IR 05000250/1993019
| ML17352A215 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 08/13/1993 |
| From: | Butcher R, Landis K, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17352A214 | List: |
| References | |
| 50-250-93-19, 50-251-93-19, NUDOCS 9309070275 | |
| Download: ML17352A215 (35) | |
Text
~P,Ie Rb0Iy v'
O Report Nos.:
50-250/93-19 and 50-251/93-19 UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 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 Conducte
June 6 through July 23, 1993 Inspectors R.
C. Bute er, Senior Resident Inspect r D te igned
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L. Trocine, Resident Inspector D te igned Accompanying Inspector:
T.
P. Johnson, Senior Resident Inspector, Salem and Hope Creek Approved by:
K. D. Landis, C ief Reactor Projects Section 2B Division of Reactor Projects Da e Signed SUMMARY Scope:
This routine resident inspector inspection involved direct inspection at the site in the areas of surveillance observations',
maintenance observations, operational safety, and plant events.
Backshift inspections were performed on June 26 and July 7, 13-14, 19, and 21-.22, 1993.
Results:
. Within the scope of this inspection, the inspectors determined that the licensee continued to demonstrate satisfactory performance to ensure safe plant operations.
One non-cited violation and no deviations were identified.
During 'this inspection period, the inspectors had comments in the following Systematic Assessment of Licensee Performance functional areas:
Plant 0 erations Operations personnel performed well by identifying a potential vulnerability, by taking conservative actions to mitigate the potential 9309'070275 9308l3 PDR ADOCK 05000250
consequences, and by properly evaluating reactor trip breaker operability (paragraph 8.e).
=
Maintenance Surveillance Engineering; maintenance, technical, and operations personnel worked
'ell together to resolve the auxiliary feedwater pump trip problem (paragraph 8.b).
Management involvement was evident, and the test activities were well controlled with good communications between the control room and field personnel.
The event review team appeared to have correctly identified the root cause, and the corrective actions were extensive and comprehensive.
Management involvement was also evident in ensuring that adequate compensatory actions were taken when a coil in the right turbine stop valve relay failed during a reactor protection system logic test (paragraph 8.f).
In addition, with regard to this issue and to the train A high containment pressure actuat'ion relay problem (paragraph 8.k), the licensee displayed good interdepartmental teamwork in the prompt troubleshooting of the problems, replacement of the relays, and restoration of the systems to service.
Plant material conditions continue to adversely impact plant operations.
This is demonstrated by the substantial number of plant events during this inspection period which were related to material condition.
Operations and reactor engineering personnel took conservative actions to mitigate the safety significance of an event when the nuclear instrumentation system quadrant power tilt ratio surveillance was commenced but could not be completed within the required time frame per the required method due to a failed CET.
This is a Non-Cited Violation, NCV 50-250,251/93-19-01, failure to follow a procedure resulting in'he failure to complete a
gPTR surveillance within the required time (paragraph 8.g).
En ineerin and Technical Su ort Various licensee departments also worked will together in order to effectively and efficiently resolve the screen wash system discharge header problem (paragraph 8.j).
The inspectors reviewed the following outstanding items:
(Closed)
Licensee Event. Report 50-250/93-001, Axially Mispositioned Wet Annular Burnable Absorber (WABA) Rods (paragraph 4.a).
(Closed)
Licensee Event Report 50-250/93-003, Both Trains of Containment Spray Pump Manual Discharge Valves Isolated Due to Personnel Error (paragraph 4.b).
REPORT DETAILS 1.
Persons Contacted Licensee Employees T. V.
W.
H.
M. J.
R. J.
J.
E.
R. J.
J.
H.
R.
E.
E.
F.
Abbatiello, Site guality Manager Bohlke, Vice President,'uclear Engineering Supervisor Bowskill, Reactor Engineering Supervisor Earl, guality Assurance Supervisor Geiger, Vice Preside'nt, Nuclear Assurance Gianfrencesco, Support Services Supervisor Goldberg, President, Nuclear Division Grazio, Director, Nuclear Licensing-Hayes, Instrumentation and Controls Maintenance Supervisor Heisterman, Hechanical Maintenance Supervisor.
Higgins, Outage Hanager Hollinger, Operations Training Supervisor Hosmer, Director, Nuclear Engineering Jernigan, Technical Manager Johnson, Operations Supervisor Kaminskas, Operations Manager Kirkpatrick, Fire Protection/Safety Supervisor Knorr, Regulatory Compliance Analyst Kundalkar, Engineering Manager Lindsay, Health Physics Supervisor rchese, Site Construction Manager Howrey, Operating Experience Feedback Engineer/Analyst O'rien, guality Assurance/guality Control Supervisor Pearce, Plant General Manager Pearce, Electrical Maintenance Supervisor Plunkett, Site Vice President Powell, Services Hanager Rose, Nuclear Materials Manager Steinke,'hemistry Supervisor Timmons, Security Supervisor Wayland, Maintenance Manager Weinkam, Licensing Hanager R.
G.
P.
C.
G.
E.
J.
B.
D.
E.
H.
H.
V. A.
J.
E.
J.
E.
R. S.
J.
D.
J.
Ha C. L.
J.. F.
L.
W.
M. 0.
T. F.
D.
R.
R.
E.
R.
N.
F.
R.
H. B.
E. J.
NRC Resident Inspectors R.
C. Butcher, Senior Resident Inspector
- L. Trocine, Resident Inspector Other NRC Personnel on Site T.
P. Johnson, Senior Resident Inspector, Salem and Hope Creek
Attended exit interview on July 23, 1993.
Other licensee employees contacted included construction craftsman, engineers, technicians, operators, mechanics, and electrician Note:
An alphabetical tabulation of acronyms used in this report is listed in the last paragraph in this report.
2.'ther NRC Inspections Performed During This Period.
Re ort No.
Dates Area Ins ected 3.
50-250,251/93-20 July 12-16, 1993 Electrical Haintenance Plant Status Unit 3 At the beginning of this reporting period, Unit 3 was operating at 100%
power and had been on line since January 20, 1993.
The following evolutions occurred on this unit during this assessment period:
At 6:00 p.m.
on July 23, 1993, a load reduction to 15% power was commenced in order to facilitate the repair of a steam leak on the 3B HSR drain line, the cleaning of the 3A north and 3A south waterboxes, and the cleaning of the 3A and 3B TPCW heat exchangers.
(Refer to paragraph 8.i for additional information.)
Unit 4 At the beginning of this reporting period, Unit 4 was in Hode
following a load reduction and subsequent turbine anti-motoring trip, generator lockout, and reactor trip from 38% power on June 22, 1993.
(For additional information, refer to paragraphs 3 and 10.d of NRC Inspection Report No. 50-250,251/93-17.)
The following evolutions occurred on Unit 4 during this assessment period:
Hode 2 was entered at 8:48 a.m.,
on June 26, 1993, and the reactor achieved criticality at 9:07 a.m.
Following successful completion of the'urbine trips test, Hode 1 was entered at 9:35:p.m.,
the unit was placed on line at 10:50 p.m.,
and reactor power was increased to approximately 28% in order to warm the turbine prior to the main turbine overspeed test.
(Refer to paragraph 8.a for additional information.)
A load reduction was commenced at 9:00 a.m.
on June 27, 1993, in order to support the main turbine overspeed test.
The turbine was taken off line at 9:27 a.m.,
and the overspeed test was successfully accomplished at 10:00 a.m.
Hode 1 was re-entered, and the turbine was placed back on line at 10:40 a.m.
Power ascension was then re-commenced to 28% power.
(Refer to paragraph 8.a for additional information.)
At 3:30 p.m.
on June 27, 1993, a power increase to 70% was initiated at a rate of 10% per hour.
At 5:45 p.m.,
a power decrease to 30% was initiated due to a steam leak at the outlet flange gasket for reheater drain tank 4A to 6A feedwater heater
control valve CV-4-1505.
Reactor power was stabilized at 30%,
and valve CV-4-1505 was isolated for repair at 6:00 p.m.
(Refer to paragraph 8.a for additional information.)
'
load increase was commenced at 9:25 a.m.
on June 28, 1993, and reactor power was stabilized at 48% at 12:30 p.m. to facilitate the repair of reheater drain tank 4B to.6B feedwater heater control valve CV-4-1506.
Following steam leak repairs, power ascension to 70% was re-commenced at 1: 15 a:m.
on June 29, 1993.
The turbine trip test was successfully completed at 4:05 a.m.,
and a power increase was re-commenced.
The unit was stabilized at 100% reactor power at 8:30 a.m.
(Refer to paragraph 8.a for additional information.)
At 7:30 p.m.
on July 1, 1993, power reduction-was commenced for xenon transient flux mapping.
Unit 4 was stabilized at approximately 85% reactor power at 8:30 p.m.
Power 'ascension was commenced at 7: 15 a.m.
on July 2, 1993, and 100% reactor power was reached at 9:30 a.m.
At 9:30 a.m.
on July 8, 1993, a power reduction to approximately 60% was commenced to facilitate the repair of a tube leak in the 4B TPCW heat exchanger, and 60% reactor power was reached at 10:40 a.m.
Power ascension was commenced at 5:00 p.m.
on July 8, 1993, and reactor power reached 100% at 8:49 p.m.
Onsite Followup and In-Office Review of Written Reports of Nonroutine 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 50-250/93-001, Axially Mispositioned Wet Annular Burnable Absorber (WABA) Rods.
This event was discussed in detail in paragraph 8.e of NRC
- Inspection Report No. 50-250,251/93-01 and resulted in the issuance of NCV 50-250,251/93-01-03, failure to implement measures to assure that the WABA assemblies conformed to procurement documents.
This LER is close b.
(Closed)
LER 50-250/93-003, Both Trains of Containment Spray Pump Manual Discharge Valves Isolated Due to Personnel Error.
This event was discussed in detail in paragraph 8.d of NRC Inspection Report No. 50-250,251/93-01 and resulted in the issuance of 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:
This LER is closed.
Surveillance Observations (61726)
The inspectors observed TS required surveillance testing and verified that the test procedures conformed to the requirements of the TSs; testing was performed in accordance with adequate procedures; test instrumentation was calibrated; limiting conditions for operation were met; test results met acceptance criteria requirements and were reviewed by personnel other than the individual directing the test; deficiencies were identified, as appropriate, and were properly reviewed and resolved by management personnel; and system restoration was adequate.
For completed tests, the inspectors verified testing frequencies were met and tests were performed by qualified individuals.
The inspectors witnessed/reviewed portions of the following test activities:
section 7.2, Hain Turbine Trips Test, of procedure 3-0SP-200.3, Secondary Plant Periodic Tests, dated March 23, 1993; and section 7.1, AFW Pump A Operability Test, of procedure 3-OSP-075. 1, Auxiliary Feedwater Train 1 Operability Verification, dated April 9, 1993.
(Refer to paragraph 8.b for additional information.)
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 service; gC records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were properly implemented; gC hold points were established and observed where required; fire prevention controls 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:
repair of the steam leaks at the flange gaskets for reheater drain tank 4A to 6A feedwater heater control valve.CV-4-1505'nd reheater drain tank 4B to 6B feedwater heater control valve CV-4-1506 (Refer to paragraph 8.a for additional information.);
replacement and testing of Unit 4 right turbine stop valve relay SR due to a burnt coil (Refer to paragraph 8.f for additional information.);
and repair of a leak in the screen wash system discharge header piping per TSA No. 03-93-11-11 (Refer to.paragraph 8.j for additional information.)
The inspectors reviewed procedure O-GHE-102.4, HOVATS Testing of Safety Related Limitorque Motor Operated Valve Actuators, revision dated March 16, 1993.
This procedure had been used during the previous Unit 4 refueling outage for diagnostic testing of HOVs.
The procedure was subsequently revised twice and issued as revisions dated April 20 and June 15.
The inspectors reviewed the revised procedures to determine the safety significance of the changes.
The revision dated April 20 was issued to correct several typographical errors in the procedure and to incorporate OTSC No.93-180 which was written on April 15.
The typographical errors were in Attachment 19, Data Sheets, and consisted mainly in, the wrong step number being reflected on.the data sheet versus the intended step number containe'd in the main body of the procedure.
The inspectors discussed the editorial changes with the Procedure Writers Supervisor and the HOV Coordinator and determined that the errors impacted the efficiency of the procedure for field work as well as the post review process for final closeout; however, the deficiencies were not significant to nuclear safety.
The OTSC to the procedure was also reviewed with the HOV Coordinator and it was determined that the-purpose of this change was to modify the installation location of various test equipment components to reduce the number of test personnel required to perform the testing.
The procedure revision dated June
was issued to update thrust values for HOV 4-751 in accordance with the licensee's HOV program.
The inspectors concluded that although the procedure revision dated March 16 was cumbersome to use, the June
revision enhanced the procedure.
The changes made by the June
revision did not involve nuclear safety concern 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.
7.
.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.
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 buildings 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,'nit 3 and 4 main steam platforms, and auxiliary building.
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 Findincis T
e of Audit gAO-PTN-93-009
ASHE Section XI Implementation gAO-PTN-93-012
'0 April, Hay, and June Performance Monitoring Report gAO-PTN-93-017
Accumulators and Reactor Trip System Instrumentation and Setpoints No additional NRC followup actions will be taken on the finding referenced above because it was identified by the licensee's gA program audits and corrective actions have either been completed or are currently underway.
Plant management has also been made aware of this issue.
By letter dated April 13, 1993, FPL requested changes to the TSs for Unit 3.
These changes would reduce the number of required incore detector locations necessary for continued operation for the remainder of Cycle 13 only.
The Unit 3 HID system contains a total of 50 instrumentation thimbles in the core.
TS 3.3.3.2 requires that at least
detector thimbles be operable with a minimum of two detector thimbles per quadrant when used for monitoring F~, F~(Z),
and F (Z).
Due to the increase in incore detector system failures during Cycle 13 thus far, FPL proposed a change which allows plant operation with the number of operable detector thimbles reduced to a minimum of 50%.
To compensate for the increased uncertainty as the number of operable detector thimbles is reduced, the measurement uncertainty for F~ and F~(Z) will be increased whenever the number of detectors is between 38 and 25.
In.
addition, the minimum number of detector thimbles per quadrant will be increased from 2 to 3 whenever the number of operable thimbles, is less than 38.
By issuance of Amendment No.
154 to the Unit 3 operating license on June 15, 1993, the NRC approved continued power operation with the minimum number of HID thimbles reduced from 38 to 25 for the remainder of Cycle 13 operation only.
The licensee formed an ERT to determine the root cause of the HID system failures and to initiate corrective measures to recover full use of the HID system.
TSA No. 03-93-59-10 was presented to the PNSC on, July 1, 1993, to provide the following:
allow the use of an alternate cable to provide control room indication for HIDs, install drip covers over the five incore detector, drive units, and
provide instrument air purge to each detector drive unit.
Engineering Safety Evaluation JPN-PTN-SEIS-93-031, Revision 1,
evaluated the use of an alternate signal cable for incore detectors A, B, C,
D, or E.
This provided the justification to use any available cable exchange as necessary.
Engineering Safety Evaluation JPN-PTN-SECS-93-032, Revision 0, provided an evaluation for the installation of canopies over the flux map detector drive units.
Engineering Safety Evaluation JPN-PTN-SEMS-93-033, Revision 1, evaluated and provided justification for the installation of a temporary instrument air purge to the detector drive units.
The last two actions are to minimize the effect of excessive moisture that is collecting in the detector drive area.
Numerous attempts to locate a leak in containment have been unsuccessful.
The actions taken above are interim measures to keep the MID system operable.
The licensee plans to clean the thimbles during the next shutdown, refurbish equipment as required, and continue to attempt to determine the source of moisture that collected" in the area.
The inspectors reviewed the
. noted safety evaluations and attended the PNSC meetings where they were discussed.
The inspectors will follow the licensee's future actions regarding the MID system.
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.
Plant Events (93702)
The following plant events were reviewed to determine facility status and the need for further followup action.
Plant parameters were evaluated during transient response.
The significance of the event was evaluated along with the performance of the appropriate safety systems and the actions taken by the 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 ~
Following repairs on the turbine control system, Mode 2 was entered at 8:42 a.m.
on June 26, 1993, and the reactor achieved criticality at 9:07 a.m.
The inspectors attended the PNSC meeting where permission for reactor startup was granted and witnessed portions of the Unit 4 startup.
(Refer to paragraphs 3 and 10.d of NRC Inspection Report No. 50-.250,251/93-17 for additional information regarding the Unit 4 load reduction and subsequent turbine anti-motoring trip, generator lockout, and reactor trip from 38K power on June 22, 1993).
Following successful completion
.
'
of the turbine trips test, Hode 1 was entered at 9:35 p.m., the unit was placed on line at 10:50 p.m.,
and reactor power was increased to approximately 30% in order to warm the turbine prior to the main turbine overspeed test.
A load reduction was commenced at 9:00 a.m.
on June 27, 1993, in order to support the main turbine overspeed test.
The turbine was taken off line at 9:27 a.m.,
and the overspeed test was successfully accomplished at 10:00 a.m.
Hode 1 was re-entered and the turbine was placed back on line at 10:40 a.m.,
and power ascension to 30% was re-commenced.
At 3:30 p.m.
on June 27, 1993, a power increase to 70% was initiated.
At 5:45 p.m.,
a power decrease to 30% was initiated due to a steam leak at the outlet flange gasket for,reheater drain tank 4A to 6A feedwater heater'ontrol valve CV-4-1505.
Reactor power was stabilized at 30%,
and valve CV-4-1505 was isolated for repair at 6:00 p.m.
A load increase was commenced at 9:25 a.m.
on June 28, 1993; and reactor power was stabilized at 48% at 12:30 p.m. to facilitate the repair of reheater drain tank 4B to 6B feedwater,heater control valve CV-4-1506.
Following steam leak repairs on valves CV-4-1505 and CV-4-1506, power ascension to 70% was commenced at 1: 15 a.m.
on June 29, 1993.
The turbine trip test was successfully completed at 4:05 a.m.,
and power ascension was re-commenced.
Reactor power was stabilized at 100% at 8:30 a.m.
At 10:30 p.m.
on July 5, 1993, train 1 of AFW was removed from service for preventive maintenance.
AFW was tested per procedure 3/4-OSP-75. 1,Auxiliary Feedwater Train 1 Operability Verification.
At ll:05 a.m.,
on July 6, the A AFW pump TET valve (6459A) tripped on electronic overspeed when closing the steam supply valve (HOV-3-1405).
At 1:35 p.m., following a test run, the C AFW pump TET valve (6459C) tripped on electronic overspeed when closing HOV-3-1405 (similar to what happened when testing the A AFW pump).
(The AFW pump turbine will trip on electronic overspeed at approximately 6200 rpm, and mechanical overspeed at approximately 6500 rpm.)
Train 1 of AFW and the A and C AFW pumps were declared out of service placing both Unit 3 and Unit 4 in a 72-hour LCO per action statement 1 of TS 3.7.1.2.
An ERT was organized to resolve the problems experienced with the AFW system testing.
The ERT determined the most likely cause of the AFW pump overspeed when closing the steam supply valve was due to excessive steam leakage/condensation in the Unit 3 train
steam lines.
At 9:15 p.m.
on July 6, 1993, the Unit 4 train
(C AFW pump)
was successfully tested per procedure 4-0SP-075.1, and Unit 4 exited the 72-hour LCO and entered a 30-day LCO per TS 3.7. 1.2, action statement 3.
This test appeared to substantiate that the ERT was taking the proper corrective action Steam trap ST-33 and valve 3-10-080 both required more repair effort than the LCO time allowed.
Auxiliary steam to valve 3-10-080 was isolated to ensure no steam leakage.
Steam trap ST-33 was cut out of the'rain line and drain valve AFSS-011A was throttled open to remove any condensate.
Following these actions, the Unit 3 train
AFW operability testing per procedure 3-0SP-075.1 was successfully completed at 2:50 p.m.
on July 7, 1993.
At 9:20 p,m, on July 7, 1993, the PNSC completed review of the ERT corrective actions and testing of the AFW system, and the 72-hour LCO on the AFW system was exited.
Following satisfactory testing of each AFW train, the AFW system was declared fully operational per TS 3.7.1.2.
The inspectors attended most of the ERT meetings, observed some of the AFW system tests, and observed some of the maintenance activities.
Engineering, maintenance, technical, and operations personnel worked together as a team to resolve the AFW pump trip problem.
Hanagement involvement in the event was evident, and the test activities were well controlled with good communications established between the control room and field personnel.
The licensee's ERT appeared to have correctly identified the root cause of the AFW problem, and the corrective actions were extensive and comprehensive.
On July 6, 1993, while unloading k6 oil (Bunker C) at the fossil plant barge unloading area, approximately 5 gallons of oil was released to the water in the slip area.
The owners of the vessel, Coastal Tug and Barge, Inc., reported the spill to the Coast Guard at about 4:00 a.m.
The responsible nuclear area was notified at approximately 7:30 a.m.
The spill was through a crack in a welded flange on the vessel.
The spill was stopped and cleaned up with no apparent damage to the environment.
The spill was reported to the NRC Operations Center at 9:46 a.m. in accordance with 10 CFR 50.72(b)(2)(vi).
The inspectors verified that a proper report to the NRC was performed.
At 9:30 a.m.
on July 8, 1993, a power reduction to approximately 60% was commenced to facilitate the repair of a tube leak in the 4B TPCW heat exchanger.
Following the plugging of the leaking tube and the five adjacent tubes, power ascension was commenced at 5:00 p.m.
on July 8, and reactor power reached 10't 8:49 p.m.
At approximately 1:00 p.m.
on July 8, 1993, during the performance of procedure 0-PHE-'049. 1, Reactor Trip and Trip Bypass Breaker Inspection and Haintenance; for the 3A reactor trip breaker; an operator noted that change out of reactor trip breakers as a
maintenance activity could potentially be performed without procedures 3/4-OSP-049. 1, Reactor Protection System Logic Test, being performed immediately thereafter and that this could potentially lead to the reactor trip breakers being installed without satisfying the reactor timing test.
As a result, the
licensee immediately performed procedure 3-0SP-049.1 on the-changed-out 3A reactor trip breaker, and OTSC No. 496-93,was generated to coordinate the running of procedure O-PHE-049.1 in conjunction with procedures 3/4-0SP-049.1.
(NOTE:
These procedures are typically performed together when procedure 0-PHE-049. 1 is required.
Electrical maintenance performs procedure 0-PHE-049. 1 after preventive maintenance is performed on each reactor trip breaker on a 6-month frequency, and operations performs procedures 3/4-0SP-049.1 to fulfillthe monthly surveillance requirements.)
The licensee also generated a
Potentially Reportable Occurrence Worksheet and Condition Report No.93-638.
The licensee's investigation revealed that testing completed as part of procedure 0-PHE-049. 1 and the re-installation of the bre'aker fulfilled the post maintenance surveillance requirements for declaring the reactor trip or trip bypass breakers operable.
Individual tests and overlapping steps within procedure 0-PHE-049. 1 verified the tripping function of the breaker by manual trip, shunt trip, and undervoltage trip and verified the continuity of the logic circuitry.
The inspectors reviewed the licensee's Potentially Reportable Occurrence Worksheet and Condition Report No.93-638 and verified that procedure 0-PHE-049. 1 adequately tested the trip actuating devices on the breaker.
Operations personnel performed well by identifying a potential vulnerability, by taking conservative actions to mitigate the potential consequences, and by properly evaluating reactor trip breaker operability.
On July 13, 1993, the licensee performed section 7. 1, Train A Logic Hatrix Test, of procedure 4-OSP-049. 1, Reactor Protection System Logic Test, with Unit 4 operating at rated power.
Step 7. 1.70.2 of this procedure requires the verification that all reactor trip relays are reset using the Sequence of Events Alarm Summary printout.
At 9: 13 a.m., the alarm summary review by the operators revealed that the right turbine stop valve indicated closed.
Action statement 12 of TS Table 3.3-1, Reactor Trip System Instrumentation, item 15.a, Turbine Trip (Above P-7)
on Turbine Stop Valve Closure, requires that with the number of operable channels 1 less than the total number of channels, startup and/or power operation may proceed until the performance of the next required actuation logic test provided that the channel is placed in the tripped condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
The NWE immediately verified that right turbine stop valve relay SR was de-energized and in the tripped condition per the TSs.
Because the channel associated with this relay did not have a bistable that could be placed in the tripped condition, the licensee convened a special PNSC meeting at approximately 9:45 a.m. to ensure that the actions taken met the intent of the TSs.
It was decided at this meeting that the status of the SR relay would be checked every 30 minutes to ensure that the SR relay remained de-energized and in the tripped condition.
The inspectors attended
this PNSC meeting and verified the performance of the additional relay status verifications.
At 2:43 p.m., the licensee closed reactor trip bypass breaker A in order to facilitate the replacement and testing of right turbine stop valve relay SR, which was determined to have a burnt coil.
This action placed Unit 4 in a 2-hour action statement per TS Table 3.3-1, item 19, Reactor Trip Breakers, action statement 8.
This action statement requires that with the number of operable channels 1 less than the minimum channels operable requirement, the unit be in at least Hot Standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
This action statement also states that one channel may be bypassed for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for surveillance testing per TS 4.3. 1. 1 provided that the other channel is operable.
The right turbine stop valve relay was replaced and tested per procedure 4-0SP-049.1, the A reactor trip bypass breaker was re-opened at 3:47 p.m.,
and all related action statements were exited.
The inspectors witnessed the testing of the new relay and verified that the A reactor trip bypass breaker had been opened.
management involvement was evident in ensuring that adequate compensatory actions were taken, and the licensee displayed good interdepartmental teamwork in the prompt troubleshooting of the problem, replacement of the relay, and restoration of the system to service.
On July 14, 1993, with Unit 4 operating at rated power, the NIS gPTR surveillance procedure was commenced but could not be completed within the required time frame per the required method due to a failed CET.
As a result, operations and reactor engineering personnel took conservative actions to minimize the safety significance of the failed CET.
Operations personnel promptly restored the applicable power range NIS channel to service, and reactor engineering personnel completed the required gPTR surveillance via another acceptable method well within the time frame of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> required by TS 4.2.4.1 and TS 4.2.4.2.
TS 6.8. l.a requires that written procedures be established, implemented, and maintained covering the activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978.
Paragraph 8.b of this Appendix recommends the use of written procedures for safety-related activities including each surveillance test listed in the TSs, and TS 4.2.4 requires surveillance testing for gPTR.
Step 4.3 of procedure 4-OSP-059. 10, Determination of quadrant Power Tilt-Ratio, requires that this procedure be performed every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> if reactor power is greater than 50K and if either annunciator B2/2, POWER RANGE UPPER DET HI FLUX DEV/AUTO DEFEAT, or annunciator B2/3, POWER RANGE LOWER DET HI FLUX DEV/AUTO DEFEAT, are not operable.
Step 7.3 of this procedure states that if any power range NI channel is not is service, then the NIS gPTR is required to be verified by performing a
CET gPTR using a specified thermocouple gPTR calculation.
Step 7.3.2. 1 of this procedure states that the
thermocouple gPTR calculation was not to be used if any of the
CETs listed in the thermocouple gPTR calculation are not in service.
In addition, step 7.3.2.2 states that if this situation occurs, then react'or engineering is required to perform 1 of the following 3 actions:
determine the gPTR by using 2 sets of 4 symmetric thimble locations, determine the gPTR by using a full core flux map, or supply a
PNSC approved update for the Plant Curve Book utilizing 16 in service CETs.
On July 14, 1993, with Unit 4 operating, at rated power and annunciator B2/3 and power range NI channel N-44 out of service at the same time the licensee failed to complete the performance of the NIS gPTR per the CET method prior to the ending of the 8-hour period required by-procedure 4-OSP-059. 10 due to a failed CET.
Although this surveillance was not completed with in the 8-hour time frame required by the procedure, it was completed well within the 12-hour time frame, allotted by the TSs.
In addition to these actions, the licensee is in the process of generating procedure changes to add steps to 16 NIS maintenance procedures and
ONOP procedures to ensure the CETs are verified to be in service prior to removal of a power range NIS channel from service.
If any of the 16 pre-determined CETs are out of service and it is still necessary to remove a power range NIS channel from service, these procedure changes will require that reactor engineering be notified promptly so there will be enough time to complete 1 of the 3 options specified in step 7.3.2.2 of procedures 3/4-0SP-059.10, Determination of quadrant Power Tilt Ratio.
The licensee is also generating procedural changes to ensure that the 16 pre-selected CETs are surveyed on a weekly basis in conjunction with the normal performance of procedures 3/4-OSP-059. 10.
These procedure changes are currently scheduled to be implemented by August 30, 1993.
The safety significance of this issue was low because a component failure precluded the completion of the surveillance within the required time frame and because the licensee promptly resolved the problem.
This event could not reasonably be expected to have been prevented by the licensee's corrective actions for a previous violation or finding, and it was not willful. Although this failure to complete a gPTR surveillance within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is a
violation of step 4.3 of procedure 4-OSP-059. 10, Determination of quadrant Power Tilt Ratio, the NRC is exercising discretion in this case to mitigate the enforcement sanctions within the Commission's statutory authority.
Accordingly, this violation will not be subject to enforcement action because the licensee's efforts in identifying and correcting the violation meet the criteria specified in Section VII.B of the NRC Enforcement Policy.
This is a Non-Cited Violation, NCV 50-250,251/93-19-01, failure to follow a procedure resulting in the failure to complete a gPTR surveillance within the required tim On July 14, 1993, operations personnel raised a concern regarding the potential for power range NIS channels to be out of service for greater than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> without, the required TS actions being taken.
This situation was identified during the performance of an NIS channel quarterly calibration in that a deviation of standard work practices per the PWO involved the performance of procedure 4-SMI-041. 16, T. and Delta-T Protection Channel T-4-412, T-4-422, and T-4-432 Test,. immediately after performance of the NIS channel quarterly calibration and prior to the performance of procedure 4-OSP-059.4, Power Range Nuclear Instrumentation Analog Channel Operational Test.
The initial concern was that when IKC personnel re-landed the 108% trip lead in accordance with the NIS channel quarterly calibration, the NIS channel being calibrated would be technically out of service until procedure 4-0SP-059.4 was successfully completed and that the performance of procedure 4-SMI-041.16 prior to procedure 4-0SP-059.4 could potentially lead to an NIS channel being out of service for greater than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> without the proper TS action being taken.
The licensee's review of these procedures showed that no credible sequence of events would result in the channel becoming inoperable after completion of the quarterly calibration.
The quarterly calibration procedures check the high flux trip relay bistable in an equivalent manner as procedure 4-0SP-059.4.
The quarterly calibration procedures also verify the high flux trip alarm setpoint and status lights; and where leads are lifted, an independent verification is used to ensure correct replacement of the leads.
In addition, subsequent completion of the power range
. NI channel operational test per procedure 4-0SP-059.4 was satisfactory on NIS channels N-41 and N-42.
Based on the sequence of events, a review of the physical design in the instrumentation,'iscussions with IKC personnel and the system engineer, and the review of the power range NI analog channel operational test procedure and the NIS quarterly calibration procedures; the licensee concluded that the performance of procedure 4-0SP-059.4 duplicated the steps previously performed in accordance the NIS quarterly calibration procedures.
The licensee also concluded that the instrument circuits associated with both NIS channels N-
and N-42 were operable after the completion of the quarterly calibrations and that each channel was able to provide the high flux trip at the correct setpoint.
Therefore, the NIS channels were capable of providing their intended TS required protective functions, and the TS action statement for inoperability of NIS channels N-41 and N-42 should not have been entered.
Based on this review, a violation of the TSs did not occur.
When notified of the completion of an NIS quarterly calibration procedure, operations plans on continuing the.conservative practice of performing procedure 0-0SP-059.4 in order to provide independent verification of work performed on the instrument.
The licensee is also in the process of adding a step to the NIS
quarterly calibration procedures for operations to perform the operational test as soon as possible after the quarterly calibration.
This action is currently scheduled for completion by August 20, 1993.
The inspectors reviewed.the operator logs, DDPS printouts, Condition Report No.93-648, and procedures 4-PMI-059.8,'-PMI-059.9, 4-PMI-059.10, 4-PHI-059.11, and O-OSP-059.4.
The inspectors also discussed this issue with various plant personnel and attended PNSC meetings where this issue was discussed on July 22 and 23, 1993.
The inspectors concur with the licensee's evaluation.
At approximately 9:30 a.m.
on July 16, 1993, the licensee identified a steam leak in the 3B HSR drain line to the 4A reheater drain tank.
This leak was located in the heat affected zone upstream of the first 90'lbow weld.
This weld was performed on January 8,
1993, during the replacement of the 90'lbow and a section of horizontal piping -in order to repair a
previous steam leak.
(Refer to paragraphs 3 and 6 of NRC Inspection Report No. 50-250,251/93-01 for additional information.)
Another previous steam leak in the same location was also repaired with Furmanite on December ll, 1992.
(Refer to paragraphs 2 and 8.a of NRC Inspection Report No. 50-250,251/92-34.)
As a result of this event, the licensee generated an Interim Nuclear Engineering Disposition and Condition Report No.93-656.
The inspectors reviewed these documents and discussed them with members of the nuclear engineering staff.
The licensee'attributed the root cause for the current through wall leak to be the result of a combination of previous excessive outside diameter grinding for weld preparation and a high internal erosion rate.
The HSR drain system at this location has a design pressure of 200 psig and a design temperature of 400'F.
The nominal wall thickness of 8-inch schedule-40 piping is.322 inches, and the minimum wall thickness required for pressure (.0589 inches)
and an estimated erosion/corrosion rate per cycle (.028 inches) is.0869 inches.
The licensee took wall thickness measurements on the 3B HSR drain line and on the corresponding drain lines for the 3A, 3C, and 3D MSRs.
The lowest wall thickness reading on the 3B HSR drain line was
.056 inches.
The wall thickness measurements taken on the remaining Unit 3 HSR drain lines indicated that only the 3D HSR drain line had any significant degree of wall thinning.
The lowest wall thickness measurement taken on the 3D HSR drain line was
.102 inches, which is greater than the required minimum of.0869 inches and is considered by the 1'icensee to be acceptable for the remainder of the operating cycle.
Ultrasonic thickness'measurements were also taken on the Unit 4 HSR drain lines during the recent Unit 4
refueling outage, and the readings taken were not as low as those taken on Unit 3.
Because the lowest wall thickness reading on the 3B HSR drain line was below the required minimum wall thickness for pressure, the licensee plans to restore the pressure integrity of this local area by permanent replacement of the pipe section.
In'order to defer permanent pipe replacement until the next refueling outage, the licensee commenced a load reduction at 6:00 p.m.
on July 23, 1993, to facilitate the installation of a temporary outside'iameter clamp with I/4-inch fillet welds on both ends.
Furmanite was used to seal the annular groove and bolt holes of the temporary clamp.
The unit was stabilized at approximately 20%
power at 7:50 p.m.
To further reduce the B HSR shell side-pressure, an additional load reduction was commenced at 8:00 p.m.
Unit 3 was stabilized at approximately 151 reactor power at 8:15 p.m.;
and clamp installation, waterbox cleaning, and TPCW heat exchanger cleaning were commenced.
On July 19, 1993, the inspectors attended a planning meeting in the Plant General Hanager's office; and on July 20, 1993, the inspectors attended a
PNSC meeting where the Interim Nuclear Engineering Disposition was discussed.
The steam leak was also periodically observed and verified that it was not growing.
Because the actual repair was planned for outside of this-inspection reporting period, the inspectors will followup on the adequacy of.this repair during future inspections.
At 9:30 a.m.
on July 19, 1993, a large hole about 2 inches wide and approximately 18-24 inches long was identified in the common discharge header piping of the screen wash system.
Per TSA No.
03-93-11-11, the licensee cut the 6-inch diameter screen wash discharge header line flush with,the south wall of the 3Al well, installed a plug, and supported the plug with a plate bolted to the wall.
These actions restored flow to all traveling screens except the 3Al traveling screen.
A fire hose was then installed to supply flow from the backup fire water supply line on the screen wash pump discharge located at the west side of the intake to a flange downstream of 3A1 traveling screen wash supply valve 3-50-217.
Valve 3-50-217 was also removed per this TSA.
In addition, the licensee generated an OTSC (No.93-504) for procedure O-ONOP-016.7, Screen Wash Emergency Hakeup to the Fire Protection System, in order to reflect the steps needed if the screen wash system must be used for the fire water supply.
These actions were completed on July 21, 1993.
The inspectors witnessed portions of these activities and reviewed Condition Report No.93-659, Work Request No. 93012305, the Interim Engineering Disposition, TSA No. 03-93-11-11, and OTSC No.93-504.
The various licensee departments worked will together in order to effectively and efficiently resolve this proble k.
At 12:40 a.m.
on July 21, 1993, the "CKT.l HCP lOX OPERATED" white light failed to come in when testing the channel 2 and
combination at the 4(R51 rack during the performance of procedure OP-4004.4, Containment Isolation Racks gR50 and gR51 Periodic Test, with Unit 4 operating at rated power.
This light had worked properly for the channel 1 and 2 and channel 1 and 3 combinations, and the related bistable status lights were responding as expected.
At 1:00 a.m., the 18C investigation revealed that these symptoms would result if the related high containment pressure relays were working correctly with the exception of individual contact pairs in the channel 2 and/or 3 circuits which fed the white lights.
Because it was unknown whether channel 2 or 3 was causing the problem, the entire A train (gR51) of high containment pressure SI automatic actuation was declared out of service at 2:35 a.m.;
and a 6-hour to Hot Standby LCO was entered per action statement 14 of TS Table 3.3-1, Engineered Safety Features Actuation System Instrumentation, item 1.b, Safety Injection Automatic Actuation Logic and Actuation Relays.
At 3:30 a.m.,
the gR51 problem was isolated to train A; channel 2, high containment pressure actuation relay 4CI/2.
The relay actuated but the contact pair feeding the SI circuitry did not make electrical continuity.
Following unsuccessful attempts to repair relay 4CI/2, the licensee replaced the relay at 5:30 a.m.
Post maintenance testing of the relay and'erformance of procedure OP-4004.4 were successfully completed at 5:55 a.m.
As a result, the A train
{gR51) of high containment pressure SI automatic actuation was returned to service, and the 6-hour LCO was exited.
The licensee displayed good interdepartmental teamwork in the prompt troubleshooting of the problem, replacement of the relay, and restoration of the train to service within the required time frame by TS.
One Non-Cited Violation and no deviations were identified.
Exit Interview The inspection scope and findings were summarized during management interviews held throughout the reporting period with the Plant General Hanager and selected members of his staff.
An exit meeting was conducted on July 23, 1993.
The areas requiring management attention were reviewed.
On August 13, the Resident Inspector informed the plant general manager that one non-cited violation had been identified.
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 50-250,251/93-19-01 Status Closed Descri tion and Refer ence NCV Failure to follow a procedure resulting in the failure to complete a gPTR surveillance within the required time (paragraph 8.g).
Acronyms and Abbreviations AFW ANPS AUTO CET CFR CKT CV DDPS DET DEV ERDADS ERT F
~t'L F~(Z)
Fxy(Z)
GME HCP HI JPN IS.C LCO LER MID MOV MOVATS MSR NCV NI NIS'RC NWE ONOP OP OSP OTSC P
PME PMI PNSC System Density at Auxiliary Feedwater Assistant Nuclear Plant Super visor Automatic Core Exit Thermocouple Code of Federal Regulations Circuit Control Valve Digital Data Processing System Detector Deviation Emergency Response Data Acquisition Display Event Review Team Fahrenheit Nuclear Enthalpy Rise Hot Channel Factor Florida Power and Light Heat Flux Hot Channel Factor Ratio of Peak Power Density to Average Power Elevation (Z)
General Maintenance - Electrical High Containment Pressure High Juno Project Nuclear Instrumentation and Control Limiting Condit'ion for Operation Licensee Event Report Moveable Incore Detector Motor Operated Valve Motor Operated Valve Actuator Testing System Moisture Separator Reheater Non-Cited Violation Nuclear Instrumentation Nuclear Instrumentation System Nuclear Regulatory Commission Nuclear Watch Engineer Off Normal Operating Procedure Operating Procedure Operations Surveillance Procedure
. On-the-Spot Change Permissive Preventive Maintenance - Electrical Preventive Maintenance 18C Plant Nuclear Safety Committee
psig PTN PWO QA QAO QC QPTR QR RCO RCS REA rpm SECS SEIS SEHS
~
T&T vs&
TS TSA VIO WABA Pounds Per Square Inch Gauge Project Turkey Nuclear Plant Work Order Quality Assurance Quality Assurance Organization Quality Control Quadrant Power Tilt Ratio Quality Related Reactor Control Operator Reactor Coolant System Request for Engineering Assistance Revolutions Per Hinute Safety Evaluation Civil Site Safety Evaluation I&C Site Safety Evaluation Hechanical Site Steam Generator Safety Injection Surveillance Hechanical - I&C Steam Trap Temperature Trip and Throttle Average Temperature Turbine Plant Cooling Water Technical Specification Temporary System Alteration Violation Wet Annular Burnable Absorber