IR 05000250/1994001
| ML17352A453 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 02/15/1994 |
| From: | Binoy Desai, Johnson T, Landis K, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17352A452 | List: |
| References | |
| 50-250-94-01, 50-250-94-1, 50-251-94-01, 50-251-94-1, NUDOCS 9402280094 | |
| Download: ML17352A453 (51) | |
Text
~y,S REgy (4
@
~ ~0
++**+
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900 ATLANTA,GEORGIA 30323-0199 Report Nos.:
50-250/94-01 and 50-251/94-01 Licensee:
florida Power and Light Company 9250 West Flagler Street Hiami, fL 33102 Docket Nos.:
50-250 and 50-251 License'os,:
DPR-31 and DPR-41 Facility Name:
Turkey Point Units 3 and
Inspection Conducted:
Ja uary 1-29, 1994 Inspectors:
T.
P.
J hns
, Sen'o es'dent Inspector D te ign d
i n
Ins ector Da e
S gn d
L.
rocine, ident nspector Da e
S gn d
t Accompanying Personnel:
J.
F. King, Headquarters Intern L.
P. King, Reactor Engineer, Operational Programs Section, Division of Reactor Safety Approved by:
K. D.
L dis, Chief Reactor Projects Section
Division of Reactor Projects Z
Da e Signed SUMMARY Scope:
This resident inspection to assure public health and safety involved direct inspection at the site in the areas of operational safety, plant events, maintenance observations, surveillance observations, followup on previous items, review of written reports, engineered safety features walkdowns, self assessment, and design changes and modifications.
Backshift inspections were performed in accordance with Nuclear Regulatory Commission policy.
Results:
Within the scope of this inspection, the inspectors determined that the licensee continued to demonstrate satisfactory performance to ensure safe plant operations'he following non-cited violation was identified:
9402280094 940215 PDR ADOCK 05000250 PDR
Non-Cited Violation 50-250,251/94-01-01, overdue medical examinations for licensed individuals (section 4.2. 1).
During this inspection period, the inspectors had comments in the following Systematic Assessment of Licensee Performance functional areas:
Operations Unit 3 was appropriately taken off line following a main condenser, tube leak which caused high conductivity levels on the secondary plant (sections 3. 1 and 5.2.4).
The licensee's response to its identification of overdue medical examinations for five licensed individuals was timely, and the scheduled long-term corrective actions are appropriate.
This issue resulted in the issuance of a non-cited violation (section 4.2. 1).
The licensee appropriately dealt with a condition of less than optimum reactor coolant pump seal leak off flow (section 4.2.2).
During routine tours and observations, the inspector noted that the licensee demonstrated safe plant operation (section 4.2.6).
Operator response to main generator voltage regulator transients was conservative (section 5.2.5).
Operator cognizance of and performance during a Unit 4 spent fuel pool cooling outage was very good.
Strong teamwork and effective quality assurance coverage were also noted (section 6.2.5).
Open items concerning emergency and off-normal procedures were closed (sections 8.2. 1 and 8.2.2).
The control room emergency ventilation system and the intake and component cooling water systems were appropriately aligned (sections 4.2.5 and 10,0).
Strong and pro-active licensee self-assessment was noted relative to the periodic Turkey Point status meeting, the Company Nuclear Review Hoard meeting, and the monthly safety meeting (sections 11.2. 1, 11.2.2, and 11.2,3).
Maintenance and Surveillance Maintenance and surveillance activities witnessed by the inspectors were well performed (sections 6.2. 1 and 7.2. 1).
Strong maintenance performance by workers and supervisors was noted during a valve packing leak repair, a reactor protection system relay replacement, the 4H safety injection pump motor replacement, and the Unit 4 spent fuel pool outage (sections 6.2.2, 6.2.3, 6.2.4, and 6.2.5).
En ineerin and Technical Su ort The licensee conservatively and aggressively pursued resolution of the emergency containment cooler outlet valve failures.
Management involvement and thoroughness of involved licensee technical staff members were evident (section 5.2. 1).
Engineering and technical support during the troubleshooting and repair activities relating to a repeat failure of the 4B emergency diesel generator were conducted in an efficient and conservative manner (section 5.2.2).
Engineering support for main generator voltage regulator system induced power oscillations was timely, thorough, and appropriate (section 5.2.5).
The licensee had previously appropriately documented an abnormal intake cooling water system deficiency; however, the inspector noted a program enhancement
relative to the safety evaluation screening process (section 12.2. 1).
The inspector noted minor Updated Final Safety Analysis Report deficiencies concerning the intake cooling water system (section 12.2.1).
Plant Su ort Radiation Controls Emer enc Pre aredness Securit Chemistr Fire Protection Fitness For Out and Housekee in Controls The NRC performed security program reviews and evaluations associated with operational safeguards response and land vehicle bomb response (section 4.2.3).
The pre-fire plan off-normal operating procedure for the control room ventilation mechanical equipment room did not list the charcoal adsorber material as a fire hazar'd (section 4.2.5).
The licensee appropriately responded to a security event which involved an inadvertent weapon discharge (section 5.2.3).
Health physics coverage of the Unit 4 spent fuel. pool cooling outage and associated work was thorough and effectively conducted (section 6.2.5).
TABLE OF CONTENTS C
1.0 Persons Contacted 1.1 Licensee Employees 1.2 NRC Resident Inspectors 1.3 Other NRC Personnel On Site 2.0 Other NRC Visits During This Period
~3.0 Plant Status 3.1
-
Unit 3 3.2 Unit,4 4.0 Operations
1
1
2 5.0 4.1 4.2 Inspection Scope Inspection Findings Plant Events 5. 1 Inspection Scope 5.2 Inspection Findings 6.0 Maintenance Observations 6. 1 Inspection Scope 6.2 Inspection Findings 7.0 Surveillance Observations 7. 1 Inspection Scope 7.2 Inspection Findings 8.0 Followup on Previous Items and Noncompliances 8. 1 Inspection Scope 8.2 Inspection Findings
14
16
17
17 9.0 Onsite Followup and In-Office Review of Written Reports 9. 1 Inspection Scope 9.2 Inspection Findings
19
10.0 Engineered Safety Features Walkdown 10.1 Inspection Scope 10.2 Inspection Findings
24
. 11.0 Evaluation of Licensee Self-Assessment Capability
Cl
Table of Contents ll.1 Inspection Scope 11.2 Inspection Findings 12.0 Design, Design Changes, and Modifications 12 '
Inspection Scope 12.2 Inspection Findings 13.0 Exit Interviews 14.0 Acronyms and Abbreviations
25
26
28
1.0
. Persons Contacted REPORT DETAILS Licensee, Employees T. V.
R. J.
C.
R.
W.
H.
H. J.
S.
H.
J.
E.
R. J.
R.
G.
P.
C.
G.
E.
D.
E.
H.
H.
V. A.
J.
E.
J.
E.
R.
S.
J.
D.
J.
Ha F.
E.
H.
N.
L.
W.
M. 0.
T.
F.
D..R.
R.
E.
R.
N.
H.
B.
E. J.
T. L.
Abbatiello, Site guality Manager Acosta, Company Nuclear Review Board Chairman Bible, Site Engineering Manager (Acting)
.Bohlke, Vice President, Engineering and Licensing Bowskill, Reactor Engineering Supervisor Franzone, Instrumentation and Controls Maintenance Supervisor Geiger, Vice President, Nuclear Assurance Gianfrancesco, Maintenance Support Services Supervisor Heis'terman, Mechanical Maintenance Supervisor Higgins, Outage Manager Hollinger, Training Manager Jernigan, Operations Manager Johnson, Operations Supervisor Kaminskas, Services Manager Kirkpatrick, 'Fire Protection/Safety Supervisor Knorr, Regulatory Compliance Analyst Kundalkar, Engineering Manager Lindsay, Health Physics Supervisor rchese, Site Construction Manager Harcussen, Security Supervisor Paduano, Manager, Licensing and Special Projects Pearce, Plant General Manager Pearce, Electrical Maintenance Supervisor Plunkett, Site Vice President Powell, Technical Manager Rose, Nuclear Materials Manager Steinke, Chemistry Supervisor Wayland, Maintenance Hanager Weinkam, Licensing Manager Wogan, Operations Support Supervisor Other licensee employees contacted included construction craftsman, engineers, technicians, operators, mechanics, and electricians.
1.2 NRC Resident Inspectors 1.3 B.
B. Desai, Resident Inspector
- T.
P, Johnson, Senior Resident Inspector L. Trocine, Resident Inspector Other NRC Personnel on Site J.
F. King, Headquarters Intern L. P. King, Reactor Engineer, Operational Programs Section, Division of Reactor Safety
K. D. Landis, Chief, Reactor Projects Section 2B, Division of Reactor Projects
Attended exit interview on February 1,
1994 Note:
An alphabetical tabulation of acronyms used in this report is listed in the last paragraph in this report.
2.0 Other NRC Visits During This Period Dates Area Evaluated January 10-13, 1994 Operational Safeguards Readiness Evaluation January 11-12, 1994 3.0 Plant Status 3.1 Unit 3 Land Vehicle Bomb Threats At the beginning of this reporting period, Unit 3 was operating at or near 100% power and had been on line since October 20, 1993.
The following evolutions occurred on this unit during this period:
On January 16, 1994, a load reduction was commenced due to high secondary conductivity levels in the steam generators caused by a main condenser tube leak.
The turbine generator was taken off line and the unit entered Mode 2 at 12:49 a.m.
on January 17, 1994.
The unit re-entered Mode 1 at 2:35 p.m.
and was placed back on line at 5:28 p.m.
on the same day; Following repairs on the main condenser, the unit-reached full reactor power near mid-day on January 18, 1994.
(Refer to section 5.2.4 for additional information.)
3.2 Unit 4 Unit 4 operated at or near 100% power throughout this reporting period and had been on line since August 17, 1993.
4.0 Operational Safety Verification (71707)
4. 1 Inspection Scope The inspectors observed control room operations, reviewed applicable logs, conducted discussions with control room operators, observed shift turnovers, and monitored instrumentation.
The inspectors verified proper valve/switch alignment of selected safety systems, verified that maintenance work orders had been submitted as required, and verified that followup and prioritization of work was accomplished.
The inspectors reviewed tagout records, verified compliance with TS LCOs, and verified the return to service of affected component By observation and direct interviews, the inspectors verified that the physical security plan was being implemented.
The implementation of radiological controls, fire protection, fitness for duty, chemistry, emergency preparedness, and plant housekeeping/cleanliness conditions were also observed.
Tours of the intake structure and diesel, auxiliary, control, and turbine buildings were conducted to observe plant equipment conditions including potential fire hazards, fluid leaks, and excessive vibrations.
4.2 4.2.1 Inspection Findings Overdue Licensed Individual Physicals As stated in 10 CFR 55.21 and paragraph 3.2.2.
1 of procedure AP-0103.21, New License Applications and License Renewals for Reactor Operators and Senior Reactor Operators, licensed individuals are required to have a medical examination by a physician every
years.
On January 13, 1994, the licensee's Training Administrative Supervisor identified that this requirement had not been met in that physical examination for 5 licensed individuals (3 ROs with active licenses and 2 STAs with inactive licenses)
were 5-6 days past due.
The original due dates were January 7-8, 1994.
During this time frame, two of the ROs had'een on shift, and problems with performance were not identified.
The root cause of this problem was attributed to personnel error in that the Licensed Operator Physical Report, which was used by the Training Administrative Supervisor to track medical examination due dates, was not adequately reviewed to ensure proper scheduling and verification that licensed. individual physicals were completed as required.
As a result of this problem, corrective action was immediately initiated to schedule and complete the required physical examinations, and condition report No.94-020 was generated.
All 5 affected licenses were logged in the licensed operator out-of-service book, and the applicable operators were temporarily removed from the shift.
The licensee informed the inspectors of this issue on January 14, 1994, and completed the actual physicals on January 18, 1994.
These examinations did not result in any new license restrictions.
In addition to the corrective actions mentioned above, the following outstanding corrective actions were documented in the condition report and are currently being tracked on the Plant Manager's Action Item system to ensure completi.on:
Training will perform a complete review of the license maintenance process by February'0, 1994, in order to ensure that no additional problems exis All license physicals and renewals will be tracked by the Plant Nanager Action Item System on a 20-month physical examination interval by February 25, 1994, -in order to ensure that the required 24-month interval will not be exceeded in the future.
Procedure AP-103.21 will be revised by February 28, 1994, in order to include the 20-month examination frequency requirement.
gA will review all of these corrective actions by Harch 18, 1994, in order to ensure that the corrective actions are adequate to prevent recurrence.
The inspectors verified that this issue was not reportable, discussed this issue with licensee management, and reviewed the condition report.
The licensee's response to the identification of this issue was timely, and the scheduled long-term corrective actions appear appropriate.
This failure to perform licensed operator medical examinations for licensed individuals every two years is a violation.
However, this violation will not be subject to enforcement action because the licensee's efforts in identifying and correcting the violation meet the criteria specified in Section VIII.B of the NRC Enforcement Policy.
This item will be tracked as NCV 50-250,251/94-01-01, overdue medical examinations for licensed individuals.
This item is closed.
4.2.2 3A RCP Number 1 Seal Leak Off Flow During the current operating cycle, the 3A RCP No.
1 seal leak off flow has been less than an optimum value.
Normally, each RCP receives seal injection flow of 3 gpm from the charging system.
However, the 3A RCP has been experiencing a lower than expected seal flow of about 1 gpm.
Hecause of this, system engineering provided guidance to operations which included engineering and vendor recommendations for allowable operation with a RCP seal leak off flow less than desired.
This guidance included STA trending activities when seal flow is less than 1.0 gpm and actions to secure the RCP if flow is less than 0.8 gpm for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
A low flow alarm occurs if flow is less than 0.7 gpm.
Further, engineering provided operations with written guidance in order to optimize RCP seal flow.
This included guidance for VCT temperature and pressure control, charging system seal injection flow rates, non-regenerative heat exchanger temperature control, and RCS dilution rates.
In addition, operators were reminded of the actions as required by procedure 3-ONOP-041. 1, Reactor Coolant Pump Off-Normal.
The inspectors reviewed the licensee's guidance letters dated September 9,
December 21, and December 22, 1993; associated alarm
4.2.3 procedures; and procedure 3-ONOP-041. 1.
The inspectors also discussed this item with engineering, operations, and management personnel.
Further, the inspectors verified that operators were knowledgeable regarding RCP seal operations in general and issues associated with, the 3A RCP seal.
The inspectors noted that the No.
1 seal is appropriately monitored with indications and alarms and that a complete failure would be compensated for by the No.
seal,'hich is a full pressure designed seal.
During the inspection period, the inspectors observed the 3A RCP seal operation during normal plant operation and during the shutdown and startup (sections 3. 1 and 5.2.4).
The inspectors noted that control room operators and the STA were cognizant of-and appropriately dealt with the RCP 3A seal operations.
Further, the inspector noted that the licensee has planned to replace the aluminum oxide seal for the 3A RCP during the Spring 1994 refueling outage with an improved design (silicon nitride).
Operational Safeguards Response Evaluation and Land Vehicle Bomb Review 4.2.4 During the'eriod, January 10-13, 1994,. NRC specialists performed an OSRE and made a site visit to review the land vehicle bomb issue.
The inspectors accompanied these teams and observed their activities including drills, interviews, and walk-arounds.
The results of these evaluations and reviews will be the subject of future NRC correspondence.
HSIV Failure at HcGuire The inspectors discussed the information pertaining to the failure of the Atwood Horrill HSIV that occurred at McGuire Nuclear Station.
The MSIVs at Turkey Point are of a different design and are manufactured by Schutte and Roerting.
These HSIVs require air to open and air to shut.
Though the information pertaining to the HcGuire failure is not applicable at Turkey Point, the inspectors will review future maintenance activities on the HSIVs.
4.2.5 Control Room Emergency Ventilation System During the inspection period, the inspector walked down the control room emergency ventilation system to ensure compliance with TS 3.7.5.
The inspector reviewed the UFSAR, system description, and normal operating, off normal, and test procedures.
The inspector verified that the system was aligned for automatic operation.
Further, the inspector verified that the charcoal adsorber material in the standby emergency filter had been reviewed for fire protection related issues as documented in UFSAR section 9.6.A.4.HH and in NRC issued safety evaluations which approved exemptions for automatic suppression systems.
However, the inspector noted that procedure O-ONOP-16.10, Pre-Fir'e Plan Guidelines and Safe Shutdown Manual Actions, for fire zone
97, fire area HN (Units 3 and 4 mechanical equipment room), did
'not include the charcoal, material as a documented hazard.
The inspector questioned licensee personnel regarding this issue, and fire protection representatives stated that a procedure'revision would be made to document this hazard.
4.2.6 General Results As a result of routine plant tours and various operational observations, the inspectors determined that the general plant and system material conditions were satisfactorily maintained, the, plant security program was effective, and the overall performance demonstrated safe plant operations.
5.0 Plant Events (93702)
5.1 5.2 5.2.1 Inspection Scope The following plant events were reviewed to determine facility status and the need for further followup action.
Plant parameters were evaluated during transient response.
The significance of the event was evaluated along with the performance of the appropriate safety systems and the actions taken by the licen'see
~
The inspectors verified that required notifications were made to the NRC.
Evaluations were performed relative to the need for additional NRC response to the event.
Additionally, the following issues were examined, as appropriate:
details regarding the cause of the event; event chronology; safety system performance; licensee compliance with approved procedures; radiological consequences, if any; and proposed corrective actions.
Inspection Findings Emergency Containment Cooler Outlet Valve Failures 5.2. 1. 1 Overview On December 29, 1993, during performance of a weekly test due to prior problems, the ECC outlet valve, CV-3-2908, failed to open as required.
During a test on January 19, 1994, another ECC outlet valve, CV-4-2907, failed to open as required.
This issue associated with ECC outlet valve failures due to potential SV problems was initially discussed as IFI 50-250,251/93-26-01, ECC Valve Failures, in section 4.2. 1 of NRC Inspection Report No. 50-250,251/93-26 dated December 22, 1993.
The licensee had increased the test frequency from monthly to weekly.
Additionally, a failed SV had been sent to the manufacturer (ASCO) for further analysis.
The licensee as well as the inspectors questioned the reliability and operability of the ECC outlet valves.
The licensee performed an operability evaluation in view of the failure rate and further increased the test frequency from a
weekly to daily basis.
Five of the failures were attributed to the SVs and one to the pilot lockup valve.
Additionally, the PC/N process to seek a permanent solution to the problem was accelerated.
5.2. 1.2 System Description The ECC system is an ESF system required by TS 3.6.2.2.
The system, in conjunction with the CS system, is designed to limit containment pressure and temperature to within acceptable limits following accidents discussed in the UFSAR.
Each unit's ECC system consists of three fans and associate cooling coils located inside containment.
CCW flow supplied through three normally open inlet valves serves to transfer heat from containment.
Three normally closed outlet valves open to allow required CCW flow following a start of the ECC fan motor.
A normally open bypass valve allows a flow of approximately 200 gpm per cooler to prevent stagnation within the cooler.
The ECC outlet valves are butterfly valves that require air as the motive force to open.
A normally energized, AC-powered, fail-safe, 4-way, ASCO SV routes instrument air through a pilot lockup valve.
Instrument air is then directed to the ECC valve operator maintaining the valve closed.
Following a start of the ECC fans,,
a relay actuates to de-energize the" SV.
This causes the ports in the SV to re-align allowing instrument air pressure to open the ECC outlet valve.
Upon loss of instrument air, an air accumulator provides sufficient pressure to stroke the ECC outlet valve open.
5.2.1.3 Root Cause The ASCO model NPL8342B2E SVs that failed included those that did not move at all following de-energization and those that failed half way., The licensee believes that several factors influence the failure mechanism.
These include, the temperature of the energized SV, the friction between the seating surfaces, and the time dependency of the failure mechanism.
Inspection of failed SVs revealed a yellowing of the normally clear lubricant (Nyogel)
indicating that the lubricant was drying out.
It was, however, noted that in each case where the SV failed, the SV operated satisfactorily after it was re-energized and subsequently de-energized. 'he l.icensee attributes this to either the initial stroke wiping away the more viscous lubricant and exposing less viscous lubricant and/or the initial stroke lubricating portions of the seating surfaces which potentially become dry between SV strokes.
The results of root cause analysis performed by ASCO and the lubricant manufacturer are ongoing.
5.2. 1.4 Licensee's Immediate Corrective Actions Following the initial failures that had occurred in August 1993, all the ECC outlet valve SVs were changed out.
Following the
failure of ECC outlet valve CCV-4-2907 on January 19, 1994, the SV was replaced and successfully stroked approximately 25 times.
Additionally, based on the failure cause hypothesis discussed above, the test frequency was changed from weekly to daily.
In the event that an SV failure were to occur during the daily testing, a contingency plan utilizing manual restoration of CCM flow to the affected ECCs was developed.
The licensee performed a
safety evaluation to show that the ECC operability could be maintained with operator action.
This ensured that licensing requirements relating to containment pressure/temperature and Eg qualification following an analyzed accident were met.
From a containment pressure standpoint, the licensee determined that operation of either of the CS pumps or two of the three ECCs could provide heat removal capability to maintain post-accident containment pressure below the design value.
From an Eg perspective, the licensee concluded that the start of ECCs could be delayed for 20 minutes after SI signal initiation without adversely affecting the environmental qualification of any safety equipment inside containment.
A written instruction sheet was developed detailing operator actions that would be needed to restore an ECC to operable status following an SI.
This contingency plan would go into effect following a failure during the daily testing of the ECC outlet valves.
At this time, a non-licensed operator would be dedicated to perform the manual op'eration following a failure after an SI.
The manual operator action involves shutting an instrument air valve which allows the accumulator air pressure to open the ECC outlet valve.
Since the instrument air valves along with the ECC valves are located in the pipe and valve room, the licensee-concluded that the operator would receive a dose of approximately 60 millirem during the manual opening of the failed ECC valve following an-accident.
5.2. 1.5 SV Modification A PC/M to enhance reliability of the ECC outlet valves had been initiated before the two recent failures.
The PC/M process was accelerated since the, daily surveillance put extra burden on the operators as well as plant hardware.
The PC/M modified the configuration of the normally energized 4-way, AC, SVs associated with the ECC outlet valves to normally de-energized, 4-way, AC SVs.
Under this configuration, a contactor off the respective ECC fan motor power supply would actuate to energize the SV upon a
start of the fan motor.
Upon energization, the SV would change position to appropriately route instrument air to open the ECC outlet valve.
The PC/M also re-oriented the SVs to a vertical upright position in accordance with recent recommendations in the manufacturer's
installation and maintenance instructions.
The modification also involved installation of some new cables to ensure proper train separation and single failure protection.
As of the end of the report period, SVs on the 3A and 3C ECC outlet valves were successfully replaced and subsequently tested.
The inspectors attended the PNSC meeting that reviewed and approved the Unit 3 PC/N, verified portions of the PC/M implementation including post-maintenance testing, and reviewed PC/H documentation.
5.2. 1.6 Generic Applicability At Turkey Point, the 4-way, AC-operated, normally energized SVs are not used on any other systems.
As of the end of the inspection period, the licensee was performing a review relative to
CFR Part 21 requirements.
5.2. 1.7 Conclusions 5.2.2 The inspector monitored licensee activities associated with this issue on a.daily basis.
This included discussions with appropriate staff as well review of the safety evaluation, surveillance, modification package, and implementation.
The inspector concluded that licensee conservatively and aggressively pursued this issue from its initial stages.
Hanagement involvement and thoroughness of involved licensee technical staff members were evident.
A conference call was also made with NRC regional management to keep them appraised of the plans following the January 19, 1994, failure.
Pending the successful completion of the planned modification, IFI 50-250,251/93-26-01, ECC Valve Failures, remains open.
4B EDG Failure On January 12, 1994, during the performance of weekly surveillance 4-OSP-023. 1, Diesel Generator Operability Test on the 4B EDG, the control room operator noticed an increase in the output voltage as well as current during a stable load of 2500 KW.
Voltage increased approximately 100 volts, and the generator output current increased to over 600 amps.
The voltage and current returned to nominal values of 4160 volts and approximately 400 amps within approximately 15 seconds.
Consequently, the surveillance was aborted and the 4B EDG was declared out of service.
This placed the Unit 4 in a 72-hour action in accordance with TS 3.8.1.1.b.
The parameters observed during this failure were similar to those observed during two previous failures of the 4B EDG on February 25, 1993, and December 23, 1993.
The February 25, 1993, failure was attributed to a loose wire on the remote gate firing module,
and the December 23, 1993, failure was attributed to a faulty remote gate firing module.
Following both previous incidents, the 4B EDG was retested for greater that the minimum required surveillance time of one hour without observed problems.
(Refer to paragraph 9.c and section 5.2.2 of NRC Inspection Report Nos.
50-250,251/93-06 and 50-250,251/93-29, respectively, for additional information.)
Following the December 23, 1993, failure, the licensee had placed the 4B EDG on a mandatory increased surveillance frequency per TS Table 4.8-1.
The test frequency was increased from once per
days to once per 7 days because there were greater than or equal to 2 failures in the last 20 valid tests.
The increased test frequency is also required to be maintained until 7 consecutive failure free demands have been performed and the number of failures in the last 20 valid demands has been reduced to 1.
The January 12, 1994, failure was the fourth failure in 38 starts.
The 4B EDG was successfully tested again on January
and 26, 1994, and is currently scheduled to be tested weekly for the next 13 weeks.
Following troubleshooting of the January 12, 1994; failure of the 4B EDG, the licensee initially postulated that the most probable cause of the failure was a loose lead on contact No.
12 of the voltage balance auxiliary relay.
After tightening of the loose lead, another test run was performed on January 13, 1994.
During this test run at no load, drifting of the regulator upwards to as much as 262.5 volts AC above the initial level for as long as
seconds was observed.
The l,icensee checked the voltage regulator inputs, outputs, and SCR circuits.
All inputs and outputs were normal.
The licensee concluded that the automatic regulator was most likely the problem and changed out the automatic voltage regulator.
Additionally, several circuit and component checks were performed during both loaded and unloaded troubleshooting EDG runs, including a full load rejection test per procedure 4-0SP-023.2, EDG Load Rejection.
The 4B EDG was returned to service at 2: 15 a.m.
on January 14, 1994.
The licensee documented the following remaining corrective actions in the condition report 94-013 in order to preclude recurrence of this type of event:
The licensee will continue to monitor voltage regulator performance during the increased testing frequency of the 4B EDG by using recorders and oscilloscopes to monitor EDG frequency, =voltage, KW, regulator input voltage, and regulator output wave form.
The licensee is currently in the process of generating a
Special Report to address this valid failure within 30 days in accordance with TS 4.8. 1. 1.3.
This action is currently scheduled for completion by February 11, 199 Prior to the next monthly surveillance of the 4A EDG, the licensee plan's to inspect the 4A EDG potential transformer circuits for loose leads.
This action is currently scheduled for completion by February 13, 1994.
The automatic voltage regulator that was removed from the 4B EDG because it was suspected to be faulty was returned to the vendor for root cause investigation and repair.
The root cause investigation and repair are currently scheduled for completion on April 4, 1994.
These outstanding corrective actions have been added to the Plant Nanager's Action Item system in order to ensure completion.
The inspectors followed up on the licensee's troubleshooting process and the status of the repairs and also reviewed the control room logs and condition report.
Troubleshooting and repair activities were conducted in an efficient manner.
The inspector also concluded that applicable TS action statements were met and that the 4B EDG was returned to service in a timely manner.
5.2.3 Security Event On January 15, 1994, at 9:26 a.m.,
a security officer inadvertently fired a round from a weapon during routine cleaning.
The round was fired into a sand barrel in the weapons area of the Nuclear Entrance Building.
The licensee removed the security officer from duty and initiated an investigation per condition
,report No.94-023.
The licensee reviewed security event reporting requirements and determined this event -to be only a loggable event.
The licensee's investigation determined that root cause was personnel error due to inattention to detail.
The security
'fficer did not check that the weapon safety was on or that the weapon was uncocked.
The licensee's corrective actions included a
fitness-for-duty check of the officer, removal from duty temporarily, retra'ining of the officer, and retraining of the security force relative to weapon and handgun safety program procedure.
An inspector was notified at home regarding this event.
The inspectors verified that the event was not reportable.
In addition, the inspectors reviewed the condition report and discussed it with licensee security management.
Further, the inspectors examined the licensee's weapon area and associated procedures.
The inspectors concluded that the licensee appropriately responded to and followed up on this security even.2.4 Unit 3 Hain Condenser Tube Leak
'n January 16, 1994, at approximately 11: 10 p.m.,
a main condenser tube leak caused all of the secondary conductivity levels to increase on Unit 3.
Annunciator D-4/3 was received in the Unit 3 control room, and the operators noted that all monitored secondary conductivity points on the chart recorder were increasing.
The licensee entered procedure 3-ONOP-071. 1, Secondary Chemistry Deviations, as a result of the increasing conductivity trend.
The 3A north condenser hotwell was noted as having the highest conductivity levels.
Secondary conductivity is not addressed in plant TSs; however, secondary conductivity levels are maintained low to prevent corrosion in the secondary plant including the steam generators.
Samples taken indicated conductivity levels of 8. 1-, 10.4, and 13.2 micromhos/cm in the A, B, and C steam generators, respectively.
With secondary conductivity levels in excess of 7 micromhos/cm, procedure 3-ONOP-071.
1 required steam generator blowdown to be increased and the plant to be brought to Hot Standby.
A load reduction on Unit 3 was commenced at approximately 11: 15 p.m. in accordance with procedure 3-GOP-103, Power Operations to Hot Standby.
At 12:49 a.m.,
January 17, 1994, the turbine was manually tripped after transferring the Unit 3 loads from the Unit 3 auxiliary transformer to the Unit 3 startup transformer, and Hode 2 was entered.
Haximization of blowdown and stopping of circulating water pumps in the north condenser resulted in the decrease of conductivity levels.
An on-the-spot change was made to procedure 3-ONOP-071. 1 allowing the unit to stay in Hode 2.
At approximately 4: 10 a.m.,
samples taken indicated secondary conductivity levels in the A, B, and C steam generators were 1.54, 0.95, and 1.29 micromhos/cm, respectively.
Entries were made in the north water boxes to identify faulted condenser tube(s).
A tube on the 3A north condenser was identified as having a major leak.
The tube was on the periphery and was most probably damaged due to debris or steam impingement.
Approximately 12 surrounding tubes along with the damaged tube were plugged.
The unit re-entered Hode 1 at 4:35 p.m.
and was placed back on line at 5:28 p.m.
on January 17, 1994.
The unit re-achieved 100% reactor power near mid-day on January 18, 1994.
Appropriate plant management personnel were notified of the event.
The inspector received numerous updates throughout the night on the unit status.
The inspector discussed the event with plant personnel and monitored activities during plant startup.
The inspector concluded that licensee actions during the event were appropriat.2.5 Hain Generator Voltage Regulator System Induced Power Oscillations During -the inspection period, several instances of Unit 3.and
main generator voltage regulator system induced power oscillations occurred.
The control room operators noted short duration swings in the indications for unit gross output (HWe), exciter field amperage, and exciter voltage.
The output swings were on the order of +20 HWe.
The operators responded by placing the units'oltage regulator control switch i'n manual (TEST position)
control, and the swings subsequently stopped.
This included, at times, both units'oltage regulator switches, and at others, just Unit 4.
In the manual mode of voltage regulation,'C control is used instead of the AC control.
The operators checked with the systems and grid operations and subsequently returned the units to automatic voltage regulator operation.
The licensee reviewed this issue by assembling a team of system and component engineers from the on-site and off-site engineering groups and by contacting the vendor.
The licensee also developed and implemented temporary procedure TP-1031, Main Generator Voltage Regulator Data Acquisition Test and Troubleshooti'ng.
Further, a check with systems and grid operators determined that these oscillations occurred during times of high grid power demand due to the cold weather, when reactive power load (HVARs) was low, and during times when some grid distribution transmission lines were out-of-service.
The licensee provided direction to the operators on how to recognize these oscillations, actions on when to take manual control, and guidance while operating in manual.
The inspectors observed one of these oscillati'ons; discussed the oscillations with operations, engineering, and management personnel; reviewed procedure TP-1031 and other related documentation; and verified licensee corrective actions included documentation in the night order book.
The inspectors also noted that the licensee demonstrated conservatism in both monitoring and ensuring grid stability for offsite power reliability.
In addition, the licensee is evaluating the use of an installed power system stabilizer which could lessen the impact of these oscillations.
The inspectors concluded that, to date, the licensee has appropriately and conservatively responded to main generator voltage regulator system induced power oscillations.
6.0 Maintenance Observations (62703)
6.1'nspection Scope Station maintenance activities of safety-related systems and components were observed and reviewed to ascertain they were conducted in accordance with approved procedures, regulatory guides, industry codes and standards, and in conformance with the TS e The following items were considered during this review, as appropriate:
LCOs were met while components or systems were removed from service; approvals were obtained prior to initiating work; activities were accomplished using approved procedures and were inspected as applicable; procedures used were adequate to control the activity; troubleshoot'ing activities were controlled and repair records accurately reflected the maintenance performed; functional testing and/or calibrations were performed prior to.
returning components or systems to service; gC records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were properly implemented; gC hold points were established and observed where required; fire prevention controls w'ere implemented; outside contractor force activities were controlled in accordance with the approved gA program; and housekeeping was actively pursued.
6.2 Inspection Findings 6.2. 1 Maintenance Witnessed The inspectors witnessed/reviewed portions of the following maintenance activities in progress:
troubleshooting of the ECC outlet valves'olenoid valve failures (Refer to section 5.2. 1 for additional information.);
troubleshooting of the 4B EDG automatic voltage regulator problem (Refer to section 5.2.2 for additional information.);
troubleshooting of a Unit 3 condenser tube leak (Refer to section 5.2.4 for additional information.);
packing leak repairs on main steam line B isolation bypass valve MOV-4-1401 (Refer to section 6.2.2 below for additional information.);
work order No. 94000183, PMT procedure 3-OSP-049. 1, RPS relay RT-6 replacement and post-maintenance test (Refer to section 6.2.3 for additional information.);
4B HHSI pump motor replacement (Refer to section 6.2.4 for
.additional information.);
and Unit 4 spent fuel pool outage (Refer to section 6.2.5 for additional information.).
For those maintenance activities observed, the inspectors determined that the activities were conducted in a satisfactory
e
manner and that the work was properly performed in accordance with approved maintenance work orders.
6.2.2 Packing Leak Repairs on Main Steam Line 8 Isolation Bypass Valve MOV 4-1401 6.2.3 The repair was performed in accordance with work order No.
93033332-01, and it involved stopping a packing leak on main steam line B isolation bypass valve MOV-4-1401 using Furmanite.
The inspector reviewed the work package which included a safety evaluation justifying on-line repair on a safety-related pressurized system as well as Furmanite's working procedure.
Approximately one-half of a Furmanite stick was initially used to stop the leak.
A followup injection of approximately one stick was made.
The licensee plans to permanently repair the leak during the next available opportunity.
The inspector did not have any negative findings with this maintenance activity.
RPS Relay RT-6 Replacement On January 3,
1994, the licensee identified that the Unit 3 RPS Train 8, relay RT-'6, associated with reactor coolant low flow reactor trip had failed.
The relay was found failed in a tripped state which is in the safe state.
A companion relay RT-5 was still energized because there was no valid low flow or RCP breaker trip condition present.
The relay was replaced, and RPS was returned to normal.
The failure of the relay was attributed to age.
A condition report was issued as this was a repetitive occurrence.
As such, the relays fail in a safe condition, and the worst case consequence would be a reactor trip either due to the simultaneous
- failure of two redundant relays or during a surveillance test while the opposite train had a failed relay.
As a precaution, the licensee visually examines the cabinets for potential failed relays.
Additionally, thermography was performed to identify relays that exhibited higher temperatures which is typically a prelude to a failure.
The inspectors concluded that the licensee acted appropriately for this relay failure.
6.2.4 4B HHSI Pump Motor Replacement The licensee replaced the motor for the 4B HHSI pump per procedure O-CME-6.2. 1, Safety Injection Pump Motor Overhaul, and PMO No.
93032309.
The inspector witnessed portions of motor replacement including rigging operations.
The inspecto'r noted very good electri'cian work practices and good supervisory oversight.
This included oversight by the chief electrician (first line'upervisor),
by the field supervisor (second line supervisor),
and by the electrical maintenance supervisor (manager).
6.2.5 Unit 4 Spent Fuel Pool Cooling System Outage During the period January 23-26, 1994, the licensee removed the Unit 4 spent fuel pool cooling system from service to perform corrective maintenance on system valves.
In order to assure that the clearance boundary was maintained, the licensee used two freeze seals.
The inspector reviewed the spent fuel pool cooling system outage and related work activities.
This included the freeze seal evaluation and operation, the HP technician coverage, the mechanical maintenance work, and the operations activities to remove the system from service and to monitor while the cooling system was out of service.
The inspector noted that appropriate periodic monitoring was in place for pool temperature including estimates for heat up rate.
During the 3-day outage, the pool temperature increased from 78'F to 120'F.
The inspector concluded that this evolution was well planned and well controlled and that teamwork among all participants was very strong.
Further, the inspector noted a positive presence of gA personnel in the performance of surveillance monitoring activities.
7.0 Surveillance Observations (61726)
7.1 7.2 7.2.1 Inspection Scope The inspectors observed TS required surveillance testing and verified that the test procedures conformed to the requirements of the TSs; testing was performed in accordance with adequate procedures; test instrumentation was calibrated; limiting conditions for operation were met; test results met acceptance criteria requirements and were reviewed by personnel other than the individual directing the test; deficiencies were identified, as appropriate, and were properly reviewed and resolved by management personnel; and system restoration was adequate.
For completed tests, the inspectors verified testing frequencies were met and tests were performed by qualified individuals.
Inspection Findings Tests Observed The inspectors witnessed/reviewed portions of the following test activities:
procedure OP-4004.2, Safeguards Relay Rack Trains A and B;
procedures 3,4-0SP-55. 1, Emergency Containment Cooler Operability Test, and procedure TP-1032, Functional Testing
of ECC Outlet CVs, for the ECC outlet valves (Refer to section 5.2. 1 for additional information.);
and
.
troubleshooting test runs of the 4B EDG following a valid failure (Refer to section 5.2.2 for additional information.).
The inspectors determined that the above testing activities were performed in a satisfactory manner and met the requirements of the-TSs.
8.0 Followup on Previous Items and Noncompliances (92702 and 92701)
8.1 Inspection Scope A review was conducted of the following noncompliance and open item to assure that corrective actions were adequately implemented and resulted in conformance with regulatory requirements.
Verification of corrective action was achieved through record reviews, observation.,
and discussions with licensee personnel.
Licensee correspondence was evaluated to ensure the responses were timely and corrective actions were implemented within the time periods specified in the reply.
8.2
, Inspection Findings 8.2. 1 (Closed)
IFI 50-250,251/91-33-01, Review of Emergency Operating Procedures and Off-Normal Operating Procedures after the 1992 Revision Cycle.is Completed.
The inspector reviewed procedure EOP-E-O, Reactor Trip or Safety Injection, dated March 30, 1993, and procedure ECA 0.0, Loss of All AC Power, dated April 6, 1993, to ensure that the instructions were consistent for the actions takeh following a phase A and phase B isolation.
The inspector determined that the steps were consistent between procedures.
The inspector reviewed the following ONOPs:
procedure 3-0NOP-004, Loss of. Offsite Power, dated May 4, 1993; procedure O-ONOP-013, Loss of Instrument Air, dated July 30, 1993)
procedure 3-0NOP-019, Intake Cooling Water Malfunction, dated August 15, 1992; and procedure 3-0NOP-030, Component Cooling Water Malfunction, dated July 30, 199 '
The inspector also reviewed basis document 3-BD-ONOP-030, Basis Document for Component Cooling Water Halfunction.
The review was conducted also using the applicable drawings for the systems.
The drawings have been revised, and therefore, it was necessary to use a cross reference document to find the applicable referenced drawings.
The inspector found no major problems with the ONOPs; however, the loss of instrument air document was lacking in details such as a list of valves and equipment affected and their failure position.
The licensee stated that these positions are stamped on the nameplates in the control room.
The licensee has an approved plant change modification system for the instrument air system, and the inspector felt the present procedure was adequate and would be revised when the new system was installed.
The review also determined that not all,of the ONOPs were written in the dual column format.
The licensee stated that priority to write in the dual column format was given to ONOPs referenced by the EOPs.
This item is closed, 8.2.2 (Closed)
VIO 50-250,251/91-38-01, Failure to Provide Adequate Independent Review The licensee responded to this violation by letter dated November 13, 1991, and attributed this violation to personnel errors by non-licensed plant personnel.
During preparation of the HEP, vendor information was unavailable for the hydraulic coupling heat load.
The HEP was issued based on informal service water flow and heat exchanger capabilities.
The requirement to start alternative charging pumps if oil temperature became greater than 180'F on the pump in operation was not included.
The HEP did not contain sufficient documentation to justify the modification.
As a result, procedures 3/4-0NOP-030, Component Cooling Water Halfunction, were revised on September 12, 1991, to incorporate the monitoring requirements and required actions from the revised HEP.
The individuals involved with the preparation of the HEP were counseled on better documentation of design basis and analysis as well as procedure adherence, and the personnel responsible for the inadequate ONOP were admonished.
guality Instruction Change Notice No.
36 to procedure gI-3. 14, Hinor Engineering Packages (HEP),
was issued on September 14, 1991, to clarify procedure gI-3. 14 as follows:
It requires thorough and clear documentation of the assessment and inclusion of evaluations of the applicable design and safety considerations.
The design analysis required to support the modification shall be included or referenced.
It requires that the engineering justification provide sufficient detail to demonstrate that the modification complies with all applicable design requirement Post-modification testing shall be clearly specified as required.
All HEPs which involve physical modification or implementation shall receive a joint pre-implementation walkdown including participation by engineering, the system engineer, maintenance, and operations.
A technical evaluation on the design process for HEP No.91-064, Backup Cooling Water System, verified that the design was adequate.
Site engineering performed a review of all HEPs issued since the inception of the HEP process and those in development to verify the adequacy of the MEP as a valid design document.
An independent review was also performed by FPL's corporate engineering technical staff.
These reviews concluded that the HEP process was sound.
A policy letter was issued on September 24, 1991, requiring Engineering Hanager approval of all HEPT The PNSC members have also been retrained concerning the level of review necessary for design change post modification testing.
This item is closed.
9.0 Onsite Followup and In-Office Review of Written Reports (90712, 90713, and 92700)
9.1
'nspection Scope The reports discussed below were reviewed.
The inspectors verified that reporting requirements had been met, root cause analysis was performed, corrective actions appeared appropriate, and generic applicability had been considered.
Additionally, the inspectors verified the licensee had reviewed each event, corrective actions were implemented, responsibility for corrective actions not fully completed was clearly assigned, safety questions had been evaluated and resolved, and violations of regulations or TS conditions had been identified.
When applicable, the criteria of 10 CFR Part 2, Appendix C, were applied.,
9.2 Inspection Findings 9.2. 1 Monthly Operating Report The inspectors reviewed the December 1993 Monthly Operating. Report and determined it to be complete and accurate.
9.2.2 Special Report - Diesel Generator On January 19, 1994, the licensee issued a Special Report in accordance with TS,4.8. 1. 1.3.
This report documented the circumstances regarding the failure of the 4B EDG on December 23, 1993.
This report stated that 37 valid tests had been completed
'since the 4B EDG was installed and declared operable and that the
~
I
~
December 23, 1993, failure was the third failure of this EDG.
This report adequately addressed this failure.
This event was also discussed in detail in section 5.2.2 of NRC Inspection Report No. 50-250,251/93-29, and a similar failure is documented in section 5.2.2 of this report.
The inspectors determined that this report was appropriate.
9.2.3 (Closed)
LER 50-250/92-003-01, Operation With Improper Pressure Transmitter Calibration In response to NRC Information Notice No. 91-75, Static Head Corrections Not Included in Pressure Transmitter Calibration Procedures, dated November 25, 1991, the licensee reviewed the pressurizer pressure setpoints in the Turkey Point Unit 3 and
calibration procedures.
On Harch 23, 1992, the licensee determined that the low pressurizer pressure reactor trip setpoint was not adjusted for static head as part of a channel calibration procedure.
After adjusting for static head correction and accounting for the allowable margin within the current TSs, the'icensee confirmed that the units were operating in accordance with the current TSs which were implemented on August 26, 1991.
However, under the TSs in effect prior to August 26, 1991, the licensee determined that the low pressurizer pressure trip setpoint (if adjusted for static head and assuming the worst case instrument error) could have resulted in the plant operating in a
condition outside the design basis of the plant.
This con'dition was reported to the NRC on April 17, 1992, as a Significant Event in accordance with procedure AP 0103. 12, Notification of Events to the NRC, and
CFR 50.72(b)(1)(ii)(B), Condition Outside the Design Basis of the Plant, and was documented in LER 50-250/92-003
,
on April 22, 1992.
This issue was also documented in paragraph 9.c of NRC Inspection Report No..50-250,251/92-10'n Hay 29, 1992.
According to the LER, the effect of a static head correction on the low pressurizer pressure trip setpoint was under evaluation, and the licensee was also in the process of conducting an engineering analysis to determine if the safety analysis limit for, pressurizer pressure of 1790 psig was exceeded.
The results of this analysis were documented in a supplement to the LER on June 1,
1992.
The revised LER stated that although the static pressure span effects had been included in differential pressure transmitter calib} ation procedures, an error had been found in the calibration procedures for steam generator level where the static pressure span effect had not been property applied.
This licensee concluded that after including the static head correction and correcting the static pressure span effect error, the.units were operating in accordance with the current TSs.
FPL's engineering analysis also concluded that after inclusion of the static head corrections, correction of the static pressure span effect error, and assumption of worst case instrument uncertainties; all of the setpoints in question were within the design basis of the plant
during operation prior to August 26, 1991.
The licensee also attributed this event to inadequate procedures in that the static head corrections had not been incorporated into the same pressure transmitter calibration procedures and that the static pressure span effects had been erroneously applied for the steam generator low-low water level setpoint.
Although inclusion of the static head correction factor and correction of the static pressure span effect for the pressure transmitters was not a violation*of the current TSs, the licensee checked applicable plant pressure transmitters locations.
The licensee also revised calibration procedures (as needed)
to include the static'head correction factor and correct the pressure span effect error.
This work was completed by the.end of the upcoming Unit 3 and 4 refueling outages (October 1992 for Unit 3 and June 1993 for Unit 4),
The inspector verified that work orders had been established and completed for the majority of the transmitters that were worked during the Unit 3 and 4 refueling outages and reviewed portions of the licensee's evaluation
[No. JPN-PTN-SEIS-92-015, Revision 2,
Engineering Evaluation for Pressure Transmitter Static Head Correction (NRC IN-91-75)] dated Hay 28, 1992.
The licensee's actions with regard to this issue were thorough and comprehensive.
This item is closed.
9.2.4 (Closed)
LER 50-250/92-006, Recirculation of Waste Monitor Tanks Not in Accordance With Offsite Dose Calculation Manual Prior to Sample Acquisition On June 10, 1992, during an annual audit of radiological liquid releases, licensee gA personnel discovered that the recirculation of the waste monitor tank prior to liquid releases was not conducted in accordance with the ODCH.
The ODCH required that liquid waste in the waste monitor tank be isolated and recirculated for a minimum of one tank volume prior to sampling, and gA personnel identified that the tank had been recirculated for somewhat less than one tank volume.
The licensee determined that an inadequate characterization of the pump and recirculation line capabilities resulted in over-estimating of the recirculation flow rate.
The normal recirculation time was one hour, and the immediate corrective action was to double the recirculation time to ensure that one tank volume would be turned over prior to sampling and to conservatively conform to the ODCH.
Chemistry personnel also performed a mixing analysis of the tank concentration.
This analysis determined that little recirculation time was actually required to obtain a representative sample of the tank contents in that the measurable nuclide contents of the tank appeared to be colloidal in nature and reached equilibrium within 15 minutes of the beginning of the recirculation process.
Licensee actions with regard to this issue were appropriate.
This item is close.2.5 (Closed)
LER 50-250/92-007, Hissed Surveillance for MOV-3-864A and B and MOV-4-864A and B Valves and Power Breakers Open While Unit 4 or Unit 3 Respectively Were in Mode 5 or 6 On July 16, 1992, licensee gA discovered that valve position (as indicated in the control room)
and motor operator breaker position for power to RWST outlet valves (MOV-3-8648 or MOV-4-864B) had not been specifically verified by check off when either Unit 3 or 4 was.in Mode 5 or 6 and the HHSI suction cross connect valves were closed.
The audit identified the following dates where this situation occurred:
Unit 4, December 12-16, 1991; Unit 4, January 29-31, 1992; and Unit 3, April 28 - Hay 3, 1992.
As a matter of procedure and plant policy, these valves and their associated motor operator breakers are locked in the open position when required to be operable.
In these instances, local verification of all valve positions was completed in the plant and documented on log sheets.
In addition, each of the breakers for
'ower to the valve operators for valves HOV-4-864B and MOV-3-864B are typically locked open, and a record search verified that both breakers had remained locked in the open position-as required by TSs.
The root cause of the missed surveillance was a less than fully adequate procedure.
Procedures, however, which controlled necessary surveillances during operation, did not include specific line item verification of breaker positions for the RWST outlet valves when one of the units was in Mode 5 or 6.
Procedures in place also did not verify valve position by use of control room indication.
The procedures did, however, require local valve position verification by inspection of the locked open valves.
As a result of this issue, the licensee completed revisions of the appropriate procedures to require a specific l,ine item checking-off of the outlet valve motor operator breaker positions have been completed and to ensure the RWST outlet valves are open by checking control room indicating lights.
The licensee's corrective actions with regard to this issue were acceptable.
This item is closed.
9.2.6 (Closed)
LER 50-250/93-002, Reactor Coolant System Pressure Boundary Leakage; Technical Specification Required Shutdown On January 15, 1993, a small unisolable RCS leak (2-3 drops per minute)
was discovered on an abandoned 3/4-inch pressurizer spray bypass line between the previous 3A spray valve body and the pressurizer spray nozzle.
The leak emanated from a socket weld
which connected a pipe cap to a pipe nipple.
Due to the identification of this RCS pressure boundary leakage, the licensee declared an Unusual Event and commenced a Unit 3 reactor shutdown from 100% power.
The Unusual Event was terminated when Unit 3 entered Mode 5.
Examination revealed inadequate pullback between, the pipe and the cap.
The inadequate pullback caused excessive local stress which in turn resulted in stress corrosion cracking 'of the fillet weld.
Consequently, the licensee attributed the root cause of this unisolable leak to be personnel error in that non-licensed contract personnel did not ensure adequate pullback of the pipe cap when it was installed as part of a modification in 1985.
The vertical configuration (cap hanging down)
and spatial limitations in the field were also considered to be contributing factors.
As a result of this event, the licensee removed the faulted Unit 3 line along with a tee and another pipe cap, and a new pipe cap was welded on.
During the Unit 4 refueling outage (Spring 1993), the licensee also replaced the vertical caps on the Unit 4 abandoned spray valve bypass lines in accordance with work order No.
93003874-01..
In order to ensure that weld cap problems do not recur, the licensee currently utilizes Construction 'guality Control Technique Sheet No. 9. 1-3.4.
For adequate fit-up, step
of this technique. sheet required verification of a specific distance between scribe marks after a pipe was inserted, withdrawn, and tacked.
Although revision 6, which was the latest revision to this step, was incorporated into this technique sheet on October 14, 1988; the problem occurred on a pipe cap that was installed during 1985.
This event was previously documented in paragraph 8.b of NRC Inspection Report No. 50-250,251/93-01.
The inspectors reviewed this write-up, the LER, portions of work order No. 93003874-01, and portions of Construction guality Control Technique Sheet No.
9. 1-3.4 and deemed the licensee's corrective actions to be appropriate.
This item is closed.
10.0 Engineered Safety Features Walkdown (71710)
10.1 Inspection Scope The inspectors performed an inspection designed to verify the status of the Unit 3 and
ICW and CCW systems.
This was accomplished by performing a complete walkdown of all accessible equipment.
The following criteria were used, as appropriate, during this inspection:
system procedures matched plant drawings and as-built configuration;
i
housekeeping was adequate, and appropriate levels of cleanliness were being maintained; valves in the system were correctly installed and did not exh.ibit signs of gross packing leakage, bent stems, missing handwheels, or improper labeling; hangers and supports were made up properly and aligned correctly; valves in the flow paths were in correct position as required by the applicable procedures with power available, and valves were locked/lock wired as required; local and remote position indication was compared, and remote instrumentation was functional; and major system components were properly labeled.
10.2 Inspection Findings Problems with system line-ups were not identified; however, a
minor UFSAR enhancement was noted concerning the ICW system.
(Refer to section 12.2. 1 for additional information.)
The inspectors concluded that'he Unit 3 and
ICW and CCW were appropriately aligned.
11.0 Evaluation of Licensee Self-Assessment Capability (40500)
11. 1 Inspection Scope The inspectors performed a review of the licensee's self assessmen't capability by including PNSC and CNRB activities, QA/QC audits and reviews, l.ine management self-assessments, individual self checking techniques, and performance indicators.
11,2 Inspection Findings 11.2. 1 PTN Status Heeting The inspector attended the periodic PTN Status Heeting on January 13, 1994.
The purpose of this meeting was to discuss and review Turkey Point status and issues including department reports, strategic tasks, operating status, and overall station performance.
Representatives from the station, engineering, and corporate organizations provided input for the meeting.
The inspector noted the meeting to be factual and thorough, and personnel present discussed appropriate safety issues.
Further, the inspector noted that personnel displayed a very good safety perspective, and the inspector concluded that the PTN status
meeting demonstrated excellent and pro-active self-assessment capability by the licensee.
11.2.2 CNRB Meeting No.
403 The periodic CNRB meeting No.
403 was held at Turkey Point on January 18, 1994.
The inspector attended portions of the meeting and verified that the following TS items were satisfied:
meeting frequency per TS 6.5.2.5; quorum per TS 6.5.2.6; review and audit items per TSs 6.5.2.7 and 6.5.2.8; records per TS 6.5.2.9; and member composition including alternates and consultants and function per TSs 6.5.2. 1, 6.5.2.2, 6.5.2.3, and 6.5.2.4.
In addition to meeting the TS requirements, the inspector noted that the CNRB members displayed a very good questioning attitude, a pro-active approach to nuclear safety, and required individuals presenting issues to be thorough and to address the =safety significance of the issues.
11.2.3 PTN Safety Neeting The inspector attended the monthly scheduled safety meetings on January 19, 1994.
Eight meetings occurred during the period January 19-20, 1994, for all station personnel.
Issues covered at this meeting included safe work practices and a briefing by the site vice president.
This briefing focused on 1993 station safety performance, recent industry nuclear safety issues, and corporate budgetary issues.
The inspector concluded that the meeting in general and in particular, the site vice president briefing, demonstrated a
strong nuclear safety perspective and pro-active self-assessment capability.
12.0 Design, Design Changes and Modifications (37700, 37828)
12. 1 Inspection Scope The inspectors reviewed selected PC/Ms including the applicable safety evaluation, infield walkdowns, as-built drawings, associated procedure changes and training, modification testing, and changes to maintenance program.2 12.2.1 Inspection findings Safety Evaluation Process During
.a routine plant walkdown (Refer to section 10.0 for additional information.), the inspector noted that the Unit 3 ICW outlet temperature control valve (CV-3-2202) from the CCW heat exchangers was tagged closed per clearance No. 3-93-11-10.
The inspector immediately checked and did not find the same condition on Unit 4.
The inspector then proceeded to the control room to discuss this issue with licensed operators.
The control room was aware of the clearance and valve CV-3-2202 was logged as inoperable in the equipment out-of-service log.
A check of the clearance log determined that a
PWO (No. 93033777)
was open for valve repair.
The PWO had been initiated in November 1993, and the valve had been tagged out of service.
Apparently, the valve was determined to be frozen in the closed position.
The inspector questioned Unit 3 CCW system operability.
Operators
.stated that the ICW to the CCW heat exchangers was adequately maintained by a full flow manual bypass around the CV-3-2202 valve.
The inspector verified this by reviewing the UFSAR, PLIDs, operating procedure, and design basis document.
Thus, there were no immediate operability issues.
The inspector also discussed the issue with the system engineer.
The inspector determined that in 1985, a single failure issue was identified with respect to valves CV-3,4-2202 and valves CV-3,4-2201 (ICW outlet for TPCW heat exchangers).
Modifications to the system, changes to system operation, and a safety evaluation were previously performed as corrective actions to this single failure issue.
The inspector reviewed revision 3 to this safety evaluation No. JPE-LR-87-45, dated March 17, 1989.
That
-.
evaluation concluded that the manual bypass valves (3,4-50-406)
for the ICW outlet temperature control valves (CV-3,4-2202) for the CCW heat exchanger were to be locked open.
The inspector verified that these actions remained in effect including documentation in the operating procedures 3,4-0P-019, Intake Cooking Water System.
During -review of the clearance (No. 3-93-11-10)
per procedure O-ADM-212, In-Plant Equipment, the inspector noted that the STA performed a monthly
CFR 50.59 safety evaluation screen once the clearance was 30 days old.
This screen checked for a possible unreviewed safety question and documented that evaluation.
The results were negative, i.e.,
no unreviewed safety question existed.
The inspector reviewed other (10 CFR 50.59) licensee documents:
procedure O-ADH-518, Conditioned Reports;
procedure O-ADM-701, Control of Maintenance and Construction Work Activities; procedure O-ADM-220, Abandoned Equipment; procedure gP-3.4, Plant Changes and Modifications; procedure gI 3-PTN-1, Design Control; procedure JPN g1-3.9,
CFR 50.59 Screening/Evaluation; Guidance For Performing
CFR 50.59 Safety Evaluations; and NSAC-125, Guidelines For
CFR 50,59 Safety Evaluation.
The inspector noted that the licensee generally meets the requirement for 10 CFR 50.59 safety evaluations and screening.
However, one issue was noted concerning the performance of mairitenance
'or equipment malfunction that does not make systems inoperable.
Systems are described in the UFSAR, and any deviations from this design should be reviewed per
CFR 50.59.
Licensee procedures 0-ADM-701 and 0-ADM-212 provide guidance for maintenance and clearances.
However, only after one month of a clearance does a
CFR 50.59 screen become documented, The inspector stated that an up-front screen/evaluation should be performed and documented.
In the particular case of valve CV-3-2202, a safety evaluation had been previously performed.
However, there is no procedural guidance to ensure that work under a
PWO and/or a clearance, which changes UFSAR design/description of systems, would be screened for 10 CFR 50.59 applicability.
The licensee concurred that this program issue could be enhanced.
Corrective actions included a night order book entry to remind NPS/ANPS personnel to perform
CFR 50.59 screenings/evaluations per block 6 of Form No.
57145A (e.g.,
safety review and unreviewed safety question determination).
In addition, the appropriate procedures will be considered for revisions.
The inspector also noted that the USFAR Section 9.6.2 for the ICW system was deficient as follows:
The single failure issue of valves 3,4-CV-2201 and 2202 was not addressed, the CCW heat exchanger amertap system is not currently used, and figures do not reflect ICW system operation/alignment.
The inspector discussed this issue with the licensee, and the licensee stated that corrective actions would be initiated to change/correct the appropriate USFAR section Exit Interview Item Number The inspection scope and findings were summarized during management interviews held throughout the reporting period with both. the site vice president and plant general manager and selected members of their staff.
An exit meeting was conducted on February 1,
1994.
The areas requiring management attention were reviewed.
The licensee did not identify as proprietary any of the materials provided to or reviewed by the inspectors during this inspection.
Dissenting comments were not received from the licensee.
The inspectors had the following finding:
Descri tion and'eference 50-2507251/94-01'-01 NCV - past due medical examination for licensed individuals (section 4.2. 1).
Acronyms AC ADM amps ANPS AP ASCO BD CCW CFR cm CME CNRB CS CV DC ECA ECC EDG EOP ESF EQ oF FPL GOP gpm HHSI HP I&C ICW IFI IN JPE JPN and Abbreviations Alternating Current Administrative Amperes Assistant Nuclear Plant Supervisor Administrative Procedure Automatic Switch Company Basis Document Component Cooling Water Code of Federal Regulations Centimeter
=
Corrective Maintenance
- Electrical Company Nuclear Review Board Containment Spray Control Valve Direct Current Emergency Contingency Actions Emergency Containment Cooler Emergency Diesel Generator Emergency Operating Procedure Engineered Safety Feature Environmental Qualification Degrees Fahrenheit Florida Power and Light General Operating Procedure Gallons Per Minute High Head Safety Injection Health Physics Instrumentation and Control Intake Cooling Water Inspector Followup Item Information Notice Juno Project Engineering Juno Project Nuclear
KW LCO LER LR HEP MOV HSIV HVAR Mwe NCV NPS NRC NSAC ODCM ONOP OP OSP OSRE P&ID PC/H PHT PNSC Pslg PTN PWO
'PS RT RWST SCR SEIS SI STA SV TP TPCW TS UFSAR VCT VIO
Kilowatt Limiting Condition for Operation Licensee Event Report Licensing Group (Engineering)
Minor Engineering Package Motor Operated Valve Main Steam Isolation Valve Mega Volts Ampheres Reactive Megawatts Electric Non-Cited Violation Nuclear Plant Supervisor Nuclear Regulatory Commission Nuclear Safety Analysis Center Offsite Dose Calculation Manual Off Normal Operating Procedure Operating Procedure Operations'urveillance Procedure Operational Safeguards Response Evaluation Piping and Instrumentation Diagram Plant Change/Modification Post-Maintenance Test Plant Nuclear Safety Committee Pounds Per Square Inch Gauge Project Turkey Nuclear Plant Work Order Quality Assurance Quality Control Quality Instruction Quality Procedure Reactor Coolant Pump Reactor Coolant System Radiation Equivalent Han Reactor Operator Reactor Protective System Reactor Trip (Relay)
Refueling Water Storage Tank Silicone Controlled Rectifier Safety Evaluation I&C - Site Safety Injection Shift Technical Advisor Solenoid Valve Temporary Procedure Turbine Plant Cooling Water Technical Specification Updated Final Safety Analysis Report Volume Control Tank Violation