IR 05000250/1993013
| ML17352A100 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 06/25/1993 |
| From: | Butcher R, Landis K, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17352A099 | List: |
| References | |
| 50-250-93-13, 50-251-93-13, NUDOCS 9307220082 | |
| Download: ML17352A100 (34) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION REGION 11 101 MARIETTASTREET, N.IIII.
ATLANTA,GEORGIA 30323 Report Nos.:
50-250/93-13 and 50-251/93-13 Licensee:
Florida Power and Light Company 9250 West Flagler Street Hiami, 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:
April 24 thr h Hay 28, 1993 Inspectors:
R.
C. But er, Se ior R ident Inspect L. Trocin Resident Inspector
/z Date igned az PZ Date igned Approved by:
I K. D. Landis, Chief Reactor Projects Section 2B Division of Reactor Projects Date Signed SUHHARY Scope:
This routine resident inspector inspection involved direct inspection at the site in the areas of surveillance observations, maintenance observations, engineered safety features walkdowns, operational safety, Unit 4 refueling activities, Unit 4 engineered safeguards integrated testing, Unit 4 startup from refueling, and plant events.
Backshift inspections were performed on April 26-30, and Hay 3-6, 10-13, 15-17, and 22-25, 1993.
Results:
In the operations area,-inadequate attention to. detail and.failure to follow a procedure resulted in an inadvertent boration event on Unit 3 (paragraph 13.b).
The fuel reloading process on Unit 4 was conducted in an efficient, professional manner with good communications between the refueling crews in containment, the spent fuel pit, and the control room.
Core reload was completed ahead of schedule (paragraph 10).
Briefings for the engineered safeguards integrated testing were very comprehensive and professional (paragraph 11).
9307220082 930625 PDR ADOCK 05000250
PDR '
Qi
In the maintenance/surveillance area, the Unit 4 steam generator eddy-current testing and, sludge lancing activities were well coordinated.
None of the steam generator tubes required plugging (paragraphs 7 and 10).
In addition, although the replacement of the feedwater piping at the steam generator nozzles was emergent work, it did not impact the critical path for the Unit 4 refueling outage due to good pre-planning and multi-discipline coordination.
Construction services was the lead discipline for coordinating and implementing the repair (paragraph 7).
In the engineering and technical support area, the engineering staff provided strong support for resolving steam generator nozzle weld crack issues (paragraph 7)
and they promptly and efficiently resolved test exception issues as they arose (paragraph 11).
Within the scope of this inspection, the inspectors determined that the licensee continued to demonstrate satisfactory performance to ensure safe plant operations.
In addition, the licensee, through self assessment, took prompt action to correct the following non-cited violation:
Non-Cited Violation 50-250,251/93-13-01, failure to follow a procedure resulting in the -inadvertent boration of the Unit 3 reactor coolant system (paragraph 13.b).
REPORT DETAILS Persons Contacted Licensee Employees T.
W.
H.
R.
J.
R.
J.
R.
E.
R.
p.
G.
J.
D.
H.
V.
J.
J.
R.
J.
J.
L.
M.
T.
D.
R.
R.
F.
H.
E.
V. Abbatiello, Site guality Manager H. Bohlke, Vice President, Nuclear Engineering Sup J. Bowskill, Reactor Engineering Supervisor J. Earl, guality Assurance Supervisor E. Geiger, Vice President, Nuclear Assur ance J. Gianfrencesco, Support Services Supervisor H. Goldberg, President, Nuclear Division E. Grazio, Director Nuclear Licensing F. Hayes, Instrumentation and Controls Maintenance G. Heisterman, Hechanical Maintenance Supervisor C. Higgins, Outage Manager E. Hollinger, Operations Training Supervisor B. Hosmer, Director, Nuclear Engineering E. Jernigan, Technical Manager H. Johnson, Operations Supervisor A. Kaminskas, Operations Manager E. Kirkpatrick, Fire Protection/Safety Supervisor E. Knorr, Regulatory Compliance Analyst S. Kundalkar, Engineering Manager D. Lindsay, Health Physics Supervisor Marchese, Site Construction Manager W. Pearce, Plant General Manager O. Pearce, Electrical Maintenance Supervisor F. Plunkett, Site Vice President R. Powell, Services Manager E.
Rose, Nuclear Materials Manager N. Steinke, Chemistry Supervisor R. Timmons, Security Supervisor B. Wayland, Maintenance Manager J.
Weinkam, Licensing Manager ervisor Supervisor Other licensee employees contacted included construction 'craftsman, engineers, technicians, operators, mechanics, and electricians.
NRC Resident Inspectors
- R.
C. Butcher, Senior Resident Inspector L. Trocine, Resident Inspector Other NRC Personnel on Site K. D. Landis, Chief, Reactor Projects Section 2B, Division of Reactor Projects, Region II W. H. Rankin, Chief, Facilities Radiation Protection Section, Division of Radiation Safety and Safeguards, Region II R.
P. Schin, Project Engineer, Reactor Projects Section 2B, Division of Reactor Projects, Region II
i
2.
- Attended exit interview on Hay 28, 1993 Note:
An alphabetical tabulation of acronyms used in this report is listed in the last paragraph in this report.,
Other NRC Inspections Performed During This Period
~N Dates Area Ins ected
- ,50-250,251/93-11 50-250,251/93-12 50-250,251/93-14 April 26-30)
1993 May 3-7, 1993 May 10-14, 1993 Inservice Inspection Health Physics Security/Material Control and Accountability 3.
50-250,251/93-15 Hay 18-21, 1993 Plant Status Unit 3 Engineered Safeguards Integrated Testing At the beginning of this reporting period, Unit 3 was operating at 100K power and had been on line since January 20, 1993.
The following evolutions occurred on this unit during this assessment period:
An inadvertent boration event occurred on Hay 6, 1993.
See paragraph 13.b for further detail.
Unit 4 At the beginning of this reporting period, Unit 4 was shut down for a refueling outage.
The unit had been taken off line on April 9, 1993, and the core was off-loaded on April 22, 1993.
The following evolutions
'ccurred on this unit during this assessment period:
Core reload was commenced at 9:35 a.m.
on Hay 4, 1993, and was completed ahead of schedule at 5:31 p.m.'n Hay 6, 1993.
The upper internals package was set at 5:55 a.m.
on Hay 7, 1993, and the reactor head was set on the flange at 12:40 a.m.
on Hay 8, 1993.
Mode 5 was entered at 7:30 p.m.
on Hay ll, 1993, when the reactor vessel head studs were tensioned.
Refer to paragraph
for, additional information.
Unit 4 entered Mode 4 at 8:14 a.m.
on Hay 20, 1993, and entered-Hode 3 at 9:50 p.m.
on the same day.
Mode 2 was entered for low power physics testing at 8:04 a.m.
on Hay 23, 1993, and criticality was achieved at 9:06 a.m..
In order to reset the rod control system after the completion of the low power physics testing, Mode 3 was re-entered at 12: 15 a.m.
on Hay 24, 1993, per
Section 7.8 of procedure O-.OSP-040.5, Nuclear Design Verification.
Criticality was re-achieved at 2:10 a.m.
on Hay 24, 1993.
At 6: 15 p.m.
on Hay 26, 1993, the turbine was placed on line.
Reactor power was then increased to 30% in order to warm the turbine prior to the overspeed test.
The main turbine overspeed test was successfully accomplished at ll:04 a.m.
on Hay 27,1993.
The unit was placed back on line at 1:06 p.'m.
on Hay 27, 1993.
Reactor power was then increased to approximately 30% for a chemistry hold.
Refer to paragraph 12 for additional information.
Power ascension was re-commenced and reactor power reached 50% at 2:00 a.m.
on Hay 28, 1993.
Reactor power was maintained at this level in order to facilitate the performance of NIS mini-calculations and the inputting of new NIS currents.
Refer to paragraph 12 for additional information.
Followup on Items of Noncompliance (92702)
A review was conducted of the following noncompliances 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.
(Closed)
VIO 50-250,251/92-28-02, Failure to Properly Lock Fire Protection, Water System Valves in Position.
The licensee responded to this violation by FPL letter L-93-008 dated January 25, 1993.
The cause of the misapplication of the locks was not conclusively determined, but the licensee stated that the most likely cause was that the valves were improperly locked during the verification process.
Following identification of this problem, the licensee properly positioned the locks and performed a walkdown of the fire protection system in accordance with procedure O-OSP-16.27, Fire Protection System Flowpath Verification, to assure correct system alignment and the proper locking of valves which are required to be locked.
No other discrepancies were found.
In addition, this event was discussed by operations management in operator meetings with the personnel responsible for the locking and verification of valve positions.
The importance of properly locking valves in accordance with procedure O-ADH-205, Administrative Control of Valves, Locks, and Switches, was stressed at these discussions.
The licensee also placed further control over the valve lock system for fire protection system locked valves.
The lock sets were replaced, and the key control for the keys to these locks was enhanced.
The inspectors reviewed the corrective actions taken by the licensee to prevent recurrence and found them to be adequate.
This violation is close Onsite Followup and In-Office Review of Written Reports of Non-routine-Events and
CFR Part 21 Reviews (90712/90713/92700)
The Licensee Event Reports and/or
CFR Part 21 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
CFR Part 2, Appendix C, were applied.
a.
(Closed)
LER 50-250/92-13, 3A Safeguards Bus De-energized During Testing.
'his event was discussed in detail in paragraph 9.e of NRC IR No. 50-250,251/92-28 and in paragraph 2.b of NRC IR No.
50-250,251/92-30.
This LER is closed.
b.
(Closed)
LER 50-250/93-04, Failure to Maintain an Hourly Fire Watch; Technical Specification Violation.
This LER was discussed in detail in paragraph 9.d of NRC IR No.
50-250,251/93-08 and resulted in NCV 50-250,251/93-08-02.
In addition to the corrective actions documented in NRC IR No.
50-250,251/93-08, the following corrective actions were included in the LER:
Direction was given requiring the fire watch shift supervisors to carry whatever communication systems are available such as portable radios or beepers whenever they are out of the office.
A briefing of all fire watch personnel was conducted on
. March 26, 1993, by the Fire Protection and Safety Supervisor emphasizing fire watch duties, responsibilities, expectations, and the impact of this event.
The fire watch training program was processed into a formal fire watch training manual.
All fire watch personnel were retrained using the new fire watch training manual, and new fire watch personnel will be fully trained with the new manual prior to be being assigned and put on post.
Documentation of the training was reviewed by the resident inspector.
All fire protection personnel were briefed by the Services Manager on the impact of the event and his expectations; and maintenance management issued letter PT-MS-93-052 to require that whenever. fire doors-or other vital doors are painted, adequate steps and precautions are taken to prevent doors from sticking and to ensure that access can be obtained.
In addition, specification SPEC-C-004, Furnishing 8 Application of-Service Level II L Balance-of-Plant Maintenance Coatings Turkey Point Units 3 5 4, was revised to require that newly painted doors, windows, and their seats be properly cured before closing them (curing time as required by the approved coating data sheet or manufacturer data sheet)..
This LER is close 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 adequ'ate.
For completed tests, the inspectors verified testing frequencies were met and tests were performed by qualified individuals.
The inspectors witnessed/reviewed portions of the following test activities:
4-OSP-023. 1, Diesel Generator Operability Test, Section 7. 1, 4A EDG Normal Start Test; 4-OSP-203. 1, Train A Engineered Safeguards Integrated Test, Attachments 1 and 2,- Breaker Test Position Lineup and Temporary Hodification Tabulation for Engineered Safeguards Integrated Test; 4-0SP-023.2, Diesel Generator 24 Hour Full Load Test and Load Rejection, for the 4A EDG; 4-OSP-203. 1, Train A Engineered Safeguards Integrated Test; 4-0SP-203.2, Train B Engineered Safeguards Integrated Test; 0-0SP-040.6, Initial Criticality After Refueling; 4-0SP-072.5 Hain Steam Safety Valve Setpoint Verification Test; 0-0SP-040.5, Nuclear Design Verification; 4-0SP-089, Hain Turbine Valves Operability Test; 4-0SP-072, Hain Steam Isolation Valve Closure Test; and 4-OSP-089. 1, Turbine Generator Overspeed Trip Test.
The inspectors determined that the above testing activities were performed in a satisfactory manner and met the requirements of the TSs.
Violations or deviations were not identified.
Haintenance Observations (62703)
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 TSs.
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; troubleshooting 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'ervice; 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 were implemented; outside contractor force activities were controlled in accordance with the approved gA program; and housekeeping was actively pursued.
The inspectors witnessed/reviewed portions of the following maintenance activities in progress:
sludge lancing of the Unit 4 SGs, eddy current testing of the Unit 4 SG tubes, replacement of a synchronizing switch and synchronizing relay in the 4A MG set control cabinet, weld preparation and ultrasonic testing in the shop on 'new reducers to be installed in the Unit 4 SG feedwater lines, and troubleshooting and replacement of the reducers on the Unit 4 SG feedwater nozzles.
I The activities referenced in the first two maintenance items listed above were well coordinated.'one of the SG tubes required plugging.
In reference to the last maintenance item listed above; the Unit 4 SG feedwater reducers were replaced per Condition Report No.93-370 dated May 1, 1993.
During this outage, routine ultrasonic testing of the 18-inch by 14-inch reducers and their welds to the SG feedwater nozzles revealed cracks.
These cracks originated in or near the nozzle-to-reducer weld root on the inside diameter of the reducer and propagated at about a 45 degree angle into the reducer base material for all three SGs.
The cracks were circumferential and primarily at the top of the 18-inch diameter end of the reducers.
The licensee's evaluation of the ultrasonic testing data determined the following crack sizes:
SG A - The largest crack was approximately 10 inches long.
It was maximum 50% through-wall and was located at the top.
Three other much smaller cracks were located on the sides.
SG B - The largest crack was approximately 20 inches long. It was maximum 40% through-wall and was located at the top.
Four other much smaller cracks were located on the sides and bottom.
SG C - The two largest cracks were approximately eight inches long.
It was maximum 40% through-wall and was located at the top and on one side.
One much smaller crack was located on the other Sid Cl
Similar feedwater piping cracks near the SG nozzles have been a
recurring problem at Turkey Point and many other nuclear plants as described in NRC Information Notice 93-20 and NRC Bulletin 79-13 about thermal fatigue cracking of feedwater piping to SGs.
In addition, NUREG-0691, Investigation and Evaluation of Cr'acking Incidents in Piping in PWRs, gives a detailed description of the thermal fatigue failure mechanism.
The thermal fatigue results from injecting cold auxiliary feedwater into hot main feedwater piping during unit startup and shutdown.
The history of this issue at Turkey Point was as follows:
Hay/June 1979 - Initial inspections in response to NRC Bulletin 79-13 revealed no cracks in either unit.
June 1980 - Routine refueling outage inspections per the NRC Bulletin 79-13 response revealed indications of cracking in all three reducers on Unit 4.
These reducers were replaced with like materials.
Two of the replacement reducers were delivered
'chedule 120, were counterbored to match the schedule'60 pipe, and were installed on SGs 8 and C.
October 1980 - Inspections revealed indications of cracks in all three reducers on Unit 3.
All three were replaced with like materials.
1981/1982
- Unit 4 SGs were replaced.
Licensee records review to date indicated that at least the B and C reducers were replaced
'ith schedule 60 reducers.
1982/1983
- Unit 3 SGs were replaced.
Licensee records review to date did not determine whether existing reducers were reused or replaced.
April 1984 - Inspections revealed cracks in two of the Unit 4 reducers in the counterbore area.
New reducers were installed in the A and C SGs using a modified weld preparation profile to reduce stress risers.
May 1984 - Inspection of Unit 3 reducers identified no cracks but did indicate reduced wall thickness in the reducer counter bore area.
Weld buildup was used to restore to original design; April 1993 - Inspection revealed cracks in all three Unit 4 reducers.
The previous inspections in 1991 had indicated no cracks.
All three reducers were replaced with like materials using the modified weld preparation method from 1984.
Meld preparations and welding were done by a contractor with experience in similar repairs at other plants.
The licensee stated that they have routinely used more advanced inspection techniques than industry standards and believes these inspections are adequate to detect cracks before they could become unacceptable.
Further, if this type of crack propagated faster than
previously experienced, it would "leak before break" and would be promptly detected by the installed leak detection equipment.
The NRC concurs with the "leak before break" conclusion.
The applicable condition report states that three corrective actions are to be converted to PMAIs for tracking, with assigned completion dates:
verification of root cause by June 1,
1993, system operation review by October 1,
1993, and long-term modification review by October 1,
1993.
The licensee found that many other util.ities have tried.various modifications including thermal shields on the reducer, but none have been installed long enough to be proven successful in eliminating the cracking problem.
Further, the licensee stated that the Westinghouse Owner's Group is not pursuing a solution to this problem.
Although the replacement of the Unit 4 SG feedwater nozzles was emergent work, it did not impact the critical path of the refueling outage due to strong support by engineering, good pre-planning, and multi-discipline coordination.
Construction services was the lead discipline for coordinating and implementing this repair.
Refer to NRC IR No. 50-250,251/93-11 for additional information.
For 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 orders.
Violations or deviations were not identified.
Engineered Safety Features Walkdown (71710)
The inspectors performed an inspection designed to verify the status of the Unit 3 and common HHSI system.
This was accomplished by performing a complete walkdown of all accessible equipment utilizing procedure 3-OP-062, Safety Injection, and safety injection system PAID Nos. 5613-H-3062, Sheets 1 and 2, and 5614-H-3062, Sheet 1.
The following criteria=
were used, as appropriate, during this inspection:
systems lineup procedures matched plant drawings and as-built configuration; housekeeping was adequate, and appropriate levels of 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; local and remote position indication was compared, and remote instrumentation was functional; and major system components were properly labeled.
Some minor drawing and labelling discrepancies were identified and brought to.the attention of the system engineer for correction.
Violations or deviations were not identified.
Operational Safety Verification (71707)
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 emergency systems, verified maintenance work orders had been submitted as required, and verified 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 components.
I By observation and direct interviews, verification was made that the physical security plan was being implemented.
The implementation of radiological controls and plant housekeeping/cleanliness conditions were also observed.
Tours of the intake structure and diesel, auxiliary, control, and turbine bui.ldings were conducted to observe plant equipment conditions including potential fire hazards, fluid leaks, and excessive vibrations.
The inspectors walked down accessible portions of the following safety-related systems/structures to verify proper valve/switch alignment:
A and B emergency diesel generators, control room vertical panels and safeguards racks, intake cooling water structure, 4160-volt buses and 480-volt load and motor control centers, Unit 3 and 4 feedwater platforms, Unit 3 and 4 condensate storage tank area, auxiliary feedwater area,
=Unit 3 and 4 main steam platforms, and
auxiliary building.
During a containment entry on May 13, 1993, the inspectors identified a small hole (approximately 2 inches in diameter)
in the screen covering one of two containment floor sumps located at the 14-foot elevation.
The RHR pumps take suction from the sumps in the containment floor during the recirculation phase of a LOCA.
There are two sump return lines which lead from the containment to the RHR pumps.
Filtration of the water entering the RHR pump suction piping is accomplished by screens located over the sumps which remove all debris 1/4 inch or larger.
This system is described in Section 6.2, Safety Injection System, of the FSAR.
The NRC recently issued Bulletin 93-02, Debris Plugging of Emergency Core Cooling Suction Strainers, to which the licensee is in the process-of responding.
Additionally, NRC Information Notice 93-34, Potential for Loss of Emergency Cooling Function Due to a Combination of Operational and Post-LOCA Debris in Containment, was recently issued.
The licensee prepared=a condition report (CR No.93-484) to initiate the investigation process and complete a repair prior to entry into Mode 4 (Tavg between 200'F and 350'F).
The licensee has procedure O-SHH-051.3, Containment Closeout Inspection, which provides instructions to ensure a proper closeout inspection of containment.
Paragraph 6.3.2 requires visual inspection of the containment recirculation sumps verifying, among other requirements, that the sump components (trash racks, screens, etc.)
are present,,properly installed and show no signs of degradation, structural distress or abnormal corrosion which would allow the entry of foreign material into the sump.
During a containment entry on May 19, 1993, the inspectors verified that the sump screens had been repaired and were in good condition.
The licensee routinely 'performs gA/gC audits/surveillances of activities required under its gA program and as requested by management.
To assess the effectiveness of these.licensee audits, the inspectors examined the status, scope, and findings of the following audit reports:
Number of Audit Number
"
~Findin s
T e of Audit OAO-PTN-93-006
March Performance Monitoring The NRC recently issued Bulletin 93-02, Debris Plugging of Emergency Core Cooling Suction Strainers and Information Notice 93-34, Potential for Loss of Emergency Cooling Function Due to a Combination of Operational and Post-LOCA Debris in Containment.
The licensee is still in the process of answering the Bulletin.
The inspectors reviewed the licensee's procedures for applicability to the Bulletin and the Information Notice.
The results were as'follows:
Procedure O-SMM-051.3, Containment Closeout Inspection, paragraph 6.3.8, requires verification that no temporary filter medium is attached to the inlet of containment coolers and has been removed from containment.
Paragraph 6.3.9 requires verification that no HEPA filters are inside the SG ventilation units (which are stored in containment)
and the filters have been removed from containment.
Procedures 3/4-GOP-503, Cold Shutdown to Hot Standby, paragraph 3.1.26, requires verification that roughing filters have been removed from the NCCs and from containment.
Paragraph 3. 1.27 requires verification that HEPA filters have been removed from the SG ventilation units and from containment.
Paragraph 3.1.28 requires verification that the containment closeout inspection was performed in accordance with procedure O-SMM-051.3 prior to entry into Mode 4 (Hot Standby).
The inspectors verified that the filters had been removed from the Unit 3 and Unit 4 containments.
No further action is required.
The NRC issued Bulletin 88-11, Pressurizer Surge Line Thermal Strati.fication, requesting that licensee's establish and i'mplement a program to ensure pressurizer surge line integrity.
By letter L-91-316 dated December 13, 1991, the licensee notified the NRC that plant specific analysis had been completed and acceptable pressurizer surge line stress levels and fatigue life for the remaining plant life was demonstrated contingent upon modifications to the surge line spring hanger.
The modification for Unit 4 was to be completed during the April/May 1993 outage.
The inspectors reviewed PC/M 91-200, Revision 1, Pressurizer Surge Line Spring Hanger Replacement, (which was incorporated dur-ing the current Unit 4 outage),
and walked down the installation.
The inspector identified that at least one of the nuts on the concrete fasteners did not have full thread.engagement.
This condition had previously been identified by the licensee.
CR No.93-239 dispositioned the present condition as acceptable and the resident inspector concurred.
No further action is required.
During a review for design basis document verification, the licensee identified a potential need for pressure relief on the hot leg HHSI line.
Based on this review, the licensee issued PC/M 92-097, Alternate Safety Injection Thermal Relief Valve Modification, for Unit 4.
The inspectors reviewed PC/M 92-097, Revision 2, and walked down the modification per drawing 5614-M-'062, Sheet 1.
The installation was successfully tested per TP-957, SI System Functional Test Procedure Following RV-4-6511 Installation.
The inspectors reviewed the completed TP-957, and no discrepancies were identified.
No further action is require On January 15, 1993, the licensee discovered a small steam leak on an abandoned pressurizer spray valve bypass line on Unit 3.
The leak emanated from a socket weld connecting a pipe cap to a pipe nipple.
The cause of the leak was determined to be due to inadequate pullback of the pipe cap when it was installed in 1985..
The inadequate pullback caused excessive local stress resulting in stress corrosion cracking of the weld.
The Unit 3 cap was removed and repaired at that time.
The licensee's LER (50-250/93-002)
stated that the'quivalent cap on the Unit 4 spray valve bypass line would be replaced during the present Unit 4 outage.
The equivalent pipe cap on Unit 4 was replaced this outage.
The inspectors reviewed the work control record and verified that the work had been accomplished.
No further action is required.
PC/H 93-100, Reactor Vessel Level Indicating System Deletion of Sensor No.
4 (HJTC),
was issued in response tb CR No.93-499.
CR No.93-499 documented a concern with a cable associated with the 4A gSPDS HJTC channel No. 4.
Due to a broken wire in the associated cable, with repair not possible at the time, HJTC channel No.
4 was inoperable.
The PC/H disconnected the HJTC cable and added a resistor to complete the circuit required for the remaining heaters in the circuit.
The gSPDS identified sensor number 4 as failed.
Channel A sensor number 1 was previously disconnected under PC/H 92-158.
Channel A had six operating sensor remaining, one in the head and five in the plenum area.
All eight sensors in channel B were operable.
RVLIS consists of two vertically oriented probes (Channels A and B), each containing eight sensors.
The top two sensors are used to determine reactor vessel water level in the head and the remaining six sensors
'are used to determine reactor vessel water level in the plenum as part of the ICCS.
Each sensor is comprised of a heater plus one heated and one unheated thermocouple junction.
The following table references the sensor to the reactor vessel water level.
Sensor Number Indicated level-%
Height in inches above the upper
2
5
7
33 HEAD 0 HEAD
PLENUM
M
M
M
0 M
166 7/16 129 5/16 115 5/16
57 3/4 42 1/4 27 3/4 11 5/16
TS Table 3.3-5, Accident Monitoring Instrumentation, requires a
minimum of four sensors be functional in order for a particular channel to be considered operable.
The yresent configuration meets TS requirement.
No further action is required.
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 of plant operations was good.
Violations or deviations were not identified.
Unit 4 Refueling Activities (60710)
As stated-in paragraph 10 of NRC IR No. 50-250,251/93-10, Unit 4 was taken off line at 11:56 p.m.
on April 9, 1993; Mode 6 was entered at 11:38 a.m.
on April 15, 1993, and the core was off-loaded at 5:35 a.m.
on April 22, 1993.
Following core off-load, the licensee performed 100%
eddy current testing of all three Unit 4 SGs, and none of the SG tubes required plugging.
Sludge lancing was also performed on all three SGs.
Additional major outage tasks included installation of a new type of conoseal on top of the vessel head, replacement of the reactor vessel seal table fittings, performance of a 10-year ISI hydrostatic test for the secondary side of the SG, performance of turbine valve overhaul on the stop and control valves, inspection and overhaul of the 3A EDG, overhaul of the electrical safety buses, inspection and repacking of approximately 300 plant valves, overhaul of approximately 60 plant valves, inspection of the 4A and
RCP seal packages, replacement of the 4A RCP motor, replacement of the R-11 and R-12 radiation monitoring detectors, and resupporting a portion of the inlet cooling bay with steel beams.
Fol-lowing filling of the RCS on Hay 2, 1993, the licensee commenced filling of the cavity, and a level of 57 feet (24 feet 6 inches above the vessel flange)
was attained at 3: 15 a.m.
on Hay 3, 1993.
Core reload was commenced at 9:35 a.m.
on Hay 4, '1993, and was completed ahead of schedule at 5:31 p.m.
on Hay 6, 1993.
The inspectors witnessed portions of the reloading activities on May 6, 1993.
The upper internals package was set at 5:55 a.m.
on Hay 7, 1993.
Upper cavity draindown was commenced at 12:35 p.m.,
and all control rods were verified to be latched at 1:15 p.m.
The reactor head was set on the flange at 12:40 a.m.
on Hay 8, 1993, and the lower cavity was drained at 3:00 a.m.
on Hay 9, 1993.
The seating pass on the reactor vessel head studs was commenced at 3:55 a.m.
on Hay ll, 1993, and Mode 5 was entered at 7:30 p.m on the same day, when the reactor vessel head studs were tensioned.
RCS filling and venting was commenced at 9:30 p.m.
on Hay 12, 1993, and the RCS and pressurizer became solid at 3:30 a.m.
on Hay 13, 1993.
RCS filling and venting was completed at 1:08 p.m.
and pressurizer level was reduced to approximately 87% in order to facilitate engineered safeguards integrated testing.
Refer to paragraph ll for additional information.
The licensee began filling the RCS at 9:50 a.m.
on Hay 18, 1993, and the RCS was filled and vented again to
begin solid plant operations at 12: 15 p.m.
At 3:00 a.m.
on Hay 19, 1993, the RCS temperature reached 180'F, and a bubble was established in the pressurizer at 10:30 a.m.
The fuel reloading process was conducted in an efficient professional manner with good communications between the refueling crews in containment,'he SFP, and the control room.
Violations or deviations were not identified.
Unit 4 Engineered Safeguards Integrated Testing (61701)
The inspectors witnessed portions of procedure 4-0SP-023.2, Diesel Generator 24 Hour Full Load Test and Load Rejection; procedure 4-OSP-203. 1, Train A Engineered Safeguards Integrated Test; and procedure 4-0SP-203.2, Train B Engineered Safeguards Integrated Test.
Procedure 4-0SP-023.2 required that the applicable EDG (4A or 4B) be run at approximately 110 percent operating range 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 percent operating range for 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br />.
Then a full load reject test was to be initiated by opening the EDG output breaker and verifying that the EDG did not trip and that specified voltage requirements were met.
In conjunction with procedure 4-0SP-023.2, step 7.2 of procedures 4-OSP-203. 1 and 4-0SP-203.2 was conducted with a LOOP test within 5 minutes of initiating an emergency stop signal to the operating EDG.
Following recovery from the LOOP test, step 7.3 of procedures 4-0SP-203.1 and 4-OSP-203.2 initiated an SI with offsite power available.
Following recovery from the SI test, step 7.4 initiated a
There were adequate personnel from all disciplines available for the tests, the test briefings were very comprehensive and professional, the data takers were identified, and personnel were familiar with their duties during the test.
Test prerequisites were completed.
There were 12 test exceptions identified during the performance of procedure 4-OSP-203.1 and 6 test exceptions were identified during the performance of procedure 4-0SP-203.2.
As each test exception was noted, a test exception report was initiated requiring resolution.
The on-site engineering staff promptly* and efficiently resolved test exception issues as they arose.
During the performance of procedure 4-OSP-203. 1, a test to verify proper operation of the automatic bus transfer circuit (auxiliary transformer to startup transformer)
per paragraph 7.4.36 was unsuccessful initially.
A required test jumper was not called out to be installed.
OTSC 383-93 to procedure 4-OSP-203.
1 was prepared to install the jumper on the Unit 4 auxiliary transformer breaker 4AA02.
The retest was successful.
In addition, during the performance of procedures 4-0SP-203.1 and 4-OSP-203.2, the 4A ECC and 4A, ECF did not m'eet the timing criteria by approximately 1 second.
Safety evaluation No. JPN-PTN-SEEP-93-015, Acceptable Upper and Lower Time Delay Limits for ECC 4A and ECF 4A Agastat Load Sequence Relays, permitted the widening of the acceptance criteria band based on the size of the EDG loading and on accident evaluation Other test exceptions were of a minor nature.
Refer to NRC IR No.50-
'50,251/93-15 for additional information.
Violations or deviations were not identified.
Unit 4 Star tup from Refueling (71711)
Unit 4 startup from refueling was conducted in accordance with procedure 4-GOP-503, Cold Shutdown to Hot Standby, and procedure 4-GOP-301, Hot Standby to Power Operation.
Unit 4 entered Mode 4 at 8: 14 a.m.
on May 20, 1993, and entered Mode 3 at 9:50 p.m.
on the same day.
Mode 2 was entered for low power physics testing at 8:04 a.m.
on May 23, 1993, and criticality was achieved at 9:06 a.m.
In order to reset the rod control system after the completion of the low power physics testing, Hode 3 was re-entered at 12: 15 a.m.
on May 24, 1993, per Section 7.8 of procedure 0-0SP-040.5, Nuclear Design Verification.
Criticality was re-achieved at 2:10 a.m.
on May 24, 1993.
At 6: 15 p.m.
on May 26, 1993, the turbine was placed on line.
Reactor power was then increased to 305 in order to warm the turbine prior to the overspeed test.
The main 'turbine overspeed test was successfully accomplished at 11:04 a.m.
on May 27, 1993.
The unit was placed back on line at 1:06 p.m.
on May 27, 1993.
Reactor power was then increased to approximately 30% for a chemistry hold.
Power ascension was re-commenced and reactor power reached 50'. at 2:00 a.m.
on May 28, 1993.
Reactor power was maintained at this level in order to facilitate the performance of NIS mini-calculations and the inputting of new NIS currents.
The refueling outage duration was 46 days, 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> and 15 minutes.
The original schedule was 53 days and 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br />.
The outage was completed 167 hours0.00193 days <br />0.0464 hours <br />2.761243e-4 weeks <br />6.35435e-5 months <br /> ahead of schedule.
The inspectors observed portions of the major startup activities in addition to the low power physics testing.
Important elements of these observations included the pre-evolution briefings, management control of other work and activities, procedural adherence, operator attention to detail, and monitoring of nuclear performance.
During these observations, the licensee identified and appropriately corrected various equipment malfunctions.. It was also noted that operators were attentive and responsive to plant parameters and conditions, plant evolutions and testing were planned and properly authorized, procedures were used and followed as required by plant policy, equipment status changes were appropriately documented and communicated to appropriate shift personnel, the operating conditions of plant equipment wer e effectively monitored and appropriate corrective actions initiated when required, and the operators followed good operating practices in conducting plant operations.
Violations or deviations were not identifie o i
13.
Plant Events (93702)
The following plant events were reviewed to determine fa'cility 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 licensee.
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.
a 0 At approximately 2:00 p.m.
on Hay 2, 1993, a contractor employee in the Unit 4 containment was struck on the head by a piece of scaffolding which had fallen approximately 40 feet; The individual was wearing a hard hat at the time.
He was subsequently transported to a local hospital by ambulance with a'ealth physics escort.
Upon arrival at the hospital, the injured individual was verified not contaminated.
He received 17 stitches on the forehead, was released from the hospital, and was medically restricted from work pending re-examination on Hay 3, 1993. 'he individual returned to work on May 4, 1993.
The licensee is currently performing an investigation to determine the root cause of this event and institute corrective actions.
The resident inspectors will followup on the licensee's actions regarding this matter.
b.
At 12:30 a.m.
on Hay 6, 1993, the Unit 3 RCS,was inadvertently borated by approximately 256 gallons during the performance of procedure O-OP-046, CVCS - Boron Concentration Control, Section 7.5, CVCS Manual Makeup to the RWST.
This event was caused by inadequate attention to detail and failure to follow a procedure.
Step 7.5.2.a of procedure 0-OSP-046 required the user to close or verify closed the blender to charging pump suction valve (FCV-3-113B)
and place the applicable control switch to the closed position.
A licensed operator trainee who was being supervised by the Unit 3 RCO verified the position of valve FCV-3-113B to be closed but failed to place the control switch for this valve in the closed position per the procedure.
This resulted in the automatic opening of FCV-3-113B during the makeup process.
This in turn resulted in the inadvertent boration of the RCS by approximately 256 gallons and the unexpected loss of approximately 16 HW Subsequently the RCS was diluted in order to return Unit 3 to 100% reactor power.
In order to prevent recurrence of this event, OTSC No. 307-93 was generated and approved on May 6, 1993.
This OTSC separated the actions required by step 7.5.2 into two steps.
The licensee issued a condition report (93-419).on this event, and a memorandum from the Operations Supervisor to all licensed operators was also
i-
issued on Hay 6, 1993, describing this event and cautioning operators on the importance of following procedural steps completely and self checking.
This memorandum also reiterated the expectation that the RCOs are directly responsible and accountable for the actions of trainees on shift when performing evolutions.
TS 6.8. l.a requires that written procedures be established implemented, and maintained covering the activities recommended in Appendix A of Re'gulatory Guide 1.33, Revision 2, February 1978.
Paragraph 3.n of this Appendix recommends procedures for startup, operation, and shutdown of safety-related PWR systems including CVCS.
Step 7.5.2.a of procedure O-OP-046, CVCS - Boron Concentration Control, requires blender to charging pump.suction valve FCV-*-113B to be closed or verified closed and for the applicable control switch to be placed in the closed position.
However, during the performance of CVCS manual makeup to.the RWST per procedure 0-OP-046 on Hay 6, 1993, the control switch for valve FCV-3-113B was not-placed in the closed position.
This results in the automatic opening of valve FCV-3-113B during the makeup process and in turn caused an inadvertent boration of the Unit 3 RCS by approximately 256 gallons.
This failure to follow a procedure constitutes a violation; however this violation is not being cited because the criteria specified in Section VII.B of the NRC Enforcement -Policy were satisfied.
This item will be tracked as closed NCV 50-250,251/93-13-01, failure to follow procedure resulting in the inadvertent boration of the Unit 3 RCS.
At 12:45 a.m.
on Hay 9, 1993, all five blackstart diesel generators were removed from service due to the electrical lineup needed to facilitate work on the 4C 4KV bus.
At this time the 3C 4KV bus power supply was swapped from the 3C transformer to the 4C transformer in preparation to switch out the 3C transformer, and clearances were placed on the supply breakers from the blackstart diesel generator bus to the 3C and 4C 4KV buses (1W134, 3AC03, and 4AC03).
The 4C 4KV bus had been de-energized at 6:57 a.m.
on Hay 5,
1993, for a scheduled bus outage.
This resulted in the loss of the capability to tie the blackstart diesel generators to the 3C or 4C 4KV buses.
The 4C bus outage clearance was released at 3:55 a.m.
on Hay 15, 1993, and the No. 1, 3, 4, and 5 blackstart diesel generators were returned to service.
The No.
2 blackstart diesel generator remained out of service because it had previously failed a surveillance test and had been removed from service at 2:10 p.m.
on Hay 5, 1993.
This blackstart diesel generator was satisfactorily tested and returned to service at 9:50 p.m.
on Hay 19, 1993.
At 10:45 a.m.
on Hay 25, 1993, with Unit 4 in Hode 2 at approximately I/ power, the licensee notified the NRC that both standby feedwater pumps were considered inoperable for Unit 4 only.
TS 3.7. 1.6, action b. 1, states that with both standby feedwater pumps inoperable, within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, notify the NRC and provide cause for inoperability and plans to restore pumps to
'
operable status.
Both standby feedwater pumps were made inoperable at 1:30 a.m.
on May 25, 1993 on Unit 4 when feedwater capability was isolated to permit repairs on valve 4-20-130, 4A SG Feed Regulator Bypass Upstream Isolation Valve.
Manual valve 4-20-130 had a small leak-(approximately one drop per second)
between the bonnet and valve body.
Feedwater capability to Unit 3 was unaffected.
The auxiliary feedwater system was being used to maintain SG water level during the repair effort.
The resident inspector observed valve 4-20-130 being repaired.
The Unit 4 feedwater system (and standby feedwater system)
was restored at 7:45 p.m.
on May 25, 1993.
One non-cited violation was identified.
Exit Interview The inspection scope and findings were summarized during management interviews held throughout the reporting period with the Plant General Manager and selected members of his staff.
An exit meeting was conducted on May 28, 1993.
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 Status Descri tion and Reference 50-250,251/93-13-01 Closed Acronyms and Abbreviations NCV - Failure to follow a procedure resulting in the inadvertent boration of the Unit 3 RCS (paragraph 13.b).
ADM CCW CFR CR CVCS DRM ECC ECF EDG F
FCV FPL FSAR GOP HEPA HHSI HJTC ICCS Administrative Component Cooling Water Code of Federal Regulations Condition Report Chemical Volume Control System Dose Rate Meter Emergency Containment Cooler Emergency Containment Fan Emergency Diesel Generator Fahrenheit Flow Control Valve Florida Power 5 Light Final Safety Analysis Report General Operating Procedure High-Efficiency Particulate Air Filter High Head Safety Injection Heated Junction Thermocouple Inadequate Core Cooling System
'R ISI JPN KV LCO LER LOCA LOOP HG HWe NCC NCV NIS NRC OP OSP OTSC PAID PC/H PHAI PTN PWR QA QAO QC QSPDS RCO RCP
'CS RHR RV RVLIS RWST SG SI SHM TP TPNP TS VDC VIO Inspection Report Inservice Inspection Juno Project Nuclear Kilovolt Limiting Con'dition for Operation Licensee Event Report Loss-of-Coolant Accident Loss of Offsite Power Motor Generator Megawatts Electric Normal Containment Coolers Non-Cited Violation Nuclear Instrumentation System Nuclear Regulatory Commission Operating Procedure Operations Surveillance Procedure On-the-Spot Change Piping and Instrumentation Diagram Plant Change/Modification Preventive Maintenance Action Item Plant Turkey Nuclear Pressurized Water Reactor Quality Assurance Quality Assurance Organization Quality Control Qualified Safety Parameter Display System Reactor Control Operator Reactor Coolant Pump Reactor Coolant System Residual Heat Removal Relief Valve Reactor Vessel Level Indicating System Refueling Water Storage Tank Steam Generator Safety Injection Surveillance Maintenance-Mechanical Temporary Procedure
'urkey Point Nuclear Plant Technical Specification Volts, Direct Current Violation