IR 05000352/1987021
| ML20236B404 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 10/22/1987 |
| From: | Linville J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20236B380 | List: |
| References | |
| 50-352-87-21, NUDOCS 8710260161 | |
| Download: ML20236B404 (29) | |
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! t U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 87-21 , Docket No.'50-352 . License lNo. NPF-39 i Licensee: Philadelphia Elect,ric Company 2301 Market Street Philadelphia, PA 19101' Facility: LLimerick Generating Station, Unit 1 ' Inspection Period: August 6 - September 22, 1987 i i Inspectors: E. M. Kelly,, Senior Resident Inspector I S. D. Kucharski, Resident Inspector i J. A. Prell, Reactor Engineer - Approved by: und [[,4 / o/zL//7 es Linviltii, Chief 'rojects Section 2A Date / Summary: Routine daytime (165 hours and backshift (46 hours. including weekends) inspections of Unit 1 by the resident inspectors consisting of: . followup.on outstanding items; walkdown of the scram discharge volume and ' the emergency diesel-generators using PRA guidance; plant tours including fire protection 7and security measures; maintenance and surveillance obser-vations; and review of LERs and periodic reports.
Portions of the containment ILRT were observed, as were final activities associated with the first refueling outage which lasted 108 days.
Startup on August 26, from the refueling outage was observed, as were repairs to the HPCI , system.which delayed the'startup.
Events followed up included reactor scrams i on September 7 and 19, and a. recirculation pump trip on September 13.
Various meetings were attended onsite during the period, including routine PORC meet-ings and post-scram reviews.
A Region I team (Inspection 87-19) assessed the readiness for Unit 1 restart from August 17-21.
- No violations were identified. An unresolved item was intiated for evaluatien .. of the bypass of emergency diesel engine protective trips under accident conditions (Detail 9).
Licensee investigations of drug allegations involving security force personnel and other contractor personnel are described in Details 3.2.2.2 and 4.1.respectively.
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.- ,. e i.i p 5/j DETAILS 1.0 Principals Contacted ' y Philadelphia Electric Company i J. Doering, Superintendent of Operations ! R. Dubiel, Senior Health Physicist G. Edwards,_ Technical Engineer , J. Franz, Station Manager ' _ M. Gallagher, Reactor Engineer J. Harding, Field Engineer ~ D. Helwig, Mechanical Engineer J. Sabados, Senior Chemist J. Spencer, Superintendent of Services Also during this inspection period, the inspectors discussed plant status
- and-operations with other supervisors and engineers in the PEC0, Bechtel and' General _ Electric organizations.
-2.0 Followup on Unresolved Items 2.1 (Closed) Unresolved Item 86-09-01; Control of Transient-Material in a Combustible Free Zone The inspector reviewed Revision 2 to Administrative Procedure A-12.2, Control of Combustible Materials.
The procedure was amended to meet commitments by'the licensee that were associated with NRC concerns about storage and/or handling of transient combustibles in 'a combustible free zone (CFZ).. Revision 2 now defines the responsi-bilities of plant personnel., shift supervision and the fire iotection Assistant (FPA) for the control of combustibles in' a , CFZ, and also has a new section in the procedure on CFZ areas in the plant and the methods of control required.
Basd on the ! revision to A-12.2, this item is closed.
2.2 -(Closed) Violation 87-02-01: Fire Watch during Hot Work This item involved the failure of the licensee to post a fire watch-during a grinding operation in the reactor building, and a welding operation in~the Unit 2 turbine building on Unit 1 piping without a i fire extinguisher in the immediate vicinity. The inspector reviewed the licensee's immmediate actions which involved the suspension of both activities and preinstruction of the site personnel in the requirements of procedure A-12, Ignition Source Contro1~ Procedure, and found these to be accep'.able.
The licensee created a fire watch video training program which is now a requirement for Bechtel person-nel who are expected to function as fire watches. Based on the above, this item is closed.
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2.3 (Closed) Violation 87-05-01; As-Built Drawing Control This item involved the licensee's failure to provide the latest revision of Category 1 drawings in the Technical Support Center (TSC) within a suitable amount of time. As-built Category 1 drawings are required to be maintained in the TSC for use during l emergency conditions. When the TSC is activated, these drawings l are used to analyze plant conditions and make operational recommendations to the Control Room personnel.
The licensee immediately updated the TSC with the latest as-built drawings and disciplined the personnel involved in accordance with company policy.
The licensee also revised Administrative Procedure A-6, Control of Drawings, Manual and Drawing Logs, to specify time requirements for updating drawings in the various locations.
This item is considered closed.
2.4 (Closed) Violation 87-09-02; Unattended Combustibles This item invol.- d the discovery of combustible items in a combustible free tone by the inspector during a tour of the Reactor Enclosure on elevation 217.
The licensee responded to the NRC's concern by removing the material within one half hour.
The licensee also increased the routine roving inspections of the power block for the remainder of the outage to assure fire protection compliance, and revised Procedure A-12.2, Control of Combustible Material to include more detailed requirements for the control of work related to combustible materials within a combustible free zone.
This item is therefore closed.
2.5 (Closed) Unresolved Item 87-17-01; LLRT Report NRC Inspection 50-352/87-17 of local leak rate testing (LLRT) conducted during the refueling outage addressed the discovery of a testable 0-ring assembly in penetration X-35B which was not being leak tested as part of procedure ST-1-LLR-281-1.
Penetration X-358 is for traversing incore probe (TIP) instrument gas purge.
Subse-quent investigation of a spare penetration X-35A, thought to be welded shut, also found an untested 0-ring assembly.
Combined leakage found during a retest was less than six sccm which is a minimal contribution to the total allowable limit.
Procedures were revised, X-35A was welded shut, and other spare penetrations were checked and found to be acceptable (i.e. no unknown seals were found).
NRC Inspection 50-352/87-17 concluded that no violation would be proposed, pending issuance of a report by the licensee.
LER No. 87-22 was issued on July 9,1987 to describe this event and associated corrective actions.
Item 87-17-01 was therefore closed.
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-4 y 2.6' (Closed) Unresolved Item 86-27-01; SGTS Tie-In The inspectors rev_tewed the closecut of modification number 614 to. tie-in the refueling floor zone to-the modified standby gas ! treatment sjstem ($GTS).
The modification acceptance test for the
SGTS,' including larger capacity fans and modified ductwork, was completed prior to Unit 1 startup on August 26.
Testing of the . Reactor Enclosure zone (see Detail 6.1) involved performance of procedure ST-6-076-310 for' secondary containment integrity.
Drawdown conditions (time to and stabilization at 0.25 inches i ' vacuum)~were easily met; however, maintaining these conditions at i.
SGTS flow rates of less than.1,250 standard cubic feet per minute . . (scfm) were-initially difficult (300/500 scfm over the Technical Specification limit), primarily due to leaks found on the refuel t ' floor where stop logs or gates associated w':th the equipment cavity and-fuel transfer chute had not been fully sealed. The leaks were . identified and corrected by maintenance personnel to the point where ' the mean flow rates of both SGTS trains were approximately 900-1,000 scfm (with 2-standard deviations of'400 cfm and reistively calm wind i.
conditions of 6-8 mph). Officially' accepted flows a re 1,105 scfm and 1,060 scfm.for the A and B trains, respectively. No unacceptable.
j conditions were identified, and station management was appropriately > involved in resolving the problems.
l 2.7 (Closed) Violation 84-27-04; Conduit Seals The inspector reviewed the completed evaluations and work associated with modification number 685 which sealed instrument conduit in the service water pipe tunnel.
The seals provide high humidity protec-tion for ten instruments and four motor operated valves in the emergency service water system.
The seals were a condition of the Unit 1 full power license, and had been reviewed recently as part of NRC Inspection Report 50-352/87-16.
The inspector discussed PEC0 QA audit report No,1LA-123 with QA representatives, and concluded that the modification, as completed, satisfied License Condition 2(a) of Attachment 1 to NPF-39.
No unacceptable conditions were identified.
3.0 Plant Operations 3.1 Summary of Events Unit I remained in a cold shutdown condition from the beginning ' E of the inspection period until August 26 when a startup was begun.
Post-modification and maintenance acceptance testing were performed, as was repair of HPCI system valve leaks, and the generator was synchronized to the grid and power operation commenced on August 31.
The first refueling outage officially lasted 108 days. A primary containment ILRT was conducted from August 9-13 (Detail 6.3).
During the week of August 17, an NRC team inspection assessed Unit i readi-ness for restart (Detail 3.5).
Following a successful drawdown test ..w . l
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l l of the secondary containment by the newly modified SGTS, startup was ' begun on August 26.
Startup was delayed for repair of a HPCI steam supply valve (Detail 7.2).
Power ascention continued from September 1-7 to 83% power at which time a reactor scram following a turbine trip occurred (Detail 4.6).
The turbine trip'was a result of high water level in moisture separator 102 caused by an isolated instrument air supply to the drain and dump valve level controls.
Reactor startup was approved on September 8, special testing of moisture separator level controls was performed at 25% power, and the unit achieved full power by , September'14.
' A recirculation pump trip occurred on September 13 during l surveillance testing of the redundant reactivity control system (RRCS) logic-(Detail 4.7), and a faulty load driver circuit board was identified as the cause and subsequently replaced.
Full power operation continued through September 19 until an electrohydraulic l control'(EHC) system weld on the number 3 main turbine control valve l ruptured, causing a turbine trip and reactor scram (Detail 4.8).
The weld failure was determined to have been caused by EHC piping vibration of a defective weld joint.
EHC weld repairs were completed and startup was begun on September 20. The unit was held at 83% - power for the rest of the inspection period pending resolution of the EHC vibration problem.
3.2 Operational Safety Verification 3.2.1 Control Room Activities The-inspectors toured the control room frequently to verify proper manning, access control, adherence to approved i procedures and compliance with technical specifications.
The inspectors reviewed shift superintendent, control room super- ' vision, and licensed operator logs and records covering the i entire inspection period.
On August 6, 27, 29, and September 3 and 16, the backshif t inspections were between the hours of 2:00 am and 6:00 am.
The inspectors reviewed logs and records for completeness, abnormal conditions, and significant operating changes and trends. Other records reviewed included: Reactor Engineering and STA books, night orders, radiation work permits, the locked valve log, maintenance request forms, temporary circuit altera-tions, and ignition source control checklists.
The inspectors l also observed shift turnovers during the period.
Operations ' activities were observed for conformance with Administrative Procedure A 7.
No unacceptable conditions were noted.
The inspectors observed startup activities following completion of the refueling outage.
The inspectors attended sessions of PORC Meeting No. 87-088 to review prerequisites to changing _a l l,.- '. -
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i ! l { reactor conditions from Operational Condition 2 (Startup) to l Condition 1 (Power Operation).
The inspectors independently i verified satisfactory resolution of outstanding surveillance,
maintenance, modifications (including license conditions and i commitments), and equipment blocking permits. All annunciated l . alarm conditions were verified as either expected or accept-able prior.to reactor _startup.
3.2.2 Security l 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.
j badging were all 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 _,t . -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 turnovers.
i 3.2.2.1 ' Sleeping Guard On August 8, a security guard was found sleeping inside a vital area by another security guard. _The guard was posted at a control structure ventilation duct that did not have two security barriers, but did have one barrier and an alarm.
The event was deter-mined to be not reportable because it did not involve a potential for undetected access.
Site access for the guard was pulled and the individual was terminated.
3.2.2.2 Random Drug Testaan i Based upon a confidential allegation received by the > licensee alleging marijuana use by security force members, a random group of ten guards was submitted to a gas mass-chromatography test on September 3.
Test results were negative for nine of the 10 tested; one person tested positive for methamphetamine and was' terminated on September 4.
An additional employee of Protection Technology,.Inc. (PTI), the security.
contractor, refused to submit to the testing and was terminated on September 3.
The NRC resident inspec-I tors were apprised of the allegation on September 4 . ' and of the test results on September 9.
The licensee ~. instituted a program of random drug testing of the guard force at the end of the inspection period.
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{Lq ' < , , 'first randomly selected group of 15 were tested on-September 23 and all results were negative. Addi-tional testing is planned by the licensee, i 3.2.3 Radiological-Controis-The~ inspectors observed the availability and use of radiation L 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.
i work. permits (RWPs) were selectively reviewed to determine that appropriate job controls, protective clothing, dosimetry and HP support were prescribed,. in use, and understood by - workers' involved.
- Radiological controls for the moisture separator and conden-ser area were assessed as part of review of RWP-001-87-034-B.
Proper surveys and contamination clothing were prescribed.
! Radiological'. conditions were discussed with HP technicians and workers who signed-up under the RWP.
Proper locked high radiation area controls, including appropriate and frequent surveys, were verified to be employed in accordance'with HP procedure 203, Startup Surveillance Procedure.
The inspector had no further concerns, and identified no violations.
3.3 Station Tours-The-inspectors toured accessible areas of the plant throughout the inspection period, including: the Unit 1 reactor and turbine-auxiliary enclosures, the main control and auxiliary equipment rooms; battery, emergency switchgear and cable spreading' rooms; . and the plant site perimeter.
During these tours, observations were made of potential fire hazards, radiological conditions, housekeeping,' tagging of equipment, ongoing maintenance and sur-veillance, and the availability of required equipment.
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unacceptable conditions were identified.
The inspector noted that rolling stock throughout the plant had been evaluated for its potential effect on safety related equipment and, 'for example, 4kV ground trucks used to move replacement breakers have had their wheels pinned to prevent unwanted movement. However, during a plant tour on. September 17, several ground trucks were improperly located close to a DC distribution panel in a 4kV bus , room.
The Superintendent of Operations issued memoranda dated 9/18 and 9/23 to all operating personnel and the training coordinator, -respectively, regarding proper adherence to administrative plant housekeeping procedures for temporary and moveable equipment storage in the plant.
The ground trucks were immediately relocated to a i - - _ _ - - _ _ - _ _ - _ - _ _ _ _ - - - - _. _ ~
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. (: ' = distance of at least two feet away from the panel, and were sub-sequently removed-from~the area.
A short lesson plan for licensed i: and non-licensed operators addressing storage of such equipment is being planned for inclusion in.requalification training. No similar instances were identified through the end of the inspection period.
' The inspector had no further concerns, and identified no violations.
-3.4.
Systems Walkdowns L 3.4'1 Engineered Safeguards Features Verification . The inspector performed a detailed.walkdown of the scram discharge instrument volume in. order-to independently verify control rod drive scram operability.-. The walkdown of.both the . east and' West volume banks included the following: -- Review of Technical Specification 3/4.1.3, FSAR Section' o 4.6.1.2.4, System Operating Procedures, P&ID M-47, and-j ! Licensed Operator Training Plan-0070.
-. Inspection of scram discharge volume equipment conditions' ~ -- System check-off list _S47.1.B and operating procedures consistent with plant drawings -- Valving and switches properly aligned including appropriate locking devices -- Instrumentation properly valved-in and operable, and proper scram valve instrument air header pressure at 70-75 psig.
-- Satisfactory status of control room indicators and controls -- Surveillance test procedures ST-2-047-200, 602, 603 and 612-615 appropriately completed ~at required intervals.
l \\ Within the scope of the inspection, no unacceptable conditions were noted.
Proper operation of scram discharge volume vent and drain valves was also verified as followup to the September 7 and 19 reactor: scram events.
l ! 3.4.2 PRA-Based System Inspections 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 - > _ _ _ _ _ _ _ -. _ _
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i 'to theirnimportance to risk, The_ study incorporates abbre-l .viated system' checklists which contain components that are , . considered to have a high contribution to risk as determined ' in the PRA.
, 3.4.2.1 Electrical Power-f -The inspector verified the proper. configuration of ~{ the following AC/DC electrical power system compo-
nents on several occasions during the inspection ' period: -- power available to the four 4 kV AC buses power available to the four 440V AC buses -- power-available to the four 125/250V DC buses -- -,all diesel generator alarms cleared ' power available from 220 kV and 550 kV offsite -- . -sources-diesel Local / Remote selector switch in Remote- -- ' ventilation fan switches in auto / standby -- governor oil level (sight glass) satisfactory --'
air receiver tank pressure at 225-250 psig ! -- fuel oil day tank level satisfactory -- - -ESW discharge valve 11-1005 throttled open and < w-locked -- closed output breakers at each battery charger (six total), and supply breakers closed as follows: Div 1 From MCC 10B211ZA to 1BCA1 From MCC 108211ZA to 1BCA2 Div II From MCC 108212ZB to 1BCB1 , From MCC 108212ZB to 1BCB2 j j No unacceptable conditions were noted.
3.4.2.2 Drywell Equipment . Prior to reactor startup, the inspectors entered the Unit 1 drywell on August 25 and verified the proper i configuration of the following normally inaccessible manual valves: ,
- ' standby liquid control system manual injection ' maintenance valve, 48-1F036; open and locked r automatic depressurization system (ADS) nitrogen -- supply isolation valves, 59-1018E, H, K, M, and S; open x__-___---__-
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RCIC isola- ! tion valve HV-49-1F007 was closed on August.25 but' ! was subsequently op'ened at 100.psig reactor pressure as the RCIC system was made operable.
3.5 Restart-Team Inspection An NRC team assessed Unit I readiness for restart from the refueling outage as part of. Inspection 50-352/87-19 conducted during August 17-21.
Based.upon the. team's' findings' preliminarily presented to the licensee on August 21,. the inspectors's subsequently. verified (during Inspection 87-21) that commitments prior to restart on August 26.were accomplished.
These included the following issues.
3.5.1 Scaffold. Removal A walkdown of all reactor enclosure, control enclosure and ! emergency diesel cubicle-scaffold, which either had a
potential to affect adjacent equipment or was unnecessarily H l= erected, would be modified or removed. The licensee.identi-i . fled approximately 17 scaffolds which wereLremoved and nine scaffolds which were modified (ie either side-braced or moved ' .at least six inches away from adjacent equipment). Addition-ally,'all scaffold in the-drywell'and suppression l pool were verified to be removed prior to startup.
3.5.2 Remote Shutdown Panel Testing Procedure ST-1-088-320-1 to test _the operability of the remote shutdown panel (RSP) was revised to include a test of the RCIC-flow controller, a test of the barometric. condensate vacuum pump contacts, and.a check of isolation of all RSP transfer switch contacts from main control room circuitry.
Visual
verification of the open state of the transfer switch contacts was perfromed on August 22. Operability of the RCIC flow controller from the RSP was satisfactorily performed on ' ~ August 22 and the RCIC barometric condensate vacuum pump l contacts were successfully tested on September 17.
The- ) licensee expects to permanently revise procedure ST-1-088-l 320-1_by October 31.
The inspector reviewed the completed ! test procedures, discussed the results with responsible test l engineering supervision, and will review the licensee's i evalustion-of the RSP test discrepancies in LER No. 87-44 (issued on September 21,1987) in future NRC inspections.
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3.5.3 Outstanding TCA's ! PORC meeting 87-087 was convened on' August 22 to review , -outstanding temporary circuit' alterations (TCA's) to.. ensure ' that appropriate safety evaluations were completed and still
. valid, and that no unreviewed safety questions existed.
The licensee employed a shift technical advisor (STA) and a senior reactor operator-licensed engineer to re-evaluate the total-193- ! outstanding TCA's in order to independently assess the need for R , PORC review in'accordance with Administrative Procedure'A-42 governing TCA approval.
' s A subtotal of 113 were originally identified as not requiring i PORC review (101 were associated with nonsafety-related: systems
and 12.with Unit 2)..However, 23 TCA's originally found to not-
require PORC review did,'in fact, require review as determined ! 1by the.STA/SRO re-evaluation. These included radwaste systems l changes and computer'(ERFDS) sample points.
In addition, there , were 56 TCA's which originally received PORC review.
This ! .resulted in a set of 79 TCA's which were selected for further PORC evaluation.
- The PORC concluded that none of TCA's involved an unreviewed l safety question. A number'of comments were generated related to 10. specific TCA's.
The inspector reviewed those comments
.as part_of the published minutes from PORC meeting 87-087,- discussed the adequacy of existing TCA_ safety evaluations ]i with' station' management, and identified no immediate safety ! concerns.
The inspector discussed TCA No. 170 with the j station. manager which defeats automatic opening of the main.
' steam line bypass leakage barrier vent valves, because of the upstream drain valves which isolate on a lower level signal.
The inspector concluded that, while the condition of TCA No.
170 was acceptable, a modification should be implemented to convert the TCA-(present since initial operation) to a per-manent design feature.
j ! The inspector noted that, as of.the end of the inspection j period, the-licensee had held several meetings with engineer-ing representatives.to develop a program to convert TCA's to permanent plant modifications, including appropriate procedural and drawing changes, operator training and post-modification < testing.
Y 4.0- 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 - ef forts to identify cause and propose effective corrective action, and L verification of proper system design response.
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4.1 Allegation RI-87-A-0083; Drug Use by Radwaste Workers The NRC.was notified anonymously on July 17 of alleged drug use by l contract radwaste workers. A July 27 letter to the licensee from the i NRC requested a report on the subsequent investigation conducted by j lisensee corporate security investigators.
In a September 18 letter from PECO to the NRC, an interim status. report was provided.
Due to i the } confidential nature of the ongoing investigation by the licensee, ! the. details'of the investigation are being witheid from this inspec-l tion report.
NRC representatives have been periodically kept app-rised of the results.of the PECO investigation which was still ' l ongoing at the en'd of. the inspection period. As of that date, 13 contractors had been either tested for drugs or had refused to submit to.a urinanalysis. test. All 13 contractors had Unit 1. protected area access denied on. August 25. The NRC will be up-dated.on pertinent developments as'the investigation continues.
4;2 Division--4 LOCA Signal ! During the performance of surveillance test ST-2-042-839-1 on August 18, an I&C technician inadvertently opened an instrument process ') valve instead of the calibration valve, causing a pressure transient in the sensing line.
The sensing line is shared with two Division 4 LOCA signal transmitters.
The 014 diesel generator and 'D' core spray pump auto-started, as designed, but no injection occurred.
The 'O' RHR pump was-in service for shutdown cooling. All other systems responded correctly. Operators verified that all the automatic actuations occurred, and the initiating signal was verified to have been caused by the technician's error.
All equipment was verified by the inspector to be restored to normal status.
4.3 No. 10 Startup Bus Fault On August 30, a Unit 2 load center transformer experienced a multi phase fault to ground causing the feeder breaker to trip on time-overcurrent protection.
The fault current on the No. 10 startup bus caused a voltage drop on the startup feed to the Unit 1 011 and D13 safeguards buses, and a Unit 1 motor control center trip occurred. A group VI A and B (containment atmosphere control) isolation signal actuated, and the standby gas treatment and reactor enclosure recirculation system initiated.
Following isolation of the faulted transformer, the isolation signal was reset and the HVAC systems were-returned to normal.
The inspector verified proper system response, and will follow the licensee's investigation as ' reported in LER 87-045.
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4.4 Scram on Moisture Separator High Level A reactor scram from 83% power occurred on September 7 following a turbine trip caused by high water level in moisture separator number 1C2.
The cause of the high level was found to be the air supply valves to the IC2 moisture separator drain tank drain and dump level transmitters which were in a partially closed condition.
The Hal-function of the control systems permitted moisture separator water level to increase to the turbine trip setpoint, tripping the turbine and producing a reactor scram.
l The cause of the event was closed redundant air supply valves to the level transmitters. Air supplies to the other fire moisture separators were verified to be properly aligned, and a special test of the IC2 moisture separator level controls was satisfactorily completed on September 9 at 25% power.
The inspector reviewed the completed version of procedure GP-18, Scram Review Procedure, including recorder traces, sequence-of-events and post-trip logs, and ERF05 computer printouts.
The inspector determined that: proper notifications were made, including an ENS call and declara-tion of 'an Unusual Event; appropriate emergency operating procedures were employed; no discrepancies from expected automatic actuations were experienced, particularly for reactor protection and RRCS logic response; and, that measured control rod scram times were all in accordance with technical specification limits.
The licensee's PORC initiated a sub-committee investigation of the event and m'et to review the sub-committee conclusions. The PORC concluded that no aspect of the scram would impact safety system function, but that a remote potential may exist for impacting balance of plant operations. Unit 1 P&ID M-15 displays the instrument air system in 15 sheets.
No checkoff list of th2 instrument air system has been ever developed. Actions were taken to solicit the development of adequate P&ID's via an engineering request EPE number 1123.
The operability of automatic control systems had been considered as sufficient evidence to indicate the presence of an adequate air supply in past licensee experience.
Further, the licensee's design philosophy of safety systems is such that loss of air resulted in completion of the safety action in the associated device and, therefore, was not an immediate safety concern.
However, the September 7 scram indicated the existance of at least one scenario where the normal air supply was insufficient.
The liccisee could not determine when the valve was isolate Fr~ :p p .. ,o i i z.
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-, . -The licensee initiated a complete walkdown of all accessible inst-rument air valving on September 14.
The system engineer, utilizing-the current P&ID's, checked valve positions (irrespective of whether or not the valves have a designation number or appear on a checkoff list).. The walkdown was documented by using a master set of P&ID's - and noting the valve conditions. At the end of the walkdown of the accessible portions, the results are planned to be reviewed by Station ' Management to determine the probability of a future instrument air supply valve mispositioning event. As of the end of the inspection period,. approximately_ one-half (or 1,000 valves) of the system had .i been walked down, with 8 drain valves found open (but capped) and an < air supply to the steam jet air ejector found closed. No safety related1 systems were.found to be affected, including the air supplies used to-normally position the MSIVs.
While the licensee could not determine that the closed moisture separator instrument air supply valve was an isolated event, it was' determined that.the incidence of a closed air supply valve, in conjunction with a control function that would operate abnormally, was highly unlikely.
Further, it was considered very unlikely that a combination would exist which would produce initially normal results, then abnormal results, as occurred on September 7.
The licensee also reviewed other plant systems to ascertain whether a condition similar to that (ie no checkoff list) for instrument air existed.
That review concluded that the problem was limited to the < instrument air system.
The long term resolution of the instrument h - air alignment problem (involving more detailed P&ID's) was discussed in the PORC sub-committee minutes. When more detailed P&ID's for system M-15 have been developed, instrument air checkoff lists will be generated which will be given-appropriate implementation by ' operations personnel.
The inspector had no further concerns.
4.5 Recirculation Pump Trip An 'A' recirculation pump trip occurred on September 13 from 95% power.
The trip was caused when a surveillance test was being conducted for the 'A' logic of the redundant reactivity contro) , system (RRCS). An apparently spurious signal at the output of an RRCS load driver card caused closure of the 'B' logic contacts. This
resulted in opening of the ATWS breaker to the 'A' recirculation pump._ Reactor power was automatically reduced to 65% by the pump , . trip, and further reduced by operators to 45% to correct flow l imbalances prior to restarting the pump.
The 'A' pump was restarted within 45 minutes, and all systems were determined to function properly. A courtesy information call was made to the NRC at 11:30 a.m., and full power was subsequently reached on September 14 j following the licensee's investigation.
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! l The inspector discussed the cause of the logic failure with I&C engineers, and determined that the RRCS had operated properly and l that continued operability was justified.
The faulty load driver l card was replaced, satisfactorily tested, and both logic channels were verified to be properly responding on September 15. The in- ! ! spector also ascertained that I&C technicians performing test ST-2-042-637 had properly followed the procedure and were cognizant of the abnormal response following the card failure.
The inspector
had no further questions.
4.6 Chlorine Detector Response On September 14 the '0' channel chlorine detector exceeded its set- ~ point of 0.42 ppm.
This caused an auto initiation cf the control room emergency fresh air system. At the same time, the 'C' channel chlorine detector indication increased to.25 ppm.
I&C and chemistry.
j personnel were notified to investigated the problem.
Subsequently, ! both indications decreased below the set points without corrective action and the isolation was reset. At the time the plant was operating at 100% power, and all systems functioned as designed.
The resident inspectors followed up on the licensee's investigation (see Detail 5.2.2).
4.7 Scram Caused by EHC Tube Rupture A reactor scram occurred on September 19 from 90% power due to a turbine trip caused by a loss of electrohydraulic control (EHC) oil to the turbine control valves. A leak had been discovered two hours earlier from one-inch stainless steel EHC tubing for the number 3 turbine control valve, and a reactor shutdown from full power was commenced at 8:30 am.
The tubing ruptured at 9:10 am near a socket weld fitting shortly after licensee personnel visually examined the weld to prepare for repairs. An Unusual Event was declared at 9:15 am and later terminated at 2:43 pm due to reactor decay heat and pressure control concerns resulting from the loss of EHC-controlled components.
The loss of control of the turbine bypass valves required HPCI and RCIC to be utilized in the full-flow test mode to the condensate l storage tank (CST) for pressure control. A complication arose when the "B" recirculation pump was restarted before reducing the temperature differential between the reactor vessel.and the "A" recirculation loop to less than 50 degrees Farenheit.
Licensee engineering evaluation of the pump restart with an 85 degree differential concluded that no adverse effects due to thermal shock l on recirculation system nozzles occurred, i m.__._____ . _. _ _ _ _. __ _ -
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r a - I The ruptured EHC tubing was repaired, and the.EHC system was retested ~ satisfactorily.
Reactor startup was begun on September 20. The new ~ 'EHC~ tubing was monitored for vibration, and the failed tubing was-metallurgically examined. Metallurgical analysis indicated an cirregular lack'of penetratio. by approximately 27% (40 mils) at the i root of the socket weld, and fatigue propagation to approximately I one-half the ' width of the'150' 111 weld towards'the heat affected - zone of the tubing; The tubing material is one-inch diameter, 0.086-inch thick Type 304' stainless steel. The licensee installed vibration sensors and accelerometers to trend vibration levels at the EHC failure location, but preliminary engineering evaluations have determined the tubing movement to be within acceptable levels.. Closed ! circuit television monitoring of the repaired tubing is also being . ' conducted. Three similar EHC connections to the turbine control valves were visually examined and dye-penetrant tested satisfactorily.
' A turbine modification performed during the refueling outage for partial arc admission steam control may have exacerbated the tubing vibrations'and stress which are thought to have contributed to the , ' September 19 failure.
The licensee's investigation of-the recir-culating-pump restart' and EHC vibration was being followed by the resident inspector ~at the end of the inspection period.
! ! 5.0 Licensee' Reports ! t 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, l including the accuracy of the description of the cause and the . adequacy of the corrective action. Where multiple causes are suspect, or_may be different than reported in the LER, this is indicated below.
, Th'e 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 87-32 7/24/87 Deficient Missing neutron installation fluence wire specification dosimetry 87-33 7/31/87 Component False high failure chlorine concentration signal 87-34 8/14/87 Design Pressure setpoint drift of main steam safety relief valves u __ n _
- _ _ -. _ i . . 17' ) ! 87-35 8/17/87 Personnel Unplanned error initiation of the , Nuclear Steam Supply Shutoff System , ! 87-36 8/21/87 Personnel error Operation of the l plant in a condition prohibited by the technical specifications 87-37 8/21/87 Personnel error Unplanned inboard
isolation of the i Nuclear Steam
Supply Shutoff l System ' 87-38 9/1/87 Personnel error Nuclear Steam Supply Shutoff , System isolations 87-39 8/31/87 Personnel error Operation of the plant in a condition ' prohibited by the technical specifications 87-40 9/3/87 Component failure Faulty wire connection 87-41 9/4/87 Component failure Partial Nuclear Steam Supply Shutoff System isolation 87-42 9/17/87 Personnel error Unplanned ' actuation of Engineered Safety-Features l LER Nos. 87-34 and 35 were previously addressed in Inspection Report 50-352/87-18, i LER No. 87-42 is addressed in Detail 4.2, Nos. 87-32, 33, 36, and ' 39 in Detail 5.2; and LER No. 87-41 in detail 8.0 of this report.
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, , ..... i h ' 18-L l . d' 5.2 Onsite Followup of Licensee Eve,nt@ orts For those LERsiselecO d for onsite: followup, the inspector. verified
thatithe reporti_ng rdquireeents of 10 CFR 50.73 and Technical Speci-
fications had.been mer., that' appropriate corrective action had been - taken,' that'~the-event was' appropriately reviewed by the licensee, and. . 'I .that continued operation of facility was conducted in-accordance with
Technical SpecificationLlimits.
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5.2.1 (ER No. 87-32; Missing Neutron Fluence Wire st On June 12, 1987, Maintenance personnel attempted to remove. _. ' the in vessel neutron fluence wire specimen dosimetry from its sample holder.
The neutron fluence wire specimen.is used to predict'the neutron embrittlement of the vessel wall since irradiation will cause an increase in Reference Temperature-' ' Nil Ductil_e Transition (RTNDT).which determines the' point at.
g which the ductility of the material is lost.. The sample.
_ holder was=found in its designated location at the vessel- - wall,'but the. neutron fluen4e wire dosimeter was not inside the holder assembly'nor couldtit be located in the vessel by underwater camera inspection.
Based on further investigation by the licensee it was deternCned that reactor pressure vessel
installation specifications did not include the dosimetry- ' device as part of the-reactor material surveillance program, and'it is believed there' fore that the dosimeter ~was-never installed during reactor pressure vessel assembly prior to; y initial startup.
However, the licensee confirmed that ' neutron fluence wire specimens were in place in the' remaining sample holders.
~ For the' case where it is-assumed that the dosimter was irntalled and became detached inside the reactor vessel, the licen:;ee performed a lost part analysis to address the adverse safety consequences.
The following concerns ware .eva luated: -- the potential for fuel bundle blockage and subsequent fuel damage - the potential for controlirad interference -- the potential for corrosion or other chemical reaction with reactor materials and were determined not to>be a safety concern.
Finally, the licensee prepared a safety evaluation concerning
safety issues raised by the absence of the neutron dosimeter.
The evaluation discussed the significance of the lack of neutron fluence data for the first fuel cycle and was . E _i_^___..______i__ _
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1 . determined based on similar plant life histories at other facilities:not to be a concern based on similar operating . experiences between Limerick and the other plants.
The. absence.of the-first cycle dosimeter does not impair the
- ability of the material surveillance program to meet the requirements of.10 CFR 50, Appendix H, which require the
- removal;and. testing of the first surveillance capsule after ten effective full-power years of operations.
No violations were identified.
' 5.2.2 ' LER No. '87-033; Chlorine Isolation The inspectors reviewed the events surrounding an isolation of main-control room ventilation and initiation of the emergency fresh air supply (CREFAS) system on July 1 caused by a defec-tive solder connection with the "C" detector channel cable connecting the probe and local processi.ng unit. The inspector verified that all systems responded as designed, and that - control room operators properly diagnosed.the isolation and indicated. conditions as spurious.
The Unit I reactor core Lwas completely offloaded'at the time of the event, and control room ventil.ation remained isoleted.with CREFAS operating until July.17.when the defective' cable was replaced.
The inspector discussed the proposed corrective action with station management for this commonly occurring problem-of spurious chlorine detector trip signals.
LER No. 87-33 referred to a modification to the CREFAS logic to avoid the potential for. ventilation isolations caused by single. failures such as occurred on_ July 1.
The modification will include the existing channel A and B detectors in a coincidence logic with the C and D detectors, and is scheduled to be. completed by December 1987. -The A and B detectors. utilize tapes manu-factured by MDA Scientific and are currently removed from CREFAS initiation logic and alarm circuits via TCA No. 246
installed on March 21, 1987. While channels A and B provide , indication only, channels C and D utilized an electrolytic probe made by Anacon and when either channel exceeds the 0.42 ppm chlorine concentration setpoint an event such as occurred on July I will occur, i There have been 27 previous events caused by breakage of the MDA-type tapes, and seven events caused by malfunctions
associated with the Anacon probes, particularly with respect-to'a sensitivity to moisture. The inspector discussed the , July 1 isolation and a more recent isolation on September 14 H (see Detail 4,6) with station management at the conclusion of lL the inspection, and expressed a concern about the proper pri-L 'oritization of the modification to the chlorine detector logic.
Although the July 1 isolation was the first chlorine event n _ _ - --
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sinceMarch6(LERNo.87-009)andwasnotrepeatedagafu/ until September 14, previous NRQ inspection review tif 55urious chlorine events in 1987 recorted in Inspection 50-352/87-09 (Detail 5.2.2) had concluded that management's attention was being directed towardn&' solution to these recurrent chlorine 0502 apparently he/sevir, progrqs on modification',riumber design problems.
H not proptergd significantly due ir,part t to refueling outage priorit!P3 AJdif Jonal concerns Mye been f identified at the end of tfyd 'inuset'ioit period with respqct to: / J ( > -- operator response to c orine alaras;, particularly when both C and D channels respond i , - proper adherence to special event procedure SE-2, Toxic ' Gas, pspecially the use of self-contained breathing i )I am,aratus within two minutes of annunciation.
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-- appropriate entry into eraergency procedure EP-101, and , consideration of classifying a site emergency, when the determination has been made that the signale, are not spurious or that/an actual chlorine release or threat
exists.
d ' The Superintend)rt cf Cperations issued a memorandum on o . ., ' ' September 23, 1987 to shift supervision which emphysized '
proper consideration of the above required actions'3sen i ' valid chlorine alarms are being verified, so as not to develop 4, casual attitude towards chlorine alarms simply because a large number rc;eived to date have been spurious and not representative oM a real threat.
The inspector discussed these issues with licensed shift supervision at o-the e;J of the inspdetion period anf concluded that proper sensitivity,to the alarm still elitts 6 in spite of.the regular occurrence of spurious signals anULthu well known sensitivity of the probes tp moisture (i.e. during rains torms).
Operators were appropriately aware of emergency plan' classification levels and, fn fact, were utilizing an Appendix ti/ procedure EP-330 to initiate chemistry field checks for actual presence of chlorine gas in the control hstructure intake plenum.
The inspector had no further concerns and identified no violations.
f ' E.2.3 LER No. 87-036; RHR Service Water Grab Sample l The inspector reviewed the details associated with a 30-minute late sample of RHR service water (RHRSW) that occurred on July 22. The sample was required every eight f hours because of the inoperability of an RHRSW radiation
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I monitor. The root ~cause was poor communications , , .'between chemistry' technicians during. shift turnover, since .
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.the previous sample.had been actually taken=30 minutes j ' . earlier than-scheduled. 'The' samples taken prior to and lj w after-this event were both below the monitor's lower limit ' of detection and the '!B" RHRSW heat exchanger was 'not' in , - service at the time, so that the safety significance of-the error was min.imal. Unit 1:was in a refueling: outage at the time the' sample was missed, with the core reloaded and reactor vessel; reassembly underway. The inspector discussed 'the event with chemistry personnel and concluded <that a notice of violation of Technical' Specifications would not be. issued because: , -- The licensee had discovered'the error-and promptly i + corrected it, and reported it in.LER No. 87-036.
-- The event had min.imal safety significance.
!
- -- Poor communications among chemistry technicians has not been a recurrent problem to date, i-The inspector had no further questions, i '5.2.4. LER No. 87-039;-Late RECW Grab Sample.
On-July 31, 1987, a chemistry technician failed to take a j grab sample from the React 3r Enclosure Cooling Water l(RECW); system within the-required time period.
Technical !
- specifications required taking a grab sample of-the RECW system every 24 hours whenever the' RECW radiation monitor-
- is inoperable.
The monitor was declared inoperable on
June 24,' 1987-and samples were taken within the required time period up until the one missed. On August 1,'1987, the same technician noticed that the grab sample had not been taken on'the previous day, and took a sample immediately.
Sample readings prior to and after the one missed were analyzed and determined to have radioactivity levels which were less than the lower limit of detection.
The inspector reviewed the licensee's corrective action -) involving' counseling the responsible technician and all
shift chemistry technicians to the importance of sampling on time and of proper communication during turnover.
The , < I %
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The inspector discussed the event with chemistry personnel and concluded that a notice of violation of Technical Specifications would not be issued because: -- The licensee had discovered the error and promptly corrected it, and reported it in LER No. 87-036.
-- The event had minimal safety significance.
-- Poor communications among chemistry technicians has not been a recurrent problem to date.
The inspector had no further questions.
5.2.5 LER No. 85-102 (Revision 2); Drywell Spray Isolation Valve Repair The inspector reviewed Revision 2 to LER No. 85-102 which described the final successful repairs to RHR valve HV-51-1F016A completed during the refueling outage. Maintenance and LLRT for the valve were reviewed and reported in NRC Inspection 50-352/87-13, Detail 2.4.
The valve had been inoperable since December 18, 1985 when excessive leakage ! was discovered during LLRT.
Valve disassembly during the { outage led to the discovery of excess material buildup on the underside of the valve wedge and body guides, preventing l proper contact sealing.
Minor amounts of corrosion products-l were postulated to have originated in RHR piping and were poscibly swept into the valve seat area by the keep-fill j system during valve surveillance stroke-testing. Also, the piping space between the inboard and outboard isolation valves (16A and 21A) is drained following the stroke tests, allowing for additional gradual corrosion buildup.
Historical LLRT . results for the 16A valve are consistent with the above theory.
' The inspector considered the supplemental reports and con-
tinued evaluation of the original 16A valve test failure to be an excellent example of an LER wherein root cause and correc-tive action are thoroughly pursued to resolution.
LER No.
85-102 has been the subject of a number of important safety issues (eg, operability and risk of containment spray systems not limited by Technical Specifications) and technical concerns (eg. Limitorgue hydraulic lockup phenomena.
LER No. 85-102, Revision 2, also included a sketch of the valve wedge areas affected and is a useful practice for future LER reviews).
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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 test results and/or , supporting information were consistent with design predictions and i performance specifications, and whether any information in the report should be classified as an abnormal occurrence.
The following reports were reviewed: Monthly operating reports for July and August 1987 _ -- PEC0 response dated August 27, 1987 to NRC Inspection Report -- No. 50-352/87-13; Refuel Platform Troubleshooting Controls -- Amendment No. 7 to the Technical Specifications, dated August 14, 1987; Core Reload for Cycle 2 Operation -- Semi Annual Effluent Release Report No. 6 (January through June 1987), dated August 31, 1987.
The inspector had no questions about the reports.
6.0 Surveillance Testing 6.1 Test Observation The inspector observed the performance of and/or reviewed the results of the following tests: ST-6-107-590; Daily Surveillance Log -- ST-1-076-310-1; SGTS Reactor Enclosure Secondary Containment -- Integrity Test ST-1-060-490-1; Containment Integrated Leak Rate Test (CILRT) -- -- ST-3-107-750-1; Control Rod Scram Timing -- ST-6-107-875-1; Shutdown Margin Determination ST-6-107-884-1; Neutron Monitoring System Overlap Verification -- on Startup ST-6-050-760-1; ADS Valve Exercising Test -- l _ _ - _ - -
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y ST-6-049-230-1; RCIC Pump Test ' -- I , . ST-6-049-320-1; RCIC Operability Verification j --- i ST-6-055-230-l'; HPCI Pump, Valve, and Flow Test ! -- ! ST-1-055-800-1; HPCI Response Time -- ST-2-074-600 thru 603; SRM Functional Tests j -- -- ST-2-074-412-1; APRM Channel A Calibration.
! The tests were observed to determine that surveillance procedures conformed to_ Technical Specification Requirements; proper administrative controls and tagouts were obtained prior to 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 Specifications; and equipment was properly returned to service ..! following testing.
No. unacceptable conditions were noted.
, -6.2 Containment ILRT
- The primary containment integrated leak rate test (ILRT) was begun j
on, August 11 but temporarily halted because of excessive off-scale ' leakage. The as-found condition had been previously classified as a
failure.as reported in LER 87-018.
The ILRT was officially held at 44,0 psig for eight houss from 5:00 am to 1:00 pm on August 13.
. Successful test results were' subsequently verified to be obtained by ! both the mass point (0.1312% per day) and total time (0.1619% per day) methods with 95% statistical-confidence. The results were-within the Technical Specifications limit of 0.75 % or 0.375% free.
containment air volume (by weight) leakage per day.
The CILRT was successfully conducted in August 1984 prior to fuel load and { power operation.
The CILRT was also witnessed as part of NRC l Inspection Report 50-352/87-22. A final test report is due to be ! submitted to the NRC within 90 days of the test, and will be ! reviewed in future NRC inspections.
No unacceptable conditions ! -were noted.
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7.0 Maintenance The-inspector observed selected maintenance activities on safety related I equipment to ascertain that: the work was conducted in accordance with
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, approved procedures; proper equipment permits and tagging were adminis-tratively controlled; craft performing the work were appropriately qualified and supported; and return-to-service of equipment included adequate post maintenance testing and operational verification.
7.1 Work Observation Portions of the following work activities were observed or reviewed:
-- MRF # 8706595; HPCI Main steam supply outboard Primary Containment Isolation Valve (PCIV) packing gland plug repair -- MRF # 8706547; HPCI Steam Supply Valve Seal Repair MRF # 87-06426; Replacement of Generator End Fuel Crosspipe ' -- Assembly 7.2 HPCI Steam Supply Valve Seal On August 26, 1987 during the performance of ST-6-055-200-1, HPCI Valve Test, Rev 2 which demonstrates the operability of HPCI, a leak developed in the HPCI steam supply valve.
The test was terminated and reactor pressure was maintained below 50 psig during the performance of the repair work.
The inspector observed parts of the disassembly, inspection and reassembly of HV-055-1F003.
The inspector noted that special instructions for the work were written by the maintenance engineer and prior to the performance of the special work instructions upper management reviewed the procedures with the personnel involved.
During the inspection process the following were noted: The under side of the bonnet retraining ring was not flush and -- was heavily rusted.
Two of the four segment gasket retaining rings were not -- horizontally true. The segmented piece of the retaining ring was twisted.
. Based on the lack of wear the seal ring apparently never -- made contact with the mating surface on the bonnet.
Based on the damage found, it was concluded when the valve was last assembled, the cap screws were torqued but that the sealing surfaces were compressed because the twisted segmented rings were really under compression by the cap screws.
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- P . 26 ~ During'the reassembly of the valve it was noted'by the inspector-that the licensee had extreme difficulty keeping the segmented gaskets in place.while installing the operator because of'the ~i vertical orientation of the valve.
The' licensee overcame this ' b difficulty by applying 'a leak repair compound to. hold the gasket in L place during the assembly of the valve.
The inspector had no ' further questions, and identified no violations.
' 7.3 Diesel Fuel Oil Crossover Tubing Since' plant startup in 1985, the Limerick diesel generators have
developed pin hole leaks-in the fuel oil line crossover piece at the ' generator end of the engine, by the No. 12 cylinder.
The licensee has determined that the failures are due to internal diameter- '. initiated erosion from localized high-velocity flow or cavitation.
Failures occurred in similar locations on the D-14 diesel generator 'in February 1986' and on the 0-13 diesel generator in March 1987.
During.the past outage, the fuel oil line in the D-12 diesel generator was replaced and.a metallurgical analysis was performed. The analysis showed that 2/3 of the wall thickness of the fuel line was gone.
On, September 2, 1987 the inspector witnessed the replacement of the fuelloil line for.the D-11 diesel generator. The line'was replaced ,per Work Instruction (WI) 2160.
The' maintenance personnel ' t performing.the work were knowledgeable of the procedure'and the methods.in performing the maintenance activity. The inspector also
noted QC' involvement in monitoring the maintenance activities, o The QC inspector was knowledgeable of his responsibilities and the 'l requirements ~of.the. work package.
The licensee is still evaluating l , long term corrective action for the problem which the inspectors will review during a subsequent inspection. No unacceptable ~ . conditions were~ide'ntified.
7.4 ' Grease Lubrication PM Program ! ' Administrative Procedure A-25.1, Rev 2, Preventive Maintenance (PM) l Program, defines the responsibilities for the PM lubrication ! program.
The Operations Department has responsibility for performing all grease lubrications of plant equipment. The Cf.nMPS PM database is used to establish the frequency and schedule for PM
activities.
Each month the Operations Department receives a PM schedule from the Plant Staff Maintenance Group.
For'each Q-listed piece of equipment requiring grease lubrication the Operations Department has developed non-PORC approved greasing procedures.
Included in these procedures are pictures of the equipment which i clearly show the grease drain and input ports, and information about l l'r the type of grease to use, which ports to open and how long to run i the equipment, if appropriate. When the grease relubrication is [
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! I completed,.the operator signs, the CHAMPS PM schedule for that item and notes any discrepancies.
Towards the end of the month the Technical Assistant reviews the schedule and identifies any PMs missed. This i information is transmitted back to the Plant Staff Maintenance Group ! which then reschedules the item (s).
A review of the September CHAMPS PM lubrication schedule was made and an inspection of the following equipment requiring grease lubrication was performed: Joy Exhaust Fans, HPCI Pump, Standby Liquid Control Pump, Fuel Pool Booster Pump, Damper Bearings, and Clean up Demineralized Pump. No problem with overgreasing was ' identified and housekeeping was acceptable.
Discussions were held with operations personnel, maintenance per-sonnel, and the maintenance engineer regarding problems associated with overgreasing bearings.
Three basic problems were identified: 1.
overgreasing bearings causes a " churning" action of bearings which causes them to overheat and seize; 2.
overgreasing can cause +!a bearing to be hydraulically forced out of position, thus mis-positioning the rotor and causing it to come in contact with stator windings; and 3.
overgreasing can cause grease to get on the stator windings which will add a " thermal blanket" between the windings and the cooling air. This will cause the motor to run hotter thus shortening its life due to insulation breakdown.
The grease will also allow dust and dirt particles to accumulate and stick on the
windings which will eventually lead to insulation breakdown, 8.0 Plant Modifications The following modifications were evaluated to assess, in part, the-details and adequacy of the safety evaluation; proper consideration of Technical 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 inspector verified that appropriate engineering design support and PORC review and approval were received; that Construction Division installation was in accordance with ERDP procedures including appropriate QC coverage and with a minimal effect on plant operations; and, that an operable system was returned to service with no apparent unreviewed safety questions. Within the scope of this inspection, no violations were identified.
8.1 RHR Service Waste Radiation Monitors Modification No. 689 proposed replacement of the RHR service water radiation monitors with dynamically qualified monitors by the first - - _ _ _
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i i , refueling l outage.
The existing monitors utilized-during Cycle 1 'I operation were log count rate meters ~, but the vendor was unable to furnish' seismic qualification records for the electronics portion of the monitors. ~ Justification for' Cycle.1 use of the unqualified ~units was. documentated-in Supplement 3-to The Limerick Safety Eval- ~ uation Report.
However, Modification No. 689 was later proposed to replace the' existing meters with functionally identica1' units that are a prototype' product'line manufactured by NUMAC Co., and seismically and dynamically qualified.
. ] The-implementation'of Modification No. 689 was unsuccessful during the refueling outage as numerous hardware and software failures were experienced during acceptance testing.
These included circuit board.
failures, wiring deficiencies and other problems resulting in four
returns to the vendor-for rework. Because the newer unit's ! reliability could not be demonstrated, the' licensee submitted a i request to -the NRC on July = 31,1987 'for continued operation during Cycle' 2 'with the original monitors. An NRC safety evaluation was issued on August 7 that found the use of the original non-seismically l qualified-log rate count meters acceptable for Cycle 2.
l The. inspector reviewed the safety evaluation for the replacement of I the' monitors, discussed the difficulties encountered in implementing
Modification No. 689 with station management, and observed proper
. operation of the reinstalled meters.
' The inspector 'also evaluated the justification for continued operation and identified no concerns. The NRC safety evaluation concluded no need to seismically qualify the monitors (since they serve no design basis function) and the recommendation to reassess ,
the unique design feature of the monitors of automatically isolating 'RHR service water and. tripping RHRSW pumps (i.e., automatic termin- ! ation of shutdown cooling).
The inspector noted that RHR heat , exchangers are not typically in-service at. power, and that stringent water chemistry controls are employed on both the tube (spray pond / service water)'and shell (reactor coolant) sides of the exchanger.
l No unacceptable conditions were noted.
9.0 Region I Temporary Instruction 87-04 The inspector reviewed the licensee's design for bypass of diesel generator protective trips.
Diesel logic currently allows for a protective ' trip of an engine under all running conditions except an emergency start (ie LOCA signal from core spray logic).
The protective trips are active in dead bus starts (ie loss of off site power) and the trips include high jacket water and lube oil temperatures and low pressures as well as a fire water suppression header flow (inferring a fire in that diesel's cubicle). The protective trips are developed in a two out of three logic, as recommended in NRC Regulatory Guide 1.9.
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The inspector questioned the following: t -- the risk associated with not bypassing protective engine trips in a ' dead bus condition tha Denefit of a fire protection flow switch trip versus the risk of -- it; interface with Class 1E diesel circuits These items are unresolved, and will be further developed and followed in a future inspection (50-352/87-21-01).
10.0 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 Superintendent of Operaitons, Mr. Jay Doering, on September 16, 1987 and again verbally with the Station Manager, Mr. John Frar,z on September 23, 1987. At the meeting, the licensee's representatives indicated that the items discussed in this report did not involve pro-prietary information.
No written inspection material was provided to licensee representatives during the inspection period.
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