IR 05000250/1997003
| ML17354A500 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 04/23/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17354A499 | List: |
| References | |
| 50-250-97-03, 50-250-97-3, 50-251-97-03, 50-251-97-3, NUDOCS 9705080188 | |
| Download: ML17354A500 (88) | |
Text
e U.
S.
NUCLEAR REGULATORY COMMISSION REGION ll Docket Nos.:
50-250 and 50-251 License Nos.:
DPR-31 and DPR-41 Report Nos.:
50-250/97-03 and 50-251/97-03 Licensee:
Florida Power and Light Company Facility:
Turkey Point Units 3 and 4 Location:
9760 S.
W. 344 Street Florida City, FL 33035 Dates:
February 16 through March 29, 1997 Inspectors:
T.
P. Johnson, Senior Resident Inspector J.
R.
Reyes, Resident Inspector J.
W. York, Acting Resident Inspector F.
N. Wright, Regional Inspector (Sections R1.1-1.5, R5.1, R6.1)
W.
C. Bearden, Regional Inspector (Sections H1.2-1.6, H2. 1.
M2.2, H7.2)
J. J. Blake, Senior Project Manager (Sections M2.7 and H2.9)
Approved by:
C. A. Julian, Acting Chief Reactor Projects Branch
Division of Reactor Projects 9705080i88 970423 PDR ADOCK 05000250
EXECUTIVE SUMMARY TURKEY POINT UNITS 3 and
Nuclear Regulatory Commission Inspection Report Nos. 50-250.251/97-03 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 (February 16 to March 29, 1997) of resident inspection.
In addition. the report includes regional announced inspections of maintenance, health physics, inser vice inspection, and steam generator programs.
0 erations Operator response to a loss of a Unit 4 non-vital motor control center was very. good, including procedure use, command and control, and personnel performance (section 01. 1).
Poorly communicated instructions, a lack of a questioning attitude, and a weak system lineup sheet caused a Unit 3 feedwater transient and power reduction to 85K.
Operator response was excellent and timely, and prevented a unit trip (section 01.2).
Unit 3 shutdown and cooldown activities for the cycle 16 refueling outage were well performed and safely conducted (section 01.3).
Unit 3 draindown activities were generally well performed; however, a personnel error due to conflicting evolutions during post core-offload activities resulted in an unplanned reactor vessel fill (section 01.3).
The license demonstrated conservatism by not entering reactor coolant mid-loop operations.
A full core offload was conducted prior to vessel draindown for refueling work (section 01.3).
Unit 3 core alterations were professionally and efficiently performed.
Strong teamwork, good procedure use.
and effective communications were noted (section 01.4).
Unit 3 post-refueling reactor coolant system fill and vent operations were well performed (section 01.5).
The common high head safety injection system was appi opriately aligned (section'02.1).
Two non-safety related radwaste operating procedures did not comply with licensee administrative procedure and writer's guide requirements.
This was a licensee identified, non-cited violation (section 03.1).
Technical Specification Action Statements were appropriately
'ollowed for activities which affected the operating unit (Unit 4)
I
during refueling unit (Unit 3) evolutions and maintenance activities (section 04.1).
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Non-licensed operator rounds were generally good; however, one instance of poor follow-through and a lack of a questioning attitude by both non-licensed operators and the control room operators was noted.
This resulted in an unplanned Technical Specification entry to the post-accident hydrogen monitor (section 04.2).
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Poor oversight of a non-licensed operator trainee resulted in an inadvertent trip of an auxiliary feedwater trip and throttle valve.
Licensee actions to immediately reset the valve and corrective actions were appropriate (section 05. 1).
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Licensee reactivity management oversight and controls were very good (section 06. 1).
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Generally strong oversight and effective risk management were noted during the Unit 3 refueling outage (section 07. 1).
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A weakness was identified because operations personnel missed several opportunities to identify corroding piping during monthly survei llances on penetration alignment verification for containment integrity,(section H2.3).
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Operator response to a fire and an Unusual Event was noteworthy (section P1.1).
Maintenance Poor work controls associated with a temporary trailer and power and breaker coordination issues caused a power loss to a Unit 4 non-vital motor control center (section 01.1).
Continuing Unit 3 rod control problems resulted in an urgent fai lure alarm, a manual trip to complete the shutdown, and a
licensee event report (section 01.3).
Corrective and preventive maintenance, and testing activities associated with the 3A emergency diesel generator; Unit 3, 4160 volt load center preventive maintenance and testing; and disassembly and inspection of the Unit 3 main steam line B check valve were performed in a good manner (sections M1.2, H1.3, H1.4.
and M1.6).
Leak rate testing of containment penetr ations was performed in a good manner.
As-found leakage values, which did not satisfy established acceptance criteria, were appropriately documented in condition reports and repaired (section Hl.5).
Personnel safety issues were appropriately addressed by the licensee (section H1.7).
Basket strainer cleaning was well performed (section Hl.8).
Unit 3 power operated relief valve testing was appropriately conducted (section M1.9).
Unit 3 turbine-generator overhaul, inspections, and modification activities were appropriately performed (section Hl.10).
Unit 3 reactor pressure vessel work (disassembly and reassembly)
was well performed (section Hl.ll).
Fire protection themolag work was observed and work control was appropriate (section H1.12).
Reactor coolant pump and motor maintenance was appropriately performed (section M1.13).,
Corrective maintenance associated with a fire damaged control rod drive mechanism motor generator was conducted in a good manner, with frequent quality assurance overview (section M2. 1).
Maintenance activities associated with a main steam safety valve which had failed to lift at the expected pressure during testing were conducted in a good manner (section H2.2).
Hotor-operated valve testing and ownership were very good (section H2.4).
Steam generator inspection and cleaning activities were well managed (section H2.5).
The 4A safety injection pump casing leak tempo ary repai r failed and permanent repairs were required (section H2
~ 8).
Welder qualifications for the outage were properly conducted and the personnel conducting these tests were experienced and capable (section M5.1).
Safety-related piping not being stored to regulatory requirements (ANSI 45.2.2)
was a non-cited violation (section M7.1).
Maintenance self-assessment in the area of work coordination provided meaningful feedback to management for performance improvement (section M7.2).
The licensee's ISI activities wer e well documented, and appeared to be representative of good. close coordination between corporate. site.
and contractor activities.
Containment
surveillance procedures had documented acknowledgement of recent changes to NRC regulations (section M2.7).
~
An exception to good coordination was noted regarding the late recognition that permission to use ASNE Code Case N-533 had not been requested due to mis-communication between licensee organizations (section N2.7).
En ineerin Engineering involvement and support of corrective maintenance and preventative maintenance activities associated with the 3A Emergency Diesel Generator, and the main steam line B check valve disassembly and inspection were very good (sections M1.2. N1.3, and M1.6).
Engineering support for maintenance was good as evidenced by resolution of a Unit 4 flange leak in the boric acid system (section E2.1).
Observed Unit 3 modifications associated with the boron injection tank removal, core reload.
intake and turbine plant cooling water, and turbine generator were well performed and appropriately documented (sections E2.2-2.4).
The licensee's program and controls for the intake structure's periodic inspections and maintenance were appropriate, and indicated good engineering involvement (section E2.5).
The licensee's response to Generic Letter 96-01 regarding safety related testing was reviewed (section E3. 1).
Licensee event reports and monthly operating reports were timely and well written (section E3.2).
The licensee has an effective flow-accelerated testing program (section N2.6).
Excellent engineering support for maintenance was observed for repai r on the high head safety injection pump 4A (section N2.8).
Plant~st Use of remote monitoring technology to save collective radiation dose was 'a strength (secti on Rl. 1).
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The licensee's program for inspection of Steam Generators appeared to be well managed.
The documentation of inspection results was more conservative during the current outage than it had been in the past (section M2.9).
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.
Adequate radiation protection control measures were in place in the Unit 3 containment.
However, one non-cited violations were identified:
failure to perform meter response checks.
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Radiation areas were properly posted.
No radioactive material was found outside the controlled area (section R1.2).
The ALARA program was a strength (section R1.3).
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Vehicle surveys were thorough and dose rates acceptable (section R1.4).
High radiation areas resulting from spent fuel transfer was appropriately identified (section Rl.5).
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The new Radiation Protection Manager met regulatory training and qualification requirements (section R5. 1).
A new radiation protection organization was acceptable (section R6.1).
Periodic Unit 3 containment tours and a review of radiation controls during the outage determined that very good health physics controls were in place (section R1.6).
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Licensee response including fire brigade, emergency preparedness, and station support to an Unusual Event due to a fire was noteworthy (section P1.1).
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An Emergency Plan and a fire drill were well conducted (sections P4.1 and F5.1).
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The lice~see appropriately responded to and reported an illegal drug found in the protected area (section Sl.l).
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Failure to have several personnel included in the random drug and al.cohol testing program was a licensee-identified.
non-cited
. violation (section S8. 1).
TABLE OF CONTENTS Summary of Plant Status...
I.
Operations II.
Maintenance
III.
Engineering
...30 IV.
Plant Support
.33 V.
Management-Meetings
Partial List of Persons Contacted..
List of Items Opened.
Closed and Discussed Items
List of Inspection Procedures Used.
..46 List of Acronyms,and Abbreviations
.47
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 January 16, 1997.
The unit shutdown for the Cycle 16 refueling outage on March 3, 1997.
At the end of the inspection period, the unit was in Node 5 (cold shutdown)
making preparations for its return to service.
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 operated at full power during the entire inspection period.
0 erations Conduct of Operations Unit 4 Loss of Non-Vital Bus 71707 and 93702 At 3:05 p.m.
on February 26, 1997, Unit 4 was operating at full power when a loss of the 4A non-vital motor control center (MCC) occurred.
Operators received several annunciator alarms, and confi rmed that the feeder breaker from the load center to the NCC had tripped.
Non-safety related equipment lost included transformer normal cooling. gland steam (GS) exhauster fan, steam generator (SG) blow-down, steam generator feed
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~
~
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ump (SGFP)
room fans, secondary sampling, lighting in the turbine ui lding, heating venti 1,ation and air conditioning (HVAC) equipment, and turbine-generator (TG) auxiliary equipment.
Alarm response procedures (ARPs) were followed, and redundant equipment was verified operating or was manually started.
In the cases where redundant equipment was not available by design or was out-of-service (OOS) (e.g.
GS fan), operators monitored system parameters in the control room and in the field.
Operators determi.ned that an exposed temporary welding outlet cable had been wetted during some Unit 3 pre-outage work.
This shorted the power supply panel from the 4A NCC, causing an overcurrent trip of the supply breaker.
Operators de-energized the temporary outlet.
opened all MCC feeder breakers, re-energized the NCC, and reclosed MCC loads one-at-a-time.
All loads were restored by 4:20 p.m.
Condition Report (CR) No.97-255 was also written.
The. licensee also determined that a lack of coordination between the MCC in-coming breaker and the power panel supply breaker was also a causal factor.
Corrective actions to address this issue are pending.
The inspector heard the public address (PA) announcement and responded to the control room.
The inspector verified that operators were responding per the ARPs, and using controlled load list documents.
The
inspector independently checked alarm and control room indications, and toured the Unit 4 turbine building area.
Local HCC breaker operations were witnessed.
The inspector examined the wetted temporary cable.
Apparently, the cable had supplied a trailer that was recently moved by the maintenance projects group.
The inspector also reviewed logs, the CR, and discussed the event with operators and management.
The inspector concluded that poor work controls associated with a trailer movement operation and with temporary power control for pre-outage work resulted in the loss of the 4A HCC.
Operator response including procedure use, command and control, field activities and control room monitoring, was very good.
CR corrective actions were reviewed and determined to be appropriate.
Unit 3 Feedwater Transient and Load Reduction 71707 and 93702 At 5:51 a.m.
on February 27, 1997, Unit 3 operators received steam generator (SG) steam-feed flow mismatch alarms while at full power.
Operators responded by taking manual control of two feedwater regulating valves, and reduced unit load to 85K power.
This was done as a
recaution due to observed low SGFP suction pressure, a loss of both eater drain pumps, and an automatic,feedwater heater bypass (e.g.
control valve CV-2011 opened on low SGFP pressure).
An Event Response Team (ERT) was established and CR No.97-259 was written.
The licensee concluded that operator alignment activities associated with the Unit 3 condensate polishing system resulted in partial closing of the system bypass pressure control valve (PCV-6325B),
causing a momentary (e.g.,
few seconds)
interruption of condensate and feedwater flow.
At Turkey Point, the full flow condensate polishing system is only used during long outage periods.
Normally at power, the system is OOS and bypassed with PCV-6325B opened.
The operator performing the post-maintenance lineup check repositioned the control switch for PCV-6325B as directed from open to auto per the OP lineup sheet.
The lineup sheet assumed the system to be in operation.
When the operator noted the valve had begun to stroke closed as designed, the switch was returned to open.
The ERT concluded that causal factors included poor instructions to the operator from the control room, a system lineup sheet that only included normal (e.g.,
operating) condition of the condensate polishing system, and a lack of a questioning attitude by.the operator and the control room.
On the positive side, the ERT concluded that the operator's quick action to re-open PCV-6325B probably prevented a unit trip from loss of feedwater.
Further, the ERT noted excellent response by the control room to prevent significant SG level transients and a possible loss of SGFPs.
The inspector reviewed the event.
including logs, the CR.
and the ERT report.
The inspector also discussed the event'with on-shift operators and with plant and operations management personnel.
The inspector verified corrective actions.
The inspector noted this transient to be a
"near miss" caused by poorly communicated instructions, a lack of a
questioning attitude by non-licensed operator, and a poor system lineup sheet.
On the other hand, quick response by the non-licensed operator using Stop-Think-Act-Review (STAR) to re-open the valve, and timely and skilled control room operator response prevented a plant trip.
Unit 3 Shutdown and Cooldown and Reactor Vessel Oraindown Ins ection Sco e
60710 and 71707 The inspectors reviewed and observed portions of the licensee's shutdown and cooldown activities associated with the Unit 3 Cycle 16 refueling outage..
In addition, the inspector s reviewed reactor vessel draindown activities.
Observations and Findin s The licensee commenced power reduction for the Unit 3 Cycle 16 refueling outage on February 28, 1997, to 60K power,.
Subsequently on March 3, 1997, at 12:01 a.m., the generator output breakers were opened.
Operators shut down the reactor, entering Node 3 at 12:41 a.m.
Subsequent testing and cooldown activities were performed and the unit entered Mode 4 at 4:13 p.m.
on March 3.
1997, and Node 5 at 9:10 p.m.
on March 3, 1997.
The unit entered Mode 6 at 10:34 p.m.
on March 6, 1997, when the licensee commenced reactor vessel head stud detensioning..
The inspectors observed portions of the shutdown, cooldown, and related testing activities.
The inspectors verified that these evolutions were performed in accordance with approved procedures, that appropriate oversight was present.
an'd that Technical Specification requirements were followed.
Overall, observed activities were well performed and safely conducted with strong oversight.
The shutdown was performed in accordance with procedure 3-GOP-103, Power Operations to Hot Standby.
During the reactor shutdown (power in the source range), at 12: 12 a.m..
on March 3, 1997, a control rod urgent failure alarm occurred.
The alarm was reset once.
Operators then performed a manual reactor trip from the control room to complete the shutdown.
Control banks A and'
and shutdown banks A and B were fully withdrawn.
Control bank C was partially withdrawn and control bank D was fully inserted prior to the trip.
All rods successfully inserted into the core following the trip as verified through the analog rod position indicating system.
Operators entered emergency operating procedures (EOPs)
as required, and then transitioned to the GOP.
An NRC Emergency Notification System (ENS) call was made at 1:24 a.m.
A CR (No.97-275)
and LER 97-02 were subsequently issued.
The licensee concluded that a phase sensing transformer in the
BD power cabinet failed.
The transformer was replaced.
The inspector noted that the operator performance during the shutdown was deliberate and professional.
Training performed prior to shutdown activities was very good.
Further, the NPS conducted briefings per procedure O-ADH-217, Conduct of Infrequently Performed Tests or
Evolution, prior to initiation of the shutdown.
Performance during the rod problem was per procedures and was conservative.
In order to accommodate reactor pressure vessel (RPV) head detensioning, the reactor coolant system (RCS) was drained to a level of'.5 feet below the RPV flange, Reduced inventory or midloop operation condition exists at 3.0 feet or more.
Therefore, the licensee did not technically go into midloop conditions until after the complete core offload.
However, the inspectors reviewed the following documents:
Generic Letter (GL) No. 88-17, Loss of'ecay Heat Removal, and the
'licensee's responses to this generic letter; Operating procedures 3-0P-041.7, Draining the Reactor Coolant System; 3-0P-041.9, Reduced Inventory Operations; and 3-0P-201, Filling/Draining the Refueling Cavity and the Spent Fuel Pit (SFP)
Transfer Canal; Offnormal operating procedure 3-0NOP-052, Loss of Residual Heat Removal (RHR):
Operations surveillance procedures 3-0SP-051.14.
Reduced Inventory Containment Penetration Alignment Verification; and 3-0SP-201.1, RCO Daily Logs; Various plant drawings; Training lesson plans and system description No.
007, Reactor Coolant System; Control room log books:
and Refueling outage schedules.
Prior to the draindown evolution, the licensee conducted special briefings as required by procedure O-ADA-217, Conduct of Infrequently Performed Tests or Evolutions.
Level was maintained at approximately 49K on'the remote reactor draindown level indicators LI-6421 and LI-6423.
This corresponded to 1.5 feet below the RPV flange.
The inspectors verified that redundant RCS level indications were available and were being monitored by control room operators.
Level devices LI-6421 and LI-6423 provided remote readout in the control room, and a tygon level tube (level device LI-6422) provided local indication in the containment.
The inspectors verified that these devices were available, being used, and recorded accor'dingly and that they indicated within their allowable tolerances..
However, during one containment tour on. Harch 6, 1997, the inspector noted that the drain down devices had a
small leak and the devices were not protected from possible detrimental outage work.
These issues were discussed with operations management, and corrective actions were.taken immediatel.4
,During the post-core offload drain down on March 12, 1997, an event occurred where approximately 10.000 gallons of refueling water storage tank (RWST) water gravity drained into the RCS.
The licensee was performing RCS clearance zone No. 41-01.
A conflict with procedure 3-OP-201, RCS Draindown, allowed a
common valve to be opened (e.g.
valve number 3-887).
This provided a
common flowpath from the RWST through the RHR lines to the RCS via motor operated valve MOV-3-872.
Operators immediately recognized the error and closed MOV-3-872.
Water level increased from 20K to 45K on the draindown indicator.
No water was spilled.
The licensee initiated CR No.97-415 and concluded the cause to be a personnel error when two supervisors e. g., senior reactor operators (SRO) di rected conflicting activities. without the oversight of the on-shift ANPS.
Also.
a lack of a questioning attitude was a
causal factor.
Corrective actions included personnel counselling, nite order entries, shift briefings, and procedure changes.
The inspectors noted that the licensee was proactive in reducing risk and demonstrated conservatism in its decision to complete core offload prior to entering reduced'inventory and midloop operations for RCP and steam generator work.
Further, licensee actions to drain the RCS (with fuel loaded)
were effectively conducted with good procedural compliance and with strong oversight.
Conclusions The inspectors concluded that the licensee demonstrated very good performance during Unit 3 shutdown, cooldown.
and pre-refueling draindown activities.
Actions taken were in accordance with procedures and demonstrated conservative operations.
However, a personnel error due to conflicting evolutions and a lack of a questioning attitude during the post-refueling (e.g.,
core offloaded) draindown caused an unplanned RCS fill.
LER 97-02 was adequate and was closed.
Unit 3 Core Offload and Reload Ins ection Sco e
71707 and 60710 The inspectors reviewed core alterations during the Unit 3 outage.
This included core offload and reload activities.
Observations and Findin s The Unit 3 reactor core was completely offloaded into the SFP during the period March 10-12, 1997.
The licensee implemented procedure 3-OP-040.2, Refueling Core Shuffle.
Procedures 3-OP-038. 1 Preparations for Refueling Activities. and 3-0P-038.9, Refueling Activities Check Off List, were used to ensure that prerequisites, precautions, limitations, and guidance were appropriate for core alteration activities.
During the period March 21-23, 1997, the licensee reloaded the reactor core for Cycle 16.
This was done per the Unit 3 Cycle 16 core reload procedures.
During the reload, a few assemblies were discovered to be
p
moderately bowed'.
Thi.s required extra time and a number of fuel assembly move deviations.
The inspectors verified that these 'deviations were performed per procedure 3-0P-040.2, Attachment 2.
The inspectors reviewed the above mentioned procedures, refueling Technical Specification.
operating procedures for each refueling station, the Updated Final Safety Analysis Report (UFSAR) section 9.5, condition reports associated with equipment problems, and operating and reactor engineering logs.
(See section Rl.5 regarding radiation levels from the SFP transfer canal.)
The inspectors witnessed portions of the Unit 3 refueling activities from the following locations:
Reactor Control Operator (RCO) station in the control room; Reactor engineer station in the control room; RCO, SRO, vendor stations on the manipulator bridge; Containment upender and transfer cart station; SFP upender and transfer cart station.
and RCO and SRO station on the SFP bridge.
01.5
02.1 Conclusions For those evolutions that were directly observed, the inspectors noted that communications were formal, teamwork was effective.
and procedure usage and compliance was strong.
Overall, observed core alteration activities were professionally and efficiently performed.
Unit 3 Reactor Coolant S stem RCS Fill and Vent 60710 The inspectors reviewed the post-refueling RCS fill and vent evolutions.
This included RCS fill, RCP runs, pressurizer bubble evolutions, and OP implementation.
These activities were well performed, with strong oversight.
Operational Status of Facilities and Equipment Hi h Head Safet In ection HHSI S stem Walkdown 71707 The inspector performed a walkdown of the Unit 3 and Unit 4 HHSI systems.
At the time, Unit 4 was at power and Unit 3 was preparing f'r restart from the Cycle 16 refueling outage.
The walkdown included Unit 3 post-maintenance and post-modification activities (sections Nl.l and E2.3).
The inspector reviewed piping drawings, system lineup sheets and related procedures.
The inspector independently walked down the system in field
and in the control room.
Further, the inspector walked portions of the system down with the system engineer.
The.inspector concluded that the common HHSI system was appropriately aligned.
The system engineer was noted as being knowledgeable and as having a strong sense of ownership.
Operations Procedures and Documentation 03. 1 0 eratin Procedures OP a.
Ins ection Sco e
71707 The inspector reviewed the licensee's program for operating procedures.
This included the writing of procedures per administrative procedure (ADM) O-ADM-101, Procedure Writer's Guide; procedure preparation and use per O-ADH-100, Preparation, Revision, Review, Approved and Use of Procedure; and.
procedure use per O-ADM-201, Operations Procedure Use.
Observations and Findin s The following areas were reviewed:
Operations organization to support procedures, Procedure identification, Format and style, Procedure writing and approval.
Basis documents.
Signoffs and verifications, Procedure adherence, On-the-spot-changes (OTSC),
Periodic review of procedures, New procedure verification and validation, and Procedure control and distribution.
The inspector reviewed two licensee CRs (Nos.
97-44 and 45) which were generated in January 1997.
The CRs concluded that the two following procedures did not comply with the ADM writers guide (e.g.
procedure 0-ADM-101) requirements:
O-OP-061.12, Waste Disposal System
- Waste Monitor Tanks and Demineralizer Operation
O-OP-061.13, Waste Disposal System
- Transferring Water to the Portable Demineralizer Skid For Processing.
Specifically. the OPs used procedure notes and cautions as action steps.
Section 5.5. 12 of procedure 0-ADM-101 specifically states that notes and cautions are advisory or administrative information regarding potential hazards.
The CR followup also identified additional deficiencies in these two procedures.
The licensee further concluded that these deficiencies were not causal. factors in the two radwaste building spills that occurred in 1996 (reference NRC Inspection Report Nos.
50-250,251/96-02 and 13).
Licensee corrective actions included the following:
Issued training brief No.
667 delineating writers guide requirements, Committed to revising the above two OPs by August 1997,
\\
- Will review other OPs for consistency with writer's guide requirements during routine or periodic OP revision, and CR completion Conclusion The inspector concluded that procedures O-OP-061.12 and 13 did not comply with licensee ADN requirements.
These procedures are non-safety related, but required by regulations.
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 97-03-01.
Failure to Follow Administrative Procedures For Writing Operating Procedures, was closed.
Operator Knowledge and Performance 04. 1 Technical S ecification Action Statement TSAS Com liance 71707 During the inspection period, scheduled outage work on Unit 3 resulted in TSAS entry on the operating Unit 4.
For example, the following shared equipment resulted in Unit 4 TSAS entry:
E ui ment/S stem Auxiliary Feedwater (AFW)
Emergency Diesel (EDG)
Electrical (AC/DC)
Post-Accident Vent (PACV)
Control Room Vent High Head Safety Injection (HHSI)
Standby Steam Generator Feed Pump (S/B SGFP)
TSAS 3.7.1.2 3.8.1 3.8.1/3.8.2/3.8.3 3.6.6 3.7.5 3.5.2 3.7..2
05.1 The inspector verified that the appropriate TSAS was entered for the operating unit, that operator s were knowledgeable of TS requirements.
that the time was minimized as far as possible, and that the risk was assessed in accordance with ADM requirements.
Further, TS section 3.9 for refueling was also reviewed during core alterations for Unit 3 (see section 01.4).
The inspector concluded that the affected TSASs were adhered to, and that the licensee paid particular attention to risk for the operating unit.
Non-Licensed 0 erator Rounds 71707 During the inspection period, the inspectors observed non-licensed operator performance. during periodic rounds and logkeeping activities.
Turbine building, auxiliary building, and outside area rounds were observed.
This included the Senior, Assistant.
and Nuclear Plant Operators (SNPO, ANPO.
and NPO) positions.
Overall performance was noted as being very good.
The inspector also reviewed an instance during the inspection period where poor non-licensed operator attention to logkeeping was noted.
During an administrative review of SNPO logs on March 25.
1997, the 4B post-accident hydrogen monitor (PAHM) reagent (oxygen)
gas bottle pressure was noted as being low.
The requirement was for greater than 200 psig of oxygen gas.
The licensee immediately entered the 30 action statement per TS 3.6.5 effective March 24, 1997.
This was the last time the gas pressure reading was acceptable.
The oxygen bottle was re-filled, a small leak was repaired, and the 4B PAHM system was returned to service.
The licensee's investigation noted that the log reading did not note this to be a
TS reading.
Further, a poor questioning attitude by both the SNPO and the control room operator was noted.
Corrective actions (CR No.97-584) were reviewed and noted to be adequate.
No TSAS violations occurred as the 4A PAHM remained operable.
The inspector concluded that non-licensed operator rounds were gener ally good.
Further, the licensee appropriately responded to the above mentioned poor attention to logkeeping requirements.
Operator Training and Qualification Auxiliar Feedwater AFW Tri and Throttle Valve Closure b
Trainee 71707 On March 13, 1997. at about 12:15 a.m.,
during a routine tour by a trainee with a field operator (NPO), the trainee inadvertently bumped
.the A AFW trip and throttle valve linkage causing its closure.
Scaffolding in the vicinity of'he AFW system was determined to be a
contributing cause.
This action placed Unit 4 in an unplanned 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> TSAS per TS 3.7.1.2 with AFW train 1 OOS.
This was recognized by an NPS field tour and by the unit RCO dur ing control board walkdowns.
The
06.1
valve was immediately reset.
and the TSAS for the A AFW pump was exited within several minutes at 1:00 a.m.
During this time, the B AFW pump was also technically OOS for planned maintenance.
The redundant train 2 AFW pump (e.g.,
Thus, Unit 4 had a single AFW pump and train available.
The B AFW was available and tested after the planned maintenance; however, the B AFW was awaiting procedure signoffs.
The 8 AFW was declared operable and the entire AFW related TSAS exited at 1:05 a.m.
The licensee initiated CR No.97-419, and concluded that poor NPO oversight of the trainee.
and inattention to detail by the trainee were the causes.
Corrective actions included:
CR followup, shift briefings, trainee and NPO counselling, training program reviews, and nite order entries.
The inspector concluded that the licensee appropriately handled this occurrence.
No TS violation occurred.
Operations Organization and Administration Reactivit Mana ement Controls Ins ection Sco e
71707 The inspector reviewed the licensee's reactivity controls for the Unit 3 shutdown for refueling (February 28 to March 3, 1997),
and overall site reactivity management as documented in two CRs.
b.
Observations and Findin s In order to control reactivity associated with di lutions and borations, and control rods, reactor engineering prepared a plan for the Unit 3 power descent for refueling (section 01.3).
Guidance was developed for slow and deliberate power decreases, and accompanied boron changes and control rod movements.
This assured adequate control of axial flux difference and xenon. peaking.
The information was promulgated to operations through two memos.
The memos did not modify nor supersede the normal shutdown procedures.
In addition, two CRs (Nos.
97-80 and 179) were recently written and answered, which addressed reactivity management issues.
The first CR (No. 97-80)
responded to an operations question concerning the CVCS OP.
In particular, whether or not chemical additions in field (that could affect reactivity) need be supervised by.licensed operators.
The licensee concluded that the evolution was satisfactory since it was per an OP and done with control room knowledge.
The second CR (No.97-179)
addressed operating e'xperience issues and recent industry events.
A number of issues and questions were addressed.
The licensee concluded that their reactivity program was sound, and some enhancements were appropriat ~
c.
07.1
Conclusions The inspector reviewed the shutdown plans and actual implementation, and the CR responses.
Licensee personnel demonstrated a good questioning attitude.
proactive reactivity, management control, and an overall very good program.
Quality Assurance in Operations Unit 3 Refuelin Outa e Oversi ht and Risk a.
Ins ection Sco e
60710 and 40500 The inspectors reviewed the licensee controls and oversight in effect during the Unit 3 refueling outage.
This included the implementation of administrative procedure 0-ADM-051. Outage Risk Assessment and Control.
Observations and findin s
'I The ADM required a risk assessment team to review the refueling schedule, switchyard work, higher risk evolutions, and key safe-shutdown functions and to maintain a risk information notebook.
The team was comprised of engineering, outage, operations, and maintenance personnel.
Minimum required equipment was addressed in the ADM enclosures.
The inspectors verified that important equipment was maintained operable or available as necessary.
Deviations from the ADM requi rements were accomplished by the use of an approved Temporary Change Notice (TCN).
The enclosures were broken into two parts:
large decay heat load (<10 days from shutdown)
and reduced decay heat load (>10 days from shut-down).
The inspectors reviewed the safety equipment necessary to support decay heat removal from Mode 3 to Mode 6 with the vessel and cavity flooded.
In Mode 3, all safety equipment were required to be operable by both technical specification and ADM requirements.
In Mode 4. the licensee maintained all safety equipment operable above any requi rements.
Although not required by the Technical Specifications, the licensee maintained ECCS available for Modes 4. 5, and 6.
For example, the cold leg accumulators, HHSI. and the charging system were available for injection, makeup, and RCS feed/bleed operations.
However, difference
,this outage was that HHSI was temporarily isolated for about two shifts (in Mode 5) in order to accommodate a flange installation to support a
modification to the BIT (see section E2.3).
This was accomplished by use of a TCN approved by both the risk team and management.
Once the cavity was flooded to support core offload. the 3A train equipment was removed from service as allowed by Technical Specifications.
This 3A train outage included the 3A EDG, the 3A 4KV buses, and the 3A RHR and support systems.
Since this occurred in the first 10 days, another TCN was written and approved by both the risk team and managemen The inspectors verified that the outage plan was implemented as scheduled and that Technical Specification and ADM requirements were met.
The inspectors noted conservatism relative to equipment made available to remove decay heat as the licensee transitioned from hot standby (Mode 3) to refueling (Mode 6).
Further, the licensee maintained RPV level above RCS reduced inventory and RCS midloop level.
The licensee continues not to go to midloop with the core loaded in the vessel.
This has been true for the past several years.
Another good ractice noted was system engineering involvement.
Periodically, and at east weekly, the system engineers walked down their systems and wrote a
report.
These reports as well as the TCNs were maintained in risk assessment notebooks located both in the control room and in the outage conference room.
The inspectors noted that the licensee assigned shift directors to cover the outage around the clock.
Senior plant personnel and department managers were assigned this shift direction function.
These shift directors provided oversight and maintained status of the refueling outage activities.
They also conducted the periodic outage status meetings.
The inspectors noted that these shift directors were involved in the field and directly involved in containment activities.
The inspectors noted that QA personnel were involved in outage activities including core offload and reload, core verification, containment tours, EDG maintenance, PC/M implementation, and control rod and integrated safeguards testing.
QA findings were discussed with the appropriate personnel and were documented in QA audit and surveillance reports.
Control room oversight was strengthened during the outages.
The operating shifts were modified from a six-shift to a four-shift rotation.
This provided extra NPSs and ANPSs on each shift to provide SRO coverage for refueling and other outage-related activities.
Further, operations management provided additional oversight for key refueling activities. e.g.,
draindown, core alteration, integrated safeguards testing, unit restart.
etc.
c.
Conclusions In conclusion, the inspectors noted generally strong oversight and effective risk management during the Unit 3 refueling outage.
One example of poor oversight was discussed in section 01.3.
II. Maintenance Conduct of Maintenance Ml. 1 General Comments a.
Ins ection Sco e
61726 62707 62700 and 62702 Maintenance and surveillance test activities were witnessed or reviewe The inspector witnessed or reviewed portions of the following mainte-nance activities in progress.
EDG overhaul and testing (sections M1.2 and 1.3)
Electrical bus work (section Hl.4)
Hain steam check valve overhaul (section H1.6)
Basket strainer cleaning (section H1.8)
PORV maintenance and testing (section M1.9)
Turbine generator overhaul (section H1. 10)
Reactor vessel assembly/disassembly (section Hl. 11)
Thermolag upgrades (secti.on M1.12)
RCP work (section H1.13)
4A HG set repair (section M2. 1)
Hain steam safety valve repai r (section M2.2)
SG inspections (sections H2.5 and H2.9)
4A HHSI pump repair (section M2.8)
The inspectors witnessed or reviewed portions of the following test activities:
Local leak rate testing (section Ml.5)
MOV testing (section M2.4)
Unit 3 BIT modification testing (section E2.3)
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 accor-dance 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 p
c.
Conclusions Observed maintenance and surveillance activities were well performed.
M1.2 Unit 3 Emer enc Diesel Generator Outa e Activities a.
Ins ection Sco e
62700 The inspectors observed selected ongoing corrective maintenance activities associated with the 3A EDG outage.
b.
Observations and Findin s The inspectors observed portions of the following ongoing corrective maintenance activities:
WO 95022087-01 was issued to replace several sections of eroded pipe in the 3A EDG Air Start System.
The inspectors observed replacement of portions of the air start piping.
WO 96029615-01 was issued to replace belts for the 3A EDG radiator cooling fans and performed troubleshooting of the high vibration on the cooling fan bearing.
The inspectors observed replacement of the fan bearing and inspected the final fan drive belt assem-bly.
WO 95027914-01 was issued to perform troubleshooting associated with an oil leak on the left side cam shaft on the 3A EDG.
The inspectors observed portions of ongoing work in progress.
The inspectors noted that the appropriate work instructions and precau-tions were followed and activities were executed in a meticulous manner.
Members of the licensee's QA organization. were frequently present in the work area and were knowledgeable of ongoing work activities.
The EDG System Engineer and an engineer from the FPL Juno Beach office were also frequently present to provide oversight and assistance for the contrac-tor personnel performing the work activities.
No pr'oblems were noted during the inspectors'bservation of the above work activities.
Conclusions The inspectors concluded that the 3A EDG corrective maintenance activi-ties were satisfactorily completed.
Engineering involvement in the ongoing work activities was very good.
In addition, appropriate work instructions and precautions were followed and activities were executed in a meticulous manne Unit 3 Emer enc Diesel Generator EDG Preventive Maintenance and
~Testin Ins ection Sco e
61726 and 62700 The inspectors observed various preventive maintenance activities associated with the 3A EDG outage.
Observations and Findin s The inspectors observed activities associated with the 3A EDG preventive maintenance as required by Technical Specification 4.8.1.1.2.
The licensee's inspection of the EDG was conducted in accordance with Procedure 3-PHH-022.3, Emergency Diesel Generator 18 Month Preventive Maintenance.
The 18 month PM inspections were accomplished and docu-mented under WO 96011365-01.
The inspections were performed by contrac-tor personnel with assistance from onsite engineering and maintenance groups with offsite support.
Ongoing activities observed by the inspectors included draining and changeout of engine lubricant, flushing and changeout of radiator coolant system, lube oil strainer inspection, engine main lube oil filter inspection, inspection of cooling system including radiator, fan drive belt tensioning, turbo oil filter replace-ment, and soakback oil strainer inspection.
The inspectors noted that licensee QA personnel were present frequently during the maintenance activities.
The EDG inspections did not reveal any notable discrepan-cies requiring further investigation.
The inspectors noted that the appropriate preventive maintenance instructions and precautions were followed.
The EDG engineer from the FPL Juno Beach office was also frequently present to provide oversight and assistance for the contrac-tor personnel performing the work activities.
No problems-were noted during the inspectors'bservation of the above activities.
Conclusions The inspectors concluded that the.3A EDG preventive maintenance and testing activities were satisfactorily completed.
QA,and engineering involvement in the ongoing testing and PMs was very good Unit 3 4160 VAC Switch ear Preventive Maintenance and Testin Ins ection Sco e
62700 The. inspectors observed various preventive maintenance activities associated with the 3A 4160 VAC switchgear outage.
Observations and Findin s The inspectors observed various ongoing preventive maintenance activities associated with the 3A 4160 VAC switchgear outage.
Activities observed included the 18 month PM for cleaning and inspection of electrical switchgear and several other selected work activities.
Additional work activities observed included:
16 WO 96020786-01 was issued to perform required preventive mainte-nance on the 3A Emergency Load Sequencer.
The inspectors observed ongoing activities in Panel 3C23A and noted that activities were conducted in accordance with Procedure.
0-PMI-024. 1, Emergency Bus Load Sequencer 18 Month Maintenance.
RWO 97-017 was issued to perform routine relay calibration using the DOBLE F2350 Test System.
The inspectors observed ongoing over-current relay calibration for relays on the 4160 VAC Intake Cooling Water Pump 3A Breaker 3M19.
The relay calibration activi-ties were performed in accordance with FP8L Protection and Control Group Procedure QTI-5-PS/PTN-2.02.
Turkey Point Plant Instruction for Testing and Independent Verification of Over-current Relays.
RWO 97-015 was issued to perform routine functional checks of trip coils.
The inspectors observed functional checks of breaker trip coils on the 4160 VAC Breakers 3M17, Bus Tie Breaker, 3M15, Breaker'o 3A RHR Pump, and 3M14, Breaker to 3C Load Center.
The breaker trip coil functional checks were performed in accordance with FP&L Protection and Control Group Procedure QTI-5-PS/PTN-2.-
04, Turkey Point Plant Instruction for Testing and Independent Verification of Circuit Breaker Trip Coils.
The inspectors noted that the appropriate work instructions and precautions were followed and activities were executed in a meticulous manner.
No problems were identified during the inspec-tors'bservation of the above work activities.
c.
Conclusions The inspectors concluded that the 3A 4160 VAC switchgear preventive maintenance and testing activities were satisfactorily completed.
Appropriate procedures and precautions were followed.
M1.5 Local Leak Rate Testin LLRT a.
Ins ection Sco e
62700 The inspectors discussed local leak rate testing of containment penetra-tions that was scheduled to be performed on Unit 3 during the outage with the Inservice Test (IST) coordinator and IST supervisor.
Addition-ally. the inspectors observed performance of leak rate testing of selected containment penetrations and reviewed licensee corrective actions associated with one condition report generated as a result of on-going testing.
Observations and Findin s The inspectors held discussions with licensee IST personnel responsible for LLRT testing activities.
The inspectors concluded that the IST coordinator and IST supervisor were knowledgeable and responsive to inspectors questions.
Additionally, the inspectors observed the
I a
e erformance of'LRT testing on Penetration 62A, Containment Pressure ine, and Penetration-65B, ILRT Test Line.
Licensee IST personnel performed the LLRT in accordance with Procedure.
3-0SP-051.5, Local Leak Rate Tests.
No problems were noted with the performance of the leak rate testing observed by the inspectors.
Additionally, the inspectors reviewed the corrective actions associated with the failed LLRT on Penetration 34, Service Air Line.
Penetration 34 had failed to meet the established LLRT acceptance criteria due to excessive leakage during leak rate testing performed on March 6, 1997.
Service Air Check Valve, 3-40-205, had as-found leakage of 155,000 cubic centimeters per minute (cc/min) which exceeded the maximum allowed leakage of 2,000 cc/min.
The licensee documented this fai lure under CR 97-0315.
The inspectors reviewed this CR and held discussions with licensee engineering personnel.
The licensee determined the most likely cause of the LLRT failure was due to internal corrosion of the carbon steel check valve.
Root. cause determination of the failure was still in progress at the end of the inspection period.
The licensee decided to schedule the valve for replacement during the outage.
The inspectors concluded that the licensee had adequately addressed the LLRT failure.
Conclusions LLRT activities observed by the inspectors were performed in an acceptable manner.
The IST coordinator and IST supervisor were knowledgeable 'and responsive to inspectors questions.
Further, the condition report system was appropriately utilized to document failures.
Hain Steam Check Valve Oisassembl and Ins ection a.
Ins ection Sco e
62700 The inspectors observed the portions of the disassembly and inspection of the Unit 3 Main Steam Line B Check Valve, 3-10-005.
Observations and Findin s The inspectors observed portions of ongoing activities associated with WO 96014568-01 which was issued to accomplish the inservice testing and SOER 86-03 inspection of Hain Steam Check Valve,'3-10-005.
These activities were performed in accordance with Procedure O-CMH-072.2, Hain Steam Non-Return Check Valve Repairs.
The site valve component engineer was closely involved in the ongoing activities.
The valve component engineer from the FPL Juno Beach office was also frequently present at the work site to provide oversight and assistance for the personnel performing the disassembly and inspection activities. 'he inspectors observed portions of the ongoing work activities including valve disassembly, removal and inspection of the check valve disk and other internals.
The inspectors noted that most valve internals including the valve disk appeared to be in very good condition.
Two minor scratches were present on the valve disk seating surface which were easily removed.
However, measurements of the rocker shaft revealed excessive
Ml.7 M1. 8
wear and the shaft required replacement.
No problems were identified during observation of the check valve disassembly and inspection activities.
Conclusions The inspectors concluded that the check valve disassembly and inspection activities were satisfactorily completed.
Site and corporate engineering involvement in the ongoing work activity was very good.
Personnel Safet 62707 The inspector reviewed personnel safety practices during the Unit 3 refueling outage.
This included several personnel injuries and associated corrective actions as documented in CR Nos.97-237 and 292.
In these incidents, contract workers were injured during turbine generator work.
One involved the crane and the other involved the high pressure turbine.
Root causes included poor tai lboard meetings, lack of oversight, poor communications, and an apparent lack of worker sensitivity towards safety.
The licensee stopped work and briefed contr actor crews, and provided increased monitoring of contractor activities.
Safety rules and practices were restressed.
Unit 4 Intake Coolin Water ICW Strainer Cleanin 62707 The inspectors observed the mechanical cleaning and inspection of ICW Basket Strainer BS-4-1403.
The journeymen were using the proper procedure, O-PMM-019.7, Intake Cooling Water Basket Strainer Cleaning and Inspection, and were signing off the individual steps.
Ouring the performance of this maintenance activity, operators monitored the ICW flow through the TPCW heat exchangers and the CCW heat exchangers.
The inspectors noted the logging of the values during the cleaning of the strainer.
The inspector concluded that the maintenance was well performed.
Ml.9 Unit 3 Power-0 crated Relief PORV and Valves Testin The licensee tested the Unit 3 PORVs per surveillance procedures.
The PORVs are two-inch, Copes-Vulvan, air -operated, plug valves with an internal cage.
The PORVs have had historical seat leakage problems.
However, none was detected prior to the outage.
The licensee also tested both Unit 3 PORV block valves (MOV-3-535 and 536).
The inspectors reviewed the procedures, PWOs and other related documentation, discussed the testing with licensee personnel, and inspected the valves in the pressurizer cubicle.
The inspectors concluded that test procedure and PWO implementation were appropriat Ml.10 Unit 3 Turbine-Generator Overhaul and Secondar Plant Modifications
~62707 The licensee performed Unit 3 turbine-generator maintenance including high pressure turbine inspections, modifications, and refurbishments, and other related preventive and corrective maintenance activities.
A number of PC/Ms (including 96-61, 96-53 and 95-77) were also completed The inspector reviewed work and selected PC/M packages.
UFSAR Chapter 10, and observed maintenance and modifications in the field.
The inspectors noted excellent supervisory oversight, and positive control of'he turbine heavy load lifting. and rigging activities.
Ml. 11 Unit 3 Reactor Vessel Work 62707 During the Unit'
refueling outage.
the inspectors observed portions of the reactor vessel work including:
reactor head interferences removal and replacement, reactor head detensioning and tensioning, upper internals lifts, cavity seal ring installation and removal, and other related activities.
The inspectors verified that maintenance procedures were being used, that an appropriate level of supervision was present, that operations personnel were cognizant of and appropriately approved those required activities, and that activities were safety conducted.
The inspector reviewed CR No. 97-0362 which addressed an issue with the Unit 3 upper internals connecting pin and lifting tool engagement.
Difficultywas experienced in installing one of'hree lifting screws due to damaged or worn threads.
A special engagement tool and appropriate procedure were developed and used.
Maintenance procedures were revised and Unit 4 applicability will be reviewed for the Fall 1997 outage.
The inspectors concluded that for these observed activities, the licensee was conducting safe and efficient evolutions.
Overall, licensee performance was very good for these vessel related maintenance and testing activities.
CR No. 97-0362 response was appropriate.
Ml.12 Unit 3 Fire Protection Modifications PC/Ms 96-14 and 84 62707 The licensee upgraded thermolag during the Unit 3 refueling outage as follows:
.PC/M 96-14, Thermolag Upgrades in the Unit 3 West Electrical Penetration Room PC/M 96-84, Radiant Energy Shields in Containment The inspector reviewed each PC/M package and observed work in the field.
Work control was appropriat r
H1.13 Reactor Coolant Pum RCP Maintenance 62707 The licensee performed planned maintenance on the 3A 'and 3C RCPs during the outage.
Work scope included pump seal overhauls, motor inspections, and other routine preventive maintenance.
The periodic flywheel inspection as required by TS 4.4. 10 was deferred by NRC letter dated February 11, 1997, approved TS Amendments Nos.
193 and 187.
The inspector observed portions of the RCP maintenance, reviewed procedures and work packages.
and discussed the work with licensee personnel.
The inspector also veri tied that the TS Amendment was appropriately implemented.
The licensee noted that the 3A RCP Number
Seal Runner was out-of-tolerance and required machining.
This may explain the historical low seal leak off flow that was discussed in previous NRC Inspection Reports.
During the 3B RCP pre-start checkout, the motor failed the break-away torque test.
The licensee uncoupled the pump and determined that two internal oil lift lines were severed.
Repairs were effected and the RCP was reassembled.
Subsequent operation was satisfactory.
The inspector concluded that the RCP work was appropriately pertormed.
H2
~
MZ.i Maintenance and Material-Condition of'acilities and Equipment Re airs Followin 4A Control Rod Drive Mechanism Motor Generator CROM
~MG Fi re Ins ection Sco e
62700 The inspectors observed licensee activities associated with repairs following the fire that occurred on March 4, 1997.
The fire had occurred in the 4A CROM HG and resulted in damage to the inboard generator bearing and generator rotor shaft.
Observation and Findin s The inspectors observed portions of the disassembly and reassembly of the 4A CRDH MG along with cleanup activities associated with fire and removal ot fire suppression chemical from various areas in the Cable Spreading Room.
WO 97005677-01 was issued to perform repairs associated with the fire.
The MG disassembly and reassembly activities were accomplished in accordance with Procedure, O-PME-028.3.
CROM HG Set Overhaul.
Work activities observed included electrical determination and retermination of motor, uncoupling and removing motor, heating and removal of HG flywheel, disassembly of'enerator and removal of rotor shaft.
The shaft and inboard MG generator bearing were replaced and the HG reassembled.
Additionally, the damaged bearing was retained for failure analysis to determine cause of the fire.
Root cause determina-tion of the Are was still in progress at the end of the inspection period.
The inspectors noted that licensee QA personnel were present
frequently during the ongoing repair activities.
No problems were noted during observation of the ongoing activities.
Conclusions OA personnel were present frequently during the ongoing repai r activities.
Additionally. the licensee's, corrective actions should be adequate to address the cause of the fire.
M2.2 Main Steam Safet Valve MSSV Activities a.
Ins ection Sco e
62700 The licensee completed set-pressure testing for six main steam safety valved (NSSVs) for Unit 3 on March 1, 1997, immediately prior to starting the refueling outage.
One valve, Hain Steam Line C Safety Valve, RV-3-1412, had failed to lift at the expected pressure during testing.
The as-found set pressure was determined to be 1168 PSIG which was 4.8X above the expected set-point of 1115 PSIG.
The acceptance criteria allows a
3X tolerance band.
Licensee employees had noted that water coming from the tailpipe drain following the lifttest included an unusual amount of corrosion products.
The inspectors reviewed the licensee corrective actions associated with this failure.
~
'bser vation and Findin s The licensee had originally scheduled four out of a total of 12 Unit 3 HSSVs for lifttesting.
As the result of this failure, the licensee immediately declared the NSSV inoperable and reactor power was reduced to less than 53K in accordance with TS 3.7.1.1.
Additionally, two more MSSVs were tested (total of six HSSYs tested)
in accordance with Procedure, 0-ADH-502. In-Service Testing Program, and ASME ON-1987. Part 1. Step 2.1.4.2.
The ASME Code and the licensee's program require that should any valve fai 1 to satisfy its acceptance criteria that two additional valves are tested for each valve failure.
None of the other five NSSVs tested failed to satisfy their acceptance criteria.
The inspectors reviewed CR 97-273 which documented the licensee's corrective actions associated with failure of HSSV RV-3-1412 to meet requi red lift pressure set-point.
The inspectors noted that licensee corrective actions included overhaul of the affected HSSV and inspection of'alve internals for any evidence that might have caused the valve to have not lifted at the expected pressure.
Corrective actions also included drainline inspections on all NSSV tailpipes to determine if excessive corrosion products might be present which might affect the normal operation of the safety valves.
Additionally, two other HSSVs, RV-3-1403 and RV-3-1407, which had been previously scheduled for overhaul due to minor leakage were also scheduled for similar inspec-tions of valve internals.
The inspectors observed the disassembly and inspection of valve inter-nals for NSSV RV-3-1412.
No problems were noted during the valve
H2.3
disassembly and inspection.
Additionally, the inspectors noted that the valve tailpipe appeared free of debris or corrosion products that could have been a possible contributing factor to this failure.
Root cause determination of the failure was still in progress at the end of the inspection period.
Conclusions The inspectors concluded that the NSSV disassembly and inspection was
. performed in an acceptable manner'.
Additionally. the 'licensee's corrective action process was appropriately used to.address this issue.
Corrosion Pi in of Penetration
B and C
Ins ection Sco e
62707 During the local leak rate testing (LLRT) of several containment penetrations for Unit 3. the inspector noted considerable corrosion (rusting)
on one of lines exiting penetrations
B and C.
A review was made of the disposition of the Condition Report (CR) No.97-408.
Observations and Findin s The.inspectors reviewed the CR on this subject.
The inspector noted that these three-'fourths inch diameter lines were used as sensing lines for monitoring containment conditions during integrated leak rate testing ( ILRT) testing.
The corrosion on these Unit 3 lines was located between the penetrations and the outside isolation valves.
The pipes were ground and an ultra-sonic test (UT) meter used to measure the wall thicknesses.
The thinnest wall measured was 0. 110 inch.
The minimum wall thickness was 0.099 inch; therefore.
no operability problem was noted.
The similar penetrations on Unit 4 did not exhibit the same problem.
A similar corrosion problem was repai red by.recoating on June 12.
1996.
A review of the work package indicated that the correct coating proce-dure (SPEC-C-004)
was used for the repair
.
The presence of considerable rusting in such a short period of time raises a question on the surface preparation for the previous recoating.
The inspectors'questioned the licensee about previous opportunities for discovering these corrosion conditions.
A monthly surveillance described in procedure 3-0SP-053.4.
Containment Integrity Penetration Alignment Verification, required operations pers'onnel to verify the valve positions by visual inspection at the valve's location.
The presence of the corrosion on the piping was easily distinguished by the inspectors in the vicinity of the valve.
Records for the last three months indicated that the surveillance had been performed:
however, no abnormalities were detected.
This lack of a questioning attitude by the non-licensed operations personnel to identify corrosion on the lines during the surveillance was identified as a weakness.
S
p J
~
c M2.4 M2.5
M2.6
Conclusions A weakness was identified because the non-licensed operations personnel missed several opportunities to identify corroding piping during monthly surveillances on penetration alignment verification for containment
'ntegrity.
Unit 3 Motor 0 crated Valve HOV Testin 61726 and 62707 The inspector reviewed the scope of MOV related activities scheduled for the Unit 3 Cycle 16 refueling outage.
The licensee performed MOV testing, differential pressure tests, MOV overhauls.
grease inspections, and preventative maintenance inspections.
The inspector received and discussed several condition reports that were generated as a result of these MOV activities, The inspector concluded that the MOV coordinator/responsible engineer was knowledgeable and maintained cognizance and ownership of the MOV related activities ongoing during this outage.
Unit 3 Steam Generator Ins ection and Cleanin Activities 62707 Ouring the current Unit 3 refueling outage, the licensee performed inspections, tube plug replacements and secondary side sludge lancing associated with all three steam generators.
This included involvement among FPL corporate. site, and contractor organizations.
In addition, a
number "alloy 600" Westinghouse mechanical tube plugs were replaced due to industry problems.
This was performed as required by an NRC commit-ment.
Steam generator inspections and associated activities were performed in accordance with approved program plans.
The chemistry department retained overall responsibility for this steam generator work.
The inspectors observed a sampling of the above mentioned activities including field work, data retrieval, and assessment.
Inspection procedures were also reviewed.
and personnel involved in the steam generator activities were interviewed.
The inspectors also reviewed UFSAR Chapter 4.2.
4B and 4C.
The inspectors concluded that the licensee's engineering and chemistry personnel were effectively involved in all phases of these activities.
Strong secondary chemistry programs and controls have resulted in minimal pluggable steam generator tubes (section M2.9).
Unit 3 Flow-Accelerated Corrosion Testin 62707 The inspectors reviewed and discussed the flow-accelerated corrosion inspection plan for the Unit 3 outage.
Highlights of the inspection plan included continued augmented safety related feedwater inspection.
inspection of 50 percent of the turbine crossunder piping, 100 percent of the moisture separator/reheaters, inspection of one steam tr ap header, and a sampling of non-isolable small bore piping.
Some of the Condition Reports concerning the inspection and replacement of some of
the piping were reviewed and were also discussed with the licensee's program manager.
Several of the inspection areas were walked down by the inspector.
No roblems were identified, and the inspectors concluded that the licensee as an effective flow-accelerated corrosion program.
Unit 3 Inservice Ins ection ISI Ins ection Sco e
IP 73753 The inspector reviewed program plans.
procedures, and documentation related to the conduct of the ISI program during the Spring 1997, Unit 3 Outage.
Observations and Findin s Pressure Boundar ISI At the time of the inspection, the ISI examinations planned for this outage had been essentially completed, therefore the inspection focussed on the ISI plan and the documentation of the results.
The inspector partially reviewed ISI-PTN-3/4-Program, Rev 1. dated August 9, 1995.
"Third Ten-Year Inservice inspection Program for Turkey Point Nuclear Power Plants U3 & U4."
The thi rd, ten-year ISI interval for Turkey Point Unit 3 started on February 22, 1994.
The second inspection period of this interval started on February 22, 1997. therefore this refueling outage was the first outage of the second inspection period.
The code of record for the third, ten-year ISI interval is the ASHE B&PV Code Section XI, 1989 edition.
The inspector reviewed the documentation for visual, surface, and volumetric examinations that were conducted during the Spring 1997 refueling outage.
Records reviewed in detail included the following:
~Com onent Examination Comment Valve, LCV-3-460 14" -RHR-2301-9 Pipe to Elbow 14" -RHR-2301-10 Elbow to Pipe 14"-RHR-2301-11 Pipe to Elbow VT-2 UT-45 UT-60. UT-70 UT-45 UT-60, UT-70 UT-45 UT-60 3/8/97 - Accumulation of boric acid at packing and bolting'NRI)
No recordable Indica-tions, Root Geometry, Limited Volume from elbow side due to configuration NRI Root Geometry NRI Root Geometry
~Com anent Examination Comment 14" -RHR-2301-18 UT-45 Valve 3-752A to Pipe UT-60, UT-70 14"-RHR-2301-24 UT-45, UT-60, Pipe to pump casing UT-70 NRI Root Geometry.
No exam from weld or from valve side Root Geometry.
No exam from pump side.
The inspector also reviewed two condition reports involving the ISI
. rogram.
Condition Report 97-0429 documented that inspection of several ocations of Class 1 Bolting during the system overpressure test would be unsafe.
The Condition Report was written to identify a communica-tion/engineering problem in that the licensee had not requested approval for the use of ASME Code Case N-533 at Turkey Point.
(Code Case N-533 allows for the inspection of pressure boundary bolting while the system is depressurized, and had been requested for and approved for use at the licensee's St Lucie plants.)
Condition Report 97-0479 documented
,unacceptable indications found during liquid penetrant examination ot an integrally welded support on RHR heat exchanger A.
Condition Report 97-0429 resolution included discussions with NRR; submittal of request for approval to use Code Case N-533; inspection of bolting in accordance with N-533:
and contingency plans in the case that the request was not granted prior to the end of the outage.
The engineering groups involved were also counseled about the need to take ownership of issues that require NRC approval.
Condition Report 97-0479 was resolved by exploring the unacceptable indication until it was determined that it was the result of a fabrication defect instead of a service induced flaw, and then applying ASME Section XI fracture mechanics resolutions to allow it to stay in service without repai r.
Containment ISI Effective September 9,
1996,
CFR. 50.55a, was amended to include the requi rements of ASME 88PV Code,Section XI, Subsections IWE and IWL 1992 Edition, with 1992 Addenda.
Subsections IWE and IWL provide ISI requirements for concrete containments
~ steel containments, and steel liners for concrete containments.
The amendment to the rule provided a
five-year period, until September 9, 2001, before full implementation of Subsections IWE and IWL.
In correspondence with'he industry, (November 6,
1996 letter to Alex Marion, Nuclear Energy Institute from Gus Lainas, Office of Nuclear Reactor Regulation, concerning
"Implementation of Containment Inspection Rule" )
NRC provided a Staff position that, in response to deficiencies noted prior to the full implementation IWE and IWL, repair'and replacement activities must be conducted in accordance with those subsection On September 3,
1996. the licensee started the 25-year inspection of the Unit 3 containment tendons as requi red by the Technical Specifications.
The inspector discussed the results of the tendon inspections with the licensee's Lead Civil Engineer, to determine if the licensee was aware of the new requirements of 10CFR50.55a for repairs and replacements.
The licensee had documented the change to 10CFR50.55a in the tendon surveillance procedure with a note to the effect that the new require-ments would be implemented during the 30-year inspection of the tendons.
The licensee also showed the inspector documentation for a tendon anchor-head shim replacement for Buttress g3, tendon 35-H-20, due to a
"cracked shim" (which turned out not to be cracked after removal and
'examination;)
as well as anchor-head shim additions for five tendons which had shown low tension during "lift-off"tests.
The application of ASME "Repair and Replacement" considerations will be addressed in the licensee's final report of the Tendon Surveillance.
Conclusions The licensee's ISI activities were well documented.
and appeared to be representative of good, close coordination between corporate, site, and contractor activities.
The only noted exception being the late recogni-tion that permission to use ASME Code Case N-533 had not been requested due to mis-communication between licensee organizations.
Containment surveillance procedures had documented acknowledgement of recent changes to NRC regulations.
Hi h Head Safet In ection HHSI Re air 62707 On March 27, 1997, Unit 4 HHSI 4A pump developed two pump casing flange leaks.
When the licensee retorqued the studs one of the leaks increased to approximately nine to ten gallons per hour.
Engineering calculated that this leak rate was in excess of conservative assumptions for emergency core cooling system (ECCS) recirculation loop leakage assumed in the UFSAR for meeting the requirements of 10 CFR Part 100.
The licensee declared the pump inoperable.
entered a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and made a one hour ENS call.
The pump was isolated and a decision was made to inject a sealant compound (Furmanite) into one of the casing stud cap nuts.
The repair took three attempts to seal the cap nuts and stop the leak.
The inspectors reviewed Condition Report No.97-613, reviewed the Furmanite procedure, and observed the work in progress.
There was excellent engineering support for maintenance on this repair.
The leak reoccurred on April 3.
1997, and the licensee made another ENS call and initiated permanent repairs.
These repairs were completed on April 5, 1997.
The LER will be reviewed in a future inspectio g
Unit 3 Steam Generator SG Ins ection Ins ection Sco e
50002 Through discussions with personnel and review of documentation, the inspector reviewed the Eddy Current (ET) inspection of the Unit 3 SGs.
Observations and Findin s The Unit 3 SGs are Westinghouse replacement Model 51F SGs which were installed in 1982.
The Model 51F SGs contain thermally treated Inconel 600 tubing which is supported by stainless steel, quatrefoil support plates.
To date, the primary reason for plugging of tubes in the Unit 3 SGs has been because of wall thinning in the area of anti-vibration bars (AVBs).
During the current inspection.
two tubes in SG 3B were preventively plugged due to a foreign object lodged against the outer diameter (OD) of the tubes.
(The foreign object had been determined to be a piece of metallic slag formed during arc-cutting of weld prep areas on the SG shell, and introduced during the replacement operations in 1982.)
The inspector reviewed a sample of the Eddy Current (ET) test data representative of SG tubes which were left in service with indications which had been diagnosed as MBM Manufacturing Buff Marks by ET,analysts.
The inspector reviewed the ET Bobbin Coil data recorded this outage, and compared it with data that was recorded during the 1994 refueling outage.
In two of the cases reviewed, the 1994 examination results had been dispositioned as No Detectable Defect, (NDD) while the 1997 data was dispositioned as having MBMs.
The inspector noted that in both cases, the MBM signals recorded in 1997 were present in the 1994 data, at the same location, and with essentially the same signal strength.
Apparently, in 1994 the ET analysts determined that these signals did not represent flaws and dispositioned the tubes as NDD.
The inspector also reviewed the test data from a tube which, during the 1997 outage, had wear signals recorded at three AVB locations: AVl-15X, AV2, - 20K, and AV3 - 13K through-wall.
The 1994 data for this tube was also reviewed, which showed that the signals at AV1 and AV3 were not present; but that the signal at AV2 was present, at essentially the same relative size, during the inspection in 1994.
Conclusions The licensee's program for inspection of SGs appeared to be well managed.
The documentation of inspection results was more conservative during the current outage than it had been in the pas J
Haintenance Staff Training and gualification Trainin and uglification of Welders Ins ection Sco e
62707 The inspectors reviewed and observed the qualification and testing of welders that were brought to the Turkey Point plant for the refueling outage on Unit 3.
Observations and Findin s The licensee had approximately 105 welders to qualify for the Unit 3 outage.
A review was made of parts of ASNE Code Section IX, and procedure O-ADN-046, Control of Welding Special Processes, to ensure that the method used for qualifying the welders met the ASHE Code.
The inspectors determined that the licensee's procedure was compatible with the Code requirements.
The inspectors observed activities in the welder qualification shop, and discussed the requirements and techniques for qualification with the welding personnel performing the work.
The inspector noted that the qualifiers required the identification of the welder, properly controlled and marked weld test coupons, and performing fit up and visual inspections of the finished weld.
The inspectors observed the actual testing on one set of weld bend specimens and the evaluation of a minor linear indication.
The previous day the welding evaluator had failed six out of 14 welder qualifications.
Some of the failed bend specimens and some that had passed were visually examined by the inspector for Code compliance.
The qualification logs and records were adequately explained by the qualification personnel.
The welding engineer performing the qualifications had experience in this area dating back to 1981 and was able to answer all of inspectors'uestions correctly.
A quality surveillance (Ouality Report No. 97-0050)
was performed by the Nuclear Assurance Group over a two day period after the inspectors evaluated the welder qualification area.
The results of this surveillance were that the welder qualification tests were being properly conducted.
In addition, the inspectors briefly observed a few of the welding repai rs and modifications made by some of these welders including weld metal control.
The inspectors reviewed two CRs (Nos.
97-0441 and 97-0488) which raised a possible problem with weld metal control.
Turkey Point personnel did not realize that a St. Lucie heat code was on the welding rod issued for several jobs.
Further investigation cleared up the confusion and the issue of the weld rod had been correctly per-formed.
The inspectors did not identify any welding problem Conclusions The inspectors concluded that the welder qualifications wer e being properly conducted and that the personnel conducting these tests were experienced and capable.
Quality Assurance in Maintenance Activities Stora e of Safet Related Pi in 62707 During a tour of an outside storage area, the inspector noted the absence of protective pipe caps on some piping in an enclosed pipe lay down area.
The inspector requested Quality Control (QC) to determine if the piping was safety related, and to determine if the storage met regulatory requirements.
The inspector reviewed CR No.97-236 that was generated by the QC inspector and then toured the storage area with the QC inspector to examine the stored piping.
Fifteen heat codes with thi rty three pieces of pipe that were safety related were identified as not being stored to the requirement of American National Standards Institute (ANSI) 45.2.2 level D storage, i.e. all openings into items shall be capped, plugged.
and sealed.
Document
CFR Part 50 Appendix 8 Criterion XIII, states in part that measures shall be established to control the handling. storage, shipping, cleaning, and preservation of material... in accordance with work and inspection instructions to prevent damage or deterioration...
Methods for implementing this requirement are in Regulatory Guide 1.38 which endorses ANSI 45.2.2.
The licensee commits to these requirements in their Topical Quality Assurance Report Appendix C.
The implementing procedure is Quality Instructions QI13-PTN-1, Handling, Storage, and Shipping of Items. This failure to proper ly store safety related piping to the requirement of ANSI 45.2.2 constitutes a violation of minor significance and is being treated as a Non-Cited Violation, consistent with Section IV of the NRC Enforcement Policy.
The CR concluded that ANSI No. 45.2.2 storage requirements were not being met.
The licensee is not storing some of thei r safety related piping to the requirements of ANSI 45.2.2.
The condition was identified as NCV 250
'51/97-03-02, Failure to Store Safety Related Piping to ANSI Standards.
The NCV was closed.
Licensee Self Assessment Ins ection Sco e
62702 The inspectors reviewed the licensee report which documented the results of a self-assessment recently performed by the Maintenance Department on January 6 - 10, 1997. This self assessment was in the area of Work Coordination.
The inspectors also held discussions with the Maintenance Manage and other licensee managemen 'L r
Observations and Findin s
III.
E2 E2.1 During the review of this assessment the inspectors noted that although no CRs were initiated by the licensee, several recommended areas for improvement were identified during the assessment.
Areas for improvement were generally associated with fai lures to satisfy management expectations, and included lack of coordination of 2 outage multi-discipline activities, ineffective utilization of maintenance resources, HP support of ongoing maintenance activities. clearance scheduling and coordination. availability of replacement parts, and pre-review of WO packages.
Maintenance management was reviewing the recommended areas for improvement for possible methods of disposition.
Conclusions The team concluded that the licensee's recent self-assessment provided significant and meaningful feedback to management.
En ineerin Engineering Support of Facilities and Equipment Unit 4 Boric Acid Leak Ins ection Sco e
37551 The licensee noted that a boric acid buildup was found on the flange of Unit 4 boric acid to blender flow transmitter (FT-4-113).
The licensee's root cause and operab'i lity determinations for this problem were examined by the inspectors.
Observations and Findin s The inspector and the system engineer observed a
QC technician performing a dye penetrant inspection of the flange and adjacent pipe.
Several linear indications were found on the flange and one on the pipe.
This test was requested because boric acid buildup was noted on the flange during an 18 month visual inspection required by a corrective action to a previous Condition Report (CR).
This leakage appears to be related to the previous discovery of stress corrosion cracking (SCC)
found on various sections of the CVCS boric acid system after removal of thermal insulation and heat tracing.
A review was made of Metallurgical Laboratory report No.95-111 which analyzed the root cause for some of the previous leakage in this system.
The inspector noted that the SCC was the reason for the cracking in the stainless steel 304 fittings and piping.
Condition Report No. 97-0213 was generated for this issue.
The inspectors reviewed the operability assessment and corrective actions.
The flange and related piping will be replaced during the next Unit 4 refueling outage (September 1997).
The flange indications will be periodically monitored by engineering, operations, and Q ~
c.
E2.2 E2.3 Conclusions Engineering support to maintenance was good in resolving the'resence of a leak on a flange in a safety related system.
The root cause analysis, the'operability assessment.
and the corrective actions were appropriate.
Turke Point Unit 3 C cle 16 Reload PC/M No.96-71 37551 The licensee initiated PC/M No. 96-71 for the Unit 3 Cycle 16 core reload.
This PC/M provided for the reload core design and included the replacement of.irradiated assemblies with new 15 x 15 optimized fuel assemblies.
The new assemblies were of the debris resistant design which included several fuel design enhancements.
These were similar to
'he recent previous reload designs.
The inspectors reviewed the documentation package for the PC/M including the design bases and analyses.
the safety evaluation, core loading plan, and other pertinent data.
The inspectors noted that appropriate reviews and approvals were performed by Engineering.
Reactor Engineering, QC, and the PNSC.
The inspectors concluded that PC/M was well documented and adequately implemented by'efueling procedures as discussed in section 01.4 of this report.
Unit 3 Boron In ection Tank BIT Modification PC/M 96-12 37551 The licensee modified the Unit 3 HHSI system piping, such that the BIT was bypassed.
During removal of the boric acid system abandoned heat tracing/insulation, multiple through wall leaks were noted (see NRC
Inspection Report
Nos. 50-250,251/95-04,
06,
and 09).
These defects
were caused
by stress
cracking corrosion
and were all repaired.
The
licensee
concluded that the BIT piping was also subject to this failure
mechanism.
Thus, the decision
was
made to bypass the BIT piping and
abandon the BIT in place.
The BIT function with highly concentrated
boric acid was
removed
from service in the 1980's.
The inspector
verified this as described in the
UFSAR section 6.2 and associated
drawings.
PC/M 96-12 removed the BIT instrumentation
and relocated
one relief
valve.
In addition. the inlet valves
(MOV-3-867A and
B) were eliminated
and replaced
by one manual
valve (3-867).
The
MOV function had been
previously removed.
The SI function remained
unchanged,
included
valves
(MOV-3-843A and B), and associated
controls, including the inter
disc equalization function.
A similar PC/M (No.95-172)
was performed
on Unit 4 during the Spring
1996 outage.
The inspector
reviewed the
PC/M package,
including the
CFR 50.59
evaluation,
and other related drawings
and documentation.
The inspector
discussed
the
PC/M with engineering,
operations,
and maintenance
personnel,
including the system engineer.
The inspector witnessed
portions of PC/M in the field, including testing.
Operator training was
addressed
through
a training bulletin.
The inspector concluded the
PC/M
was appropriately
implemente t
l
Unit 3 Intake Coolin
and Turbine Plant Coolin
Water'odifications
PC/Ms-96-49
96-94 and 96-10
37551
The licensee
abandoned
the Unit 3
ICW to TPCW heat exchangers
outlet
valve (CV-3-2201) per
PC/H 96-10.
The valve has histo'rically not
functioned well and was previously bypassed
per
a safety evaluation.
A
spool piece
was put in place of the
CV in parallel to a locked-open
manual
bypass
valve.
A similar PC/M was performed
on Unit 4 last outage
(March 1996).
In addition,
PC/M 96-49 modified the
TPCW valves CV-3-
2200 and 2203.
These are for the turbine lube oil and hydrogen
gas
coolers.
PC/M 96-94 installed flow instrumentation
on the Unit 3
ICW
The inspector verified that
UFSAR section 9.6 for the
ICW system
was
being revised to reflect these
PC/Ms.
The inspector also reviewed the
PC/M packages.
procedure
changes,
safety evaluations,
drawings, training
briefs,
and other related documentation.
The PC/M was discussed
with
engineering
and operations
personnel.
In addition, portions of the work
were observed in the field.
The inspector concluded that the
PC/Ms were appropriately
implemented.
Intake Structure
Ins ection
37551
The inspector
reviewed the licensee's
program plan for the Unit 3 and
Unit 4 intake structure inspections.
Historical degradation
'due to the
salt water corrosion
and erosion
was noted during the mid 1980's.
Since
then, the licensee
embarked
on an inspection
and repair program.
These
activities were reviewed in previous
NRC Inspection Reports.
The inspector noted that the licensee controls intake inspection/repair
activities per Speci,fication
No. CM-2.28, Nuclear Engineering
Intake
Structure Inspection
and Repair.
No inspections
or repair activities
were scheduled for the 1997 Unit 3 or Unit 4 outages.
The next
activities are scheduled for Unit 3 Cycle 17 (Fall 1998).and Unit 4
Cycle 18 (Spring 1999).
The inspector verif'ied that these future
activities were budgeted
and approved
by the
PRB,
and were on the "Top
20" modification lists.
In addition. engineering
evaluation
PTN-ENG-
SECS-96-043'.
was also reviewed.
The inspector concluded that the licensee's
program and controls for the
intake structure periodic inspections
and repairs were appropriate,
and
indicated
good engineering
involvement.
Engineering
Procedures
and Documentation
Generic Letter
Res
onse
37551
GL 96-01 required the licensee to review their testing of safety related
circuits to assure
TS compliance,
and to verify that systems
would
function when called upon.
These actions were required to be complete
for Unit 3 prior to the restart
from the Cycle 16 refueling outag e
E3.2
The licensee identified three instances
of non-compliance.
which was
reported to the
NRC in LER No. 96-04 and subsequent
supplements.
These
issues
were reviewed in previous
NRC Inspection Reports.
The licensee
completed thei r review per the GL, and documented this in safety
evaluation
No. JPN-PTN-SEIS-97-001.
The
PNSC reviewed
and approved the
safety evaluation
on March 18,
1997.
The inspector
reviewed the safety evaluation,
attended
the
PNSC meeting,
and discussed this issue with engineering
personnel.
Final
NRC review
and closeout of the
GL will be documented
in future correspondence.
Re orts
90712
90713
and 92700
The inspectors
reviewed the monthly operating reports for January
and
February
1997,
and
LER 97-021 (section 01.3).
The reports were timely
and well written.
IV. Plant
Su
ort
R1
~
Rl.l
Radiological Protection
and Chemistry
(RPEC) Controls
The purpose of this inspection effort was to evaluate radiological
protection program effectiveness
during outage conditions.
External
Ex osure Controls
Ins ection Sco
e
83750
The adequacy of radiation protection controls in containment
were
reviewed.
Observations
and Findin s
The review included performance of independent
radiation surveys,
review
of radiological boundaries
and postings,
checks
on security of high
radiation areas.
reviews of records
and procedures,
and observations
of
work activities in progress.
The inspector
observed interactions of
radiation workers
and Health Physics
(HPs) technicians
in containment
and conducted interviews with Turkey Point and contract personnel
concerning
adequacy of radiation protection controls.
The licensee did not have
a
HP control area inside the containment
building but did station
HPs in containment to monitor work and assist
radiation workers
as needed.
Personnel
entering containment
were
provided Radiation
Work Permit
(RWP) briefings and any special
dosimetry
needed in the
HP building.
HPs could control work in high radiation
areas
from the
HP building. observing activities with video monitoring
equipment,
communicating
and directing workers with radio headsets,
and
monitoring individual radiation doses with teledosimetry
on the
radiation workers'he
licensee
was making good use of radio head sets
for communications
between the roving HPs in containment
and the
HPs in
the
HP bui lding.
Use of technology in monitoring and controlling work
from low dose areas
was
a radiation protection
program strength.
The air conditioning of containment
made the envi ronment safer
as
temperatures
were comfortable.
The air conditioning helped
keep
protective clothing dry which helped
reduce contamination
leaching
problems
and lower personnel
contaminations.
In interviews with
radiation workers, the inspector inqui red about working conditions
inside containment
and the adequacy of radiation protection support.
Specifically were breaks outside containment sufficient and was
support available when needed.
Workers reported that they were able to
take breaks
when needed
and that they had not had any problems getting
HP support.
Licensee
procedures
O-HPT-013,
"Portable Survey Instruments," revision
dated
November 2,
1994, provided specifications
and operational
instructions for HP portable survey instruments.
Section 9.2,
"Heter
Checkout
and Use," stated,
in part. that the
HP technician shall
choose
an instrument that will detect the expected
type and range of radiation
and or radioactivity.
Additionally, step 9.2.4 requires the technician
ensure the instrument being used
has
been daily response
checked for
that date by checking the date
on the response
check sticker attached to
the instrument.
On Harch 25.
1997, the inspector noticed that the licensee
was using
a
portable thin window Geiger Huller
(GN) count rate contamination
monitor
on the refueling floor that had not been source
checked since Harch 5,
1997.
The instrument
had
"For Information Only" written across
the
daily response
check chart attached to the monitor
.
The background
where the instrument
was utilized was approximately 1,200 - 1,400 counts
per minute (cpm).
The inspector observed
HP technicians
using the
monitor to obtain contamination levels
on items being
removed from the
reactor
cavity.
Licensee
procedures
required
a daily source
check of
the radiation survey instruments.
The inspector
asked
why the
instruments
were not being response
checked daily and licensee
personnel
reported that they did not believe the source
check was necessary
since
the instruments
were used in high background
areas
and were not utilized
to measure
radioactive contamination for "official surveys"
or release
purposes.
The inspector
found that the licensee's
procedures
did not
address
"For Information Only" portable radiation survey instruments.
The procedures
did not address
requirements,
limitations, or the method
to distinguish
"For Information Only" instruments
from other
instrumentation.
The licensee
also did not have
any training describing
proper
and improper uses of such instrumentation.
The inspector
reported that failure to response
check the monitors in containment
daily appeared to be
a violation of licensee
procedures.
This is being
treated
as
a minor violation per Section
IV of the
NRC Enforcement
Policy.
NCV 50-250.251/97-03-03,
Failure to perform daily response
checks
on radiation monitoring equipment in accordance
with licensee
procedure
requirements
was close I
The licensee
reported that the procedures
would be modified to permit
the'use of the friskers without a daily source
check.
The inspectors
were unable to find radiation surveys
where the instrument
had been
used
to quantify radioactive contamination levels.
While response
checks
can
be used to determine efficiency of an instrument,
one of the purposes
is
to look for changes
in monitor performance
and to verify that the
detector
and ratemeter
were still operating properly.
The licensee's
persistence
to use
an instrument that was not receiving daily Quality
Control
(QC) checks,
for any monitoring purpose,
was imprudent.
Licensee
procedure
0-ADM-605. "Control of Radioactive Tools,
Equipment,
and Components,"
revision dated
December
31,
1996, required in step
5.9.1, that tools and equipment designated
for use only on the
RCA shall
be conspicuously
painted with purple paint.
While observing work in upper
containment
on March 26,
1997. the
inspectors
examined contents of'ool boxes.
The tool boxes contained
hundreds of various small tools used for refuel floor work during
outages.
The inspectors
found that most of the tools were painted
purple.
However,
a significant number (approximately
20 - 40 percent)
were not painted purple as required
by licensee
procedures.
The
inspector reported that failure to paint tools used for work in the
purple appeared to be
a violation of licensee
procedures.
Subsequently,
the licensee
presented
documents to the resident inspectors to
demonstrate
that they had already identified this matter
and that
corrective action was in process to be completed 4/15/97.
This matter
will be treated
as
an inspector followup item IFI 50/250.
251/97-03-04.
Failure to conspicuously identify tools used in RCA in accordance
with
licensee
procedure
requirements.
The inspectors identified other examples of poor attention to detail.
For example.
the licensee
had established
a radiation control boundary
around the reactor
cavity and the equipment
pool
as
a high radiation
and
hot particle area.
The licensee
had
removed that zone
and established
a
smaller one at the top of the personnel
ladder into the equipment
and
reactor cavity.
While surveying the refuel floor area,
the inspectors
found one of the signs f'r the previous
zone still hanging
on
a guard
rai'1
and another
propped
up against
a guard rail post.
The inspector
reported
th'e posting discrepancy to a
HP on the refuel floor who
promptly removed the signs.
The licensee
had established
a radioactive materials storage
area in
containment that was used to store trash until it could be removed from
containment.
The inspectors
found bags of trash bulging out of zone
with some bags outside the boundary
on the floor and hanging over the
boundary ribbon.
The materials. boundary could have
been easily extended
such that all material
was within the radioactive materials
area.
This
was pointed out to a
HP technician
and all of the material
on and
outside the boundary
was moved back into the storage
are r
Concl us ion
In general,
the inspectors
found adequate
radiation protection control
measures
in place inside Unit 3 Containment Building.
Good use of
remote monitoring technology to save collective dose
was
a program
strength.
However,
a non-cited violation was identified and other
observations
indicated poor attention to detail.
Ins ection of Plant Areas
Ins ection Sco
e
83750
The inspectors
toured plant areas for radiation protection issues
Observations
and Findin s
On tours within the
RCA, the inspectors
made independent
radiation
surveys,
examined the adequacy of the licensee's
radiation protection
boundaries
and radiological postings,
examined labeling of containers,
verified radiation monitoring equipment in use was calibrated
and
receiving periodic source
checks,
checked the security of high radiation
area doors,
observed
housekeeping,
observed radiation worker compliance
with radiation protection controls.
obser yed
HP technicians
performing
radiation surveys.
and.interviewed radiation workers.
The inspectors
made independent
radiation surveys in the
RCA including
the auxiliary building, dry storage faci lity, yard areas within the
RCA.
Radiation surveys
were also
made outside the
RCA in the turbine
building, warehouses,
yard,
and
RCA boundary.
Conclusion
Radiation
were properly posted
and secured.
Control of radioactive material in the
RCA was adequate
and no
radioactive material
was found in areas
outside the licensee's
RCA.
As Low As Reasonabl
Achievable
Ins ection Sco
e
83750
The inspectors
interviewed licensee
personnel
and reviewed records of
ALARA program results
and activities to determine whether the ALARA
program was effective in maintaining doses
ALAR ~
b.
C.
Observations
and Findin s
The 1996 site collective dose
was approximately 186.0 person-rem of 275
person-rem objective'and
was the site's
lowest operating
exposure.
The
Unit 4 Re-Fueling
Outage
(RFO) in 1996 was
35 days in length
and the
total collective dose
was approximately 158.0 person-rem.
The outage
goal
was 215 person-rem.
The licensee attributed the 1996 successes
rimarily to effective scheduling,
pre-job planning,
department
man-rem
udget program,
and increased
plant involvement and accountability.
Non-outage
dose
was approximately 27.7 person-rem.
Short notice outage
dose
was approximately 0.3 person-rem.
In 1996 the licensee cut outage
dose
by approximately
16 person-rem
and non-outage
dose
by about
person-rem
from the doses in 1995. which was also
a year with a single
.
35 day
RFO.
To increase
the plant staff's involvement in dose reduction activities,
the licensee
implemented
an ALARA dose budget process
in 1995.
The
process allotted dose to various work groups depending
upon their
assigned
responsibilities.
Managers of the various departments
of the
site organization
were expected to complete assignments
without
exceeding allotted doses.
The dose budget
was similar to their
financial budgets.
This caused
managers to plan tasks better or face
the possibility of exhausting
dose allotments
and failure to meet
assigned
goals.
One of the most important elements
in the program was
the strong
upper
management
support
and involvement in the process.
The
people responsible
for the work were caused to perform it more
efficiently and,
as
a result,
reduce
dose.
The licensee
planned to
improve the process further through additional
involvement of personnel
at lower levels within the organization.
The personnel
experienced
in
performing the various tasks in radiation areas
know how.to perform the
work more efficiently that anyone else.
The licensee
plans to have
those personnel
more involved in processes
to lower their radiation
doses.
The licensee
had two RFOs planned for 1997.
The most recent years
having two RFOs were 1991
and 1994.
The licensee
had 939 and 474
person-rem f'r those years respectively.
The 1997 goal
was 475 person-
rem with 165 person-rem allotted for each
RFO.
The licensee
had
expended,
159 person-rem of the
165 person-rem Unit 3 goal through day
40 of the planned
35 RFO.
Another licensee
goal
was
110 person-rem/unit
3 year average.
Evidence of site management
involvement with ALARA was
observed in the 1997
ALARA plan that also included individual department
ALARA plans.
Conclusion
The licensee's
ALARA activities in 1996 were very good and the licensee
continued to be successful
in reducing the site collective doses in
1997.
The inspector
found the licensee's
ALARA successes
were due to
several
factors including strong
management
support,
improved
participation of plant staff'n implementing the ALARA dose budget,
and
shorter refueling outages.
The licensee
had
a very good program for'
R1.4
establishing
and tracking performance related to ALARA goals
and
objectives.
Vehicle Surve
s
a.
Ins ection Sco
e
83750
Independent
radiation surveys of a loaded exclusive
use vehicle were
made to evaluate the licensee's ability to identify highest
dose rates
on the vehicle and to verify the dose rates
were within regulatory
limits.
Observations
and Findin s
'L
The inspectors
made independent
radiation surveys
on an exclusive use
vehicle just prior to its release
from the site.
The inspectors
found
that the radiation levels identified by the licensee's
HP technician
agreed with the inspector's
and were within regulatory limits for
transportation of radioactive materials
by an exclusive
use vehicle.
The
HP technician performing the survey was thorough
and completed the
survey in accordance with licensee
procedures.
Conclusion
The licensee radiation surveys of an exclusive use vehicle were thorough
and all dose rates
were below applicable regulatory limits.
R1.5
a.
Unit 3 Fuel Transfer
Canal
Radiation Surve
s
Ins ection Sco
e
83750
This area
was reviewed to determine whether the licensee
was properly
evaluating plant radiation levels during the transfer of spent fuel from
the reactor to the Spent
Fuel
Pool
(SFP) storage.
Observations
and Findin s
On Harch 15,
1996, during core alterations,
HP personnel
noted higher
than expected radiation levels
on the Unit 4 auxiliary building roof in
the vicinity of the SFP transfer canal
outer wall.
Dose rates
were as
high as 1.500 mrem/hr on contact with the concrete wall and
900 mrem/hr
at 12 inches.
One of the'licensee's
corrective actions in response to
the event was to monitor the Unit 3 areas that may have elevated
radiation levels during fuel movement in the next Unit 3 refueling
outage.
The program included use of portable radiation surveys
by HP technicians
during initial fuel movements
and the u'se of radiation monitoring
equipment continuously recording radiation levels throughout the fuel
transfer
process.
The licensee's
documentation
showed the highest
radiation dose rate to be approximately
600 mrem/hr at
a point in the
Cask
Washdown
Room
(CWR).
The radiation levels
on the auxiliary
h
building roof were much lower that those
seen
on Unit 4 due to extra
shielding provided by Boric Acid Storage
Tanks
(BAST).
Areas that were
posted
during the fuel movement included the
auxiliary building roof'bove the
BAST,
BAST Room,
New Fuel
Room,
CWR,
and
SFP Heat Exchanger
room.
Conclusion
The inspector
concluded that the licensee
adequately identified the
temporary high radiation areas
resulting from the transfer of spent fuel
from the Unit 3 reactor to the Unit 3 SFP.
Radiation Controls Durin
the Unit 3 Outa
e
71750
Periodically during the Unit 3 outage,
the inspectors
made containment
entries to review work in progress.
radiological conditions.
and assess
housekeeping
and general
material conditions.
The inspectors
also
reviewed the licensee's
radiological controls to minimize dose, to
prevent contamination
spread,
and to protect workers.
The inspectors
noted
good practices
including remote monitoring by the use of cameras
including closed circuit television
and dose telemetry.
Observed. jobs
included
RPV and cavity work,
SG primary work,
CVCS heat exchanger
repai r, and other containment work.
Overall dose performance will be
reviewed in a subsequent
inspection.
Staff Trainin
and
uali fications in Radiation Protection
and Chemistr
83750
Ins ection Sco
e
The qualifications of a new HP Supervisor
were reviewed against
qualification criteria in Technical Specification (TS) 6.3.1.
Observations
and Findin s
Licensee
TS 6.3. 1 required
each
member of the unit staff meet or exceed
the minimum qualifications of ANSI N18. 1-1971 for comparable positions,
except, for the Health Physics Supervisor
who shall
meet or exceed the
qualifications of Regulatory Guide (RG) 1.8,
"Personnel
Selection
and
Training," revision dated
September
1975.
Regulatory Guide 1.8. prescribed specific qualifications for Supervisor
of Radiation Protection referred to as the Radiation Protection
Manager
(RPM).
The
RG stated the
RPM should have
a bachelor's
degree
or the
equivalent in a science
or engineering subject.
including some formal
training in radiation protection.
The
RPM sh'ould also have at least
five years of professional
experience
in applied radiation protection.
At least three years of the professional
experience
should
be in applied
radiation protection work in a nuclear facility dealing with
'
R6
R6.1
radiological
problems similar to those encountered
in nuclear
power
stations preferably in an actual
nuclear
power station.
The inspector
reviewed the qualifications of the new
HP Supervisor.
Overall, the
HP Supervisor
had been
a supervisor
in some radiation
rotection capacity at Turkey Point for approximately eighteen years.
he supervisor
had also received National Registry of Radiation
Protection Technologist
(NRRPT) certification.
The
HP Supervisor
did
not have
a bachelors
degree but did possess
the equivalent in
experience.
The
NRC has considered
four years of applied radiation
protection experience
at
a nuclear facility equivalent to the bachelors
degree
requirement.
Conclusion
The inspectors
concluded the new
RPM met the qualification requirements
of TS 6.3.1.
RP&C Organization
and Administration
Radiation Protection
and Chemistr
Or anization
and Administration
83750
Ins ection Sco
e
The inspectors
evaluated the recent organization
changes for their
affect in the licensee's
program for control of radiation exposures,
especially
any changes that result in a lessening of the ability of the
radiation protection manager to have direct recourse to the onsite plant
or station manager in order to resolve questions
related to the conduct
of the radiation protection program.
Observations
and Findin s
The licensee
had recently combined the chemistry
and health physics
departments.
The reorganization
was
made to allow more efficient use of
available resources
and to allow individuals an opportunity to work in
new positions of responsibility.
The new organization
had Chemistry,
HP,
and Technical sections,
with each having an assigned
supervisor.
The Technical section
was
a new group.
An HP/Chemistry Supervisor
position was also created to manage the three sections.
The
HP/Chemistry supervisor
would report to the operations
manager.
The
former
HP Supervisor
was
made the Technical section supervisor
and the
ALARA coordinator
was
made the supervisor of Health Physics.
The
licensee did not know when the manager
position would be filled.
In accordance with licensee
TS 6.2 the
HP supervisor
shall
have di rect
access to the senior site management for resolving issues affecting
implementation of the radiation protection program.
The new
organization did affect the
RPHs chain of command to senior
management,
in that.
another
manager
had been
added to the chain of command.
However, the route through the operations
manager
to the plant manager
remained the same.
HP personnel
reported
good access
to upper
management.
c.
Conclusion
The inspector
concluded the
new organization did not adversely
impact
the licensee's ability control radiation exposures.
Pl
Conduct of EP Activities
Pl. 1
Notification of Unusual
Event
Due to Fire
93702
and 71750
At about 7: 15 a.m.
on March 4,
1997, Control, room operators
received
fire alarms f'r the invertor rooms
and cable spreading
room (CSR),
and
observed
some
smoke in the invertor room behind the control
room.
A
public address
(PA) announcement
was
made
and the fire brigade
responded
to'the affected areas.
Subsequently,
one of the invertor room halon
systems
automatically initiated.
The fire brigade observed
sparks
and
fire emanating
from the inboard generator
bearing
on the 4A control rod
drive motor-generator
(MG) set.
The 4A MG set
was secured locally, and
the fire brigade extinguished the fire using portable carbon dioxide and
dry chemical extinguishers.
Other licensee
actions
included the following:
Called for outside assistance,
Declared
an
UE due to fire lasting more than ten minutes at 7:37
a.m.,
r
Notified the State
(FL) and
NRC as required,
Declared the control
room ventilation system
OOS,
Downgraded the
UE when fire was confirmed out at 8:00 a.m.,
Organized
an
ERT to determine root cause,
Debriefed the fire brigade
and other involved personnel,
and
Repaired the 4A MG set
(see section M2.1).
The effects
on each unit was
as follows:
Unit 3 was in mode 5, in the second
day of the refueling outage.
RHR was in service,
and no immediate concerns
were noted.
(2)
Unit 4 was at 100'ower.
The 4B
MG set
remained in service
providing rod control power.
(3)
The licensee
reviewed control
room evacuation
procedures
based
on
the proximity of the fire and smok p5
P5.1
S1
S1.1
.
The resident
and region based
inspectors
heard the
PA announcement,
and
reported
immediately to the scene
and the control
room.
Procedure
implementation (e.g.. fire ONOPs),
TSAS,
and
Emergency
Plan activation
were independently verified to be appropriate.
Timely and effective
response
by the fire brigade
was noted.
Strong oversight
by the fire
brigade leader.
the
NPS,
and licensee
management
was noted.
The
ERT
efforts were noteworthy and comprehensive.
A fire brigade debrief was
held by fire protection personnel,
and
ERT members,
and plant manage-
- ment.
This debrief was proactive.
informative,
and well executed.
In conclusion;
the licensee's
response to the fire. and the
UE,
and
followup activities were noteworthy.
Staff Training and Oualification in
EP'mer
enc
Plan Drill
71750
On February 24,
1997. the licensee
conducted
an Emergency
Preparedness
(EP) drill, including actuation of the Technical
Support Center
(TSC)
and the Operations
Support Center
(OSC).
The inspectors
monitored
portions, of the drill in the control
room simulator
as well as the
and
OSC.
The inspectors
concluded that the
EP drill was appropriately conducted
and critiqued.
Overall licensee
performance
was very good.
New and
recently promoted personnel
were used in their
EP positions for the
first time.
This provided good training for these individuals.
Conduct of Security and Safeguards Activities
Ille al
Dru
Found In the Protected
Ar ea
71750
On February
19.
1997. at 12:20 p.m.,
a licensee security officer
discovered
a glass tube with a white powder substance
at one end of the
tube.
The tube was found in a portable toilet, inside the protected
area just north of the spare transformer.
The tube fell from a ledge
above the door while the portable toilet was being cleaned.
Metro-Dade
Police were notified,
and took possession
of the glass tube.
Confirmatory testing identified the substance
as containing crack
cocaine.
The licensee
inspected all the similar portable toilets on-
site and no other material
was found.
Subsequent
inspections of the Protected
Area and site by heightened
security and operations
personnel
did not identify any other material.
The licensee
also initiated Condition Report
No. 97-0227
and
made
a 24-
hour notification
ENS to the
NRC at 8:52 p.m. per
CFR 36.73.
Additional corrective actions
included maintaining
a heightened
awareness
during the refueling outage
due to a large number of extra
personnel
onsite.
increased
Protected
Area searches,
and increased
random testing per fitness-for-duty requirement r
S8
S8.1
The inspector
reviewed the licensee's
investigation,
examined the
material,
independently toured
and inspected
the Protected
Area and
site, verified corrective actions.
and reviewed the
ENS worksheet
and
CR.
The inspector concluded that the licensee appropriately
responded
to this issue,
including reportabi lity assessment
and corrective
actions.
A regional specialist
intends to review this item in a future
inspection.
Hiscellaneous
Security and Safeguards
Issues
Closed
URI 95-21-01
Failure to Include Individuals in A Dru
Testin
Pro
ram
Enforcement Action
No. 97-86
92904
On September
26.
1995, the licensee identified that several
individuals
were missing from the Nuclear Employee Plant Access
(NEPA) System.
This
omission from the computer
system also excluded these individuals from
the required
random drug testing pool.
The discrepancy
was detected
when another licensee
requested
transfer of access
of affected
individuals.
Upon investigation
and through
an audit conducted
by the
licensee, it was confirmed that information for several
individuals was
not input to the
NEPA system.
The licensee
determined that
a contract security officer failed to
complete the procedure
and upon realizing the licensee's
investigation
was proceeding,
decided to input the data without informing the
licensee.
The employee
was subsequently
terminated
as
a result of this
action.
The individuals who were not under the random drug screening
program were not aware of their exclusion.
The time-frame of exclusion
of the various individuals was approximately
19 to 30 days.
The licensee
concluded root cause
was
a personnel
error.
The
individual's inattention to detail also contributed to falsification of
records.
The individual failed to perform job related tasks in a timely
manner, getting behind in duties.
Upon learning of the pending
investigation,
the individual attempted to input the data using the
dates the data
was supposed
to be entered,
rather than the date the data
was actually entered in the
NEPA System.
CFR 26.24 requires
licensees
to have unannounced
drug and alcohol
tests
imposed in a statistically
random and unpredictable
manner.
Thus,
all persons
in the population subject to testing
have
an equal
probability of being selected
and tested.
For approximately
19 to 30
days,
during the period July 1995 to September
1995, several
individuals
were excluded
from the licensee's
required
random drug and alcohol
testing program.
The inspector
reviewed the licensee's
corrective actions
and
NRC
enforcement criteria.
This licensee-identified
and corrected violation
is being treated
as
a Non-Cited Violation (NCV), consistent with Section
VII.B.1 of the
NCV 50-250.251/97-03-03,
Failure
to Include Individuals in a Drug Testing
Program,
and the URI and
were close P
t
F5
Fire Protection Staff Training and Qualification
75.1
~Fi
Il 111
71755
The inspector
observed
a routine. unannounced fire drill conducted
on
February
19.
1997, at the Unit 3 lube oil reservoir.
The inspector
observed activities from the control
room and locally at the scene.
The
inspector
concluded that personnel
appropriately
and adequately
responded to the simulated fire.
The response
included operators
and
personnel
assigned to the fire team,
chemistry
and medical
personnel
assigned
as the emergency
medical
team,
and security personnel.
The inspector
concluded that the fire drill was well conducted
and
critiqued.
V.
Mana ement Meetin s
Xl Exit Meeting Summary
The inspectors
presented
the inspection results to members of licensee
management
at the conclusion of the inspection
on April 11,
1997.
The
licensee
acknowledged
the tindings presented.
Licensee representatives
presented their views that the item on failure to paint all tools used
in the
RCA had been prior identified by them and that corrective action
was in progress,
therefore it should not be cited by the
NRC as
a
violation.
The inspector
acknowledged their comments.
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 Manager
G. Alexander,
Supervisor
Inspections/CSI
R. J. Acosta, Director, Nuclear Assurance
J.
C. Balaguero,
Plant Operations
Support Supervisor
P.
M. Banaszak.
Electrical/18C Engineering Supervisor
R.
M. Brown,
HP Supervisor
T. J. Carter,
Mechanical
Maintenance Supervisor
S. Chaviano,
Lead Civil Engineer
B.
C.
Dunn, Mechanical
Systems
Supervisor
R. J. Earl,
QC Supervisor
S.
M. Franzone,
Electrical Maintenance
Supervisor
R. J. Gianfrancesco.
Maintenance
Support Supervisor
J.
R. Hartzog.
Business
Systems
Manager
G.
E. Hollinger, Licensing Manager
R. J.
Hovey, Site Vice-President
M.
P.
Huba,
Nuclear Materials Manager
D.
E. Jernigan,
Plant General
Manager
T. 0. Jones,
Operations
Supervisor
M. D. Jurmain,
IKC 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
Support Supervisor
E. Lyons, Engineering Administrative Supervisor
F.
E. Marcussen,
Security Supervisor
R.
B. Marshall,
Human Resources
Manager
C. Mowrey. Licensing Specialist
H.
N.
Paduano,
Manager,
Licensing and Special
Projects
M. O.. Pearce,
Maintenance
Manager
K.
W. Petersen,
Site Superintendent
T. F. Plunkett,
President,
Nuclear Division
K. L. Remington,
System Performance
Group Supervisor
R.
E.
Rose,
Outage
Manager
C.
V. Rossi.
QA and Assessments
Supervisor
W. Skelley, Plant Engineering
Manager
R.
N. Steinke,
Chemistry Super visor
E. A. Thompson.
Engineering
Manager
D. J.
Tomaszewski,
Systems
Engineering
Manager
R. Turner, Inservice Inspection Coordinator
G. A. Warriner, Quality Surveillance Supervisor
R.
G. West, Operations
Manager
Other licensee
employees
contacted
included construction
craftsmen,
engineers,
technicians,
operators,
mechanics,
and
electricians.
NRC Resident
Inspectors:
T.
P. Johnson,
Senior
Resident
Inspector
J.
W. York, Resident
Inspector
J.
R.
Reyes,
Resident
Inspector
Partial List of Opened,
Closed,
and Discussed
Items
~0ened
50-250.251/97-03-04
Closed
IFI, Failure to Conspicuously
mark tools in the
RCA (R1.1).
50-250,251/95-21-01
URI, Failure to Include Individuals in A Drug
Testing Program (section
SB. 1).
50-250.251/97-03-01
NCV, Failure to Follow the
ADM for Operating
Procedures
(section
03. 1).
50-250,251/97-03-02
NCV, Failure to Meet ANSI N45.2.2 Storage
Requirements
for
Piping (section M7.1).
50-250,251/97-03-03
NCV. Failure to Perform Daily Radiation Meter
Response
Checks (Rl.l).
50-250.251/97-03-05
LER 50-250/97-02,
Discussed
None
NCV, Failure to Include Individuals in a Drug
Testing
Program (section S8.1)
Manual Reactor Trip (section 01.3)
List of Inspection
Procedures
Used
'IP 37551:
Onsite Engineering
IP 40500:
Effectiveness of Licensee Controls in Identifying,
Resolving,
and Preventing
Problems
IP 50002:
IP 60705:
Preparation
for Refueling
IP 60710:
Refueling Activities
IP 61726:
Surveillance
Observations
IP 62700:
Maintenance
Program Implementation
IP 62702:
Maintenance
Program
IP 62707:
'aintenance
Observations
IP 71707:
Plant Operation
IP 71750:
Plant Support Activities
IP 73753:
Inservice Inspection
IP 83750:
Occupational
Radiation
Exposure
IP 90712:
Inoffice Review of Written Reports
IP 90713:
Review of Periodic Reports
IP 92700:
IP 92904:
IP 93702:
Onsite Followup of Written Reports of Nonroutine Events at
Power Reactor Facilities
Followup - Plant Support
Prompt Onsite
Response
to Events at Operating
Power Reactors
List of Acronyms and Abbreviations"
ADM
a.m.
ANPO
ANPS
ANSI
AVB
BIT
CFR
CMM
CR
CSR
CV
DB/DBD
dpm
e.g
ENG
, EOP
ERT
etal
oF
F
FL
FT
Alternating Current
Administrative (Procedure)
As Low As Reasonably
Achievable
Ante Meridiem
Associate
Nuclear Plant Operator
Assistant
Nuclear Plant Supervisor
American National Standards
Institute
Alara Review Board
Response
Procedure
American Society of Mechanical
Engineers
Anti-Vibration Bar
Boiler and Pressure
Vessel
Boron Injection Tank
cubic centimeter
Component Cooling Water
Code of Federal
Regulations
Corrective Maintenance
- Mechanical
Condition Report
Control
Rod Drive Mechanism
Cable Spreading
Room
Control Valve
Chemical
Volume Control System
Design Basis
(Document)
Direct Current
Department of Transportation
Disintegrations
Per
Minute
Power Reactor
License
Division of Reactor Safety
Enforcement Action
Emergency
Core Cooling System
For Example
Engineering
Emergency Notification System
Emergency Operating
Procedure
Emergency
Preparedness
Event Response
Team
Eddy Current
"and the rest"
Degrees
Fahrenheit
Fuse
Flow Control Valve
Florida Power and Light
Flow Transmitter
GL
gpm
GS
HPA
HPES
HPS
HPSS
HPT
hr
'&C
ICW
i.e.
IEEE
IG(SCC)
IP
IWE,
IWL
JPN
JPNS
KV
L
LCO
LER
LPDR
MBM
'OVATS
NCY
NDD
No.
NO(UE)
NRC
Generic Letter
General
Operating
Procedure
Gallons
Per Minute
Gland Steam
High Efficiency Particulate Air
High Head Safety Injection
Health Physics
Health Physics
- Administrative
Human Performance
Evaluation System
Health Physics
- Surveillance
HP Shift Supervisor
Health Physics
- Technical
hour
Heating Ventilation and Air Conditioning
Instrumentation
and Control
Intake Cooling Water
That Is
Institute of Electrical
and Electronics
Engineers
Intergranular
(Stress
Corrosion Cracking)
Integrated
Leak Rate Testing
Inspection
Procedure
Inservice Inspection
Inservice Test
Subsections
XI
Juno Project Nuclear (Nuclear Engineering)
Juno Project Nuclear Safety
Kilovolt
Letter (licensing)
Level Controller
Limiting Condition for Operation
Level Control Valve
Licensee
Event Report
Level Indicator
Local Leak Rate Test
Local
milli
Manufacturing Buff Marks
Motor Control Center
Motor Generator
Motor-Operated
Valve
MOV Acceptance Testing System
Non-Cited Violation
No Detectable
Defect
Nondestructive.Examination
Nuclear Employee Plant Access
Number
Notification of (Unusual
Event)
Nuclear Plant Operator
Nuclear Plant Supervisor
Nuclear Regulatory Commission
NRI
ONOP
OP
PACV
PAHH
PC
PC/H
p.m.
PMI
PHM
PNSC
Pslg
PTN
PWO
QAO
QI
RCO
(
RP(H)
PRV
RWO
RV
S/B
S
SEC/S
SNPO
No Recordable
Indications
Office of Nuclear Reactor Regulation
Outside Diameter
Off-Normal Operating
Procedure
Out-of-Service
Operating
Procedure
Operational
Support Center
Operations Surveillance
Procedure
Public Address
Post-Accident
Containment Ventilation
Post-Accident
Hydrogen Monitor
Protective.Clothing
Personnel
Contamination
Event
Plant Change/Modification
Pressure
Control Valve
Public Document
Room
Post Meridiem
Preventive
Maintenance
Preventive
Maintenance
- I8C
Preventive
Maintenance
- Mechanical
Plant Nuclear Safety Committee
Power-Operated
Relief Valve
Pounds
Per Square
Inch Gauge
Project Turkey Nuclear
Plant Work Order
Quality Assurance
Quality Assurance
Organization
Quality Control
Quality Instruction
Radiation Control Area
Reactor Control Operator
Reactor
Coolant
Pump
m rem) Roentgen
Equivalent
Man (milli)
Regulatory Guide
(NRC)
Residual
Heat Removal
Reactor Operator
Radiation Protection
Manager
Radiation Protection
(men)
Reactor
Pressure
Vessel
Relay Work Order
Radiation
Work Permit
Refueling Water Storage
Tank
Relief Valve
GFP
Standby
Safety Evaluation Civil - Site
Safety Evaluation Report
Spent
Fuel
Pit'team
Generator
Safety Injection
s/g Feedwater
Pump
Senior Nuclear Plant Operator
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TCN
TG
TS
TSAS
V
VAC
VAR
VMR
W
WGDT
WHT
Significant Operating
Experience
Review
Senior Reactor Operator
Stop-Think-Act-Review
Temporary
Change Notice
Turbine Generator
Technical Specification
TS Action Statement
Technical
Support Center
Updated Final Safety Analysis Report
Unresolved
Item
Ultrasonic Examination
Volt
Volt AC
Volts Amperes Reactive
Volume Control Tank
Violation
Voltage Metering Relay
Visual Examination
Waste
Gas
Decay Tank
Waste Holdup Tank
Work Order
Work Request
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4