IR 05000250/1997004
| ML17354A522 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 05/30/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17354A521 | List: |
| References | |
| 50-250-97-04, 50-250-97-4, 50-251-97-04, 50-251-97-4, NUDOCS 9706100100 | |
| Download: ML17354A522 (60) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos.:
50-250 and 50-251 License Nos.:
DPR-31 and DPR-41 Report Nos.:
50-250/97-04 and 50-251/97-04 Licensee:
Florida Power and Light Company Facility:
Turkey Point Units 3 and 4 L'ocation:
9760 S.
W. 344 Street Florida City. FL 33035 Dates:
March 30 through May 10, 1997 Inspectors:
T.
P. Johnson.
Senior Resident Inspector J.
R.
Reyes, Resident Inspector J.
W. York, Acting Resident Inspector Approved by: K.
D. Landis. Chief Reactor Projects Branch 3 Division of Reactor Projects 970hi00i00 970530 PDR ADOCK 05000250
EXECUTIVE SUMMARY TURKEY POINT UNITS 3 and 4 Nuclear Regulatory Commission Inspection Report 50-250,251/97-04 This integrated inspection to assure public health and safety included aspects of licensee operations, maintenance.
engineering, and plant support.
The report covers a six week period (March 30 to May 10, 1997) of resident inspection.
~0erations o
The Unit 3 startup from ref'ueling was professionally conducted, with strong oversight and good communication.
Steam generator level control was very good (section 01. 1).
o Non-licensed operator performance was generally good.
Two examples of poor performance were self-identified during log keeping rounds and hotwell draining operations.
and these issues were appropriately addressed (section 01.2).
e The intake and component cooling systems were appropriately aligned (section 02.1).
e A licensee event report concerning a Unit 3 mode change without steam generator blowdown and sample valve automatic isolation logic available was a licensee-identified non-cited violation (section 03; 1)
~
An operations procedural weakness contributed to a reactor cooling system dilution and resultant, small power increase (section 03.2).
~
Weaknesses in operation's control of Unit 3 during fill and vent activities resulted in a power operated relief valve being inadvertently opened (section 04. 1).
~
Operator response to a Unit 4 automatic trip was noteworthy.
Operators demonstrated professionalism, excellent communications and coordination, strong command and control, and excellent procedure use.
This reflected well on operator training programs (section 04.2).
~
A poor pre-trip Unit 4 decision made by shift supervision to remove turbine indications during a risk-related surveillance resulted in a more difficult response by operators (section 04.2).
The licensee safely conducted a Unit 4 short notice outage (section 06.1).
Management's self-assessment process prior to Unit 3 startup from refueling was noteworthy (section 07. 1).
o The inspectors attended a portion of the Company Nuclear Review Board on April 15, 1997, and noted that the meeting met the Technical Specifications and procedural requirements.
A good questioning attitude and safety focus we.
noted (section 07.2).
Mixed performance has been noted in the operations area for the past six months.
Licensee self-assessment and improvement programs have been developed, and this area
.was determined to be an open item (section 07.3).
o A strong questioning attitude by an Assistant Nuclear Plant Supervisor led to a discovery of a maintenance pre-conditioning practice (section H1.3).
o Operators responded well to a loss of the 3C non-vital bus (section M2.4) and to an auxiliary feedwater start (section H1.4).
Maintenance Observed maintenance and surveillance.activities were well performed (section Hl.l).
The Unit 3 integrated safeguards testing was well conducted with excellent oversight and strong procedure compliance (section M1. 2).
The failure to document four hour analog rod position checks with the Unit 3 rod deviation monitor out-of-service was a licensee identified non-cited violation (section H1.3).
Weaknesses were identified in the control of balance-of-plant instrument valves.
This led to an inadvertent auxiliary feedwater start (section H1.4).
Licensee corrective actions to address Unit 3 rod control problems appeared to be aggressive and thorough (section H2.1).
The licensee appropriately reviewed, dispositioned, and identified corrective actions for an intake cooling water pump motor failure (section H2.2).
During a Unit 3 containment closeout inspection, the inspector noted that the containment was relatively clean and in a good material condition (section H2.3).
Maintenance response to a loss of the 3C non-vital bus was appropriate and thorough (section H2.4).
A leak in the oil system of the non-safety related, risk important, B standby steam generator feed pump was addressed in a
'
timely manner and appropriately handled by the licensee (section M2.5).
En ineerin The system engineer for the intake cooling water and component cooling water systems demonstrated excellent knowledge and a very good oversight of problems/potential solutions during a walkdown inspection with the inspectors (section 02. 1).
Engineering and Event Response Team activities associated with a Unit 4 tr,ip were well conducted and noteworthy (section 04.2)
Engineering support of, maintenance relative to the failures of the 3C non-vital bus, the B standby steam generator feed pump, and the intake cooling water pump motor were very good (sections M2.2, M2.4. M2.5).
Unit 3 startup and physics testing were effectively controlled and conducted with very good coordination.
However, weaknesses were noted relative to the reactivity computer connections and setup procedures (section El.l).
Excellent support by the engineering group was provided for operation and maintenance in affecting non-routine temporary repairs for a leaking non-safety related Unit 3 feedwater pump (section E1.2).'he management and engineering support for accomplishing a non-code repair for a Unit 4 pressurizer spray valve was excellent (section E2.1).
Issues were appropriately addressed by an Event Response Team in reviewing a high seal leak off rate on a Unit 3 reactor coolant pump (section E2.2).
There was appropriate engineering support provided f'r operations and maintenance in performing a leak repair to the Unit 3 seal table (section E2.2).
A licensee event report regarding safety injection pump casing leaks was factual, well written, and discussed appropriate causes and corrective actions (section E3.1).
The material was appropriate and the instruction was very good for requalification training for Plant Nuclear Safety Committee members (section E5. 1).
Plant Su ort Unit 3 containment entries and inspect; "--
ppropr ately followed radiation and personnel safety requirements.
Health physics personnel provided very good oversight (section Rl. 1).
The licensee appropriately responded and reported a fitness-for-duty issue (section S1.1).
The licensee conservatively and appropriately reacted to Unit 3 Unusual Event due to reactor leakage (section Pl.1).
An Emergency Plan drill was well performed and an excellent training mechanism (section P5. 1).
TABLE OF CONTENTS Summary of Plant Status I.
Operations II.
Maintenance III.
Engineering
IV.
Plant Support
V.
Management Meetings..
Partial List of.Persons Contacted.
List of Items Opened, Closed and Discussed Items List of Inspection Procedures Used..
List of Acronyms and Abbreviations..
24
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. 26
REPORT DETAILS Summary of Plant Status Unit 3 At the beginning of this reporting period
~ Unit 3 was shutdown in Hode 5 completing the cycle 16 refueling outage.
The unit restarted on April 14 and went on-line on April 16, 1997 (section 01.1).
The unit operated at full power the remainder of the period.
Unit 4 At the beginning of this reporting period, Unit 4 was operating at or near full reactor power and had been on line since February 3.
1997.
The unit automatically tripped from 100K power on April 23, 1997 (section 04.2).
The unit returned to service on April 26.
1997.
The unit operated at full power the remainder of the period.
Common NRC Commissioner Nils Diaz and Region II DRS Director Johns Jaudon visited the Turkey Point site on Hay 1, 1997.
They toured the facility and met with licensee employees and management.
A team from NRR and Region II reviewed the Turkey Point thermo-lag upgrade project on-site during the period Hay 6-7, 1997.
Results of this review will be promulgated by future correspondence.
0 erations Conduct of Operations Unit 3 Mode Chan es and Startu 61703 71707 and 71711 Unit 3 transitioned from Mode 5 to Mode 1 during the period April 2 to April 17, 1997.
The unit achieved criticality at 9:03 p.m.
on April.
14, 1997, and was placed on-line April 16, 1997.
This ended the Unit 3 Cycle 16 refueling outage.
The outage was originally scheduled for 32 days and was completed in 44 days.
Following completion of the turbine overspeed test, the unit was placed back on-line on April 17, 1997.
While in Mode 3 on April 6, 1997, an identified reactor coolant boundary leakage resulted in a cooldown to Node 5 and an Unusual Event (section Pl. 1).
The inspectors noted that the Unit 3 outage delays were caused by problems with the R-11/12 radiation monitor, a
3C Bus trip, reactivity computer problems, reactor coolant pump (RCP) seal leak-off abnormalities, and seal table leakage.
Some of the selected issues are discussed further in the following report sections.
Notwithstanding
01.2
02. 1 these delays, the licensee demonstrated conservatism and aggressiveness in dealing with these issues.
The inspectors observed portions of the startup activities, power ascension, turbine overspeed testing, Main Steam Isolation Valve (MSIV)
testing, Auxiliary Feedwater (AFW) testing, and other related activities.
The inspectors noted strong oversight and good communication and concluded that the Unit 3 startup was professionally conducted.
Steam generator (SG) level control was very good.
Non-licensed 0 erator NLO Performance 71707 During the period, the inspectors reviewed non-licensed operator (NLO)
performance.
This included review of performance during normal and routine operations, unit startup and shutdown activities, outage evolutions, and Unit 4 trip operations.
NLO performance was generally good with two noted exceptions.
These two noted occurrences affected Unit 3 during the final phases of the refueling outage.
On April 4, 1997, a low nitrogen pressure for backup supply to the AFW flow control valves was noted by the turbine building NLO; however, actions were not taken to changeout the affected bottles.
CR 97-0687 addressed this issue.
AFW operability was not affected.
Weaknesses were identified in the NLO follow through and control room response to this out-of-specification reading.
Corrective actions included personnel discipline, nite order book notifications, increased emphasis in log readings, and training assessments.
On April 2, 1997, a
NI 0 drained the Unit 3 hotwell to the west condenser pit.
The draining rate was too high causing the pit to flood which covered the ammertap motors.
CR 97-0666 was written to address this issue.
The licensee concluded that poor work controls and an inexperienced NLO were causes.
The non-safety related motors were all replaced.
Corrective actions included procedure and clearance enhancements, issuance of a training brief and retraining, personnel counselling, nite order book promulgation of the event for all personnel, and posted local placards cautioning operators when draining the hotwell.
The inspectors reviewed each of these two CRs.
and discussed the issues with operations and management personnel..
The inspectors concluded that the licensee appropriately followed up on these two occurrences.
Operational Status of Facilities and Equipment Com onent Coolin Water CCW and Intake Cool in Water ICW S stems Wa1 down 71707 The inspector was accompanied by the system engineer during a walkdown of the CCW and ICW systems.
The walkdown was performed on Unit 3, with some of Unit 4 components also being examined.
These two systems are both safety-related and risk significant.
The function of various
W
03. 1 pa'rts of the system were discussed along with past problems that the system had encountered.
The retubing of the 3A (scheduled)
and 3B (completed)
CCW heat exchanger difficulties with the new ultrasonic flow detectors (installed near the basket strainers),
and steps that are being taken for resolution of the problems were discussed with the system engineer
.
The housekeeping on these systems and the valve alignments were acceptable.
The system walkdowns included control room indicators and controls.
During the earlier part of the inspection period, there was an indication that 4A CCW pump may be having a vibration problem.
The system engineer was aware of the problem and the potential repair for the pump.
Pump vibration levels were increasing and this may have been indicative that one of the bearings is beginning to deteriorate.
The licensee, under observation of the system engineer and manager, had tested the vibration level by running the pump a number of times and for a longer period of time than required by the ASME Code.
Only one vibration value fell into the alert range for the pump (reference Manual No. 10816, Mechanical Vibration-Evaluation of Machine Vibration by Measurement on Non-rotating Parts).
The licensee conservatively assumed this higher value and doubled the number of surveillances on the pump.
The licensee intends to replace this bearing as soon as the parts are available and a schedule can be established.
The licensee concluded that there was no operability concern.
The inspectors concluded that the system engineer was very
.
knowledgeable on these systems and was aware of the current problems and potential solutions that were being proposed.
Further
. the ICW and CCW systems were appropriately aligned.
Relative to the 4A CCW pump vibration issue, the inspectors concluded that operability was addressed and that the licensee was following ASME code requirements.
Operations Procedures and Documentation Unit 3 Mode Chan e Without Steam Generator SG S stem Isolations 93702 92700 90712 At 9:00 a.m.
on April 10, 1997, while in Mode 4, Unit 3 operators noted that the SG Blowdown system interlock bypass keylock switches were in the "Drain/Fill" position.
This position blocks the automatic closure of the SG blowdown and sample isolation valves.
The unit entered Mode 4 at 3:49 p.m.
on April 9, 1997.
TS 3.6 '
requires that containment isolation valves be operable in Modes 1 through 4.
UFSAR section 6.6 (Table 6.6-1) states that the SG blowdown valves (CV-3-7275 A, B. C)
and SG sample valves (MOV-3-1425, 6, 7) are automatic containment isolation valves which will close on a containment phase A or 8 safety injection (SI) signal or on a containment ventilation isolation signal.
Although a number of the initiation signals are not required in Mode 4 (e.g.,
low pressure SI, containment high pressure SI. steam break SI.
and AFW auto start)
TS 3.0.4 does not allow mode changes without meeting the required operability requirements.
The auto closure function for these SG isolation valves was unavailable for 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> and
~
'
11 minutes.
TS 3.6.4 action d requires a cold shutdown (Hode 5) entry within 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> without the closure and isolation operability being met.
The licensee's investigation concluded that inadequate operating procedures (OP and GOP)
and an operator knowledge level deficiency relative to these keylock switches were causal factors.
Corrective actions included:
immediate switch repositioning, CR and LER submittals, nite order briefings, procedure changes planned, development of a switch/indicating light verification checklist for mode changes.
UFSAR clarifications, and planned training.
The licensee's review into this issue noted that these SG isolation valves provide a single isolation barrier as the SG tubes inside containment provide the passive barrier.
UFSAR Table 6.6-3 and the TSs do not list these SG valves as automatic. containment isolation valves.
Further, the original Westinghouse design specification did not consider these SG valves as containment automatic isolation valves.
For convenience, these valves were given containment phase A and SI signals for closure.
In addition. the UFSAR section 14 (accident analysis)
does not consider a
SG tube rupture.
main steam line break, loss of feedwater, or other reactivity events while in Mode 4.
A Mode 4 loss-of-coolant-accident (LOCA) would be addressed by ONOPs which include procedural steps to ensure SG isolation valve closure.
Based on the above, the licensee concluded that there was no safety impact with these SG isolation valves'eylock switches in a bypassed condition.
The inspector reviewed the CR, Unit 3 LER No. 97-03 dated May 9, 1997, the TS and UFSAR applicable sections, and discussed the issue with operators and management.
The failure to have the Unit 3 SG system isolations available during the transition from Mode 5 to Mode 4. was a
violation of TS 3.0.4.
This licensee-identified violation is being treated as a non-cited violation (NCV) consistent with Section VII.B.1 of the NRC Enforcement Policy.
NCV 97-04-03, Failure to Meet TS 3.0.4 and Unit 3 LER No. 97-03 were closed.
Unit 4 Dilution Durin Chan cput of Demineralizer 71707 On May 2, 1997, during the dayshift. chemistry requested operations to use a newly recharged demineralizer (4D) for lowering the level of lithium in the RCS.
Since this was a newly charged demineralizer, operations was saturating the boron level in the unit to the same level as found in the RCS (470 ppm boron) by running RCS water through the unit and then to the CVCS holdup tank.
Upon notification from chemistry that the lithium level reached the proper level. operations placed the VCT level control switch LC-4-112A to automatic.
In this position, without the deminer alizers in bypass.
the flow thr ough the 4D demineralizer was going to the VCT.
This flow had a 200 ppm boron concentration while the RCS had a concentration of 470 ppm. With a flow of 50 gpm to the VCT the primary was being diluted and this continued for 12 minutes.
The power and average temperature began to slowly
04.1 increase.
The RCO noted this condition and took necessary action to mitigate the increases by borating the RCS by adding 35 gallons.
and by driving the control rods in eight steps.
Power reached 100.3X In addition, the licensee's investigation (CR No. 97-0934)
revealed that due to a procedural inadequacy there was a time delay between LCV-4-112A being placed in the automatic position and TCV-4-143 being positioned so that flow goes to the VCT without going through the demineralizers.
This allowed the diluted water to go to the VCT.
Procedural changes have been made for both units which requires LCV-3/4-143 to be positioned for flow to the VCT prior to placing LCV-3/4-112A in automatic.
The inspectors concluded that a procedural weakness was the major contributor to the dilution occurrence.
Licensee corrective actions were prompt and thorough.
Operator Knowledge and Performance Unit 3 Power 0 crated Relief Valve PORV Actuation 71707 and 90713 On April 1, 1997. at about 1:23 a.m.,
one of the Unit 3 PORVs lifted as demanded by the Overpressurization Mitigation System (OMS).
Unit 3 reactor fill and vent operations were being performed with periodic RCP runs.
One charging pump was in service.
The plant was solid in cold shutdown, with primary pressure 300 to 350 psig, and procedure 3-OP-
.
41.8, Filling and Venting the Reactor Coolant System, in progress.
Pressure increased to about 410 psig and one PORV lifted for about one second by the OMS.
TS 3.4.9.3a requires a
PORV setpoint of between 400-430 psig.
Operators secured the running charging pump and returned RCS pressure to normal.
CR No.97-648 was initiated and the licensee reported the event per TS 3.4.9.3.e by submitting a special report as documented in a licensing letter (L-97-102).
The licensee concluded that the cause of the PORV actuation was poor operator attention, ineffective supervisory oversight.
and a weak pre-evolution briefing.
In addition, minimal margin between the high pressure alert alarm of 400 psig and the PORV lift pressure of 415 + 15 psig was a contributing factor.
Corrective actions included personnel counselling, procedure enhancements, improvements in training of personnel.
planned changes for the high pressure OMS alert alarm, and nite order book entries to brief all personnel.
The inspector reviewed log entries, the CR, the special report, and control room charts and computer printouts.
The inspector also reviewed other PORV lift events in 1992 (L-92-340) and in 1993 (L-93-28).
The inspector attended the PNSC meeting which reviewed and approved the special report.
The inspector noted that the licensee's followup was thorough, including cause determination and corrective actions.
The inspector concluded this event to be a weakness in
operations control of'lant conditions during reactor coolant fill and vent.
and pressurizer solid operations.
Unit 4 Automatic Reactor Tri Ins ection Sco e
71707 and 93702
The inspectors reviewed licensee response to an automatic Unit 4 reactor trip on April 23, 1997.
Observations and Findin s At 10:54 a.m.
on April 23, 1997, Unit 4 automatically tripped from 100K power due to an overtemperature-delta-temperature (OTbT) signal.
An inadvertent actuation of the turbine overspeed protection controller (OPC) resulted from an apparent IKC technician bumping into a relay (R/OPC) while working in control room panel 4C02.
The OPC actuation closed the turbine control and intercept valves as designed.
This resulted in a loss of load, a steam dump to atmosphere and safety valve actuation.
and a trip in about 10 seconds due to an OTBT signal.
Primary temperature increased due to the load loss.
causing the OTbT setpoint to decrease.
All control rods inserted on the trip.
SG levels remained above the AFW low level initiation setpoint.
In response to unrelated turbine valve position circuit work, operators closed the HSIVs.
The steam dumps to the condenser were unavailable due to a prerequisite for an 18C surveillance procedure that was in progress.
The licensee maintained the unit in Node 3 (hot standby).
EOPs were entered as required.
The primary pressure and temperature transient lifted the primary PORVs as-expected, and both PORVs reseated.
Primary pressure reached 2350 psig (normal is 2235 psig)
and primary temperature reached 581'F (normal'is 574'F at 100K and 547'F at no load).
These parameters were returned to their normal values by both the automatic control systems and by operator manipulations.
SG and pressurizer levels were controlled by manual operator actions.
An NRC notification pursuant to 10 CFR 50.72 was made at 11:37 a.m.
Unit 4 LER No. 97-02 was-submitted.
The licensee initiated an ERT and post trip review.
These actions were documented in CR No.97-786.
The licensee concluded that plant systems responded as expected for the plant conditions.
UFSAR chapter 14 was reviewed, and Unit 4 response was consistent with the transient analysis.
The licensee concluded that the trip was due to inadvertent manual agitation of the R/OPC relay by an 18C technician.
The technician was working on the calibration of the CST level gauge within the control room panel.
Causal factors included less than adequate work controls and environment, (dark, cramped cabinet)
an exposed relay (e.g.,
no cover) with no labelling relative to a trip hazard.
and the design of relay (e.g.,
susceptible to minimal agitation).
06.1 The PNSC and plant management reviewed the trip, and authorized restart pending completion of containment leak repairs (sections H1.1 and E2. 1).
The PNSC noted excellent operator res,"""
~o the t. an ient.
Corrective actions were addressed and documented in the CR and in the LER.
The inspectors were in the control room at the time of the trip and reviewed the trip response.
EOP implementation and notification actions were witnessed.
The inspectors observed strong operator performance in response to the trip.
Actions were well communicated and coordinated, and NPS command and control was effective.
However, the pre-trip decision by shift supervision to remove turbine indications at the same time a load threatening surveillance was being performed, was poor.
Although these activities did not cause the trip, they made the response more difficult.
The inspectors also reviewed post trip review and ERT activities.
CR 97-786 and Unit 4 LER No. 97-02 were reviewed along with control room logs, charts, sequence of events recorder, prints, PMOs, and other related documentation.
The inspectors also reviewed a Training brief (97-128)
and an Information bulletin (97-25)
The inspectors verified the R/OPC relay was not labelled.
and in a sensitive area for related work.
The inspectors confirmed that license root cause determination and corrective action recommendations were thorough and appropriate.
The inspectors also observed a simulator run paralleling the actual trip.
Conclusions Licensee response (operator.
engineering and ERT, and management including the PNSC) to a Unit 4 automatic trip was noteworthy.
Operators demonstrated professionalism.
excellent communications and coordination, strong command and control.
and excellent procedure use.
This reflects well on the operator training programs.
Engineering and ERT involvement was thorough and demonstrated excellent plant knowledge.
PNSC and plant management demonstrated a conservative approach to the post trip activities.
However, a poor pre-trip decision by shift super vision to remove turbine indications during a
load threatening surveillance resulted in a more difficult response.
Unit 4 LER No. 97-02 was closed.
Operations Organization and Administration Unit 4 Short Notice Outa e
SNO 71707 The licensee conducted a Unit 4 outage (SNO) after an unplanned automatic trip (section 04.2) during the period April 23-26, 1997.
Besides trip root cause determination and related corrective actions, the licensee.repaired several primary system leaks.
Operations established plant conditions and system clearances for these repairs.
The repairs included valve packing leakage and body-to-bonnet leaks (sections Hl. 1 and E2. 1).
After a) 1 work was completed, management
authorized restart.
The unit was taken critical at 1:10 P.M.
on April 26, 1997 and placed on-line at 6:28 p.m.
Full power was achieved at 9:00 p.m.
on April 27, 1997.
The inspectors reviewed the SNO work list and outage organization.
Outage shift directors provided management oversight and control of the work.
Periodic outage meetings provided good communications between departments.
The inspectors also observed portion's of the work activities and restart for the unit.
The inspectors concluded that the licensee safely conducted the short notice outage on Unit 4.
Quality Assurance in Operations 07.1 Unit 3 Startu Readiness a.
Ins ection Sco e
40500 71707 and 71711 The inspectors evaluated Unit 3 readiness for restart after the Cycle 16 refueling outage Observation and Findin s In addition to the normal general operating procedural controls for heatup and startup (procedures 3-GOP-503.
Cold Shutdown to Hot Standby.
and 3-GOP-301, Hot Standby to Power Operation),
the licensee performed independent verifications and checks by implementing administrative procedure O-ADM-529,,Unit Restart Readiness.
This included:
System Engineer completion of readiness checklists for their specific systems:
Review of the clearance log, open issues (PMAIs. fire impairments, PC/Ms, TSAs. condition reports.
system lineups.
and surveillances):
Letters from each department head documenting readiness for restart; PNSC reviewed readiness; and Plant General Manager final review and determination.
The inspectors assessed the licensee's process.
attended the related PNSC meetings.
reviewed the completed restart readiness procedure, and discussed the process with licensee management.
The inspectors concluded that this process appeared effective and demonstrated conservatism in assuring that Unit 3 would be safely returned to service following the refueling outag ~,
The inspectors independently assessed Unit 3 restart readiness by performing the following tasks:
Reviewed selected open and closed work items including post-maintenance testing, deficiencies, and commitments (e.g.,
condition reports, PWOs PHAIs, CTRAC items, etc.);
Verified system lineups and equipment availability by checking TSAs, system operating procedure checklists, the TSA log, clearances, and the equipment out-of-service log; Toured the facility including the Unit 3 containment; Reviewed control room instruments, alarms, and controls; Reviewed general operating procedure implementation; Reviewed operator training and readiness; Reviewed outage PC/H completion, testing, and turnover (e.g..
ITOP and SATS);
Reviewed startup testing procedures and readiness; Reviewed surveillance testing completion; Reviewed and verified local leak rate testing and containment integrity; and Reviewed ISI and erosion/corrosion inspections and repairs.
c.
Conclusions The inspectors concluded that Unit 3 was ready to support power operation.
One noteworthy item was management's self-assessment process.
Hanagement self-assessment included the restart readiness procedure process discussed above.
07.2 Inde endent Reviews and Self Assessment 40500 The inspector attended a portion of the Company Nuclear Review Board (CNRB) meeting No. 442 held at Turkey Point on April 15, 1997.
The inspector verified that the meeting was conducted in accordance with Technical Specification 6.5.2, NP-803 (Nuclear Policy-CNRB), and the CNRB implementing procedures.
The CNRB normally meets monthly.
rotating the locatio'n of the meeting among the three FPL sites(i.e..
Turkey Point. St. Lucie.
and Juno Beach).
Usually representatives from all three locations are present at each meeting.
The inspectors also attended several PNSC meetings that involved activities that were being inspected in greater detail i.e.,
pump repairs, operation events, etc.
Technical Specifications and procedure
requirements were verified, including meeting frequency.
quorum, and review responsibi 1ities.
The inspector concluded that the CNRB and PNSC meetings conformed to procedures guidelines.
A good questioning attitude was noted by safety committee members.
07.3 0 erations Self-Assessment 71707 and 40500 The inspectors have noted mixed performance in the operations area over the past six months.
Events and issues were discussed in NRC
Inspection Report
Nos. 50-250.251/97-03,.97-01
and 96-13,
and in this
current report.
The apparent
causes
of these
issues
included:
Examples of poor attention to detail
by licensed
and non-licensed
operators,
Examples of poor procedure
compliance
and logkeeping
by non-
licensed operators,
Indications of a lack of a questioning attitude by some
new and
inexperienced operators,,
Examples of ineffective supervisory oversight,
Conflicting evolutions conducted at the
same time,
and
Examples of poorly communicated instructions
from the Control
Room.
As discussed
in NRC Inspection
Report
No. 50-250 '51/97-01,
section
07.2, operations
error reduction programs
were effective in reducing
valve positioning problems during the period 1995-1996.
Currently,
plant and operations line management,
and the independent
organization is reviewing these operations
issues.
Proposed
and
completed corrective actions
have included:
Plant Hanager
meetings with all operators,
gA human performance
review of selected
events,
Operations
self-assessment
scheduled for the near future.
Nite order entries,
Operations
Hanager
and Supervisor briefings for all crews,
and
Each operating shift review and discussion of the recent events.
The inspectors
consider this area to be an open item pending completion
of the above corrective actions
and operations
performance
improvements:
Inspector
Followup Item (IFI), Oper ations
Sel f-
h
Assessment
and Performance
Improvements
(50-250.251/97-04-01)
was
opened.
II. Maintenance
M1
Conduct of Maintenance
Hl. 1
General
Comments
a.
Ins ection
Sco e
61726 and 62707
Maintenance
and surveillance test activities were witnessed or
reviewed.
The inspector witnessed or reviewed portions of the following
maintenance activities in progress.
Unit 3 rod control maintenance
and testing (section
H2. 1),
Unit 3 containment radiation monitor troubleshooting
Unit 4 primary valve repairs
{section 06. 1 and E2.1).
Unit 3 seal table H-1 repair (section EZ.3).
The inspectors
witnessed
or reviewed portions of the following test
activities:
Unit 3 startup test procedures
O-OSP-40.5
and 40.6 (section
E1.1),
Unit 3 Integrated
Safeguards
Testing (section Hl.2).
Unit 3 turbine overspeed test (section 01.1).
Unit 3 HSIV testing (section Ol.l).
Unit 3 AFM testing (section 01.1).
Observations
and Findin s
For those maintenance
and surveillance activities observed
or reviewed,
the inspectors
determined that the activities were conducted in a
satisfactory
manner
and that the work was properly performed in
accordance with approved
maintenance
work orders.
The inspectors
also determined that the above testing activities were
performed in a satisfactory
manner
and met the requirements
of the
technical specification Conclusions
Observed
maintenance
and surveillance activities were well performed.
Unit 3 Inte rated Safe uards Testin
61726
During the period March 29-30.
1997, the licensee
performed Unit 3
procedures
3-0SP-203.1,
Train A Engineered
Safeguards
Integrated Test,
and 3-0SP-203.2,
Train 8 Engineered
Safeguards
Integrated Test.
Technical Specifications
required testing various engineered
safeguards
features
including Safety Injection with and without off-site power,
containment
phase
A and
8 isolation,
loss of off-site power,
isolation.
main steam line isolation, control
room ventilation
isolation,
and containment ventilation isolation.
~ The inspectors
observed portions of these tests
and verified selected
test results.
Apparent system
abnormal
responses
were either evaluated
as satisfactory
or portions of'he tests were re-run.
No significant
problems were noted.
The inspectors
concluded that the Unit 3
integrated
safeguards
testing
was well conducted with excellent
oversight
and strong procedure
compliance.
Rod Deviation Monitor
90712 and 92700
a.
Ins ection Sco
e
The licensee
submitted Unit 3 LER 97-01 due to a missed surveillance
as
requi red by TSs 4. 1.3.1.1
and 4.1.3.2.1.
These
TSs require that analog
rod positions
be monitored every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
If the rod deviation
monitor is
OOS. the TSs require analog rod positions
be monitored every
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
The licensee
determined that the rod deviation monitor was
technically
OOS for about
a five month period (August 1996 to January
1997).
Observations
and Findin s
Although the rod deviation monitor was not itself designated
as
a TS
instrument,
the monitor's availability determines
the frequency of rod
position monitoring.
I&C personnel
were having difficulty in
performing
a monthly preventive maintenance
(PM) procedure for the rod
deviation monitor.
Subsequent
PMs noted the instrument to be drifting.
I&C personnel
began cleaning the electronic card connections prior to
the
PM in order to achieve the required acceptance criteria.
The
licensee
concluded this to be "pre-conditioning".
and therefore not a
valid PM.
Thus, the rod deviation monitor
was technically
OOS and 4
hour rod positions were not taken (the licensee actually logged
8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />
rod positions routinely).
Licensee root cause evaluation determined that the
I&C practice of
"pre-conditioning" was due to a lack of understanding
for
PH processes
and procedures
that support survei llances or TS requirements.
The
cause of the bad card for the rod deviation monitor was
a bad
connector.
Corrective actions
completed or planned included the following:
I8C supervisory personnel
were counselled,
Maintenance
personnel
were either trained or scheduled to be
trained to better
recognize "pre-conditioning",
Procedures will be changed to ensure operations is notified of
all instrument problems,
ISC reviewed present practices to ensure
no other "pre-
conditioning" existed.
The faulty circuit card was repaired,
Open
PMOs were reviewed for similar issues
and none were found,
and
Similar circuit cards were inspected
and no other problems were
found.
The inspector noted that this self-identified missed surveillance
was
a
proactive observation
by an operations assistant
nuclear plant
supervisor
(ANPS).
The ANPS's questioning attitude discovered this
IEC
practice of "pre-conditioning" prior to one of the periodic rod
deviation monitor
PM procedure
implementations.
The inspector also
noted that the. licensee
documented
8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />
rod positions in lieu of the
r equired
12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
or
4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> (rod deviation monitor
OOS rod position).
Further, operator practice
was to routinely monitor
rod positions
during control board walkdowns.
However, these
were not documented
nor
logged.
Also, other than rod drops,
Turkey Point has not recently
experienced
rod position deviations.
Based, on, the above,
the safety
significance
was determined to be minor.
Conclusion
The failure to document
4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
analog rod position checks
on Unit 3
with the rod deviation monitor technically out-of-service
due to "pre-
conditioning" prior to a routine preventive maintenance activity was
a
violation of TSs 4.1.3.1.1
and 4.1.3.2. 1.
This licensee-identified
violation is being treated
as
a non-cited violation (NCV). consistent
with Section VII.B.1 of the
NCV 97-04-02,
Failure to Perform Control
Rod Position Verification Due to Inoperable
Rod Deviation Monitor, and Unit 3 LER No. 97-01 were close Unit 3 Auxi liar
Actuation
62707
At 5:03 a.m.
on April ll, 1997, the Unit 3."'.-!! system automatically
started
when the
3B SGFP tripped upon
a start attempt.
Unit 3 was in
Mode 3, at rated temperature
and pressure.
The 3A SGFP was
OOS and the
38 SGFP was started
from the control
room,
and immediately tripped.
The
AFW start logic saw this as
a trip of the last running
~ and
therefore auto started the
AFW system.
The
AFW auto start was.normal.
The licensee
made
a four hour
ENS call per
10 CFR 50.72 and submitted
Unit 3 LER No. 97-04.
The licensee initiated
a root cause investigation
per
CR No.97-723 and
formed an
ERT.
The licensee
concluded that the
3B SGFP oil pressure
ermissive switch (PS-3-2051) isolation valve (3-40-097B)
was closed.
hus, the
3B SGFP control logic tripped the
pump when the control
room
switch was placed in the start position due to a sensed
low oil
pressure.
Root cause determination
was inconclusive.
Corrective
actions included
a check of all Unit 3 instrument valves,
procedure
revisions,
personnel
counselling,
and evaluations relative to SGFP
starting alternatives.
No other
instrument valves were found out of
their required position.
The inspector
reviewed logs. the
CR, the LER, the
ERT report,
and
discussed this item with operations
and maintenance
personnel.
The
inspector
concluded that the licensee appropriately
reviewed
and
investigated this matter
.
Operator
response
was very good.
Weaknesses
were identified in I&C control of secondary plant instrument valves.
Unit 3 LER No. 97-04 was found to be adequate
and was closed.
Haintenance
and Material Condition of Facilities and Equipment
Unit 3 Rod Control Issues
Ins ection
Sco
e
62707
As, discussed
in section
E2.2 of NRC Inspection Report
No. 50-
250,251/97-01,
the licensee
has experienced multiple Unit 3 rod control
failures.
These
have included card failures,
power supply failures,
high ambient temperatures,
and component failures.
During the Unit 3
Cycle 16 refueling outage,
preventive
and corrective maintenance
and
special
and routine testing activities were conducted.
Observations
and Findin s
Unit 3 LER No. 97-02 and
CR 97-0275 Supplement
No.
1 addressed
relative
licensee actions,
including the following:
Plant procedure
O-PMI-028.5,
Rod Control System Preventive
Maintenance,
was completed.
The procedure verified power
supplies.
power supply auctioneering.
fuses,
logic cabinet timing
and firing card testin J
All Unit 3 Rod Control System firing cards
were replaced with a
new enhanced firing cards
purchased
from Ouke
Power
Corp.
The
new cards
reduce heat generated
in each "":: " binet.
R ducing
the operating temperature within the Power Cabinets is designed
to prolong the operating life of the control cards.
Cooling fans were added to'ach
Power Cabinet, to provide
additional cooling during system operation.
The new cooling fans
were added to reduce the operating temperatures
within the Power
Cabinets.
All Rod Control system printed ci rcuit cards were removed from
the system
and tested
by the vendor.
Firing, Phase.
and
Regulation control cards
from the
Power
Cabinets
were tested at
elevated
temperatures
using
a dynamic tester.
A zener
diode
replacement
was completed
as
a preventative
maintenance
action
(work order
number
97005555).
Testing of the cards
was
a
preventive maintenance activity to identify and correct potential
card failures.
The 3B
MCC room air handler
was replaced.
The new,air handler
facilitates easier filter replacement.
The
DC Hold Cabinet
was functionally tested
on each
rod group.
Additionally, a procedure
was written for its use.
This is
intended to provide
a means of repairing
Rod Control failures on
line.
The Unit 3 Rod Control System will be monitored by the system
engineer,
using
a recorder during quarterly
rod exercise test.
Monitoring is intended to be performed for one year starting at
the next scheduled surveillance after the refueling outage.
I8C is scheduled to support the quarterly monitoring of the Rod
Control System.
The System Engineer is planning to send the sensing transformer
T3 out for failure analysis.
Results will be documented in a
supplement to the
CR.
The System Engineer is planning to update the procedure to test
the three
phase
sensing transformers
and phase control cards.
Although not required,
the Unit 3 rod control system
was placed
in categoi y a(1) requiring enhanced
monitoring per the
Maintenance
Rule.
The inspector verified the licensee's
corrective actions:
observed
portions of the maintenance
and testing activities including rod
control performance during cold stepping.
hot stepping,
and reactor
startup;
reviewed the
CR and recent failures;
and, discussed this item
with engineering,
maintenance,
operations,
and management
personne Conclusi ons
The inspector concluded that licensee
actions
appeared to be aggressive
and thorough.
The inspector intends to follow Unit 3 rod control
performance during the upcoming cycle.
3C Intake Coolin
Water
ICW
Pum
Hotor Failure
62707
The
3C
ICW pump experienced
a motor failure on January
16,
1997.
As
discussed
in NRC Inspection
Report
Nos. 50-250,251/97-01
section Ml.3,
the motor failure root cause.
corrective actions,
and maintenance
rule
applicability were to be reviewed.
The licensee
amended
CR Mo. 97-59 to address
these
issues.
The failed
motor (Allis Chalmers
4160 volt AC) was inspected
by the vendor
(Tampa
Armature Works).
The vendor concluded that
a winding failure occurred
where the coil connection
lead exits the coil.
This is typically a
weak spot.
Host likely, a void was introduced during the manufacturing
rocess,
and went undetected
during testing
and initial operations.
his void in the winding allowed moisture to penetrate into the coil
and caused it to flash to ground, resulting in a
B phase overcurrent
trip of'he motor.
The licensee
concluded that failure was due 4o a re-manufacturing
deficiency.
A review did not reveal
any process
or testing weaknesses.
Further the
3C
ICW failure was classified
as
a functional failure and
a maintenance
preventable
functional failure (NPFF)..
The HPFF was not
repetitive as an-earlier failure was age-related
and not due to
manufacturing.
Further,
no system, train. or plant level performance
criteria were exceeded.
Thus,
per Haintenance
Rule requirements,
normal monitoring continues for the Unit 3
ICW system.
The inspector
concluded that the licensee appropriately
reviewed
and
dispositioned this fai lure.
Corrective actions were determined'to
be
adequate.
Unit 3 Containment Closeout
Ins ection
62707
The inspector
accompanied
the site Quality Assurance
Hanager into the
Unit 3 containment to observe the licensee's
inspection of the
conditions of the containment
'and to verify their assessment.
A number
of QA/QC personnel
were present
performing their inspections
along with
maintenance
and operations
personnel
assessing
the cleanliness
and
completing several
small jobs and survei llances.
The
QC group is
responsible for the performance of this inspection which is described
in procedure
O-SNN-051.3,
Containment Closeout Inspection.
The
personnel
were very thorough in identifying equipment that had to be
removed
or corrections that were needed.
The inspector considered
the containment to be relatively clean
and
ready for the change to Node e
e
h
M2.4
Loss of 3C Non-Vital Bus
62707
On April 11,
1997. the
3C non-vital
bus trans~:".mer
locked out during
the start of the 38 SGFP.
Operators
responded to loss of the
3C bus
per
ONOP requirements.
Needed
load centers
were cross-tied
from Unit
4.
Unit 3 was in Mode 3 at the time.
The licensee initiated
CR No.97-736
and
an
ERT was formed.
The
ERT concluded that the
3C bus
transformer lockout was caused
by the failure of lockout relay
3CBTX/GF.
The relay was replaced
and the bus
was retested
satisfactorily.
Root cause evaluations
are pending.
Maintenance rule
applicability is pending root cause determinations.
These corrective
actions included were documented
in the
CR.
The inspector
reviewed operator
response to the loss of the 3C bus,
and
maintenance/engineering
review of the failure.
Licensee actions
appeared to be appropriate
and thorough.
Excellent teamwork was noted
during the followup activities.
8 Standb
Feed
Pum
S/8
Oil Leak
62707
On April 11,
1997, during
a run of 8 S/8 SGFP,
a pressure
switch (PS-
7304) sensing line broke off and sprayed
gear
box oil onto the diesel
engine driver.
Operators
immediately shut
down the 8 S/8 SGFP.
Haintenance
and engineering
personnel
responded
and
CR No.97-735 was
initiated.
The licensee
concluded that the failure was caused
by piping vibration
and subsequent
fatigue.
Inadequate
piping design
(schedule
40 threaded
pipe) was determined to be the cause.
The failure was determined to be
a functional failure, but not maintenance
preventable.
Corrective
actions included
a redesign of the pipe with schedule
80 pipe;
verification through oil analysis that the diesel
gear
box was not
adversely affected;
sending the broken pipe out for metallurgical
analysis;
and checking other piping designs
for
a similar
susceptibility.
No other susceptibilities
were identified.
The failed
piping was repaired
and upon completion of retesting the
B S/B SGFP it
was returned to service
on April 13,
1997.
The inspector
reviewed operations
and maintenance
actions,
examined the
failure, reviewed the
CR and corrective actions,
and verified post-
maintenance testing activities.
The inspector
concluded that the
licensee appropriately
responded to this failure.
Teamwork 'was noted
to be strong,
and
a timely response to return the pump to service was
note En ineer in
Conduct of'ngineering
Unit 3 Startu
and
Ph sics Testin
71711
and 37551
The inspectors
observed portions of the Unit 3 initial criticality,
startup,
and physics testing evolutions (section 01.1).
The licensee
performed procedures
0-0SP-040.6.
Initial Criticality After Refueling,
and 0-0SP-040.5
Nuclear
Design Verification.
These tests verified that
nuclear design criteria and related predictions
were satisfactory.
Specific tests
included critical boron concentrations,
worths. temperature coefficients of reactivity,
and power
distributions.
Technical Specifications 3/4.1.1.3, 3/4.2.2,
and
3/4.2.3 were also verified.
During the initial startup
on April 12,
1997, prior to achieving
criticality, abnormal
indications were noted
on coolant temperatures
(Tavg and Tref). and on two of the control rod step counters.
Operators
re-inserted all of the control rods,
and
CR No.97-739 was
initiated.
The licensee
determined that two of the reactivity computer
connections
were shorted.
The reactivity computer
was re-connected
using procedure
O-OP-96.1.
Normal Alignment and
Use of the Digital
Reactivity Computer
.
The unit achieved criticality on April 14,
1997.
The inspectors
reviewed the test results
and independently
confirmed
that acceptance criteria were met.
The inspectors
noted very good test
coordination between operations
and reactor
engineering
personnel.
Weaknesses
were noted relative to the reactivity computer connections.
The inspectors verified that these tests
were conducted in accordance
with procedure
O-ADH-217, Conduct of Infrequently Performed Tests
or
Evolutions.
Overall, the licensee
demonstrated
effective test control
and conduct.
Feed Water
Pum
Re airs
Ins ection
Sco
e
62707
The Unit 3 3B SGFP was replaced during the Harch 1997 outage.
When the
ump was started,
a leak was observed in the casing.
Several
other
eaks developed during further runs of the pump.
The inspectors
observed the repairs
made to this pump and engineering efforts to
support the activity.
Observations
and Findin s
As a result of a visual leak during start
up activities for Unit 3,
a
through wall crack in the pump casing adjacent to the discharge
nozzle
of the 3B SGFP was identified.
CR No.97-737 was initiated.
The
location of the approximately
one and three-fourth inch long crack was
an indication that the flaw was caused
by a hot or cold cracking tear
during the casting process,
and was not the result of a mechanical
E2
E2.1
failure.
The flaw was not opened during the hydrostatic testing
process.
Additionally, the pump casing
was cast significantly oversize
with approximately
one inch wall thickness.
The inspectors
reviewed the temporary non-safety related
and non-Code
repair
procedure
suggested
by the vendor
and the licensee.
This is
a
not
a safety related
system (i.e. not
ASIDE Section XI) but the
pump
does serve
as
a seismic anchor.
This function was not affected
by the
temporary repair.
The intent of the repair
was to eliminate leakage
and the associated
further degradation of the casing condition.
The
casing mater'ial is
a cast martensitic stainless
steel
(ASTH A743-CA6NN)
with a high yield strength
(approximately 97.5 ksi).
The crack was
ground to approximately
one eight of an inch in depth,
and
a weld bead
was deposited
on each side of this cavity.
Then
a third bead
was
deposited to cover the crack.
Then
a second layer of weld beads
was
placed over the first giving a temper
bead welding approach (i.e. the
second layer gives
a beneficial
tempering affect to the heat affected
zone of the first layer).
The weld material
was
an austenitic
stainless
steel
(309 L).
A preheat
temperature
lower than the optimal
was used
because
the
pump began to bind as the preheat
temperature
was
raised.
The pump will have
a proper
Code repair
during the next
refueling outage.
Visual surveillance of the repaired
area is being
conducted at various intervals
and if any leakage develops.
then
an
engineering evaluation will be performed.
Three other leaks also
developed.
and two were repaired
by peening
and one attempted repair by
Furmaniting.
Conclusions
The engineering
group provided excellent support for operations
and
maintenance
in affecting
a non-routine temporary weld repair
for
a
leaking feedwater
pump casing.
Engineering Support of Facilities and Equipment
Re air of the Unit 4 Pressurizer
S ra
Valve 455B
Ins ection Sco
e
62707
and 37551
On April 24,
1997. during
RCS leak inspection boric acid residue
was
found on pressurizer
spray valve PCV-4-455B.
The licensee initiated
CR
No. 97-0789.
The inspectors
reviewed the response to the condition
report and attended
the
PNSC review for the Furmanite repair of this
valve.
Observations
and Findin s
This pressurizer
spray valve performs
no active safety function and is
required for pressurizer
boundary maintenance
only.
This was
considered
as mechanical
leakage
and under
ASME Section
XI this was not
considered
as
a failure of a pressure
retaining component.
Under
Technical Specification (TS) 3.4.6.2 the amount of minor leakage fell
e
E2.2
E2.3
within the boundary requirements
and therefore
no operability concern
existed.
, The inspectors
used
NRC Inspection
Manual Part 9900, Technical
Guidance,
Section
on,
"Assessing
On-Line Leak Sealing of ASME Code
Class
1 and
2 for inspection guide lines.
This guidance stated that
the
NRC Staff Position is leak sealing is an allowable temporary
measure
for mitigating gasket
and packing leaks.
The guidance also
gives
11 items that the licensee
should consider to ensure that an
accepted
logic path was considered
from the problem discovery to the
conclusion that performing an on-line leak seal
was
a safe solution.
These
items considered
use of management
and engineering
for the
evaluation, structural integrity assessment,
cause of leak. calculation
of fastener
loading during sealant injection, etc.
Ouring
a telephone
call to discuss
the repair with Region II and
NRR,
a request
was
made
for more information concerning total injection pressure of the
Furmanite gun rather than considering
some pressure
losses
due to
molding and extrusion.
This conservative calculation was
made by the
licensee
and total stress
on the studs
was less than the preload
(e.g..45 ksi vs.
60 ksi).
Conclusion
The inspectors
concluded that the licensee did consider all of the
steps in the
NRC guidance
document.
The management
and engineering
support for accomplishing the repair were excellent.
Event
Res
onse
Team
ERT
For Unit 3 RCP Seal
Leakoff Problem
37551
The inspector
observed
portions of the
ERT efforts for resolving
problems with higher than normal seal leakoff flow rates
on two out of
three
RCPs during the Unit 3 startup
from the refueling outage.
One of
these
two pumps
had the seals
replaced during this outage.
The
inspectors
attended the initial meeting of the
ERT.
Initially. the
ERT
postulated that these
instrument lines should be vented
as one possible
solution since
a large amount of gas
had been vented in the previous
outage
from the third pump (the pump that was in the correct leak off
range).
The I8C group was to take
some additional information for the
team and determine if any gas
was observed
when the lines were vented.
The inspector
concluded that the team had an orderly and rational
approach for resolving the problem.
Final resolution revealed that
venting was not the solution. 'owever, after running one
pump a lower
seal
leak off flow was noted.
Further,
a small foreign material
particle was found in the other pump's leakoff orifice giving the false
indication of a higher
seal leakoff value.
These issues
were
appropriately
addressed.
Unit 3 Seal
Table Leak
62707
and 37551
In preparation
for startup of Unit 3 from a refueling outage
on April
6.
1997. the, licensee
was conducting
an
RCS overpressure
test
and
E3
E3.1
discovered fluid on the seal table.
The leakage
was coming from
Thimble Guide Tube H-1 in the region between the top of the seal table
and-the welded connection to the high pressure fitting.
This condition
laced the unit in an Unusual
Event (section Pl. >> per TS 3.4.6.2
(RCS
eakage).
The unit had to be returned to cold shutdown to allow f'r
the removal
and replacement of the failed guide tube.
The inspectors
reviewed Minor Engineering
Package
(MEP) No.
PC/M 97-
010,
Repair of Flux Mapper
Guide Tube.
which was used for the repair.
Several of these guide tube replacements
have been previously performed
on Unit 3.
Based
on the appearance
of the leak and the licensee's
revious experience,
the through wall crack defect
was anticipated to
e due to
transgranular
stress
corrosion cracking
(TGSCC).
The
licensee
removed the defect entirely because of a tendency for
TGSCC to
propagate.
Since
a double freeze seal
was to be used,
a review was
made of the procedure to be used,
procedure
O-GMM-102.5, Freeze
Seal
Application.
The inspectors
concluded that there
was appropriate
engineering
support
for maintenance
and operations
in performing the repair.
Engineering
Procedures
and Documentation
Unit 4 Licensee
Event
Re ort
LER
Number 97-01
92700 and-90712
Unit 4 LER No. 97-01 was issued to address
a casing leak on the 4A HHSI
pump.
The leak occurred
on March 27,
1997 and was greater than that
allowed by the
UFSAR Table 6.2-12.
Therefore.
Unit 4 was outside its
design basis.
The licensee
concluded that cause
was
a damaged
between the inside of the casing
and the penetration
through the gasket
for the casing bolt.
The licensee believes that this probably occurred
during 4A HHSI pump overhaul in March 1996.
Corrective actions included the following:
The 4A HHSI was permanently repaired within the allowed TSAS,
The casing gasket installation technique
was modified,
The 3 other
HHSI pumps were inspected
and no problems-were
noted,
Each
HHSI pump will be inspected
by system engineering
and
operations,
Supervisory inspection of the gasket installation will be
performed,
and
A review of the leak sealant
process will be reviewed.
This event review was discussed
in NRC Inspection Report
Nos.
50-
250,251/97-03.
The inspector
reviewed the
LER, including causes
and
corrective actions.
The inspectors
concluded that the
LER was factua F5
E5. 1
E5.2
well written,
and that causes
and corrective actions were appropriate.
The
LER was closed.
Engineering Staff Training and Qualification
Trainin f'r the Plant Nuclear Safet
Committee
PNSC
Members
37551
The inspector attended
one of the biennial requalifications for the
PNSC members.
The training covered the procedure
QI 1-PTN-4.
PNSC
Organization
and Operation.
parts of Nuclear Training Manual for
10 CFR 50.59, discussions
for violations at both Turkey Point and St. Lucie
concerning
CFR 50.59/TS decisions,
and Turkey Point's
response to
the
NRC request
for information regarding the adequacy
and availability
of design basis information.
The material
was appropriate
and the training instructor did a good job
on presenting the information.
Overall. the inspector concluded that
the training appeared to be effective.
En ineerin
Mana ement
Chan es
Liz Thompson
was
named
as the Turkey Point Engineering
Manager
during
the period.
IV. Plant
Su
ort
R1
Rl. 1
P1
P1. 1
Radiological Protection
and Chemist y (RP&C) Controls
Unit 4 Containment
Ins ections
71750
The inspectors
toured the Unit 4 containment
on April 25,
1997 while in
Mode 3 during the forced outage (section 06.1).
The inspectors
verified that licensee
provided appropriate pre-entry briefings
regarding radiological conditions
and
RWP requirements.
heat stress
and
personnel safety,'onfined
space entry requirements,
and containment
integrity.
Work in progress
by I&C and mechanical
maintenance
personnel
was
reviewed.
Containment radiological
and material conditions were
inspected.
The inspectors
concluded that the licensee's
radiation and
personnel
safety requirements
were appropriately followed.
personnel
provided very good oversight.
Conduct of EP Activities
Notification of Unusual
Event
Due to Unit 3 Leaka
e
93702
At 1:30 p.m.
Sunday April 6, 1997. Control
room operators classified
observed
leakage at the Unit 3 H-1 seal table instrument thimble guide
tube as through wall; and therefore reactor
coolant pressure
boundary
leakage
requirements
were exceeded.
The leakrate
was about
1 drop per
minute.
Subsequent
inspections
could not quantify the leakage;
however,
leakage
had been observed.
Licensee actions included the following items:
Declared
an
UE due to reactor coolant pressure
boundary leakage,
Called the Resident
Inspector at home,
Notified the State
(FL) and
NRC as required,
Initiated
a cooldown to Node 5 per
Downgraded the
UE when the unit reached
Node 5 at 9:15 p.m.,
Organized
an
ERT to determine root cause,
and
E
Repaired the seal table leak (section E2.3).
The inspector
responded to the site to monitor licensee actions.
Procedure,
TS,
and Emergency
Plan implementation
was verified to
correct.
The inspector
concluded that the licensee
reacted
conservatively
and appropriately.
Operator performance
and engineering
support
was very good.
P5
Staff Training and Qualification in EP
P5.1
fmer enc
Plan
Drill
71750
The inspectors
observed
and participated in an
EP drill on April 29,
1997.
Technical
Suppor t Center
(TSC) and Control
Room Simulator
activities were observed.
The drill was well performed. 'reas
for
improvement were identified at the post-drill critique by players.
evaluators,
and
NRC personnel.
The inspectors
concluded that the drill
was
an excellent training mechanism.
Sl
Conduct of Security and Safeguards Activities
Sl. 1
Fitness
For Dut
Event
71750
On April 29,
1997, the licensee tested
a supervisor for cause in
accordance
with FFD program requirements.
The individual tested
positive for alcohol.
A
10 CFR part 26 notification was subsequently
made via the
ENS.
The individual was referred to FPL's employee
assistance
program.
The inspector
reviewed the event and related notifications.
The
inspector concluded that the licensee appropriately
responded to this
even V.
Hang ement Heetin s
X" " '5 Meet'n
Summa
The inspectors
presented
the inspection results to members of licensee
management
at the conclusion of the inspection
on May 22,
1997.
The
licensee
acknowledged the findings presented.
The inspectors
asked the licensee whether any materials
examined during
the inspection should
be considered proprietary.
No proprietary
information was identified.
Partial List of Persons
Contacted
Licensee
T. V. Abbatiello, Site Quality Manage
R. J. Acosta, Director, Nuclear Assurance
J.
C. Balaguero.
Plant Operations
Support Super visor
P.
M. Banaszak.
Electrical/l8C Engineering Supervisor
T. J. Carter, Project Engineer
B.
C.
Dunn. Mechanical
Systems
Supervisor
R. J. Earl,
QC Supervisor
S.
M. Franzone.
Electrical Haintenance
Supervisor
R. J. Gianfrancesco.
Maintenance
Support
Supervisor'.
R. Hartzog.
Business
Systems
Manager
G.
E. Hollinger. Licensing Manager
R. J.
Hovey, Site Vice-President
H.
P.
Huba, Nuclear Materials
Manager
D.
E. Jernigan,
Plant General
Manager
T. 0. Jones,
Operations
Supervisor
M.
D. Jurmain,
I8C Maintenance Supervisor
V. A. Kaminskas.
Services
Manager
J.
E. Kirkpatrick, Fire Protection,
EP, Safety Supervisor
J.
E. Knorr, Regulatory Compliance Analyst
G.
D. Kuhn, Procurement
Engineering Supervisor
R. J. Kundalkar. Vice President,
Engineering
and Licensing
M. L. Lacal. Training Manager
J.
D. Lindsay, Health Physics Supervisor
E. Lyons. Engineering Administrative Supervisor
F.
E. Marcussen,
Security Supervisor
H.
N. Paduano,
Manager,
Licensing and Special
Projects
H. 0. Pearce.
Maintenance
Manager
K.
W. Petersen,
Site Superintendent
T. F. Plunkett,
President,
Nuclear Division
K. L. Remington.
System Performance
Supervisor
R.
E.
Rose.
Outage
Manager
C.
V. Rossi,
QA and Assessments
Supervisor
W. Skelley, Plant Engineering
Manager
R.
N. Steinke.
Chemistry Supervisor
E. A. Thompson,
Engineering
Manager
D. J.
Tomaszewski,
Systems
Engineering
Manager
G. A. Warriner. Quality Surveillance Supervisor
R.
G. West, Operations
Manager
Other licensee
employees
contacted
included construction
craftsmen,
engineers,
technicians,
operators.
mechanics,
and
electricians.
Partial List of Opened,
Closed,
and Discussed
Items
0 ened
50-250,251/97-04-01,
IFI, Operations
Self-Assessment
Activities.
(section 07.3).
Closed
50-250/97-04-02
50-250/97-04-03
LER 50-250/97-01
LER 50-250/97-03
LER 50-250/97-04
LER 50-251/97-01
NCV, Failure to Perform Control
Rod Position
Verification Due to an Inoperable.Rod
Deviation
Monitor (section M1.3).
NCV, Failure to Meet TS 3.0.4 (section 03.1).
Failure to Perform Control
Rod Position
Verification Due to an Inoperable
Rod Deviation
Monitor (section M1.3).
/
Mode change without steam generator
blowdown
system interlock bypassed
(section 03.1).
Automatic AFW Start
Due to a Tripped
(section M1.4).
4A HHSI Pump Casing
Leak (section E3.1).
LER 50-251/97-02
Unit 4 Reactor
Tr ip (section 04.2).
List of Inspection
Procedures
Used
IP 37551:
Onsite Engineering
IP 40500:
Effectiveness of. Licensee Controls in Identifying,
Resolving'nd
Prevent
Problems
IP 60710:
Refueling Activities
IP 61710:
Control
Rod Worth Measurements
for Pressurized
Reactors
IP 61726:
Surveillance Observations
IP 62707:
Maintenance
Observations
IP 71707:
IP 71711:
Plant Operation
Plant Restart
From Refueling
IP 71750:
Plant Support Activities
IP 90712:
Inofiice Review of Written Reports
IP 90713:
Review of Periodic Reports
IP 92700:
IP 93702:
Onsite Followup of Written Reports of Nonroutine Events at
Power Reactor Facilities
Prompt Onsite
Response to Events at Operating
Power
Reactors
List of Acronyms and Abbreviations
ADM
a.m.
ANPS
CBTX/GF
CFR
. CNRB
CR
CTRAC
CV
e.g.
ERT
etc.
FL
GMM
gpm
18C
Alternating Current
Administrative (Procedure)
Ante Meridiem
Assistant Nuclear Plant Supervisor
American Society of Mechanical
Engineers
American Society for Testing
and Materials
Relay
Component Cooling Water
Code of Federal
Regulations
Company Nuclear
Review Board
Condition Report
Cathode
Ray Tube
Commitment Tracking
Control Valve
Chemical
Volume Control System
Direct Current
Division of Reactor
Safety
For
Example
Emergency Notification System
Emergency Operating
Procedure
Emergency
Preparedness
Event Response
Team
et cetera
Florida Power and Light
General
Maintenance
- Mechanical
General
Operating
Procedure
Gallons
Per Minute
High Head Safety Injection
Health Physics
Instrumentation
and Control
ICW
i.e.
IFI
ITOP
ksi
LER
No.
NP
NRC
ONOP
OP
OTbT
PC/H
,
p.m.
PHAI
PHI
PNSC
ppm
'S
PS
Psl9
PWO
QI
RCO
R/OPC
RP8C
S/B SGFP
SATS
Intake Cooling Water
That Is
Inspector Followup Item
Inservice Inspection
Implementor Turnover Package
'housand
pounds per square
inch
Level Controller
Level Control Valve
Licensee
Event Report
Loss-of-Coolant Accident
Motor Control Center
Minor Engineering
Package
Hotor-Operated
Valve
Maintenance
Preventable
Functional Failure
Non-Cited Violation
Non-licensed
Operator
Number
Nuclear Policy
Nuclear Plant Supervisor
Nuclear Regulatory Commission
Overpressure
Mitigation System
Off-Normal Operating
Procedure
Out-of-Service
Operating
Procedure
Protection Controller
Operations Surveillance
Procedure
Over-temperature
Delta-temperature
Plant Change/Modification
Pressure
Control Valve
Public Document
Room
Post Meridiem
Preventive Maintenance
. Plant Manager Action Item
Preventive Maintenance
- I8C
Plant Nuclear Safety Committee
Power-Operated
Relief Valve
Parts
Per Million
Power Supply
Pressure
Switch
Pounds
Per
Square
Inch Gauge
Plant Work Order
Quality Assurance
Quality Control
Quality Instruction
Reactor Control Operator
Pump
Relay Overspeed
Protection Controller
Radiological Protection
and Chemistry
Standby
System Acceptance
Turnover
Sheet
S/G
Tavg
TREF
TS
TSAS
Safety Injection
s/g Feedwater
Pump
Surveillance
Maintenance
- Mechanical
Short Notice Outage
average coolant temperature
Temperature
Control Valve
Transgranular
Stress
Corrosion Cracking
Reference
temperature
Technical Specification
Tempo ary System Alteration
TS Action Statement
Technical
Support Center
Unusual
Event
Updated Final Safety Analysis Report
Volume Control Tank
0