IR 05000250/1994010
| ML17352A675 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 06/07/1994 |
| From: | Binoy Desai, Johnson T, Landis K, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17352A674 | List: |
| References | |
| 50-250-94-10, 50-251-94-10, NUDOCS 9406290043 | |
| Download: ML17352A675 (44) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900 ATLANTA,GEORGIA 303234199 Report Nos.:
50-250/94-10 and 50-251/94-10 Licensee:
Florida Power and Light Company 9250 West Flagler Street Miami, FL 33102 Docket Nos.:
50-250 and 50-251 License Nos.:
DPR-31 and DPR-41 Facility Name:
Turkey Point Units 3 and
Inspection Conducted:
hiay 1 through 28, 1994 Inspectors:
T.
P. JohIIson, Senio Resident Inspector
~!('. 4 L B.
B. Desai, Residen Inspector L. Trocine, Resident I spector Accompanied by:
RE P. Schin, Project Engineer, Divisio of Reactor Projects
/
K. D. Landis, Chi Reactor Projects Section 2B Division of Reactor Projects C'ate S gned I.
Dat Signed Dat Si ned Reactor Projects Section 2B, (s /i!fV Date Signed SUMMARY Scope:
This resident inspection was performed to assure public health and safety.
It involved direct inspection at the site in the following areas:
plant operations including engineered safety features walkdowns. operational safety, and plant events; maintenance including surveillance observations; engineering; and plant support including radiological controls, chemistry, fire protection, and housekeeping.
Backshift inspections were performed in accordance with Nuclear Regulatory Commission inspection guidance.
940b290043 940b09 PDR ADOCK 05000250
Results:
Within the scope of this inspection, the inspectors determined that the licensee continued to demonstrate satisfactory performance to ensure safe plant operations.
The following inspector followup item was identified:
Inspector Followup Item 50-250,251/94-10-01
- Review the Results of a Containment Structures Re-Analysis With Regard to the New Containment Design Pressure and the Adequacy of the Containment Tendon Prestress Forces (section 6.2.7)
During this inspection period, the inspectors had comments in the following Systematic Assessment of Licensee Performance functional areas:
Plant 0 erations The Unit 3 emergency diesel generators were satisfactorily aligned for standby operation; minor deficiencies were addressed by the licensee (section 4.2. 1).
Operators responded timely and professionally to an inadvertent Unit 3/4 engineered safeguards features actuation (section 4.2.2).
Facility tours demonstrated that Unit 3 was ready to support power.operations following a refueling outage.
However, a weakness was identified relative to the scaffold program concerning safety-related equipment (section 4.2.3).
The licensee's startup readiness process for Unit 3 was effective in assuring conservative and safe plant operation (section 4.2.4).
Startup activities including zero power physics testing were conducted in accordance with procedures without any complications (section 4.2.5).
The licensee aggressively and effectively followed up on three previous violations (section 4.2.6).
Maintenance Inspector observed surveillances and maintenance activities were conducted in a satisfactory manner (sections 5.2. 1 and 5.2.2.)
The licensee satisfactorily completed maintenance activities which they had committed to do associated with safety injection check valves, solenoid-actuated air-operated valves, and incore detector system (sections 5.2.3, 5.2.4, and 5.2.5).
Due management attention was given to ensure completion of permanent repairs on components that were temporarily repaired with Furmanite.
Permanent repairs on all such components were completed on Unit 3 prior to startup (section 5.2.6).
Dynamic testing of motor-operated valves was appropriately conducted (section 5.2.7).
A sufficient number of individuals from various disciplines was available for tne perrormance of the Unit 3 engineered safeguards i>>tegrated testing, and it was completed satisfactorily.
The test briefings were comprehensive and professional, and the personnel involved were familiar with their duties and knowledgeable of the systems involved.
Management presence was also evident during the test evolutions, and the decision to re-perform sections of the train A test to verify data was conservative (section 5.2.8).
En ineerin Engineering activities associated with an unplanned Unit 3/4 safeguards actuation demonstrated strong knowledge and a conservative approach to safety (section 4.2.2).
The onsite engineering staff promptly and efficiently resolved the test exception issues that were identified during the performance of the Unit 3 engineered safeguards integrated testing (section 5.2.8).
Engineering event response team efforts and followup efforts in evaluating the safety significance of equipment failures that occurred just prior to and during the performance of the engineered safeguards integrated testing were noteworthy (section 6.2. 1).
The plant change/modification package associated with the elimination of the circuitry for the turbine trip on a dropped rod adequately documented the modification, and the work performed in accordance with this package was well planned and implemented (section 6.2.2).
Modifications to the Unit 3 main turbine hydraulic control system were satisfactorily performed (section 6.2.3).
A modification associated with safety-related relays was appropriately documented (section 6.2.4).
The plant change/modification associated with the refurbishment and upgrade of the 3A reactor coolant pump motor was successfully completed (section 6.2.5).
A meeting conducted with licensee representatives in the Nuclear Regulatory Commission Region II office was beneficial in understanding the licensee's recent engineering and technical efforts in supporting the plant.
The elimination of numerous operator work-arounds was considered to be a very positive effort (section 6.2.6).
An inspector followup item was opened involving a containment structures re-analysis with regard to the new containment design pressure and the adequacy of the containment tendon prestress forces (section 6.2.7).
A special report regarding an emergency diesel general failure was accurate and appropriately submitted (section 6.2.8).
Plant Su ort The Unit 3 containment closure process was effective; and material condition, housekeeping, and cleanliness were good (section 7.2. 1).
The licensee appropriately responded to Unit 3 refueling outage personnel contamination events (section 7.2.2).
The 1993 Annual Environmental Report was complete and met technical specification requirements (section 7.2.3).
TABLE OF CONTENTS 1.0 Persons Contacted................
1. 1 Licensee Employees
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1.2 NRC Resident Inspectors....
1.3 Other NRC Personnel On Site.....
2.0 Other NRC Inspections Performed During This 3.0 Plant Status Period.............
3.1 Unit 3 3.2 Unit 4............
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4.0 Plant Operations
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4. 1 Inspection Scope 4.2 Inspection Findings
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5.0 Maintenance...............
5. 1 Inspection Scope
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5.2 Inspection Findings 6.0 Engineering....
6. 1 Inspection Scope...
6.2 Inspection Findings
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17 7.0 Plant Support
7.1 Inspection Scope 7.2 Inspection Findings 8.0 Exit Interviews
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9.0 Acronyms and Abbreviations
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REPORT DETAILS 1.0 Persons Contacted 1. 1 Licensee Employees T. V. Abbatiello, Site guality Manager H. J. Bowskill, Reactor Engineering Supervisor D. A. Culpepper, Chief, Engineering Assurance S.
H. Franzone, Instrumentation and Controls Maintenance Supervisor R. J. Gianfrancesco, Maintenance Support Services Supervisor R.
G. Heisterman, Mechanical Maintenance Supervisor P.
C. Higgins, Outage Hanager G.
E. Hollinger, Training Manager D.
E. Jernigan, Operations Manager'.
H.
H. Johnson, Operations Supervisor V. A. Kaminskas, Services Manager J.
E. Kirkpatrick, Fire Protection/Safety Supervisor J.
E. Knorr, Regulatory Compliance Analyst R.
S. Kundalkar, Engineering Manager J.
D. Lindsay, Health Physics Supervisor J.
Marchese, Site Construction Manager F.
E. Harcussen, Security Supervisor H.
N.
Paduano, Manager, Licensing and Special Projects L.
W. Pearce, Plant General Manager H. 0. Pearce, Electrical Maintenance Supervisor T.
F. Plunkett, Site Vice President D.
R. Powell, Technical Manager D.
C. Poteralski, Manager, Nuclear Fuels R.
E.
Rose, Nuclear Materials Manager W. A. Skelly, Supervisor, Reliability and Risk Assessment R.
N. Steinke, Chemistry Supervisor H.
B. Wayland, Maintenance Hanager E. J.
Weinkam, Licensing Manager Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, mechanics, and electricians.
1.2 NRC Resident Inspectors B. B. Desai, Resident Inspector T.
P. Johnson, Senior Resident Inspector L. Trocine, Resident Inspector 1.3 Other NRC Personnel on Site R.
P. Schin, Project Engineer
- K. D. Landis, Chief, Reactor Projects Section 2B
Attended exit interview on Hay 27, 1994
Note:
An alphabetical tabulation of acronyms used in this report is listed in the last paragraph in this report.
2.0 Other NRC Inspections Performed During This Period None 3.0 Plant Status 3.1 Unit 3 At the beginning of this reporting period, Unit 3 was in Mode
while in the Cycle 14 refueling outage.
Unit 3 was brought to Mode 5 on Hay 4, 1994, following completion of reactor vessel head tensioning activities and to Mode 4 on Hay 13, 1994.
Mode 3 was entered on Hay 14, 1994, and the reactor reached criticality on Hay 17, 1994.
The unit was placed on line on Hay 19, 1994, at approximately 6:51 a.m.
(Refer to section 4.2.5 for additional information.)
Power was increased to 100% on Hay 24, 1994, following Furmanite repairs to the 3A main feedwater pump casing.
A load reduction was commenced on Hay 26, 1994, following indications of a condenser tube leak.
The unit was later taken off line on Hay 27, 1994, to effect repairs on the orifice associated with the main turbine control oil system.
The unit was placed back on line later that day.
The unit was brought to 60%
on Hay 28, 1994, due to another condenser tube leak.
3.2 Unit 4 At the beginning of this reporting period, Unit 4 was operating at or near 100% power and had been on line since March 18, 1994, A
load reduction to 40% power was initiated on Hay 23, 1994, to perform a scheduled turbine valve testing surveillance and to clean the condenser water boxes and the turbine plant cooling water heat exchangers.
The unit was returned to 100% power on Hay 26, 1994.
Later that day, power was reduced to approximately 60%
to accommodate repairs on the 4A main feedwater pump.
The unit remained at 60% through the end of this reporting period.
4.0 Plant Operations (40500, 60710, 71707, 71711, 92901, and 93702)
4.1 Inspection Scope The inspectors verified that FPL operated the facilities safely and in conformance with regulatory requirements.
They accomplished this by direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety system status and technical specification compliance, review of facility records, and evaluation of the licensee's management contro The inspectors reviewed plant events to determine facility status and the need for further followup action.
The significance of the event was evaluated along with the performance of the appropriate safety systems and the actions taken by the licensee.
The inspectors verified that required notifications were made to the NRC and that licensee followup including event chronology, root cause determination, and corrective actions were appropriate.
The inspectors reviewed previous noncompliances to assure that corrective actions were adequately implemented and resulted in conformance with regulatory requirements.
The inspectors performed an inspection designed to verify the status of the selected systems.
This was accomplished by performing a complete walkdown of all accessible equipment.
The inspectors reviewed system procedures, housekeeping and cleanliness, major system components, valves, hangers and supports, local and remote instrumentation, and component labelling.
The inspectors performed a review of the licensee's self assessment capability by including PNSC and CNRB activities, QA/QC audits and reviews, line management self-assessments, individual self checking techniques, and performance indicators.
4.2 Inspection Findings 4.2. 1 Unit 3 EOG Walkdowns The inspectors performed a walkdown designed to verify the status of the 3A and 3B EDGs and their support systems.
This was accomplished by performing a complete walkdown of all accessible equipments The following criteria were used, as appropriate, during this inspection:
system lineup procedures matched plant drawings and as-built configuration; appropriate levels of housekeeping cleanliness were being maintained; valves in the system were correctly installed and did not exhibit 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;
4.2.2 local and remote position indication was compared, and remote instrumentation was functional; major system components were properly labeled; surveillance testing procedures and activities were appropriate; and maintenance activities (past, current, and planned)
were appropriate.
The inspectors concluded that the 3A and
EDGs were satisfactorily aligned for standby emergency operation.
Minor lineup and labelling deficiencies were discussed with engineering, operations, and maintenance personnel.
The inspectors noted that the 3B EDG air dryer system was out of service for corrective maintenance.
The inspectors also reviewed the clearance (No. 3-94-04-132),
the UFSAR, and the design basis document and verified that system operability was not affected.
In addition, there was a
TSA (No. 03-94-23-05)
associated with the 3A EDG PT fuse holder.
Apparently, during EDG maintenance activities, it was noted that fuse holder clip for Fuse No.
14 in panel 3E04A was damaged, The licensee could not obtain replacement parts and, therefore, elected to perform a TSA to ensure EDG operability.
This TSA compensated for the broken fuse holder with a hard wired jumper from the fuse mounting bolt to the corresponding stab mounting bolt.
Fuse operation was not affected.
The TSA included safety and engineering evaluations which concluded that the EDG was fully operable and that no unreviewed safety question existed.
The licensee intends to repair the fuse clip permanently when spare parts become available.
The inspector reviewed the TSA, the evaluation, a
special report (Refer to section 6.2.8 for additional information.), condition report No.94-428, electrical drawings, and discussed the TSA with engineering personnel.
The inspector had no further questions at this time.
Unplanned Unit 3/4 ESF Actuation During Re-energization of the Unit 3 Safeguards Instrumentation Racks At 5:25 p.m.
on Nay 5, 1994, an inadvertent ESF actuation occurred on both Units 3 and 4, The licensee was returning the Unit 3 safeguards instrument racks to service following the refueling outage per procedure 3-0NOP-049, Re-energizing Safeguard Racks After Loss of Single Power Supply.
Step 5. 1.8 of that procedure placed both control room SI block switches in neutral, and performance of this step was followed by an unexpected train A safeguards actuation.
The licensee responded to the actuation and noted that the 4A HHSI pump did not start as was expected.
Equipment was secured and
isolations were reset.
Unit 3 shutdown cooling was maintained throughout the event.
Unit 4 power operation was unaffected.
The licensee declared the 4A HHSI pump out of service, entered the appropriate technical specification action statements, initiated a
condition report, convened an ERT (Refer to section 6.2. 1 for additional information,), notified the resident inspectors, and made a 4-hour ENS call as required.
The licensee determined that SI block switch seal in-relay (SIB1)
failed due to a dirty relay contact.
This resulted in the SI signal not being bypassed when the ONOP steps re-energized the logic.
The relay was replaced, and the FPL lab examined the failed relay.
The licensee determined that a silver sulfide film on the contact caused intermittent contact operation.
This was due to it being infrequently operated.
The licensee revised its periodic inspection procedures to ensure this issue is examined in the future.
The licensee further determined that the 4A HHSI pump failure to start was due to misoperation of the relays (34/4A3 and TB/4A3)
which are designed to close the pump motor 4KV breaker.
The relays are physically located in the 4A sequencer cabinet, and they get an initiation signal from the 3A sequencer cabinet.
The licensee developed a plan to replace these relays per procedure TP-1067, 4A Sequencer Relay Replacement for 4A HHSI Pump and Functional Test.
This required taking the 4A sequencer out of service and entering Technical Specification 3.0.3 due to Technical Specification Table 3.3-2, item 6.d, action No. 23.
(The AFW bus stripping ESF logic requires one undervoltage sensor per vital bus.
This was not met with the 4A sequencer being out of service.)
The licensee briefed the inspectors and held a
conference call with NRC Region II and NRR personnel prior to entering Technical Specification 3.0.3.
Technical Specification 3.0.3 was subsequently entered For 17 minutes on May 6, 1994, for replacement of the relays.
The circuit, including the new relays, was satisfactorily tested the same day.
The inspector reviewed this event by performing the following actions; monitored post-event control room indications; reviewed control room logs and the condition report; monitored ERT activities; reviewed the
CFR 50.72 report; discussed the safeguards logic and prints with engineering personnel; inspected the control room and sequencer cabinets;
4.2.3 attended the PNSC meeting which approved procedure TP-1067; participated in the conference call with NRC Region II and NRR personnel; discussed the event, repairs, and testing with plant management; witnessed relay replacement and testing activities; and verified compliance during Technical Specification 3.0.3 entry.
The inspector concluded that control room operators responded to the unplanned ESF actuation in a professional and timely manner.
Engineering followup was thorough and demonstrated strong safeguards logic knowledge.
Repair and test activities were conservative and demonstrated a safety conscious approach.
(Refer to sections 5.2.8 and 6.2. 1 for additional information.)
I Plant Tours During the inspection period, the inspectors toured the facility periodically checking for plant and system status, material condition, deficiencies, and containment isolation lineup.
In particular, the inspectors toured most areas of Unit 3 prior to the entries into Hodes 4, 3, 2,
and 1.
The inspectors verified that plant and system conditions were appropriate to support the unit's return to service following the Cycle 14 refueling outage.
The inspectors noted that Unit 3 was generally in good material condition and that systems were appropriately aligned per the completed system or lineup check lists.
Specific deficiencies included missing floor drain covers, material adrift in several rooms, control room instrument problem list (green tags)
not consistent with plan-of-the-day listing, the 3H HCC out of service, and other minor items.
The inspector verified that the 3C HCC was not required by technical specifications, and it was returned to service prior to Hode 2 entry.
The inspectors also noted that scaffolding remained in place in the vicinity of safety-related equipment, The inspectors verified that the scaffolding was appropriately erected.
The inspectors noted that one scaffold (No. 2451)
remained over the Un>t 3 AFW Train 1 piping in the CST room.
The scaffold request form incorrectly noted that no safety equipment was effected.
The
'inspectors informed the NWE who immediately verified that the scaffold was adequate and documented as such on the scaffold tag.
The inspectors reviewed the scaffold program per procedure 0-ADH-012, Scaffold Control.
(Refer to section 4.2.3 of NRC Inspection Report 50-250,251/94-07 for additional information.)
It is left
up to the department erecting scaffolding to make a safety-related call.
The inspectors considered this a weakness in the licensee's scaffold program and plan to follow this issue during a future inspection.
These items were discussed with licensee management.
The inspectors verified that specific items were corrected and concluded that Unit 3 was ready to support post-refueling power operations.
4.2.4 Unit 3 Startup Readiness In addition to the normal general operating procedural controls for heatup and startup (procedures 3-GOP-301 and 3-GOP-503),
the licensee performed independent verifications and checks by implementing temporary procedure T0'-1065, Unit Restart Readiness.
This process included the following activities:
system engineer completion of readiness checklists for their specific systems; reviewed the clearance log, the equipment out-of-service log, PWOs, fire impairments, PC/Hs, TSAs, condition reports, system lineups, and surveillances; letters from each department head documenting readiness for restart; PNSC review of restart readiness; and final plant general manager review and determination.
The inspectors assessed the licensee's process, attended the PNSC meeting, reviewed the completed TP, and discussed the process with licensee management.
The inspectors concluded that this process appeared effective and demonstrated conservatism in assuring that Unit 3 would be returned to service safely following the refueling outage.
The inspectors independently reviewed Unit 3 restart readiness by performing the following tasks:
reviewed selected open and closed work items including post-maintenance testing, deficiencies, and commitments (e.g.,
condition reports, PWOs, PMAIs, CTRAC items, etc.);
verified system lineups and equipment availability by checking TSAs, system OP checklists, the TSA log, clearances, and the equipment out-of-service log; toured the facility (Refer to sections 4.2.3 and 7.2.2 for additional information.);
reviewed control room instruments, alarms, and controls;
reviewed general operating procedure implementation; reviewed operator training and readiness; reviewed outage PC/H completion, testing, and turnover; reviewed startup testing procedures and readiness; reviewed surveillance testing completion; reviewed and verified local leakrate testing and containment integrity; and reviewed ISI and erosion/corrosion inspections and repairs.
The inspectors concluded that Unit 3 was ready to support power operation.
One noteworthy item was operator training.
Reactor and plant startup training and modification training was given to all licensed operators.
4.2.5 Unit 3 Mode Changes and Startup Following completion of the refueling outage, startup activities were commenced on Unit 3 in accordance with approved procedures.
Unit 3 entered Mode 5 (Cold Shutdown)
on Hay 4, 1994, following completion of reactor vessel head tensioning activities.
The unit was taken to Mode 4 (Hot Shutdown)
on May 13, 1994, and to Mode
(Hot Standby)
on Hay 3, 1994.
The unit was taken critical at 4: 12 a.m.
on Hay 17, 1994.
Critical boron concentration was 1666 ppm and control rod group D was at 188 steps as expected.
Following completion of zero power physics testing, Unit 3 entered Mode 1 at 2:15 p.m.
on May 18, 1994.
The inspectors observed a large portions of the startup activities including the zero power physics testing.
The inspectors determined that startup activities were conducted in accordance with approved procedures with a sufficient compliment of licensed personnel as well as support by station staff including reactor engineers and management.
gA personnel presence was also noted.
4.2.6 Review of Previous Noncompliances 4.2.6.
(Closed)
VIO 50-250,251/93-01-02, Failure to Follow Procedures in the Area of Conduct of Operations Resulting in the Isolation of Containment Spray Prior to RCS Temperature Going Below 200'F The licensee responded to the NOV by a letter dated March 15, 1993.
The response included a discussion of completed and planned corrective actions associated with the violation.
These included revision of several administrative and operations procedures to better control activities during startup and shutdown evolutions and also included communication between shift personnel as a gA
audit criterion.
In addition, the importance of good communications was stressed by management during shift meetings and during non-licensed operator requalification classes.
The inspector verified the implementation of these corrective actions.
The inspector also concluded that although communication-related issues occasionally occur, overall operator performance in this area has improved and corrective actions appeared to be effective.
Therefore, this violation is closed.
4.2.6.2 (Closed)
VIO 50-250,251/93-21-01, Failure to Follow a Procedure Resulting in a Feedwater Transient and Subsequent Reactor Trip The licensee responded to the NOV by a letter dated October 14, 1993.
The response included a discussion of completed and planned corrective actions associated with the violation.
The licensee reviewed procedure 4-OSP-081. 1, Feedwater Heaters, Extraction Steam, Vents, and Drains, Valve Alignment, to provide better direction on sequential and/or simultaneous performance of sections.
In addition, the thermal relief valves on the 6A and 6B feedwater heaters on Units 3 and 4 were replaced with ones with a higher setpoint.
This was done to avoid system lineups that contributed to the reactor trip during future plant startups.
The inspector reviewed the licensee's corrective actions.
This violation is closed.
4.2.6.3 (Closed)
VIO 50-250,251/93-24-02, Inadvertent Overdilution The licensee responded to the NOV by a letter dated December 16, 1993.
The response included a discussion of completed and planned corrective actions associated with the violation.
The corrective actions included a night order requiring RCOs to remain at the control board during reactivity changes, discussion of this event by senior plant management with all the operating crews, and a
letter to all operators reminding them of the need to log reactivity changes.
Additionally, a requirement for the ANPS to remain within the operating area of each unit's main control board to provide additional supervisory oversight was imposed until plant management was satisfied that all crews had adequately demonstrated their commitment to the procedural requirements and manageme'nt expectations described above.
The inspector concluded that the corrective actions were effective in sensitizing licensed operators to the importance of need for positive control over evolutions affecting reactivity changes.
This violation is close.0 Maintenance (61701, 61702, 61708, 61710, 61726, 62703, and 92902)
5. 1 Inspection Scope The inspectors verified that station maintenance and surveillance testing activities associated with safety-related systems and components were conducted in accordance with approved procedures, regulatory guides, industry codes and standards, and in conformance with the technical specifications.
They accomplished this by observation of maintenance and surveillance testing activities, performing detailed technical procedure reviews, and reviewing completed maintenance and surveillance documents.
The inspectors reviewed open items to assure that corrective actions were adequately implemented and resulted in conformance with regulatory requirements.
5.2 Inspection Findings 5.2. 1 Maintenance Witnessed The inspectors witnessed/reviewed portions of the following maintenance activities in progress:
repair of the 4A main feedwater pump per procedure 0-CMM-074.2, Main Feedwater Pump Repair; procedure 0-PME-005. 11, 4160V
"ASEA Brown Boveri" Breaker Inspection and Cleaning; procedure 3-PMI-028.3, RPI Hot Calibration, CRDM Stepping Test, and Rod Drop Test; Unit 3/4 safeguards logic troubleshooting per procedure TP-1067, 4A Sequencer Relay Replacement for 4A HHSI Pump and Functional Test (Refer to section 4.2.2 for additional information.);
replacement of two defective relays on 4A sequencer per WR No.
9401101601 and procedure O-PMI-024.4, Emergency Load Sequencer Relay Inspection and Replacement (Refer to section 4.2.2 for additional information.);
and replacement of TDRL-n-A zvb ilmel relay.
(rceTel l~o section 6.2.2 for additional information.)
'or those maintenance activities observed, the inspectors determined that the activities were conducted in a satisfactory manner and that the work was properly performed in accordance with approved maintenance work order.2.2 Surveillance Tests Observed The inspectors witnessed/reviewed portions of the following test activities:
procedure 3-OSP-023. 1, Diesel Generator Operability Test; procedure 0-0SP-040.5, Nuclear Design Verification; procedure 0-0SP-040.6, Initial Criticality After Refueling; procedure 3-OSP 51.5, Type C Leakrate Testing; procedure 3-OSP-089. 1, Turbine Generator Overspeed Trip Test; procedure TP-1067, 4A Sequencer Relay Replacement for 4A HHSI Pump and Functional Test (Refer to section 4.2.2 for additional information.);
procedure 3-0SP-023.2, Diesel Generator 24-Hour Full Load Test and Load Rejection Test; (Refer to section 5.2.8 for additional information).
procedure 3-OSP-203. 1, Train A Engineered Safeguards Integrated Test (Refer to section 5.2.8 for additional information.);
and procedure 3-0SP-203.2, Train B Engineered Safeguards Integrated Test.
(Refer to section 5.2.8 for additional information.)
The inspectors determined that the above testing activities were performed in a satisfactory manner and met the requirements of the technical specifications.
5.2.3 Anchor-Darling Check Valves In response to NRC Information Notice 88-85 and NRC Bulletin 89-02, the licensee replaced the stainless steel retaining block studs on 8-inch and 10-inch Anchor-Darling check valves with material made from 17-4 ph steel.
Industry experience indicated cracking of the stainless steel studs occurred due to stress corrosion cracking.
The licensee responded to this issue and has completed all inspections and replacements.
FPL letter L-90-195 dated June 8,
1990, indicated that all valves had been inspected
'and studs replaced except seven Unit 3 valves.
The licensee completed those valves during the fall 1992 and spring 1994 refueling outages.
The affected check valves were located in the SI and CVCS systems.
PC/H No.89-182 was developed to document the inspections and
replacements.
No deficiencies were noted during the check valve internal inspections.
Maintenance procedure O-CMM-062.3, Safety Injection System Accumulator Check Valve Maintenance, was implemented to perform the work.
WO Nos.
93021871 and 2 were performed documenting the work on the remaining two Unit 3 valves (3-876A and E).
The inspector verified licensee actions by reviewing the response to the NRC Bulletin, the PC/M package, the completed WOs, the post-maintenance testing, and the maintenance procedure.
The inspector concluded that the maintenance work was performed per the appropriate procedures/WOs and that licensee commitments were met.
5.2.4 Replacement of Solenoid-Actuated Air-Operated Valves In response to NRC Information Notice No. 88-24, the licensee replaced the ASCO 3-way solenoid valves for the Unit 3 feedwater bypass valves (FCV-3-479, FCV-3-489, and FCV-3-499).
The issue with the ASCO solenoid valve was a failure mechanism due to overtravel of the solenoid core caused by high air pressure.
This then resulted in the valve failing to reposition on loss of solenoid power.
The licensee tracked this issue as commitment CTRAC No. 93-0719-03.
PWOs Nos.
94003817, 94003814, 940033812, 94003813, 940003815, and 940003816 were completed during the current Unit 3 refueling outage.
These PWOs documented the replacement of the six ASCO solenoids (two per valve)
The inspector reviewed the Information Notice, the completed PWOs and the commitment closure documentation.
The inspector verified installation of these solenoids in the field and concluded that the licensee appropriately met its commitment.
No abnormal conditions were identified with the maintenance work and associated documentation.
5.2.5 Unit 3 Incore Detector System Repairs The licensee committed to performing modifications and maintenance on the movable incore neutron detector system for Unit 3 during this refueling outage as required by Technical Specification 3.3.3.2 and amendment No.
154 dated June 15, 1993.
This was necessary as a number of the detector paths were inoperable.
The amendment allowed operation of the incore system with less than a
normal llumoel'T Elelect01 paths.
The inspector verified that these actions were performed and
'eviewed a change notice dated April 26, 1994, which confirmed the,. 2. 6 5. 2. 7 5.2.8 Temporary Leak Repairs The inspector reviewed the list of existing Unit 3 temporary leak repairs using Furman ite sealing material and the associated work orders pend ing permanent repair.
There were approximately
Furman i te jobs pend i ng permanent repairs prior to the Cycle 1 4 Unit 3 refuel i ng outage.
S ix of these were on safety -related systems
.
During the current Unit 3 outage, the licensee completed permanent repairs on al 1 of the 54 leaks.
The inspector concluded that licensee practices associated with temporary leak repairs were conservative, and a
sufficient level of management attention was given to ensure completion of permanent repairs at the next ava i'1zbl e opportunity.
MOV Testing Pursuant to NRC Generic Letter 89'- 1 0 The inspectors reviewed procedures TP-1 027, Differential Pressure Testing of Safety Injection Motor Operated Valves MOV-3 - 869 and MOV-3 -843A
& B ;
TP - 1 029, Differential Pressure Testing of RHR Motor Operated Valves HOV-3 -872 and MOV-3 -863A
& B ;
and TP - 1 059, Differential Pressure Testing of CCW Motor Operated Valves HOV-3-749A, MOV-3-749B, HOV-3-716A, MOV-3-716B, MOV-3-1417, and HOV-3-1418.
These procedures were associated with dynamic testing of HOVs pursuant to the requirements of NRC Generic Letter 89-10.
The inspector noted that of the 15 safety-related MOVs tested during this Unit 3 refueling outage,
HOVs did not meet the initial acceptance criteria defined in the TP.
A condition report requiring further evaluation was initiated for each valve that did not meet the initial acceptance criteria.
The licensee completed the evaluations prior to startup and determined that the acceptance criteria had been conservatively set and that no operability issues existed for any of the HOVs.
An HOV inspection had been performed by region based specialists with particular focus on the programmatic aspects of HOV testing.
These region based inspectors plan to conduct a followup inspection in the future.
The resident inspectors plan to inform the specialists of the results of the HOV testing conducted during the recent Unit 3 refueling outage.
The inspectors had no further questions at this time.
Unit 3 Engineered Safeguards Integrated Testing The inspectors witnessed portions of the licensee's performance of procedure 3-0SP-023.2, Diesel Generator 24-Hour Full Load Test and Load Rejection; procedure 3-OSP-203. 1, Train A Engineered Safeguards Integrated Test; and procedure 3-0SP-203.2, Train B
Engineered Safeguards Integrated Test.
Procedure 3-0SP-023.2 required that the applicable EDG (3A or 3B)
be run at approximately 110% of its operating load for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and at 100%
of its operating load for 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br />.
It then required a full load
reject test to be ini'tiated by the opening of the respective EDG output breaker.
The licensee was then required to verify that the EDG did not trip and that specified voltage requirements were met.
In conjunction with the performance of procedure 3-0SP-023.2, section 7.2 of procedures 3-OSP-203.
and 3-0SP-203.2 required the licensee to perform a loss of offsite power test (on each train independently)
within 5 minutes of the initiation of the 'emergency stop signal to the operating EDG.
Tests involving SI with offsite power available and coincident with a loss of offsite power were also required to be performed (on each train independently)
per sections 7.3 and 7.4 of procedures 3-OSP-203.
1 and 3-0SP-203.2.
The following equipment problems were identified during the performance of this testing:
After a successful 24-hour run of the 3A EDG, the train A
loss of offsite power test was commenced at approximately 2: 15 p.m.
on Hay 7, 1994.
In response to a simulated bus undervoltage signal, the 3A EDG started and obtained rated voltage and frequency.
The 3A 4160-volt bus was stripped; however, the 3A EDG breaker failed to close.
Troubleshooting activities identified that the voltage sensing relay (VHR) which provides input to the ready to load permissive, had not picked up.
It was determined that the relay was out of tolerance and was picking up at 120 volts AC as opposed to the setpoint value of 113 volts AC.
The out-of-tolerance VHR relay utilized a solid state sensing circuit, and it had previously been tested by the vendor to operate within 1% over a specified ambient temperature range.
This temperature range had not been exceeded, and the device had most recently been calibrated on April 16, 1994.
Subsequent to the failure, the 3A VHR relay was bench tested for drift under various voltage and temperature conditions, and the device drifted approximately 4 volts to the opposite direction.
The licensee considered the setpoint drift experienced to be anomalous for this device.
As a result, the licensee returned this VHR relay to the vendor for possible failure mechanism identification.
The license intends to submit a special report for this failure, During troubleshooting activities for the 3A EDG breaker failure to close, a technician inadvertently grounded the voltage sensing circuit and blew a fuse.
The fuse isolated one phase of voltage sensed by the voltage regulator and caused the generator to overexcite.
The overexcitation caused the generator field breaker (CBX) to open.
Investigation of the generator field breaker indicated that the breaker dust cover was not in place and that there was high (2 ohms) resistance between the breaker contacts on one phase.
The condition of this breaker did not contribute directly to the 3A EDG breaker failur The licensee also removed, tested, and inspected the train B
breaker.
There were no anomalies identified on the train B
breaker, and it was placed back in service.
During the train A loss of offsite power coincident with an SI portion of the test on Hay 8, 1994, the containment spray pump failed to start.
The failure was traced to an HG-6 relay (Sl) in the RPS racks which latches when a high and high-high containment pressure signal is initiated.
The latched relay picks up an auxiliary relay which starts the containment spray pump and opens its associated discharge valve (HOV-3-880A).
The screw which holds the relay stationary contact in place was found to be loose.
As a
result, intermittent contact was made.
The screw was tightened, and the remaining five HG-6 relays in the train A safeguards racks were inspected and tightened as part of the inspection.
The six HG-6 relays in the train B safeguards rack were also inspected and tightened as necessary.
No other contact was found loose enough such that contact operation would not be assured.
The licensee also assigned an action item in the disposition of condition report No.94-582 for maintenance planning to revise procedure HI-63-004, for installation and maintenance of MG-6 relays to include inspection of the stationary contact screws.
An action item was also assigned to I&C maintenance to inspect/tighten the stationary contact screws in the Unit 4 HG-6 relays in the safeguards cabinet during the next refueling outage.
On Hay 9, 1994, an attempt was made to fill the surge tank for the 3B EDG while the 3B EDG was running unloaded at 900 rpm.
Due to the system lineup at the time, the operator inadvertently drained the surge tank, and the 3B EDG tripped on low cooling water pressure (35 psig)
immediately following the reset of the 'SI signal as per the safeguards testing.
The EDG trouble alarm had annunciated approximately three minutes prior to the reset action.
However, with the EDGs running in the emergency mode, the low water pressure trip is bypassed as a non-essential trip.
This event did not significantly affect the outcome of the safeguards testing.
The inspectors plan to review this event further following the issuance of the licensee's special report.
In addition to these equipment problems, the licensee identified
'10 test exceptions during the performance of procedure 3-OSP-203.
and 2 test exceptions during the performance of procedure 3-OSP-203.2.
As each test exception was noted, a test exception report was initiated to ensure resolution.
Although these test exceptions were minor in nature, the licensee opted to re-perform various sections of procedure 3-OSP-203.
1 in order to verify the
5.2.9 data received.
(Sections 7.2 and 7.4 were performed 4 times, and section 7.3 was performed twice.)
The inspectors witnessed portions of these tests activities and reviewed the documented test results for procedures 3-OSP-203.
and 3-0SP-203.2.
A sufficient number of individuals from various disciplines was available for the performance of these tests, and the testing was completed satisfactorily.
The inspectors also noted the presence of gA personnel performing independent assessments.
The test briefings were comprehensive and professional, and the personnel involved were familiar with their duties and knowledgeable of the systems involved.
Hanagement presence was also evident during the test evolutions, and the decision to re-perform sections 7.2, 7.3, and 7.4 of procedure 3-OSP-203.
an extra time to verify data was deemed to be conservative.
In addition, the onsite engineering staff promptly and efficiently resolved the test exception issues as they arose.
(Refer to sections 4.2.2 and 6.2. 1 for additional information.)
Open Items Review 5.2.9.
(Closed)
IFI 50-250,251/93-26-01, ECC Valve Failures This issue had been previously discussed in NRC Inspection Report Nos. 50-250,251/93-24, 50-250,251/93-26, and 50-250,251/94-01.
The licensee completed the modification involving changing the ECC solenoid valves from normally energized to normally de-energized in the standby mode.
In addition, the solenoid valves are currently being cycled on a 10-day frequency.
There have not. been any failures of the solenoid valves since the modification.
The inspector concluded that the licensee has given appropriate attention to resolving the issue.
This item is closed.
5.2.9.2 (Closed)
IFI 50-250,251/94-03-02, Hoisture Separator Reheater Drain Line Leaks This IFI concerned the steam leaks on the 3D and 3B HSR drain lines that occurred in February 1994 and in July 1993, respectively.
The IFI was opened pending a root cause analysis on the HSR drain line leaks.
The licensee completed the root cause analysis and confirmed that the failure mechanism for the 38 and 3D HSR drain line leaks was erosion/corrosion.
The inspector reviewed the root cause analysis and determined that corrective actions have already been initiated by the licensee to
'revent recurrence.
These corrective actions include increased inspection of the HSR drain piping and components that are susceptible to accelerated flow induced corrosion.
This IFI is close e
6.0 Engineering (37551, 90712, 90713, and 92700)
6.1 6.2 6.2.1 Inspection Scope The inspectors verified that licensee engineering problems and incidents were properly reviewed and assessed for root cause determination and corrective actions.
They accomplished this by ensuring that the licensee process included identifying, resolving, and preventing problems, and evaluating their self-assessment and control program.
The inspectors reviewed selected PC/Hs including the applicable safety evaluation, infield walkdowns, as-built drawings, associated procedure changes and training, modification testing, and changes to maintenance programs.
The inspectors reviewed an open item to assure that corrective actions were adequately implemented and resulted in conformance with regulatory requirements.
The inspectors reviewed the reports discussed below.
The inspectors verified that reporting requirements had been met, root cause analysis was performed, corrective actions appeared appropriate, and generic applicability had been considered.
When applicable, the criteria of 10 CFR Part 2, Appendix C, were applied.
Inspection Findings ERT Efforts and Engineering Followup of Safeguards Testing Failures In order to assess the safety significance of the equipment failures identified just prior to and during the performance of the Unit 3 engineered safeguards integrated testing (Refer to sections 4.2.2 and 5.2.8 for additional information.), the licensee developed several condition reports, formed several ERTs, and performed an engineering evaluation.
This evaluation (No.
JPN-PTN-SEIP-94-020)
provided a summary of the equipment failures experienced.
It evaluated the safety significance of these failures, identified the potential applicability of the identified failure modes to other equipment, and recommended corrective measures.
The licensee also compared these failures to industry failure data for the identification of failure trends and comparisons of failure frequencies.
The licensee's evaluations of the component failures indicated that the failure mechanisms were not unusual and that there were no common conditions related to operation, maintenance, or design which would have linked any of the failures.
The licensee did not identify any generic concerns regarding equipment operability.
In addition, the potential safety impact of these failures was
6.2.2 addressed for prior plant operation.
When considering these failures concurrent with a design basis accident and another single failure, the licensee's evaluation showed that an unacceptable condition would not have resulted.
In addition, when evaluated probabilistically, the additional failures resulted in less than a
5% increase in the total core melt frequency from internal events.
The inspectors attended some of the licensee's ERT meetings and followed up on the licensee's evaluations as they occurred.
The inspectors also reviewed the condition reports associated with these failures and the licensee's safety evaluation to assess the safety significance of these failures.
The licensee's ERT and engineering followup efforts in evaluating the safety significance of equipment failures just prior to and during the performance of the Unit 3 engineered safeguards integrated testing was noteworthy.
PC/H No.93-005, Elimination of Turbine Runback on Dropped Rod The automatic turbine runback feature at Turkey Point was designed to provide protective action in the event of a single dropped RCCA or dropped control rod 'bank.
Detection of a dropped RCCA or control rod bank occurred by either a rod-on-bottom signal device or by a change in neutron flux as seen by the NIS excore power range detectors.
The rod-on-bottom signal provided separate indication for each RCCA in the core, and one signal was sufficient to initiate the turbine runback.
In addition, a change in flux as seen by one of the four power range excore detectors would cause the turbine load to be reduced to a pre-set value when the selector switch was in the NIS position.
(This scenario was discussed and analyzed in section 14. 1.4 of the Turkey Point UFSAR.)
The design of the automatic turbine runback on a dropped rod was prone to spurious runbacks because there was no coincidence logic used in the initiation of the runback.
Therefore, a single failure of an electrical component, such as the burnout of an RPI or failure of one excore detector when in the NIS mode, would cause a turbine runback when it was not needed
- resulting in unnecessary plant transients and loss of availability.
Due to the fact that the majority of the spurious runbacks had resulted from failures in the flux rate input to the runback logic, this input was previously deleted from the turbine runback system during normal operation and the NIS switch position was only used for short time intervals while performing periodic maintenance or tests.
This modification was analyzed in appendix 14C of the UFSAR.
It was concluded that deletion of the flux rate portion of the turbine runback system was acceptable.
The reactor could be maintained in automatic rod control because the automatic rod withdrawal had also been eliminate In addition, the licensee's analysis of the dropped RCCA events at Turkey Point assuming no turbine runback verified that the DNBR would remain within its limit.
The, licensee subsequently concluded that the elimination of the automatic turbine runback following a dropped RCCA event would not have an adverse impact on plant safety.
During the Unit 3 Cycle 14 refueling outage, the licensee implemented PC/M No.93-005, Elimination of Turbine Runback on Dropped Rod.
This PC/M package provided the necessary documentation to facilitate the removal of turbine runback selector switch HS-3-6686 and its associated relays from control room panel 3C02 in order to eliminate the automatic turbine runback on a dropped RCCA.
Per th'is PC/H, the licensee performed the following work:
Selector switch HS-3-6686 and the corresponding relays used for the turbine runback on a dropped rod were disconnected and removed.
The control circuits were modified to maintain the remaining turbine runback functions created by events other than the rod drop.
(Turbine runbacks are also initiated by an approach to an overpower or overtemperature condition or any steam generator feedwater pump trip.)
The control board holes were covered, and some of the cables were spared.
Annunciator window B-7/2, Rod Drop Runback Switch Off Normal, was re-labelled as Spare, Annunciator window B-7/1, NIS/RPI Rod Drop Turb.
Runback Rod Stop, was re-labelled as NIS/RPI Rod Drop Rod Stop.
During the performance of procedure TP-1002, Operational Checkout of Remaining Turbine Runback Inputs for Unit 3, an RPS timer relay TDRL-X-A failed to cycle.
Because this relay was obsolete, the licensee generated PC/M No.94-050, TDRL-X-A Relay Changeout, and replaced this relay with a new model.
The licensee performed this work under PWO No. 94-00917401 and procedure O-GMI-102.1, Troubleshooting and Repair Guidelines.
OTSC No. 334-94 was also generated to incorporate the relay post-maintenance test per the PC/H.
The inspectors reviewed the PC/M package which included, among
'other things, a
UFSAR change package, safety evaluation No. JPN-PTN-SEFJ-92-014, a design basis document change package, and applicable plant drawings.
The inspectors also reviewed portions of three change request notices pertaining to this PC/H, procedure TP-1002, OTSC No ~ 334-94, implementor turnover package No. 94-04-008, and the system acceptance turnover sheet.
In addition, an
inspector observed the replacement of the relay.
The inspectors concluded that the PC/H package adequately documented the modification and that the work performed in accordance with this PC/H was well planned and implemented.
6.2.3 Unit 3 Hain Turbine Trip Modifications The licensee performed PC/Ms on the main turbine hydraulic control system effecting trip logic as follows:
PC/H No. 94-52 added an independent electric overspeed trip device for the Unit 3 hydraulic control system.
This trip function can be bypassed with a key lock switch.
It includes two pressure switches to sense main turbine oil pump discharge pressure, which will trip the turbine on an overspeed condition.
The licensee intends to operate with this independent overspeed trip system bypassed as long as the normal and backup trip protection systems are functional.
The PC/H also changed the turbine trip logic for devices 20/AST and 20/ASB to be 2-out-of-2.
PC/H No. 93-10 relocated the 20/ASB backup trip solenoid device, allowing it to remain functional during turbine front standard testing.
Previously, when the turbine test handle was engaged, the 20/ASB device and turbine trip logic were bypassed.
Vendor recommendations due to recent industry events resulted in a similar PC/M (No. 93-11) being performed on Unit 4 during the 1993 outage.
The 20/ASB connection point was moved to the high pressure oil supply side of the test handle.
The inspectors reviewed the PC/H packages including safety and engineering evaluations, drawings, process sheets, change notices, procedure changes, equipment listings, turnover documentation, and post-modification testing.
The inspector examined in-field installations and discussed the PC/Ms with licensee personnel.
The inspector also witnessed main turbine trip and overspeed testing.
The inspector concluded that the above mentioned PC/Hs were satisfactorily implemented.
6.2.4 Unit 3 Relay Replacement PC/H Nos.
93-82 and 93-182 The licensee replaced DC relays (ASCO) associated with the 3A/3B EDGs and the 3A/3B 4160-volt AC switchgear per PC/M No. 93-82.
Westinghouse BFD relays in the RPS were also replaced per PC/H No.93-182.
These PC/Hs were performed during the Unit 3 Cycle
refueling outage.
The licensee indicated that these relays were obsolete and that they were also experiencing reliability problems.
The inspector reviewed the completed PC/H packages including the safety evaluations, wiring and schematic drawings, environmental
6.2.5 6.2.6 qualification documentation, work orders, process sheets, post-modification testing, and turnover documentation.
The inspector also walked down portions of relay replacement work in the field.
The inspector did not identify any issues.
The completed PC/H packages and related documentation appeared satisfactory.
NRC specialists plan to further review these modifications in a future inspection.
PC/H No.93-217, 3A RCP Hotor Refurbishment/Upgrade This PC/H involved replacement of 3A RCP motor with a spare motor which had been refurbished at the Westinghouse Electro-Hechanical Division facility.
The refurbishment consisted of inspection and maintenance activities performed to the existing design specifications.
In addition, the spare RTD, the lower bearing labyrinth seal, the multi-port drain sump, the lower bearing support ring, the oil lift system, the lower cooling coil, and the thrust runner seal were modified to ensure consistency with the latest RCP technology and to realize additional reliability and availability.
The inspector reviewed the PC/H package and observed portions of activity associated with the removal of the old 3A RCP motor.
The inspector also observed portions of coupled and uncoupled RCP runs.
The inspector concluded that the 3A RCP motor was successfully replaced.
In addition, the seal package on the 3A RCP was replaced during the refueling outage.
The inspector concluded that the seal replacement as well as the PC/H were successfully completed.
Engineering and Technical Staff Information Heeting An engineering and technical staff information meeting was conducted at the licensee's request in the NRC Region II office on Hay 23, 1994, Representatives from the licensee's corporate and site engineering and technical groups and from the NRC's NRR and Region II offices (including resident inspectors from both St.
Lucie and Turkey Point) were in attendance.
The topics of discussion included a final report on an RCP failure at St. Lucie, recent St. Lucie engineering initiatives, the St.
Lucie PSA results and applications, the Turkey Point Unit 3 Cycle
refueling outage status, recent Tur key Point technical department initiatives, reactor physics vendor independence, and licensee self-assessment policies and multi-element processes'his meeting was beneficial in understanding the licensee's recent engineering and technical staff efforts in supporting the plant.
The elimination of numerous operator work-arounds was considered to be a very positive effor.2.7 Open Items Review (Closed)
LER 50-251/92-009, Containment Tendon Surveillance-Measured Prestress Force Lower Than Predicted At approximately 9: 17 a.m.
on November 17, 1992, with Unit 4 in Mode 1, the licensee measured a lift-offforce value less than 90%
of the predicted lower limit for Unit 4 containment tendon 35H38, and the action statement for Technical Specification 3.6. 1.6.a was entered.
With one tendon below 90% of the predicted lower limit, the action statement of Technical Specification 3.6. 1.6.a required the licensee to restore the tendon to the required level of integrity within 15 days, perform an engineering evaluation of the containment, and provide a special report to the NRC within 30 days.
The surveillance requirements of Technical Specification 4.6. 1.6.1 also required the licensee to measure the lift-off forces of the adjacent tendons.
The measured lift-offforces for tendons 35H39, 35H40, 35H41, and 35H42 were found by the licensee to be between the predicted lower limit and 90% of the predicted lower limit.
The licensee completed the retensioning of tendons 35H38, 35H39, 35H40, 35H41, and 35H42 at approximately 5:15 p.m.
on November 19, 1992, and the action statement for Technical Specification 3'. 1.6.a was exited.
The Unit 3 containment tendon twentieth-year tendon surveillance was performed during the period of June
- July 1992.
This surveillance was performed in a satisfactory manner and complied with the requirements of the technical specifications, (Refer to sections 7 and 14 of NRC Inspection Report Nos.
50-250,251/92-15 and 50-250,251/92-16, respectively, for additional information.)
Operability of Unit 4 tendon 35H38 was re-established by the revision of the calculated value for the predicted lower limit and minimum required prestress force for the'Unit 4 containment.
These values were initially calculated assuming a maximum containment design pressure of 59 psig and were subsequently revised to 55 psig, which is 110% of the current containment peak internal pressure based on a design basis LOCA.
As documented in the LER, the licensee planned to submit a license amendment request by June 1,
1993, to revise the technical specification design pressure of the containment buildings.
By letter dated May 21, 1993, the licensee submitted a license amendment request to modify the maximum containment design internal pressure from 59 psig to 55 psig in Technical Specification 5.2.2 and the associated bases.
This request was
"supplemented by the licensee on January 25, 1994, and this license amendment was granted by the NRC on March 30, 1994.
The licensee issued training brief No.
455 on April 4, 1994, in order to notify operations personnel of this change, and the amendment was fully implemented by the licensee on April 29, 199 The long-term corrective actions documented in this LER also included the preparation of a more detailed engineering evaluation to investigate the cause and extent of the low lift-offvalues in the Unit 4 containment structure post-tensioning system and to determine the length of time that the system would continue to satisfy the licensing basis requirements.
The licensee planned to submit this evaluation to the NRC by January 29, 1993.
By letter dated January 25, 1993, the licensee submitted a report to the NRC summarizing the surveillance testing of all hoop and dome tendons inspected during the Unit 4 twentieth-year tendon surveillance.
The licensee concluded that the probable cause for the low lift-offforces measured for the Unit 4 containment hoop and dome tendons was the increased tendon wire steel relaxation loss occurring at a tendon temperature which was higher than originally assumed.
The licensee also predicted that the Unit 4 hoop and dome tendons would provide sufficient prestress force to maintain the Turkey Point licensing basis requirements at least through the anniversary date for the twenty-fifth-year tendon surveillance including the 25% extension of the surveillance interval allowed by Technical Specification 4.0.2 (i.e.,
Hay 1998).
This prediction was based on the results of a regression analysis.
As a result of this issue, licensee representatives also met with the NRC staff in Rockville, HD, on January 11, 1993.
At this meeting, the licensee presented the details of the twentieth-year containment tendon surveillance results and its action plan to address the tendon low lift-offforces observed.
Following this meeting, the NRC issued a meeting summary dated January 25, 1993, in which the NRC staff requested additional information to support the tendon surveillance review.
The licensee responded to this request by letter dated August 10, 1993.
In this letter, the licensee stated that a re-analysis of the Turkey Point Unit 3 and 4 containment structures was in progress.
The re-analysis was being performed in accordance with the existing design basis as established by the Turkey Point UFSAR using a design internal pressure of 55 psig.
The licensee expects that this re-analysis will demonstrate the post-tensioning system's capability to meet the design basis requirements for the service life of the plant (i.e.,
40 years from the issuance of the operating license), will include a rate of steel relaxation representative of the actual conditions occurring at the plant, and will establish predicted upper and lower bound limits to which future tendon surveillance lift-offforces will be compared for acceptance.
This re-analysis is scheduled for completion prior to the twenty-fifth-year tendon
'surveillance but is currently expected to be completed early in 1995.
The NRC acknowledged this response by a letter dated Harch 30, 1994.
The inspectors verified the licensee's corrective actions and reviewed the applicable documentation.
Based on this review, the
LER is closed.
However, an IFI is being opened in order to ensure followup of the licensee's re-analysis of the Turkey Point Unit 3 and 4 containment structures.
This item will be tracked as IFI 50-250,251/94-10-01, Review the Results of a Containment Structures Re-Analysis With Regard to the New Containment Design Pressure and the Adequacy of the Containment Tendon Prestress Forces.
6.2.8 3A EDG Failure Special Report On April 21, 1994, the 3A EDG experienced a high voltage (5200 volts AC) condition for about one minute during post-maintenance testing.
The licensee tripped the EDG and initiated troubleshooting efforts.
The licensee concluded that the cause was a failure of PT fuse F-14 holder clip which was broken.
This resulted in a malfunction of the PT and associated voltage regulator.
Resistance checks of EDG were satisfactory, and the licensee implemented a temporary repair per TSA No. 03-94-23-05 (Refer to section 4.2. 1 for additional details.)
The licensee further concluded that this failure was non-valid.
A special report (L-94-123) dated May 18, 1994, was issued.
The inspectors reviewed the special report, the associated determinations, root cause and corrective actions.
The inspectors also discussed the issue with the system engineer.
The inspectors concluded that the special report was accurate and appropriately submitted'.2.9 Monthly Operating Report The inspectors reviewed the April 1994 Monthly Operating Report and determined it to be complete and accurate.
6.2.10 Annual ECCS Report The licensee's Annual ECCS Report (L-94-073)
was issued April 11, 1994, as required by 10 CFR 50.46.
The licensee reported that both Units 3 and
ECCS analysis met the 2200'F peak clad temperature limit for a small break and large break LOCA.
The inspectors reviewed the report, and determined it to be appropriate.
7.0 Plant Support (71750)
7.1 Inspection Scope The inspectors verified the appropriate licensee's implementation of the physical security plan, radiological controls, the fire protection program, fitness for duty, chemistry programs, emergency preparedness, plant housekeeping/cleanliness conditions,
7.2 7.2.1 and radiological effluent, waste treatment, and environmental monitoring programs.
Inspection Findings Unit 3 Containment Inspections Prior to entering Mode 4 (Hot Shutdown)
and Mode 2 (Startup),
the licensee performed a Unit 3 containment closeout inspection.
This activity was performed in accordance with procedure O-SMM-051.3, Containment Closeout Inspection.
The procedure and the associated checklists were performed on May 12 and 16, 1994.
Closeout personnel included participation from maintenance, gC, HP, operations, and construction.
Deficient items were documented and corrected.
7.2.2 The inspectors independently toured the Unit 3 containment on May 13 and 16, 1994, prior to the licensee's entries into Modes 4 and 2, respectively.
The inspectors noted that the containment was clean and overall material condition was good:
Specific minor deficiencies were discussed with plant management personnel.
The inspectors also reviewed the completed SMM procedure and noted that deficient items were captured in this document.
The inspectors concluded that the licensee's containment closure process appeared to be thorough and effective.
Personnel Contamination Events During the Unit 3 refueling outage, the licensee set a goal of no more than
PCEs.
However, the goal was not achieved as 116 PCEs occurred.
The licensee reviewed each event by documenting it with both a condition report and a personnel contamination event report.
Further, each PCE was reviewed by the ALARA Review Committee including discussions with the contaminated individual and his/her supervisor.
The licensee responded to each PCE by deconning the individual and/or the individual's clothing.
No excessive exposures occurred from these events.
The licensee also tabulated each PCE in a matrix format including the root cause.
Common causes for all PCEs were then evaluated.
The licensee was able to determine that poor work habits, contaminated protective clothing, implementation of the revised
CFR Part 20, and seal table work were common causes.
Longer-term corrective actions are being addressed.
The inspectors reviewed the PCEs including the associated reports
'and causes.
The inspectors also attended selected ALARA Review Committee meetings and discussed this issue with HP and plant management personnel.
The inspector concluded that the licensee appropriately responded to this issu.2.3 1993 Annual Environmental Operating Report The inspectors reviewed the 1993 Annual Environmental Operating Report dated April 25, 1994, per FPL letter L-94-094.
This report is required by 10 CFR 50.36 and Technical Specifications 6.9. 1.3 and 3/4. 12.
The licensee concluded that the levels of radiation and concentrations of radioactive material in the environment within the Turkey Point monitored areas were not being increased.
The inspector noted that all of the environmental monitoring direct radiation (TLD) data for the first quarter 1993 was unavailable due to personnel error which caused inadvertent TLD exposure from a source while in transit to the laboratory facility.
The report detailed this event and appropriate corrective actions.
Other issues related to lost and/or defective sampling equipment were also addressed.
The inspector determined that the report appeared complete and met Technical Specification requirements.
8.0 Exit Interview The inspection scope and findings were summarized during management interviews held throughout the reporting period with the site vice president and selected members of his staff.
An exit meeting was conducted on May 27, 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:
Item Number 50-250)251/94-10-01 Status Descri tion and Reference (Open) IFI - Review the Results of a Containment Structures Re-Analysis With Regard.to the New Containment Design Pressure and the Adequacy of the Containment Tendon Prestress Forces (section 6.2.7)
Additionally, the following previous items were discussed:
Item Number Status Descri tion and Reference 50-250,251/93-01-02 50-250,251/93-21-01 (Closed)
VIO - Failure to Follow Procedures in the Area of Conduct of Operations Pesulting in the Isolation of Containment Spray Prior to RCS Temperature Going Below 200'F (section 4.2.6. 1)
(Closed)
VIO - Failure to Follow a Procedure Resulting in a Feedwater Transient and Subsequent Reactor Trip (section 4.2.6.2)
50-250,251/93-24-02 50-250,251/93-26-01 50-250,251/94-03-02 LER 50-251/92-009
(Closed)
VIO - Inadvertent Overdilution (section 4.2.6.3)
(Closed)
IFI -
ECC Valve Failures (section 5.2.9.1)
(Closed)
IFI - Moisture Separator Reheater Drain Line Leaks (section 5.2.9.2)
(Closed)
LER - Containment Tendon Surveillance-Measured Prestress Force Lower Than Predicted (section 6.2.7)
9.0 Acronyms and Abbreviations AC ADM AFW ALARA ANPS ASB ASCO AST CCW CFR CMM CNRB CRDM CST CTRAC CVCS F
0 F DNBR ECC ECCS EDG ENS ERT ESF FCV FPL GMI, GOP HHSI HP HS ILC IFI ISI JPN KV Alternating Current Administrative Auxiliary Feedwater As Low As Reasonably Achievable Assistant Nuclear Plant Supervisor Automatic Stop Backup Automatic Switch Company Automatic Stop Trip Component Cooling Water Code of Federal Regulations Corrective Maintenance
- Mechanical Company Nuclear Review Board Control Rod Drive Mechanism Condensate Storage Tank Commitment Tracking Chemical Volume Control System Fuse Degrees Fahrenheit Departure From Nucleate Boiling Ratio Emergency Containment Cooler Emergency Core Cooling System Emergency Diesel Generator Emergency Notification System Event Response Team Engineered Safety Features Flow Control Valve Florida Power and Light General Maintenance
-
IKC General Operating Procedure High Head Safety Injection Health Physics Hand Switch Instrumentation and Control Inspector Followup Item Inservice Inspection Juno Project Nuclear Kilovolt
LER LOCA MCC HD MI MOV MSR NIS NOV NRC NRR NWE ONOP OP OSP OTSC PCE PC/H PMAI PME PMI ppm PNSC PSA Pslg PT PTN PWO QA QC RCCA RCO RCP RCS RHR RPI rpm RPS RTD SEFJ SEIP SI SHM TB TLD TP TSA UFSAR VIO VHR WO WR Licensee Event Report Loss-of-Coolant Accident Motor Control Center Maryland Maintenance Instruction Motor-Operated Valve Hoisture Separator Reheater Nuclear Instrumentation System Notice of Violation Nuclear Regulatory Commission Office of Nuclear Reactor Regula Nuclear Watch Engineer Off Normal Operating Procedure Operating Procedure Operations Surveillance Procedur On-the-Spot Change Personnel Contamination Event Plant Change/Hodification Plant Manager's Action Item Preventive Maintenance
- Electri Preventive Maintenance
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I&C Parts Per Million Plant Nuclear Safety Committee Probabilistic Safety Assessment Pounds Per Square Inch Gauge Potential Transformer Plant Turkey Nuclear Plant Work Order Quality Assurance Quality Control Rod Control Cluster Assembly Reactor Control Operator Reactor Coolant Pump Reactor Coolant System Residual Heat Removal Rod Position Indication Revolutions Per Minute Reactor Protective System Resistance Thermal Detector Safety Evaluation Fuels
- Juno Safety Evaluation IKC - Plant Safety Injection Surveillance Maintenance
- Mecha Terminal Block Thermoluminescent Dosimeter Temporary Procedure Temporary System Alteration Updated Final Safety Analysis Re Violation Voltage Metering Relay Work Order Work Request tion cal ni cal port
I'