IR 05000335/1998002
| ML17229A668 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 03/11/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17229A667 | List: |
| References | |
| 50-335-98-02, 50-335-98-2, 50-389-98-02, 50-389-98-2, NUDOCS 9803180355 | |
| Download: ML17229A668 (66) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos: 50-335, 50-389 License Nos:
DPR-67, NPF-16 Report Nos: 50-335/98-02, 50-389/98-02 Licensee:
Florida Power Im Light Co.
Facility:
St. Lucie Nuclear Plant.
Units
8 2 Location:
6351 South Ocean Drive Jensen Beach, FL 34957 Dates:
January 4 - February 14, 1998 Inspectors:
H. Hiller. Senior Resident Inspector J.
Hunday, Resident Inspector D. Lanyi, Resident Inspector F. Wright, Regiona'l Inspector (Sections Rl.l. R1.2.
R2.1, R?.1, R?.2.
and 'R8.1)
J.
Kreh. Regional Inspector (Sections P5. 1, P7. 1, P7.2.
and P8.1)
W. Sartor, Regional Inspector (Sections P2. 1, P3. 1, P6. 1)
S.
Rudi sai l. Project Engineer (Secti on 08. 6)
Approved by: T. Johnson, Acting Chief, 'Reactor Projects Branch
Division of Reactor Projects 9803l80355 9803li PDR ADQCK 05000335
P C
EXECUTIVE SUMMARY St. Lucie Nuclear" Plant, Units
& 2 NRC Inspection Report 50-335/98-02, 50-389/98-02 This integrated inspection included aspects of licensee operations, maintenance, and plant support.
The report covers a 6-week period of resident inspection; in addition. it includes the results of inspections performed by Region based inspectors in the areas of emergency preparedness and radiation protection.
~0er ations
~
The initial return to service of Unit 1 from the Steam Generator Replacement Outage was performed in a controlled fashion.
Several technical problems occurred during the startup and initial power ascension.
and these were adequately addressed by the licensee.
The inspector noted good procedural compliance by the licensee's staff (Section 01.2).
~
Emergency Diesel Generator 2A was properly aligned and in good material condition.
Instrumentation was noted to have been properly calibrated and functional.
Two minor procedural deficiencies were identified but will be resolved as part of the procedures upgrade program (Section
,02.2).
Operators responded quickly and correctly in tripping Unit'
in response to a large Digital Electrohydraulic fluid leak on the turbine front standard.
The trip was complicated by a failure of the Hain Feedkater Pumps brought about by a known inability of the feedwater system to recirculate enough feedwater to prevent the feedwater pumps from tripping due to low flow conditions.
The licensee's proposed corrective actions for this long standing equipment problem were similar to those proposed on at least two other occasions (Section 02.3).
The licensee demonstrated conservative decision-making in removing Unit 1 from service to replace Engineered Safety Feature Actuation System (ESFAS)
power supplies.
Engineering documents to support the evolution were well-prepared.
Crew briefs were thorough and clear di rection for actions to be taken in the event of an ESFAS actuation were clearly communicated.
The licensee successfully replaced the degraded power supplies and. returned the unit to service (Section 02.4).
The licensee responded to the failure of the lower seal stage of the 182 reactor coolant pump appropriately and arguments justifying continued operation were reasonable (Section 02.5).
The Facility Review Group performed its function as requi red by Technical Specification 6.5. 1 (Section 07. 1).
Maintenance
~
The inspector concluded that functional testing of the Emergency Core Cooling System Radiation Monitors was performed properly and with
i satisfactory results.
The procedure contained several steps that were confusing and difficult to follow.
The method for controlling process radiation monitor setpoints was considered to be a weakness (Section M1. 1).
Plant Su ort
~
Licensee chemistry personnel closely monitored secondary water chemistry parameters during startup to maintain parameters within limits specified in licensee procedures.
Corrective measures for a parameter above its'ormal value were appropriate and timely (Section Rl. 1).
An inspected shipment of radioactive waste was properly prepared and met applicable Nuclear Regulatory Commission (NRC) and Department Of Transportation (DOT) shipping requirements.
Licensee personnel having responsibilities for transporting radioactive materials at St Lucie were very knowledgeable in the applicable NRC and DOT shipping regulations (Section Rl.Z).
The inspector concluded that the licensee was adequately meeting all requirements for controlling and posting locked high radiation areas (Section R1.3).
The licensee has made improvements in the Radiation Monitoring System (RMS).
However, the lack of resources and priority for the system has resulted in continued delays of system performance improvements (Section R2.1).
'he quality of recent audits of'he chemistry and radiological e'ffluent programs was very good.
The audit findings were accurate and licensee responses to the audit findings were comprehensive.
As a results the quality of the chemistry and radiological effluent monitoring programs were strengthened through the quality audit processes (Section R7. 1).
~
The Chemistry Department was making program improvements through the self-assessment process (Section R7.2).
~
Problems documented in licensee Condition Reports indicated Instrumentation and Control (I8C) technicians may not fully understand how the Radiation Monitoring System implements Technical Specifications and Offsite Dose Calculation Manual requirements.
The licensee had
'ommitted additional I8C personnel resources to the Radiation Monitoring System; however, none of the additional I8C technicians had completed required training (Section R8. 1).
.
Emergency Response Facilities (ERFs) were well equipped and were maintained at a suitable level of operational readiness (Section P2. 1).
Changes to the Emergency Plan were made in accordance with 10 CFR 50.54(q).
The emergency declaration made on April 19, 1997 was made in accordance with the Emergency Plan Implementing Procedures (Section P3.1).
The licensee's training program for its emergency response organization was in accordance with Emergency Plan training commitments and met the intent of NRC regulatory requirements and guidance.
Major improvements in this program had been developed and implemented during the past 15 months.
The conduct of quarterly integrated drills during 1997 enhanced the quality of Emergency Response Organization training (Section P5.1).
No degradation had occurred in the organization or management of the Emergency Preparedness program (Section P6. 1).
The 1997 Emergency Plan program audit fully satisfied the 10 CFR 50.54(t) requirement for an annual independent audit of the EP program (Section P7.1).
The licensee's program for identifying. tracking.
and resolving problems in emergency preparedness was effective.
Self-assessments were useful in focusing licensee staff and management attention on problem areas (Section P7.2).
Summar of Plant Status Re ort Details Unit 1 began the period in a refueling outage.
The'unit returned to service on January 7.
1998.
On January 10.
1998. the licensee manually tripped the reactor because of a, turbine control system hydraulic fluid leak.
The unit returned to service the next day and reached 100 percent power on January 14, 1998.
The licensee manually shut down the unit on January 16 to repai r failing redundant power supplies on a channel of the Engineered Safeguards Actuation System.
The unit returned to service the following day and remained essentially at full power for the remainder of the report period.
Unit 2 remained essentially at full power for the entire report period.
I. 0 erations
Conduct of Operations 01.1 General Comments 71707 Using Inspection Procedure 71707. the inspectors conducted frequent reviews of ongoing plant operations.
In general.
the conduct of opera-tions was professional and safety-conscious; specific events and noteworthy observations are detailed in the sections below.
01.2 Restart of Unit 1 From the Steam Generator Re lacement Outa e
a.
Ins ection Sco e
71707 At 5:40 a.m..
on January 6,
1998, Unit 1 entered Mode 2 and, at 7:34 a.m., the unit reached criticality.
The licensee performed low power physics testing during the next day.
The Unit was synchronized to the grid at 2: 16 p.m.
on January 7,
1998.
The licensee conducted a power asc'ension test period of approximately three days.
The inspectors observed portions of the dilution to criticality, physics testing, turbine startup, and initial power ascension.
b.
Observations and Findin s The licensee performed the initial startup from the Steam Generator Replacement Outage in accordance with Preoperational Procedure POP 1-3200088, Revision 19, "Unit 1 Initial Criticality Following Refueling."
This procedure sequenced all of the required Operating Procedures, 18C Procedures, and Physics Tests.
The inspector periodically reviewed the record copy of the Procedure to ensure that the licensee was complying with the requirements.
The inspector noted that the Operators and Reactor Engineers were routinely referring to the procedure to verify that they were ready for future activities.
The licensee performed the procedure as written.
The licensee entered Mode 2 at 5:40 a.m.,
on January 6,
1998.
The inspector observed the dilution to criticality.
The inspector noted
that the licensee stationed a Reactivity Manager as required by their Administrative Procedure AP-0010120, Revision 96,
"Conduct of Operati ons. "
This individual hei d a Seni or Reactor Operator 's License and had no other collateral duties during reactivity manipulations.
The inspector observed good communications among the Reactor Control Operator (RCO) performing the reactivity manipulations, the Reactivity Manager, and the on-shift Assistant Nuclear Plant Supervisor (ANPS).
Procedural adherence was good.
The unit reached criticality at 7:34 a.m.
The licensee stabilized power at approximately 5xl0'ercent reactor power for low power physics testing performed in accordance with Procedure POP 3200091.
Revision 15.
"Reload Startup Physics Testing."
The first test was a checkout of the reactivity computer.
The licensee determined the upper (Point of Adding
.
Heat)
and lower (based on noise level) power ranges for the test.
Next, the licensee performed a check of the Shutdown Group's Dual Control Element Assembly (CEA) Symmetry.
During this test.
an upper gripper fai l*ure alarm for CEA 49 was received.
During troubleshooting, the CEA dropped into the core.
The licensee transitioned into Appendix I of Procedure POP 3200092,
"Actions for Hisaligned CEA During Physics Testing," to recover the CEA.
Troubleshooting by I8C with Engineering support was performed to determine the cause of the dropped CEA.
The licensee had recently completed a modification to the CEA system to help alleviate this problem.
In order to troubleshoot the alarm, I8C installed voltage tracing equipment to the Control Element Drive Assembly circuitry.
The rod did not drop until the Operator attempted to drive the rod again for troubleshooting.
The licensee was able to identify that a power supply in the upper gripper module failed.
The Automatic CEA Timer Module (ACTH) detected this fai.lure and caused the lower gripper to engage to hold the module.
This happened five times before the ACTH failed to hold the CEA.
The licensee formed an Event Response Team (ERT) to investigate the occurrence.
The team determined that the ACTH had prevented the rod drop initially.
The licensee then revised thei r procedures for CEA alarms to ensure that the operators did not attempt to move a
CEA unti 1 I&C could investigate.
The inspector reviewed the ERT's report.
The co'rrect expertise was assembled for the team and the investigation was thorough.
Low Power Physics Testing was resumed and completed satisfactorily.
After Physics Testing was complete.
the Unit was returned to service in accordance with Preoperational Procedure POP 320092, Revision 21,
"Reactor Engineering Power Ascension Program."
This procedure sequenced the required Operations and ISC pr'ocedures to return the unit to tull power in a controlled fashion.
Again, the inspector observed good procedural complianc The.inspector noted several minor problems that the licensee had to overcome.
First during Physics Testing, the B Startup Rate (SUR) pre-trip annunciator alarmed several times.
The licensee opted to declare the B SUR instrument out of service.
I8C performed a functional check of the instrument and found that it was fully capable of performing its safety function.
The lice~see then declared the instrument back in service.
About that time, the licensee identified the A linear power range channel was indicating approximately twice the value that other safety channels and control channels were.
The licensee had replace the A channel detectors during the refueling outage.
The detector currents had been calibrated based upon the best information available to the licensee.
The licensee reviewed several options, and decided the simplest was to declare the A channel Out of'ervice and then, at the first sufficiently high power, to recalibrate the channel.
Other contingency paths were reviewed and held in standby in case of another detector f'ai lure.
The inspector observed the discussions among the Technical staff and ensured that the licensee was complying with all applicable Technical Specifications and procedures.
The A Channel Linear Power Range was declared Out of Service.
The licensee performed turbine pre-operational testing, and the unit was returned to service at 2: 16 p.m.
on January 7,
1998.
Power was raised to approximately 25 percent in accordance with the Power Ascension Plan where the Nuclear Instruments were first recalibrated.
Conclusions The initial return to service of Unit 1 from the Steam Generator Replacement Outage was performed in a controlled fashion.
Several
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technical problems occurred during the startup and initial power ascension, and were adequately addressed by the licensee.
The inspector noted good procedural compliance by the licensee staff.
02.1 Operational Status of Facilities and Equipment En ineered Safet Feature S stem Walkdowns 71707 The inspectors used Inspection Procedure 71707 to walk down accessible portions of the following Engineered Safety Feature systems:
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Intake Cooling Water System (Units 1 and 2)
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Component Cooling Water System (Units 1 and 2)
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Boric Acid.Makeup Systems (Units I and 2)
Equipment operability, material condition, and housekeeping were acceptable in all cases.
Several minor discrepancies were brought to the licensee's attention and were corrected.
The inspectors identified no substantive concerns as a result of these walkdown.2 Walkdown of the Unit 2A Diesel Generator S stem a.
Ins ection Sco e
71707 The inspector performed a review of the Unit 2A Emergency Diesel Generator (EDG) system.
Specifically. associated procedures were reviewed, instrument calibrations verified, proper valve configuration confirmed, drawings were reviewed.
and system walkdown performed to verify the system was being maintained and operated in accordance with Technical Specification (TS) and Updated Final Satety Analysis Report (UFSAR).
b.
Observations and Findin s The inspector verified the 2A EDG valve and electrical components were aligned as required by Procedure OP 2-2200020.
Revision 29 'Emergency Diesel Generator Standby Lineup."
In addition, the inspector verified the system drawings also identified each components appropriate position.
The drawings reviewed were; 2998-G-086, Revision 33, 2998-G-096-1A, Revision
~ 2998-G-096-1B, Revision 10, and 2998-G-096-1C, Revision 9.
During this review, the inspector noted numerous differences between the component description on the valve identification tag, the description in the OP and the description in the total equipment data 'base (TEDB).
The following table identifies several examples which were representative of a much larger population:
Valve/.
Breaker Number V17208 OP Description 2A DOST Fill Isol Valve Tag Description Oil Fill To 2A DOST Isol Total Equipment Data Base Description Isolation Valve For Oil Fill To Diesel Oil Storage Tank 2A V38170 2A1 Diesel Demin Water Isol DMW To ZA1 Expan Tank Isol Va'lve For DWS Isol Emerg Dsl Gen 2A.RDTR Expan Tk'2A1 Fill Line V59075
V59094 Breaker 2-41415 PI-59-005A Root Isol (2A2 Lube Oil Press)
2Al South Star ting Motors Isol.
2Al AC Turbo Oil Pump PI-59-005A On Diesel Engine 2A2 Root S/A To Diesel Engine 2A1 South Side Isol Feeder for Starter DG-2A Turbo Lube Oil AC PP 2Al-1 Root Valve For PI-59-005A Isolation Valve For Start-up Air To Diesel Eng 2A1 (S Side)
Circuit Breaker For 480V MCC 2A7-C03
Administrative Procedure ADM-11.02, Revision 1, "St. Lucie Procedure Writer's Guide," Section 6.4.5, requires that the
"Identification of equipment, controls, displays and valve tags shall match the label at the location where the component is manipulated.
observed or monitored.
to eliminate any confusion to the users when identifying components."
However, this procedure is a guide to be used when revising or writing procedures, not a requirement for existing procedures.
The inspector discussed this issue with members of the Procedures Upgrade group who stated that the component identifications that are used in the procedures are taken from the component tags in the plant.
The inspector did not identify any tags that were misleading or confusing.
The inspector discussed this issue with the Operations Manager who stated that these differences should be resolved as the upgraded procedures are issued.
The TEDB will be revised during the TEDB upgrade project that has been delayed due to the increased Engineering activities preparing for a Fire Protection Functional Inspection.
In addition, the inspector reviewed the periodic surveillance, Procedure OP 2-2200050A, Revision 30,
"ZA Emergency Diesel Generator Periodic Test And General Operating Instructions," to verify that the requirements of TS were being satisfied.
No discrepancies were identified.
The annunciator procedure, ONOP 2-00301318, Revision 0, "Plant Annunciator Summary (Panel 8)," was reviewed to ensure proper setpoints and reference documents were identified.
The inspector noted that window 8-16,
"EMERG DG 2A ONE ENGINE START FAILURE," documented a
setpoint of >200'F exhaust A/8 diesel temperature differential.
The actual setpoint was 220'F.
The inspector discussed, with the system engineer, whether the actual setpoint should be referenced in the'nnunciator procedure.
He stated that this would be taken into consideration as the annunciator procedures are revised as a part of the procedural upgrade program.
In addition, the "Indicated Condition" identified as item 1 for Windows 8-6 and 8-16 of ONOP 2-0030138, stated
"I ater,"
as did the "Auto Action" item 1 identified for window 8-16.
This apparently meant that additional information would be added at a
later date.
These items were discussed with the Operations Manager who stated that the procedures were in the process of being revised and that these items would be corrected.
The inspector also reviewed the calibration records of several.
instruments to verify they were proper ly calibrated and able to perform their intended functions.
The instrument calibration records reviewed were for LS-59-006A, 009A, 010A and 014A, LIS 17-9A and 9B, and PS-59-001A, 002A.
003A.
004A.
005A.
006A.
007A, 008A.
009A.
010A.
011A, 012A, 013A, 014A, 015A.
016A, 017A. 018A, 019A, 020A.
021A, 022A, 023A.
and 024A.
No discrepancies were identified.
Lastly, the inspector reviewed the overall condition of the EDG, paying particular attention to leaks, fluid levels. cleanliness, and known items requi ring work.
No deficiencies were identifie Conclusions The inspector concluded that the EDG 2A was properly aligned and in good material condition.
Instrumentation was noted to have been properly calibrated and functional.
Two minor procedural deficiencies were identified but will be resolved as part of the procedures upgrade program.
No other deficiencies were identified.
Unit 1 Manual Reactor Tri Due to Di ital Electroh draulic DEH S stem
~eakacee Ins ection Sco e
93702 and 71707 On January 10, 1998. Unit 1 was manually tripped from 65 percent power due to a -large DEH leak, which threatened to result in an automatic trip of the turbine.
The inspector responded to'he site and followed the licensee's activities.
Observations and Findin s On January 9,
1998, a
DEH leak of approximately 42 drops per minute developed on the DEH test block.
The licensee attempted to stop the leak by tightening the associated bolts, but the leak persisted.
On January 10, 1998, the licensee was preparing to tighten bolts again when the leak increased from approximately one drop per minute to 'a large leak which resulted in a spray of DEH fluid in the turbine front standard area.
Operators were alerted to the worsening leak by a number of annunciators in the control room.
At approximately the same time, a
non-licensed operator (NLO) returning to the area from a tai lboard meeting identified the extent of the leakage and reported it to the control room.
Control room operators manually tripped the unit from 65 percent power at 8: 18 p.m.
At approximately 24 seconds from the trip, both Main Feedwater Pumps (MFPs) tripped due to low flow.
At 8:25 p.m., operators transitioned from Emergency Operating Procedure (EOP)
Auxiliary Feedwater system (AFW) actuations were received at approximately 8:32 p.m.
At 9:00 'p.m., operators exited EOP-2.
The AFW system performed as designed.
The inspector reviewed control room indications and found that the unit responded appropriately to the trip, with the Steam Bypass and Control System functioning properly to control Steam Generator pressure and Reactor Coolant System temperature.
Operator action to trip the unit appeared both appropriate and timely.
The licensee's root cause investigation determined that the cause for the DEH leak was extrusion failure of an 0-ring in the DEH test block.
The licensee had, in the recent Unit 1 outage.
machined the test block to reduce the crush on an 0-ring between the test and trip blocks to
'
prevent extrusion.
As a result of the reduced crush and the fact (unknown'o the licensee) that fasteners attaching the test block to the trip block were bottomed out (creating a gap between the blocks).
a leakage path developed.
The licensee subsequently shortened the subject fasteners to allow for proper application of torque without their bottoming out.
The licensee concluded that the root cause for the HFP trips was a low flow condition brought about by the closure of the Hain Feed Regulating Valves (MFRVs).
The automatic closure of these valves is a Combustion Engineering design feature following a trip.
A 15 percent HFRV bypass valve position automatically causes a 5 percent feed flow position upon closure of the HFRVs.
The subsequent slow action of the main feedwater recirculation valves results, which recycles water from the discharge of the HFPs to the condenser hotwell.
The licensee stated that, historically, this behavior had been encountered following trips from the middle of the power range.
The licensee compared post-trip response from this current trip to one which occur red on March 28, 1994, from 68 percent.
Almost immediately following that plant trip, both HFPs tripped due to low flow.
The inspector reviewed Licensee Event Reports (LERs) prepared in the last 3 years and identified a number of'dditional examples, including
~
LER 50-389/95-002-00
- On February 21, 1995, Unit 2 'tripped and experienced a trip of the 2A MFP due to low flow
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LER 50-335/95-003-01
- On July 8.
1995, Unit 1 tripped and experienced a trip of the 1B MFP due to low flow
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LER 50-389/96-002-00
- On June.6, 1996, Unit 2 tripped and
.
experienced a trip of the 2B HFP due to low flow Following the last two trips, above, the licensee committed to exploring the possibility of modifications to the feedwater recirculation valves in an attempt to prevent low flow trips in the future.
The inspector reviewed the disposition to St. Lucie Action Report (STAR) 951373, initiated on October 10, 1995 as a result of Unit 1 trip of July 8, 1995, which reported the loss of the 1B MFP due to low flow.
The disposition to this STAR requi red that Systems and Component Engineering (SCE) provide circuit logic for opening.
and keeping open, the MFW recirculation valves following a plant trip and to evaluate the existing low flow trip switch for a possible change in actuation ranges.
These items were to be completed by September 30, 1996, and were tracked under Plant Manager Action Item PM96-03-801.
The inspector inquired as to the status of these activities and found that the issue had been evaluated and that no action was taken to modify the units.
The licensee's proposed actions for the most current
'MFP trips were the same as those proposed previously.
In discussions with the system
~
~
engineer.
the inspector was informed that a relatively simple modification. involving an electrical wiring change which would force the MFP recirculation valves to remain open so long as a turbine trip was not reset.
had been submitted to the Plant Review Board (which evaluates proposed changes for merit and cost-effectiveness)
for implementation in the year 2000 during the Unit 2 outage.
A similar change was being prepared for Unit 1.
The inspectors will track the licensee's actions on this portion of the corrective actions from this unit trip under Inspection Followup Item (IFI) 50-335/98-02-01,
"Feedwater Recirculation Valve Corrective Actions."
LER 50-335/98-003-00,
"Manual Reactor Trip Due to a Digital Electro-Hydraulic (DEH) Leak at the Turbine Test Block," was reviewed by the inspector.
The inspector found that the LER correctly characterized the event.
This LER was closed.
Conclusions The inspector concluded that operators responded quickly and correctly in tripping Unit 1 in response to a large DEH leak on the turbine front standard.
The trip was complicated by a failure of the Main Feedwater Pumps brought about by a known inability of the feedwater system to recir'culate enough feedwater to prevent the pumps from tripping due to low flow conditions.
The licensee's proposed corrective actions for this long standing equipment problem were similar to those proposed on at least two other occasions.
An IFI will track the licensee's progress toward solving this problem.
Unit 1 Shutdown for Power Su l
Chan cput Ins ection Sco e
71707 On January 16, 1998, an Engineered Safety Feature Actuation System (ESFAS)
power supply in the A actuation logic cabinet failed.
The licensee elected to remove the unit from service prior to attempting a
power supply changeout to prevent an inadvertent A side actuation at power.
The inspectors followed the licensee's actions on this issue.
Observations and Findin s The ESFAS at St.
Lucie Unit 1 includes two pairs of auctioneered 24 volt power supplies in each of two actuation logic trains.
One auctioneered pair supplied normally energized actuation relays and the other pair supplied normally deenergized relays.
Oui ing the ESFAS monthly functional test, the licensee determined that the output voltage of both power supplies in the S2/M2 pai r (the pai r that supplied normally energized relays:
those which would, by design, actuate the A side safety injection actuation system.
containment isolation actuation system and main steam isolation system upon deenergization)
was abnormally low.
Continued observation of the power supplies'utput
indicated that voltage was degrading with time (with the implication that. at some point. voltage would drop below a value which would result in an actuation of those ESFAS components powered by the pair).
To revent an actuation at power (which would result in a unjt trip), the icensee elected to remove the. unit from service prior to attempting a
power supply changeout.
The inspector observed portions of the Unit 1 downpower to Node 3.
The operators controlled removing the unit from service in a professional and deliberate manner.
The operators controlling the main generator output and the reactivity of the primary were in constant communication while downpowering.
The Assistant Nuclear Plant Supervisor (ANPS)
maintained his overall. awareness of the plant.
The crew briefings were appropriate and covered the required information.
The licensee's plan for the power supply changeout involved applying a
temporary power supply to the output of one power supply, changing out the power supply, moving the temporary power supply to the output of the second power supply, changing out that power supply, and removing the temporary power supply.
The inspector reviewed Safety Evaluation PSL-ENG-SEIS-98-006, Revision 0, -Engineered Sai'ety Features Actuation System Replacement of 24 Vo1t Power Supply." which was prepared to evaluate the planned activities.
The document assessed the operability of the A side actuation system under'onditions proposed by the activity and documented a
10 CFR 50.59 safety evaluation for the proposed installatio'n of the temporary power supply.
The inspector'found the licensee's conclusions acceptable.
The inspector witnessed preparations for the activity, which involved evaluating the job site for issues of component accessibility and possible problems associated with the close proximity of power supplies in the cabinet.
Additionally. the inspector attended a briefing of maintenance and operating crews by the Nuclear Plant Supervisor (NPS)
prior to the commencement of work.
The briefing was well-prepared, and included a discussion of actions to be taken in the event of an ESFAS actuation.
Specifically, it was decided which containment penetrations would be immediately restored should a Containment Isolation Actuation Signal (CIAS) occur and the implications under TS for such actions (of primary concern was restoring component cooling water to the reactor coolant pumps and the fact that, if the CIAS was overridden.
a TS Action Statement would be entered as the automatic A side isolation would be rendered inoperable).
The power supplies were successfully replaced January 17.
1998.
Output voltages were acceptable.
The unit was subsequently restarted.
achieving criticality 4:21 a.m.,
and was synchronized to the grid at 9:37 a.m.
Conclusions The licensee demonstrated conservative decision-making in removing Unit 1 from service to replace ESFAS power supplies.
Engineering
documents prepared to support the evolution were well-prepared.
Crew briefs were thorough and clear direction for actions to be taken in the event of an ESFAS actuation were clearly communicated.
The licensee successfully replaced the failing power supplies and returned the unit to service.
Reactor Coolant Pum 1B2 Seal Sta e Failure Ins ection Sco e
71707 At 5:50 a.m.,
on January 19, 1998, the lower seal stage f'r the 1B2 Reactor Coolant Pump (RCP) failed, as indicated by control room annunciators and seal stage pressure indications.
The inspector followed the licensee's activities in response to this failure.
Observations and Findin s Unit
RCPs employ a Byron Jackson seal package with three tull pressure seals and a vapor seal capable of withstanding full operating pressure with the RCP stationary.
Normally. there is an approximate 1/3 operating pressure breakdown across each high pressure seal.
The seals are cooled by a controlled bleedoff tlow of approximately 1 gallon per minute (gpm).
The inspector observed 1B2 pump seal behavior following the lower stage failure and noted approximately 2200 pounds per square inch gauge (psig) in the middle cavity and 1100 psig in the upper cavity.
Control bleedoff flow had increased to approximately 1.3 gpm, which was consistent with predictions made in Unit 1 UFSAR Table 5.5-9 for two seals operating.
Operations responded to the tai lure by increasing observations of seal package performance.
Parameters were logged every one half-hour.
Seal behavior was generally stable:
however, since the fai lure. operators observed periodic, rapid, fluctuations in individual cavity pressures and controlled bleedoff flow.
These transients occurred approximately once to twice per day and rapidly subsided to stable conditions.
The licensee reported that discussions with the vendor and operational experience indicated that this was not an indication of a degrading situation.
The inspector found the licensees justification for continued operation appropriate.
Conclusions The inspector found that the licensee responded to the failure of the lower seal stage of the 1B2 reactor coolant pump appropriately and that licensee assessments justifying continued operation were reasonable.
0 erations Performance of Unit 1 Auxiliar Feedwater Periodic Test Ins ection Sco e
71707 The inspector witnessed the performance of Procedure OP 2-0700050.
Revision 49, "Auxiliary Feedwater Periodic Test," for the "B" pump.
on January 27, 199 e
b.
Observations and Findin s The inspector verified the operators used the.current revision of the procedure and noted that it was followed verbatim.
The data was taken correctly with test equipment that had been properly calibrated.
Following completion-of the test.
the inspector verified the results were satisfactory.
Conclusions Operations personnel performed the auxiliary feedwater periodic test adequately.
07.1 Ouality Assurance in Operations Facilit Review Grou Meetin Ins ection Sco e
71707 The inspector attended the Facility Review Group (FRG) meeting held by the licensee on January 30, 1998.
The inspector verified that the meeting was held in accordance with Technical Specification (TS) 6.5. 1, observed the issues discussed, and verified that FRG action items were completed.
Observations and Findin s The licensee held a regularly scheduled FRG on. January 30.
1998.
The
'nspector attend the meeting as an observer.
A minimum quorum, as defined by TS 6.5. 1.5, was convened and the membership discussed sixteen open items.
Host of the items were procedure change/upgrade items.
The inspector noted that all FRG members were fami liar with the items to be covered.
Several pertinent questions were asked about some of the procedure changes.
The licensee ensured that the item sponsor was present during the applicable discussions to answer these questions.
One set of procedures was tabled because they conflicted with each other.
The sponsors were tasked with resolving the conflict prior to resubmitting the procedures.
The inspector also observed the FRG discussion about a Licensee Event Report and its applicable Significant Condition Report.
The inspector found the discussions appropriate for the event.
Several minor
, administrative action items were opened to close out some of the items.
The inspector confirmed, that all items had been closed out by February 2, 1998.
Conclusions The inspector concluded that the FRG had performed its function as required by Technical Specification 6.5. 1.
The FRG members were prepared for the meeting and they asked several relevant question '
08 Miscellaneous Opei ations Issues "
R 08.1 E ui ment Clearance Order ECO Issues 71707 The inspectors reviewed several ECOs, which were in effect during the inspection period, for technical and administrative adequacy.
The following ECOs were reviewed:
~
2-98-01-079
~
1-98-02-012 The inspector found the ECOs reviewed were technically adequate and the administrative details were performed according to the licensee's procedures.
08.2 Closed LER 50-335/96-005-00
"Wide Ran e Nuclear Instrumentation Channel Ino erable When Re ui red to Be in Service for Fuel Hovement'2901 This event was discussed in Inspection Report 96-08.
A non-cited violation was identified in that report, NCV 50-335/96-08-01.
No new
. issues were revealed by the LER.
The LER was closed.
08.3 Closed LER 50-335/96-009-00
"0 eration Prohibited b
Technical S ecifications Oue to Procedural Inade uac and Personnel Error 92901 The subject LER described a condition which occurred on July 9, 1996.
An abbreviated timeline for the event is as follows:
Date 7/9/96 Time 2140 Action Unit 1 in mid-loop conditions for 1B Steam Generator (SG) work.
The boration flow path (BFP). established to satisfy Technical Specification (TS) Limiting Condition for Operation (LCO) 3. 1.2 was from a Boric Acid Makeup Tank (BAHT). through a Boric Acid Makeup (BAM) Pump. to the suction of the charging pumps.
The decision was made to terminate SG work and to fill the Reactor Coolant System (RCS)
from its mid-loop conditions due to the threat posed by Hurricane Bertha.
At the time. the RCS was vented by the removal of the pressurizer manway.
RCS temperature was approximately 100 'F.
It was decided that the RCS would be filled from the BAMTs through the charging pumps'hich required a shift in the BFP.
The BFP was to be comprised of the Refueling Water Tank (RWT). aligned to the 1B High
'Pressure Safety Injection (HPSI) pump.
The Nuclear Plant Supervisor (NPS) recognized at this decision point that the BFP would have to be realigned once the pressurizer manway was installed.
as TS 3.5.3 required that all HPSI pumps be disabled.
and their associated header stop valves be closed. if RCS temperature was below 236'F and the RCS pressure boundary was intact (conditions which would exist when the manway was installed).
The RWT-to-1B HPSI pump BFP was established.
The 1B HPSI pump discharge isolation valve was opened.
The individual HPSI injection valves from the 1B HPSI pump remained close Date Time 2200 7/10/96 QOOQ Action The 1A and 18 charging pumps were started to begin the fill of the RCS.
NPS shift turnover occurred.
No discussion occurred relative to the need to shift the BFP prior to installing the pressurizer manway..
The oncoming NPS failed to review the chronological logs. which would have served to alert him to the establishment of the existing BFP.
0400 Pressuri zer manway instal 1 ation began.
0625 0700 0720 The pressurizer manway was in place and its studs were fully tensioned.
At this point, the requirements of TS 3.5.3 were not met in that the A HPSI pump header isolation valve was 'open with RCS temperature below 236'F.
NPS shift turnover. occurred.
The oncoming NPS recognized the need to realign the BFP.
The boration flowpath was realigned to credit the 8 HANT-gravity feed valves-18 charging pump flowpath with satisfying the TSs.
The inspector found that, while the licensee closed the 1B HPSI pump header isolation valve immediately upon discovery, the failure to close the valve prior to installing the pressurizer manway const'ituted noncompliance with TS 3.5.3 until the point that the TS AS was satisfied.
The inspector reviewed the licensee's investigation of this event.
as documented in Condition Report (CR) 96-1702.
The licensee determined the root cause of the event to be failure of the peak shift NPS to discuss the impending BFP lineup change with the crew prior to implementing it on July 9, 1996.
and his subsequent failure to discuss the change in lineup, and the need to realign the BFP once the pressurizer manway was put in place, with the on-coming mid shift NPS.
Another causal factor included the maintenance procedure employed for installing the pressurizer manway, in that it did not include a
verification to insure that the BFP was aligned to support its installation.
The inspector found that corrective actions for this event were complete and appropriately documented.
The inspector noted that this event was similar to an event detailed in LER 50-335/95-008-00 in that it involved a violation of the same. TS LCO.
Mowever, after reviewing the two events for their similarities and after considering the corrective actions for the first event, the inspector concluded that it was not reasonable to expect that the corrective actions for the first event to have prevented the second event.
Consequently, this non-repetitive, licensee-identified and corrected violation is being'reated as a Non-Cited Violation. consistent with Section VII.B.1 of the NRC Enforcement Policy (NCV 50-335/98-02-02,
"Failure to Satisfy the Requirements of Technical Specification 3.5.3").
The subject LER was close T
Closed LER 50-335/96-013-00
"0 eration Prohibited b
Technical S ecifications Due to Failure to B
ass An Ino erable En ineered Safet Feature Channel Within the Re uired Action Time" 92901 This event was discussed in Inspection Report 96-15.
A non-cited vi.olation was identified, NCV 50-335/96-15-02.
No new issues were revealed by the LER.
The LER was closed.
Closed VIO 50-335/97-01-01
"Failure to Follow In-Plant E ui ment Clearance Orders Procedure" 92901 This event involved a typographical error made while preparing a
clearance.
Two wires that were to be lifted as part of an equipment clearance order (ECO) were mis-identified in the ECO.
The clearance tags were subsequently hung on the two wires and the error was not identified.
Several procedure steps designed to prevent this type of error, including a comparison of the component ID on the ECO tag and the component ID on the equipment tag as well as an independent verification of that step, were identified as having not been properly performed.
Upon discovery of the issue, the licensee replaced the incorrect clearance tags.
Personnel involved in the preparation and implementation of the ECO were counseled regarding the need for precise attention to detai 1 in all phases of the ECO process.
In addition, Procedure OP 0010122,
"In-Plant Equipment Clearance Orders';" was revised in Revision 68 to address the use of lifted leads as part of a clearance boundary and to ensure that the appropriate Maintenance discipline is consulted to verify the ECO if it contains lifted leads.
Since that revision was made, the'rocedure to control the ECO process has been changed.
The new procedure is ADM-09.04, "In-Plant Equipment Clearance Orders."
The inspector reviewed Revision 2 of that procedure and verified the controls associated with lifted leads had been incorporated.
This item was closed.
Closed LER 50-335/98-01-00
"Inadvertent RPS Actuation Due to Personnel Error" Ins ection Sco e
92901 The inspector reviewed the licensee's corrective actions for LER 50-335/98-01-00,
" Inadvertent RPS Actuation Due to Personnel Error."
Observations and Findin s On January 4,
1998, Unit 1 was in Mode 3 with a reactor plant heatup to normal operating temperature and pressure in progress following a refueling outage.
The reactor trip breakers were closed and all reactor control element assemblies were fully inserted.
The operator was directed to remove the zero power mode bypass (ZPMB) keys for each channel of the reactor protection system when the fourth reactor coolant pump was started.
The RTBs opened immediately after the RPS system
"C" channel zero'power mode bypass was unbypasse The ZPHB switch allowed the RPS low flow and Thermal Margin/Low Pressure (TH/LP) trip to be bypassed for subcritical testing of the control element drive mechanisms.
With four reactor coolant pumps operating (as was the case prior to this event).
the low flow trip was not present.
However, system pressure at the time of this event was not high enough to prevent a'M/LP trip.
This resulted in a trip when the third bypass key was switched satisfying the coincidence logic requirements for the TM/LP trip.
This event resulted from inadequate procedural guidance and self checking.
Normal Operating Procedure NOP 1-0030121,
"Reactor Plant Heatup
- Cold to Hot Standby," directs operators to place the bypass keys from bypass to off after starting the fourth RCP.
The procedure did not include all trip functions bypassed by the ZPHB keys.
Additionally, the operating crew did not investigate the cause of the trip alarms when they were received as the ZPMB keys were moved from bypass to off.
Corrective actions for this event included changes to Procedures NOP 1-0030121 and NOP 2-0030121 which required the RCS pressure to be greater than 1900 psia and without any trips present prior to removing the ZPHB keys.
Operators were counseled and operator briefings were conducted describing the event in detail and lessons learned from the event.
Also, placards were placed in the control rooms requiring conditions be met prior to removing the ZPMB keys.
c.
Conclusions The inspector reviewed the corrective actions for the LER and determined they were adequate.
LER 50-335/98-01-00,
"Inadvertent RPS Actuation Due to Personnel Error," was closed.
II. Maintenance Conduct of Maintenance Ml.'1 Functional Test of the 1B Emer enc Core Coolin S stem ECCS Process Radiation Monitor - Unit 1 Ins ection Sco e
61726 and 62707 On February 3, 1998. the inspector observed the performance of a portion of Procedure l-IMP-26.15. Revision 5,
SPING, PING-3B Mobile and Steam Line Process Monitor Functional and Calibration Instructions."
Observations and Findin s The inspector observed Maintenance perform a functional test of the 1B ECCS process radiation monitor in accordance with Appendix B of 1-IHP-26. 15.
The inspector noted that the test performers appeared
knowledgeable about the system.
" During the performance of this surveillance, several deficiencies were identified as indicated below.
~
The Alert and High alarm setpoints for the low range channel, 03-05. were found by the test performers to be incorrect prior to actually commencing the test.
The as-found values were 4.07E-4 microcuries per cubic centimeter (yci/cc) and 5.42E-4 pci/cc for the Alert and High alarms, respectively.
The values should have been 3.76E-4 pci/cc and 5.02E-4 yci/cc for the same parameters.
Operations and the Maintenance lead were informed of the findings and CR 98-0212 was initiated to determine the root cause of the error and the effect it had on the system.
The correct setpoints were subsequently installed.
The licensee later determined that on January 21.
1998
'aintenance implemented several radiation monitor setpoint changes that had been revised in accordance with Procedure COP-07.05.
Revision 0, "Process Monitor Setpoints",
Appendix E.
Appendix E
is simply a list of radiation monitors with a blank where Chemistry adds the latest setpoints.
When a setpoint is revised, Chemistry writes in the new setpoint and places a check mark beside that particular monitor.
Maintenance then physically changes the setpoints for the monitors identified on Appendix E
with a check mark.
On January 21, 1998, Maintenance changed all the setpoints on Appendix E that contained a check mark, with the exception of the "A" and "B" Steam Generator (SG)
Blowdown monitors.
The ANPS requested that the proposed setpoints for the two monitors be reverified before they were changed.
Haintenance returned the Appendix E form to Chemistry and requested that they reverify the setpoint.
On January 23, 1998, Chemistry returned Appendix E to Maintenance to have the setpoints installed.
However, the setpoints for the "B" ECCS monitor were also changed on the Appendix E form which was returned to Maintenance.
Maintenance was not aware that this had occurred and only changed the setpoints for the SG blowdown monitor.
This resulted in the
"B" ECCS monitor having the wrong Alert and Alarm setpoints from January 23 to February 3, 1998.
The inspector reviewed the circumstances surrounding this issue and concluded that this error was the result of a weak process in transmitting setpoint changes from Chemistry to Maintenance for implementation.
At the conclusion of this report period, the licensee was in the process of developing a better method for controlling process radiation monitor setpoints.
The data printer, CT-1, located on the Eberline control panel, did not legibly print various numbers.
The number 3 could not be distinguished from the number 8.
A work request was initiated.
Step B.5.g. of Procedure 1-IHP-26. 15, referenced Appendix E of Procedure COP-65.85.
In addition, the setpoint section of, Procedure ONOP 1-0030131X, Revision 1, "Plant Annunciator Summary
(Panel X)," also referenced Procedure COP-65.85.
Procedure COP-65.85 was replaced by Procedure COP-07.05 on December 18 '997.
The inspector brought this to the attention of the licensee who generated the necessary documentation to correct the procedures.
Step B.25, of Appendix B, Tab 1. states that if additional channels are to be tested, the test performer is to return back to Step B.2 and reperform Steps B.2 through B.24 for the remaining channels, or continue with Step B.29.
Step B.Z9 has the test performer return the monitor to its Normal configuration and requires independent verification. If the procedure is performed in this manner, only the last channel tested receives an independent verification of the return to the Normal configuration.
The inspector noted the test performers completing Step B.29 after testing each channel before continuing with the next channel.
They had recognized the procedural weakness and compensated by performing the independent verifications as each channel was tested.
.The test performers documented thei r actions and submitted a request to clarify that portion of the procedure.
c.
Conclusions The inspector concluded that the procedure was performed properly and with satisfactory results.
Procedure 1-IHP-26. 15 contained several steps that were confusing and difficult to follow.
The method for controlling process radiation monitor setpoints was considered to be a
weakness.
H8 Hiscellaneous Haintenance Issues H8. 1 Closed LER 335/96-001-00
"Control Room Emer enc Ventilation S stem Ino erable Due to Im ro er S stem Confi uration 92902 The subject LER discussed an occurrence which caused both trains of the Unit 1 Control Room Emergency Ventilation system to become inoperable.
On February 19.
1996, at approximately 2:25 a.m., the Shift Technical Advisor (STA) entered the Unit 1 Control Room and noticed that air was flowing into the Control Room when the door was open.
The STA informed the Assistant Nuclear Plant Supervisor (ANPS) of the condition and they began to investigate.
The STA found an inlet plenum access hatch to the Electrical Equi.pment Room supply fans open with one of the fans in operation.
The hatch had been opened at 2:20 a.m. for maintenance on the non-operating fan.
The STA also found the inlet plenum hatch and inlet damper for a Control Room air-conditioning unit open.
These had been opened the previous day for maintenance.
The Electrical Equipment Room supply fans share a
common inlet plenum, which is aligned to outside air.
The Control Room air-conditioning
units are located in the same Heating. Ventilation.
and Air Conditioning (HVAC) room as the Electrical Equipment Room supply fans.
With the Electrical Equipment Room fans'nlet plenum hatch open, the operating fan suction was effectively aligned to the HVAC room.
Since the Control Room air-conditioning, plenum hatch and damper were opens the Electrical Equipment Room supply fans were drawing a suction from the Control Room.
This was the cause of the negative pressure in the Control Room.
Maintenance personnel closed the Electrical Equipment Room supply fan lenum hatch at 2:37 a.m.
and the Control Room air-conditioning plenum atch was shut at 2:40 a.m.
Control Room pressure returned to normal.
The licensee performed an assessment to determine the effects on plant operation as a result of this alignment.
They concluded that during the time that all of the abov'e mentioned plenum hatches were open, the Control Room Emergency Ventilation system would not have been able to perform its design function.
The licensee identified the cause of the event as insufficient guidance and work control associated with identifying and maintaining the integrity of the Control Room pressure boundary during the maintenance.
The boundary had been breached while maintenance was being performed on one of the Control Room air-conditioning units.
The boundary had never been clearly defined within the plant processes.
Control Room boundary penetrations had never been clearly labeled or identified in the field.
The licensee established multiple corrective actions for this event.
They identified and labeled all of the Control Room boundary penetrations for Unit 1.
The licensee assessed all other Unit 1 HVAC interactions and identified any potentials for similar problems.
Similar actions were planned to be completed for Unit 2 by February 28, 1998.
The Equipment Clearance Order master clearance orders were upgraded to address activities affecting HVAC system interactions or building integrity.
Operations has placed the plenum keys under administrative control with caution tags that state that HVAC boundaries need to be verified.
The inspector reviewed the corrective actions completed for Unit 1 and found th'em to be thorough.
The Unit 2 corrective actions were equally thorough and should prevent recurrence of the problem.
No TS violations were identified.
The LER was closed.
Closed LER 50-389/96-002-00
"Manual Reactor Tri Due to Hi h Main Generator Cold Gas Tem erature Caused b
Valve Failure" 92902 The subject, LER discussed a manual reactor trip on June 6, 1996, due to a high main generator temperature condition.
At 12:32 p.m., the Operators on Unit 2 received a main generator temperature alarm.
The main generator cold gas temperature quickly reached 53'C.
The Operators tripped the reactor and turbine in accordance with their Off-Normal Operating Procedures to prevent damage to the main generator.
Cold gas temperature returned to normal values following the trip.
The licensee subsequently found the valve that regulates the cooling water flow for the generator gas-had failed shu During the post trip recovery, the Operators noted several anomalies.
Pressurizer level and pressure decreased to less than that usually observed.
The 28 Main Feedwater Pump (MFP) had tripped.
Also, the 2A'FP suction relief lifted. Later'uxiliary Feedwater Actuation System-I (AFAS-1) initiated as designed on a low 2A Steam Generator level.
However, the 2C Auxiliary Feedwater (AFW) Pump.
which had been started during the AFAS-2 actuation, tripped due to overspeed.
Feedwater flow to both steam gen'erators'was maintained by the 2A and 2B AFW pumps.
The primary cause of the high gas temperature was the failure of the positioner feedback arm for the temperature control valve.
The failure caused the valve to shut.
securing cooling water for the hydrogen gas.
The positioner linkage nut had fallen off due to vibration.
The licensee changed the mounting configuration of the valve positioner to minimize the vibration experienced by the valve assembly.
Also, the mechanical feedback arm was removed, eliminating the fai lure mechanism.'he licensee completed similar modifications on the other susceptible temperature control valves.
The licensee removed and inspected the 2A MFP suction relief valve.
They determined that the relief valve setpoint was set too low.
The setpoint was raised to correspond with the vendor's recommendations.
The inspector concluded that the licensee's action to address this issue was adequate.
The licensee determined that the 2C AFW pump tripped on overspeed due to water accumulation in the warmup line being forced into the turbine upon initiation of steam flow from the 2A steam generator.
The licensee completed a modification to the warmup line in June 1996 that should preclude this type of overspeed event again.
FPL evaluated the pressurizer pressure and level response following the trip.
They concluded that the parameters responded as expected considering the upgrade in the Steam Bypass Control system.
They issued a training bulletin to all operating personnel on the new expected system response, and all crews received simulator training.
These actions were, adequate to close out this concern.
A Plant Manager Action Item (PMAI) was initiated to provide circuit logic and cost estimates for implementing a modification to the MFP minimum recirculation flow control valves to improve performance.
.The recommendations from this PMAI included modifying the ci rcuitry to allow the recirculation valves to remain fully open after a turbine trip.
This would ensure that both pumps would have sufficient flow to avoid a
low flow trip. The inspector noted that this recommendation had not yet been scheduled for implementation.
Section 02.3 discusses this concern in greater detail.
The licensee addressed the causal factors for the manual reactor trip and the associated anomalies in the LER.
The LER was close M8.3 M8.4
Closed LER 50-389/96-004-00
"0 eration Prohibited b
Technical S ecifications Due to Missed Surveillance Caused b
Co nitive Personnel
~9" 929II2 This LER discussed an event in which the licensee identified that they had missed a Technical Specification (TS) required surveillance.
On September 23.
1996, a utility non-licensed technician was reviewing TS surveillance records and he noticed that a required stroke time surveillance for two Unit 2 containment vacuum relief valves had not been performed within the requi red periodicity plus grace period.
A review ot the records showed that the valves were stroked and timed satisfactorily on May 15, 1996.
and then again on September 20.
1996.
The requi red periodicity was every 92 days.
The actual interval exceeded the allowable period and grace period by thirteen days.
The licensee's investigation revealed that the surveillance was deferred on August 15, 1996, and rescheduled to coincide with the semi-annual surveillance on September 20, 1996.
This decision was based upon the knowledge that stroke time testing was routinely performed during the semiannual functional test of the differential pressure transmitters for these valves., This had been last performed on June 9, 1996.
However, the licensee did not record the stroke times during that test.
The licensee failed to check any records before deferring the surveillance, and subsequently the surveillance interval was exceeded.
The licensee identified the root cause as a cognitive personnel error.
Corrective actions included reviewing all other surveillance data to ensure no other surveillances were past due.
updating the work order task description for the semiannual funptional test to ensure that the stroke times would be recorded, and upgrading the implementing procedure for TS surveillances to require verification of the last performance date before deferral.
The surveillance requirements associated with the containment vacuum relief valves were specified in TS 4.0.5.
This TS requi red that an in-service testing and inspection would be completed in accordance with Section XI of the ASME Boiler and Pressure Vessel Code-and applicable addenda for code class 1, 2, and 3 pumps and valves.
These valves were class 2 valves and the implementing procedures requi red stroke time testing once every 92 days.
The fai lure to perform a stroke time of the valves per the requi red frequency, including allowable extension time, is identified as a violation.
This non-repetitive, licensee identified and corrected violation is being treated as a Non-Cited Violation.
consistent with Section VII.B of the NRC Enforcement Policy (NCV 50-335,389/98-02-03,
"Failure to Perform a Technical Specification Surveillance Within the Required Periodicity" ).
The LER was closed.
Closed LER 50-335/96-007-00
"Inadvertent Start of the 18 Emer enc Diesel Generator Durin
"B" Channel Containment Isolation Actuation Si nal Testin Due to Procedural Inade uac
"
92902 This event occurred on June 4.
1996, with Unit 1 in Mode 6.
Electrical Maintenance had completed a degraded voltage functional test of the 1BZ
i
480 volt bus.
The activity required the removal of fuses associated with that bus.
however, the procedure did not contain a step to reinstall the fuses at the completion of the test.
On June
~ 1996.
Operations manually initiated a Containment Isolation Actuation Signal (CIAS) to satisfy requi rements of the refueling procedure.
When the CIAS was initiated, the 1B Emergency Diesel Generator (EDG) started and loaded onto its respective bus.
The cause of the EDG auto start was attributed to the inadequate maintenance procedure which failed to include steps to reinstall fuses which were removed as part of the degraded voltage test.
The fuses being pulled resulted in an undervoltage signal existing on the bus.
This undervoltage condition in combination with the CIAS caused an auto start of the associated ED's designed.
The licensee's corrective actions to this event included the following:
Maintenance Procedures MP 1-0970027 and HP 1-0970028, were revised to provide better control of the fuses.
However. since that time those procedures were replaced by 1-EMP-52.02(1-EMP-52.03),
"Channel Calibration And Functional Test Of The A(B) Safety Buses Loss Of Voltage/Degraded Voltage Network."
These procedures prevent the inadvertent auto start of EDGs by lifting wires to the initiation logic cir cuits.
The inspector reviewed Revision 1 to l-EMP-52.02 and 1-EMP-52.03 as well as the associated wiring diagrams and concluded that lifting the wires would prevent an inadvertent EDG auto start;
~
Operating Procedure 1-0910024,
"Crosstying/Removal/Restoration of 480V Buses,"
was revised to provide additional guidance to the operators with regard to what l.oads are affected and what precautions should be taken during the various evolutions.
~
The fuses pulled during the test that resulted in the LER were labeled.
~
Electrical procedures were identified to be revised to include steps i'or ensuring fuses that are removed during the performance of the procedure are replaced upon completion.
The revision of those procedures are being tracked as part of the maintenance procedures upgrade program and is tracked by PMAI 97-01-330.
The inspector reviewed the licensee's corrective action, both completed and proposed and determined that they should be adequate to prevent recurrence.
The LER was closed.
M8.5 Closed LER 50-335/96-008-01
" Inadvertent Actuation of'he Safet In ection Actuation Si nal and Containment Isolation Actuation Si nal Due to Loss of the
VDC Re ulated Power Su l
Durin Maintenance"
~9Z902 On June 8.
1996.
an inadvertent actuation of channel B safety injection actuation signal (SIAS) and containment isolation actuation signal
l
(CIAS) occurred during the performance of maintenance in an engineered safety features actuation system (ESFAS) cabinet.
- The event was caused by a loss of the S3/H3 15 volt power supply to the B channel SIAS and CIAS logic ci rcuits.
The power supply was lost when a fuse cleared while replacing a power supply monitoring card.
In addition, on July 3, 1996, an unexpected B channel recirculation actuation signal (RAS) and containment s'pray actuation signal (CSAS) was generated.
The event occurred while investigating the power supply wiring discrepancies discovered during the previous event.
The actuations occurred when the S4/H4 15 volt power supply was deenergized.
It was considered unexpected because the licensee was not aware that a
loss of that power supply would result in the actuations.
While investigating the two events, the licensee determined that the ESFAS, cabinets were not wired according to the drawings supplied by the vendor.
Each cabinet contains two pairs of 15 volt power supplies, S3/H3 and S4/H4, which provide power for the system logic circuits.
Each pai r is auctioneered which results in two 15 volt supplies.
Additionally, each cabinet contains two pairs of 24 volt power supplies which supply power to the actuation relay ci rcuits and are also auctioneered.
The 15 volt power loads are divided between the two supplies as are the 24 volt power loads.
The vendor manual drawings indicated that the S3/H3 power supply was associated with CSAS and RAS.
However, when that power supply was lost on June 8, 1996, a SIAS and CIAS was initiated.
The licensee reviewed the vendor manual drawings and'the wiring in the field and concluded that the 15 volt loads were not allocated to each power supply as indicated on the drawings.
The licensee concluded that the as found wiring did not affect the ability of the ESFAS to perform its safety function, separation criteria between ESFAS channels.
or the failure modes of the ESFAS considering any single failure.
The inspector discussed this with the licensee and reviewed the applicable drawings, and reached the same conclusion.
On July 3, 1996, during troubleshooting, a
RAS and CSAS occurred when-the S4/H4 power supply was deenergized.
This occurred because the 24 volt power supply to the actuation relays was energized in its normal alignment.
This actuation was not anticipated due to the misconception that the "energize to actuate" signals would not actuate.
This ESFAS resulted in the loss of one LPSI pump which was operating in the shutdown cooling mode, at the time.
Following the event.
the operators
'estored the pump to service.
The licensee modified the wiring in both ESFAS cabinets to agree with the drawings.
The Unit 2 ESFAS wiring configuration was also reviewed.
Precautions were added to both the vendor manuals and the ESFAS cabinets
M8.6 R1 Rl.l
in the field,"regarding the failure mode of the various circuits on a
loss of a 15 volt power supply when a 24 volt power supply is available.
In addition
~ training was provided to operators and maintenance personnel regarding this event.
The inspector considered these corrective actions adequate to prevent recurrence.
The LER was closed.
Closed LER 50-335/96-012-00
"Manual Reactor Tri Due to Increasin Gas Accumulation Indicated on the 1B Hain Transformer" 92902 This LER documented a manual reactor trip due to increasing gas pressure in the 1B Hain Transformer.
On August 31, 1996, the licensee identified an increasing gas accumulation in the 1B main transformer and they commenced a unit shutdown.
During the plant shutdown, gas accumulation continued to increase.
The operators manually tripped the reactor and turbine to preclude a potential fai lure of'he main transformer.
The reactor trip was uncomplicated and all systems functioned as designed.
The licensee determined that the cause of the increased gas accumulation was the intrusion of outside air into the transformer oil cooling system.
The licensee instituted several corrective actions to ensure the replacement coolers were not leaking and FPL Transmission and Distribution upgraded their cooler storage requirements and cooler installation procedures.
The licensee's actions should be'dequate to prevent recurrence of this type of event.
The LER was closed.
IV. Plant Su ort Radiological Protection and Chemistry Controls Secondar Chemistr Ins ection Sco e
84750 The purpose of this inspection effort was to verify the licensee was monitoring plant'hemistry parameters for the replaced Unit 1 Steam Generators (SGs).,
Observations and Findin s The licensee's Chemistry Operating Procedure 03.01,
"Maintaining Steam Generator Chemistry," Revision 0, dated December 22.
1997, provided instructions for maintaining chemistry in all modes.
The inspectors observed chemistry personnel monitoring secondary chemistry parameters over one shift'uring a Unit 1 startup.
In line monitor s and samples of condensate were utilized by the staff to monitor parameters throughout the shift.
With the exception of dissolved oxygen concentration, all parameters were well below normal values.
During the t
startup, the dissolved oxygen levels began trending upwards and were as high as 20 parts per billion (ppb).
Chemistry personnel noted the conditions and increased oxygen scavenger feed to lower the levels below normal values (less than 5 ppb).
The source of the dissolved oxygen was undetermined and the levels later returned to expected levels during the shift.
The inspectors learned that the licensee was making plans to improve secondary chemistry with the use of dimethylamine in the secondary system and was also improving iron transport monitoring procedures.
Licensee representatives reported plans to implement the changes in 1998.
Conclusions Licensee chemistry personnel closely monitored secondary water chemistry parameters during startup to maintain parameters within limits specified in licensee procedures.
Corrective measures for a parameter above its normal value were appropriate and timely.
Trans ortation of Radioactive Materials Ins ection Sco e
86750 The purpose of this inspection effort was to verify a radioactive shipment departing the site during the inspection met applicable regulatory requirements.
Observations and Findin s Title 10 Code of Federal Regulations. (CFR) Part 71.5(a) required a
licensee who delivers licensed material to a carrier for transport, to comply with the applicable requirements of the Department of Transportation (DOT) regulations in 49 CFR Parts 170 through 189 appropriate to the mode of transport.
The inspectors reviewed a radioactive waste shipment offered for transport on January 29.
1998.
The inspectors verified the licensee had prepared appropriate shipping papers for a shipment of spent resin delivered to a carrier for transportation to a low level radioactive waste disposal facility.
The inspectors performed independent radiation surveys of the transport vehicle and found radiation levels less than applicable transportation limits.
The inspectors verified the transport vehicle was properly placarded.
Conclusion An inspected shipment of radioactive waste was properly prepared and met applicable Nuclear Regulatory Commission (NRC) and DOT shipping requirements.
Licensee personnel having responsibilities for transporting radioactive materials at St Lucie were very knowledgeable in the applicable NRC and DOT shipping regulation Rl. 3 R2 R2.1
Locked Hi h Radiation Area Ins ection Ins ection Sco e
71750 The inspector reviewed the licensee's locked High Radiation Area (HRA)
controls and implementation of the plan.
The inspector verified that all locked HRA were properly posted and secured.
Observations and Findin s The inspector reviewed Health Physics Procedures HPP-3.
Revision 6,
HPP-4, Revision 6, "Scheduling of Health Physics Activities," and HP-2, Revision 11,
"FP8L Health Physics Manual.-
HPP-3 contained the details for the control of locked HRA.
Specifically, the procedure required that the locked HRA keys were maintained in the North and East Security buildings with a current list of people authorized to hold the keys.
The inspector verified that.the logs were maintained and the authorization lists were current.
No discrepancies were noted.
The inspector reviewed the latest radiation surveys conducted by the licensee.
Based on these surveys.
the licensee had identified all of the locked HRAs properly.
The inspector then verified that all identified locked HRAs were properly posted and secured.
Also, the inspector c'onfirmed that the waste decay tank rooms were being controlled as a locked HRA, as required by HPP-4.
Again, no discrepancies were identified.
Conclusions The inspector concluded that the licensee was adequately meeting all requirements for controlling and posting locked high radiation areas.
Status of Radiation Protection and Chemistry Facilities and Equipment Radiation Monitorin S stem Ins ection Sco e
84750 The inspectors reviewed licensee Condition Reports (CRs) concerning the Radiation Monitoring System (RMS) that were initiated in 1997 to determine the nature of system problems and to identify trends in system performance.
Observations and Findin s Problems with the operability and maintenance of the RMS have resulted in the Unit 2 RMS and the Unit 1 Plant Vent Monitors being placed into Maintenance Rule A(1) status.
. The RMS includes area, process control, and radiological effluent monitors.
There are approximately 53 monitors on Unit 1 and 64 monitors on Unit 2.
The equipment for the Unit 1 and 2 RMS differ and were provided from different vendors.
The Unit 1 system is maintained by the
R7
~
Instrumentation and Control (IKC) Department and the Unit 2 system is maintained by the Chemistry Department.
The licensee plans to have the IKC department maintain both systems in the future.
In the last 18 months, additional resources have been provided in support of the RMS.
A system engineer.
having other system responsibilities, was assigned to the RMS in the fall of 1996 and there was a Radiation Monitoring Reliability Team that was formed to make improvements in the RHS performance.
Additional 18C personnel have also been assigned to RHS maintenance activities, however, those personnel had.not completed the qualification program and were required to work under supervision of qualified technicians.
While the licensee has recently taken measures.to improve the reliability of the system it has progressed slowly.
The inspectors found that RMS monitors having Technical Specifications (TSs)
and Offsite Dose Calculation Manual (ODCM) operability and surveillance requirements generally received some resource priority.
The licensee had recently completed a System Engineering 1997 Self Assessment of the Unit 2 Radiation Monitor System, dated January 29.
1998, which did a
good job of documenting the status of the Unit 2 RHS and the maintenance and engineering support problems.
In addition to the work orders and engineering request prepared in 1997, approximately
CRs were also initiated for problems concerning the RHS.
System problems varied and individually were generally minor in significance.
The CRs addressed a wide variety of issues including hardware.
software, design, documentation.
and procedure problems.
The inspectors found the quantity of work to eliminate the problems was significant and the corrective actions for those problems were repeatedly delayed.
The TS survei llance and repair of "out-of-service" equipment were consuming most of the staff's resources, leaving few resources for corrective maintenance of non-TS equipment and performance of non-TS survei llances.
Request for Engineering Assistance to address equipment design deficiencies.
NRC commitments, Final Safety Analysis Report and Regulatory Guide 1.97 discrepancies were repeatedly delayed.
Conclusions The licensee has made some improvements in the RMS.
However. the lack of resources and priority for the system has resulted in continued delays of system performance improvements.
Quality Assurance in Radiation Protection and Chemistry Activities ualit Assurance Audits and Sur veillance of Chemistr and Radiolo ical Effluent Monitorin Pro rams Ins ection Sco e
84750 The review was made to determine whether the chemistry and*radiological effluent program audits identified programmatic weaknesses and assessed
the quality of the program.
The-review also evaluated the adequacy of the licensee's corrective actions for identified weaknesses.
b.
Observations and Findin s The inspector s reviewed recent audits and survei llances performed by 'the Quality Assurance Department related to the chemistry and radiological effluent monitoring programs.
The inspectors reviewed:
QSL-CHN-96-16, Chemistry Functional Area Audit, completed October 4, 1996; and QSL-EFF-97-01. Offsite Dose Calculation Manual/Process Control Procedure/Effluents, completed May 21.
1997.
The inspectors found both audits had identified programmatic issues.
The 97-01 audit was very good and had identified several program weaknesses that the inspectors found to be very accurate.
The proposed corrective actions for identified findings were proper and comprehensive.
The inspectors reviewed the audit plan, auditor qualification documentation, and audit checklist for the most recent audit (QSL-EFF-97-01)
and found all audit documentation and records were in order.
Conclusions The quality of recent audits of the chemistry and radiological effluent programs was very good.
The audit findings were accurate and licensee responses to the audit findings were comprehensive.
As a result. the quality of the chemistry and radiological effluent monitoring programs were strengthened through the quality audit processes.
R7.2 a'.
Chemistr De artment Self Assessments Ins ection Sco e
84750 The review was made to evaluate whether the Chemistry Department was performing self-assessments and correcting identified problems.
Observations and Findin s The inspectors found that the licensee had conducted four planned survei llances of department activities and had also performed several assessments in response to events occurring during the year.
The most significant.self-assessment concerned the Chemistry Department's organization and responsibilities.
As a result of that review. the licensee was reassessing and proposing responsibilities, not directly related to nuclear chemistry, be transferred to an appropriate organization.
The licensee was also looking at processes such as processing makeup water to find more efficient methods of accomplishing the tas Conclusions
R8.1 The Chemistry Oepartment was making program improvements through the self-assessment process.
Miscellaneous Radiation Protection and Chemistry Issues Instrumentation and Control Technician Trainin and ualifications 92904 In a previous inspection, inspectors found that the licensee had not qualified the I8C technicians prior to assigning them the responsibility to maintain the.RMS on Unit 1.
The failure to provide training in accordance with the requirements of the licensee's TS and implementing procedures was identified as Violation 50-335/96-17-02,
"Failure to Provide I8C Technicians Training on Calibration Methodologies for Plant Radiation Monitors and Plant Radiation Monitoring Systems."
The licensee developed a training plan and committed to complete the training by March 31.
1997.
The inspectors verified that the licensee had completed the training for the three technicians in the group when the licensee's corrective action response to the violation was prepared.
.The VIO was closed.
Ouring the review of the licensee's corrective actions, th'e inspectors identified some concerns with the training and qualificatio'n of I8C personnel that indicated additional training may be needed.
For example, a condition report documented an I&C technician's improper removal of effluent monitor filter paper'indicating a lack of understanding concerning the importance of the filter in radiological effluent accountability.
There were additional cases in which the filters were installed improperly.
Additionally, a RHS self-assessment reported the I&C technicians lacked expertise to troubleshoot RMS electrical boards.
The inspector also learned that the group had grown and a total of approximately ten I&C technicians were performing some maintenance on the RMS.
The group was divided into a Unit 1 and Unit 2 staff each having three assigned technicians full time.
The other technicians were auxiliary support as needed.
The unqualified I8C personnel were to be performing activities under the guidance of qualified personnel.
The inspectors found that the licensee had not qualified any of the additional I8C personnel assigned to the RHS group.
Licensee personnel reported that the Unit 2 refueling outage and the Unit 1 Steam Generator Replacement Project had significantly limited training activities in 1997.
Additionally, the I&C staff planned to complete the Unit 2 I8C RMS maintenance and calibration procedures before training and qualifying I&C personnel assigned to the Unit 2 RMS.
The licensee planned to complete the procedures in 199 P3
Status of EP Facilities, Equipment, and Resources Faci lit Ins ection Ins ection Sco e
82701 The inspectors examined the licensee's emergency response facilities (ERFs)
and equipment to assess their adequacy and to determine (1) whether they were maintained in a state of operational readiness as specified in the St. Lucie Radiological Emergency Plan (REP),
and (2) whether ERF changes made since the last such inspection (Harch 1997)
were technically adequate and in accordance with NRC requirements and licensee commitments.
Observations and Findin s The inspectors toured the Unit 1 Control Room, Technical Support Center (TSC). Operational Support Center (OSC),
and Emergency Operations Facility (EOF).
Selected equipment and supplies within these facilities were inspected.
All tested equipment was found to be in operable condition.
The facilities were well maintained.
A significant facility improvement since the last inspection was a video link from the TSC to the OSC and EOF.
Conclusions ERFs were well equipped and were maintained at a suitable level of operational readiness.
EP Procedures and Documentation P3.1, Emer enc Res onse Plan Ins ection Sco e
82701 The inspectors reviewed the licensee's maintenance of the REP and selected commitments therein, and reviewed recent revisions to the REP to determine whether changes were made in accordance with 10 CFR 50.54(q).
Observations and Findin s, The REP in effect at the time of the current inspection was Revision 34, effective February 3, 1998.
Revision 33, effective June 6, 1997, had also been issued and superseded since the last routine EP inspection in Harch 1997.
The inspectors'eview of Revisions 33 and 34 determined that the changes were primarily editorial or administrative in nature.
Changes of substance had been reviewed and did not constitute a
reduction in the effectiveness of the REP.
An Emergency Action Level (EAL) change that addressed unidentified reactor coolant system (RCS)
leakage had been formally approved by the NRC prior to implementatio c p5 P5.1
The licensee had also made changes to its implementing procedures which focused on making them more user-friendly.
Oocumentation was reviewed that confirmed the concurrence of offsite authorities in the EAL change The licensee had made one emergency declaration since the March 1997 inspection.
The declaration was a Notification of Unusual Event on Apnl 19, 1997, resulting from RCS pressure boundary leakage.
The inspectors examined documentation for this event and concluded that it was correctly classified based on the license'e's EALs, and that notifications to cognizant offsite authorities were made in accordance with requirements regarding timeliness and content.
Conclusions Changes to the Plan via Revisions 33 and 34 were made in accordance with
CFR 50.54(q).
The emergency declaration made on April 19, 1997.
was made in accordance with the EPIPs.
Staff Tr aining and Qualification in EP Trainin of Emer enc Res onse Personnel Ins ection Sco e
82701 The inspectors reviewed the training program for the ERO and interviewed designated key responders to determine whether emergency response, personnel were properly trained and understood thei r assigned responsibilities under the REP.
Observations and Findin s The inspectors reviewed the REP training commitments (Section 7.2)
and Procedure EPIP-12,
"Maintaining Emergency Preparedness
- Radiological Emergency Plan Training," Revision 1.
The training program included the requirement for specialized training courses (specified in position-to-course matrices in EPIP-12) for all ERO personnel.
The inspectors selectively reviewed the lesson plans and student handouts used for the various emergency response training topics.
These materials were developed since October 1996 to replace the previous ERO training program, which primarily entailed self-study of a package of applicable EPIPs (an approach commonly known as
"read and sign").
Furthermore, all of the lesson plans and handouts were revised in December 1997 or January 1998 to incorporate the upgraded EPIPs.
The training materials clearly delineated the duties and responsibilities of ERO personnel during an emergency response.
Overalls the changes made to the ERO training program since October 1996 constituted a major improvement over the previous and longstanding-read and sign" methodology, and the inspectors. commended licensee management for its commitment to this projec p6 P6.1
In January 1997, the licensee began conducting quarterly integrated response drills to further enhance the training for ERO personnel.
This drill program was documented as a licensee commitment in Procedure EPIP-12 (formerly issued as EPIP-3100034E),
Revision 1.
An effort was being made by the EP staff (as specified in EPIP-12) to provide drill experience to as many ERO personnel as possible through the rotation of players from one drill to the next.
In an effort to gauge the effectiveness of the emergency response training program for Control Room SROs (the, position designated as interim Emergency Coordinator at the outset of an event), the inspectors interviewed one Nuclear Plant Supervisor (NPS)
and one Assistant NPS.
These extensive interviews (lasting 70 minutes and 110 minutest respectively)
were designed to ascertain the designated EC's understanding of emergency classification, offsite notifications, protective action recommendations, site evacuation.
emergency worker dose limits. and nondelegable responsibilities of the EC.
Various technical questions involving these subject areas were presented to each interviewee, as well as several plant-specific accident scenarios.
The Emergency Preparedness Supervisor was present during the inter views to facilitate the licensee's firsthand understanding of any issues that arose.
Each interviewee demonstrated comprehensive understanding of his duties and responsibilities as EC; emergency classifications and PARs were timely and correct.
The methodology for training SROs for the EC position appeared to be very effective.
Conclusions The licensee's ERO training program was in accordance with the REP training commitments and with the intent of NRC regulatory requirements and guidance.
Hajor improvements in this program had been developed and implemented during the past 15 months.
The conduct of quarterly integrated drills during 1997 enhanced the quality of ERO training.
EP Organization and Administration EP Or anization and Administration Ins ection Sco e
82701 The inspectors reviewed this area to determine if any changes in management or personnel had occurred which could adversely affect the management and implementation of the emergency p'reparedness program.
Observations and Findin s The organization and management of the EP program were reviewed and discussed with licensee management representatives.
The organizational relationship between the EP Supervisor and upper plant management had not changed since the last EP inspection.
Some organizational changes had been made just before the inspection; however.
these changes did not
P7 P7.1 P7.2
alter the ERO.
The EP Supervisor was maintaining a dialogue with management so as to be promptly apprised of any organizational changes that could affect the ERO.
Conclusions No degradation had occurred in the organization or management of the EP program.
Quality Assurance in EP Activities
CFR 50.54 t Audit of Emer enc Pre aredness Pro ram Ins ection Sco e
82701
The inspectors reviewed this area to assess the quality of the required annual audit of the emergency preparedness program, and to verify that the audit met the requirements of 10 CFR 50.54(t).
Observations and Findin s The inspectors reviewed documentation associated with the following EP program audit conducted by the licensee's Quality Assurance (QA) group:
~
QSL-EP-97-05, conducted March 3 - July 13, 1997 This audit was judged to be thorough and independent.
and the nature of the 'identified issues indicated inclusive understanding of the EP area by the auditors.
The audit provided evidence of the licensee's ability to self-identify emergency preparedness program deficiencies.
Conclusions The 1997 EP program audit fully satisfied the
CFR 50.54(t)
requirement for an annual independent audit of the EP program.
Effectiveness of Licensee's Corrective Action Pro ram for EP Issues Ins ection Sco e
82701 The inspectors reviewed this area to evaluate the licensee's program for identifying, tracking; and resolving problems in emerge'ncy preparedness.
Observations and Findin s The licensee formally identified and tracked EP issues by means of Condition Reports (CRs)
and Plant Manager Action Items (PMAIs).
Many more items in both categories were generated in 1997 than in 1996 as a
result of'he licensee's efforts to correct numerous EP program deficiencies.
The EP staff alone originated
CRs during 1997.
Review
P8 P8.1 S2.1 of records for a small sample of. CRs and PHAIs indicated that these systems were being used effectively for the identification and resolution of EP problems and issues.
Self-assessment in EP was performed under Department Instruction DI-EP-06,
"Emergency Planning Continual Assessment Program." Revision 0.
This process (begun in early 1997) involved quarterly assessments of EP in 13 program areas, for each of which specific criteria were defined for the determination of status (namely, green. white, yellow, or red).
None of the 13 areas were red or yellow for the fourth quarter of 1997.
Conclusions The licensee's program for identifying, tracking, and resolving problems in EP was effective.
Self-assessments were useful in focusing licensee staff and management attention on problem areas.
Hiscellaneous EP Issues Closed VIO 50-335 389/EA-96-464/02033
"ERO Trainin Pro ram Not Ade uatel Im lemented" 92904 This finding remained open following a Harch 1997 EP program inspection pending NRC confirmation of implementation of Procedure EPIP-12 (formerly issued as EPIP-3100034E);
completion of the upgraded ERO training program:
and implementation of Procedure QI-5-PSL-1 (formerly issued as QI 5-PR/PSL-1),
"Preparation, Revision, Review/ Approval of Procedures,"
a procedure which addressed the requirement for pre-implementation training on revised EPIPs containing substantive changes.
The inspectors independently confirmed that the licensee had completed appropriate actions for the issues listed above.
(For details regarding the training program, see Section P5. 1. above.}
This item is closed.
Status of Security Facilities and Equipment Protected Area Fence Malkdown 71750 The inspector conducted a walkdown of the protected area fence on January 12, 1998.
Areas observed were found to be in good repair and free of openings in excess of regulatory guidelines.
Isolation zones were free of obstruction.
V. Hang ement Heetin s and Other Areas X1 Exit Heeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on February 17, 1998.
Interim exit meetings were held on January 30 and February 13, 1998 to discuss the findings of Region based inspection.
The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.
No proprietary information was identified.
X1.1 Review of INPO Re ort 71707 The inspector reviewed the Institute of Nuclear Power Operation's (INPO's),
"Evaluation of St. Lucie Nuclear Plant." dated March 1997, as modified by FPL's responses and circulated within the site by memo dated January 7.
1997.
The inspector found that the evaluation did not indicate strengths or limitations which differed from the NRC's assessment of the facilit ls la
Licensee
PARTIAL LIST OF 'PERSONS CONTACTED M. Allen. Training Manager C. Bible, Site Engineering Manager W. Bladow, Site Quality Manager G. Boissy, Materials Manager H. Buchanan, Health Physics Supervisor D. Fadden, Services Manager R. Heroux, Business Manager H. Johnson, Operations Manager J.
Harchese, Maintenance Manager C. Harple, Operations Supervisor J. Scarola, St. Lucie Plant General Hanager A. Stall, St. Lucie-Plant Vice President E.
Weinkam, Licensing Manager W. White, Security Supervisor Other licensee employees contacted included office, operations, engineering, maintenance, chemistry/radiation, and corporate personnel'.
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 82701:
IP 84750:
,IP 92901 IP 92902 IP 92904 INSPECTION PROCEDURES USED Surveillance Observations Maintenance Observations Plant Operations Plant Support Activities Operational Status of the Emergency Preparedness Program Radioactive Waste Treatment.
and Etfluent and Environmental Monitoring Solid Radioactive Waste Management and Transportation of Radioactive Materials Followup - Plant Operations Followup - Maintenance Followup - Plant Support
~0eeed 50-335/98-02-01 50-335/98-02-02 50-335.389/98-02-03 01osed 50-335/98-02-02 50-335,389/98-02-03 50-335/96-17-02 50-335,389/EA-96-464/
02033 50-335/97-01-01 50-335/96-001-00 ITEMS OPENED, CLOSED, AND DISCUSSED IFI
"Feedwater Recirculation Valve Corrective Actions" (Section 02.3).
"Failure to Satisfy the Requirements of Technical Specification 3.5.3" (Section 08.3)
"Failure to Perform a Technical Specification Surveillance Within the Required Periodicity" (Section M8.3).
"Failure to Satisfy the Requirements ot Technical Specification 3.5.3" (Section 08.3).
"Failure to Pertorm a Technical Specification Surveillance Within the Required Periodicity" (Section M8.3).
"Failure to Provide 18C Technicians Training on Radiation Monitoring Systems and Calibration Methodologies" (Section R8. 1).
"ERO Training Program Not Adequately Implemented" (Section P8. 1).
"Failure to Follow In-Plant Equipment Clearance Orders Procedure" (Section 08.5).
LER
"Control Room Emergency Ventilation System Inoperable Due to Improper System Configuration" (Section H8.1)
.
50-389/96-002-00 50-389/96-004-00 50-335/96-005-00 50-389/96-002-00 50-335/96-007-00 50-335/95-008-00 50-335/96-008-01 50-335/96-009-00 50-335/96-012-00 50-335/96-013-00 50-335/98-001-01 50-335/98-003-00 50-335/96-08-01 LER LER LER LER LER LER LER LER LER LER LER LER NCV
Manual Reactor Trip Due t'o High Hain Generator Cold Gas Temperature Caused by Valve Failure" (Section H8.2).
"Operation Prohibited by Technical Specifications Due to Hissed Surveillance Caused by Cognitive Personnel Error" (Section H8.3).
"Wide Range Nuclear Instrumentation Channel Inoperable When Required to Be in Service for Fuel Movement" (Section 08.2).
"Manual Reactor Trip Due to High Hain Generator Cold Gas Temperature Caused By Valve Failure" (Section 02.3).
"Inadvertent Start of the 1B Emergency Diesel Generator During "B Channel Containment Isolation Actuation Signal Testing Due to Procedural Inadequacy" (Section M8.4).
"High Pressure Safety Injection Pump Operation During Plant Conditions Not Allowed by Technical Specifications Due to Personnel Error" (Section 08.3).
"Inadvertent Actuation of the Safety Injection Actuation Signal and Containment Isolation Actuation Signal Due to Loss of the
VDC Regulated Power Supply During Maintenance" (Section H8.5).
"Operation Prohibited by Technical Specifications Due to Procedural Inadequacy and Personnel Error" (Section 08.3).
"Manual Reactor Trip Due to Increasing Gas Accumulation Indicated on the 18 Hain Transformer" (Section M8.6).
"Operation Prohibited by Technical Specifications Due to Failure to Bypass An Inoperable Engineered Safety Feature Channel Within the Required Action Time" (Section 08.4).
" Inadvertent RPS Actuation Due to Personnel Error" (Section 08.6).
Manual Reactor Trip Due to a Digital Electro-Hydraulic (DEH) Leak at the Turbine Test Block" (Section 02.3).
"Failure to Maintain Operability of Two Wide
50-335/96-15-02
Range Nuclear Instruments During Fuel Hovement" (Section 08.2).
" Inadvertent Bypassing of the Wrong ESFAS Signal" (Section 08.4).
Discussed 50-389/95-002-00 50-335/95-003-01 LER-Automatic Reactor Trip on Low Steam Generator Water Level Due to a Failed Level Transmitter" (Section 02.3).
LER
"Automatic Reactor Trip During Turbine Overspeed Surveillance Testing Due to Personnel Error" (Section 02.3).
NOTE: Attached is an ENFORCEHENT DISPOSITION TABLE which documents for record purposes the closure of identified EEIs and requires no response from the licensee.
Following Predecisional Enforcement Conferences or the evaluation of the licensee responses to each apparent violation, a
Notice of Violation (NOV) was issued.
Based on the NOV issued, the Escalated Enforcement Issues (EEIs) are closed.
The cited violations are identified in the NOV and are being tracked per the following Enforcement Disposition Table as Enforcement Actions (EAs).
Each individual NOV has a specific NOV ID Number.
LIST OF ACRONYHS USED ADH AFAS AFW ANPS AP ASHE Code ATTN BFP CEA CFR CIAS CR CSAS DEH DOT DPR EAL ECCS ECO EDG Administrati ve Procedure Auxiliary Feedwater Actuation System Auxiliary Feedwater (system)
. Assistant Nuclear Plant Supervisor Administrative Procedure American Society of Hechanical Engineers Boiler and Pressure Vessel Code Attention Boration Flow Path Control Element Assembly Code of Federal Regulations Containment Isolation Actuation Signal Condition Report Containment Spray Actuation System Digital Electro-Hydraulic (turbine control system)
Department of Transportation Demonstration Power Reactor (A type of operating license)
Enforcement Action Emergency Action Level Emergency Coordinator Emergency Core Cooling System Equipment Clearance Order Emergency Diesel Generator
EOF EOP EP EPIP ERF ERO ERT ESFAS F
FPL FR FRG HP HPP HPSI HRA HVAC I8C IFI INPO IP IR LCO LER LIS LS MFP MFRV MFW NCV NLO NOP NPF NPS NRC ODCM ONOP OP PDR PMAI ppb psia PSL QA QI QSL RAS RCO RCP RCS REA REP RII
Emergency Operations Facility Emergency Operating Procedure Engineering Package Emergency Plan Implementing Procedure Emergency Response Facility Emergency Response Organization Event Response Team Engineered Safety Feature Actuation System Fahrenheit The Florida Power 8 Light Company Federal Regulation Facility Review Group Health Physics Health Physics Procedure High Pressure Safety Injection (system)
High Radiation Area Heating Ventilation and Air Conditioning Instrumentation and Control
[NRC3 Inspector Followup Item Institute for Nuclear Power Operations Inspection Procedure
[NRC3 Inspection Report TS Limiting Condition for Operation Licensee Event Report Level Indicating Switch Level Switch Main Feed Pump Main Feedwater Regulating Valves Main Feed Water Non Cited Violation (of NRC requirements)
Non-Licensed Operator Normal Operating Pressure Nuclear Production Facility (a type of operating license)
Nuclear Plant Supervisor Nuclear Regulatory Commission Offsite Dose Calculation'anual Off Normal Operating Procedure Operating Procedure NRC Public Document Room Plant Management Action Item Part(s)
per Billion Pounds per square inch (absolute)
Plant St. Lucie Quality Assurance Qual,ity Instruction Quality Surveillance Letter Recirculation Actuation Signal Reactor Control Operator Reactor Coolant Pump Reactor Coolant System Request for Engineering Assistance Emergency Radiological Plan Region II - Atlanta, Georgia (NRC)
C'
RMS RPS RTB RWT SCE SG SIAS SRO St.
STA STAR SUR TEDB TS TSC UFSAR VIO ZPMB
Radiation Monitor System Reactor Protection System Reactor Trip Breaker Refueling Water Tank Systems and Component Engineering Steam Generator Safety Injection Actuation System Senior Reactor flicensed] Operator Saint Shift Technical Advisor St. Lucie Action Request Startup Rate Total Equipment Data Base Technical Specification(s)
Technical Support Center Updated Final Safety Analysis Report Violation (of NRC requirements)
Zero Power Mode Bypass
ENFORCEMENT DISPOSITION TABLE This information is being provided for record purposes to close identified EEI's and requires no response from the licensee.
Following Predecisional Enforcement Conferences or the evaluation of the licensee responses to each apparent violation, a Notice of Violation (NOV) was issued.
Based on the NOV issued.
the Escalated Enforcement Issues (EEIs) are closed.
The cited violations are identified in the NOV and are being tracked per the following Enforcement Disposition Table as Enforcement Actions (EAs).
Each individual NOV has a specific NOV ID Number.
EEI NO.
389/96-12-01 (Renumbered to 389/96-12-06)
TITLE.
Failure to Perform a
10 CFR 50.59 Safety Evaluation for CEDHCS Enclosure EA NO.96-236 NOV IO NO.
Withdrawn TITLE 335,389/96-12-02 Failure to Perform a
CFR 96-236 50.59 Safety Evaluation For Use of a Temporary Fire Pump Withdrawn 335/96-12-03 389/96-12-04 335 '89/96-12-05 Failure to Perform a
10 CFR 50.59 Safety Evaluation For Change in Setpoints Listed in UFSAR Unreviewed Safety Question Involving EDG 28 Failure to Ensure Configuration Control 96-236 96-236 96-249 Withdrawn VIO 01013 VIO 02014 VIO 03014 Unreviewed Safety Question Involving EDG 2B Failure to Update Annunciator Response Procedures Failure to Update Drawings Following Plant Hodification NCV 335/96-12-01 Failure to Incorporate SFP Heat Load Calculation Re uirements
C'
l~l 0