IR 05000387/1985021
| ML17139D116 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 08/14/1985 |
| From: | Jacobs R, Plisco L, Strosnider J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17139D113 | List: |
| References | |
| 50-387-85-21, 50-388-85-17, IEB-83-03, IEB-83-3, IEIN-83-75, NUDOCS 8508220173 | |
| Download: ML17139D116 (39) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION Report Nos.
50-387/85-21 50-388/85-17 License Nos.
NPF-14 NPF-22 2 North Ninth Street Facility Name:
Inspection At:
Salem Townshi Penns lvania F
Inspection Conducted:
June
1985 Jul
1985 Inspectors:
R.
H. Jacobs, Senior Resident nspector L.
R. Plisco, Resident Inspect I
Approved By:
J. Strosnider, Chief Reactor Projec s
Section 1C, DRP L
8508220i73 850816-PDR ADOCK 05000387 Q
REGION I
Docket Nos.
50-387 CAT C
50-388 CAT C
Licensee:
Penns lvania Power and Li ht Com an Allentown Penns 1 vania 18101 Sus uehanna Steam Electric Station
~F/t date
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date
~rb date Ins ection Summar
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7 h'f plant operations, licensee events, open items, surveillance, maintenance, IE Bulletins, Information Notices, and ESF Walkdown.
Results:
Unit
RCIC topaz inverter fuse problem has still not been corrected (Detail 1. 17);
ESF walkdown of the Unit 1 Standby Liquid Control System identified only minor discrepancies (Detail 2.3); Maintenance on reactor'~
protection system relays did not consider response time testing (Detail 5.2);
Allegation concerning lack of QC involvement in the Unit 1 refueling outage was not substantiated (Detail 8.0).
One violation was identified concerning not locking closed a manual containment isolation valve (Detail 2.2).
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DETAILS 1. 0 Fo 1 1 owu on Previous In s ection Items 1.1 1.2 Closed Ins ector Fol 1 owu Item 387/84-14-02:
RCIC Turbine l
On many occasions in 1983 and 1984, the Unit 1 RCIC turbine tripped on overspeed during surveillance testing and on automatic actuations.
The licensee implemented various corrective actions to reduce 'the frequency of overspeed trips although they had difficulty determining the root cause of the problem.
The licensee later determined from discussions with Woodward Governor Co. that the EGR governor used with the RCIC turbine was obsol'ete.
The current EGR includes a modified pilot valve and pilot valve bushing which allows quicker porting of oil to the RCIC control valve.
This allows the RCIC control valve to position faster
~to minimize the intial speed peak on startup.
By Work Authorization S43094 dated May 17, 1984, the updated EGR was installed in Unit
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This appears to have corrected the RCIC overspeeding pr'oblem.
Closed Ins ector Followu Item 387/84-38-06
- Nitro en Inertin Line Over ressurization ki In December 1984, the Unit 1 nitrogen inerting line was overpressur-ized while preparing to inert the Unit 1 containment.
The incident occurred due to the nitrogen truck vendor starting nitrogen (N2) flow before the plant was lined up to receive it.
Contributing causes to the incident were the operators not having positive control of",the evolution and inadequate relief protection on the inerting line.
As a result of the incident, the operability of the containment purge valves could not be assured and the licensee deactivated and kept the outboard containment purge valves closed until the first refueling outage.
II The licensee's corrective actions were described in LER 84-48.,
The internals of the 24-inch purge valves, HV-15722 and HV-15723, have been replaced under PMR 83-189 with upgraded components in order to meet commitments for purge valve qualifications.
The 18-inch valves, HV-15724 and HV-15725, have been refurbished.
Nineteen welds in the inerting line were ultrasonic tested with satisfactory results.~,
Based on these actions, the purge valves are considered operabl,e.
The licensee fabricated a spoolpiece which includes a manual isola-tion valve, pressure and temperature indication and a blowout disk for overpressure protection.
The spoolpiece is connected to the nitrogen connection as part of the inerting lineup.
The operat'ing procedures, OP-173-001 and OP-273-001, were revised to specify that a
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PP&L operator shut the manual isolation valve if pressure rises to 80
'psig.
A modification to install permanent relief protection on the non-safety related inerting line is approved for a future outage.
Closed Violation 387/82-39-01
- Failure to Control ualit
-,"
Related Com uter Software In 1982, the inspector determined that a computer software quality assurance (QA) listing ("C" list) for all computer software which performs a quality-related function did not exist.
The licensee has since established a "C" list in accordance with Nuclear Department Instruction NDI-QA-8.2. 1.
The "C" list contains software program modules used to process variables which are used to meet technical specification surveillance requirements, as wel,l as other quality software.
Since most program modules which process these variables are non-quality, some aspects of the QA program are applied to these program modules'he inspector reviewed
"C" list Revision 1 dated July 16, 1984.
The inspector noted that computer modules for the G.E. core monitoring programs, Rod Worth Minimizer and the Suppression Pool Temperature Monitoring System (SPOTMOS) were not included in the "C" list.'he licensee indicated that these modules were not included because PP&L does not modify software in these programs; only the vendor modifies this software.
The inspector had no further concerns.
Closed Ins ector Followu Item 387/83-29-04
4KV Breaker Cell Switch Problems In January 1984, the 1D Diesel Generator breaker 1A20404 did not open when the incoming feeder breaker for offsite power was closed during restoration from a test.
The problem was due to misadjustment of the cell switch in the breaker cubicle.
The licensee determined that the actuator shaft for this cell switch was slightly longer than the shaft of cell switches in other 4KV breakers.
The licensee replaced the cell switch of the breaker, and inspected other safety-related 4KV breakers on both units for similar problems.
None were found.
The inspector examined SOOR 1-84-032, NCR 84-159, NCR 84-170, and Work Authorization S40746 and had no further concerns.
Closed Ins ector Followu Item 387/84-22-01 388/84-28-01:
i, Technical S ecification Problem with ADS Technical S ecifications In June 1984, the inspector determined that the Technical Specifications did not permit surveillance testing of the ADS without entering an Action Statement which requires plant shutdown.
In addition, the Technical Specifications reflected an incorrect
number of minimum operable channels per trip system for the core spray and RHR pump discharge pressure permissives and the ADS drywell bypass timer.
1.6 By letter dated January 31, 1985, the licensee requested modifica-tions to the Technical Specifications (TS) for Units 1 and 2 to correct the above discrepancies and include Technical Specifications for the new manual inhibit switch.
On May 14, 1985, the NRC issued Amendment No.
44 to the Unit 2 TS and Amendment No.
11 to the;Unit
TS to correct the above discrepancies.
The licensee is now permitted to place a channel in an inoperable status for up to two hours, to permit testing without placing the associated instrument in the tripped condition.
This is similar to the requirements for other ECCS logic systems.
A discrepancy still exists in the ADS Technical Specifications in that the Technical Specifications permit no
'ut-of-service time if one channel is lost.
This is more restrictive than the TS for other ECCS logic systems and the licensee intends to pursue obtaining relief from this Technical Specification at a later date.
Since this discrepancy is conservative, no inspector followup is necessary.
Closed Violation 387/83-03-03
- Failure to Make Re ort on Standb Gas Treatment S stem SGTS Ino erabi lit In March 1983, both trains of SGTS were inoperable and the licensee failed to make a one hour report as required by 10 CFR 50.72(a)(6).
The licensee conducted training on reporting requirements to desig-nated Supervisory personnel.
Since that time,
CFR 50.72 and
CFR 50.73 have been revised to implement standard reporting require-ments.
AD-gA-424, Incident Reporting, implements the above require-ments and reportabi lity determinations are reviewed at daily management meetings.
No further instances of failing to make 50.72 reports have been noted.
1.7 Closed Violation 387/83-14-01
- Main Turbine Tri B
assed Technical S ecification Violation In June 1983, the 1'icensee discovered that the high reactor water level main turbine trip had been bypassed since May 1983.
A Special Inspection (50-387/83-14)
was performed and an enforcement conference held.
The cause of the event was inadequate review of system status prior to changing Operational Conditions or declaring a system
'perable and inadequate control of system bypasses.
The licensee's violation response dated August 25, 1983 committed to modifying Administrative Directive (AD) AD-gA-302, System Status and Equipment Control, and AD-gA-307, Electrical and Mechanical Bypass Control, to strengthen the administrative controls over system status and bypasses.
Specifically, AD-gA-302 was revised to require reviews
of the system status files for each system prior to declaring the system operable or changing Operational Conditions.
AD-gA-307 was revised to require determining which TS Limiting Conditions for Operations (LCOs) apply (or may apply in a different Operational Condition)
on the Bypass Form and Bypass Log, and to require Section Head approval of all bypasses.
Training on the incident and the new procedure changes was also conducted.
The inspector verified.that the above changes had been included in AD-gA-302 and 307.
To prevent further violations in this area, the licensee also committed to perform an integrated review of work management practices as they pertain to operational impacts.
The licensee contracted with NPR Associates to perform this task.
Followup on recommendations from NPR's study have been incorporated in PP&L's Operations Enhancement Program which also includes a
number of, the recommendations in other areas from reviews by INPO, IMPELL Corporation and the Nuclear Safety Assessment Groups I's a result of the above actions and other operational incidents, the licensee performs a much more thorough review of system status prior to changing Operational Conditions and control of system bypasses has improved.
Closed Violation 387/83-29-06 388/83-32-03
- Standb Gas Treatment S stem 0 eration Durin the Cold Functional Test During Unit 2 preoperational testing, from January
24, 1984, the Standby Gas Treatment System (SGTS)
was not operated in accordance with the Cold Functional Test Procedure P200. 1B and, when repeatedly actuated as prescribed by the procedure, the SGTS malfunctioned at least seven times due to SGTS fan tripping and no action was taken by the licensee to promptly correct the condition.
After discussions with the Test Director, a Test Change Notice,was issued to delete the steps requiring the system to be lined up in accordance with the operating procedure.
The SGTS anomalies that were observed during the P200 testing were investigated by the
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licensee and were found to be due to modifications which were in progress on the system.
The system was fully tested following, completion of the modifications and the system was declared operable after review by PORC.
The proper and designed operation of the', SGTS was not part of the acceptance criteria for the P200 test, and the system was not required to be operable since Unit 1 was shutdown and Unit 2 was not yet licensed.
The inspectors witnessed other tests during the startup test program and similar occurrences were not observe.9 Closed Ins ector Fol lowu Item 387/83-12-03:
Valve Indication Problems and TCN to 0 erational Procedure Had Not Been Im lemented In Hay 1983 the inspector found that a Temporary Change Notice (TCN)
to an operational procedure, which added eight additional valves to the check-off list, had not been implemented by operations personnel.
Additionally, during a walkdown of the Unit 1 Core Spray system, several valve position indication problems were identified.
The inspector reviewed completed Work Authorizations (WA) S-31715 and 31716 which corrected the local valve indication problems.'dditionally, the inspector reviewed Operations Instruction OI-AD-002, Revision 8, Operational Procedure Control, which now requires operations personnel to perform any additional valve lineups required by procedure changes to COL's within 2 days of issuance.
1.10 Closed Ins ector Fol'1owu Item 387/83-31-01 388/83-31-01 Procedures Need to be Revised to Define 0 erators Interface with SPDS In December 1983, an inspector identified that the licensee had not developed written instructions to define the operators interface with the newly installed Safety Parameter Display System (SPDS).
The management philosophy for the operators'nterface with the SPDS had been presented to the operators in the licensed operator requalification training program.
The inspector reviewed Administrative Procedure AD-gA-300, Revision 6, Conduct of Operations, which incorporated administrative controls on the use of the SPDS.
Section 6.4.3 of the procedure states that SPDS is to be used to overview plant parameters as an aid and is not to be solely relied upon for decisions effecting safe operation of the plant.
1. 11 Closed Ins ector Followu Item 387/83-03-04
- Verif Im lementat'ion of FSAR Chan e
Re uest Revise Incorrect Drawin In January 1983, the inspector identified that the Recirculation Pump trip logic, described on Figure 7.2-1, sheet 4 of the FSAR, was not in agreement with the as-built configuration.
The inspector reviewed the current revision of the FSAR and verified implementation of the drawing revision to Figure 7.2-1, sheet III
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1.12 Closed Unresolved Item 387/83-11-04:
Submittal and A
roval of a Chan e to Technical S ecifications to Re uire H draulic Testin of Containment Penetrations X-210 X-215 and X-217 In May 1984, the inspector identified that the licensee should submit a change to the Unit 1 Technical Specifications (TS) to require hydraulic testing of penetrations X-210, X-215 and X-217.
The Unit
TS indicated that type "C" local leak rate testing [at these penetrations should be performed pneumatically.
However, the licensee performed hydraulic tests since the penetration lines were normally water sealed'ydraulic testing appeared appropriate'or these water sealed penetrations, in accordance with 10 CFR 50,,
Appendix J.
The licensee submitted Proposed Amendment 39 to the NRC on Mayi 4, 1984 (PLA-2192) to revise the leak rate testing requirements.
" The Technical Specification change was approved and issued in license Amendment 36, dated April 12, 1985.
1.13 Closed Licensee Identified Item 388/84-08-02
- Cavitation of Jet Pum s Durin IHSI Pro ram A Region I specialist reviewed the final report, GE Report NEDC-30267 (Proprietary)
"Susquehanna Unit 2 Jet Pump Cavitation Vibration Measurements" dated September 1983 and concurred with the conclusion that the cavitation occurrences did not reduce the design life of the affected components.
1.14 Closed Violation 387/83-21-01
- Diesel Generator Tri Not Lo ed in D/G Start Lo As Re uired In September 1983, the inspector identified that a non-valid failure of a diesel generator had not been recorded in the Start Log as required by operations instruction OI-24-002.
In February 1984, the Diesel Start Log was found to have inaccurate and unclear information, making it difficult to assess diesel surveillance test performance, and operating history.
(See Inspection Report 50-387/84-07).
In both cases the errors identified were corrected immediately.',
Licensee management has reemphasized the importance of accurate and complete data recorded in the log and has revised the instruction to include clearer instructions.
Inspector monitoring of the Diesel Start Log since the instruction revisions have found that the entries are now more complete, an'd no deficient or incomplete entries have been identifie C'u F
gl.15 Closed Ins ector Followu Item 388/84-28-02:
Core S ra Isolation Si nal not er Technical S ecifications LER 84-26 Licensee Event Report (LER)84-026 documented that the isolati'on signals to the Core Spray Full Flow Test Valves were not as specified in Technical Specification 3.6.3-1 and FSAR Table 6 '-12.
The Technical Specification and FSAR required the valves to isolate on low reactor vessel level or high drywell pressure.
The as-built condition isolated the valves on low reactor vessel level or high drywell pressure with a low reactor pressure permissive signal.
Plant Modification PMR 84-3086 changed the isolation signal to,the valves so that the reactor pressure permissive signal was deleted.
The inspector verified completion of the modification package.~',
1. 16 Closed Ins ector Followu Item 387/84-35-01:
Followu on Licensee Actions Re uired B
CAL 84-18 Confirmatory Action Letter (CAL) 84-18 was issued by NRC Region I on October 17, 1984 which described the corrective actions that the licensee had taken or planned to take with respect to scram pilot solenoid valve failures that occurred on Unit 1.
The licensee's corrective actions were reviewed in NRC Inspection Reports 50-387/84-34, 84-35 and 85-09.
Based on the information provided in the licensee responses, and resident inspector review, the licensee corrective actions described in CAL have been completed.
jl 1. 17 0 en Unresolved 387/83-19-03
- Inade uate Mana ement Control'f a Known Plant Deficienc LER 83-036 and 83-153 In March 1983, the licensee reported that a
Amp fuse providi,ng power to the RCIC Topaz Inverter had blown.
The inverter suppl~ies power to RCIC instrumentation and speed control circuitry at the'emote shutdown panel.
LER 83-036, dated March 24, 1983 and anl update dated August 10, 1983 discussed four occurrences over a five month period where the fuse was found to be blown.
The inspect'or discussed the LER with the plant staff and stated that it appeared to be an example where inadequate management control of a known'lant deficiency had resulted in a relatively simple problem not being corrected for approximately six months.
Since August 1983, the fuse has been found blown an additional four times, the last being February 7, 1985.
The inspector reviewed~,'the LERs associated with the 1983 events and the Significant Operating Occurrence Reports (SOOR) for the 1984 and 1985 events.
This specific event,'s no longer reportable under the revised reporting requirements.
The review was performed to determine if the licensee's corrective action has been implemented and will prec1ude repet,itio The immediate corrective action by the licensee included replacing the 10 Amp fast-blow fuse with a
Amp slow-blow fuse (BUSSMAN type FNM-10) under Work Authorization S39601, and installing a recorder on the circuit.
Additionally, the inverter power indicating light was added to the shiftly rounds of the Reactor Building operator.
LER 83-036 stated that'
plant modification was in progress to replace the 10 Amp fuse with a 20 Amp fuse based on a vendor recommendation.
The update to the LER, dated August 10, 1983,"
stated that recorders had been installed in the circuitry to monitor the operating characteristics and environmental conditions, an'd to record dynamic parameters of the circuit during any repeat occurrences.
The data was to be used in determining the cause and corrective actions The use of the
Amp fuse was not approved by NPE since the circuit had not been tested sufficiently to just'ify its use.
LER 83-153, dated December 2,
1983, stated that the recorders
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installed in the circuits discussed in LER 83-036, were removed prior to the fifth occurrence, and a
new plan for monitoring the circuit was being evaluated.
The update to the LER, dated March 20, 1984, stated that the monitored parameters were found to be within normal ranges and no further action was required, since the slow-blow fuse appeared to have corrected the problem.
On March 24, 1984 the fuse blew again during a
RCIC quick start surveillance and current spikes were observed on the recorder.
The spikes appeared to be due to the cycling of a relay, which is in parallel with the inverter input.
The licensee then decided to develop a test procedure to analyze the functioning of the circuit during steady state and transient conditions.
On June 4,
1984 the fuse was found blown again during the performance of operator rounds.
The special test procedure, TP-150-003, RCIC Topaz Inverter Test, was performed three days
'ater.
The results of the test were then sent to NPE to be analyzed.
Investigation also determined that a capacitor network was installed across the input of the Unit 2 inverter, and it has not experienced any blown fuse problems.
Analysis of the test,~'data was performed by NPE and a report was issued June 18, 1984.
Th'
report recommended that a 0. 1 microfarad ceramic capacitor be installed on the input to the inverter, a revised bias diode be, applied to the KX relay coil to suppress transients, and to send copies of the recorded waveforms to the inverter manufacturer for evaluation.
On November 30, 1984 an Engineering Work Request (EWR) was subm'itted to NPE requesting a modification to the circuit.
The EWR was returned stating a modification request should be submitted.
On January 8,
1985 site Request for Modification (RfM)85-024 was
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submitted by the plant staff to install a voltage suppression device across the input to the inverter.
The RFM was approved as 85-0114
. but was subsequently cancelled since the modification category was changed.
It currently is designated RFM 85-0212 and is proposed for completion in 1986.
On February 7,
1985 the inverter was foun'd deenergized due to another blown fuse.
The SOOR package states that the resolution and action to prevent recurrence will be completed upon performance of the filter modification.
As of July 28, 1985 the circuit has not been modified and a modifi-cation package has not been approved.
This deficiency was reviewed in Inspection Reports 50-387/83-19 and 50-387/84-26, and in both cases the inspector found that the licensee has not vigorously",
pursued resolution of this problem.
Eight occurrences have been identified over a two year period.
Three of the ocurrences took place after the fuse was replaced with a slow-blow type.
It appears that although a great deal of effort has been expended in identifying and evaluating the def'iciency, little corrective action took place after the recommendations were made.
This item remains unresolved pending completion of the circuit modification.
1.18 Closed Unresolved Item 388/84-34-27
- Resolve Recorder Pen Color Differences in Control Room Recorders Identified in Loss of AC Power Event Licensee Action Item No. 2-84-04-37 from the Unit 2 Loss of AC Power Event of July 26, 1984 required resolution of the recorder pen 'color differences in the control room.
A plant modification was proposed to resolve the pen color discrepancies for reactor level and reactor pressure.
Plant Modification (PMR)83-064, which was completed during the Unit 1 first refueling outage, corrected the pen color differences on recorder LR/PR 14201A.
The inspector reviewed the PMR package and observed the modified recorder.
2.0 Review of Plant 0 erations 2.1 0 erational Safet Verification The inspector toured the control room daily to verify proper manning, access control, adherence to approved procedures, and compliance with LCOs.
During entry to and egress from the protected area, the, inspector observed access control, security boundary integrity, search activities, escorting and badging, and availability of radia-tion monitoring equipmen The inspector reviewed shift supervisor, plant control operator, and nuclear plant operator logs covering the entire inspection period.
Sampling reviews were made of tagging requests, night orders,,the bypass log and QA nonconformance reports.
The inspector observed several shift turnovers during the period.
The operations activities observed were performed in accordance with the applicable procedures and requirements and found acceptable.
2.2 Station Tours The inspector toured accessible areas of the plant including the control room, relay rooms, switchgear rooms, cable spreading rooms, penetration areas, reactor and turbine buildings, security control center, diesel generator building, ESSM pumphouse, plant perimeter and containment.
During these tours, observations were made relative to equipment condition, fire hazards, fire protection',
adherence to procedure's, radiological controls and conditions, housekeeping, security, tagging of equipment, ongoing maintenance and surveillance and availability of redundant equipment.
On July 9, in the Unit 2 Reactor Building, the inspector noted that RCIC valve 249F055, a 1-inch manual LLRT test valve which is a',
containment isolation valve, was closed but not locked.
AD-QA-302 Section 6. 1.3 specifies that manual containment isolation valves (including LLRT test valves) will be locked.
The inspector reviewed the Unit 2 RCIC and HPCI checkoff lists'and (COL-OP-250-001-2 and COL-OP-252-001-2),
P&IDs M2149 and 2152, and FSAR Table 6.2-22 and checked the actual positions of several other manual containment valves in these systems.
No other manual containment isolation valves were found to be unlocked.
However, the following minor discrepancies were noted:
Unit 2 RCIC valves 249F032, 249F058, and 249008 and Unit 2 HPCI valve 255F044, are identified as containment isolation valves in the COL and have containment tags on the valves, but they are not locked.
It appears that these valves are not actually con-tainment isolation valves since they are outside the containment isolation boundary.
Hence, they would not be required to 'be locked.
However, they are improperly labeled as containment isolation valves.
Unit 2 RCIC valve 249F041 is a manual containment isolation valve, but is not indicated in the COL as required to be locked closed.
The valve is actually locked close rl'
In Inspection Report 387/84-14 dated May 22, 1984, the NRC issued a
Notice of Violation (NOV) for not locking closed manual LLRT test valves which are containment isolation valves, on Unit 1.
In 'their response to the NOV dated June 22, 1984, the licensee stated that remaining containment penetrations would be reviewed and discrepan-cies corrected by December 31, 1984.
Although only one valve "(i.e.
RCIC valve 249F055)
was found to be not locked as required, this condition should have been corrected by the above action.
Not locking closed RCIC valve 249F055 is a violation of AD-QA-302.
(388/85-17-01)
In response to the inspector's concern, the licensee modified the COL and locked 249F055.
In addition, a review of all containment penetrations has been initiated to correct discrepancies with manual containment isolation valves.
2.3 ESF S stem Walkdown - Standb Li uid Control S stem On July 25, 1985, ity of the Unit
complete walkdown engineered safety following:
the inspector independently verified the operabil-Standby Liquid Control System by performing a
of the accessible portions of the system.
The feature system status verification included the Confirmation that the system check-off list and operating procedure are consistent with the plant drawings and as-built configuration, Identification of equipment conditions and items that might degrade performance, Inspection of breaker and instrumentation cabinet interiors, Verification that the surveillance procedures adequately implement the Technical Specification surveillance requirement, Verification of properly valved in and functioning instrumentation, Verification that system valves, breakers, and switches properly aligned, and appropriate valves are locked.
The following references were utilized during this review:
ar'
FSAR Section 7.4. 1. 2 Technical Specification 3. 1.5 OP-153-001, Revision 2, Standby Liquid Control System
gl 4],
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i P&ID M-148; Standby Liquid Control The following items were identified during the review:
I'ttachment A to OP-153-001 lists the incorrect circuit breaker numbers for squib valves XV-1F004A and XV-1F004B.
In January 1984, during performance of the Unit
18 month initiation and injection surveillance, the licensee identified that the l
power supplies to the squib valves were mislabeled.
The drawings and surveillance procedure were subsequently corrected but the operating procedure was not revised to correctly reflect the as-built configuration.
The inspector informed the licensee of the procedure deficiency, and they stated the
'perating procedure would be corrected.
Both breakers were found in the correct position.
Attachment A to OP-153-001, lists the circuit breaker for SLCS pump "A" motor space heater as 1LP21C BKR02, but electrical schematic E-166 Sheet 1 states that breaker is 1LP21C BKR11.
The inspector informed the licensee who stated the procedure would be corrected.
The breaker was found in the correct, position.
Additionally, the operator log sheets for the Reactor Building also require revi sion since they also list the incorrect circuit breaker number.
The responsibility for several surveillance procedures has, recently been transferred from Operations to the Technical',
Staff, and the procedures have been rewritten and approved',
but the superceded procedures have not yet been removed from the
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SE-153-001, Revision 0, Standby Liquid Control System Eighteen Month Initiation and Injection Demonstration SE-153-002, Revision 0, Standby Liquid Control System Eighteen Month Operability Demonstration 1(
SE-153-004, Revision 4, Quarterly Standby Liquid Control Flow Verification E0-100-014, Revision 1, Anticipated Transient With Failure to Scram (ATWS)
AR-107-001, Revision 1, Alarm Response Window Box 07 I)
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GE Elementary Ml-C41-36, Standby Liquid Control t
Schematic Diagram E-166, Standby Liquid Control System The inspector determined that the system was properly aligned in accordance with the operating procedure and plant drawing Q1
II program.
The inspector informed the surveillance coordinator who stated he would initiate action to have the procedures cancelled to eliminate the potential of using the incorrect procedure.
Alarm response procedure, AR-107-001, states that circuit[
breaker 1B236051 for SLCS pump "A" be checked if annunciator
"Loss Continuity to Squib Valves" alarms.
The actual circuit breaker for the pump is 1B236081.
This appears to be a
typographical, error and the licensee was informed that a
i correction was needed.
Several errors existed in Attachment B to OP-153-001 concerning instrument root valves.
Valve OP1-PI-1R003 is listed as a
pressure instrument isolation valve but the valve does not physically exist in the field.
Valve OP2-PI-1R003 is listed as the high point, vent valve but the vent valve is actually labeled OP1-PI-1R003.
Valve OP1-PT-1N004 is installed in,'the field and should be included in the attachment, but was not listed.
The inspector discussed the discrepancies with the operations department, who verified that the attachment wa's incorrect, and initiated action to correct the procedure.
I, The licensee is currently implementing an instrument root valve labeling program and several of these valves were relabeled since the last revision of, the procedure.
All of the valves were in their correct position.
The corrective action for the above noted items will be reviewe'd in a subsequent inspection.
(387/85-21-01)
3.0 Summar of 0 eratin Events 3.1 Unit
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Unit 1 operated at or near 100 percent power for most of the in'spec-tion period.
Scheduled power reductions were conducted throughout the period for control rod pattern adjustments and surveillance,'esting.
3.2 Unit 2 On June 30, 1985 at 5:46 p.m. the Unit 2 reactor scrammed from 100 percent power on a generator load reject caused by a generator I
neutral phase overvoltage signal.
Licensee investigation identified a failed low voltage bushing on the "C" phase transformer.
The~',
bushing and another which showed slight damage were replaced.
The unit returned to operation on July 6, 198.0 Licensee Re orts 4. 1 In Office Review of Licensee Event Re orts The inspector reviewed LERs submitted to the HRC:RI office to verify that details of the event were clearly reported, including ther~
accuracy of description of the cause and adequacy of corrective action.
The inspector determined whether further information was required from the licensee, whether generic implications were
,,
involved, and whether the event warranted onsite followup.
The following LERs were reviewed:
Unit
85-022-00, Inadvertent ESF Actuation Due to Communication Error,
- 85-023-00, Excess Flow Check Valve Isolation Valve Left Open After LLRT Due to Incorrect Procedure in Violation of TS Action Statement
- 85-024-00, HPCI Inoperable Due to Failed Surveillance
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85-025-00, ESF Actuation Due 'to Contaminated Ventilation Screen'nit
~Discussed in Detail 4.2.
~Previously discussed in Inspection Report 50-387/85-18; 50-388/85-16 4.2 Onsite Followu of Licensee Event Re orts For those LERs selected for onsite followop (denoted by astenishs in Detail 4. 1), the inspector verified that the reporting requirem'ents of 10 CFR 50.73 had been met, that appropriate corrective actiop had been taken, that the event was reviewed by the licensee, and that continued operation of the facility was conducted in acccordance with Technical Specification limit <
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4.2.1 LER 85-023 Excess Flow Check Valve Isolation Valve Left
~Oen On June 11, 1985, following Unit 1 startup after the first refueling outage, a non-licensed operator noticed a'ressure on the vessel head seal leakoff gage.
He identified that valve 141005, a one-inch manual isolation valve for instrument excess flow check valve XV-141F~009, was open.
This valve, 141005, is required to be closed due to the inability to per form surveillance testing on XV-141F009.
Valve 141005 was opened to perform the Integrated Leak Rate Test (ILRT) from May 31 to June 2,
1985 'he ILRT restoration lineup called for the valve to be open.
There was a yellow tag on the valve which, stated that the valve should remain closed.
Neither the operator who initially checked the restoration nor the verifier read the instructions on the yellow tag.
The plant
changed Operational Condition on June 8.
Hence, the valve was out of the required position from June 8 to June 11.
The inspector reviewed this occurrence and discussed it with Operations personnel.
The only corrective actions indicated in the LER were to reposition the valve an'd counsel the operator s who did the ILRT restoration l,ineup regarding the yellow tag requirements.
In the inspector's view, this corrective action is inadequate.
There is no indication in the LER whether other operators were informed of the occurrence, whether the ILRT restoration procedure should be changed or when actions will be taken to permit testing of XV-141F009.
On July 31, the inspecto~ discussed this concern with the Supervisor of Operations and the Plant Superintendent.
They agreed to review the corrective actions, augment as necessary and issue a supplement to the LER.
This item is unresolved pending further review.
(387/85-21-02)
4.3 Review of Periodic and S ecial Re orts Upon receipt, periodic and 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 performance specifications; that planned~
corrective action was adequate for resolution of identified problems, and whether any information in the report should be classified as an abnormal occurrence.
The following periodic and special reports were reviewed:
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I Monthly Operating Report - June 1985, dated July 15, 1985 These reports were found acceptable.
5.0 Monthl Surveillance and Maintenance Observation l,
5.1 Surveillance Activities The inspector observed the performance of surveillance tests to determine that: the surveillance test procedure conformed to technical specification requirements; administrative approvals! and tagouts were obtained before initiating the test; testing was
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accomplished by qualified personnel in accordance with an appr'oved surveillance procedure; test instrumentation was calibrated; limiting conditions for operations were met; test data was accurate and complete; removal and restoration of the affected components was properly accomplished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and
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appropriately resolved; and the surveillance was completed at the required frequency.
These observations included:
TP-252-007, HPCI Stop Valve Operation During Cold Quick Start CST to CST, performed on July 23, 1985.
l'o unacceptable conditions were identified.
5.2 Maintenance Activities The inspector observed portions of selected maintenance activities to determine that: the work was conducted in accordance with approved procedures; regulatory guides, Technical Specifications, and industry codes or standards.
The following items were considered during this review: Limiting Conditions for Operation were met while components or systems were removed from service required administrative approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and QC hold points were established where required; functional testing was performed prior to declaring the particular component operable; activities were accomplished by qualified personnel; radiologic'al controls were implemented; fire protect,ion controls were implemented; and the equipment was verified to be properly returned to service.
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Activities observed included:
Troubleshooting of Unit 2 valve 2F062, RCIC turbine exhaust vacuum breaker outboard valve performed under Work Authorization WA-V50616 on July 8, 1985.
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The maintenance activities observed were performed in accordance with the applicable requirements and found acceptable.
5.2.1 Reactor Protection S stem Rela s
On June 1,
1985, the licensee identified that the C72-K14B and K14F relays (Division 2 scram contactors)
on Unit 2 were chattering and causing periodic half scrams.
The licensee cleaned the relay contacts under WA V50499, and the problem appeared to be corrected.
On June 19, 1985, the problem recurred and relays C72-K14B and K14F were both chattering.
The licensee identified that two
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contacts in the C72-K7B relay (main steam line high radiation)
were not properly making up.
The licensee cleaned a stationary contact in this relay which corrected the problem with the K14 relays.
The inspecto'r reviewed the above maintenance actions and discussed them with electrical maintenance personnel.
The inspector noted the following:
WA V50499 was performed without QC inspection.
The WA indicates that the scram relays were disassembled and cleaned.
The only retest involved cycling the relays three times to verify that they were operating properly.
These relays (i.e.
K14B and K14F) deenergize the scram pilot solenoid valves upon receipt of a scram signal.
Certain trip functions of the reactor protection system are required to be response time tested by Technical Specifi-cations.
These functions include the APRN upscale t'rips, the reactor high pressure trip, the low water level trip, MSIY closure trip and the turbine stop valve and control valve trips.
RPS response time is defined in T.S.
1.34 as the time interval from when the monitored parameter exceeds its trip setpoint at the channel sensor until deenergiza-tion of the scram pilot solenoid valves (SPSV).'or each of the above trip functions, the K14 relays must operate to deenergize the SPSV.
Therefore, for maintenance on these relays which could affect response time, consideration should be given to performance of response time testing.
It is possible for relay disassembly and cleaning to'affect, system response times.
By review of the work plan and discussions with electrical maintenance personnel, it is apparent that no consideration was given to conducting response time testing.
The inspector reviewed the mainte-nance action further and determined that the maintenance performed on the K14B and F relays should not have disturbed response times.
Nevertheless, the concern,,
remains since the work plan authorized relay disassembly and response time testing was not specified as a retes As noted above, on June 19, it was determined that two contacts in the C72-K7B relay were not properly making up.
The inspector reviewed WA V50547 which indicated that contact wipe was adjusted by bending out slightly on the stationary contact.
No dimensions were included.,
C72-K7B is a
GE HFA Type 151 relay.
IE Information Notice No.
83-19 and GE Service Information Letter (SIL) No.
Supplement 4 indicate that relay contact adjustments such as wipe and gap settings can affect HFA relay seismic qualification.
SIL No.
44 contains specific instructions (including dimensions) for contact wipe and gap adjustments.
No specific maintenance procedure exists for HFA relays and no reference to the above information was made in WA V50547.
The inspector discussed the above concerns with the maintenance supervisor and the maintenance engineering supervisor.
The maintenance supervisor committed to develop a procedure for HFA relay maintenance and to ensure response time testing of RPS relays is conducted as appropriate.
E The inspector also discussed with the Assistant Manager-QA (operations),
the concern about not providing QC inspection of maintenance on the K14 relays.
The QA/QC department recently instituted a sampling program whereby QC inspection of certain maintenance and modification work would only be performed on a sampling basis.
The work on the K14 relays was designated as part of the sampling program and was not selected for inspection.
Based on the inspector's concern, the Assistant Manager QA will exempt the reactor protection system from the sampling program and review all maintenance actions on this system for appropriate inspection.
These actions will be reviewed in a subsequent inspection (388/85-17-02).
6.0 IE Bulletins and Information Notice Followu qj 6.1 IE Bulletin No. 83-03:
Check Valve Failures in Raw Water Coolin S stems of Diesel Generators IE Bulletin No. 83-03, Check Valve Failures in Raw Water Cooling Systems of Diesel Generators, was sent to the licensee for action on March 10, 1983.
It required licensees to review their plant, Pump and Valve In-Service Test (IST) program and to modify it, if necessary, to include check valves in the flow path of cooling water for the diesel generators.
The testing was to include verification procedures that confirm the integrity of the valve internal.2 The licensees'nitial response to the bulletin, dated June 9,
1983 (PLA-1697), inclu'ded a listing of the check valves which would be added to the Pump and Valve IST program and stated that the verifi-cation of check valve operability and internal integrity would(be accomplished by valve disassembly and inspection during the Un't
first refueling outage.
The licensee committed to inspect twelve check valves in the system, which included eight Pacific check valves on the inlet to the diesel generator coolers and four Anchor Darling check valves at the ESW pump discharges.
The licensee has not experienced any previous failures of these twelve check valves.
However, as stated in their bulletin response, there has been a failure of another Pacific('check valve in the ESW system that may have inhibited the cooling water flow to the diesel generators.
During the implementation of aIplant modification to permanently remove the internals on check valve 0-11-053, it was discovered that 'the valve disc was not attached to the swing arm and the cotter pin and nut were missing.
(See LER 83-066).
The internals were removed.
The inspections on the twelve check valves were completed on May 10, 1985 and the final bulletin response was transmitted to NRC Region I on July 16, 1985 (PLA-2504).
All the valves were determined to be satisfactory except 0-11-039 which was discoveled to be partiallly disassembled.
The check valve disc was found to be not seating properly due to a loose disc nut.
The licensee felt that the disc nut pin had not been peened over sufficiently during initial vaIlve assembly and vibration had caused the pin to work out of the diIsc stud allowing the disc nut to loosen.
The valve was reassembled and the disc nut pin was properly peened.
I The inspector reviewed the completed work authorizations for the check valve inspections to verify that the inspections had been'I performed using the disassembly method and that no other deficiencies were identified.
The documents were found to be complete and acceptable.
The inspector reviewed Revision 3 to the Inspection Program for'umps and Valves, submitted to the NRC on December 31, 1984 and>>
verified that the twelve check valves are included in the program as stated in the licensee's bulletin response.
Half of the check
~j valves will be inspected each Unit 1 refueling outage.
Mis ositioned Control Rods at BWRsIi IE Information Notice 83-75 and INPO SOER 84-2 describe several occurrences of mispositioned control rods at BWRs.
Per IE Headquarters request, the inspector reviewed the actions taken by the licensee in response to the recommendations in SOER 84-2
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The licensee prepared a detailed internal response to each of the SOER
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recommendations and in general, concluded that the aspects of ~the plant design, procedures or policy noted below would preclude
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incidents such as those described in the SOER.
Reactor engineering is present at scheduled rod movements above 35%
power except for weekly rod exercising.
Below this power level, adequate direction exists in the form of control rod pull sequence sheets in the control room and startup procedures.
Off normal,~
procedures specify actions to be taken if a misaligned rod exists and require notification of reactor engineering prior to returning the rod to its normal position.
The plant has both a
Rod Sequence Control System (RSCS)
and Rod Worth Minimizer (RWM).
Both the'echnical Specifications and the RWM Operating Procedure specify that the RWM can only be bypassed if it is inoperable.
If RSCS is inoperable, no rod movement is permitted except by scram.
The'
approved sequence for rod movements is provided in the control"room and specified in the Reactor Engineering Instructions in the control room.
Susquehanna does not have a control rod test panel in the control room with individual rod scram switches.
The switchesj,are located at the individual hydraulic control units.
Hence, it is not practical to use this equipment to reduce power.
The plant design also does not incorporate
"an emergency in" mode of rod insertion and continuous insert and withdrawal modes do not bypass RWM or,,
RSCS.
The operators have received training on the consequences of misaligned control rods and industry events involving misaligned control rods.
7. ~iE During review of GE Elementary drawings, the inspector noted inconsis-tencies between power supplies for the RPS as shown on the GE Elementary series drawings when compared to E-157 drawings.
Specifically, circ'uit breaker (CB) assignments from panel 2Y201B shown on E-157 sheet 4 were in disagreement with GE Elementary drawings Ml-B21-101, M1-D12-2 and Ml-C72-4.
The licensee verified that the CB assignments as shown one E-157 are correct.
The licensee initiated drawing change notices (DCNs) t'o correct the above errors.
8.0 Anon mous Alle ation In February 1985, Region I received an anonymous allegation by telephone regarding inadequate QC involvement in work being performed by Catalytic during the Unit 1 first refueling outage.
The caller indicated thata Nonconformance Report (NCR) was written on February 18 regarding this subject.
il The inspector discussed the concern with QC personnel.
There was concern early in the outage that there were insufficient QC personnel available to support ongoing work.
Additional QC personnel were assigned to assist with the work load.
However, no evidence was noted of QC controls being bypassed.
The inspector reviewed NCR 85-0070 which indicated that several P
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IIIIAs were not sent to QC for final work package review.
However, QC inspections had been performed for the actual work.
Hence, QC inspection p'oints were not bypassed.
During the outage, the inspectors observed work activities and reviewed work packages for a number of modifications.
Ho concerns with lack of QC involvement were noted.
This allegation is considered unsubstantiated and is closed.
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fl AQ On August 1, 1985 the inspector discussed the findings of this inspection with station management.
Based on NRC Region I review of this report and discussions held with licensee representatives, it was determined that this report does not contain information subject to
CFR 2.790 restrictions.
A copy of Enclosure 3 was provided to the licensee at the Exit meeting.
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By now, you have received PP-L's letter PLA2453, the much delayed response to your inquiry on the status of as-built drawings.
I thought you might like to know why it took so long to get your response.
Enclosed for your interest is a copy of an internal memo sent out after the official response was sent to you.
Reading between the lines:
- plant operators try to use only top level drawings for blocking
isolation.
The termination information on these drawings, which is subject to the 2% error rate, is not complete, as only the connection diagrams show all the wires/devices connected at any point. If operators use the schematics or loop diagrams for blocking, they will probably be all right for the device they intended to block, but don't know if they have disabled anything else that might be attached to the same points.
Since many of the people establishing blocking don't know how to find the required information on the electrical connection diagrams, which are a second level below the schematics, and all the. connection info on the loops and schematics came from the connection diagrams with the errors, they really have a problem with the existing error rate.
- even though they know they have a problem,with Class 1 drawings (NCR83-152),
they have cancelled-all work to try and bring the drawings into as-built conditio the recent problem with open terminal block links is another sign of the same problem.
because of political problems between the plant staff organization and downtown engineering, plans to write a letter to the plant'sking for additional training Xor the plant personnel in using the drawings has been squelched.
As always, not being healthy around here to raise this kind of issue, call me Joe
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1985 GZ9 cc:
J. J.
Graham R.
M. Paley D. J.
Thompson R.
G. Byram F,
G. Butler L. D. O'Neil OCC File SSES SSES SSES SSES SSES SSES SSES A.N Pfa I e:
A6-2 SUSQUEHANNA STEAN ELECTRIC STATION NRC INSPECTION REPORT 387/85-02 TERMINATION ERRORS ON "AS BUILT" DRAWINGS ER 100450 FILE 841-04 PLIS-20 211 The subJect inspection report described evidence of configuration control problems with Class 2 connection and wiring diagrams.
NPE's response, to this finding indicated a 2l rate of "as built" drawing error exists.
This,,error rate is unacceptable from an operationa'1 standpoint, since it causes undue investigation effort when discrepancies are found.
Additionally, the" known discrepancies reduce the general level of confidence in the drawing system.
The resulting attitude is a difficult problem to correct.
Please provide a suIImary of your plans to correct the known discrepan'cies as soon as possible.
H.W. Keiser RHP/cg st:rmp/asbuilt PENNSYLVANIA POWER 4 LIG8T COMPANY
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