IR 05000250/1991050
| ML17348B384 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 01/22/1992 |
| From: | Butcher R, Landis K, Schnebli G, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17348B383 | List: |
| References | |
| 50-250-91-50, 50-251-91-50, NUDOCS 9202140098 | |
| Download: ML17348B384 (26) | |
Text
gpss RECII Wp0 UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MAR IETTA ST R E E 7, N.W.
ATLANTA,GEORGIA 30323 Report Nos.:
50-250/91-50 and 50-251/91-50 Licensee:
Florida Power and Light Company 9250 West Flagler Street Miami, FL 33102 Docket Nos.:
50-250 and 50-251 Facility Name:
Turkey Point Units 3 and
License Nos.:
DPR-31 and DPR-41 Inspection Conducted:
November 23 through December 27, 1991 Inspectors:
R.
C. Butcher, Senior Resident Inspector
~.G. A. Schnebli, Resi ent Inspector c
~
~
~
.I~L. Trocine, Res dent Inspector Approved by:
K.
. Landis, Chief Reactor Projects Section
Division of Reactor Projects 0 te Si ed D te Si, ned Da e
S gned Date Signed SUMMARY Scope:
This routine resident inspector inspection entailed direct inspection at the site in the areas of monthly surveillance observations, monthly maintenance observations, operational safety, plant events, a
management meeting, and Temporary Instruction 2515/103.
Results:
Within the scope of this inspection, the inspectors determined that the licensee continued to demonstrate satis'factory performance to ensure safe plant operations.
In addition, the licensee, through self assessment, took prompt action to correct the following non-cited violations:
50-250,251/91-50-01, Non-Cited Violation -
Failure to follow the requirements of Technical Specification 6.8. 1 resulting in the inadvertent rapid start of the 3A emergency diesel generator (paragraph 4).
50-250,251/91-50-02, Non-Cited Violation - Failure to check procedure index to ensure that latest revision of procedure was being utilized (paragraph 6).
9202140098 920122 PDR ADQCK 05000250
'DR
Persons Contacted REPORT DETAILS Licensee Employees T.
V. Abbatiello, guality Assurance Supervisor
- L. W. Bladow, Site guality Manager
- R. J. Gianfrencesco, Support Services Supervisor
- S. T. Hale, Engineering Project Manager K. N. Harris, Senior Vice President
- Nuclear Operations E.
F.
Hayes, Instrumentation and Controls Maintenance Supervisor R.
G. 'Heisterman, Mechanical Maintenance Supervisor
- D. E. Jernigan, Technical Manager
"H. H. Johnson, Operations Supervisor
- Y. A. Kaminskas, Operations Manager
- J.
E. Knorr, Regulatory Compliance Analyst J. D. Lindsay, Health Physics Supervisor G. L. Marsh, Reactor Engineering Supervisor L.
W. Pearce, Plant General Manager N. 0. Pearce, Electrical Naintenance Supervisor
- T. F. Plunkett, Site Vice President D. R. Powel.l, Services Manager C. V. Rossi, guality Assurance Supervisor R.
N. Steinke, Chemistry Supervisor
, F.
R. Timmons, Security Supervisor M. B. Wayland, Maintenance Manager J.
D. Webb, Outage Manager (acting)
Other licensee employees contacted included construction craftsman, engineers, technicians, operators, mechanics, and electricians.
NRC Resident Inspectors
"R. C. Butcher, Senior Resident Inspector G. A. Schnebli, Resident Inspector
- L. Trocine, Resident Inspector
- Attended exit interview on December 2?,
1991 Note:
An alphabetical tabulation of acronyms used in this report is listed in the last paragraph in this report.
Plant Status Unit 3 At the beginning of this reporting period, Unit 3 was operating at a
reduced power level of 56K in order to permit maintenance on the 3B heater drain pump.
This unit has been on line since October 4, 1991.
The following evolutions occurred on Unit 3 during this assessment period:
On November 23, 1991, at 3:10 a.m.,
a load reduction to less than 360 HWe (approximately 54K power)
was commenced in order to stop the second heater drain pump for seal water isolation.
On November 23, 1991, at 4: 10 a.m., Unit 3 reached 54K power.
On November 24, 1991, at 12:05 a.m.,
power escalation to SQX was commenced.
On November 24, 1991, at 4:00 a.m., Unit 3 reactor power was stable at 80%.
On November 24, 1991, at 8:40 a.m.,
power escalation was recommenced after satisfactory verification of 3B heater drain pump seal operation.
On November 24, 1991, at 10:55 a.m., reactor power reached 100K.
On November 28, 1991, at 12:37 p.m., the right turbine st'op valve closed due a momentary auto oil pressure transient, and reactor power was stabilized at approximately 500 MWe (75K power).
(Refer to paragraph 9.c for additional information.)
On November 28, 1991, at 1:25 p.m.,
power escalation to lOOX was commenced.
On November 28, 1991, at 6:00 p.m., Unit 3 reactor power was stable at 100%.
Unit 4 At the beginning of this report period, Unit 4 was operating at 100K power, and the unit had been-on line since October 29, 1991.
The following evolutions occurred on Unit 4 during this assessment period.
On November 25, 1991, at 5:30 p.m.,
a load reduction to 30% power was commenced due to a condenser tube leak (secondary chemistry off-normal). (Refer to paragraph 9.a for additional information.)
On November 25, 1991, at 6:10 p.m., reactor power, reached 30K.
On November 26, 1991, at 10:40 a.m.,
power escalation to 50% was commenced.
On November 26, 1991, at 12:40 p.m., reactor power reached 50%.
On November 28, 1991, at 7:00 a.m.,
a load increase to 100K power was commenced.
On November 28, 1991, at 2:00 'p.m., Unit 4 reached 100K reactor power.
On December 10, 1991, at 5:37 p.m.,
an Unusual Event was declared, and a reactor shutdown was commenced due to a failure on the 4A sequencer.
(Refer to paragraph 9.e for additional information.)
On December 10, 1991, at 7:33 p.m., the turbine was taken off line.
On December 10, 1991, at 7:37 p.m., Unit 4 entered Mode 3.
On December 10, 1991, at 10:15 p.m.,
an RCS cooldown to Mode 4 was commenced.
On December 11, 1991, at 1:42 a.m., Unit 4 entered Mode 4.
On December 11, 1991, at 5:25 a.m.,
a boric acid buildup was
observed on several valves and at the southeast conoseal.
(Refer to paragraph 9.f for additional information.)
On December 11, 1991, at 6: 10 p.m.,
RCS cooldown was. recoranenced in order to repair conoseal leakage.'n December ll, 1991, at 9: 15 p.m., the 4A sequencer was declared back in service, and the Unusual Event was terminated.
On December 12, 1991, at 5:55 p.m., Unit 4 entered Mode 5.
On December 13, 1991, at 5:40 a.m.,
the RCS was fully depressurized.
On December 16, 1991, at 2:20 a.m., the conoseal repairs were completed, and the RCS filling and venting procedure was commenced.
On December 16, 1991, at 8: 10 p.m., Unit 4 entered Mode 4.
. On December 17, 1991, at 4: 14 a.m., Unit 4 entered Mode 3.
On December 18, 1991, at 9:50 a.m., Unit 4 entered Mode 2, and criticality was achieved.
On December 18, 1991, at ll:55 a.m., Unit 4 entered Mode 1.
On December 18, 1991, at 4:38 p.m., the turbine was placed on line.
On December 18, 1991, at 5:42 p.m., Unit 4 reached 27K power.
On December 19, 1991, at 8:50 a.m.,
a load reduction for turbine overspeed testing and valve testing was commenced.
On December 19, 1991, at 9:28 a.m., Unit 4 entered Mode 2.
On December 19, 1991, at 9:40 a.m., the turbine overspeed test trip occurred at 1980 rpm.
On December 19, 1991, at 10:52 a.m., Unit 4 re-entered Mode 1, and the turbine was placed back on line.
On December 19, 1991, at 9:00 p.m., Unit 4 reached lOOX power.
3.
Followup on Items of Noncompliance (92702)
A review was conducted of the following noncompliances to assure that corrective actions were adequately implemented and resulted in conformance with regulatory requirements.
Verification of corrective action was achieved through record reviews, observation, and discussions with licensee personnel.
Licensee correspondence was evaluated to ensure the responses were timely and corrective actions were implemented within the time periods specified in the reply.
(Closed)
VIO 50-250,251/91-37-01, Failure to Follow Procedure During the Installation of the Unit 3 Reactor Vessel Cavity Seal Ring.
The licensee responded to this violation in FPL letter L-91-318 dated November 22, 1991.
The inspectors reviewed the corrective actions taken to prevent recurrence and found them to be adequate.
This violation is closed.
4.
Followup on Inspector Followup Items (92701)
Actions taken by the licensee on the item listed below were verified by the inspecto (Closed)
URI 50-250,251/91-31-01, Determine Cause for Inadverten't Rapid Start of the 3A EDG.
This event occurred on August 22, 1991, when startup personnel were performing a wiring scheme verification on leads located in a
newly replaced cable in the 3A EDG rapid start circuit.
When they lifted the rapid start leads, the 3A EDG star ted due to shorting the leads together.
The leads were re-landed, and the
'EDG was shut down.
The cause of the event was inadequate communication between startup personnel and licensed operators.
The NWE and the APSN knew the work involved the 3A EDG but were unaware that leads would be lifted.
The RCO knew that leads would be lifted but thought the work was on, the
EDG.
Had the proper precautions been taken, such as notification of the PSN in conjunction with an isolation on the proper control circuits, this situation would not have occurred.
At the time of this event, the 3A EDG was not required to be operable as the unit was shut down and defueled.
The license =took prompt'orrective actions by revising startup field procedures to require that the PSN give concurrence, by signature, to perform any scheme verifications on an energized circuit.
Startup personnel were immediately trained on the procedure revisions, and licensed operators were briefed on the event and the implications of ineffective communications.
TS 6.8;1 requires that written procedures be established, implemented, and maintained covering activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2,
February 1978.
Section 9.a of this Appendix recommends that maintenance that can affect the performance of safety-related equipment be properly preplanned'nd performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances.
The recommendations stated above were not fol1owed in that on August 22, 1991, maintenance on the 3A EDG was not properly preplanned or performed causing the inadvertent rapid start of the 3A EDG.
This violation is not being cited because the criteria specified in Section V.G.1 of the NRC Enforcement Policy were satisfied.
This item will be tracked as NCV 50-250,251/91-50-01, failure to follow the requirements of TS 6.8.1 resulting in the inadvertent rapid start of the 3A EDG.
This item is closed.
Onsite Followup and In-Office Review of Written Reports of Nonroutine Events and
CFR Part 21 Reviews (90712/90713/92700)
The Licensee Event Reports and/or
CFR Part 21 Reports discussed below were reviewed.
The inspectors verified that reporting requirements had been met, root cause analysis was performed, corrective actions appeared appropriate, and generic applicability had been considered.
Additionally, the inspectors verified the licensee had reviewed each event, corrective actions were implemented, responsibility for corrective actions not fully completed was clearly assigned, safety questions had been evaluated and resolved, and violations of regulations or TS conditions had been identified.
When applicable, the criteria of 10 CFR Part 2, Appendix C, were applie (Closed)
LER 50-251/91-02, 4A EDG Permanent Magnet Generator Failure Due to Design Inadequacy.
Due to continued problems with this component, the licensee removed the PMG from the 4A and 4B EDGs.
The removed PNGs were replaced with a system powered from the 125-volt DC station batteries which is similar to the existing configuration of the original 3A and 3B EDGs.
This LER is closed.
(Closed)
LER 50-251/91-05, Containment and Control Room Ventilation Isolation Following Inadvertent Opening of Output Breaker to Inverter
Due to Personnel Error by Construction Worker.
This issue was previously discussed in
,NRC Inspection Report Ho. 50-250,251/91-31.
The inspectors reviewed the licensee's corrective actions to prevent recurrence and determined them to be adequate.
This
'ER is closed.
6.
Monthly Surveillance Observations (61?26)
The inspectors observed TS required surveillance testing and verified that the test procedure. conformed to the requirements of the TSs; testing was performed in accordance with adequate procedures; test instrumentation was calibrated; limiting conditions for operation were met; test results met acceptance criteria requirements and were reviewed by personnel other than the individual directing the test; deficiencies were identified, as appropriate, and were properly reviewed and resolved by management personnel; and system restoration was adequate; For completed tests, the inspectors verified testing frequencies were met and tests were performed by qualified individuals.
The inspectors witnessed/reviewed portions of the following test activities:
Operating Procedure 9404.2, 480-Volt Swi tchgear-Undervoltage Test, for the 3B and 3D 480-volt load centers; 3-SNI-041.6, RCS Instrumentation Protection Set II, Channel F-3-435 Analog Test; 3-0SP-059.5, Power Range Nuclear Instrumentation Shift Checks and Daily Calibrations; 4-0SP-089, Section ?.1, Main Turbine Valves Operability Verification; 4-OSP-089. 1, Turbine Generator Overspeed Trip Test; and 4-0SP-200.3, Section ?.2, Main Turbine Trips Tes During performance of procedures 3-SMI-041.1 through 3-SMI-041.9 on December 6,
1991, IKC'ersonnel identified that an outdated version of procedure 3-SMI-041.6 (referenced above)
was being utilized for performance of the monthly analog channel operational test for reactor coolant flow protection set II, channel F-3-435.
The procedure being utilized was dated December 18, 1987, in lieu of the current revision dated May 21, 1991.
This procedure had been obtained from the document control spare copies file but had not been checked against the procedure index to ensure that the latest revision was being utilized.
TS 6.8. 1 requires that written procedures be established, implemented, and maintained covering activities recommended in Appendix A of Regulatory
. Guide 1.33,.
Revision 2, February 1978, and Sections 5. 1 and 5.3 of ANSI N18.7-1972.
Sections 8 and 9 of Appendix A of Regulatory Guide 1.33, Revision 2, February 1978, recommend procedures for safety-related activities involving surveillance test, 'procedures, and calibrations and involving the performance of maintenance.
Paragraphs 5.3.5 and'5.3.6 of ANSI N18.7-1972 require the provision of procedures for maintenance and for periodic calibration testing of safety-related plant instrumentation.
Paragraph 5.3. 1 of procedure O-ADM-715, Maintenance Procedure Usage, dated December 31, 1990, requires that all maintenance personnel performing a
maintenance procedure check the procedure index in the control room or in document control to ensure that the latest'evision is being utilized.
Contrary to these requirements, on December 6,* 1991, an outdated version of procedure 3-SMI-041.6, RCS Flow Instrumentation Protection Set II, Channel F-3-435 Analog Test, was being utilized for performance of'he monthly analog channel operational test.
.
This licensee-identified violation is not being cited because the criteria specified in Section V.G. 1 of the NRC Enforcement Policy were satisfied.
This item
'will be tracked as NCY 50-250,251/91-50-02, failure to check procedure
'index to ensure that latest revision of procedure was being utilized.
This item is closed.
With the exception of the NCV documented above, the inspectors'etermined that the above testing activities were performed in a satisfactory manner and met the requirements of the TSs.
Violations or deviations were not identified.
Monthly Maintenance Observations (62703}
Station maintenance activities of safety-related systems and components were observed and reviewed to ascertain they were conducted in accordance with approved procedures, regulatory guides, industry codes and standards, and in conformance with the TSs.
The following items were considered during this review, as appropriate:
LCOs were met while components or systems were removed from service; approvals were obtained prior to initiating work; activities were accomplished using approved procedures and were inspected as applicable; procedures used were adequate to control the activity; troubleshooting activities were controlled and repair records accurately reflected the maintenance performed; functional testing and/or calibrations were
4
e 8.
performed prior to returning components or systems to service; gC records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were properly implemented; gC hold points were established and observed where required; fire prevention controls were implemented; outside contractor force activities were controlled in accordance with the approved gA program; and housekeeping was actively pursued.
The inspectors witnessed/reviewed portions of the following maintenance activities in progress:
repair of Unit 4 condenser tube leaks, repair of Unit 4 southeast conoseal leak, repacking and valve inspection of 4C charging pump, and troubleshooting and repair of 4A sequencer failure (Refer to paragraph g.e for additional information.).
For those maintenance activities observed, the inspectors determined that the activities were conducted in a satisfactory manner and that the work'as properly performed in accordance with approved maintenance work orders.
Violations or deviations were not identified.
Operational Safety Verification (71707)
The inspectors observed control room operations, reviewed applicable logs, conducted discussions with control room operators, observed shift turnovers, and monitored instrumentation.
The inspectors verified proper valve/switch alignment of selected emergency systems, verified maintenance work orders had been submitted as required, and verified 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 direct interviews, verification was made that the physical security plan was being implemented.
The implementation of radiological controls and plant housekeeping/cleanliness conditions were also 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/structures to verify proper valve/switch alignment:
A and B emergency diesel generators, control room vertical panels and safeguards racks,
intake cooling water structure, 4160-volt buses and 480-volt load and motor control centers, Unit 3 and 4 feedwater platforms, Unit 3 and 4 condensate storage tank area, auxiliary feedwater area, Unit 3 and 4 main steam platforms, and auxiliary building.
The licensee routinely performs QA/QC audits/surveillances of activities required under its QA program and as requested
.by management.
To assess the effectiveness of these licensee audits, the inspectors examined the status, scope, and findings of the following audit reports:
. Number of Audit Number
~Findin s
T e of Audit QAO-PTN-91-052 QAO-PTN-91-059 QAO-PTN-91-064 QAO-PTN-91-065 QAO-PTN-91-066 QAO-PTN-91-069 QAO-PTN-91-071 QAO-PTN-91-074 QAO-PTN-91-076 National Technical Systems On-Site Services Analysis and Neasurement Services On-Site Activities fermanite Testing of Nain Steam Safety Valves Secondary Water Chemistry
October Performance Nonitoring Audit Verification of Design Cycle Records Implementation of INPO Commitments Physical Security Pl an and
CFR 73.55(g)(4)
Requirements TS 6.10, Record Retention No additional NRC followup actions will be taken on the findings referenced above because they were identified by the licensee's QA program audits and corrective actions have either been completed or are currently underway.
Plant management has also been made aware of these issues.
As a result of routine plant tours and various operational observations, the inspectors determined that the general plant and system material conditions were satisfactorily maintained, the plant security program was effective, and the overall performance of plant operations was good.
Violations or deviations were not identifie e
9.
Plant Events (93702)
Th'e following plant events were reviewed to determine facility status and the need for further, followup action.
Plant parameters were evaluated during transient response.
The significance of the.event was evaluated along with the performance of the appropriate safety systems and the actions taken by the licensee.
The inspectors verified that required notifications were made to the NRC.
Evaluations were performed relative to the need for additional NRC response to the event.
Additionally, the
.
following issues were examined, as appropriate:
details regarding the cause of the event; event chronology; safety system performance; licensee compliance with approved procedures; radiological consequences, if any; and proposed corrective actions.
a.
On November 25, 1991, at 5:30 p.m., Unit 4 reduced load to less than 30'A due to a condenser tube leak.
The suspect tubes were plugged, and the unit returned to 100K power at 2:00 p.m.
on November 28, 1991.
(Refer to paragraph 2 for additional information regarding times for changes in plant status.)
b.
On November 27, 1991, at 5:45 p.m., the Unit 3 and 4 control room was notified by the Hazardous Waste Coordinator that a one gallon diesel fuel oil spill occurred at the sites'ossil units.
The spill was reported to DERN; and therefore, the licensee notified the NRC of a Significant Event in accordance with
CFR 50.72(b)(2)(vi),
notification to other government agencies.
C.
On November 28, 1991, at 12:37 p.m.,
Unit 3 experienced a
load reduction to approximately 76K power due to the right turbine stop valve going closed.
Closure of the stop valve occurred while the licensee was adjusting a flow control orifice to close the oil trip valve which was stuck open.
During the adjustment, auto stop oil pressure for the right stop valve momentarily decreased causing the stop valve to shut.
The unit was stabilized at about 500 NMe, and the right stop valve was reopened.
The unit returned to 100K power at 6:00 p.m.
on the same date.
(Refer to paragraph 2 for additional information regarding times for changes in plant status.)
d.
On December 6,
1991, at 9:08 a.m.,
the licensee was notified by its truck driver that a
small amount of liquid had leaked from a
container that he was transporting from the site to a waste processor in Oak Ridge, Tennessee.
The leak occurred at a truck stop in Jasper, Florida, while the vehicle was parked for the driver'
mandatory rest period.
The licensee dispatched HP personnel to Jasper to take radiological measurements and clean up any contamination found.
The State of Florida was notified and local authorities secured the area around the vehicle.
The licensee teams arrived at the scene and surveyed the area.
No contamination was found.
The shipping container door was opened and the leak was determined to be condensation that had formed inside the container due to the temperature difference between Turkey Point and Jasper, Florida.
The door of the container was sealed and the vehicle returned to the site on December 7,
1991, escorted by licensee HP
'l
e e.
personnel.
The licensee notified the NRC of this event at 11:30 a.m.,
on December 6,
1991, per=
CFR 50.72(b)(2)(vi).
On December 10, 1991, at 1:45 p.m.,
with Unit 4 at lOOX power, a
system engineer conducting a routine system walkdown noted that the 4A emergency load sequencer auto-test light was not illuminated as it should have been.
Resetting the auto-test mode did not change the sequencer status, and placing the sequencer in the manual mode also did not affect the sequencer status.
The licensee declared the 4A.sequencer OOS and commenced troubleshooting.
TS Table 3.3-2, Item 6.d, AFW Bus Stripping, Action 23, invokes TS 3.0.3, which requires that within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> action shall be initiated to place'the uni t in hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, hot shutdown within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and "old shutdown within the subsequent 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
At 5:37 p.m.,
the licensee commenced a
shutdown of the unit and declared an Unusual Event per EPIP 20101, Table 1, Item 20, Power Reduction Required By TS.
The turbine was taken off line at 7:33 p.m.,
and the unit entered Mode 3 at 7:37 p.m..
The NRC was notified of this event at 7:49 p.m.
in accordance with
CFR 50.72(b)( 1)(i)(A).
Mode
was entered
,at 1:42 a.m.'he following morning.
Troubleshooting of the 4A sequencer identified a faulty output test module which was replaced.
The licensee prepared an engineering evaluation, JPN-PTN-SEES-91-098, documenting the failure, troubleshooting, and r'epair'f the sequencer.
The evaluation stated that the sequencer would have performed its design function with the failed output test module.
The failure only affected the test circuit.
The sequencer was post-maintenance tested and returned to service at 9: 15 p.m.
on December 11, 1991, thus terminating the Unusual Event.
However, the unit was still required to continue to Mode 5 in order to facilitate the repair of the conoseal leak discussed below.
(Also refer to paragraph 2 for additional information regarding times for changes in plant status.)
The sequencers have a feature designed to perform a continuous automatic test and to abort the auto-test in response to a valid input.
The sequencer auto-test program generates minimum duration
'pulse signals that are used in the PLC for the purpose of verifying the.PLC program and the circuit continuity.
Certain failures of the PLC output test modules can result in the generation of a false valid signal that is processed by the sequencer as a valid input.
Because of this potentially undesirable situation, an engineering evaluation was performed that justified placing the test mode selector switch in the off position and discontinuing the use of the auto-test feature.
TSA 4-91-24-40 was generated to defeat the Sequencer Not In Auto Test alarm in the control room.
The licensee is continuing to evaluate a
long-term solution of the situation.
Presently the following alternate manual actions are being performed:
A manual test is being performed on a 30-day interva Every eight hours, a visual inspection of the observable indications is being performed to confirm that the sequencers are operable.
Every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, an operator will open the sequencer door and verify internal indications to confirm that the sequencers are operable.
Procedure 3/4-0SP-201.3 was revised to cover the 8-hour and 24-hour surveillance requirements.
The resident inspectors will follow the licensee's resolution of this issue.
At 5:25 a.m.
on December 11, 1991, while Unit 4 was shut down for troubleshooting of the 4A sequencer, the licensee identified a leak at the southeast conoseal assembly on the Unit 4 reactor vessel.
This assembly is one of four conoseals that provide a means to seal the thermocouple penetrations through the reactor vessel head.
(Refer to NRC Inspection Report No. 50-251/87-16 for an AIT inspection concerning a previous conoseal leak.)
In order to repair this leak, the unit must be in cold shutdown and depressurized.
Unit 4 reached Node 5 at 5:55 p.m., on.December 12, 1991.
The conoseal was repaired, and the unit was returned to service at 4:38 p.m.
on December 18, 1991.
(Refer to paragraph 2.for additional information regarding times for changes in plant status.)
g.
At 12:05 p.m.
on December 18, 1991; all five blackstart diesel generators were declared 00S due to the identification of a faulty relay in the dead bus control circuitry which would have prevented any of the blackstart,diesel generators from properly loading on a
dead bus start.
The No.
1 and 3 blackstart diesel
'generators were returned to service at 3:30 a.m.
on December 20, 1991, and the No.
blackstart diesel generator was returned to service at 2:42 p.m.
on the same day.
The No.
and 4 blackstart diesel generators were returned to service at 12: 10 p.m.
and 1: 15 p.m., respectively, on December 23, 1991.
Prior to this event, the No.
4 blackstart diesel generator had been declared 00S for quarterly preventive maintenance
.at 10:15 a.m.
on December 17, 1991.
h.
At 9:00 p.m.
on December 25, 1991, all five blackstart diesel generators were taken 00S in order to facilitate repairs to the roof over the cranking diesel bus.
Following completion of these planned repairs, the blackstart diesel generators will be tested and returned to service.
At 4:20 a.m.
on December 26, 1991, during the performance of a
scheduled surveillance, the 4B EDG tripped from full load and locked out due to a
ground received on the 4B DC bus.
Following troubleshooting, the ground was isolated to an automatic voltage
, regulator.
Both the automatic voltage regulator and a
bad Agastat relay were subsequently replaced.
Three 72-hour LCOs were entered as a result of this event:
TS 3.8. 1. l.b.2 action statement b for the
0,
e
48 EDG being OOS, TS 3.5.2.a action statement f for a required SI pump being operable but not capable of being powered from its associated diesel generator (This affected both units.),
and TS 3.4.3 for the 48 group pressurizer heaters not being capable of being supplied by emergency power.
At 2:42 a.m.
on December 28, 1991, the
EDG was returned to service, and all three 72-hour LCOs were exited.
Violations or deviations were not identified.
10.
Temporary Instruction 2515/103, Loss of Decay Heat Removal (Generic Letter No. 88-17)
CFR 50.54(f)
Programmed Enhancements (Long Term)
Review, (TI 2515/103).
The loss of decay heat removal during non-power operation and the consequences of such a loss have been of increasing concern to the NRC resulting in =the issuance of GL 88-17.
GL 88-17 required two plans of action:
a short-term program entitled, Expeditious Actions, and a
long-term program entitled,, Programmed Enhancements.
TI 2515/101 addressed the inspection.requirements for the licensee's expeditious actions program per GL 88-17.
The licensee's actions were reviewed by the NRC, and this review was documented in NRC Inspection Report No. 50-250,251/89-27.
Subsequently, TI 2515/103 was issued to ensure verification of licensee preparation for non-power operation while there is irradiated fuel in the reactor vessel in accordance with the programmed enhancements phase of GL 88-17.
a.
General The licensee responded to the long-term programmed enhancements by FPL letter L-89-37 dated February 1,
1989.
NRC letter dated November 7, 1990, constituted the NRR report that reviewed the licensee's submittal, and the licensee incorporated its remaining GL 88-17 coranitments during the recent dual unit outage.
These actions fulfill the prerequisites for this inspection as stated in paragraph 05.01 of TI 2515/103.
On two occasions when Unit 3 had been in a
reduced inventory c'ondition, the inspectors reviewed the licensee's actions and precautions taken with regard to reduced inventory operations.
These actions were documented in NRC Inspection Report Nos. 50-250,251/90-09 and 50-250,251/90-43.
b.
Instrumentation GL Item No.
Two independent RCS drain down level indicators for each unit were provided by PC/Ms89-332 and 89-333, Generic Letter 88-17, Loss of Decay Heat Removal Programmed Enhancement
-
RCS Redundant Level Monitors, for Units 3 and 4, respectively.
Level signals for the two independent level indicating switches (LI-6421 and LI-6423)
are provided by differential pressure transmitters that are referenced
C back to the pressurizer to provide a more reliable level indication; The two transmitters provide independent signals to a digital dual bargraph indicating switch located in the control room.
The indicating switches have an adjustable setpoint capability with common annunciation in containment (horn)
and the control room.
Level indication is also available on SPDS.
In addition to a
bargraph LED display, a digital display is also provided on the level indicating switches.
A single annunciation window is utilized'or all RCS level indicating switch annunciation; The level indication-range is
to 100%
with loop mid-nozzle corresponding to approximately 20K and the top of the reactor vessel head corresponding to 100K.
The drain down level indicating switches also overlap with the pressurizer cold calibration level indicator (LI-462) for continuity.
When in a reduced inventory condition, two independent measurements representative of core exit temperature are provided by the existing core exit thermocouples whenever the reactor vessel head is located on top of the reactor vessel.
Reduced inventory operation will be prohibited when the reactor vessel head is removed with fuel in the reactor vessel.
PC/Ms90-292 and 90-293, QSPDS Core Exit Thermocouple Alarm Modifications, for Units 3 and 4, respectively,'rovided an adjustable high core exit thermocouple temperature alarm in the existing QSPDS.
This provides both a visual and audible alarm in the control room on high core exit temperature during a reduced primary coolant system inventory condition by providing an adjustable high core exit thermocouple alarm setpoint and a corresponding alarm output interfaced with the plant annunciator system.
QSPDS is a
safety-related display system which provides indication of core exit temperature, reactor vessel level, and subcooled margin.
Improved RHR flow indication including an adjustable flow alarm and a
fixed low flow alarm were provided by PC/Ns89-457 and 89-568, Generic Letter 88-17, Loss of Decay Heat Removal Programmed Enhancement
- Residual Heat Removal (RHR) Flow, for Units 3 and 4, respectively; The new RHR flow meter is a digital bargraph indicator which provides a more accurate indication in the lower flow range.
A new dual comparator module also allows for both an adjustable flow alarm and a fixed low flow alarm.
The control room annunciator has been revised to reflect the new alarm conditions.
The original RHR temperature trend recorder and local RHR pump suction pressure indicators were adequate and did not require modification.
Procedures (GL Item No.
Procedures were revised to incorporate PC/N changes that affected reduced inventory operation.
Affected procedures were as follows:
3/4-GNI-041.1, ICCS NI Cable Disconnecting and Storage; 3/4-GNI-041.2, ICCS NI Cable Reconnecting;
3/4-0NOP-033.2, Refueling Cavity Seal Failure; 3/4-0NOP-050, Loss of RHR;
.
3/4-0P-041.2, Pressurizer Operation; 3/4-0P-041.7, Draining the Reactor Coolant System; 3/4-0P-041.8, Filling and Venting the Reactor Coolant System; 3/4-0P-041.9, Reduced Inventory Operations; 3/4-0P-201, Filling/Draining the Refueling Cavity and the SFP Transfer"Canal; 3/4-OSP-051. 14, Reduced Inventory Containment Penetration Alignment Verification; and 3/4-0SP-062.4, Safety Injection System - Full Flow Pump and Valve Test.
Procedures cover reduced inventory operation and require entry into ONOPs if RHR is lost, and containment closure is to be initiated upon loss of RHR for greatet than five minutes.
d.
E ui ment GL Item No.
As enhancements to improve the reliability of existing plant equipment associated with reduced inventory operation included upgrades of the RHR pump seals as provided by PC/M 88-077, Residual Heat Removal Pumps'echanical Seals and Seal Cooler Replacement; upgrades of the emergency electrical power system; and upgrades of the instrumentation previously discussed.
A new reduced inventory procedure, 3/4-0P-041.9, was developed to control the prerequisites and the operating requirements for RCS, RHR, and other support systems.
The requirements for one HHSI pump, two charging pumps, and associated flow paths to the core were also incorporated into this procedure as well as operating techniques which were provided in Westinghouse Owner's Group letter WOG-88-156, Transmittal of Mid-Loop Operations Interim Guidance and Workshop Attendance List, dated November 7, 1988, to decrease the likelihood of equipment malfunction.
The off-normal procedure for loss of RHR, 3/4-0NOP-050, has also been revised to include corrective actions for closure of RHR loop suction valves, use of gravity makeup, use of steam generators to provide cooling, and guidance for the use of charging and SI pumps.
Following development, these procedures were walked down to ensure that adequate communication equipment is available to support normal and off-normal operation.
These walkdowns were completed by May 31, 1989.
Where constant communication is required, the procedures stipulate the specific methods of communication.
The feasibility of defeating the RHR suction valve automatic closure interlock was evaluated in JPN-PTN-SEMJ-90-105, Defeat of RHR Suction Valves Interlock During Mid-Loop Operations.
This evaluation was completed on October 17, 1990, and it recommended that procedure
changes be inco'rporated to defeat the RHR suction valve automatic closure interlock.
This action has not yet been performed but is-currently being tracked under Technical Staff Action Item No. 91-12-109.
e.
Anal ses GL Item No.
In order to establish an understanding of NSSS behavior during non-power operation, an analysis was performed by FPL and the WOG.
This analysis was completed on August 16, 1990, and was documented in JPN-PTN-SEMJ-89-094, Engineering Evaluation for the Adequacy of Core Cooling ( In Support of Generic Letter 88-17, Loss of Decay Heat Removal).
It included heat up rates, pressurization rates, venting requir'ements, containment conditions, containment closure
'equirements, the effects of the loss of RHR on possible make-up water sources, and improved understanding of RCS level instrumentation response.
Technical S ecifications GL Item No.
9, The concerns identified in GL 88-17 and their impact on the upgraded TSs were discussed with the NRC prior to submittal of the upgraded TSs.
The upgraded TSs have since been approved'and incorporated.-
RCS Perturbations GL Item No.
Step 4. 11 of the new procedure controlling reduced inventory operation,.
3/4-0P-041.9, states that the RCS shall not be drained below mid-nozzle level unless authorized by the Operations Superintendent.
Step 4. 12 of this procedure also states that when RCS water level is lower than three feet below the reactor flange, all activities which may cause perturbations of the RCS water level, including the manipulations of systems that maintain the RCS in a
stable condition, should be prohibited.
In addition, a list of activities which have been identified through Turkey Point and industry events to cause or have the potential to cause perturbations to the RCS or systems required to support reduced inventory operation has also been included in 'Enclosure 1, Undesirable Activities During Reduced Inventory.
Verification that these activities are not in progress or will not cause perturbations prior to reducing RCS inventory is required by Step 5.1.2.9 of this procedure.
The inspectors consider the licensee's response to the recommended programmed enhancements under GL 88-17 and the implementation of the response in training, equipment, and procedures to be adequate to satisfy the requirements of TI 2515/103.
This TI is closed.
No violations or deviations were identi fie Management Meeting (30702, 94702)
NCV - Failure to follow the requirements of
TS 6.8.1 resulting in the inadvertent rapid start of the 3A EDG (paragraph 4}.
A management meeting was held at the site on December 10, 1991, in order.
to present the SALP report.
Licensee personnel and representatives from the NRC',s Region II and NRR staffs were in attendance.
During this meeting, plant performance in eight functional areas for the assessment period of August 1, 1990, through September 28, 1991, was discussed.
The SALP findings are documented in NRC Inspection Report No. 50-250,251/91-41.
P Exit Interview (30703)
The inspection scope and findings were summarized during management interviews held throughout the reporting period with the Plant General Manager and selected members of his staff.
An exit meeting was conducted on December 27, 1991.
The areas requiring management attention were reviewed.
The licensee did not identify as proprietary any of the materials provided to or reviewed by the inspectors during this inspection.
Dissenting comments were not received from the licensee.
Violations or deviations were not identified.
The inspectors had the following findings:
I Item Number Descri tion and Reference 50-250,251/91-50-01 50-250,251/91-50-02 NCV - Failure to check procedure index to ensure that latest revision of procedure was being utilized (paragraph 6).
Acronyms and Abbreviations ADM AFW AIT ANSI APSN CFR DC DERM EDG EPIP FPL GL GMI HHSI HP I E(C ICCS INPO Administrati ve Auxiliary Feedwater Augmented Inspection Team American National Standards Institute Assistant Plant Supervisor - Nuclear Code of Federal Regulations Direct Current Dade County Environmental Resource Management Emergency Diesel Generator Emergency Plan Implementing Procedure Florida Power and Light Generic Letter General Maintenance ISC High Head Safety Injection Health Physics Instrumentation and Control Inadequate Core Cooling System
'Institute for Nuclear Power Operations
e JPN LCO LED LER LI MI MWe NCV NRC NRR NSSS NWE ONOP OOS OP OSP PC/M PLC PMG PSN PTN QA QAO QC QSPDS RCO RCS TSA RHR r'pm SALP SI SMI TI TS UR -
IV
Juno Project Nuclear Limiting Condition for Operation Liquid Electronic Display
, Licensee Event Report Level Indicator Mineral Insulated Megawatts - Electric
'on-Cited Violation Nuclear Regulatory Commission Office of'Nuclear Reactor Regulation Nuclear Steam Supply System Nuclear-Watch Engineer Off Normal Operating Procedure Out.of Service Operating Procedure Operations-Surveillance Procedure Plant Change/Modification Programmable Logic Controller Permanent Magnet Generator Plant Supervisor - Nuclear Plant Turkey Nuclear
~
Quality Assurance Quality Assurance Organization Quality Control Qualified Safety Parameter Display System Reactor Control Operator Reactor Coolant System Temporary System Alteration Residual Heat Removal Revolutions Per Minute Systematic Assessment of Licensee Performance
- Safety Injection Surveillance Maintenance IEC Temporary Instruction Technical Specification Unresolved Item Violation Westinghouse Owners Group