IR 05000250/1991046
| ML17348B328 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 12/16/1991 |
| From: | Burnett P, Butcher R, Landis K, Schnebli G, Trocine L, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17348B327 | List: |
| References | |
| 50-250-91-46, 50-251-91-46, NUDOCS 9201140044 | |
| Download: ML17348B328 (41) | |
Text
,UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos.:
50-250/91-46 and 50-251/91-46 Licensee:
Florida Power a'nd 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:
October 26 through November 22, 1991, 6..
S i, Resident Inspector L.
oc'
ident Inspector J.
W or, Resi nt Ins ctor Surry Inspectors:
R.
C. Bute enior Resident Inspector Date Signed iz r Date Signed
/~ 1'4 /
Da e
igned Dat Si ned r ett, ac or ngineer Date Signe Approved.by:
K.
D.
La is, hse Reactor Projects Section 2B Division of Reactdr Projects I
ae aged SUMMARY Scope:
This routine resident inspector inspection entailed direct inspection at the site in the areas of monthly surveillance observations, monthly maintenance observations, Unit 3 power escalation and surveillance tests, Unit 4 startup from refueling, sustained control room observations, operational safety, and plant events.
Results:
Within the scope of this inspection, the inspectors determined that the l
licensee continued to demonstrate satisfactory performance to ensure safe 9201140044 911216 PDR ADOCK 05000250
plant operations.
Violations or deviations were not identified.
The inspectors had the following findings:
Strength - Prompt operator action to preclude a reactor trip (paragraph 10.a).
Concern - Lack of procedural requirements for interface of operations between nuclear and non-nuclear divisions-(paragraph 10.c).
REPORT DETAILS Persons Contacted Licensee Employees L.
T.
R.
S.
K.
E.
R.
H.
W.
V.
J.
G.
L.
T.
D.
K.
C.
R.
F.
M.
J.
A.
V. Abbatiello, guality Assurance Supervisor Arias, Jr., Technical Assistant to Vice President W. Bladow, guality Manager A. Finn, Assistant Operations Superintendent J. Gianfrencesco, Assistant Maintenance Superintendent T. Hale, Engineering Project Manager N. Harris, Senior Vice President - Nuclear Operations F. Hayes, Instrumentation and Controls Supervisor G. Heisterman, Assistant Superintendent of Electrical Maintenance H. Johnson, Operations Supervisor M. Johnson, Mechanical Department Supervisor A. Kaminskas, Operations Superintendent E. Knorr, Regulatory Compliance Supervisor D. Lindsay, Health Physics Supervisor L. Marsh, Reactor Engineering Super visor W. Pearce, Plant Manager - Nuclear
'F. Plunkett, Site Vice President R. Powell, Superintendent
- Plant Licensing L. Remington, System Performance Supervisor V. Rossi, guality Assurance Supervisor.
N. Steinke, Chemistry Supervisor R. Timmons, Site Security Superintendent B. Wayland, Maintenance Superintendent D. Webb, Assistant Superin;endent Planning and Scheduling T. Zielonka, Technical Department Supervisor 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 Accompanying NRC Inspectors P.
T. Burnett, Reactor Engineer J.
W. York, Resident Inspector, Surry
- Attended exit interview on November 22, 1991'ote:
An alphabetical tabulation of acronyms used in this report is listed in the last paragraph in this repor e 2.
Plant Status Unit 3 At the beginning of this reporting period, Unit 3 was operating at 100%,power.
This unit has been or the.line since October 4, 1991.
The following evolutions occurred on Unit 3 during this report period:
On November 13, 1991, at 11:05 a.m.,
a load reduction to less than
reactor power was commenced due to problems with
.
control bank C group 2 rod heights.
(For additional information, refer to paragraph 10.d.)
On November 13, 1991, at 11:20 a.m.,
the load reduction was extended to less than 505 reactor power in order to avoid problems with axial flux distribution.
On November 13, 1991, at 11:37 a.m., reactor power was below 50%.
On November 14, 1991, at 2:30 p.m.,
power escalation to 100K was commenced.
On November 14,'991, at 9: 15 p.m., Unit 3 reached 100% power.
On November 16, 1991, at 6: 15 p.m.,
a load reduction to 100 MWe (approximately 20% reactor power)
was commenced as a resul't of closureiof the SE intercept valve due to a break in a control oil pipe.
(Refer to paragraph 10.g for additional information.)
On November 16, 1991, at 7:3G p.m., the unit reached approximately 100 MWe'.
On November 16, 1991, at 11:GG p.m.,
a load increase was commenced until steam generator levels were stable and the feedwater pumps were in automatic (approximately 30~ reactor power).
On November 17, 1991, at 6:24 a.m.,
power escalation to 100~ was commenced.
On November 17, 1991, at 1:25 p.m., reactor power reached 100%.
On November 17, 1991, at 10:25 p.m.,
a power reduction to 95K was commenced to prevent the possibility of an inadvertent automatic turbine runback due to spiking on overtemperature delta temperature.
(Refer to paragraph 10.f for additional information.)
On November 17, 1991, at 11:00 p.m., reactor power reached 95%.
On November 18, 1991, at ll:20 p.m.,
a power reduction to 85$ was commenced for monitoring of the overpower delta temperature and overtemperature delta temperature channels while the channel II bistables were in the tripped position..
On November 19, 1991, at 12:31 a.m.,
85% reactor power-was attained.
On November 19, 1991, at 8:25 a.m
, the channel II bistables were returned to service.
On November 19, 1991, at 10:20 a.m.,
power escalation to 95'A was commenced in order to establish conditions for the continued investigation of the Eagle 21 average temperature and delta temperature input On November,19, 1991, at ll:33 a.m., reactor power was returned to 95K.
On November 22, 1991, at 5:50 p.m.,
power escalation to 1005 was commenced following installation of new overpower delta temperature-and overtemperature delta temperature set points.
On November 22, 1991, at 6:30 p.m.,
lOOX reactor power was attained.
On November 22, 1991, at 8:00 p.m.
commenced reactor power reduction to 56'X for maintenance on the 3B MOP.
Unit 4 At the beginning of this reporting period, Unit 4 was in Mode 3., The unit had entered Mode 3 at 10:25 p.m.
on October 22, 1991, when RCS temperature reached 350 degrees F.
The following evolutions occurred on Unit 4 during this report period:
On October 27, 1991, at 12:25 a.m., Unit 4 entered Mode 2.
On October 27,= 1991, at 1:01 a.m., criticality was achieved.
On October 27, 1991, at 2:38 p.m., Unit 4 entered Mode 3 again after completion of low power physics testing.
On October 27, 1991, at 6:25 p.m., Unit 4 re-entered Mode 2.
On October 27, 1991, at 6:45 p.m., criticality was re-achieved.
On October 29, 1991, at 3:20 a.m., Unit 4 entered Mode 1.
On October 29, 1991, at 4:36 a.m., the turbine was placed on line thereby ending the dual unit outage.
On October 29, 1991, at 7:53 a.m., reactor power reached 30K.
On October 29, 1991, at 5: 10 p.m.,
a reduction of reactor power from 30~ to less than 10" was commenced, the turbine was manually taken off line in preparation for the performance of the turbine overspeed test, and the unit re-entered Mode 2.
On October 29, 1991, at 6: 15 p.m., the turbine overspeed test was
~
successfully completed.
On October 29, 1991, at 10:25 p.m., Unit 4 re-entered Mode 1.
On October 29, 1991, at 10:54 p.m., the turbine was placed back-on line.
On October 30, 1991, at 2:05 a.m., Unit 4 reached 28.5% power.
On October 30, 1991, at 11:50 a.m., following flux mapping, power escalation to 45K was commenced.
On October 30, 1991, at 5:30 p.m.,
power escalation to 50% was commenced.
On October 30, 1991, at 6:40 p.m., Unit 4 reached'50%
power.
On November 2, 1991, at 8:55 p.m.,
power escalation to 75K was commenced.
On November 3, 1991, at 9:30 a.m., Unit 4 reached 75K power.
On November 3, 1991, at 2:55 p.m.,
power escalation to 85% was commenced.
On November 3, 1991,. at 6:30 p.m., Unit 4 reached 85% power.
On November 3, 1991, at 9:15 p.m.,
power escalation to 100K was commence ~
~
On November 4, 1991, at 2:10 a.m.,
On November 5, 1991, at 9:30 p.m;,
commenced for flux mapping.
On November 6, 1991, at 1:45 a.m.,
On November 6, 1991, at 3:35 a.m.,
commenced.
On November 6, 1991, at 5:05 a.m.,
for correction of an RPI problem.
On November 6, 1991, at 7:25 a.m.,
recommenced.
On November 6, 1991, at 10:30 a.m.,
Unit 4 reached 100% power.
a power reduction to 85K. was Unit 4 reached 85K power.
power escalation to 100% was power escalation was stopped power escalation to 100% was Unit 4 reached lOOX power.
3.
Onsite Followup and'n-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 i'dentified.
When applicable, the criteria of 10 CFR Part 2, Appendix C, were applied.
(Closed)
LER 50-251/90-08, Automatic Reactor Trip on Low-Low Steam Generator Level Due to Loss of the 4A Steam Generator Feedwater Pump.
This event was previously discussed in paragraph 8 of IR 50-250,251/90-30.
As a result of this event, the licensee implemented the following corrective actions.
The 4B condensate pump was repaired and reinstalled.
The design documents (i.e., the logic diagram and elementary wiring diagrams for the 3A(4A) and 3B(4B)
SGFW pump breakers were revised to reflect a
7012PC Agastat relay setpoint of 5.0 seconds
+10%.
The 7012PC Agastat relay for the 4A SGFW pump breaker was calibrated to 5.0 seconds
+IOX, and the relay for the 4B SGFW pump breaker was also reset after testing found it to be set at 3.3 seconds.
The 7012PC Agastat relays for the 3A and 3B SGFW pumps were found to be set at approximately 7.0 seconds and 3.5 seconds, respectively, based on relay dial settings.
Although acceptable for operation, the relays were recalibrated to reflect the new setpoint during the dual unit outage.
In addition, an action plan was developed to identify the setpoints for Agastat time delay relays that do not have setpoints specified on design documents, and PC/Ms91-033 and 91-034, Miscellaneous Agastat Time Delay Relay Setpoint Changes, were issued to identify the setpoints for Agastat time delay relays in use at Turkey Point Units 3 and 4.
This LER is close (Closed)
LER 50-251/90-09, Containment Personnel Air Lock Pressure Test Not performed in Accordance With Plant Technical Specifications Due to Work Control Deficiencies.
t This event was caused by a
work control deficiency'in that no controls were in place to prevent maintenance from working on the inner barrier while the outer barrier was inoperable..
Inadequate communications between maintenance and technical personnel also contributed to this event.
As a result, the computer program that generates work orders was updated to print a caution statement on work orders for the personnel and emergency air locks.
This caution.
statement warns that during times when the air lock is required to be operable and maintenance is required on one barrier (door, valve, etc.),
no maintenance shall be performed on the other operable door.
This event was also reviewed by mechanical maintenance foremen and supervisors to emphasize the safety functions of the airlock and its associated hatches and to e"phasize the post maintenance test requirements used to verify that these safety functions are functional.
This LER is closed.
(Closed)
LER 50-251/90-10,'S 3.0. 1 Entry Due To Train
Undervoltage Protection Fuse Failure.
This event was caused by a blown fuse which was subsequently replaced and the system returned to normal.
The licensee returned the fuse to the vendor for analysis.
The specific cause for the blown fuse could not be determined.
This LER is closed.
(Closed)
LER 50-251/90-13, Failures Associated With the 4A and 4B EDG Pilot Exciter Regulators.
The issue involving this voluntary LER identified during pre-operational testing of th new EDG was previously discussed in IR 50-250,251/90-42 and identified as IFI 50-250,251/90-42-01.
This IFI was subsequently closed and identified as NCV 50-250,251/91-03-01 in IR 50-250,251/91-03.
This LER is closed.
(Closed)
LER 50-251/90-14, 4B EDG Cooling Water Flexible Hose Weld Crack Could Prevent EDG From Performing Intended Safety Function.
This voluntary LER identified a manufacturing defect in the weld connecting the cooling water flexible hose pipe stub and the flange.
The defect was found by the licensee during an installation=
inspection being performed in preparation for acceptance testing of the new EDGs prior to turnover to the plant.
The defective hose and one additional hose was returned to the vendor for analysis.
The vendor supplied a
complete set of new hose assemblies for both new EDGs which were subsequently inspected and installed.
This LER is close (Closed)
LER 50-250/91-01, Material Discrepancy Involving the 3C CCW Heat Exchanger Tubes.
This issue was previously discussed in IR 50-250,251/91-07.
The corrective actions required by this L'ER were reviewed and found to be adequate.
This LER is closed.
(Closed)
LER 50-250/91-02, Inadvertent Reactor Trip Signal Due To Inadequate Work Controls.
This event was previously discussed in IR 50-250,251/91-24 and identified as NCV 50-250,251/91-24-02.
This LER is closed.
(Closed)
LER 50-250/91-03; Loss of 3A and 3B 4KV Busses Due to Generator Lockout Signal.
This event was discussed in detail in IR 50-250,251/91-24.
The licensee's extensive corrective actions in response to this event were identified as a strength in the report.
This LER is closed.
(Closed)
LER 50-251/91-03, De-energization of ICW Pump Causes Loss of SFP Cooling.
This voluntary LER was previously discussed in IR 50-250,251/91-24.
Corrective actions required by this event were reviewed and found to be adequate.
This LER is closed.
(Closed)
LER 50-250/91-04, Inadvertent Start of 3A Emergency Diesel Generator.
This event was discussed in IR 50-250,251/91-31 and identified as URI 50-250,251/91-31-01.
Closeout of this issue will be accomplished on followup of the URI.
This LER is closed.
(Closed)
LER 50-251/91-04, Inadvertent Phase A Containment Isolation Due to Inadequate Procedure.
This event was previously.discussed in IR 50-250,251/91-24 and identified as NCV 50-250,251/91-24-01.
This LER is closed.
(Closed)
LER 50-250/91-05, Automatic Start of 3A CCW Pump on Low Pressure Due to Personnel Error.
This event was discussed in IR 50-250,251/91-37 and identified as NCV 50-250,251/91-37-02.
This LER is closed.
(Closed)
LER 50-250/91-07, Unit 3 Entered Mode 2 with One of Two Intermediate Range Instrumen ation Channels Inoperabl This issue was discussed in IR 50-250,251/91-37 and identified as URI 50-250,251/91-37-04.
Closeout of this issue will be accomplished on followup of the URI.
This LER is closed.
(Closed)
LER 50-250/91-08, Manual Reactor ITrip Following Loss of Main Turbine Generator Load Due to a Mechanical Failure of a Piping Nipple in the Control Oil System.
This issue was discussed in IR 50-250,251/91-42.
This LER is closed.
4.
Monthly Surveillance Observations (61726)
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.
In addition to the test activities listed in paragraphs 6 and 8, the inspectors witnessed/reviewed portions of the following test activities:
4-0SP-075.6, Auxiliary Feedwater Train 1 Backup Nitrogen Test; and 0-OSP-075. 11, Auxiliary Feedwater Inservice Test.
The inspectors determined that the above testing activities were performed in a satisfactory manner and met the requirements of the TSs.
Violations or deviations were not identified.
5.
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 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 housekeepi ng was actively pursued.
The inspectors witnessed/reviewed portions of the following maintenance activities in progress:
balance shots of the Unit 4 turbine, troubleshooting and repair of Unit 3 rod control system (Refer to paragraph 10.d for additional information.),
and troubleshooting to identify the source of spurious signals which resulted in automatic turbine runback rod block alar'ms and overtemperature delta temperature rod stop alarms on Unit 3 (Refer to paragraph 10.f for additional information.).
For those maintenance activities observed, the inspectors determined that these activiti.es were conducted in a satisfactory manner and that the work was properly performed in accordance with approved maintenance work orders.
Violations or deviations were not identified.
6..
Unit 3, Mid-Cycle 12, Power Escalation and Surveillance Tests (72700, 61702, 61705)
a.
Power Escalation Tests Operating Procedure 0204.5, Nuclear Design Tests During Startup Sequence After Refueling, was essentially complete for the mid-cycle 12 restart, with only a few full power data and observations to be entered.
b.
Surveillance Tests The following completed surveillance tests were reviewed and found acceptable:
(1)
OP-12404.1, Normal Operation of Incore Movable Detector System and Power Distribution Surveillance, which was performed on October
and 16, 1991, with acceptable hot channel factors measured; (2)
O-OSP-059.9; Computer Axial Flux Monitor Verification, which was performed on October 15, 1991; (3)
0-OSP-059. 10, Determination of quadrant Power Tilt Ratio, which was performed on'ctober 18, 1991;
(4)
OP.-12304.6, Power Range Nuclear Instrument Calculation of Target Axial Flux Difference, ~hich was performed on October 7 and 17, 1991; and (5)
3-0SP-040.15, Cal orimetri c Verificati on of Reactor Cool ant System'low, which was in final review by the" licensee when reviewed by the inspector.
No violations or deviations were identified.
7.
Unit 4, Cycle 13, Initial Criticality, Startup Tests, and Plant Startup From Refueling (72700, 61708, 617 0, 71711).
,a ~
Approach to Criticality The approach to initial criticality for Unit 4, cycle 13, was conducted on October 27, 1991, under the guidance of OP-0204.3, Initial. Criticality after Refueling.
Operability of the source range nuclear instruments was confirmed prior to withdrawing safety rods.
. All rod withdrawals and the subsequent dilution to criticality were monitored by calculating ICFR after predetermined increments of rod motion or dilution.
The successive rod withdrawals were not
=
. performed unti 1 the plot was evaluated to confirm that criticality would not occur during the next increment.
Dilution was'
continuous process until ICRR was reduced to 0. 1, when it was stopped.'riticality was not achievec during mixing but was established by withdrawing D
bank from the 160 step position maintained during dilution.
In IR 50-250,251/91-42, a
concern was raised in response to observations of the dilution to criticality of Unit 3, mid-cycle 12.
The use of the alternate di lute mode of operation without modification appeared to lead to over dilution of the VCT with a
potential for reducing rod position below the
. power dependent insertion limit and a furth r potential for creating one of the precursors for a more severe accident.
This concern and a concept
,
for corrective action were discussed with licensee management at that time.
In response to that concern, OP-0204.3 was revised by adding the following note after ste" 8.9:
If primary water is directed to the VCT during dilution, ensure the CVCS turnover rate is sufficient to prevent the VCT from becoming over diluted..
Further discussion with licensee personnel regarding the Unit 4 startup confirmed that the response to the note was to close a valve, preventing primary water from entering the VCT spray, and to establish a charging rate gr ater than the dilution rate.
These are the necessary and sufficient actions to prevent over dilution of the VCT.
Whether that note will produce the same response in future
tests from individuals less familiar with the issue and reason for the note is open to question.
Subsequent Tests Appendix A of OP-0203.'4 was performed to establish the flux level at which nuclear heating is observed and subsequent low power testing was conducted below the heating range.
Establishing the upper power limit for zero power tests prevented doppler effects in the fuel from invalidating the zero power physics tests.
Appendix B
was performed to check out the DRC dynamical ly.
Acceptable agreement between inhour equation solutions and DRC solutions of period and reactivity were obtained for both positive and negative reactivity inputs.
Zero Power Physics Tests The tests listed below were appendices of OP-0204.5, Nuclear Design Check Tests during Startup Sequence after Refueling.
- They are described in more detail in IR 50-250,251/91-42 and were reviewed for this startup in the same depth described in that report.
Appendix A, Boron Endpoint Measurement.
Appendix B, Isothermal Moderator Temperature Coefficient.
Appendix D, Rod Worth Verification by Rod Swap Method.
Data Sheet 10; Differential Boron Worth, used data collected in the test appendices to calculate a differential boron worth.
All of the test results were acceptable and satisfied acceptance criteria derived from WCAP-13201, The Nuclear Design and Core Manage-ment of the Turkey Point Unit 4 Nuclear Power Plant, Cycle 13, which was also 'reviewed by the inspector.
Startup from Refueling As stated in IR 50-250,251/91-42, the CNRB convened by telecon on October 25, 1991, to review the status of Unit 4 prior to entering Mode 2.
During this call, the CHRB voted unanimously that Unit 4 wa's ready to enter Node
when the Site Vice President determined that the required outstanding items had been completed.
Prior to this reporting period, the Unit 4 had entered Node 3 at
, 10:25 p.m.
on October 22, 1991, when RCS temperature reached 350 degrees F.
On October 27, 1991, Unit 4 entered Node 2 at 12:25 a.m.,
and criticality was achieved at 1:01 a.m..
After completion of the low power physics testing, Unit 4 re-entered Node
at 2:38 p.m.;
and Mode
and criticality were re-achieved at 6:25 p.m.
and 6:45 p.m., respectivel'y, on the same day.
Unit 4 entered Mode 1 at 3:20 a.m.,
was placed on line at 4:36 a.m.,
and
reached 30$
power at 7:53 a.m.
on the same day.
At 5:10 p.m.
on October 29, 1991, a reduction in power from 30% to less than 105 (the P-7 permissive)
was cormenced in preparation for the performance of the turbine overspeed test.
The turbine was then manually taken off line, and the unit re-entered Mode 2.
The turbine oterspeed test was successfully completed at 6: 15 p.m.
on October 29, 1991.
Mode
was'e-entered at 10:25 p.m.,
and the unit was placed back on line at.
10:54 p.m.
on October. 29, 1991.
Unit 4 reached 28.5%
power at 2:05 a.m.
on October 30, 1991.
Following flux mapping on the same day, power escalation to 45" was comnenced at 11:50 a.m.,
power escalation to 50K was commenced at 5:30 p.m.,
and 50K power was attained at 6:40 p.m..
Power escalation to 75K was commenced at 8:55 p.m.
on November 2, 1991, and 75K power was attained at 9:30 a.m.
on November 3, 1991.
Power escalation to 85% was commenced at 2:55 p.m.,
and 85~ power was reached at 6:30 p.m.
on the same day.
Power escalation to 100~
was coranenced at 9:15 p.m.
on Nov'ember 3, 1991, and 100%
power was achieved at 2:10 a.m.
on November 4, 1991.
At 9:30 p.m.
on November 5, 1991, a
power reduction to 85%
was commenced in preparation to'nduce Xenon oscillations for flux mapping.
At 11.:04 p.m.,
the licensee commenced inducing Xenon oscillations in accordance with OP-12304.8, Inducing Xenon Osci llations to Produce Various Incore Axial Offsets.
The unit reached 855 power at 1:45 a.m.
on November 6, 1991.
At 3:35 a.m.
on the same day, flux mapping was completed,,
and the licensee commenced increasing reactor power to 1005.
Power escalation was stopped at 5:05 a.m. for correction of an RPI problem.
Power escalation was recommenced at 7:25 a.m.,
and Unit 4 reached 100K power again at'0:30 a.m.
on November 6, 1991.
Some carelessness-in data entry on the part of test personnel was noted during the review and was discussed with the appropriate supervisor.
None of the errors invalidated the tests.
.Following discussions of these tests with licensee personnel, the inspector had no further questions.
Placing the turbine on line at 4:36 a.m.
on October 29, 1991, marked the end of the dual unit outage.
This outage was completed 6 days and 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> ahead of the original schedule making the total duration 338 days versus the originally planned duration of 344 days.
Considering the magnitude and complexity of the work performed, completion of the dual unit outage ahead of schedule is considered to be a major accomplishment.
Violations or deviations were not identified.
8.
Sustained Control Room Observations (71715)
During the Unit 4 startup from hot standby to 100K power (Refer to paragraph 7 for additional information.),
the inspectors observed the
0'
licensee's satisfactory performance of all or portions of the following procedures on Unit 4:
4-GOP-301, Hot Standby to Power Operation; 4-0NOP.-014, Main Condenser Loss of Vacuum; 4-0NOP-028.3, Dropped RCC Operating Procedure 0204.3, Initial Criticality After Refueling; Operating Procedure 0204.5, Nuclear Design Tests During Startup-Sequence After Refueling; I
Operating Procedure 12404.1, Normal Operation of Incore Movable
. Detector System and Power Distribution Surveillance; 4-0SP-072, Main Steam Isolation Closure Test; 4-0P-075, Auxi1 iary Feedwater System; 4-0SP-075.1, Auxiliary Feedwa.er Train 1 Operability Verification; 4-0SP-075.2, Auxiliary Feedwater Train 2 Operability--
Verification; 4-0SP-075.6, Auxiliary Feedwater Train 1 Backup Nitrogen Test; 4-0SP-075.7, Auxiliary Feedwater Train 2 Backup Nitrogen Test; 4-0P-089, Hain Turbine; 4-0SP-089, Main Turbine Valve Operability Test; 4-OSP-089. 1, Turbine Generator Overspeed Trip Test; and 4-0SP-200.3, Secondary Plant Periodic Tests.
During these observations, the licensee identified and appropriately corrected errors in new procedures and also identified and corrected various'inor equipment problems.
It was also noted that operators were attentive and responsive to plant parameters and conditions, plant evolutions and testing were planred and properly authorized, procedures were used and followed as required by plant policy, equipment status changes were appropriately documented and, communicated to appropriate shift personnel, the operating conditions of plant equipment were effectively monitored and appropriate corrective actions initiated when required, and the operators followed good operating practices in
"conducting plant operations.
No violations or deviations were identifie.
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 pro'per valve/switch alignment of'elected emergency systems, verified.maintenance
'ork 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 retu'rn 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.
, Th'e inspectors walked down accessible portions of the following safety-related systems/structures to verify proper valve/switch alignment:
I A and B emergency diesel generators, control'oom 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 an'd 4 main steam platforms, and auxiliary building.
'a ~
Recent industry events have raised concerns regarding the adequacy of plant staffing during a fire concurrent with operational plant transients and required offsite notifications.
Minimal plant staffing that meets the requirements of
CFR 50.54(m)
may not provide adequate staff 'to handle fire brigade and other special occurrences that may arise on the backshift.
A review was made of the licensee's staffing requirements for licensed and non-licensed operating staff to determine the adequacy of staffing when the fire brigade may be required.
Operating procedure 0204.2, Periodic Tests, Checks, and Operating Evolutions, defines specific tasks for each
operating crew.
Paragraph 8.2.2, Nuclear Watch Engineer, requires that within the first hour of each shift the NWE (who is a qualified SRO) perform the following:
The NWE shall assign two operations brigade members in addition to himself or his designee and shall verbally notify them of thei'r assignment.
When notified of the health physics and chemistry fire brigade as'signments, the NWE shall indicate the five fire brigade personnel on the fire brigade assignment sheet.
I The NWE shall assign two SNPOs (one inside and one outside the RCA)
and one NPO to per orm the appropriate steps of ONOP-105 (Control Room Evacuation) if required.
These three operators shall not be part of the fire team.
The NWE shall assign personnel to perform blackstart diesel operation and communicator duties if required.
The inspectors'eview of staffing requirements show the following relationship:
'TAFFING REQUIREMENTS'S Licensee Estimate of
CFR 50.54 Minimum Re uired Staffin SROs
ROs NLOs TS 10 CFR 50.54
Licensee Estimate of Minimum Re uired Staffin STAs Other The licensee presently meets or exceeds their 'estimated minimum staffing which exceeds regulatory requirements.
The inspectors consider the licensee's staffing to be adequate.
b.
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,
e
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-91-009 QAO-PTN-91-032 QAO-PTN-91-033 QAO-PTN-91-058 QAO-PTN-91-060 QAO-PTN-91-062 QAO-PTN-91-066 QAO-PTN-91-067
RTD Bypass Elimination Installation United Controls Incorporated Sequencer Program Modification and Testing Training and Facility Staff Qualifications Radiation Protection (TSs 6.11 and 6.12)
September Performance Monitoring Aud1t Qualification and Training of Security Force Personnel Design Control Radioactive Sources No additional NRC followup actions will be taken on the findings referenced above b'ecause 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 identified.
10.
Plant, Events (93702)
The '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.
At 11: 16 p.m.
on October.
29, 1991, with Unit 4 at 22'A power, all three AFW pumps automatically started when the,4A steam generator feedwater pump tripped on low suction pressure due to a condensate polisher valve malfunctio The 4A steam generator feedwater pump tripped when feedwater pump suction pressure dropped to the trip setpoint of 200 psig.
As a
result, all three AFM pu-. ps automati'cally started as designed.
Additional automatic acticns to help restore suction pressure included the opening of the feedwater heater bypass valve (CV-2011)
when feedwater pump suction pressure decreased to 240 psig and the opening of the condensate demineralizer system bypass valve (PCV-6325)
when the differential pressure between the condensate effluent increased to 40 psid.
When suction pressure had been restored to approximately 300 psig, the operators manually started the 4B steam generator feedwater pump.
This action was completed within nine seconds after the 4A steam generator feedwater pump had tripped., Feedwater heater bypass valve CV-2011 was then closed, and the AFW pumps were secured at 11:23 p.m.
per procedure 4-0P-075, Auxiliary Feedwater Syste."..
The licensee declared a Significant Event as of. 11: 16 p.m.
on October 29, 1991," per AP 103. 12,
. Notification of Significant Events to'NRC.
The NRC Operations Center was notified of the 4-hour reportable event at 12:20 a.m.
on October 30, 1991, in accordance with
CFR 50.72(b)(2)(ii),
ESF actuation (automatic start of AFW).
During investigation of the low suction pressure, an operator observed the backwash receiver tank overflowing and took the appropriate actions to restore all condensate flow to the steam generator pump suction by isolating the D filter demineralization vessel.-
The discharge valve from the overflow area to the canal was also closed.
Prior to this event, a chemistry supervisor was attempting to backwash the D filter demineralization vessel which depressurized the vessel.
During this process, the vessel inlet valve (CV-4-6351D) did not completely close to isolate the D vessel due to a failed limit swi:ch.
An examination of the failed limit switch determined the switch to be out,of adjustment.
This permitted'condensate flow to pass through the vessel while it was being backwashed, and between 3000 and 4000 gallons overflowed through the backwash receiver along wi-.h the resin 'contents of the D vessel The resin was sampled and counted by health physics, and no radioactivity was found.
The preclusion of a reactor trip on low steam generator water level by prompt operator actions to restore feedwater flow is considered to be a strength.
On October 30, 1991, the licensee requested a temporary waiver of compliance.
TS 4.3.1.1 references TS table 4.3. 1, Reactor Trip System Instrumentation Surveillance Requirements, item 2.a, Power Range, Neutron Flux-High Setpoint Channel Calibration, which references footnote (6) which requires'that the incore-excore neutron flux calibration be performed above 75% of rated thermal power on a
quarterly basis.
TS 3.2.1 requires.that AFD be maintained within a
+5% target band about the target flux difference with cumulative penalty deviation time for time spent outside the target ban e
Acceptable operation limits for AFD are defined in TS figure 3.2-1.
It is recognized that the accur'acy of incore-excore neutron flux calibration is enhanced at larger AFD conditions; therefore, TS 3.2.1 footnote ** allows surveillance testing of the power range neutron flux channels pursuant to TS 4.3.1.1 (provided the AFD is maintained
'ithin the operational limit's of figure 3.2-1) outside the target band for up to 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> without penalty deviation.
This footnote was intended to apply to operation between 50% to 90% rated thermal power.
Due to an'rror, the ** for the footnote was mislocated in action statement TS 3.2. l.b such that.the licensee could not take advantage of the relaxed penalty conditions for surveillance testing.
This was previously discussed in IR 50-250,251/91-42, paragraph ll.d.
Based on the licensee's letter to the NRC dated October 29, 1991, (and supplemented by a
letter dated October 30, 1991)
on October 30, 1991, the NRC verbally approved the temporary waiver of compliance of TS 3.2.1.b by referencing footnote ** of TS 3.2.1 in the applicability statement of the specification rather, than in the action statement of TS 3.2. l.b.
The NRC's approval of'the temporary waiver of compliance was documented by letter dated October 31, 1991.
On October 31, 1991, at 3:30 a.m.,
switchyard breakers 8W65 and 8W29 relayed open due to a problem on the Doral Line 5'2 offsite power line.
At 4:30 a.m.,
switchyard breakers 8W68 and 8W32 relayed
.open due to a
problem on the Da'v',s Line P3 offsite power line.
FPL re-energized the Davis Line
=-"3 and Doral Line b2, and at 4:37 a.m.,
all switchyard breakers were reclosed successfully.
Subsequently, at 6:30 a.m.,
switchyard breakers 8W175 and 8W139 relayed open due to a problem with Flagami Line Pl.
The 8W175 and 8W139 breakers were reclosed immediately.
The licensee stated the cause of the breakers opening was faults on the lines that were interim in nature and not readily evident.
These events resulted-in the loss of three of eight offsite power lines.
There are no requirements for maintaining a
minimum number of operable offsite power lines.
Also, at any given time,'he nuclear operators are not aware of how many offsite power sources are available.'his is another example of the inspector's concern with the lack of procedural requirements for interface of operations between nuclear and non-nuclear divisions.
Previous nuclear and non-nuclear interface problems were identified in IR 50-250,251/91-11 and are carried as URI -50-250,251/91-11-04.
This.
concern will be tracked as part of URI 50-250,251/91-11-04.
On November 13, 1991, at 8:05 a.m. with Unit 3 at lOOX power, the licensee was performing a full length rod exercise surveillance per
OP 1604.
While selected to control bank A and driving rods inward, both shutdown bank A group
and control bank A group 1 rods moved inward together.
The RCO withdrew all rods fully and continued with the surveillance to identify additional problems.
Control bank B was then selected and tested satisfactorily.
When control bank C was selected, a rod control system urgent failure alarm was received from a logic error in the 2AC power cabinet.
The licensee declared all
e e.
control rods powered from the 2AC power cabinet as OOS, and TS Action Statement 3. 1.3. l.b was entered placing the unit-in a 6-hour to Hot Standby LCO.
During troubleshooting of the 2AC power cabinet, a
signal processing card and a firing card were replaced; When the new signal processing card was installed, control bank C group 2 rods partially dropped into. the core ( F12 at 110 steps, K4 at 193 steps, D6 at 197 steps, and H10 at 198 steps).
Power was reduced to less than
then the firing card was replaced.
The urgent failure alarm reset.,
and the power cabinet and associated control rods were declared operable at 12:20 p.m.;
however, the unit was still in the original 6-hour LCO due to the rod misalignment.
At 1:21 p.m., the 4 rods were realigned, and the 6-hour LCO was exited.
During the event,
-the accumulated penalty deviation time for axial flux difference outside the target band was greater than 60 minutes.
The action statement for TS 3.2. 1 required that reactor power remain below 50% and the neutron flux high trip setpoint 'be reduced to 55K
, until the cumulative penalty deviation time wa's reduced to less than 60 minutes.
The requirements of this TS were met, and the unit was returned to 100% power at 9: 15 p.m.
on November 14, 1991.
At 1:00 a.m.
on November 14, 1991, all inservice blackstart diesel generators were declared out of service due to a
ground on the 4160-volt cranking diesel bus.
The No. 4'lackstart diesel generator
.had already been taken out of service for preventive maintenance.
All blackstart diesel generators except for No.
4 were returned to service at 4:20 p.m.
on the same day.
The No.
4 blackstart diesel generator was returned to service at 10:30 p.m.
on November 15, 1991.
On November 15, 1991, the licensee inserted new values for delta temperature at rated thermal power for Unit 3 based on calculations utilizino data taken from a
100%
power calorimetric.
These new values were approximately 1 to 1-1/2 degrees F less than the previous values, which were extrapolated from calculations utilizing data taken from a 75K power calorimetric.
Following this change, Unit 3 began to receive spurious signals resulting in automatic turbine runback rod block alarms and overtemperature delta temperature rod stop alarms on the B loop.
A two-out-of-three logic must be satisfied in order to get an, actual turbine runback.
In. order to prevent the possibility of an inadvertent automatic turbine runback due to noise on the overtemperature delta temperature signals, the licensee reduced reactor power on Unit 3 to 95K at 11:00 p.m.
on November 17, 1991.; Reactor power was further reduced to 85~ at 12:31 a.m.
on November 19, 1991, for monitoring of the overpower and overtemperature channels while the channel II bistables were in the tripped position.
The unit was returned to 95Ã power at ll:30 a.m.
on November 19, 1991, in order to establish conditions for continued investigation of the Eagle 21 average temperature and delta temperature input signals.
The licensee developed a temporary system alteration and safety evaluation to permit monitoring of Eagle
test points via a strip chart recorder without placing the channel in
9
~
r the tripped mode.
Further investigation revealed that the installation of the Eagle 21 system and the removal of the RTD bypass loops resulted in the licensee decreasing the value of delta temperature at rated thermal power.
This also changed the overpower delta temperature and overtemperature.delta temperature setpoints in the conservative direction and brought the trip and runback settings closer to the 100K value of delta temperature.
These values vary with changes in the core parameters that affect the equations that determine overpower delta temperature and overtemperature
'delta temperature.
It was the reduction between the actual" delta temperature and the setpoints that caused the alarms.
Further studies and calculations with input from the Westinghouse representatives determined that the runback settings could be.
revised.
Instead of the old values of 1-1/2 degrees F and 2-1/2 degrees F for the overpower delta temperature and the overtemperature delta temperature runbacks, the new value is 1. 1 degrees F for both runbacks.
This is equivalent to a power change of 2X.
The licensee developed a'C/M and corresponding safety evaluation to facilitate this change.
The new runback setpoi nts should provide adequate margin between the 100% value for delta'emperature and the runback setpoints for normal operations and still maintain sufficient operator response time to prevent a reactor trip if a runback occurs.
The runback setpoint changes were incorporated on November 22, 1991, and Unit,3 reactor power was returned to 100% at 6:30 p.m.
on the same day.
Although the noise on the overtemperature delta temperature and overpower delta temperature signa'ls appeared to be within acceptable limits, the licensee is continuing to work with Westinghouse to evaluate the fluid dynamic effects o'n the hot leg RTOs.
The inspectors will follow up on any additional licensee actions regarding this matter.
On November 16, 1991, at 6:10 p.m. with Unit 3 at 100>>
power, the operators observed that the SE intercept valve was:-indicating shut.
Based on a
- caution in procedure 3-0SP-089, Main Turbine Yalve Operability Test, for the condition of being unable to reopen 'the intercept valve within five minutes of its closure, the operators reduced power to less than 100 MWe.
Inspection determined that a
crack in the turbine control oil pipe to the SE intercept valve was responsible for the valve closure.
The pipe crack was downstream of a regulating orifice which permitted isolating the crack.
The pipe was cut to remove the failed 'portion and rethreaded for reassembly.
The pipe repair was completed at 6:25 a.m.
on November 17, 1991.
Power was restored to 100". at 1:25 p.m.
on November 17, 1991.
Initial root cause evaluation attributed the pipe break to fatigue stress of a
threaded 'pipe.
-
This is the second event on Unit 3 involving turbine control oil pipe break since Unit 3 startup on September 26, 1991 (Refer to IR 50-250,251/91-42, paragraph 11.a for additional information.).
Yiolations or deviations were not identifie e e
Exit Interview (30703)
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 November 22, 1991.
The areas requiring management attention were reviewed.
Proprietary materials were reviewed during the course of this inspection but were not included in this report.
Dissenting corments were not received from the licensee.
Violations or deviations were not identified.
The inspectors had the following findings:
Strength
--Prompt operator action to preclude a reactor trip (paragraph 10.a).
Concern - Lack of procedural requirements for interface of operations between nuclear and non-'nuclear divisions (paragraph 10.c).
Acronyms and Abbreviations AFD AFW CCW CFR CNRB CV CYCS DRC EDG ESF FPL GOP HDP ICRR ICW IFI IR KV LCO LER HWe NCV NLO NPO NRC NWE
.ONOP OOS OP OSP PC/M PCV psid Axial Flux Difference Auxiliary Feedwater Component Cooling Mater Code of Federal Regulations Company Nuclear Review Board Control Valve Chemical Volume and Control System Digital Reactivity Computer Emergency Diesel Generator Engineered Safety Feature Florida Power 5 Light General Operating Procedure
.
Heater Drain Pump Inverse Countrate Ratio Intake Cooling Water I'nspector Followup Item Inspection Report
~'i 1 ovol t Limiting Condition for Operation Licensee Event Report He'gawatts Electric Non-Cited Violation Nuclear Licensed Operator Nuclear Plant Operator Nuclear Regulatory Commission Nuclear Watch Engineer Off Normal Operating Procedure Out of'ervice Operating Procedure Operations Survei'llance Procedure Plant Change/Hodification Pressure Control Valve Pounds Per Square Inch Differential
psl 9 PTN QA QAO QC RCA RCC RCO RCS RTD SE SFP SGFW SNPO SRO STA TS URI VCT YIO Pounds Per Square Inch Gauge Plant Turkey Nuclear Quality Assurance Quality Assurance Organization Quality Control Radiation Controlled Ar'ea Rod Control Cluster Reactor Control Operator Reactor Coolant System Resistance Temperature Detector Southeast Spent Fuel Pit Steam Generator Feedwater Senior Nuclear Plant Operator Senior Reactor Operator Shift Technical Advisor Technical Specificati'on Unresolved Item Volume Control Tank Violation