IR 05000250/1986035
| ML17346B236 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 10/08/1986 |
| From: | Brewer D, Elrod S, Macdonald J, Van Dyne K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17346B235 | List: |
| References | |
| 50-250-86-35, 50-251-86-35, NUDOCS 8610210405 | |
| Download: ML17346B236 (29) | |
Text
~P,S REGS, fp.0 Cy C
O 0p*~4 UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos.:
50-250/86-35 and 50-251/86-35 Licensee:
Florida Power and Light Company 9250 West Flagler Street Miami, Florida 33102 Docket Nos.:
50-250 and 50-251 License Nos.:
DPR-31 and DPR-41 Facility Name:
Turkey Point 3"and 4 Inspection Conducte August 5 September 8,
1986 Inspectors:
D.
R Br er, n or Res'nt nsp ctor Da e
igned K.
W.
V Dyne, Resident nspect t
J.
.
acD d, Resident Inspector Approved by:
Step en A. Elr
,
ection C
ef Division of Reactor Projects Da e Signed g6 D te Signed D te Signed SUMMARY Scope:
This routine, unannounced inspection entailed direct inspection at the site, including backshift inspection, in the areas of licensee action on previous inspection findings, annual and monthly surveillance, maintenance observations and reviews, operational safety, independent inspection, design control and plant events.
Results:
No violations or deviations were identified.
8bl0210405 8bl010 PDR ADOCK 05000250
I'a-c,
REPORT DETAILS Licensee Employees Contacted
- 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
"D. D. Grandage, Operations Superintendent 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 Supervisor D. Tomasewski, Instrument and Control (IC) Maintena J.
C. Strong, Electrical Department 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 Supervisor nce Supervisor Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, mechanics, electricians and security force members.
"Attended exit interview on September 9,
1986.
Exit Interview The inspection scope and findings were summarized during management interviews held throughout the reporting period with the Plant Manager-Nuclear and selected members of his staff.
An exit meeting was conducted on September 9,
1986.
The areas requiring management attention were reviewed.
Three unresolved items were identified:
Evaluate the adequacy of corrective actions to prevent recurrence of missed Technical Specification (TS)
required surveillance testing (paragraph 6) (250,251/86-35-01);
Evaluate the adequacy of Temporary Operating Procedure (TOP) 233 with respect to maintenance planning and coordination (paragraph 8)
(251/86-35-02);
and
Evaluate licensee compliance with the requirements of Administrative Procedure (AP)
0103.36, Control of Operator Aids and Temporary Information Tags (paragraph 8) (250,251/86-35-03).
The licensee did not identify as proprietary any of the materials provided to or reviewed by the inspectors during this inspection.
The licensee acknowledged the findings without dissenting comments'icensee Action on Previous Inspection Findings (92702)
(Closed)
Licensee Event Report (LER) 251/84-27.
On November 30, 1986, while Unit 4 was in refueling shutdown, residual heat removal (RHR) cooling flow was lost for 4 minutes due to the failure of pressure controller (PC) 405B.
Flow was manually restored and no temperature rise was observed.
PC 405B was replaced on November 30, 1984, under plant work order (PWO) 6443, with a new, calibrated controller.
PWO 6443 was reviewed and no maintenance or administrative discrepancies were identified by the inspectors.
RHR system operation subsequent to the controller replacement was observed to be satisfactory.
Corrective actions with this mechanical failure are complete.
(Closed)
This event was addressed in Inspection Report 250, 251/86-10 but remained open because the modified turbine runback motor time delay setpoint had not been incorporated in the precautions, limitations and setpoints (PLS)
document as required by administrative procedure (AP)
0140.2.
The required change to the PLS document was made on March 3, 1986.
All corrective actions for the mechanical failure identified in LER 250/84-29 are complete.
(Open)
Violation 250, 251/86-10-01.
This violation addressed three examples of failures to meet TS 6.8.1.
One of the examples was based on the same discrepancy discussed in LER 250/84-29, relative to replacement of the turbine runback motor.
The failure to include the revised motor time delay setting, as required by AP 0140.2 constituted example
"B" of the violation.
Corrective action for this item is complete, in that the required information was added to the PLS Document (page 18, revision dated March 3, 1986)
and AP 0140.2 was revised on June 19, 1986 to more clearly specify those administrative actions to be followed to ensure that setpoint changes are reviewed, approved and incorporated into reference documents.
Completion of the corrective action is documented under licensee corrective action tracking system (CTRAC) item 86-406.
Two additional examples of this violation have not yet been reviewed for corrective action completeness and remain open.
(Closed)
This event documents a personnel error on the part of a control room operator during a reactor shutdown.
Reactor power was reduced below 10 percent and the turbine was tripped in accordance with procedures.
Reactor power was subsequently allowed to exceed 10 percent.
Since the turbine was not latched, a reactor trip resulted as required by
the reactor protection system logic.
The personnel error was studied during licensed operator requalification training (Cycle I) as part of lesson plan 62-OL.
Presentation of the lesson plan was completed on April 12, 1985, as documented by letter PTN-TRNG-85-256.
(Closed)
This event documents a personnel error on the part of a nonlicensed operator.
The operator was instructed to remove the Unit 4 motor generator sets from service.
However, he removed the Unit 3 motor generator sets from service causing a Unit 3 reactor trip.
Door markings, which were removed at the time of the event, have been replaced.
Additionally, the plant has improved general area labeling and adopted a
color coding system to differentiate Unit 3 and Unit 4 equipment.
Color coded equipment tags and painted stripes clearly identify Unit 4 equipment as blue and Unit 3 equipment as tan.
By clearly labeling and color coding all equipment affecting safety, the licensee has reduced the recurrence of wrong unit events.
Requalification training relative to the color coding system was covered under lesson plan 62-0L, revision dated March 4, 1985.
(Closed)
Inspector Fol 1owup Item (IFI) 250, 251/85-04-02.
This IFI was originated because a concern existed that the post trip review instructions contained in AP 0103. 16 did not adequately address the need for supervisory concurrence that all required post trip maintenance actions were satisfactorily completed.
AP 0103. 16 was revised on April 24, 1985 to emphasize the review of maintenance issues.
The procedure requires that prior to reactor restart the cause of the trip be known, acceptably corrected, and all applicable safety considerations resolved.
Additionally, the Plant Supervisor - Nuclear, Shift Technical Advisor and Operations Supervisor must concur that the restart is justified.
Should any issue of safety concern not be fully resolved, the Plant Manager Nuclear must be consulted to determine the need for additional investigation, technical support and Plant Nuclear Safety Committee (PNSC)
review prior to reactor restart.
Completed maintenance reviews are assured by requiring the applicable maintenance department supervisors to sign page 30 of the procedure specifying maintenance findings and work performed; The maintenance department investigation of the problem is reviewed to verify that it supports the known sequence of events.
Discrepancies receive direct supervisory review'.
The review mechanisms established in AP 0103. 16, Appendix B, effectively preclude reactor restart, prior to completing reviews of corrective maintenance'Closed)
This event documented the identification of numerous fire protection water system flowpath valves which were not receiving, surveillance as required by TS.
The valves were survei lied as required within one day subsequent to the identification of the discrepancy under PWO 0622.
The valves were incorporated into AP 0103. 19, Monthly Verification of. Safety Related Systems Flowpaths, to meet TS requirements.
Additionally, the valves were incorporated into Maintenance Procedure (MP)
15537.2, Fire Protection Equipment Annual Maintenance, revision dated
'
March 29, 1985, to meet valve cycling requirements specified in TS 4.15.
MP 15537. 2 was subsequently superseded by procedure 0-OSP-016. 3, Annual Surveillance of Fire Suppression System Flow Path Valves.
The valves in question are included in 0-0SP-016.3.
(Closed)
Violation 250,251/85-06-02.
This violation identified five fire protection system flow valves that were not receiving surveillance testing as required by TS 4. 15.2.
Licensee corrective action was specified in letter L-85-222, dated June 6,
1985.
Surveillance procedure O-OSP-016.3 and AP 0103. 19 have been modified to include these valves.
The valves are now included in the appropriate surveillance tests.
(Closed)
This event documents a reactor shutdown due to the determination, on March 30, 1985, that both channels of the Unit 3 reactor subcooling margin monitoring instrumentation did not meet environmental qualification requirements.
The Unit 3 reactor remained shutdown to complete a
scheduled refueling outage.
On May 28, 1985, Plant Change/Modification (PC/M)
85-40 was completed.
The PC/M involved the application of an epoxy sealing compound around the temperature detector connections to the reactor head.
This increased the water tight integrity of the detectors, establishing a qualified life of 40 years.
The PC/M was completed prior to the Unit 3 reactor restart subsequent to the March 30, 1985 shutdown.
(Closed)
This event documents a
personnel error which resulted in an inadvertent Engineered Safety Features (ESF) actuation due to bumping the Uni't 3 main generator panel door located in the cable spreading room.
Workers from the System Protection Oepartment inadvertently tripped protection relay 86GT/G3.
Since similar events have occurred in the past, action was taken to restrict access to the portion of the cable spreading room'near the main generator relays.
A letter dated May 8, 1985, from the System Protection Supervisor to the Plant Manager-Nuclear documents the corrective action.
Work in specified areas of both the cable spreading room and the emergency diesel generator room requires prior notification of the System Protection Oepartment to assure that any work performed will not result in inadvertent relay actuation and subsequent plant transients.
Additionally, many panels known to be sensitive to jarring or bumping have been labeled with information signs.
The area around the main transformer relays in the cable spreading room is clearly isolated using tape barriers to preclude inadvertent entry.
(Closed)
This event documents the inadvertent starting of the A
emergency diesel generator by maintenance personnel who were performing relay timing adjustments in the Unit 3A sequencer cabinet.
Plant personnel inadvertently shorted a contact which provided a false indication of low voltage on the 3A 4160 volt bus.
Procedure changes have been made (On the Spot Change 3250 dated June 13, 1985)
to Temporary Operating Procedure (TOP)
160, 4160 Volt and 480 Volt Undervoltage Scheme Timer Test
\\
h
to require the removal and reinstallation of fuses to reduce the risk of inadvertently starting the sequencer.
Subsequently, TOP 160 was redesignated TOP 249 and the On the Spot Change was permanently incorporated.
Deenergizing the sequencer during maintenance will reduce the likelihood of inadvertent emergency diesel generator star ts.
(Closed)
This event documents personnel error which resulted in the use of an incorrect page of a procedure during 120 volt direct current ground isolation.
As a result, an incorrect breaker was opened and a partial ESF Train B actuation occurred.
A review of the procedure revealed that it adequately addressed the desired ground isolation steps.
The procedure was not adequately followed.
The worker was counselled by the Operations Supervisor on July 8, 1985, relative to the consequences of incorrect actions and the need to accurately implement procedural requirements.
(Closed)
This event documents the failure of Auxiliary Feedwater (AFW) flow control valve CV-3-2817 to close during system testing on July 26, 1985, The failure of the valve to fully stroke closed
.was the result of a misadjusted positioner.
The valve was repaired under PWO 7516.
Valve controller calibration was performed in accordance with MP 14007.30, which was subsequently superseded by procedure 3-PMI-075. 1, AFW Flow Indication and Control Instrumentation Calibration Channels.
Calibration data was reviewed by the inspector and found to be satisfactory.
The valve was returned to service on the same day it failed and was satisfactorily retested.
(Closed)
This event documents the failure to perform a
TS required axial flux surveillance until six days after it was due.
The surveillance was performed on September 19, 1985, and verification of proper axial flux was confirmed.
The cause of the event was personnel oversight in that responsible personnel did not realize that the surveillance was due.
Corrective action included the posting of the surveillance schedule on the reactor engineering bulletin board which enhances supervisory review of surveillance completion.
The responsible individual was immediately counselled as to the need to exercise greater care in ensuring that surveillance requirements were met.
Additionally, on November 6, 1985, the responsible individual conducted a training session on the event which was attended by the Reactor Engineering staff.
(Closed)
This event documents the failure of containment isolation valve SV-2819 to close during an operational test.
A set of contacts in the lockout relay in rack (}R 50 for containment ventilation isolation were determined to be dirty.
This prevented the isolation signal from reaching the valve.
The isolation valve was immediately closed to restore containment integrity.
PWO 6508 was implemented to clean the contacts.
Contactor 17 was replaced due to a broken tensioner.
Retesting was satisfactorily completed on January 4,
1985.
The PWO was reviewed and was determined to be effectively implemente i 4'il
(Closed)
On December 17, 1985, the A emergency diesel generator (EDG)
was declared out of service due to personnel error in recording temperature readings during surveillance testing.
The B
EDG was out of service at the time to permit the replacement of a control switch.
Subsequent testing of the A
EDG could not reproduce the single high pyrometer temperature reading recorded by a technician.
Subsequent staff review determined that the high pyrometer temperature indication was due to the operator incorrectly recording the temperature.
The B
EDG was tested and returned to service shortly after the A
EDG was thought to be inoperable.
The inspector reviewed the A EDG test data and verified that no actual high temperature condition existed on the A
EDG.
The A
EDG was returned to service after surveillance testing in accordan'ce with Operating Procedure (OP) 4304.1.
Members of the operating'staff have been made aware of the need to take accurate log readings to preclude uncertain knowledge of equipment status.
4.
Unresolved Items
~
5.
An unresolved item is a matter about which more information is r'equired to determine whether it is acceptable or may involve a violation or deviation.
Three unresolved items identified during this inspection are discussed in paragraphs 6 and 8.
Performance Enhancement Program The NRC has issued Confirmatory Order EA-20.
The Order confirms the FP&L commitment to implement the Turkey Point Performance Enhancement Program including the Phase II Assessment Program as described in FP8 L Letters L-86-112 and L-86-197.
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'nd were reviewed by personnel other than the individual directing the test, that deficiencies were identified, as appropriate, and were properly reviewed and resolved by management personnel and that system restoration was adequate.
For completed 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:
Procedure 4-0SP-75.3, Auxiliary Feedwater Nitrogen Backup. System Low Pressure Alarm Setpoint and Leakrate Verification;
Preoperational Procedure 0800. 109, Unit 4 Auxiliary Feedwater Nitrogen Backup System Test; Preoperational Procedure 0800. 111, Unit 4 Auxiliary Feedwater Steam Supply Replacement Valve Test; Preoperational Procedure 0800. 113, Unit 4 Auxiliary Feedwater Flow Control Valve Stability Test; Procedure OP 1804. 1, Axial Flux, Rod Oeviation and Rod Position Indication System Monthly Test; Procedure OP 3204.1, RHR Pump Monthly Surveillance Units 3 and 4; and Procedure OP 2604, 1, Boric Acid Transfer System - Periodic Test of Pumps.
Additionally, the following LERs were reviewed, they illustrate, in part, deficiencies identified in the area of TS Surveillance Requirements:
250/86-29 250/86-27 250/86-20 250/86-13 250/86-11 250/85-28 250/85-08 250/85-07 250/85"06 250/85-01 250/84-30 250/84-16 251/83-19 250/82"09 The review resulted in identification of the following concerns:
1.
The timeliness of reporting, in several instances part of the corrective action specified by the LER verifies that satisfactory performance was accomplished for surveillance testing which had previously missed testing within the TS required periodicity.
Yet the LERs in question were submitted in excess of 30 days after the satisfactory performance of the missed surveillances.
The implication here is that when a
surveillance test is performed it should be clearly known whether or not performance was within the TS time limit.
2.
The adequacy of the corrective action specified on the LERs.
In at least three separate instances TS surveillance test procedures were not implemented for license amendments.
- As a
result, required surveillances were not performed and were reported via LERs.
Subsequently, different surveillance test requirements from these same license amendments were identified that were also not performed within the required periodicit.
In general, the NRC is concerned with the number of instances were TS surveillance testing was not performed within the required time limits.
Based on the extent of corrective action taken thus far, and the apparent ineffectiveness to prevent similar occurrences, the NRC is concerned that the problem may not be fully bounded by the licensee.
Further review of the licensee's program for identification, incorporation, and scheduling of TS required surveillance testing continues.
The above concerns constitute an unresolved item (250/86-35-01),
Evaluate the Effectiveness of Corrective Action to Prevent Recurrence of Missed TS Required Surveillance Testing.
7.
Maintenance Observations (62703/62700)
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 accomplished using approved procedures and were inspected as applicable;
'hat procedures used were adequate to control the activity; that troubleshooting 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 gC 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 gC 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 gA program; and that housekeeping was actively pursued.
The following maintenance activities were observed and/or reviewed:
Repair of Auxiliary Feedwater System motor operated valve 4-1404 (PWO 64-5014) following identification of failure to operate properly during preoperational testing; Replacement of Auxiliary Feedwater System check valve 4-383 as a result of failure to meet seal leak testing acceptance criteria during preoperational testing; Replacement of Unit 4 control rod E-7 rod position indicator amplifier module (PWO 64-6776)
as a result of failure identified during rod drop testing (OP 1604.9) prior to initial criticality after refueling;
ii
Replacement'f Unit 4 control rod H-12 rod drive mechanism coil stack (PWO 64-6778)
as a result of failure identified during rod drop testing (OP 1604.9) prior to initial criticality after refueling; Replacement of Unit 4 control rod L-7 rod drive mechanism coil stack (PWO 64-6777)
as a result of failure identified during rod drop testing
, -(OP 1604.9) prior to initial criticality after refueling; Repair of Unit 3 Rod Control System mode switch rods stepped in when switch was placed in the automatic position (PWO 63-6895);
Replacement of Unit 4 Reactor Protection System Actuation Relay RT-5-B coil due to failure of coil insulation (PWO 64-6715);
Replacement of Unit 4 Reactor Protection System Actuation Relay RT-4-A coil due to failure (overheating)
of coil (PWO 64-6680);
Replacement of Unit 4 Reactor Protection System Actuation Relay RT-3-B coil due to failure of coil insulation (PWO 64-6714).
Ho violations or deviations were identified in the areas inspected.
8.
Operational Safety Verification The inspectors observed contro By observation and direct interviews, verification was made that the physical security plan was being implemented.
Plant housekeeping/cleanliness conditions and implementation of radiological controls were observed.
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.
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
I
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t
'1
The inspectors witnessed/reviewed portions of the following test activity to verify, in part, the ability of the black start cranking diesel generator's
=
to energize the Unit 3'nd 4 safety related buses:
'I Temporary Procedure 272, Phaseout Unit 4C Bus to 4A Bus Cable Using 4B Bus as Reference
'a ~
b.
On August 6, 1986, at the request of the NRC, the licensee successfully performed Temporary Procedure 272.
This test, in conjunction with previously obtained test results, was written to support the confirmation that the non-safety-related black start cranking diesel generators are capable of energizing safety related equipment.
The NRC requested that the licensee demonstrate the availability of the cranking diesel generator s to power the safety related buses as a
result of a discussion in the Emergency Diesel Generator (EDG) load evaluation, JPE-L-86-74, Rev.
1.
The conclusions reached in this evaluation were:
(1) the presence of the black start cranking diesel generators dramatically reduces the probability of not restoring an additional AC power source; and (2) an additional AC power source could be made available on the ordet of an hour post-LOCA.
The purpose of the test was to ensure proper phase angle, rotation, and magnitude of the 4160 volt bus tie cable from the 4A safety related bus to the 4C non-safety related bus.
The test also verified the operability of the opening and closing circuits of the 4AA09, 4AB22, and 4AC13 breakers from the control room.
The test methodology involved backfeeding the 4C bus from the 4A bus and then verifying the existence of the proper phase sequence.
On August 5, 1986, with Unit 4 in cold shutdown, a subcritical reactor trip occurred.
At the time of the trip, operations personnel were performing test 4-0SP-089, Main Turbine Operability Test, and l8C personnel were performing TOP-233, Functional Test of PC/M 84-211, Turbine Runback Modifications, and PC/M 84-209, Power Mismatch Modifications.
Procedure 4-OSP-089 required resetting of the reactor trip breakers, which are normally open during extended cold shutdowns.
The breakers did not immediately trip when reset because the P-7 and P-8 permissives blocked the Reactor Protection System actuation signals generated by system conditions during cold shutdown.
TOP-233 required simulation of turbine first stage impulse pressure above 705 power.
Upon input of this signal, the P-7 permissive was unblocked due to sensing turbine power above 105 and the trip logic was unblocked and the reactor trip breakers opened.
Of particular concern in reviewing the reactor trip was that two departments were performing separate tests without apparent knowledge of the unit test status.
One test, 4-0SP-089, put the unit in a
trippable condition by resetting the reactor trip breakers and the
A a
'A I
other, TOP-233, an apparent inadequate procedure, challenged the unblocked At-Power Trip signals and caused the subcritical trip.
The apparent inadequate-procedure, TOP-233, was a result of personnel oversight in the preparation and performance of the test in that, the procedure did not ensure that the At-Power Trip signals were clear or bypassed prior to simulation of 7'ower level.
When the test was performed, multiple trip signals were present and the reactor trip breakers opened.
Pending further review, this item will be identified as Unresolved Item (251/86-35-02),
Evaluate the adequacy of Temporary Operating Procedure (TOP) 233 with respect to maintenance planning and coordination.
c.
Included in the review of control room logs were the temporary information tag, operator aid, and caution tag indices.
Various discrepancies in the operator aids and temporary information tag logs were observed.
Among them were the following:
Authorization for posting tags did not appear to have been granted Authorization for removing tags-was not signed Work necessary to release tags was omitted.
Operations Department personnel periodically "clean-up" or update the logs by hand copying them over.
This practice compounds the difficulty of normal log keeping procedures since it is impractical to copy authorization signatures.
These discrepancies and control of operator aids, temporary information tags, and caution tags, in general, constitute an unresolved item (250,251/86-35-03)
pending further NRC review.
No violations or deviations were identified in the areas inspected.
9.
Independent Inspection During the report period the inspectors routinely attended meetings with-licensee management and monitored shift turnovers between shift supervisors',
shift foreman, and licensed operators.
These meetings included daily discussions of plant operating and testing activities as well as discussions of significant problems or incidents.
As a result, the inspectors reviewed potential problem areas to independently assess:
their importance to safety; the adequacy of proposed solutions; improvement and progress; and adequacy of corrective actions.
The inspectors'eviews of these matters were not 1'imited to the defined inspection program.
Independent inspection effort was continued in the area of EDG loading and implementation of design changes to preclude EDG overload.
Inspection effort in the area of plant security led to the identification of concerns relative to the control of access to vital areas.
A reactive inspection was conducted on September 2-5, 1986.
Inspection results are documented in Inspection Report 250, 251/86-3 t'
10.
Design Changes (37700)
As discussed in paragraph 8,
at the request of the NRC, the licensee performed a special test to verify, in part, the ability of the black start cranking diesel generators to energize the Unit
and 4 safety related buses.
As a
result of the preparation of the safety evaluation (JPE-L-86-91) for this special test, a single device was identified which coul'd adversely affect the ability of the EDGs to energize the Unit 3 and
safety related buses under emergency conditions.
Power Plant Engineering initiated an investigation to confirm this failure potential and to determine if other potential failures may exist on the 4160 volt lockout schemes.
Bechtel Power Corporation was requested to perform a Failure Modes and Effects Analysis (FMEA) on all inputs to the safety bus lockout schemes and on August 11, confirmed the potential for a single device to adversely affect the ability of the EDGs to energize both unit's safety related electrical buses.
Two types of devices were identified which could adversely affect the ability of safety related equipment to perform its intended function:
1)
The failure of auxiliary switch contacts 1-1T or 3-3T in the EDG supply breaker would cause a false input to the load sequencer such that, on loss of offsite power (LOOP) coincident with a safety injection on one
'nit, the automatic loading of two battery chargers would be blocked.
Failure of both contacts could result in the inability to automatically load any of four battery chargers.
However, a battery charger bypass
'switch located in the control room can be use'd to place the battery chargers on the appropriate buses even though contacts 1-1T and/or 3-3T have failed.
The requirement to use the bypass switch in the event the failure mode described above should occur has been incorporated in the plant emergency operating procedures.
The battery chargers will be restored within 30 minutes of the LOOP, meeting the battery capacity assumptions and time limitations described in the Final Safety Analysis Report (FSAR).
2)
The failure of any one of four separate overcurrent auxiliary relays (174X/TDDO), each of which is located in a separate 4160 volt vital bus tie breaker, could cause isolation of both the A and B 4160 volt buses and prevent closing the the A and.B EDG output'reakers.
The unit which suffered the relay failure would be left without any power to the vital 4160 volt buses.
Should the unit not experiencing the relay failure require an ESF actuation, the EDGs could also fail to close on that unit's vital buses.
The potential for, and the effects of, the failures discussed above were evaluated by the licensee in a safety evaluation (JPE-L-86-92, Rev. 0) dated August 14, 1986, and Rev.
1 dated August 15, 1986.
The evaluation specified lifting the electrical leads for the affected relays as an interim solution to disable the four overcurrent auxiliary
gl
'k
0 relays associated with the Unit
and
safety related bus tie breakers.
This interim solution is acceptable because the tie breakers are normally maintained open and racked out.
The breaker s would only be shut to allow the A and B 4160 volt vital buses to be operated in parallel (a situation which is not administratively or procedurally authorized)
or to allow energizing the A or B bus from the cranking diesels (a situation that would 'exist only if both EDGs had already failed).
Consequently, the loss of the overcurrent protection function associated with the tie breakers does not hazard plant operations.
Disconnecting the relays prevents the above mentioned failures from occurring even when the breakers are open and racked out (during normal plant operations)
and thus contributes to safety.
The licensee is evaluating the relay failure problem to determine if reporting in accordance with 10 CFR Part 21 is appropriate.
11.
Plant Events (93702)
An independent review was conducted of the following events.
On August 5, 1986, Unit 4 experienced a subcritical reactor trip as the result of personnel oversight in the'reparation of TOP-233, Functional Test of PC/M 84-211 Turbine Runback Modifications and PC/M 84-209 Power Mismatch Modifications.
No transient occurred because the plant was in cold shutdown and all control rods were fully inserted.
This event is discussed in more detail in paragraph 8.
On August 9, 1986, with Unit 4 in cold shutdown, the auxiliary feedwater (AFW) system automatically actuated as a result of Low-Low steam generator level in the 4C steam generator.
The cause of the actuation was personnel error in conjunction with excessive feedwater bypass valve leakage.
The 4C feedwater bypass valve was isolated during AFW testing due to excessive leakage.
After completing the AFW system testing the 4C bypass valve was not restored to service.
Level in the 4C steam generator decreased slowly, as is expected when maintaining temperature by using the atmospheric steam valves and not replenishing the water supply.
The Control Room Operator failed to correct the lowering level and apparently did not realize that the bypass valve was isolated.
The actuation of the AFW system corrected the low level condition.
The 4C bypass valve was restored to service.
On August 13, 1986, Unit 3 tripped from a steady state power level of 53 percent due to an apparent low pressurizer pressure trip.
An actual low pressure condition did not exist.
A severe thunderstorm was in progress and
,several close lightning strikes were reported near the containment buildings along with arcing on the Unit 3 and 4 main and startup transformers.
Plant equipment performed as designed following the trip.
Analysis of the event concluded that a nearby lightning strike induced a transient signal in the pressure instrument loops causing false low pressure signals to be received by the reactor protective system.
A lightning strike was determined to have caused a similar low pressure reactor trip of Unit 3 on July 21, 1985.
That event was described in LER 250/85-1 On August 15, 1986, Juno Power Plant Engineering (JPE) identified a single failure scenario that could prevent the EDGs from from energizing the Units 3 and 4 safety related 4160 volt vital buses under certain conditions.
Further information on the ensuing investigation and safety evaluation is detailed in paragraph 10.
On August 21, 1986, while performing Preoperational Procedure (POP)
0800. 111, AFW Steam Replacement Valve Test, 4C steam supply check valve 4-383 failed to seat, causing excessive leakage.
This rendered train A of AFW inoperable.
Unit 4 was placed in mode 4 as required by TS 3.0. 1.
and the failed check valve was replaced and satisfactorily tested.
On August 23, 1986, Unit 4 was manually tripped from approximately lX power due to failure of redundant power supplies in one of four power supply cabinets for the rod control system.
One of two redundant power supplies (PS-2)
in power cabinet 2BD had failed on August 5, 1986 and replacement parts were on order to affect repairs (PWO 64-6672).
Subsequently, PS-1 failed on August 23, 1986, which caused a loss of all voltage in power cabinet 2BD and resultant drop all group 2 rods in control banks B and D and shutdown bank,B.
Both power supplies were replaced/repaired, post maintenance testing was performed satisfactorily, and the unit was returned to power.
On September 6,
1986, Unit 4 experienced a reactor trip from 38K power due steam generator 4B steam flow greater than feed flow in conjunction with low level automatic trip.
The apparent cause of the trip was a short circuit in the Train B safeguards panel supply (relay rack R-44) indication circuit of the loop C feedwater isolation light (Ill).
The short circuit isolated the C -steam generator feedwater supply and tripped the operating feed pump which resulted in the automatic trip.
The short circuit was repaired, satisfactorily retested, and the unit was returned to power.
Review of Plant Operations (71711)
Unit 3 came off line on July 15, 1986, to complete electrical modifications required to resolve the EDG overload evaluation.
The outage was scheduled for eighteen days with the electrical system modifications and RHR motor end bell inspections/rework as critical path items.
Based on ultrasonic examination the end bells were determined to be in satisfactory condition.
The electrical system modifications were completed and tested satisfactorily and the outage lasted nineteen days.
No significant primary system problems were encountered in returning the unit to service.
The secondary system experienced several problems.
On August 21, 1986, the unit was forced to come off the line as a result of a main condenser tube leak apparently due, in part, to a free bolt in the tube bundle.
Also discovered at this time was a hole in the 3B condensate pump suction piping.
An ongoing problem exists with a leaking condenser boot seal.
The licensee intends to effect long term repairs in the form of a major overhaul during the next refueling outage.
The interim solution has been to seal the leak with condensate flow to prevent air from entering the secondary system.
C
'
Unit 4 was in an extended outage as a result of the EOG overload evaluation.
Restart was contingent upon completion of electrical system modifications.
Subsequent to the successful testing of these modifications, simultaneous unit operation was authorized by the NRC.
The following is a brief summary of delays encountered in attempting to achieve rated power.
Multiple control rod failures were experienced during testing at normal operating temperature although satisfactory performance of the rod control system was observed during cold shutdown testing.
Subsequent repair/replacement of control rod drive mechanism instrumentation resulted in a delay of power operation by several days.
On August 20, 1986, the 4C AFW steam supply check valve (4-383)
was replaced.
Start-up personnel identified excessive seat leakage through the valve during acceptance testing of modifications made to the AFW system.
Unit operation was further delayed as a result of high vibration in the exciter.
The Unit 4 exciter had been replaced during the outage as a preventive maintenance measure.
As a result, required balancing of the reworked exciter was not unexpected but the initial turning of the turbine revealed exciter vibration of such magnitude that the exciter was again replaced.
The licensee continued to experience difficulty in balancing the exciter and several weight balancing shots had to be performed to reduce vibration.
Maintenance personnel now believe that balancing difficulties observed with both exciters are attributable instead, to the generator rotor.
In fact, both exciter shafts are believed to be true and that during the extended outage the generator rotor bowed.
Since the reworked exciter was coupled to the bowed generator and therefore misaligned, the high vibration was manifested in the exciter shaft.
During this period, the 4A feedwater regulating bypass valve (4-FCV-479)
was also repaired because control of steam generator level was difficult at low feedwater flow rates and the possibility of a reactor trip was of concern.
Throughout the start up period, the secondary system experienced chemistry conditions which resulted in many holds at low power levels.
These conditions were attributed to welding operations related to the moisture separator reheater demister modifications.