IR 05000250/1996012
| ML17354A371 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 12/10/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17354A370 | List: |
| References | |
| 50-250-96-12, 50-251-96-12, NUDOCS 9612230382 | |
| Download: ML17354A371 (47) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos.:
50-250 and 50-251 License Nos.:
DPR-31 and DPR-41 Report Nos.:
50-250/96-12 and 50-251/96-12 Licensee:
Florida Power and Light Company Facility:
Turkey Point Units 3 and 4 t
Location:
9250 West Flagler Street Miami, FL 33102 Dates:
September 29 through November 16, 1996 Inspectors:
T.
P. Johnson.
Senior Resident Inspector B.
B. Desai, Resident Inspector W.
C. Bearden, Reactor Safety Inspector Approved by:
C. A. Julian. Acting Chief Reactor Projects Branch
Division of Reactor Projects 96i 2230382 96i210 PDR ADOCK 05000250
EXECUTIVE SUMMARY TURKEY POINT UNITS 3 and 4 Nuclear Regulatory Commission Inspection Report Nos. 50-250,251/96-12 This integrated inspection to assure public health and safety included aspects of licensee operations, maintenance, engineer ing, and plant support.
The report covers resident inspection from September 29 to November 16, 1996.
In addition, the report includes a headquarters announced inspection of seismic adequacy, and a regional announced inspection of the alternate shutdown system and balance of plant maintenance.
~0erat1ons Unit 3 and 4 thermal upr ate power escalations were well controlled, and demonstrated conservative operations.
Primary and secondary plant responses were as expected.
The inspectors noted excellent teamwork, strong operator procedure compliance, and proactive oversight by line management and independent groups (section 01.1).
Operator response to a false Unit 3 air ejector radiation alarm was excellent.
including very good procedure compliance, strong oversight, excellent communication, and positive command and control (section 01.2)
The post-accident containment ventilation system was appropriately aligned (section 02.1).
The annunciator system was noted to be operating properly.
The licensee is pursuing a "spare" window illumination issue (section 02.2).
The redundant reactor protection systems (AMSAC) were operable (section 02.3).
The alternate shutdown systems were appropriately aligned (section M2.4).
Inspector identified weaknesses in the post-accident containment ventilation emergency operating procedures were appropriately addressed by the licensee.
The procedures were adequate.
and operators were able to appropriately implement them (section 03.1).
The transition to electronic operator narrative logs for the control room was well planned and effectively implemented (section 06.1)
The off-site and on-site safety committees were appropriately functioning, with a noted positive oversight of and contribution to plant operations (section 07. 1 and 07.2)
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The licensee's self-assessment capability was noted to be very good relative to quality assurance reviews and an independent team assessment (section 07.3).
Haintenance
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Lack of spare parts availability for two process radiation monitor fai lures that occurred, and the generic implications were being appropriately addressed (section 01.2).
Haintenance and surveillance activities witnessed were well performed (section Hl.l).
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A Unit 4 (Hode 3) short notice outage was well planned and conducted.
Abnormal turbine vibrations on startup were appropriately and conservatively addressed (section H1.2).
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The 4B emergency diesel generator monthly test was well performed, with strong procedure compliance and independent verifications noted (section H1.3).
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The licensee has experienced several unplanned power reductions over the last few years due to poor reliability of BOP equipment.
Although some of these problems were the result of equipment design, other problems such as the blocked orifice in the turbine control oil line were caused by previous maintenance practices.
These problems are currently well understood by the licensee and ongoing corrective actions should result in improvements in reliability of the associated equipment (section H2. 1).
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The licensee appropriately addressed a battery intercell connector high resistance issue (section H2.2)
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Reactor protection system testing was well conducted (section H2.3).
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A review of the alternate shutdown panel and associated equipment at Turkey Point was performed.
The licensee's program for maintenance and testing for this equipment was adequate (section H2.4).
En ineerin The licensee addressed generic seismic issues, including open items, from an audit last year.
However, weaknesses were identified in the material condition of the component cooling water system areas (section E2. 1).
Thermal power uprate related plant changes and modifications were appropriately implemented, and closure packages were well maintained and easily retrievable (section E2.2).
The licensee identified a single failure vulnerability that could occur during post-accident hydrogen monitor alignment procedures.
This item was a reportable event, and the licensee event report remains open pending further review (section E3. 1).
A licensee-identified inadequate procedure for controlling heavy loads, was classified as a non-cited violation.
The related licensee event report and unresolved item was closed (section E3.2).
Three reviewed licensee event reports were well written and submitted in a timely manner (section E8. 1)
Plant Su or t A radwaste building tank overflow was caused by a fai lure of a non-safety related hot water tank.
The water was adequately contained in a concrete berm.
Inspector review of the event noted weaknesses in health physics turnover, operator tours.
and remote alarm capabilities.
The licensee is currently addressing these issues (section Rl.l).
Hurricane Lili preparations were proactive, and demonstrated strong performance (section Pl.l)
A self-assessment of the emergency preparedness area was proactive and thorough, and did not identify any significant problems (section P7.1).
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.
.26
..28
29
REPORT DETAILS Summary of Plant Status Unit 3 At the beginning of this reporting period, Unit 3 was operating at or near full reactor power and had been on line since September 27, 1996.
On October 11, 1996, unit power was raised in accordance with thermal power uprate procedures from 2200 to 2300 megawatts (MW) thermal (MWTh)
(section 01.1).
The unit operated at full power the enti re 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 July 14.
1996.
Load reductions to repair feedwater relief valves occurred on October 7 and 12, 1996.
Additionally, a planned short notice outage occurred during October
- 24, 1996. to address secondary plant issues (section M1.2).
On October 29, 1996, unit power was raised in accordance with thermal power uprate procedures from 2200 to 2300 HWTh (section 01. 1).
The unit operated at full power the remaining portion of the period.
Common A new Outage Manager (Dick Rose)
and Operations Manager (Rusty West)
were selected to replace managers who were transferred to St. Lucie.
In addition, a replacement Materials Manager (Hike Huba) was selected.
I.
0 erati ons 40500 71707
01.1 Conduct of Operations Thermal Power U rate Ins ection Sco e
The licensee implemented a thermal power uprate on Units 3 and 4 during the period.
The NRC approved license amendments 191 and 185, dated September 26, 1996.
The inspector reviewed the related plant modifications (section E2.2),
and licensee activities which implemented the power uprate from 2200 to 2300 HWTh on both units.
Findin s and Observations Power escalation was controlled by temporary procedures (TPs)96-071 (72),
Implementation of Unit 3(4) Thermal Power Uprate.
The TPs controlled all activities including baselining, setpoint scaling, power changes, data collection, primary and secondary plant monitoring, and control room indicator changes.
Plant and engineering management provided oversight as required by administrative procedure (ADH) 0-AOM-217, Conduct of Infrequently Performed Tests and Evolution The power uprate process was scheduled over a four week period in order to change all the required setpoints.
procedures, alarms, indicators, plant curves, and to provide training.
Training Brief No.
648 and simulator training provided licensed operators with an uprate overview and plant specific changes.
Section E2.2 of this report addresses the plant modifications that were performed to support power uprate.
Plant management, the Plant Nuclear Safety Committee (PNSC),
and quality assurance (QA) provided oversight and approval of the process, including procedure change approval.
In additions management and QA monitored selected activities.
A detailed critical path schedule was provided by engineering, with assistance from outage management.
The Unit 3 and Unit 4 power escalations occurred during dayshift on October 11, 1996, and October 29.
1996, respectively.
Power increases were made deliberately.
and were of a 6 MW electric (MWe) magnitude.
Briefings were held with all participants including:
control room operators.
field operators, engineering, maintenance, management, QA, and others.
Unit 3 achieved 2300 MWTh at 2:40 p.m.
on October 11, 1996.
Unit 4 achieved 2300 MWTh at 12:50 p.m.
on October 29.
1996.
The inspector reviewed the above mentioned documents, observed calibration of selected instruments, verified selected procedure and plant curve book changes, monitored the power escalation, attended PNSC meetings, and discussed the process with plant personnel.
The inspector noted that TP controlled and verified the large number of changes that were required, including about 30 modifications.
over 300 procedure changes, Technical Specification (TS) changes, 28 Emergency Operating Procedures (EOP) changes, 60 curve book and drawing changes, about 870 drawing updates.
and numerous control room indicator changes.
c. Conclusions The inspector noted the power uprate process to be very deliberate and conservatively implemented.
Excellent teamwork among all participants was noted.
PNSC, QA, and management demonstrated excellent oversight and a questioning attitude.
Primary and secondary plant performance was as expected.
Each unit achieved an increase of about 31.0 MWe.
01.2 Unit 3 Steam Jet Air E ector SJAE Radiation Monitor R-15 Failure At approximately 4:15 p.m.
on October 18, 1996. the inspectors responded to the control room following a plant page announcement that indicated
"stay clear of the Unit 3 turbine deck".
The inspectors noted that the Unit 3 operators were responding to an increasing trend in the Unit 3 SJAE radiation monitor R-15.
Further, an upswing in the steam generator (S/G) liquid sample radiation monitor R-19 was also noted by the operators.
Increasing trends on both the R-15 and R-19 radiation monitors are indicative of a steam generator tube leak.
The appropriate off-normal operating procedure (ONOP) was entere.1 The licensee confirmed that a steam generator tube leak did not exist through reactor coolant system (RCS) leakrate calculations; by noting normal radiation levels during health physics (HP) surveys; by performing steam generator sample analysis; and the by absence of abnormal indications on the main steam header radiation monitor and the SJAE SPING radiation monitor.
Further, the R-19 monitor returned to a normal level.
Based on the above indications, the operators concluded that R-15 monitor had failed.
A condition report and a work request were initiated.
The R-15 radiation monitor was returned to service after resolving spare parts issues on October 30, 1996 following replacement of the detector.
Another process radiation monitor (R-17B)
for the component cooling water (CCW) system failed during the period.
This failure was also attributed to aging and spare parts issues.
Based on these two failures, the licensee is currently reviewing availability of spare parts and equipment aging issues for the process radiation monitoring systems.
The inspector independently monitored Unit 3 plant parameters, as well as operator performance and ONOP implementation.
The inspector did note that the chart recorder (R-3-1419) associated with radiation monitor R-15 was difficult to read for trending purposes.
This was brought to the attention of the operations supervisor who indicated a work order would be submitted.
Both the Unit 3 and 4 recorders were fixed.
The licensee is pursuing longer term replacements of these recorders.
Overall, the inspectors concluded that operators appropriately responded to this perceived S/G radiation alarm.
Procedure compliance, command and control, communication, and oversight were very good.
Teamwork among HP, chemistry, and operations was also very good.
t'perational Status of Facilities and Equipment Post-Accident Containment Ventilation PACV S stem Walkdown The inspectors performed a review and walkdown of the PACV system.
This system is provided to facilitate the post-accident controlled venting of either units'ontainment through redundant unit specific containment penetrations.
and a
common high efficiency particulate air filter (HEPA)
and charcoal filter.
The effluent can then be directed to either the waste gas decay tanks (WGDT) or directly to the main stack.
The PACV system ensures post-accident hydrogen concentration is maintained below 3X (e.g.,
below the flammable limit).
The hydrogen recombine system provides a fully redundant backup to the PACV system.
CFR 50.44 required the recombiner system, and Turkey Point shares a skid mounted system which is normally stored at the Ouke Oconee Plant.
This skid mounted system can be installed days after an accident.
The inspectors reviewed the following documents:
UFSAR section 9. 12, Post-Accident Hydrogen Control Various Unit 3 and 4 EOPs
Procedures 3/4-OP-094.
Containment Post-Accident Monitoring Systems Engineering evaluation of the PACV System (JPN-PTN-SEMS-92-4)
Safety evaluation for the operation of the PACV System (JPN-PTN-SENJ-90-073)
Piping drawings 5613 and 5614-M-3094 PACV Specifications (SPEC-M-042)
Procedure 3-0SP-051.13.
PACV Flowpath Verification Procedure 3-OSP-051. 11, PACV System/Valve Operability Test Technical Specification (TS) 3/4.6.6, PACV System Calculation PTN-BFJM-96-014.
PACV System Replacement Filter Specs The inspector toured the accessible portions of the PACV system including the unit specific containment isolation valves, reach-rod remote operating stations, unit common filter trains and piping, and local instrumentation station.
During Unit 3 power uprate activities (section 01.1, Ml.l and E2.2). the inspector witnessed the new filter installation and modifications.
The inspector noted that the filter work included installation of poly "containment bags" within the filter housings.
The inspector questioned whether the system temperature design of 180'F would be acceptable for this poly bag.
The licensee's analysis stated that the PACV system would be placed inser vice at 41 days post-accident when the containment was at 2.5 psig and 122'F.
The PACV filter vendor stated the poly bags would be acceptable up to 135'F.
Thus, based on PACV system design initiation. the licensee concluded that the poly bags were acceptable.
However, the bags were removed as the licensee determined that they were not needed.
This was documented on condition report (CR) 96-1246.
In addition, the inspector reviewed the licensee's filter upgrades and evaluations which assure PACV system functionality and operability at containment design pressures.
The licensee had also previously evaluated radiation levels as acceptable in the Unit 4 containment spray pump room in order to implement the Unit 3 and 4 EOPs.
(The local PACV system panel is located in the Unit 4 spray pump room).
The inspector concluded that the PACV system was appropriately aligned for standby operation.
S are Annunciator Windows During a routine control room tour, the inspector noted that some spare annunciator windows were dark and some were illuminated (dim backlight).
The Turkey Point alarm (annunciator)
system is designed so that "non-
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alarmed" windows have a dim backlight.
This condition represents a
"darkboard" alarm status.
The inspector walked-down the annunciator system, and pursued this spare alarm difference.
The system engineer stated that a
CR (95-1289)
had been previously written to address this issue.
Current plans were to modify the spare windows which were dark in order to have all non-alarmed windows to be dim backlighted.
The inspector concluded that the annunciator system was operating properly.
Annunciator Response Procedures (ARP) were determined to be appropriate.
Further, the licensee was appropriately addressing the spare window illumination issue.
Antici ated Transient Without Scram ATWS Niti atin S stem Actuatin Ci rcuitr ANSAC S stem The inspector performed a walkdown of the Unit 3 and 4 ANSAC systems.
The ANSAC system provides a backup to the reactor protection system (RPS) to mitigate the eff'ects of'n ATWS event.
The ANSAC system would actuate 25 seconds after a failure of the RPS to trip the reactor.
The ANSAC system actuates when 2 of 3 S/G levels are less than 8.65K if reactor power is greater than 35.98K.
The ANSAC system actuates to open the control rod drive motor generator sets'utput breakers, thus de-energizing the rod control system power.
The AMSAC system also auto starts AFW (both trains). isolates S/G blowdown and sampling, trips the main turbine (energizes trip solenoids),
and alarms and annunciates in the control room.
Turkey Point installed the ANSAC systems per PC/Ms89-168 and 169, as required by 10 CFR 50.62.
The inspector reviewed training system description No. 63; operating procedures 3/4-OP-093. 1, AMSAC; test procedures 3/4-OSP-093. 1, ANSAC Logic Test; Instrument calibration procedure MI-I-93-001, ANSAC Calibration and Test; logic and wiring drawings 5610-T-LI; various ONOPs and EOPs; related OPs:
ANSAC design manual 17-60701-DM-001; and, other industry related generic ATWS information.
The inspector also walked down the ANSAC systems with the system engineer.
Selected completed procedures were reviewed, and control room operators were interviewed relative to their system knowledge.
The inspector did not identify any system abnormalities.
Both units'MSAC systems were operating in standby, with both channels functional.
Although not a techniaal specification (TS) related system, licensee attention was evident.
Further, ANSAC is a risk-related and maintenance rule covered system.
Turkey Point ANSAC availability has been very good (greater then 99K).
The system engineer demonstrated excellent knowledge, and a strong sense of system ownershi Operations Procedures and Documentation 03. 1 Emer enc 0 eratin Procedures EOP Review The inspectors reviewed procedures 3/4-EOP-FR-2. 1, Response to
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Containment Pressure, and walked them down with operations personnel in the field.
The inspectors had the following EOP comments:
Valves 11-HV-77 and HV-3/4-1 through 4 were locked; however, the procedures did not acknowledge this condition; Valves'dentification labels were not consistent with the piping drawings; however, the labels were consistent with EOP nomenclature:
The Unit 3 and 4 remote handwheel reach rod operators were different colors (white vs. black);
DPI-2304 (filter differential pressure)
scale was 0-5"; however, the EOP required the pressure be maintained less than or equal to
lt A flow integrator (Y-1425) was installed, but not used by the EOP; Unit 3 and 4 procedures were different as evidenced by waste gas system manipulations in the Unit 4 EOP.
Although differences existed, operators were able to adequately operate the PACV system using the EOPs.
This was based on field observation and in-office review.
Nevertheless, the licensee initiated EOP changes to enhance these procedures.
The inspector concluded that adequate procedures existed, with revisions completed to enhance the EOPs as stated in condition report No. 96-1246.
Based on inspector questions on the PACV system, the licensee reviewed the system in detail.
During this review, issues with an interfacing system were discovered (section E3.1).
Oper ations Organization and Administration 06, 1 JOOti I-During the period, the licensee formalized the electronic log book process.
The computer local area network (LAN) is now used to record operating information for the control room operator narrative log books.
Procedure 0-ADH-204. Operations Narrative Logbooks, was revised.
Further.
a new operating department instruction (ODI) for conduct of operations (CO) was written (ODI-C0-024, Operations Narrative Logbooks LAN Program).
The inspector reviewed the ADM and ODI-CO, examined the logkeeping practices, and discussed implementation with operators.
The logs were
07.1 07.2 07.3 noted to be accurate and informative.
The inspector concluded that operator logkeeping was appropriate, and that the transition to electronic logs was well planned and effectively implemented.
Quality Assur ance in Operations Com an Nuclear Review Board CNRB The inspector attended a portion of CNRB meeting No. 436 held at Turkey Point on October 15, 1996.
The inspector verified that the meeting was conducted in accordance with Technical Specification 6.5.2, NP-803 (Nuclear Policy - CNRB), and CNRB implementing procedures.
Generally, the CNRB meets monthly. rotating the location of the meeting among the three FPL sites (e.g..
Turkey Point, St. Lucie and Juno Beach).
Normally representatives from all three locations are present at each meeting.
The inspector noted that the Turkey Point Plant Manager's report was very informative and it sparked a good exchange of questions and a
healthy discussion.
The inspector also noted that the CNRB continued to address self-assessment issues.
and the CNRB held a discussion. of early warning indicators in order to identify degrading performance.
The inspector concluded that the CNRB remained focused towards nuclear safety, effectively carried out their charter, and that members displayed a very good questioning attitude.
Plant Nuclear Safet Committee PNSC The inspectors attended several PNSC meetings during the period.
Technical Specification (TS) and procedure requirements were verified including meeting frequency, quorum, and review responsibilities.
The inspectors noted a good questioning attitude by most members.
The power uprate reviews for both units were particularly thorough.
Overall. the inspectors concluded that the PNSC was functioning well, and demonstrating strong oversight of plant operations.
Self-Assessment Ca abilities The inspector reviewed independent self-assessment capabilities during the period.
This included Quality Assurance (QA) reviews and involvement, and thi rd party reviews.
The inspector noted positive QA involvement during the power uprate activities of both units (section Ol. 1), during routine daily meetings, and during the emergency preparedness activities and audits (sections Pl. 1 and P7.1).
This QA involvement appeared to be beneficial and a
positive effect on nuclear safety.
Specific QA findings were appropriately discussed and addressed by plant managemen e In preparation for the periodic INPO plant evaluation scheduled for January 1997. the licensee initiated a self-assessment audit.
A five person team (from corporate and St. Lucie) evaluated all aspects of station operations during the week of October 28, 1996.
This team debriefed plant management.
and intends to write a special report.
Specific issues were discussed with the inspector.
The inspector concluded that the licensee's self-assessment capability was very good.
II. Maintenance 61726 62700 62703 62707 Ml Conduct of Maintenance Hl. 1 General Comments a.
Ins ection Sco e
Maintenance and surveillance test activities were witnessed or reviewed.
The inspector witnessed or reviewed portions of the following maintenance activities in progress:
PACV system filter changeouts (sections 02. 1 and E2.2).
Unit 4 secondary plant maintenance (section M1.2).
The inspectors witnessed or reviewed portions of the following test activities:
Unit 3 and 4 power uprate instrument surveillance calibrations (section 01.1),
18C preventive maintenance procedure 3-PMI-059.24, Intermediate Range Nuclear Instrumentation H35 Calibration, 4B EDG per procedure 4-0SP-23.1, Diesel Generator Operability Test (section M1.3),
3B Vital Battery related electrical maintenance surveillance procedure O-SME-003.3, 125 VDC Battery Quarterly Maintenance (section M2.2),
Unit 3 operations surveillance procedure 3-OSP-049. 1, Reactor Protection System Logic Test (section H2.3).
Alternate Shutdown Systems Tests (section H2.4).
b.
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 erformed in a satisfactory manner and met the requirements of the echnical Specifications.
c.
Conclusions Observed maintenance and surveillance activities were well performed.
Unit 4 Short Notice Outa e
SNO Unit 4 power was reduced to Mode 2 at approximately 1 x 10-6 amps in the intermediate range, during peakshift on October 21, 1996. for a scheduled SNO.
Among the maintenance activities that were performed during the SNO were the following:
replacement of four feedwater heater relief valves (RV), 4B main feedwater bearing oil leak repai r, and 2A feedwater heater inspection and tube plugging.
The four feedwater heater RVs replaced were on the 5A, 3A.
1B, and 3B heaters.
This completed actions referenced in NRC Inspection Report Nos.
50-250,251/96-6 and 11.
Approximately 42 of 948 tubes were plugged on the 2A feedwater heater.
The root cause for the leaks was determined to be operation with feedwater heater bypassed due to bypass valve failure.
Fretting corrosion resulted in tube failure.
Unit 4 was placed on line at 9:36 p.m.
on October 24, 1996, and reached 100K power on October 25, 1996.
I The inspector monitored the Unit 4 down power evolution, including taking the turbine-generator off-line, portions of the maintenance activities.
and portions of the startup activities.
The initial turbine startup at about 11:30 a.m.
on October 24, 1996, produced abnormally high vibrations at critical speeds.
The licensee stopped startup activities, shutdown the turbine.
and contacted the vendor (Westinghouse).
The vendor had two possible explanations, shaft bow or the abnormal 2A feedwater lineup.
Both of these issues were appropriately addressed, and the vendor observed a successful turbine startup.
The inspectors concluded that overall, licensee performance was good during the Unit 4 SNO.
Emer enc Diesel Generator EDG Testin The inspector observed portions of the 4B EDG monthly test per procedure 4-OSP-023. 1, Diesel Generator Operability Test.
The inspector verified that testing was consistent with TSs, that OSP compl'iance was appropriately and that communications were formal.
Operators performed the testing, with support from system engineering and maintenance.
The inspector witnessed testing and related preparations in the field and from the control room.
Operations use of independent verification and "dual concurrent" verification was noted to be very strong.
This assured correct
component manipulations.
The EDG was declared OOS as appropriate during portions of the test preparations, including when the engine was
"bar'.red over" with air.
The material condition was good and standby lineup of both the 4A and 4B EDG were verified to be appropriate.
In conclusion, operator testing of the 4B EDG was very professional, with noted strong procedure compliance and independent verifications.
Haintenance and Haterial Condition of Facilities and Equipment Balance of Plant BOP E ui ment Reliabi lit a.
Ins ection Sco e
62700 The inspector reviewed a several year listing of unplanned capability loss data for both units along with other plant operating history provided by the licensee to identify potential equipment reliability problems that might exist.
Several unplanned power reductions and trips associated with equipment failures were selected for review to verify that maintenance activities for structures.
systems, and components (SSCs)
were being conducted in a manner that results in the reliable and safe operation of the plant.
The purpose for this review was to identify equipment that has a history of recurring problems or whose failure resulted in a safety system actuation or plant shutdown or resulted in reduced system capability and determine if the problem might have been caused by inadequate maintenance.
b. Observation and Findin s The inspector reviewed plant operating history for 1994, 1995.
and 1996.
The inspector noted that the licensee had experienced several plant trips and unplanned power reductions due to degraded performance of BOP equipment.
The 4KV electrical switchgear, condenser tubes, turbine control oil system, and the 3B steam generator feed pump (SGFP)
discharge check valve were noted to have caused lost electrical generation due to trips or power reductions.
These components were selected for review.
The inspector met with-the system engineers assigned to those systems and reviewed the status of any licensee corrective actions to determine adequacy of'hose actions.
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Corrosion Products in Turbine Control Oil On April 9, 1996, the Unit 4 reactor was manually tripped after operators observed an abnormal response (rapid load increase)
while increasing turbine load following completion of the refueling outage.
As the result of this problem the governor control valve was disassembled and inspected.
During this inspection corrosion products were found and cleaned.
Other turbine control components were inspected for presence of corrosion products in the oil and none were found.
The licensee determined that the problem was a blocked orifice within the turbine governor impeller oil pressure line.
The orifice which
provides a turbine speed feedback signal to the governor bellows was blocked due to the presence of corrosion product buildup.
The inspector reviewed CR 96-0134 which had been issued by the licensee to address this problem.
The licensee attributed the problem to water intrusion into an open governor bellows hole while the governor was removed and covered with temporary covering during the refueling outage.
Although licensee personnel had observed water around the bellows hole during the maintenance activities. the orifice at bottom of the block had not been cleaned and inspected prior to reassembly.
The inspector noted that the licensee had considered the failure to be due to the inadequate cleanup during conduct of maintenance.
Additionally, the licensee classified this failure as a maintenance preventable functional failure (HPFF) under the Haintenance Rule.
NRC
Inspection Report
Nos. 50-250,251/96-4 further addressed this issue, Condenser Tube Failures A large number of unplanned power reductions prior to 1995 were associated with condenser tube fai lures.
Hany of these failures were determined to be the result of manufacture defects associated with titanium condenser tubes provided by a single vendor.
The licensee was subsequently able to identify and plug these tubes.
Additionally, after 1993 the licensee started a condenser inspection program which required an extensive inspection of the hotwell and condenser tubes every refueling outage.
Results of these inspections were addressed through the licensee's CR program.
The inspector reviewed CR 95-713 which documented the most recent refueling outage inspection and tube repairs on the Unit 3 condenser and hotwell.
Examples of licensee actions in this area include replacement of defective tube plugs.
installation of'dditional staking between tubes, removal of loose/damaged flashing, improvement of supports, and improvement of extraction steam spargers.
The inspector concluded that the licensee's program has been effective since no significant condenser tube failure events have occurred on either unit since 1994.
Unit 3 Reactor Tri Due to Loss of 3C 4KV AC Bus An unplanned manual reactor trip occurred on Unit 3 on Harch 27, 1996.
The 3C 4KV AC Bus was inadvertently deenergized when Breaker 3AC16 tripped open while testing breaker 3AC01.
As a result, the 3B SGFP was deenergized when power was no longer available to the 3C 4KV Bus.
Operators were unable to recover the subsequent feedwater and steam generator level transients.
A manual reactor trip was ordered in anticipation of an automatic trip on low steam generator level.
The inspector reviewed CR 96-481 which had been issued by the licensee to address corrective actions associated with this
problem.
This event occurred due to the unexpected opening of breaker 3AC16 which had been supplying electrical power from the 3C Transformer to the 3C 4KV AC Bus.
The 4C transformer supply breaker to the 3C 4KV AC Bus, (3AC01),
was out of its cubicle for breaker testing.
Breaker 3AC16 tripped unexpectedly when breaker 3AC01 was manually tripped during the ongoing testing.
The licensee's investigation of this event revealed that the event occurred due to mechanical induced vibration caused by opening of breaker 3AC01.
The licensee's decision that breaker 3AC16 had tripped due to vibration was due to the absence of the overcurrent or ground fault relays for breaker 3AC16.
The steel floor plates inside of the 3C 4KV AC Bus enclosure were loose.
Additionally, the four floor plates in front of breaker cubicles 3AC01.
3AC02, 3AC15, and 3AC16 were not attached to the structural members at several places.
The licensee believes that this condition allowed the transmission of vibration through the floor.
Inspection of the structure revealed that the floor plates were not secured to the structural members during original installation of the equipment.
The inspector concluded that the event was not due to inadequate maintenance.
Additionally the inspector reviewed WOs 96008279-01 and 9600830-01 which documented tack welding repairs for the associated floor plates for the 3C and 4C 4KV AC Buses.
NRC Inspection Report Nos. 50-250,251/96-4 further discussed this event.
~
Unit 4 Reactor Tri Due to Loss of 4C 4KV AC Bus The inspector reviewed CR 94-890 which had been issued by the licensee to address corrective actions associated with this problem.
An unplanned automatic reactor trip occurred on Unit 4 on September 23, 1994.
The 4C 4KV AC Bus received a lockout when the cubicle door for Breaker 4AC01 was being closed.
The C-phase di.fferential protection relay (1874CBT1) which was mounted on that door had been jarred when the door was closed.
The lockout of the 4C 4KV AC Bus resulted in loss of the non-vital Rod Control Power Supply, PS-4.
Additionally, Rod Control System Power Supply, PS-3, in Power Cabinet 1AC failed resulting in dropping of 12 control rods.
PS-4 and PS-3 provide power to the rod control system through an auctioneered power supply ci rcuit such that the highest voltage is used.
PS-3 had failed due to component age, and was unable to provide adequate voltage to the rod control system resulting in the control rods dropping.
The licensee's investigation concluded that the loss of the 4C 4KV AC Bus had been due to the system design and subsequent modifications were scheduled to relocate the protection relays to a less vulnerable location.
The licensee also decided to replace the rod control system power supplies with new power supplies.
The inspector reviewed PC/M 94-139 and PC/M 94-114, and verified that the respective protective relays had been relocated on the 3C and 4C 4KV AC Buses.
Additionally, the inspector reviewed WO 95010349-01, 95010031-01, 95001004-01, and 95004400-01 which
documented replacement of the existing power supplies in the Unit 3 and Unit 4 rod control power cabinets 1AC.
2AC, 1BD.
and 2BD with new power supplies.
The inspector determined that the old power supplies had already been scheduled for replacement due to age.
However, based on this event the licensee placed a higher priority on that replacement.
The inspector concluded that the event had not been due to inadequate maintenance and that corrective actions were adequate to address this problem.
NRC
Inspection Report
Nos. 50-250,251/94-18 also addressed this issue.
~
Steam Generator Feedwater Pum Dischar e Check Valve Failure On February 9, 1996, the Unit 3 reactor tripped due to an unplanned automatic turbine trip on high S/G level which had resulted during a feedwater transient following a failure of the 3B SGFP Discharge Check Valve, 3-20-218.
At the time of the trip, the licensee was in the process of investigating a suspected loose part in the 6B feedwater heater, and had installed diagnostic test equipment on the 3B SGFP discharge check valve.
The check valve failed to close when the SGFP was stopped and feedwater flow to all three S/Gs was reduced due to reverse flow through the stuck open check valve.
During the subsequent recovery operations personnel failed to adequately monitor S/G levels.
and excessive flow to the 3C S/G resulted in a main turbine trip on high S/G level.
The inspector reviewed CR 96-0134 which had been issued by the licensee to address this problem.
The licensee determined that the fai lure of the check valve had been due to failure of tack welds on one of the hinge pin retaining bolts.
The unsecured bolt became unscrewed and the hinge pin fell out.
Both hinge pins on the affected check valve were replaced and new tack welds were verified as adequately sized.
The licensee inspected all similar type check valves to verify adequate sized retaining bolt tack welds.
Although there were no specific examples of improper maintenance activities which had caused this failure the licensee had concluded that the event might have been avoided by corrective actions associated with the previous loss of a check valve hinge pin in Unit 4 during 1993.
Corrective actions were established at that time, but not performed on Unit 3.
As the result of this the licensee had classified this failure as a
MPFF in accordance with the Maintenance Rule.
The inspector concluded that the licensee's corrective actions were adequate.
Additionally, the inspector noted that the licensee had subsequently classified this check valve as a Maintenance Rule category a(1)
SSC which required additional monitoring and the establishment of goals and specific performance criteria.
NRC Inspection Report Nos. 50-250,251/96-2 further discussed this automatic reactor tri c. Conclusions The licensee experienced several trips and unplanned power reductions due to poor reliability of BOP equipment over the past few years.
Although some of these problems have resulted due to equipment design, other problems could have been avoided by better maintenance practices.
These problems are well understood by licensee management and ongoing corrective actions should result in improvements in reliability of the associated equipment.
3B Batter Interconnector Hi h Resistance During the performance of procedure O-SME-003.3, 125 VDC Station Battery Quarter ly Maintenance.
on the 3B Battery, electricians noted minor corrosion on the intercell connections.
Further, the jumper connection between cell 20 and 21 was noted to have a higher than expected micro-ohm resistance reading.
(The acceptance criteria was less than 150 micro-ohms.)
The resistance of the cell-to-cell jumpers ranged from 156 to 187 micro-ohms.
Consequently.
the jumpers were disconnected.
cleaned, and reassembled.
The as-left resistance was within the acceptance criteria.
The minor corrosion noted was also removed.
The inspectors monitored portions of the surveillance, and concluded that appropriate supervisory oversight and attention was present.
Further, the surveillance and the subsequent maintenance were appropriately completed.
Reactor Protection Rela RT Failure Operations surveillance procedure 3-OSP-049. 1, Reactor Protection System (RPS) Logic Test, was performed on Unit 3 beginning at 11:35 a.m.,
on November 5, 1996.
The "A" RPS channel was allowed to be bypassed for up to two hours for testing per T.S. 3.3. 1. Table 3.3-1 item, 19, with the 3A Reactor Trip bypass breaker closed.
At approximately 12:41 p.m.,
during the conduct of procedure 3-OSP-049. 1, relay RT-9, associated with turbine trip function failed to re-energize.
Subsequent troubleshooting identified a burned coil, and the relay was replaced.
Procedure 3-OSP-049. 1 was satisfactorily completed.
To accommodate changeout of relay RT-9, a six hour action statement pursuant to T.S. 3.3. 1, Table 3.3-1 was entered at 1:35 p.m., i.e., at the expiration of the allowed two hours for testing.
Procedure 3-OSP-049. 1 was satisfactorily completed at 1:48 p.m., with a newly replaced relay RT-9.
The inspector monitored and discussed the issue with the licensee.
The inspector concluded that entering the six hour to hot standby T.S. 3.3. 1 action statement at 12:41 p.m. (i.e.. at the time that RT-9 was identified to have failed), would have been more conservative.
However, this did not change the outcome as the RPS train was returned to service well within the allowed six hours.
The inspector concluded that the RPS test was well conducte M2.4 Alternate Shutdown Panel
a.
Ins ection Sco e
62700 and 61726 The inspector reviewed the licensee's maintenance and testing program for the alternate shutdown panel (ASP) at Turkey Point to evaluate the adequacy of the licensee's program for maintenance and routine testing of this system.
Additionally, the inspector reviewed post modification testing following implementation of design changes to determine adequacy of testing.
b. Observation and Findin s Instrumentation and controls to achieve and maintain hot and cold shutdown as required by 10 CFR 50 Appendix R are provided by a separate ASP for each unit.
This is supplemented by manual actions at local component control stations.
The inspector determined that the Unit 3 ASP was installed and functionally tested in 1988.
and the Unit 4 ASP was installed and functionally tested in 1986.
Systems and components required to satisfy the alternate shutdown capability at Turkey Point were described in the licensee's UFSAR Sections 7.7.2.2, 9.6A-5.0 and Table 9.6A-2.
Although the site has no Technical Specification requirements for routine testing, the licensee performed functional testing of ASP controls on a refueling outage basis as the result of a licensing commitment.
This commitment was documented in FPL letter (L-83-516) dated October 7.
1983.
The inspector performed walkdowns on the Unit 3 ASP (Panel 3C264)
and the Unit 4 ASP (Panel 4C264),
along with selected local controls located on the safety related 4KV electrical switchgear
.
No loose wires, nor damaged components, nor evidence of corrosion were observed during this walkdown.
Material condition inside and outside of the panels.
including housekeeping.
was very good.
The inspector reviewed the licensee's listing of modifications for the ASP and systems controlled from the ASP.
Three completed plant modifications which could have potentially affected operability of ASP instrumentation or the ability to control components from the ASPs were selected for review.
Plant Change/Modification (PC/M) records for those completed modifications were reviewed by the inspector to determine actual scope of modification activities and adequacy of required post modification testing.
The inspector determined that for each case post modification testing of ASP controls was not required since the scope of modification activities for the selected PC/Ms could not have affected the ability to control components from the ASPs.
No problems were identified during this review.
The inspector reviewed procedures.
3-0SP-300.2, Pre-staging Equipment and Alternate Shutdown Panel 3C264 Switch and Instrument Alignment Check, and 4-0SP-300.2, Pre-staging Equipment and Alternate Shutdown Panel 4C264 Switch and Instrument Alignment Check, which are performed by the licensee on a monthly basis.
The inspector also reviewed
procedures, 3-0SP-300.1, Alternate Shutdown Panel 3C264 Operability Test.
4-OSP-300. 1. Alternate Shutdown Panel 4C264 Operability Test, 3-OSP-300.3, Safe Shutdown and Alternate Shutdown Operability Test Unit 3, 4-0SP-300.3, Safe Shutdown and Alternate Shutdown Operability Test Unit 4, which are used by the licensee to periodically verify operability of the transfer switches and functional controls located on the ASP and at local control stations.
These test procedures were performed every refueling outage.
During this review the inspector determined that all necessary instrumentation located on the ASP or locally is routinely checked.
and all requi red controls are adequately tested.
c. Conclusions The inspector concluded that the licensee has maintained the alternate safe shutdown equipment in a satisfactory manner.
Further, the licensee.'s program for routine testing of ASP instrumentation and controls was adequate.
The inspector did not identify any examples of inadequate post modification testing following licensee modifications activities that could have had a negative impact on any control functions of equipment operated from the ASP.
Reactor-. Tri Breakers The inspector reviewed the status of licensee action to address an NRC Information Notice ( IN 96-44).
IN 96-44 was issued to alert licensees to the possible failure of reactor trip breakers to properly function because of cracking or breakage of the secondary disconnecting contact assemblies.
During reactor trip breaker testing at another nuclear facility, the licensee found that one of the bypass breakers failed to open electrically when the local shunt trip push button was depressed.
During subsequent inspection of the breaker, a small piece of the assembly was found lodged in the secondary disconnecting contact assembly, which may have prevented reliable electrical continuity for the local shunt trip push button ci rcuitry for the manual trip function.
The disconnect assemblies provide circuit connections between the control and monitoring devices on the breaker and external control circuits.
The housing of the electrical contacts in the disconnect assemblies consists of a phenolic material.
The assemblies are made of a molded, cellulose-filled, phenolic material that appears to have low impact strength and may be highly susceptible to chipping or cracking.
Breakage or partial cracking of these assemblies may prevent the breaker from performing its design function or other secondary functions provided by the status of'he breaker position.
The inspector reviewed CR 96-1277 which documented the licensee's disposition of this issue.
The Reactor Trip Breakers installed at Turkey Point are Westinghouse DB-50 type breakers which differ from the design which were in use at the nuclear facility mentioned in IN 96-44.
DB-50 type breakers include a metal insert on the secondary contact assembly which is not present in the DS-416 type breakers as used in the
other facility.
This insert provides reinforcement of the assembly such that the phenolic should not be subject to the same breakage mode as seen with the DS-416 type breakers.
Additionally, the inspector noted that the licensee performs a breaker inspection every refueling outage which should identify potential problems.
The inspector reviewed inspection procedure, OPME-049. 1. Reactor Trip and Trip Bypass Breaker Inspection and Maintenance, and verified that Step 6. 18. 1 included a
requirement to verify that the secondary contact assembly base is free of cracks during this periodic inspection.
The inspector concluded that the licensee adequately addressed IN 96-44.
III.
En ineeri n 37551 90712 90713 92700 E2 En ineerin Su ort of Facilities and E ui ment E2. 1 Seismic Ade uac of Mechanical and Electrical E ui ment a.
Ins ection Sco e
By letter dated February 9, 1995, the NRR staff issued a safety evaluation (SE) report on the licensee's implementation program for addressing Generic Letter 87-02, "Verification of Seismic Adequacy of Mechanical and Electrical Equipment in Operating Reactors, Unresolved Safety Issue (USI) A-46."
In the SE, the NRR staff identified several open items, and indicated that a site audit would be conducted to address the open items.
The audit was performed during December
through 8, 1995, by a team consisting of two members from NRR, one member from NRC Region I, and one contractor from Brookhayen National Laboratory (reference NRC/NRR Trip Report and NRC Inspection Report Nos.
50-250.251/95-22).
During this current inspection period, the NRR Project Manager reviewed the licensee's corrective actions associated with the audit findings.
b. Observations and Findin s
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Concrete Crack During the audit, the NRC staff noted a crack on the concrete floor in front of the Unit 4A DC Load Center.
The staff was concerned that the crack may propagate through the pedestal near the anchor bolts, and could degrade the load carrying capacity of the bolts.
The staff was also concerned the crack could worsen and further degrade the anchorage capacity.
The licensee documented the item in CR 95-1220.
The licensee calculated that the integrity of the panel anchoring system was adequate with the existing crack.
The crack was re-inspected on February 26, 1996, within the perimeter of the distribution panel.
The licensee indicated that the crack crossed the perimeter of the cabinet but stopped approximately 5 inches prior to reaching an anchor bolt.
The licensee concluded that the
structural capacity of the anchor bolt was not compromised by the crack and no further actions were required.
Photographs of the area within the cabinet were reviewed during this period.
The crack does not appear to be approaching the anchor bolt, even if it did continue to grow.
The staff concluded that the crack is not approaching the anchor bolt and even if it did, the licensee has demonstrated that the integrity of the panel anchoring system would still be acceptable.
Based on the licensee's review and the NRC's assessment, this issue is closed.
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Unit 3 Emer enc Diesel Generator EDG Da Tank Site Glass During the audit, it appeared that the licensee had failed to address the Seismic Review Team (SRT) recommendation to replace a
sight glass on the EDG day tank.
The SRT and the NRC staff were concerned that the sight glass may rupture during a seismic event causing a loss of the EDG fuel oil rendering the affected Unit 3 EDG inoperable.
The licensee documented this deficiency on CR 95-1219.
Subsequent to the audit, the licensee indicated that the sight glass isolation valves contained an internal ball which seats on excess flow to minimize oil loss upon rupture of the sight glass.
The NRC reviewed drawings which documented the existence of an internal ball/seat arrangement.
Based on the inspection, this item is closed.
125 VDC Safet Related Batter S acers During a walkdown of the station batteries during the audit. the NRC staff noted the existence of small clearances between some of the end battery cross braces, and between some interior battery cells and vertical cross braces.
These clearances could result in damage due to the batteries impacting the restraints and support structures.
The staff believed that the gaps should be eliminated or spacer cushions should be inserted.
The licensee documented this deficiency on CR 95-1217.
A walkdown of the five safety related battery rooms was conducted.
The batteries were confi rmed to be in contact with the end braces and foam existed between the battery cells.
In addition, procedure O-SME-003.3, 125VDC Station Battery Quarterly Maintenance, was revised to visually inspect the batteries for missing foam spacers and replace any missing spacers.
The current condition of the battery spacers was adequate, and the quarterly surveillance addressed the battery spacers acceptable configuration.
Based on inspection and review this issue is close VAC Safet Related Switch ear Cabinet Fasteners During the equipment walkdowns during the December 1995 Audit, the NRC staff identified loose fasteners and, in some cases, a lack of fasteners for securing some electrical cabinet doors.
This was documented in CR 95-1217 which stated that "doors on 4160 switchgear are not secured with the bolt on the upper part of the dooI
.
The panel doors are hinged on one side and secured by a single pivoting door latch at the midpoint of the outer edge of the door.
A hole exists at the upper corner of the door and, previously, bolts were loosely attached through some of these holes.
The licensee indicated that the upper bolts were not currently used to secure the doors and postulated that these bolts were used during shipping of the cabinets to the site or provided to secure the door when routine personnel access is not desired.
The licensee stated that there was no need for these fasteners and they had been removed subsequent to the audit.
The inspectors verified that the bolts had been removed from the switchgear panels, and there were no loose fasteners on the exterior of these panels.
Hased on inspection and review, this issue is closed.
Com onent Coolin Water CCW Rust and Corrosion During the December 1995 audit, several areas were observed to have equipment which was severely degraded by corrosion.
Of special note was the CCW area.
The NRC staff was concerned that further degradation could challenge the structural integrity of the supports.
It was noted that in several cases, the licensee appeared to have recently painted some of the corroded structures, but that the corrosion products had not been removed.
It was found that more aggressive maintenance may be necessary for prolonged reliance on these systems for carrying seismic (and other) loads.
This was documented in CR 95-1217.
In the engineering evaluation of CR 95-1217, the licensee stated that various supports within the CCW pump Rooms exhibited minor surface rust and the section loss was negligible and did not affect the structural integrity of the supports.
The CR disposition also stated that the cleaning and re-coating of these supports would be addressed under the Material Condition Upgrade Program which periodically inspects and maintains the material condition of plant systems, structures and components.
The CCW rooms were walked down during this current inspection period.
Several areas of surface corrosion were noted in the Unit 4 CCW area, none of which appeared to be severe.
The licensee stated that this area was last recoated in 1994.
The NRC noted that one structural member had been replaced due to
corrosion in this area since the December 1995 audit.
This area was scheduled to be re-coated in the near future.
The Unit 3 CCW area was in the process of being recoated.
It was noted that three anchor bolt nuts were degraded, some to the point of being nonexistent, and had been painted over.
It appeared that they had become corroded, the corrosion products removed.
and the remaining anchor bolt painted over.
The licensee initiated CR 96-1222 to document this new problem.
The licensee stated that Maintenance Specification SPEC-C-004 provides requi rements for coatings in these areas.
Section 2.1.5 of the SPEC stated that abnormal conditions in structures, equipment, hangers, etc (loose nuts, wiring, cracks, severe corrosion, etc.) shall be reported to the FPL Coating Supervisor.
For the areas in question, it is intended that engineering would be contacted to evaluate these abnormal conditions when encountered by the maintenance personnel performing the coating.
The licensee stated that additional guidance for coating personnel may be necessary to prevent recurrence.
As stated previously, the licensee indicated that the Material Condition Upgrade Program would address the cleaning and re-coating of the supports in the CCW pump area.
CR 95-1217 did not completely address the deficiencies identified during the December 1995 audit, since additional deficiencies were noted this period.
The licensee could not produce documentation for a formal
"Material Condition Upgrade Program".
The currently existing program consisted of an informal process of management walkdowns of plant areas on a periodic basis.
The observations during the walkdowns were then used to establish priorities for cleaning and re-coating of areas as well as other work based on the observations.
Although there is no formal "Material Condition Upgrade Program".
there are formal station procedures used for maintaining the material condition of the plant.
Procedure ADM-008. Management and Supervisor Field Walkdowns, provided requirements to ensure that material deficiencies.
industrial safety hazards.
cleanliness and housekeeping deficiencies are identified and corrected to meet management standards.
This ADM states that the Plant General Manager should schedule and lead a field walkdown at least once per week.
The ADH does specify that material condition deficiencies such as rust and corrosion, loose missing fasteners, and missing/open panels should be noted and corrected.
Engineering Department Instruction (EDI) procedure EDI-SE-005, Component and System Walkdowns, required monthly walkdown of systems by System Engineers.
This procedure requires checking for excessive corrosion on piping.
pumps.
valves, HVAC ducts, electrical conduits, supports.
and other metal surface The NRC concluded that seismic housekeeping in the CCW pump and heat exchanger areas remained a problem.
CR 95-1217 did not specifically address the problem identified in the December 1995 audit.
In addition. existing licensee processes were weak in maintaining the material condition of the CCW area.
The inspector intends to revi.ew corrective actions associated with this recent issue in a future inspection.
c. Conclusion Open items associated with the seismic adequacy of mechanical and electrical equipment were closed.
USI A-46 was considered to be resolved based on the NRC issued SE and on inspection.
E2.2 Power U rate Plant Chan e/Modifications PC/Ms In order to support the Unit 3 and 4 thermal power uprates, a number of PC/Ms were requir ed.
These included the following Unit 3 (4) PC/Hs:
PC/M 95-75 (95-97),
Hainsteam safety valve discharge piping, PC/H 95-76 (95-113),
Condenser tube staking.
PC/M 96-22 (96-22).
Thermal power uprate implementation, PC/H 95-170 (95-171).
Thermal power upr ate setpoint and scaling, PC/H 96-24 (96-25), Cycle Reloads (Unit 3 Cycle 15. Unit 4 Cycle 16)
PC/M 95-167 Environmental qualification, PC/H 95-147 (95-148),
Emergency Containment Cooler (ECC) autostart modification.
PC/H 94-035 (95-100), Protection System setpoint changes, PC/H 94-111 (95-87),
Rod control timing changes, PC/H 95-89 and 103 (95-104)
CCW supports, PC/H 95-54 Unit 3 CCW Cooling Changes, PC/M 95-119 (95-120), Piping isometric thermal changes PC/H 95-99 (95-143).
Minor drawing updates, PC.H 96-37 (96-38).
RCS flow scaling.
and PC/M 95-141 (95-142),
CST low level alarm modificatio In addition, a number of PWOs were implemented to address setpoint and alarm changes.
A number of these PC/Ms were completed during the last two refueling outages.
NRC Inspection Report Nos. 50-250,251/95-16, and 96-02.
and 96-06 reviewed selected outage PC/Hs.
During the current inspection period, inspectors reviewed selected PC/Hs including the following items:
PC/H packages.
CFR 50.59 review, Post-modification testing, Work controls and instructions, Operator oversight and control, Drawing updates.
Procedure changes, Site training, and PC/M turnover and acceptance.
The inspectors concluded that the PC/Ms were appropriately implemented.
PC/M packages were well maintained and easily retrievable for audit purposes.
E3 Engineering Procedures and Documentation E3. 1 Post Accident H dro en Monitor PAHM S stem Vulnerabi lit Based on questions arid issues related to the design and operation of the PACV system (see sections 02. 1 and 03. 1), the licensee initiated a
design review.
The inspector discussed these issues with plant management during the routine 9:00 a.m.,
Wednesday meeting on October 9,
1996.
Subsequently, management directed engineering to perform an assessment, and a multi-disciplined operational and design review of the PACV system.
Although not formally required, the licensee referenced the following quality instructions (QI) procedures and processes:
QI-3-PTN-1, Design Control ENG QI 1.0, Design Control ENG QI 1.7.
Design Input/Verification
ENG QI 1.8, Design/Operability Reference Guide ENG QI 1.9, Equipment/Accident Interface Reference Guide By 4:20 p.m.
on October 9,
1996. the licensee had discovered a
vulnerability in the PAHM system and its possible negative effect on the interfacing PACV system.
A 10 CFR 50.72, section (b)(2)(iii)(c) report, due to a possible uncontrolled radiation release, was made to the NRC at 5:32 p.m.
The licensee determined that in a single active failure the PAHM system lineup following a valid ESF actuation could render both the PAHM and PACV systems inoperable.
If a single active fai lure of one of the containment hydrogen sample suction valves occurred, procedural guidance existed to allow cross-tying the PAHM and PACV systems.
This would result in potentially over-pressurizing the PACV filter system resulting in an unintentional monitored release and compromising containment integrity.
Specifically, valves HV-3/4-1 and 3 are opened per procedures 3/4-OP-094, Containment Post Accident Monitoring Systems, section 7. 1. If valve HV-3/4-1 fails to open, valves HV-3/4-2 and 4 are di rected to be opened by the OP.
If this were to occur, the PACV system would be exposed to containment design pressure of 55 psig, resulting in a possible failure of the PACV filters (designed to 5-10 psig).
This would then result in a release to the auxiliary building.
The licensee immediately modified the OPs on October 9, 1996.
A condition report (96-1263)
was generated and an LER (96-11) was written.
This issue remains open pending further NRC review.
Control of Heav Loads The inspector reviewed unresolved item 50-250,251/96-10-02 that was discussed in NRC Inspection Report Nos. 50-250,251/96-10, dated September 11, 1996.
The item was unresolved pending submittal of an LER and completion of planned corrective actions.
The licensee issued LER 96-009-00, Failure to Reflect Heavy Load Design Information in Procedural Controls on August 27, 1996.
This docketed LER further discussed the issue pertaining to the URI.
Further, the inspector also reviewed revised procedures O-ADM-717, Heavy Load Handling and 0-ADM-719, Rigging Controls.
These procedures were revised to address deficiencies that were identified during licensee review of NRC Bulletin 96-02, Movement of Heavy Loads Over Spent Fuel, Over Fuel in the Reactor Core, or Over Safety Related Equipment.
Specifically, Heavy Loads were re-defined as loads in excess of 1760 pounds for areas not included in the SFP.
Further, safeload paths associated with the Turbine Gantry Crane were re-defined to address concerns surfaced as a result of NRC Bulletin 96-02 review.
As discussed in LER 96-009.
safeload path and heavy load handling procedure changes made in 1982 did not adequately reflect the safe load path and heavy load handling criteria established in an NRC approved safety evaluation.
This failure to adequately upgrade plant procedures
e
in the early 1980's was classified as a Non-Cited Violation, NCV-50-
'50,251/96-12-01.
Control of Heavy Loads, consistent with section VII.B.1 of the NRC Enforcement Policy.
The LER and URI, as well as the NCV are closed.
E8 Hiscellaneous Engineering Issues E8. 1 Licensee Event Re ort LER Reviews
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Unit 3 LER 96-10 The LER addressed two dropped rods that occurred on September 24, 1996.
The unit was shutdown in response to the event to troubleshoot the rod control system.
Root cause was determined to be a rod control card (regulation card) fai lure due to high temperature related aging.
This was confirmed by Westinghouse testing.
The inspector reviewed the event during NRC Inspection Report Nos, 50-250,251/96-11.
The inspector reviewed the LER, confirmed that root cause and corrective actions were addressed.
and closed the LER.
The LER was determined to be well written and submitted in a timely fashion.
~
Unit 3 and 4 LER 96-09 (see section E3.2 of this report)
~
Unit 3 and 4 LER 96-11 (see section E3. 1)
IV. Plant Su ort 71750 82701 R1 Radiological Protection and Chemistry (RP&C) Controls Rl. 1 Number Two Waste Holdu Tank 2 WHUT Overflow During peakshift (3:00 p.m.
- 11:00 p.m.)
on October 23, 1996, the radwaste building hot water heater RV failed resulting in leakage of clean service water (non-safety related)
on the first and second floors of the radwaste building.
The water flowed into a floor drain and then into the sump, and was subsequently pumped into the g2 WHUT.
The large amount of water overflowed the tank, and the water was contained within the concrete berm which surrounds the tank.
The licensee initiated CR No. 96-1329 to evaluate root cause and to determine corrective actions.
The midnight shift SNPO noted this condition at about ll:35 p.m. during a routine tour.
The peakshift SNPO noted a slightly higher g2 WHUT level during the shiftly tour.
However, the peakshift SNPO attributed the level increase to water processing evolutions that had occurred during day shift.
A high level alarm for the tank apparently annunciated locally; however, no one is stationed in the radwaste
,
e
building unless water processing is being conducted.
This alarm has no remote annunciation either in the auxiliary building or the control room.
The licensee initiated actions to pump down the berm and to process the water.
The inspector learned of this issue during the morning meeting on October 24.
1996.
Followup included log reviews, discussions with operators and HP personnel, and a walkdown of areas affected.
The inspector confirmed that only shiftly tours of the radwaste building were required, and they were performed.
Several feet of water (from the overflow) were visible and contained by the tank berm.
The inspector did note a small (one square foot) area of water outside the berm.
HP personnel surveyed this area, and noted slightly above background counts.
The area was subsequently cleaned.
A discussion with the peakshift HPSS on October 24, 1996, was held at about 3:30 p.m.
Although the HP log documented the tank overflow, the HPSS had not yet read the log.
The licensee included the following corrective actions:
Upgraded the HPSS shift turnover process, including the initiation of a formal "operator-like" HPSS shift relief checklist, Improved SNPO log readings, including tank trending data for the computerized logging devices.
Initiated actions for engineering to review a remote alarm capability for the radwaste building alarm panels, Processed the overflow water in the g2 WHUT berm, and deconned the affected areas, Upgraded the hot water heater RV, and area material condition, and Counselled personnel involved.
The inspector evaluated these corrective actions, and determined them to be adequate.
Weaknesses were identified relative to operator tours and logging, HPSS turnover, and in the radwaste building alarm capabilities.
The licensee appropriately addressed each of these areas.
In addition, later in the inspection period, the licensee instituted some changes in HP management and reporting relationships.
P1 Conduct of EP Activities P1.1 Hurricane Lili Pre arations The inspectors monitored licensee preparations that were performed in anticipation of Hurricane Lili during the period October 15 -19, 1996.
These included plant walkdown. discussions with local and state officials, and contingency planning.
While the path of Hurricane Lili did not affect Turkey Point, the inspectors concluded that licensee
planning, preparation, and coordination activities were well performed.
The hurricane and tropical storm related procedures (ONOP and EPIP) were well implemented, and the continuing use of an "outage-like" critical path schedule demonstrated proactive hurricane preparedness.
P7 Quality Assurance in EP Activities P7.1 Emer enc Pre aredness EP Self-Assessment Based on issues and concerns which surfaced at St. Lucie relative to the EP program. the Turkey Point EP group performed a self-assessment.
This activity reviewed the concerns and issues that were raised at St. Lucie, and evaluated their applicability at Turkey Point.
The licensee reviewed the 16 specific issues.
and evaluated each item individually.
The licensee concluded that Turkey Point EP plan and its implementing procedures adequately address all of these concerns.
The licensee documented this review per an EP initiated memo (PTN-EP-96-046)
dated October 15, 1996.
The inspector reviewed the issues and the memo, and discussed each item with EP management.
The NRC intends to review this again during the normal EP core inspections.
The inspector did note that the licensee was proactive.
and thorough during the EP self-assessment and review.
V.
Mana ement Meetin s The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on November 22, 1996.
The licensee acknowledged the findings present.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.
No proprietary information was identifie Partial List of Persons Contacted Licensee T.
V. Abbatiello, Site guality Manager R. J. Acosta, Director, Nuclear Assurance J.
C. Balaguero.
Plant Operations Support Supervisor P.
H. Banaszak, Electrical/I8C Engineering Supervisor C.
R. Bible, Systems Engineering Manager W.
H. Bohlke, Vice President.
Engineering and Licensing T. J. Carter, Project Engineer B. C.
Dunn, Mechanical Systems Supervisor R. J.
Ear 1, OC Supervisor S.
H. Franzone.
Instrumentation and Controls.Maintenance Super visor R. J. Gianfrancesco.
Maintenance Support Supervisor R.
G. Heisterman, Maintenance Manager J.
R. Hartzog, Business Systems Manager P.
C. Higgins, Outage Manager G.
E. Hollinger, Licensing Manager R. J.
Hovey, Site Vice-President M. P.
Huba, Procurement Supervisor and Materials Manager D.
E. Jernigan.
Plant General Manager T. 0. Jones.
Acting Operations Supervisor H.
D. Jurmain, Electrical 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 H. L. Lacal. Training Manager J.
D. Lindsay. Health Physics Supervisor J.
T. Luke, Engineering Manager E. Lyons, Engineering Administrative Supervisor F.'.
Harcussen, Security Supervisor R.
B. Marshall, Human Resources Manager H.
N. Paduano.
Manager, Licensing and Special Projects M. 0. Pearce.
Projects Supervisor K.
W. Petersen, Site Superintendent T. F. Plunkett, President, Nuclear Division K. L. Remington, System Performance Supervisor R.
E.
Rose.
Nuclear Materials Manager and Outage Manager C.
V. Rossi, QA and Assessments Supervisor A. H. Singer, Operations Supervisor (Acting Operations Manager)
W. Skelley, Plant Engineering Manager R.
N. Steinke, Chemistry Supervisor E. A. Thompson.
Project Engineer D. J.
Tomaszewski, Component Specialist Supervisor B.
C. Waldrep, Mechanical Maintenance Supervisor G. A. Warriner
. Ouality Surveillance Supervisor R.
G. West, Operations Manager
Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, mechanics, and electricians.
NRC Resident Ins ectors B.
B. Desai, Resident Inspector T.
P. Johnson, Senior Resident Inspector NRR Pro ect Mana ers PM R. Croteau
~ Turkey Point (PM)
L. Wiens, St. Lucie (PM)
Partial List of Opened, Closed, and Discussed Items 0 ened None Closed 50-250.251/96-12-01
~
NCV, Control of Heavy Loads (sections E3.2, E8.1)
50-250,251/96-10-02.
URI, Control of Heavy Loads (sections E3.2.
E8.1)
LER 50-250/96-09.
Control of'eavy Loads (sections E3.2
~
E8. 1)
LER 50-250/96-10, Unit 3 dropped rods (section E8. 1)
Discussed LER 50-250,251/96-11, Post-Accident Containment Hydrogen Monitor Vulnerability (section E3. 1)
List of Inspection Procedures (IP) Used IP 37551:
Onsite Engineering IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and Prevent Problems IP 61726:
Surveillance Observations IP 62700:
Maintenance Programs IP 62703:
Maintenance Observations IP 71707:
Plant Operation
IP 71750:
IP 90712:
IP 90713:
IP 92700:
Plant Support Activities Inoffice Review of Written Reports Review of Periodic Reports Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities List of Acronyms and Abbreviations AC ADM a.m.
amp AMSAC ARP ASP ATWS BOP CCW CFR CNRB CR CST DC DP(I)
'F FL FPL GDT HEPA HP HPSS HV I8C Alternating Current Administrative (Procedure)
Ante Meridiem Ampere ATWS Mitigation System Actuation Circuitry Annunciator Response Procedure Alternate Shutdown Panel Anticipated Transient Without Scram Balance of Plant Component Cooling Water Code of Federal Regulations Company Nuclear Review Board Condition Report Condensate Storage Tank Direct Current Differential Pressure ( Indicator)
Power Reactor License Division of Reactor Safety Emergency Containment Cooler Emergency Core Cooling System Emergency Diesel Generator Engineering Department Instruction For Example Engineering Emergency Operating Procedure Emergency Preparedness Emergency Plan Implementing Procedure Engineered Safeguards Feature Degrees Fahrenheit Florida Florida Power and Light Gas Decay Tank High Efficiency Particulate Air Health Physics HP Shift Super visor Hand Valve Instrumentation and Control
~ ~
i.e.
IN INPO JPN KV LER LPDR LT MI MPPF MWe(th)
NCV No.
NP NPS NRC NRR ODI-CO ONOP OP OSP PACV PAHM PC/M PDR p.m.
PM PME PNSC PS PTN PWO QA QI R(M)
RCS RPS RT RV SE SENJ SEMS SFP S/G SGFP SJAE SME SMI SNO SNPO SPEC SPING
That Is Information Notice Institute for Nuclear Power Operations Juno Project Nuclear (Nuclear Engineering)
Kilo Volt Licensee Event Report Local PDR Level Transmitter Maintenance Instruction Maintenance Preventable Functional Failure Megawatts Electric (Thermal)
Non-Cited Violation Number Nuclear Policy Nuclear Plant Super visor Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Operations Department Instructions (Conduct of Operations)
Off-Normal Operating Procedure Operating Procedure Operations Surveillance Procedure Post-Accident Containment Ventilation Post-Accident Hydrogen Monitor Plant Change/Modification Public Document Room Post Meridiem Project Manager (NRR)
Preventive Haintenance Electrical Plant Nuclear Safety Committee Power Supply Project Turkey Nuclear Plant Work Order Quality Assurance Quality Instruction Radiation Monitor Reactor Coolant System Reactor Protective System Reactor Trip Relief Valve Safety Evaluation Safety Evaluation Nuclear - Juno Safety Evaluation Mechanical
- Site Spent Fuel Pit Steam Generator Steam Generator Feed Pump Steam Jet Air Ejector Surveillance Maintenance
- Electrical Surveillance Maintenance
- I8C Short Notice Outage Senior Nuclear Plant Operator Specification System Particulate Iodine Noble Gas (Monitor)
e
VAC (DC)
WGDT WHUT WO
Seismic Review Team Structures.
Systems, and Components Temporary Procedure Technical Specification Updated Final Safety Analysis Report Unresolved Item Unresolved Safety Issue Volt Volt AC (DC)
Waste Gas Decay Tank Waste Holdup Tank Work Order