks, The Unit 1 motor windings are. vacuum-impregnated and epoxy-insulated, which tends to make end turns stiffer and'provides extra strength. The core spray motors also incorporate.an internal heater _to reduce
. moisture condensatio Therefore, based upon a 25% shorter service experience and the epoxy. insulation, continued core spray pump motor operation was concluded by the licensee to-be acceptable for Cycle The inspector reviewed the licensee's. safety evaluation dated. August 19, discussed the licensee's plans for future motor insulation inspection and correction (under development as PORC committment 87-0067), and had no further concerns. The program for core spray motor inspection.under development will be-reviewed in future inspection '
8.3 Information Notice 87-04, Degraded Diesel Fuel The inspector verified the completion of modification number 87-5529 for Unit 1 to remove the screen elements from the two strainers on the suction side of the diesel engine-driven fuel pumps and DC motor-driven auxiliary fuel pumps for all four diesels. The modification prevents potential fuel starvation of the diesels due to undetected fouling of the engine screen elements, located between the' day tank and injector The licensee also evaluated the diesel fuel oil sampling and test program for monthly particulate analyses, potential use of biocides and stabilizers in the fuel oil storage tanks, and improved methods to allow for dip-sampling at various tank level {
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E:n -27 The inspector, observed ' diesel engine surveillance. testing.during-the inspection _ period (and since removal of the screens in August'1987),
discussed fuel oil ~ sampling results with the station chemist, and concluded that the modification was appropriate'and has not affected-engine operatio .01 Plant Modifications _
The following modification was eval'uated to assess, in.part: the adequacy of the safety evaluation'; consideration of Technical-
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Specification changes; implementation under Administrative Procedure =
A-14; the status of completion. of physical installation;_. effectiveness of _
modification. acceptance testing; and accurate update of operating _and test; procedures, as-built drawings, and operator training programs. The
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inspector verified that appropriate engineering design support and PORC review and approval.were received; that installation _was in accordance-with procedures, including appropriate QC coverage; and, that an operable system was returned to service with no apparent unreviewed safety question .1 Diesel Fire Suppression Engine Trip Logic
.1 Modification number' 5457 disabled the diesel generator trip logic l initiated.by fire protection system flow by removal of the time delay relay and de-energization of flow switches. associated with the trip of each diese The modification replaced temporary circuit alteration (TCA) 1159 applied on-October 9, 1957, following tne discovery that the flow switches created a potential common mode failure of all four emergency diesels (during other than LOCA.
L operations) coincident with a. fire in the ESW pipe tunne The original purpose of the trip was.for engine protection should a fire system actuation occur while the diesels were running for reasons other than a LOCA start signal. In order to reduce the probability of diesel operation during fire system spray (the trip disabled), operating procedures were modified to direct operators to trip the diesels on fire system initiation in the respective diesel ba The modification removed the phase and neutral leads of cable between the non-safety related flow switches and the common power'
distribution panel 104202 (circuit number 17). The time delay l relays-interfacing between the non-Class 1E switches and the i
safety-related diesel engine start logic were removed from their sockets located in the respective. diesel bay motor control center cubicles 10B515, 516, 517 and 518.of all four engines. The modification was implemented on October 21, 1987, t-The inspector discussed the modification with responsible field engineers, was present during the PORC evaluation of the changes, and witnessed the removal of the relays. The inspector reviewed the safety evaluation of the modification, including proposed FSAR and fire protection evaluation report changes. The licensee has also i i
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! .. 28 committed to a review of diesel engine reliability and availability as a result of a fire suppression system actuation in the diesel cubicles, including the' ability to operate in the presence of water spray and the extent of equipment damage expected. The potential for such damage is minimized by the pre-action sprinkler system design and baffling provided for certain equipmen No unacceptable conditions were note .0 Exit Meeting The NRC resident inspectors discussed the issues in this report throughout the inspection period, and summarized the findings at an exit meeting held with the Station Manager on October 30, 1987. At the meeting, the licensee's representatives indicated that the items discussed in this report did not involve proprietary information. No written inspection material was provided to licensee representatives during the inspection period.
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