IR 05000250/1989034
| ML17347B322 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 08/31/1989 |
| From: | Butcher R, Crlenjak R, Mcelhinney T, Schnebli G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17347B321 | List: |
| References | |
| 50-250-89-34, 50-251-89-34, NUDOCS 8909140152 | |
| Download: ML17347B322 (17) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTAST., N.W.
ATLANTAIGEORGIA 30323 Report Nos.:
50-250/89-34 and 50-251/89-34 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 3 and
Inspection Conduct d: July,
through July 28, 1989 Inspectors-.
R.
C.
-her, Seni o es iden@ Inspector Ear Cr'r D te Signed T.
F.
Mc l nney, Re e
Ins ector G. A. Sch
, Res dent pector Approved by:
R.
. Crlenjak, Se ion Chief Di ision of Reactor Projects Date Signed c5'r W/
Date Signed ate igned SUMMARY Scope:
This routine resident inspector inspection entailed direct inspection at the site in the areas of monthly surveillance observations, monthly maintenance observations, engineered safety features walkdowns, operational safety and plant events.
Results:
There was one Inspector Followup Item, one Non-Cited Violation, and one Unresolved** Item identified as follows:
One Non-Cited Violation for allowing the 4A accumulator level to exceed upper limits, paragraph 7.
- "Unresolved Items are matters about which more information is required to determine whether they are acceptable or may involve violations or deviations.
~~09iq01 2 8908::-:i
~DOCK 0000250 q
One Inspector Folowup Item regarding the relocation of one HPN phone at the EOF, paragraph 7.
One Unresolved Item regarding the use of primary containment temperatures from the Safety Assessment System prior to final qualification, paragraph 9.
One concern was expressed to the licensee regarding the need for better direction in determining instrumentation operability when only two indications are availabl REPORT DETAILS Persons Contacted Licensee Employees J.
AJ AJ L.
- S J.
R.
T.
S S.
AD K.
Ap R.
V.
J.
- R.
)kL AQ J.
"M.
A'Q J.
W. Anderson, equality Assurance Supervisor Arias, Sr. Technical -Advisor to Plant Manager
.C..Balaguero, Assistant Technical -Department Supervisor W. Bladow, equality Assurance Superintendent Chappelle, equality Assurance E.'ross, Plant Manager -.Nuclear J. Earl, equality Control Supervisor A. Finn, Training Supervisor Franzone, Lead Engineer, JPN T. Hale, Engineering Project Supervisor Hall, Health Physics Supervisor N. Harris, Vice President C. Higgins, Project Engineer - JPNS J. Gianfrencesco, Maintenance Superintendent A. Kaminskqs, Reactor Engineering Supervisor A. Labarraque, Senior Technical Advisor Lyons, Acting Regulatory and Compliance Supervisor G.
Mende, Operations Supervisor W. Pearce, Operations Superintendent M. Smith, Services Manager Nuclear C. Strong, Mechanical Department Supervisor R.
Timmons, Site Security Superintendent B. Wayland, Electrical Department Supervisor A. Warr incr, equality Control Supervisor D.
Webb, Operations - Maintenance Coordinator Other licensee employees contacted included construction craftsman, engineers, technicians, operators, mechanics, and electricians.
"Attended exit interview Note:
An Alphabetical Tabulation of acronyms used in this report is listed in paragraph 12.
Actions on Previous Inspection Findings (92702)
A review was. conducted of the fo1lowing noncompliances to assure that the licensee's corrective actions were adequately implemented and resulted in conformance with regulatory requirements.
Verification of actions were achieved through record reviews, observation and discussions with licensee personnel.
Licensee correspondence was evaluated to ensure that the responses were timely and that corrective actions were imp')emented within the time periods specified in the repl (Closed)
URI 50-250,251/88-18-02, this item involved problems encountered with the CRVS.
The licensee's investigation determined that failure of the emergency supply fan (SF-1B) to start was due to a drifting bridge circuit.
Modifications were implemented which provided a new push button to separate the high flow and high radiation reset functions.
In addition, when a high flow condition exits, Fan SF-1B is prevented from auto-starting.
In order to identify this condtion, an amber light was installed in the control room.
The CRVS test procedure has been changed to delete the requirement for the operators to push the reset button prior to commencing the surveillance.
The operator is now directed to refer to the ONOP for the CRVS if the amber light is on, indicating high flow.
The operators are also no longer required to depress the reset push button each shift due to the amber light indication.
These enhancements should assure the redundancy requirements of the CRVS emergency fans.
The inspectors found the licensee's corrective actions acceptable.
Therefore, this item is closed.
Followup on Inspector Followup Items (92701)
(Closed)
IFI 50-250,251/88-40-01, concerning draining the Residual Heat Removal (RHR) system on Unit 4 to the point of RHR pump cavitation.
The licensee's corrective actions were reviewed during the closeout of Generic Letter 88-17 which is discussed in detail in Inspection Report 50-250,251/89-27.
This item is closed.
(Closed)
IFI 50-250,251/88-14-02, concerning using the wrong size breaker in the alternate power supply to the RPI system.
The existing
AMP breaker was replaced with the required
AMP breaker and drawing 5610-E-303 was revised by PC/M DEEP 88-254.
This item is closed.
Onsite Followup and In-Office Review of Written Reports of Nonroutine Events (92700/90712/90713)
The LER discussed below was reviewed and closed.
The inspectors verified that reporting requirements had been met, root cause analysis was performed, corrective actions were appropriate, and generic applicability had been considered.
Additionally, the inspectors verified that the licensee had reviewed each event, corrective actions were implemented, responsibility for corrective actions not fully completed was clearly assigned, safety questions had been evaluated and resolved, and violations of regulations or TS conditions had been identified.
When applicable, the criteria of 10 CFR 2, Appendix C, were applied.
(Closed)
LER 50-251/88-12, concerning a turbine runback caused by a
dropped control rod.
The CROM assembly was inspected by Westinghouse during the Unit 4 outage and a crack was found in the stationary coil which was replaced.
The licensee's corrective actions were reviewed by the inspectors and found to be adequate.
This item is close.
Monthly Surveillance Observations (61726)
The inspectors observed TS required surveillance testing and verified that the test procedures conformed to the requirements of the TS, testing was performed in accordance with these procedures, and that the test instrumentation required to perform the tests was calibrated.
In addition, the inspectors verified that the test results met acceptance criteria requirements, were properly reviewed by personnel other than those direct-ing the test, deficiencies identified were properly reviewed and resolved by management personnel and that system restoration was adequate.
For completed tests, the inspectors verified that testing frequencies were met and tests were performed by qualified individuals.
The inspectors witnessed/reviewed portiohs of the followin'g test activities:
OP-12404. 1, Normal Operation of Incore Moveable Detector System and Power Distribution Surveillance.
3-OSP-075. 1, Auxiliary Feedwater Train 1 Operability Test.
3-OSP-049. 1, Reactor Protection System Logic Test.
3-SMI-071.2, Steam Generator Protection Set II (gR-13) Analog Channel test.
4-0SP-089, Main Turbine Valves Operability Test.
During the performance of section 7.3. 16 of 4-0SP-089, Main Turbine Valves Operability Test, for Unit 4 on July 13, 1989, the right turbine stop valve (4-10-009)
would not close using the test switch.
Subsequent troubleshooting showed that the NE and SE reheat stop valves also would not close when using their respective test switches.
The licensee's troubleshooting indicated that the multiple orifice block which supplies oil to the three valves would not close.
The licensee then reduced power, to less than 10K, below the P-10 setpoint, and manually tripped the turbine to verify right turbine stop valve closure.
The stop valve closed as required to satisfy the surveillance requirement and the unit was returned to 100%%u'ower.
Additional troubleshooting commenced on July 17, 1989, when the unit was shutdown to repair ICW header isolation valve 4-50-308.
The troubleshooting was conducted by the licensee's turbine expert and Westinghouse turbine personnel, as this portion of the turbine control oil system is Westinghouse proprietary information.
The problem appeared to be that.the Westinghouse proprietary drawing for the multiple orifice block was not clear as to which orifice was to be used in each port of the block for the various applications of this system.
Each multiple orifice block contains four orifices, three of which are identical and supply oil to the three valves that failed to close.
The fourth orifice, which is the supply of auto stop oil to the block, is slightly different in that it does not have a larger threaded discharge port in the end of the orifice.
, The threaded portion of the other
orifices is to facilitate the removal of these orifices from their deep seated position in the block.
All four orifices in the block were found to be identical in that they all contained the threaded portion in the discharge port.
The licensee and Westinghouse concluded that the larger threaded opening in the auto stop oil orifice may have allowed too much oil flow against the orifice check plate causing the plate to lift slightly and provide additional oil flow to the valve being tested.
This additional oil flow to the valve under test would have caused the valve to remain partially open if the, total oil flow to valve was more than the test solenoid valve could relieve.
Under Westinghouse direction, the auto stop oil orifice was modified to plug the large threaded opening with a set screw to limit the oil flow through this passage of the orifice.
The same modification was then made to the left turbine stop valve multiple orifice.
The turbine valve test was then re-performed satisfactorily on July 19, 1989.
Westinghouse is currently planning on making a design change to the orifice and clarify the drawing as to which orifice is used for each application.
No violations or deviations were identified in the areas inspected.
Monthly Maintenance Observations (62703)
Station maintenance activities on safety related systems and components were observed and reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides, industry codes and standards, and in conformance with TS.
The following items were considered during this review, as appropriate:
That Limiting Condition for Operation (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; guality Control (gC) records were maintained; activi-ties 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 preven-tion controls were implemented; outside contractor force activities were controlled in accordance with the approved guality Assurance (gA) program; and housekeeping was actively pursued.
The inspectors witnessed/reviewed portions of the following maintenance activities in progress:
Repair of MOV;3-1427, SG Blowdown Sample Isolation Valve.
Troubleshooting Pressurizer Level Transmitters LT-461 for Units
and Repair of Unit 4 ICW Isolation Valve 4-50-308.
Troubleshooting 4A Turbine Plant Heat Exchanger to Determine Cause of Low Flow.
Repacking and Repair of 3C Charging Pump.
Repair of Unit 4 Turbine Multiple Orifice Block (see paragraph 5).
No violations or deviations were identified in the areas inspected.
7.
Operational Safety Verification (71707)
The inspectors observed control room operations, reviewed applicable logs, conducted discussions with control room operators, observed shift turnovers and confirmed operability of instrumentation.
The inspectors verified the operability of selected emergency systems, verified that maintenance work orders had been submitted as required and that followup and prioritization of work was accomplished.
The inspectors reviewed tagout records, verified compliance with TS LCOs and verified the return to service of affected components.
In addition, by observation and direct interviews, the inspectors verified that the physical security plan was being implemented.
Plant housekeeping/cleanliness conditions and implementation of radio-logical controls were also observed.
The inspectors found the cleanliness conditions in the plant and the implementation of radiological controls to be satisfactory.
Tours of the intake structure and diesel, auxiliary, control and turbine buildings were conducted by the inspectors 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 to verify operability and 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 On June 27, 1989, with Unit 4 at 52K power, the 4A Safety Injection Accumulator level transmitter (LT-4-920) exceeded the high level setpoint of 6628 gallons.
The redundant level transmitter (LT-4-922) indicated level in the normal operational band.
Operations personnel decided to remove LT-4-920 from 'service.
A plant work order (PWO)
was written to
repair LT-4-920.
The I8C Department vented the transmitter and performed a calibration.
On June 29, 1989, I8C determined that LT-4-920 was reading five gallons higher than actual level which did not account for the large deviation from the redundant level transmitter.
LT-4-920 was returned to service and LT-4-922 was taken out of service for troubleshooting.
Since LT-4-920 was reading the actual level, the 4A accumulator was drained to lower the level to the normal operating band.
Inspection of LT-4-922 revealed insulation damage on two wires and damage to the upper terminal board.
Non-Conformance Report (NCR) 89-0251 was generated for engineering evaluation.
Engineering determined that the transmitter could be repaired with tape and if it could be bench calibrated according to plant procedures, then the transmitter could be declared operable.
However, LT-4-922 was listed on the
CFR 50.49, Environmental Qualification (EQ)
list, and this repair would not qualify the transmitter for post accident conditions.
There were no spare transmitters in stock at Turkey Point; therefore, the licensee performed an engineering evaluation justifing continued operation.
Engineering used guidance contained in Generic Letter 88-07 as the bases of their evaluation.
The guidance provided in Generic Letter 88-07 allows the use of redundant qualified indication with respect to demonstrating operability.
Available to the operators for accumulator levels were the accumulator pressure transmitters and a graph which correlates pressure to level.
The redundant LT-4-920 was also available.
In addition, the accumulator level indicators are not used by operators for any design basis accident mitigation procedures.
Based on this, engineering concluded continued operation is justified providing the plant procured a qualified replacement level transmitter and replaced the existing transmitter within eight weeks.
On July ll, 1989, the licensee determined that the 4A Accumulator level Technical Specification (TS) Action Statement Requirements were not met on June 28, 1989.
At 9: 12 a.m.
the 4A Hi-Hi level alarm was acknowledged by the Unit 4 operator but was considered invalid since LT-4-920 was out of service and LT-4-922 indicated within the normal operating band.
From that time until approximately 6:50 p.m. that day (9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />, 38 minutes)
the level exceeded the TS limit of 6664 gallons.
TS 3. 4. l. a.3 specified that each accumulator shall contain 875 - 891 cubic feet of water.
TS 3.4. l.b. 1 allows one accumulator to be out of service during operation for a period of up to four hours.
If the accumulator is not returned to service within the required time limit, then the operators must commence a
unit shutdown.
Contrary to the above, on June 28, 1989, the 4A Accumu-lator level exceeded the TS limit for a period in excess of four hours and the unit was not shutdown.
This condition resulted from an operator making the incorrect determination with regard to which accumulator level transmitter was out of service.
This constitutes a violation of TS 3.4. 1.
However the licensee determined that the highest water level experienced was bounded by an existing safety evaluation.
This evaluation was performed on May 16, 1989, to determine the maximum accumulator level instrument inaccuracies.
This was in response to LER 50-250,251/88-30, Instrument Loop Error and Installation Error Caused Accumulator Level Instrumentation Inability to Assure Technical Specification Limits Me i i
This evaluation determined that the accumulator water volumes could be as much as 21.4 gallons greater than the maximum volume specified in TS without invalidating the Turkey Point Unit 4 accident analyses.
The review of the June 28, 1989, water levels revealed that the highest level was 20.4 gallons over the TS limit.
Therefore, this level was bounded by the safety evaluation.
The licensee plans to incorporate a
maximum channel deviation value between redundant accumulator level transmitters into the Units 3 and 4 operator logs.
Exceeding this value will require a
PWO be issued to determine the cause of the deviation.
Since there are only two redundant level transmitters, a
more thorough investigation is required to be done to determine which of the two is defective.
The licensee committed to develop guidance for the determination of the defective instrument when two or more instruments disagree.
The inspectors determined that this violation met the criteria specified in Section V of the NRC Enforcement Policy as a
Licensee Identified Violation and will not be cited.
This item will be tracked as NCV 50-250, 251/89-34-01.
The inspectors toured the Turkey Point EOF which is located in the licensee's General Office building at 9250 W. Flagler Street in Miami, Florida.
The EOF has an emergency communications network which includes commercial telephone lines, the ENS phone, the HPN phone, and direct lines to the control room and Technical Support TSC.
The inspectors determined that one HPN phone was located in the open assessment area at the NRC desk and the second HPN phone was located in a conference room to be used exclusively by the NRC.
The licensee's health physics dose assessment area is located in another area independent of the two areas noted above.
The inspector determined from NRC regional emergency preparedness group that an HPN phone should be located at the licensee's health physics dose assessment area.
The inspector will follow up on the relocation of the HPN phone from the NRC conference room to the licensee's health physics dose assessment area as Inspector Followup Item 50-250,251/89-34-02.
The inspectors reviewed the licensee's EOF set of emergency plan implementing procedures and found no discrepancies.
The procedures were indexed and well maintained.
The licensee also maintains two sets of selected operating drawing/diagrams in addition to those that Engineering is responsible for providing during an emergency (See JPE-AP 1. 11, FPL Nuclear Plants Emergency Operations Facilities
-
Materials and Deployment).
The drawings were well maintained and only one discrepancy was noted.
Red line drawing 5610-M-339, Sheet 1/R38, Rev.
0, was in the drawing book but has been superseded and should have been removed.
The licensee was notified of the one minor discrepancy.
No violations or deviations were identified in the areas inspected.
Plant Star tup From Refueling (71711)
The inspectors witnessed/reviewed selected activities related to the Unit 4 Startup From Refueling Cycle XII.
These reviews were performed to verify that the licensee properly restored systems effected during the
outage and to ascertain whether plant startup and core physics tests were conducted in accordance with approved plant procedures.
Operating Procedure 0204.5, Nuclear Design Check Tests During Startup Sequence After Refueling, dated March 24, 1989, was used by the licensee to conduct power escalation tests.
Inspection Report 250,241/89-27 documented the results of the low power physics testing.
Portions of the power escalation tests were witnessed by the inspectors which included performance of flux maps and thermal calometrics at various power levels.
The inspectors also witness/reviewed the adjustments of the Power Range Nuclear Instruments in accordance with procedure 4-OSP-059. 5, Power Range Nuclear Instrumentation Shift Checks and Daily Calibrations.
Unit 4 reached 100K power on June 30, 1989, and the startup testing was completed.
Followup Of Onsite 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.
On July 13, 1989, at 4: 25 p.m.,
the Unit 4, 4A Intake Cooling Water/
Component Cooling Water (ICW/CCW) strainer was taken out of service for cleaning due to high dp.
At 4: 35 p. m., the Unit 4 nuclear operator notified the control room that low ICW flow was indicated in the CCW heat exchanger flow indicators.
The nuclear operator was instructed to valve the 4A ICW/CCW strainer back in service.
The strainer was returned to service at 4:40 p.m..
The licensee then cleaned the 4B ICW/CCM strainer with no further problems with ICW flow.
The licensee performed an evaluation to determine the minimum allowable ICW/CCW flow and on July 15, 1989, at 8:00 a.m., it was determined that ICW flow to the CCW heat exchangers through the 4B ICW/CCW header was probably less than the amount required to mitigate the Design Basis Accident heat load.
A significant event was reported per
CFR 50.72(b)(2)(iii)(D).
The NRC was notified on July 15, 1989, at 8:58 a.m.,
ICW/CCW flow was restored within 15 minutes.
Procedure 4-0P-019, Intake Cooling Water System, did not have a
caution/requirement to verify proper ICW flow to the CCW heat exchangers when valving a strainer out of service for backwashing, also, the B ICM strainer dp gauge (DPI-4-1403)
was giving inaccurate indications due to possible clogged strainer lines.
On The Spot Changes (OTSCs) were written to add a caution statement to 3/4-0P-019, to verify proper ICW flow to the CCW heat exchangers.
I8C blew down the sensing lines to DPI-4-1403.
Subsequent investigation into the low ICW flow indications while the "A"
ICW/CCW strainer was out of service indicated the "B" ICW header isolation valve, 4-50-308, may not be operating properly and causing a flow obstruc-tion in the "B" header.
This valve is a manually operated butterfly valve used for maintenance isolation.
Initial testing by the licensee indicated the manual operator was not turning the valve disc, indicating the disc was separated from the upper stem or the stem was sheared.
At 2:25 p.m.,
on July 16, 1989, with Unit 4 in Mode 1, the 4B ICW header was declared inoperable due to low flow conditions.
Technical Specification 3.4.5.b allows the unit to remain at power for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with one ICM header out of service before placing the unit in hot standby, and further allows the unit to remain in hot standby for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> before going to cold shutdown.
Unit 4 shutdown was initiated at 3:25 a.m.
on July 17, 1989 and the unit came off line at 5:52 a.m.."
The Unit entered Mode 4 at 12:30 a.m.,
on July 18, 1989.
The licensee notified the NRC of the unit shutdown at 12:42 a.m.,
on July 17, 1989, in accordance with 10 CFR 50.72(b)(l)(i)(A).
The testing also indicated that although flow was reduced in the "B" ICM header there was sufficient ICW flow through the "B" header to remove the existing heat loads for the condition the unit was in.
Prior to isolating the "B" header for maintenance, which would remove all ICW flow throughout the
"B" header, the licensee requested Discretionary Enforcement from TS 3.4.5 to isolate the 4A ICM header to allow cleaning the 4A ICW basket strainer.
This was to ensure the 4A strainer was as clean as possible prior to isolating the
"B" header.
The NRC considered this to be a
prudent action as the strainers were being frequently cleaned due to excessive amounts of seaweed floating throughout the canal cooling system.
During the period the 4A strainer was isolated the only ICW flow would be the reduced flow through the
"B" header.
The NRC approved the Discretionary Enforcement at 4: 00 p. m.,
on July 18, 1989, provided the time did not exceed one hour and personnel were stationed to immediately return the 4A strainer to service if flow problems were encountered while the
"B" header was supplying the cooling flow.
The proposed action was justified based on:
b.
The short duration (less than one hour) that the 4A ICW header would be isolated with the 4B header in a degraded flow condition.
Engineering calculation that indicated that. the 4B ICW header flow was adequate to remove the existing operational component cooling water heat loads.
Engineering calculation that indicated sufficient time to restore flow through the 4A ICM header in the event that flow through the 4B ICM header was instantaneously lost while cleaning the 4A strainer, such that the limiting components in the component cooling water system would not be affected, d.
The stationing of operators to immediately restore flow in the 4A ICW header in the unlikely event of loss of flow in the 4B ICW header.
The 4A strainer was removed from service at 8: 15 p.m.,
on July 18, 1989, for cleaning and returned to service at 9:00 p.m....ICW flow through the
system was 23,600 GPM prior to isolating the 4A strainer and dropped to 18,600 GPM when the strai ner was isolated and the flow was being supplied through the "B" header.
After the flush the flow again returned to 23,600 gallons per minute (GPM).
The "B" header was then isolated and valve 4-50-308 was removed from the system.
As suspected, the valve disc had separated from the upper stem or shaft and had partially closed, causing the flow reduction.
A new valve was reinstalled, tested, and the
"B" header was returned to service on July 20, 1989, at 7:00 p.m.
During replacement of the valve, the licensee requested Discretionary Enforcement to allow the unit to remain in Mode 4 an additional 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to entering Mode 5 as required by TS 3. 4. 5.
The request was granted by the NRC on July 20, 1989, at 4:45 p.m.,
however, the licensee was not required
,to implement this request as the system was returned to service on July 20, 1989, at 7: 00 p. m.
and the LCO time allotted by TS 3. 4. 5 required the system be returned to service by 2: 25 a. m.,
on July 21, 1989.
On July 15, 1989, the Unit 4 Pressurizer Relief Tank (PRT) gas space was being purged due to high oxygen and hydrogen concentrations per 4-0P-41.3, section 7.6.
This involved raising the PRT liquid level while venting the gas, and then lowering the liquid level with the Reactor Coolant Dr'ain Tank pump while admitting nitrogen.
When the level was lowered the PRT gas pressure went to zero and at the same time the containment sump level increa'sed approximately 120 gallons.
The purging of the PRT was stopped and an investigation was performed which identified no positive reason for the containment sump level rise, but it was theorized that the nuclear operator inadvertently opened LCV-4-1003B the PRT drain to the containment sump.
To prevent this from possibly occurring again, the.following actions are -being taken:
The fuses have been pulled from LCV-3/4-1003B and are controlled on a plant clearance order until the following actions are completed; the color of the label plate for LCV-3/4-1003B control switch will be changed to yellow and a protective plexiglass cover will be placed over the control switch for LCV-3/4-1003B.
The licensee will continue to monitor this area when the evolution is performed to ensure the corrective actions taken were adequate.
On July 21, 1989, with Unit 3 at 100K power the operators noted a discrep-ancy between the primary containment temperature indication of the SAS and the backup containment temperature recorder R-4-1413.
The primary points were reading as follows:
TE-6700 112.5 degr ees F.
TE-6701 122.5 degrees F.
TE-6702 112.0 degrees F.
The backup points were indicating as follows:
TE-1497 TE-1498 TE-'1499 122 degrees F.
122.5 degrees F.
120.5 degrees The licensee's ITS as implemented by ADM Procedure 021, Technical Specification Implementation Procedure, dated July 9,
1989, section 3.6. 1.5, specified that the primary containment average temperature shall not exceed 120 degrees F.
Section 4.5. 1.5, specified that the average containment temperature shall be determined at least once per twenty four hours using the primary points and if they are inoperable, to use the backup points.
When the discrepancy was noted, 18C Department notified Operations that the SAS containment temperature points were not turned over to the plant.
The licensee indicated that the temperature elements were calibrated, however, the supporting documentation was not completed.
The documentation was completed later that day and the SAS containment temperature points were turned over to the plant.
The licensee investigated other SAS points for Units 3 8 4 which were used to satisfy TS requirements to verify proper turnover.
The licensee identified points used for thermal calometric determination and leak rate calculations that were calibrated but not officially turned over to the plant.
The inspectors were investigating this issue at the end of the inspection period and will track this item as Unresolved Item 50-250,251/89-34-03.
No violations or deviations were identified within the areas inspected.
Management Meeting This meeting was the twelfth in a series of management meetings between the NRC and FP8 L following the issuance of Confirmatory Order 87-85 in October 1987.
The previous meeting was held on May 10, 1989.
A plant tour was conducted by the resident inspectors to update NRC management on plant conditions.
The formal meeting was opened by Mr.
K. Harris.
Mr. J.
Cross gave a brief summary of plant status and recent operational events.
He emphasized the demonstration of cooldown from outside the control room, the pressure binding of the residual heat removal suction valves, 4-750/4-751, a 100K pass rate for the operations fundamentals test conducted at Atlanta, GA.
and two inadvertent safety injection actuations due to switch labeling and post maintenance testing deficiencies.
Mr.
Harris discussed the IMA status.
Mr. Bladow discussed gA's assessment of the IMA implementation and Mr. Pell discussed the INPO exit in terms of major concerns and good practices.
Mr.
Cross addressed improvement in several key indicators in maintenance.
Mr. Wayland discussed maintenance indicators in general and assessed progress.
Mr. Hale discussed the drawing update progress and the PRA staus.
Mr. Beatty discussed training issues and efforts to improve the training program.
Mr. Beatty is now the Training Superintendent.
Mr.
West discussed key indicators in the security area and actions taken to stabilize the security force.
Exit Interview (30703)
The inspection scope and findings were summarized during management interviews held throughout the reporting period with the Plant Manager-Nuclear and selected members of his staff.
An exit meeting was conducted on July 28, 1989.
The areas requiring management attention were reviewe No proprietary information was provided to the inspectors during the reporting period.
The inspectors had the following findings:
50-250,251/89-34-01, Non-Cited Violation.
4A accumulator level exceeded upper limits.
(Paragraph 7)
50-250,251/89-34-02, Inspector Followup Item.
Relocate HPN phone at EOF from NRC conference room to health physics dose assessment area.
(Paragraph 7)
50-250,251/89-34-03, Unresolved Item.
Use of primary containment temperatures from the Safety Assessment System prior to final qualification.
(Paragraph 9)
Acronyms and Abbreviations ADM ANSI AP ASME CCW CFR CRVS CS DBA DP ENS EOF ERT FPL FSAR GPM HHSI HPN ICW IEB IFI ITS LCO LER LIV LOCA MP NCR NE NRC ONOP OOS OP OTSC Administrative American National Standards Institute Administrative Procedures American Society of Mechanical Engineers Component Cooling Water Code of Federal Regulations Control Room Ventilation System Containment Spray Design Basis Accident Differential Pressure Emergency Notification System Emergency Operations Facilities Event Response Team Florida Power 8 Light Final Safety Analysis Report Gallons Per Minute High Head Safety Injection Health Physics Network Intake Cooling Water Inspection and Enforcement Bulletin Inspector Followup Item Interim Technical Specifications Limiting Condition for Operation Licensee Event Report Licensee Identified Violation Loss of Coolant Accident Maintenance Procedures Non-conformance Report NorthEast Nuclear Regulatory Commission Off Normal Operating Procedure Out of Service Operating Procedure On the Spot Change
PC/M PNSC PRT PSN PWO QA QC RCO RCP RCS RHR SAS SE SRO TS TSC URI Plant Change/Modification Plant Nuclear Safety Committee Pressure Relief Tank Plant Supervisor Nuclear Plant Work Order Quality Assur ance Quality Control Reactor Control Operator Reactor Coolant Pump Reactor Coolant System Residual Heat Removal Safety Assessment System SouthEast Senior Reactor Operator Technical Specification Technical Support Center Unresolved Item