IR 05000250/1993010
| ML17349A870 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 05/19/1993 |
| From: | Butcher R, Landis K, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17349A869 | List: |
| References | |
| 50-250-93-10, 50-251-93-10, NUDOCS 9306020136 | |
| Download: ML17349A870 (27) | |
Text
~P,R REQyq Vp0 UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.IN.
ATLANTA,GEORGIA 30323 Report Nos.:
50-250/93-10 and 50-251/93-10 Licensee:
Florida Power and Light Company 9250 West Flagler Street Hiami, FL 33102 Inspection Conducted:
Hare 27 through April 23, 1993 Inspectors:
.
C.
Bu cher, Senior Resident Inspector
. Trocine, Resid nt Inspector Approved by:
K. D. LanIH's, Chief Reactor Projects Section 2B-Division of Reactor Projects Da e
igned Date Sig ed
~/a ps Date igned Docket Nos.:
50-250 and 50-251 License Nos.:
DPR-31 and DPR-41 Facility Name:
Turkey Point Units 3 and
SUHHARY Scope:
This routine, resident inspector inspection involved direct inspection at the site in the areas of surveillance observations, maintenance observations, operational safety, plant events, evaluation of licensee self-assessment capability, Unit 4 refueling activities,.and management meetings.
Backshift inspections were performed on Harch 27 and April 1, 3, 5-6, 10, and 12-15, 1993.
Results:
In the operations area, the fuel off-loading process was conducted in an efficient professional manner (paragraph 10).
In the safety assessment/quality verification area, the licensee's self-assessments are proactive and comprehensive (paragraph 9).
Within the scope of this inspection, the inspectors determined that the licensee continued to demonstrate satisfactory perfo".mance to ensure safe plant operations.
Violations or deviations were not identified.
'9306020136 9305i9 PDR ADQCK 05000250
Ql
REPORT DETAILS Persons Contacted Licensee Employees
¹*
¹8
¹9
¹¹
¹8
¹8 T.
W.
H.
R.
R.
J.
R.
J.
R.
E.
J.
R.
R.
¹8
¹*
P.
G.
D.
H.
V.
T.
¹ K.
R.
F.
D.
H.
E.
J.
- J
¹ * R.
J.
J.
R.
¹ * L.
H.
¹*T.
D.
R.
J.
V. Abbatiello, Site guality Mana'ger H. Bohlke, Vice President, Nuclear Engineering and Licensing J. Bowskill, Reactor Engineering Supervisor L. Carey, Licensing Technician J. Earl, guality Assurance Supervisor E. Geiger, Vice President, Nuclear Assurance J. Gianfrencesco, Support Services Supervisor H. Goldberg, President, Nuclear Division Golden, Nuclear Communications Specialist F. Hayes, Instrumentation and Controls Maintenance Supervisor K. Hays, Director, Nuclear Services'.
Meisterman, Hechanical Maintenance Supervisor W. Heroux, Operation and Maintenance Cost Control Senior Plant Supervisor C. Higgins, Outage Manager E. Hollinger, Operations Training Supervisor E. Jernigan, Technical Manager H. Johnson, Operations Supervisor A. Kaminskas, Operations Manager L. Kammer, Cutler Plant Electrician/International Brotherhood of Electrical Workers Local 359 Treasurer E. Kirkpatrick, Fire Protection/Safety Supervisor E. Knorr, Regulatory Compliance Analyst S. Kundalkar, Engineering Manager D. Lindsay, Health Physics Supervisor Harchese, Site Construction Manager B. Marshall, Human Resources Manager W. Pearce, Plant General Manager 0. Pearce, Ele'ctrical Maintenance Supervisor F. Plunkett, Site Vice President R. Powell, Services Manager E.
Rose, Nuclear Materials Manager H. Sambito, Health Physics Technician/International Brotherhood of Electrical Workers Local 359 Safety Committeeman R. Sims, Transmission and Development/International Brotherhood of Electrical Workers Local 359 President N. Steinke, Chemistry Supervisor R. Timmons, Security Supervisor J.
Tomaszewski, Component Specialist Section Supervisor B. Wayland, Maintenance Manager J.
Weinkam, Licensing Manager Other licensee employees contacted included construction craftsman, engineers, technicians, operators, mechanics, and electricians.
NRC Resident Inspectors R.
C. Butcher, Senior Resident Inspector
i
¹8* L. Trocine, Resident Inspector Other NRC Personnel on Site
¹8 H.
N. Berkow, Director, Project Directorate II-2, NRR
¹8 K. M. Clark, Public Affairs Officer, Region II B.
B. Desai, Resident Inspector, Oconee Power Station, Division of Reactor Projects, Region II
¹8 S.
D. Ebneter, Regional Administrator, Region II
¹8 J.
R. Johnson, Deputy Director, Division of Reactor Projects, Region II
¹8 H. S. Hiller, Reactor Engineer, NRR
¹8 L. Raghavan, Project Hanager, Turkey Point, Project Directorate II-2, NRR
¹8 M. V. Sinkule, Chief, Reactor Projects Branch 2, Division of Reactor Projects, Region II
¹8 R.
E. Trojanowski, Regional State Liaison Officer, Office of the Regional Administrator, Region II Non-Licensee/Non-NRC Personnel on Site for Meetings
K. Corso, WCIX Television, Channel 6, Miami
¹8 J.
Drewing, Radiological Emergency Preparedness Planner, Monroe County, Office of Emergency Management
¹8 J.
C. Eakins, Technician, Environmental Radiation Program, Office of Radiation Control, Department of Health and Rehabilitative Services
¹8 P. Godfrey, Deputy Director, Metro-Dade County, Office of Emergency Management
¹8 T. Hawkins, Radiological Emergency Preparedness Specialist, Federal Emergency Management Agency, Region IV
¹8 J.
C. Heard, Jr., Chief, Technical Hazards Branch, Federal Emergency Management Agency, Region IY
¹8 B. LeBlanc, Senior Planner, Florida Division of Emergency Management
¹ W. Lindsay, Member of the Public
¹8 J. Lorion, Greenpeace representative
¹8 R.
Pankow, WIOD Radio
¹8 P.
Reyna, Associated Press Writer.
¹8 A. Rubin, Miami Herald Reporter
¹ Attended SALP presentation on April 15, 1993
Attended local public officials meeting on April 15, 1993
Attended exit interview on April 23, 1993 Note:
An alphabetical tabulation of acronyms used in this report is listed in the last paragraph in this repor S
Other NRC Inspections Performed During This Period Re ort No.
50-250,251/93-09 Dates April 5-7 and 12-15, 1993 Areas Ins ected
. Environmental Effluents, Chemistry, Transportation, and Radioactive Waste Plant Status Unit 3 At the beginning of this reporting period, Unit 3 was operating at 100%
power and continued operating at this power level throughout the assessment period.
The unit had been on line since January 20, 1993.
Unit 4 At the beginning of this reporting period, Unit 4 was operating at 100%
power and had been on line since January 7,
1993.
The following evolutions occurred on this unit during this assessment period:
At 8:00 p.m.
on April 9, 1993, the licensee began reducing power in order to facilitate entry into a planned refueling outage.
The turbine was manually tripped at 11:56 p.m. marking the beginning of the refueling outage.
The reactor trip breakers were opened, and the unit entered Mode 3 at 12: 16 a.m.
on April 10, 1993.
RCS cooldown was commenced at 4:30 a.m.,
Mode 4 was entered at ll:20 a.m.,
and Mode 5 was entered at 10:50 p.m.
Unit 4 entered Mode 6 at 11:38 a.m.
on April 15, 1993, when the first head stud was de-tensioned, and fuel off-loading was commenced at 10:25 a.m.
on April 20, 1993.
The last fuel assembly was off-loaded at 5:35 a.m.
on April 22, 1993.
(Refer to paragraph.
10 for additional information.)
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.
(Closed)
LER 50-251/93-01, Failure to Post Continuouq Fi~re Watch:
Technical Specification Violatio This event was discussed in paragraph 9.b of NRC IR No. 50-250,251/93-06 and resulted in NCY 50-250,251/93-06-01.
This LER is closed.
Survei 1 1 ance 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:
3-0SP-202.2, RHR Pump and Piping Venting, and testing of the KF/ALE emergency network radio on NRC Region II frequencies with NRC emergency preparedness personnel located in Atlanta, GA.
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; approv'als 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 pursue i
The inspectors witnessed/reviewed portions of the following maintenance activities in progress:
removal and rebuilding of the 4A SFP pump, overhaul of steam generator A feedwater bypass valve 4-20-130, and removal of feedwater heater 3A and 4A condensate outlet stop valve 4-20-109.
In reference to the first item listed above, the 4A SFP pump (Ingersoll-Rand)
was being upgraded with a new shaft and seal configuration per PC/H 92-126.
Concurrently, valves 4-820 and 4-742 were being replaced, and valves 4-819 and 4-913'ere being repacked.
SFP cooling was removed from service per procedure 4-0P-033, Spent Fuel Pit Cooling System, and log readings of SFP temperatures were maintained per attachment 3 of procedure 4-OP-033.
The SFP cooling was originally removed from service at 4:40 p.m.
on Harch 29, 1993, with the SFP temperature at 87'F.
An administrative limit of 125'F had been put in place as noted by night orders.
On Harch 31, 1993, three separate through wall leaks were observed during the hydrostatic test of valve 4-742.
Leakage was found in the valve body next to the field weld.
NCR N-93-0035 was issued documenting the nonconformance.
(Valve 4-742 is located at the discharge of the emergency SFP cooling pump.)
The SFP temperature was 108'F at this time, and the heatup rate was approximately 0.33'F per hour.
A weld repair was made on the 4-742 valve body, and the subsequent hydrostatic test was successful.
SFP cooling was restored at 4:00 a.m.
on April 2, 1993.
The highest SFP temperature was approximately 113'F.
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.
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 gonditions were also observe 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, Unit 3 and 4 main steam platforms, and auxiliary building.
The licensee routinely performs QA/QC audits/surveillances of activities required under its QA 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 QAO-PTN-93-002, QAO-PTN-93-004'TN Physical Security Plan
.
TSs 2. 1, 3/4.4, 3/4.6, and 6.7 No additional NRC followup actions will be taken on the finding referenced above because it was identified by the licensee's QA program audits and corrective actions have either been completed or are currently underway.
Plant management has also been made aware of these issues.
As a result of routine plant tours and various operational observations,'he 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.
8.
Plant Events (93702)
/
The following plant events were reviewed to determine facility status and the need for further followup action.
Plant parameters were
Cl
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'RC 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 ~
On February 10, 1992, the inspectors provided the licensee with information that indicated other utilities with Westinghouse PWR designs had found that the Westinghouse calculations used to determine the setpoints used in their OMS may have been non-conservative and that possible overpressure transients could result.
The licensee contacted Westinghouse and determined that TPNP had the same issue.
For Modes 4, 5, and 6 with the reactor vessel head on, TS 3.4.9.3 states that the high pressure SI flow paths to the RCS shall be isolated and that below an average coolant temperature of 275'F, at least one of the following OMS systems shall be operable:
two PORVs with a lift setting of 415 + 15 psig or the RCS depressurized with an RCS vent of greater than or equal to 2.20 square inches.
The OMS is designed to mitigate mass input and heat input induced pressure transients during cold shutdown transient and steady-state conditions.
The ONS utilizes the PORVs with a variable low pressure setpoint as the pressure relief path.
Because the OMS provides overpressure protection to ensure the integrity of the RCS, it is classified as safety related.
The OMS was designed to provide overpressure for the following cases:
the start of an SI pump and its injection into a water solid RCS, the inadvertent start of two charging pumps with a loss of letdown, or the start of an idle RCP with the secondary water temperature of the steam generators 50'F above the RCS cold leg temperature.
The first and third cases above are stated in the TS bases.
All three cases were addressed in the 'original generic Westinghouse analysis.
It was recently determined, that the pressure difference between wide range pressure indication location an/ the core belt line region had"not been explicitly considered tn the OMS design.
The pressure differential is the result of core pressure drop with one or more RCPs in operation and elevation differences between
the area of interest in the reactor vessel and the hot leg location of the pressure transmitter taps.
The consequences of this bias is most significant at low temperatures while water solid with three RCPs in operation.
The'introduction of mass or thermal input transients under these conditions represents the most limiting event.
A specific review for TPNP has determined that the identified calculational issues exist as part of the original Unit 3 and
OHS designs.
Discussions with Westinghouse (the OMS designer)
confirmed that the bias associated with core pressure drop (dynamic head)
and elevation differences (static head)
were not considered in the original PTN OHS design.
In addition, PORV setpoint tolerance (+15 psig per TSs)
was not explicitly considered under the original PTN ONS design.
The issues of the amount of error introduced into the setpoint calculations due to static head and PORV setpoint tolerance was determined to be insignificant and bounded by the conservatism contained in the formulation of the Appendix G curves.
Therefore, these sources of bias do not post a potential overpressure concern.
Based on a completed plant specific calculation performed by Westinghouse, the resultant differential pressure error is 57 psi at 85'F.
Per Westinghouse, the Appendix G curve at 85'F corresponds to an allowable pressure of 503 psig.
One heat injection and two mass injection scenarios are considered that may challenge this limit.
These scenarios were noted above.
The limiting scenario occurs if an'I pump is started while inadvertently aligned to the RCS during cold, solid conditions with all three RCPs running.
Based on the results of a plant specific evaluation for the maximum permissible PORV setpoint, there is no margin between the Appendix G curve at 85'F and the predicted maximum pressure attained.
In this case, any differential pressure caused by an operating RCP will cause an overpressure excursion in excess of the Appendix G curve.
The following table reflects the maximum vessel pressure obtained for each combination of running RCPs.
No. of Total RCPs ZP Pressure Running (psid)
(psig)
25
57 503 528 539 560
If this limiting mass injection event is assumed with any RCPs running, the Appendix 6 curve would be exceeded.
As stated in paragraph 9.e of NRC IR No. 50-250,251/93-08, this issue was reported to the NRC Operations Center at 4: 18 p.m.
on March 25, 1993, per 10 CFR 50.72 (b)(1)(ii)(b) as a condition outside the design basis due to the dynamic head pressure drop not being accounted for in the OMS setpoint.
By letter dated April 8, 1993, the licensee requested an exemption to allow the application of ASHE Code Case N-514, Low Temperature Overpressure Protection, in determining the acceptable low temperature overpressure protection OHS setpoint for Turkey Point Units 3 and 4.
ASHE Code Case N-514 allows setting the OMS actuation setpoint such that the Appendix G curves would not be exceeded by more than 10%.
The ASHE Code Committee has concluded that the low temperature overpressure guidelines provide acceptable margin against.crack initiation and failure in reactor vessels and that they will reduce the potential for unnecessary activation of protection system pressure relieving devices.
Consequently, the ASHE Code Committee concluded that the OMS limits provide both operational and safety benefits with no adverse safety or environmental impact, and the use of ASME Code Case N-514 provides an acceptable level of quality and safety.
Application of this code case at TPNP would allow continued operation with the present setpoint.
The licensee also requested that this exemption from certain requirements of 10 CFR 50.60 be.
processed in an expeditious manner in order to be consistent with the Unit 4 restart schedule.
RCS filling and venting following placement of the reactor vessel head is currently projected to commence by approximately Hay 15, 1993.
During a meeting between FPL and NRR representatives on April 9, 1993, the NRR staff agreed to review the exemption request on an expedited basis.
This meeting was held in order to discuss revision to the TS bases for OMS setpoint considering pressure differences between the reactor vessel and the pressure transmitters due to RCP operation and elevation 'differences.
The licensee informed NRR that during the Unit 4 cooldown scheduled to commence on April 10, 1993, it would comply with TSs by implementing adequate controls to prevent mass
'injection from the high pressure SI pumps during reactor. cooldown.
By letter dated April 8, 1993, the licensee submitted a request for exemption from certain requirements of 10 CFR 50.60, Accepatance Criteria for Fracture Prevention Heasures for Lightwater Nuclear Power Reactors for Normal Operation, to allow application of an alternate methodology in determining the acceptable OMS stepoint for Turkey Point, Units 3 and 4.
By letter dated Hay 11, 1993, the NRC granted the exemption to permit using the safety margins recommended in ASHE Code Case N-514 in lieu of the safety margins required by Appendix G,
CFR Pyrt 50.
The inspectors will follow up on the licensee's actipns regarding this matter during future inspection On March 29, 1993, a test run of the No.
4 blackstart diesel generator'as aborted due to a loss of governor oil level.
This diesel generator would not shut down normally and was secured by utilization of the fuel racks.
When this occurred, fault lights locked in on all five blackstart diesel generators, and 'the faults could not be reset.
As a result, all five blackstart diesel generators were declared out of service at 11:25 p.m.
Troubleshooting revealed a blown fuse in the starting circuitry.
The fuse
{F19) provided control power from the fossil units to the blackstart diesel generator starting relays.
Additional troubleshooting revealed many shorts due to aged wiring.
Following replacement of fuse F19, several wiring bundles, and a
relay; the No.
1, 2, and 3 blackstart diesel generators were satisfactorily tested and were returned to service at 9:35 p.m.
on April 1, 1993.
The No.
5 blackstart diesel generator was satisfactorily returned to service at 12:23 p.m.
on April 2, 1993.
The No.
4 blackstart diesel generator failed testing twice due to a high engine temperature alarm, but all temperatures and levels, were within the normal range.
Following the replacement-of a
cooling water level switch, the No.
4 blackstart diesel generator was satisfactorily re-tested and was returned to service at 4: 15 a.m.
on April 4, 1993.
At 6:00 a.m.
on April 18, 1993, with the Unit 4 reactor vessel head removed and refueling cavity fill activities in progress, seal cavity leakage at a rate of approximately
gpm was identified.
At this time, the water level was approximately
feet above the reactor vessel flange.
Fill activities were secured and an investigation ensued.
At 10:50 a.m., the licensee began draining the cavity per Section 6.1, Draining the Refueling.'avity with the RHR System to the Reactor Vessel Flange, of procedure 4-0P-201, Filling/Draining-the Refueling Cavity and the SFP Transfer Canal.
Water level reached the reactor vessel flange at 12:50 p.m.,
and draining activities were secured at 1:45 p.m.
when the water level was 1 foot below the flange.
Lower cavity draining activities were re-commenced at 2:35 p.m.
per Section 6.2, Draining the Refueling. Cavity Below the Reactor Vessel Flange via the RCDT, of procedure 4-0P-201.
When the refueling cavity was fully drained, it was discovered that the leak was caused by two studs missing from NIS well cover No.
10 for PRNI N44.
Further investigation revealed that all four PRNI covers were loose with the nuts only finger tight.
The two missing studs were replaced, and the loose nuts were tightened.
The as-left configuration was determined to be acceptable for fuel off-load, and reactor cavity fill activities were re-commenced per procedure 4-OP-201 at 10:00 p.m.
A water level of 2 feet above the reactor vessel flange was attained at 1:20 p.m.
on April 18, 1993, and the refueling cavity was filled to greaty than 23 feet above the reactor vessel flange at 10:25 a.m.
on April 19, 199,
Prior to reflooding the refueling cavity for fuel reload, the licensee plans to rework all PRNI covers per procedure O-CHI-059.9, Replacement of Power Range Nuclear Instrumentation Detectors.
This activity is currently scheduled for completion by April 30, 1993.
The licensee is also currently investigating the cause for the missing studs and the loose NIS covers.
This issue will be addressed by Nuclear Problem Report No.
CR 93-242 which is currently scheduled for completion by Hay 4, 1993.
The inspectors will follow up on the licensee's ongoing investigations and corrective actions during future inspections.
Violations or deviations were not identified.
Evaluation of Licensee Self-Assessment Capability (40500)
NRC Region I Technical Issue Summary No. RI-93-04 dated February 22, 1993, described how BG&E discovered that it had been rendering the ECCS and the CS pumps o'f both Calvert Cliffs nuclear units inoperable during the performance of monthly recirculation activation logic testing.
The minimum flow lines, for all ECCS and CS pumps, both trains, tie together to a single common line back to the RWST.
Two series isolation HOVs in this common line are shut for approximately five minutes each during this monthly surveillance test.
With either valve shut, operation of any ECCS or CS pump without adequate discharge flow (such as might exist during some small-break LOCA conditions)
could cause damage to operating pumps.
The CS pumps are affected because the pumps start on an SI actuation signal, but discharge is delayed until a
CS actuation signal opens the isolation valves.
TSs requires that each ECCS sub-system be demonstrated operable by verifying the minimum flow line HOVs are open.
These valves are normally locked open but must be shut to change to the recirculation mode upon receipt of a recirculation actuation signal.
Testing verifies the proper response of the recirculation mode valves, but at the same time, the ECCS and the CS systems are placed in an inoperable condition.
BG&E determined that operators would have sufficient time to open these HOVs and prevent failure of any ECCS and CS pump during any small break LOCA.
Calculations were performed to demonstrate that the minimum flow line HOVs would open against the HPSI pump shutoff head.
FPL was requested to determine if the TPNP units had similar problems.
At Turkey Point, the minimum recirculation lines for the ECCS and CS systems also tie into a common line that has two isolation valves in series.
Valves HOV-3/4-856A and B are normally open during power operations and close during a design basis LOCA when transferring to recirculation mode to prevent RCS from flowing into the RWST and out of the tank vents.
Although Turkey Point's system is similar to Calvert Cliffs', these valves are not r equired to be tested monthly.
A review of the SI pump inservice test (procedure 0-0SP-062.2)
and, CS pump inservice test (procedures 3-0SP-068.2 and 4-0SP-068.2)
reveals that these valves are not tested along with the system inservice test.
However, valves
MOV-3/4-856A and 8 are tested each refueling outage as governed by procedures 3-OSP-206.
and 4-OSP-206. 1, Inservice Valve Testing
- Cold Shutdown.
These procedures only allow testing of these MOVs during Mode 5 (Cold Shutdown) or Mode 6 (Refueling).
At this time, testing of the above referenced valves is not an operability concern because of the following:
SI is valved out for ONS protection per procedures 3-GOP-305 and 4-GOP-305, Hot Standby to Cold Shutdown, as required by TS 3.4.9.3.
CS is also valved out with pumps in pull-to-lock per procedures 3-'GOP-305 and 4-GOP-305.
To support full power operation of the other unit, the refueling units'I pumps are aligned to the running unit RWST per procedures 3-OP-201 and 4-0P-201, Filling/Draining the Refueling Cavity and the SFP Transfer Canal.
Other safety-related systems were reviewed to find whether or not this technical issue applied.
In these systems, either no valves were found whose isolation could affect all trains of recirculation during surveillance testing, no common recirculation header was found, or surveillance testing was performed in a mode where the system was not required to perform any safety-related function.
Operability concerns were not found to be applicable to PTN involving the above referenced incident at Calvert Cliffs.
The licensee's self-assessments are proactive and comprehensive.
Violations or deviations were not identified.
Refueling Activities (60710) Unit 4 Only A power reduction per procedure 4-GOP-103, Power Operation to Hot Standby, was commenced at 8:00 p.m.
on April 9, 1993, in order to facilitate entry into a planned refueling outage.
The turbine was manually tripped at ll:56 p.m. marking the beginning of the refueling outage.
The reactor trip breakers were opened, and the unit entered Node 3 at 12: 16 a.m.
on April 10, 1993.
RCS cooldown was commenced at 4:30 a.m.,
Mode
(RCS temperature less than 350'F)
was entered at ll:20 a.m.,
and Mode
(RCS temperature less than 200'F)
was entered at 10:50 p.m.
At 6:25 p.m.
on April 13, 1993, the pressurizer bubble was collapsed, and solid operations was commenced.
Following RCS depressurization and drain down, Unit 4 entered Mode 6 at ll:38 a.m.
on April 15, 1993, when-the first head stud was de-tensioned.
The reactor vessel head was lifted and was placed on its stand at 3:43 a.m.
on April 18, 1993, and the cavity was filled to a level greater than
feet above the vessel flange at 10:25 a.m.
on April 19, 1993.
(Refer to paragraph 8.c for information regarding a problem experienced during the reactor cavity fill process.)
Unlatching of the full.length control rods was commenced at 7: 19 p.m.
on April 19, 1993, and was completed at 10:06 p.m.
on the same day.
'The upper internals package was removed
from the vessel and placed on its stand at 6:35 a.m.
on April 20, 1993; fuel off-loading was commenced at 10:25 a.m.
on April 20, 1993; and the last fuel assembly was off-loaded at 5:35 a.m.
on April 22, 1993.
The inspectors witnessed portions of the off-loading activities on April 21, 1993.
The process was conducted in an efficient professional manner.
Violations or deviations were not identified.
Hanagement Heetings (30702, 94702)
A management meeting was held at the site on April 15, 1993, in order to present the SALP report.
Licensee personnel and representatives from the NRC's Region II and NRR staffs were in attendance.
During this meeting, plant performance in seven functional areas for the assessment period of September 29, 1991, through January 30, 1993, was discussed.
The SALP findings were documented in NRC IR No. 50-250,251/93-03.
(Refer to paragraph 1 for a list of attendees.)
A local public officials meeting was 'also held at the site on April 15, 1993, in order to facilitate the discussion of matters of mutual interest.
Licensee personnel, various local public officials, representatives from FEHA and Greenpeace, and representatives from the NRC's Region II and NRR staffs were in attendance.
'he local public officials had no concerns regarding the SALP presentation or the licensee's actions following Hurricane Andrew.
The Greenpeace representative expressed concerns regarding the SALP process and stated that the concerns would be documented and provided to the NRC.
(Refer to paragraph 1 for a list of attendees.)
Exit Interview The inspection scope and findings were summarized during management interviews held throughout the reporting period with the Plant General Hanager and selected me'mbers of his staff.
An exit meeting was conducted on April 23, 1993.
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.
Violations or deviations were not identified.
Acronyms and Abbreviations ALE Automatic Link Establishment ASHE American Society of Hechanical Engineers BGKE Baltimore Gas and Electric CFR Code of Federal Regulations CHI Corrective Haintenance
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I&C CR Condition Report CS Containment Spray ECCS Emergency Core Cooling System F
Fahrenheit FEHA Federal Emergency Hanagement Agency FPL Florida Power 5. Light
GA GOP gpm HF HPSI I&C IR LCO LER LOCA HOV NCR NCV HIS NRC NRR OHS OP OSP ZP PC/H PORV PRNI Psi psid Pslg PTN PWR QA QAO QC RCDT RCP RCS RHR RI RWST SALP SFP SI TPNP TS Georgia General Operating Procedure Gallons Per Minute High Frequency High Pressure Safety Injection Instrumentation and Control Inspection Report Limiting Condition for Operation Licensee Event Report Loss-of-Coolant Accident Notor Operated Valve Non-Conformance Report Non-Cited Violation Nuclear Instrumentation System Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Overpressure Nitigation System Operating Procedure Operations Surveillance Procedure Differential Pressure Plant Change/Hodification Power Operated Relief Valve.
Power Range Nuclear Instrument pounds per square inch pounds per square inch differential pounds per square inch gauge Plant Turkey Nuclear Pressurized Water Reactor Quality Assurance Quality Assurance Organization Quality Control Reactor Coolant Drain Tank Reactor Coolant Pump Reactor Coolant System Residual Heat Removal Region I Refueling Water Storage Tank Systematic Assessment of Licensee Performance Spent Fuel Pit Safety Injection Turkey Point Nuclear Plant Technical Specification
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