IR 05000250/1986045
| ML20212H999 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 01/13/1987 |
| From: | Brewer D, Macdonald J, Van Dyne K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20212H925 | List: |
| References | |
| 50-250-86-45, 50-251-86-45, NUDOCS 8701280069 | |
| Download: ML20212H999 (19) | |
Text
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Report Nos.: 50-250/86-45 and 50-251/86-45 Licensee:
Florida Power and Light Company 9250 West Flagler Street Miami, FL 33102 Docket Nos.: 50-250 and 50-251 License Nos.:
DPR-31 and DPR-41 Facility Name:. Turkey Point 3 and 4 Inspection Conducted:
November 3 - December 15, 1986 Inspectors:
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K.W.9anDyn'Te[ident Inspector Dat'e Signed b 096edn s 9)
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/1k 7 7 Approved by:
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8.' A. Wilson, Section Chief
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Date Signed Division of Reactor Projects SUMMARY Scope: This routine, unannounced inspection entailed direct inspection at the site, including backshift inspection, in the areas of annual and monthly surveillance, maintenance observations and reviews, operational - safety, indepen-dent inspection, and plant events.
Results: Three violations were identifie'd - Failure to meet the requirements of Technical Specification (TS) 6.8.1, four examples (paragraphs 7 and 9); failure to meet the requirements of 10 CFR 50, Appendix B, Criterion XVI, two examples (paragraph 8); and failure to meet the requirements of TS 3.3.3 (paragraph 8).
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REPORT DETAILS 1.
Persons Contacted Licensee Employees
- C. M. Wethy, Vice President - Turkey Point
"C. J. Baker, Plant Manager-Nuclear - Turkey Point F. H. Southworth, Senior Technical Advisor E. Preast, Site Engineering Manager (SEM)
- D. D. Grandage, Operations Superintendent and Acting Plant Manager
- T. A. Finn, Operations Supervisor J. Crockford, Operations Enhancement Coordinator J. Webb, Operations - Maintenance Coordinator
- J. W. Kappes, Maintenance Superintendent - Nuclear R. A. Longtemps, Mechanical Maintenance Department Supervisor D. Tomasewski, Instrument and Control (IC) Department Supervisor J. C. Strong, Electrical Department Supervisor W. Bladow, Quality Assurance (QA) Superintendent
- M. J. Crisler, Quality Control (QC) Supervisor J. A. Labarraque, Technical Department Supervisor R. G. Mende, Reactor Engineering Supervisor J. Arias, Regulation and Compliance Supervisor
- R. Hart, Regulation and Compliance Engineer W. C. Miller, Training Supervisor P. W. Hughes, Health Physics Supervisar
- G. Solomon, Regulation and Compliance Engineer
- J. Donis, Engineering Department Supervisor
- J. J. Zudans, Nuclear Engineering, Human Factors Performance
- J. W. Anderson, QA Regulatory Compliance Supervisor
- R. L. Wade, Engineering Department Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, mechanics, electricians and security force members.
- Attended exit interview on December 17, 1986.
2.
Exit Interview The inspection scope and findings were summarized during management inter-yiews held throughout the reporting period with the Plant Manager-Nuclear and selected members of his staff.
An exit meeting was conducted on December 17, 1986. The areas requiring management attention were reviewed.
Three violations were identified.
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Failure to meet the requirements of TS 6.8.1, four examples, in that:
(1) scaffolding was erected over both redundant trains of the Unit 4 Auxiliary Feedwater (AFW) system; (paragraph 9) (2) a procedure
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describing the proper method by which to supply Backup Service Water to
.the AFW pump turbine lubricating oil coolers did not exist; (paragraph 9) and (3) valves70-102, 70-103 and AFWU 009 were found not to be in their required positions (paragraph 9); and (4) during repairs on Power Range Channel N-41, maintenance personnel inadvertently-removed the instrument fuses for Power Range Channel N-42-(paragraph 7) (250,251/
86-45-01).
Failure to meet the requirements of 10 CFR 50 Appendix B, Criterion
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XVI, two examples, in that:
(1) after discovering that two support hangers on the Unit 4 charging line were not properly assembled, the licensee failed to take timely corrective action in determining the safety significance and; (2) after determining that both the A and B Emergency Diesel Generator (EDG) starting air receivers were improperly bolted to the floor, the licensee failed to take timely corrective action in evaluating safety significance (paragraph 8) (250,251/
86-45-02).
Failure to meet the requirements of TS 3.3.3, in that the licensee did
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not isolate penetrations affected by failed steam generator blowdown isolation valves (paragraph 8)(251/86-45-03).
3.
Licensee Action on Previous Inspection Findings (92702/92700)
(Closed) LER 250/85-032, Reactor Protection System Actuation - Reactor Trip.
On 0ctober 15, 1985, while Unit 3 was at 100% power, a reactor - trip
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occurred.
The cause of the trip was the accidental jarring of the main i
transformer differential relays by construction personnel, which caused an electrical generator trip, which in turn caused a turbine trip and a reactor
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trip.
During recovery from the reactor trip, leakage past the "B" steam generator (SG) bypass feedwater control valve (FCV-3-489) was discovered.
The feedwater control valves were disassembled, cleaned and inspected and the required repairs were performed. FPL inter-office correspondence, dated October 29, 1985, established guidelines for work efforts in the area of
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system protection equipment.
(Closed) LER 251/85-022, TS - 480 Volt Motor Control Center. On October 16, 1985, while Unit 4 was at 100% power, the 4A 4160 volt breaker 4AA08, which feeds the 4A 4160V/480V transformer tripped, de-energizing the 4A 480V motor
i control center (MCC). The cause for the tripping of breaker 4AA08 could not be identified, the 4A MCC was re-energized within 40 minutes. Although no abnormal conditions were found when the 4AA08 breaker was inspected, the LER
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stated that the breaker would be replaced during the next outage of suffi-
cient duration.
However, based on the General Electric (GE) evaluation, documented in GE correspondence to FPL, FSR 356E4651, dated February 26,
1986, it wis concluded that breaker 4AA08, was satisfactory for service.
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(Closed) LER 251/84-010, ESF Actuation - Reactor Trip. On June 4, 1984, while Unit 4 was at 100% power, a reactor trip occurred. Just prior to the reactor trip, the 4A SG feedwater pump tripped on low suction pressure, which caused a 30% turbine runback. No immediate apparent cause for the
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reactor trip was evident.
The DDPS printout indicated the trip was t
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initiated by the opening of the "A" reactor trip breaker. The post trip review gave no indication of any reactor trip breaker matrix being made up.
The "A" reactor trip breaker was replaced and the unit was returned to power operation on June 5,1964.
(Clesed) LER 251/85-003, ESF Actuation - Reactor Trip. On February 6, 1985, while Unit 4 was at 27% power, a reactor trip occurred. A normal reactor startup was in progress.
The reactor tripped due to "A" SG steam flow greater than feed flow coincident with low SG level. The operators had been having difficulties maintaining level in the "A" SG at the time of the trip.
All equipment functioned as designed following the trip.
The setpoint and calibration of SG level, feedwater flow and steam flow transmitters were inspected and were within limits.
The feedwater regulating valves were inspected and found to be operating satisfactorily.
The startup was re-initiated and full power was achieved the same day.
(Closed) LER 251/85-014, ESF Actuation - Containment and Control Room Ventilation Isolation. On June 8,1985, while Unit 4 was at 100% power, a containment and control room ventilation isolation occurred. Shortly before the isolation, the pressurizer drain tank (PRT) had been drained to the containment sump to lower the PRT level and pressure.
The normal PRT drainage path via the reactor coolant drain tank (RCDT) was unavailable due to equipment being out of service. The PRT drainage to the containment sump caused the airborne activity in containment to increase to the high activity alarm setpoint for monitor R-11 whicn resulted in the isolations. The high PRT level and pressure was caused by leakage past the pressure control valve PCV-4-456.
MOV-4-535, the block valve associated with PCV-4-456, was closed, reducing leakage to the PRT. PCV-4-456 was repaired and returned to service during the extended Unit 4 outage.
(Closed) LER 251/84-013, ESF Actuation - Auxiliary Feedwater Initiation. On June 24, 1984, during power escalation, automatic initiation of auxiliary feedwater (AFW) occurred. The cause of the AFW initiation was the trip of the 4B SG feedwater pump due to low suction pressure, resulting from the start of the 4A condensate pump. All equipment performed as designed and AFW was secured within two minutes after initiation.
(Closed) LER 251/85-006, ESF Actuation - AFW Initiation.
On February 7, 1985, while Unit 4 was in hot shutdown, AFW was automatically actuated.
While starting the 4B SG feedwater pump, a lockout relay actuated, de energizing the 4C 4160V bus tripping the 4B SG feedwater pump. The 4A SG feedwater was secured. This completed the initiation logic for AFW and it automatically actuated. All systems functioned as designed.
The effected relay had been set up for relay testing and not been returned to the opera-tienol configuration.
The effected relay was secured.
Additionally, a quarterly relay survey has been instituted.
(Closed) LER 251/85-026, ESF Actuation - Emergency Diesel Generator.
On December 24, 1985, while Unit 4 was at 100% power, the 480V power supply (40107) to the 4A backup group pressurizer heaters was discovered.to have no light indication.
Investigations indicated the problem was in the internal tripping circuit of the breaker.
This was significant because in that
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condition, the breaker could not have tripped on a safety injection or bus stripping signal as designed. This would have allowed the 4A backup group pressurizer heater to be loaded onto the
"A" Emergency Diesel Generator (EDG), which was an electrical load not allowed for in the FSAR.
The breaker was manually tripped and replaced. The similar Unit 4 breakers were inspected and the Unit 3 breakers will be inspected in the Spring 1987 refueling outage.
(Closed) LER 251/85-021, Rev.1, ESF Actuation - AFW System Initiation. On July 22,1985, two automatic initiations of AFW occurred. Unit 3 was in hot standby recovering from a previous reactor trip when the
"B" SG bypass feedwater control valve FCV-3-489, would not open. When the
"B" SG level reached the 15% low-low level setpoint, the first AFW initiation occurred.
The "A" and "C" AFW pumps tripped on electronic overspeed and the "B" AFW pump oscillated on its mechanical overspeed trip. Several hours later, the second AFW automatic initiation occurred when "C" SG FCV-3-499 would not close, allowing "C" SG level to reach its 80% high-high level setpoint.
This tripped the
"B" SG feedwater pump and with the "A" SG feedwater pump secured, AFW automatic initiation logic was completed.
Throughout the AFW
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automatic initiations, the AFW control valves were experiencing malfunctions due to the presence of moisture in the instrument air of the actuators. The overspeed trips were reset for the AFW pumps and all the flow control valve actuators were inspected, cleaned and repaired as necessary. A surveillance plan was established to ensure that the instrument air systems operated within acceptable criteria.
(Closed) LER 251/86-013, Inadvertent Relay Actuation During Maintenance Causes Phase A Containment Isolation.
On July 22 and July 24, 1986, while Unit 4 was in cold shutdown, Phase A containment isolations (CI) were actuated. Both CI actuations were caused by personnel error as I&C tech-nicians performed work on safeguard relays which were difficult to access.
The first Phase A CI was the result of a technician bumping relay SIA1; the second Phase CI resulted when the technician's screwdriver shorted out the contact on relay SIA2. The maintenance instruction was revised to require physical blocking of the contacts of all relays being tested.
Technicians were rebriefed on the proper precautions necessary to prevent inadvertent actuations of the relays.
(Closed) LER 251/86-014, Subcritical Reactor Trip Due to Testing Using an Inadequate Procedure. On August 5, 1986, while Unit 4 was in cold shutdown, a subcritical reactor trip occurred. The trip was the result of the I&C performance procedure TOP-233, to test turbine runback and power mismatch modifications. 10P-233 was an inadequate procedure in that it failed to verify the open position of the reactor trip breakers and did not address the need to block the P-7 and P-8 permissives prior to simulating 70% power.
When the 70% power signal was input, the P-7 and P-8 permissives were enabled and the reactor trip breakers opened.
TOP-233 was revised and the required changes were made to prevent recurr'ence and the procedure was successfully performed.
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(Closed) LER 251/86-31 and LER 251/86-018, AFW Flow Control Valve Failures.
On August 3, 1986, and August 24, 1985, Units 3 and 4, respectively, entered TS 3.0.1 due to flow control valve (FCV) failure during the performance of procedure OSP-075.2, "AFW Train 2 Operability Verification."
In both events, the cause of failure was water entering the current to pressure conversion module (I/P) through a designed cut-out in the casing.
The source of water was dripping from the feedwater deck overhead.
The I/P cases were remounted to allow water to drain past the case. The I/P case vent filters were flushed and cleaned, and the internals air dried.
The flow transmitters, local flow indicators, and I/Ps were calibrated and returned to service.
(Closed) LER 251/84-015, ESF Actuation - SI Pump Actuation.
On July 16, 1984, while Unit 4 was in cold shutdown, an unexpected start of the 4A high head safety injection (HHSI) pump occurred. Construction personnel erecting scaffolding in the vicinity of the breaker inadvertently brushed the remote switch, starting the pump. No ESF actuation signal was present and no flow was injected into the core.
The construction personnel were given addi-tional instruction on the need to exercise extreme care while performing work near critical equipment. Also, protective devices have been installed over local switches to decrease accidental actuations.
The corrective actions are documented in letter PTP-JPM-86-473, dated October 24, 1986.
(Closed)
LER 251/85-015, Technical Specification, Emergency Diesel Generator. On June 10, 1985, while Unit 4 was at 100% power, both the
"A" and "B" EDG were declared out of service (005).
The "B" EDG was 00S for Appendix R modifications. The
"A" EDG was declared 005 when the 3A MCC, which pcwers various "A" EDG auxiliary equipment, was de-energized. A PNSC approved Engineering Department safety evaluation recommended the use of the
"B" EDG power supply to its auxiliary equipment to temporarily power the "A" EDGs similar equipment. The appropriate procedures were written to facili-tate the transfer, and to institute a continuous watch in the EDG rooms.
When the 3A MCC was returned to service, the power source was returned to its normal configuration.
(Closed) LER 251/84-019, TS - Missed Surveillance. On September 1, 1984, while Unit 4 was at 100% power, the daily calibration of the nuclear power range was not performed. The calculation is required by TS to be performed daily. The cause of the missed TS surveillance was operator oversight. The procedure OP-12304.3, Power Range Nuclear Instrumentation Shift Checks and Daily Calibrations, was revised to require the thermal power calculation to be completed before doing the shift check of the NIS.
(Closed) LER 250/84-036, B EDG Overspeed Trip. On December 21, 1984, during daily testing of the B EDG, required by TS because of the A EDG was 00S, the diesel failed to start from the control room due to an overspeed alarm. The alarm was reset and the B EDG was started, but immediately tripped on overspeed. The cause of the event was the improper setting of the governor no load speed above the overspeed trip setpoint.
The no load speed was properly readjusted and training brief number 39 was issued addressing proper governor setting.
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(Closed) LER 251/86-023, B EDG Declared 00S on Low Lube Oil Temperature Due to Failure in the Immersion Heater Coil (IHC) Circuit. On October 25, 1986, while Unit 4 was in hot shutdown, the B EDG ready to start light was lost and the trouble alarm annunciated as a result of the low lube oil tempera-ture alarm setpoint being reached.
Several hours later, the B EDG was declared OOS and the IHC contactor coil was replaced. After post mainte-nance testing the B EDG was returned to service. On October 27, 1986, the lube oil temperature began to fall again. The B EDG was declared 00S and trouble shooting revealed the root cause to be an intermittent ground caused by a nick in the insulation of the wire from the IHC contactor to a terminal block. The wire was replaced and post maintenance testing was performed satisfactorily and the "B" EDG was returned to service.
(Closed) The following 12 LERs were generated as a result of RPS actuations (reactor trips) and ESF actuations (turbine runbacks) caused by various failures of the vital AC instrument power inverters and of the turbine runback system. Two long term corrective actions have been taken.
The first was to enhance the reliability of the AC instrument power supplies.
The inverters were replaced and constant voltage transformers (CVT) have been installed as the alternate power supplies for each of the eight normal l
vital inverters.
Each new normal vital inverter has a static transfer
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switch that will automatically transfer the lead to the alternate power supply (CVT) upon loss of a normal inverter.
The second corrective action involved the implementation of two major plant modifications to the turbine runback system to increase availability and reliability of the units. The 12 LERs listed below are closed as a result of the completion of these corrective actions.
LER 250/84-009 LER 250/85-023 LER 251/85-012 LER 250/84-013 LER 251/84-011 LER 251/85-013 LER 250/84-026 LER 251/84-021 LER 251/85-017 LER 250/85-018 LER 251/84-022 LER 251/85-019 4.
Performance Enhancement Program (PEP) Summary a.
On November 18, 1986, members of the licensee staff and the NRC met in Bethesda to discuss the status and review schedule for converting the Turkey Point TSs to the Westinghouse Standard TS format and content.
b.
On December 9,1986, the licensee presented a quarterly update of the PED to NRC Region II staff at the Turkey Point site.
The status of each of 11 projects was discussed.
Plant management also assessed progress being made in operations, maintenance, and QA/QC programs to improve SALP ratings.
c.
On December 15, 1986, the licensee held a meeting and conducted a plant tour for Commissioner Carr. The meeting topics included the labelling project, AFW System, Quality Improvenent Program, and PE.
5.
Unresolved Items An unresolved item is a matter about which more information is required to determine whether it is acceptable or may involve a violation or deviation.
No unresolved items were identified during this inspection.
6.
Monthly and Annual Surveillance Observation (61726/61700)
The inspectors observed TS required surveillance testing and verified: that the test procedure conformed to the requirements of the TS, that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that limiting conditions for operation (LCO) were met, that test results met acceptance criteria requirements and were reviewed by personnel other than the individual directing the test, that deficiencies were ider-fled, as appropriate, and were properly reviewed and resolved by managemer personnel and that system restoration was adequate.
For com-pleted tests, the inspectors verified that testing frequencies were met and tests were performed by qualified individuals.
The inspectors witnessed / reviewed portions of the following test activities:
4-0SP-049.1, Reactor Protection System Logic Tast 4-PMI-028.2, Axial Flux, Rod Deviation, and Rod Position Indication Monthly Test POP 0800.110, Unit 3 AFW Pumps RPM Monitoring (A pump)
4-OSP-075.1, AFW Train 1 Operability Verification OP 4304.3, Emergency Diesel Generator-Eight Hour Full Load Test and Load Rejection (A EDG)
OP 4304.1, Diesel Generator Operability Test (A EDG)
OP 14004.1, Unit 3 Steam Generator Protection Channels-Periodic Test ST 85-10, Special Test of Unit 3 Component Cooling Water Heat Exchanger Performance No violations or deviations were identified within the areas inspected.
7.
Maintenance Observations (62703/62709)
Station maintenance activities of safety related systems and components were observed and reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides, industry codes and standards and in conformance with TS.
The following items were considered during this review, as appropriate:
that LCOs were met while components or systems were removed from service; that approvals were obtained prior to initiating work; that activities were l
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accomplished using approved procedures and were inspected as applicable; that procedures used were adequate to control the activity; that trouble-shooting activities were controlled and repair records accurately reflected the maintenance performed; that functional testing and/or calibrations were performed prior to returning components or systems to service; that QC records were maintained; that activities were accomplished by qualified personnel; that parts and materials used were properly certified; that radiological controls were properly implemented; that QC hold points were established and observed where required; that fire prevention controls were implemented; that outside contractor force activities were controlled in accordance with the approved QA program; and that housekeeping was actively pursued.
The following maintenance activities were observed and/or reviewed:
0-PMM-22.3, Emergency Diesel Generator 18 Month Preventative Mainte-nance Replacement of 4C feedwater control valve solenoid Inspection / Repair of all feedwater control valve instrument air lines Repair of 4A feedwater control valve trip solenoid flexible conduit Repair of 4A feedwater control valve positioner linkage Replacement of 4C feedwater control valve positi-ner pilot Replacement /recalibration of Barton DP switches in all feedwater control valves Rebuilding of pilot valve assemblies on all feedwater flow control valves Troubleshooting of Power Range N-41 dropped rod / rod stop bistable a.
On November 10, 1986, the Unit 4 reactor tripped due to low steam generator level.
The cause of the level transient was a failed instrument air solenoid coil for the 4C S/G feedwater flow control valve. When the solenoid failed closed, instrument air to the flow control valve was isolated causing the flow control valve to auto-matically close. Consequently, feeowater flow was reduced to less than steam flow and this resulted in decreasing steam generator level. The failed coil was replaced and the reactor was returned to power on November 11, 1986.
The licensee sent the coil the vendor (ASCO) to determine the mode of failure.
On November 12, the licensee discovered a leaking instrument air fitting associated with the 4C S/G feedwater flow control valve. The i
fitting had been broken to facilitate replacement of the failed coil the previous day and was improperly made up.
The leak was excessive and plant management was concerned that complete failure of the fitting
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may result in another reactor trip. An immediate load reduction was required to break and properly make up the connection.
On November 14, plant work orders were generated to inspect / repair the 4A and 48 feedwater flow control valves. In addition to rebuilding the pilot valves for both of the flow control valves the 4A valve had some defective instrument air tubing that was replaced.
The 4B valve high side root valve on DP 2902 was rebuilt. These repairs required a load reduction while feed flow was maintained through the feedwater flow bypass valves.
On November 18, still another load reduction was required for mainte-nance on the 4A feedwater flow control valve. A cracked instrument air line fitting on the valve positioner threatened continued Unit 4 operation and required immediate repair.
i b.
On December 2, 1986, maintenance personnel were troubleshooting a dropped rod / rod stop signal generated on Unit 3 during rod control periodic testing.
Upon completion of troubleshooting / repair of Power Range Nuclear Instrumentation Channel N-41, 0-GMI-102.1, Trouble-shooting and Repair Guidelines, required that the drawer be de-energized to remove test equipment and replace any lifted leads.
With Unit 3 operating at 100% reactor power, during repairs on Power Range channel N-41, and while N-41 was still removed from service, an Instrument and Controls Technician inadvertently removed the instrument fuses from power range channel N-42. This resulted in operation for a short time with less than the minimum number of redundant Nuclear Instrument channels operable.
T S 6.8.1 requires that written pro-cedures be implemented that meet or exceed the requirements and recom-mendations of USNRC Regulatory Guide 1.33.
Item 9.a of USNRC Regulatory Guide 1.33, Appendix A indicates that maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, docu-mented instructions, or drawings appropriate to the circumstances. The failure to properly implement the requirements of 0-GMI-102.1 consti-tutes Example 4 of violation (250/86-45-01).
8.
Operational Safety Verification (71707)
The inspectors observed control room operations, reviewed applicable logs, conducted discussions with control room operators, observed shift turnovers and confirmed operability of instrumentation.
The inspectors verified the operability of selected emergency systems, verified that maintenance work orders had been submitted as required and that followup and prioritization of work was accomplished. The inspectors reviewed tagout records, verified compliance with TS LCOs and verified the return to service of affected components.
By observation and direcc interviews, verification was made that the physical security plan was being implemented.
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Plant housekeeping / cleanliness conditions and implementation of radiological controls were observed.
- Tours of the_ intake structure and diesel, auxiliary, control and turbine buildings were conducted to observe plant equipment conditions including potential fire hazards, fluid leaks and excessive vibrations.
The inspectors walked down accessible portions of the following safety related systems to verify operability and proper valve / switch alignment:
Emergency Diesel Generators Auxiliary Feedwater Control Room Vertical Panels and Safeguards Racks Unit 3 and Unit 4 Residual Heat Removal Systems Unit 3 and Unit 4 Component Cooling Water Systems Unit 3 and Unit 4 Intake Cooling and Discharge Canal Areas Standby S/G Feedwater System Unit 3 and Unit 4 S/G Feedwater Flow Platforms a.
During this inspection period two Nonconformance Reports (NCRs) were extensively reviewed to determine the adequacy of the licensee's approach to the resolution of technical issues. Appropriate corrective action was not taken by the licensee in that timely analyses were not performed regarding system operability or TS limiting condition for operation compliance.
The two issues are discussed below.
(1) On October 23, 1986, a Quality Control Inspector determined that-two support hangers on the Unit 4 charging line were not properly assembled.
NCR 86-354 was issued and addressed to the site engineering department for disposition. On October 24, the NCR was reviewed as part of an initial scheduling effort to identify required work repairs.
The review, which required no written documentation, did not identify any potential charging system operability concern and resulted in the assignment of the NCR to a routine schedule and priority.
On October 27 a job engineer received the NCR.
He did not perform an initial operability review because no such review was required by procedure. Work repairs associated with the NCR were scheduled to begin on November 21, 1986, 29 days following the identification of the nonconformance.
On November 18, 1986, the job engineer physically inspected the charging line and determined that it was required to meet Final Safety Analysis Report (FSAR) seismic requirements. The supports were deficient in that the clamp guides were missing, thus pro-viding far greater pipe motion than the original design.
An expedited repair effort was initiated in parallel with an effort to calculate the existing pipe stresses. On November 21, 1986, the piping was determined to be functional under the criteria of Inspection and Enforcement (IE)Bulletin 79-14, Seismic Analyses For As-Built Safety Related Piping Systems. However, it was found not to be supported as adequately as required by the FSAR.
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Between October 23 and November 18, 1986, no determination was made as to the operability of the charging line. The plant staff did not insist on an engineering assessment of operability and the engineering staff was not procedurally required to supply an operability determination. The licensee assumed that the charging system was. operable because it was not known for a fact that the piping was inadequately supported.
(2) On October 27, 1986, a QC Inspector determined that the starting air receivers for both the A and B EDGs were improperly bolted to the floor. NCR 86-358 was issued and sent to the site engineering department for disposition.
During an initial scheduling review performed on October 28, the engineering staff determined that a potential operability concern existed. The NCR was placed on an expedited disposition schedule. On November 4, an initial assess-ment of the as-found condition of the bolts was completed. A determination was made that a more rigorous analysis would be required to evaluate the operability of the EDG air receivers.
Between November 4 and 13, both civil and mechanical engineers were involved in a review of the bolts. The civil engineers were assigned responsibility for determining acceptable bolt loading in the as-found condition and calculating bolt loads based on various possible tank stresses.
Mechanical engineers researched the physical characteristics of the tanks for use in civil calcula-tions. Parallel efforts were taken to locate the original calcu-lations or drawings for the tank installation. On November 24, informal calculations were performed which indicated that standard tank loadings provided an unacceptable basis upon which to base an operability determination. A decision was made to pursue bolt repair in parallel with continuing engineering calculations.
On November 28, 1986, a justification for continued operation (JPE-L-86-108 dated November 26, 1986) was issued which stated that the air receivers could be considered operable for the three week estimated repair period, due to the unlikely probability of a seismic event.
During the resolution of this issue the licensee failed to take timely corrective action in that the safety significance of the condition was not evaluated until November 26, 1986.
Between October 23 and November 25, 1986, analyses performed relative to the seismic qualification of the air receiver floor bolts failed to provide a positive indication of acceptability.
Preliminary, conservative calculations performed by the site engineering staff indicated that two of the eight receivers might not withstand the safe shutdown earthquake.
Between October 23 and November 25, 1986, no analysis was done regarding EDG operability or TS limiting condition for operation compliance.
The plant staff did not insist on an engineering assessment of operability and the engineering staff was not procedurally required to supply an operability determination.
The licensee
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assumed that the EDGs were operable because it was not known for a fact that the air receivers were inadequately bolted to the floor.
10 CFR 50, Appendix B, Criterion XVI, as implemented by Florida Power and Light. (FPL) Topical Quality Assurance Report FPLTQAR 1-76A, Revision 9, and TQR 16.0, Revision 5, entitled Corrective Action, requires, in part, _that measures be established to assure that conditions adverse to quality, such as failures, malfunc-tions,- deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified, tracked and correc-ted.
The disposition of the two NCR; discussed above were not adequate in that timely analysis of s; stem operability or TS limiting condition for operation compliance was not performed. The. failure to meet the requirements of 10 CFR 50, Appendix B, Criterion XVI is a violation (250,251/86-45-02).
In FP&L's October 1, 1986 response to Enforcement Action (EA)
86-20, issued on August 12, 1986, on the violation for failure to take prompt corrective action for conditions adverse to quality, the licensee stated in part:
There has been a significant increase in the on-site engineering force at Turkey Point.
The Site Engineering function now reports directly to the Site Vice President.
The increased presence and visibility of the on-site engi-neering function has allowed NCRs and REAs to be disposi-tioned more promptly without the attendant communications difficulties created by distance between the site and the corporate engineering group at Juno Beach.
To address the concern of satisfying operability requirements while identified deficiencies are being evaluated, a proposed site engineering procedure is being finalized.
This pro-cedure will formalize the requirements and responsibilities
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associated with determining the impact on operability and reporting deficiencies.
As part of this process, safety evaluations by [the] Power Plant Engineering are initiated where appropriate.
The procedures referenced above had not been finalized or approved at the time the NCRs of concern were dispositioned (October 23 through November 25, 1986).
Subsequent to detailed discussions
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between the Site Engineering Manager and the NRC inspectors, Engineering Procedure (EP) 2.3, entitled Processing of Nonconfor-
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mance Reports, Revision 0, dated December 4, 1986, was issued on December 8, 1986. This procedure establishes a three day maximum time period during which the lead engineer receiving an NCR must initiate an operability assessment of the discrepancy. If the NCR is determined to contain operability concerns then its disposition and/or evaluation shall receive the highest priority and immediate
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processing in accordance with EP 2.7, Initial Engineering Assess-ment of Operability.
EP 2.7, Revision 0, was first approved on December 8, 1986.
Section 5.2.4 of the procedure requires a clear and concise evaluation of a NCR which has been determinad, via EP 2.3 to contain operability issues.
The engineering evaluation is-required to provide specific conclusions regarding the system's operability and safety design basis.
EP 2.6, Engineering Safety Assessment, Revision 0, was initially approved on November 25, 1986. This procedure describes responsibilities for performing a second level assessment of the safety significance of items initially determined to have operability concern under EP 2.3.
Procedures EP 2.3, 2.6, and 2.7 are being reviewed by the NRC inspectors to determine their suitability in providing timely determinations of system operability while deficiencies are being evaluated.
b.
On September 26,1986, at 0035 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br />, the 48 steam generator blowdown isolation valve (CV-4-62758) and its associated blowdown isolation bypass valve (SV-4-62758-1) failed closed, rendering the valves inoperable.
On October 6, 1986, at 0457 hours0.00529 days <br />0.127 hours <br />7.556217e-4 weeks <br />1.738885e-4 months <br />, the 4C steam generator blowdown isolation valve (CV-4-6275C) and its associated blowdown isolation bypass valve (SV-4-6275C-1) failed closed, rendering the valves inoperable.
These valves are Phase A containment isolation valves. TS 3.3.3.b and 3.3.3.c require that with one or more contain-ment isolation valves inoperable, if. the inoperable valve (s) can not be restored to operable status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the affected penetration must be isolated within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
Contrary to the requirements of TS 3.3.3.b and 3.3.3.c, the licensee failed to take the actions necessary to properly iso' ate the affected penetrations, within the required 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The operators on shift during the events did not recognize that although the valves had failed closed in the accident position, to comply with the TS requirements, the failed valves had to be deacti-
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vated to prevent the possibility of a spurious opening and subsequent failure in the open position or as an alternative, close a manual isolation valve in the affected penetration.
In both instances the salves were deactivated in the isolation position approximately 51/2 hours after failing closed.
The failure to comply with TS 3.3.3 constitutes a violation (251/86-45-03). As a result of the apparent operator weakness in thi s ar e:t, Trainteg Brief #185 was issued to clarify the requiromnts of TS 3.3.3 ana Operations Memo PTN-0PS-86-210 was reissued to all on shift l u.ensed senior operators to reinforce the need to contact the operations supervisor, the operations superinten-dent and licensing personnel when questions of TS compliance arise.
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9.
Engineered Safety Features Walkdown (71710)
The inspectors verified operability of the Unit 3 and Unit 4 Residual Heat Removal Systems by performing a. complete walkdown of all accessible equip-ment. The following criteria were used, as appropriate, during the walk-down:
a.
System lineup procedures matched plant drawings and the as-built configuration.
b.
Equipment conditions were satisfactory and items that might degrade performance were identified and evaluated (hangers and supports were operable, housekeeping was adequate, etc.).
c.
Instrumentation was properly valved in and functioning and that cali-bration dates were not exceeded.
d.
Valves were in proper position, breaker alignment was correct, power was available, and valves were locked /lockwired as required.
e.
Local and remote position indication was compared and remote instru-mentation was functional.
f.
Breakers and instrumentation cabinets were inspected to verify that they were free of damage and interference.
The inspectors noted the following Unit 3 concerns to licensee management:
a).
A bolt was missing from the motor actuator cover plate on valve 860B; b)
The A RHR heat exchanger shell vent line was improperly supported; c)
Valves 862A and 862B were tagged improperly in that the tags indicated normally closed but the valves were actually locked open; d)
Piping support for valve 766A appeared inadequate; e)
The B RHR pump room sump trash screen was not in place ana the sump contained foreign material; f)
Lagging on valve 862A was torn and falling off;
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g)
The B pump bearing heat exchanger CCW flowmeter was disconnected; h)
Temporary lighting was found adrift in the B pump room; and 1)
An I beam supported by C clamps was found overhead valves 752B and 862A.
The inspectors noted the following Unit 4 concerns to licensee management:
a)
Valve 758 instrument air line was inadequately supported;
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b)
Valve 759A was not labeled; c)
Valve 7598 was not labeled; d)
Lagging on valve 757C was torn and falling off; e)
Differential pressure instrument lines for the B pump were inadequately supported; and f)
The A and B RHR heat exchangers were reverse labeled.
A walkdown of the AFW and feedwater systems was performed on November 14, 1986.
The discrepancies identified were promptly dispositivned by the licensee and corrective action has been or is scheduled to be performed.
The following list of discrepancies was brought to licensee management attention:
a)
Service water valves70-102 and 70-103, backup AFW lube oil cooling supply isolation valves, are required to be open as indicated on the
valve tags, drawing 5610-T-E-4075 Revision 4, and procedure 0-0P-012, Service Water Operating Procedures, Revision dated August 26, 1986.
The valves were found in the closed position. This, in part, consti-tutes Example 3 of Violation 250,251/86-45-01; b)
Valve AFWU 009, located at the backup service water connection for the C AFW oil cooler, is incorrectly referenced on page 27 of procedure 0-0P-012 as valve AFWU 007.
Similarly, the procedure reverses valves 007 and 009 for the A AFW oil cooler.;
c)
The backup service water flexible hose which, according to note 2 on drawing 5610-T-E-4062, Sheet 3, Revision 44, is to be connected during extended periods of AFW pump recirculation operation or emergency, is connected and fully installed for the C AFW pump oil cooier.
Additionally, valve AFWU 009, which is required to be closed, appears to be partially open. This constitutes, in part, Example 3 of Viola-tion 250,251/86-45-01; d)
No procedure exists controlling the use of the backup service water system for the AFW oil coolers.
This constitutes Example 2 of Viola-tion 250,251/86-45-01. Additionally, the service water hose for the B AFW pump oil cooler and its associated connection do not have any mechanism for preventing the entry of foreign material; e)
Valves AFWU 23, 24 and 25 are not included in the system lineups of either the AFW or Service Water systems. Consequently, these valves are not checked closed prior to AFW system operation even though their position, if open, would reduce the normal cooling water flow; f)
Valve 70-102, backup service water supply to the A AFW pump oil cooler, is improperly supported, in that wire has been used to tie the valve to instrument air piping for support;
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. Procedure 0-0P-012 is deficient, in that numerous service water valves,
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including the isolation valve for AFW pump cooling, do not have valve numbers assigned; h)
Scaffolding has been installed such that it is in direct contact with AFW valve FCV-3-2833, train 2 flow to the 3C steam generator.
Additionally, scaffolding has been installed adjacent to or above both trains of AFW for Unit 4.
This constitutes, in part, - Example 1 of Violation 250,251/86-45-01; i)
Armored cable for the C AFW pump control, located at TB 3574, is degraded in that the shielded cable has pulled away from the conduit connector. Additionally, the rubber coating on a second cable is torn; j)
Two large boards have been stored above Unit 4 steam emit valve MOV-4-1404, creating an unnecessary hazard in the event of a seismic occurrence. This constitutes, in part, Example 1 of Violation 250,-
251/86-45-01; k)
A nitrogen tubing support clip is missing above the Unit 3 AFW nitrogen bottle station; 1)
The emergency exit from the AFW pump area is not marked to indicate that use of the exit constitutes entry into the RCA; m)
Unit 3. instrument piping for feedwater flow transmitters FT 477 and FT 487 appears to be inadequately supported; and n)
Unit 4 instrument piping for feedwater flow transmitters FT 776 and FT 477 appears to be inadequately supported and, as a result, deformed apparently from nearby scaffolding.
10.
Plant Events (93702)
An independent review was conducted of the following events.
On November 6,1986, while the B Emergency Diesel Generator (EDG) was out of service for maintenance of the key bypass switch and temperature gauge calibration, the A EDG was declared out of service following the required daily one hour operability run when it failed to properly shut down. An operability test of the B EDG was immediately commenced and it was subse-quently placed back in service. Investigation revealed the cause of the A EDG malfunction was that the solenoid plunger on the engine governor was out of adjustment. Although the A EDG had been declared out of service, because of the affected shutdown sequence, the A EDG was still capable of performing its intended function.
On November 10, 1986, while operating at 100% reactor power, Unit 4 tripped due to low level of the C steam generator. The cause of the level transient was a failed instrument air solenoid coil for the 4C S/G feedwater flow control valve.
Further discussion of this event is in paragraph o
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On November 14,1986, a Unit 3 load reduction was commenced as a result of an apparently cocked #2 seal on the 3B reactor coolant pump.
The operator increased pressure in the Volume Control Tank (VCT) to aid in reseating the seal.
3B RCP seal leakoff was recovered and VCT pressure was maintained greater than 30 psig until leakoff stabilized. The apparent cause of the problem was attributed to drastic changes in VCT level / pressure due to the performance of charging pump periodic testing that was in progress.
On November 17, 1986, a Unit 4 (4C) accumulator was declared out of service for approximately four hours. A leak, subsequently determined to be from a vent valve on the accumulator system piping, resulted ir. operations person-nel having to closely monitor and fill the accumulator more frequently than previously performed.
While filling the accumulator on November 17, the safety relief valve lifted at approximately 660 psig and reseated at approximately 340 psig. As the lift setpoint for the relief valve is 700 psig the relief apparently lifted early which resulted in the accumulator being declared out of service. At this time the licensee determined that a vent valve inside containment (4-940H) which was leaking had caused the accumulator level to decrease at an excessive rate.
Vaive 4-940H was backseated to prevent further leakage. After ensuring that pressure, level and boron concentration were within specification the accumulater was returned to service.
On November 18, 1986, the A steam generator feedwater regulating valve failed partially closed due to failure of the instrument air line between the positioner and the valve actuator.
The plant handled the ensuing transient as designed with several discrepancies noted on secondary plant equipment.
These discrepancies were addressed by the post event response
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team and appropriate corrective action was coordinated.
On December 5, 1986, a Unit 4 control room ventilation and containment isolation occurred as a result of a spurious actuation of radiation monitor R-11.
All appropriate automatic actions were verified to occur.
The channel was subsequently declared out of service for troubleshooting.
On December 6, 1986, Unit 4 rod position indication (RPI) was lost for approximately five minutes.
Maintenance troubleshooting resulted in tripping of the power supply to lighting panel LP-417 which is the emergency power supply for RPI.
The normal power supply for RPI was out of service for troubleshooting and repair.
On December 10, 1986, the C AFW pump, normally aligned to train I, was aligned to train II to support planned maintenance on the B pump trip and throttle valve. While attempting to perform operability testing of the C pump in this configuration, the operator inadvertently opened MOV-1405, steam supply valve to the A pump (train I) causing it to start.
The operator, realizing his error, secured the pump and verified the AFW system alignment. The C pump was subsequently tested satisfactorily en train II.
In the review of this occurrence, the NRC considered the criteria of 10 CFR Part 2, Appendix C, V.A., and concluded that a notice of violation would not be issue,
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On December 13 and again on December 14, 1986, R-11 spiked.high resulting in a Unit 4 control room ventilation and containment. isolation.
All appro-priate automatic actions were verified to occur.
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