IR 05000250/1989006
| ML17347B049 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 03/21/1989 |
| From: | Butcher R, Crlenjak R, Mcelhinney T, Schnebli G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17347B047 | List: |
| References | |
| 50-250-89-06, 50-250-89-6, 50-251-89-06, 50-251-89-6, NUDOCS 8904040018 | |
| Download: ML17347B049 (27) | |
Text
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos.:
50-250/89-06 and 50-251/89-06 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 4 Inspection Conducted:
January 28, 1989 through February 24, 1989 Inspectors:
W Y.
R.
C. Butcher, Senior Resident Inspector T.
F. McElhinney, Resident Inspector G.
A. Schne
>
Resident Inspector
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Appro'ped by:
R.
V.
en ak, Sec Chic Divi on of Reactor Projects, Da e
)gned
I 7 Date Signed
(> e Da e S'gned ate igned SUMMARY Scope:
Results:
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, evaluation of licensee self-assessment capability, management meetings and plant events.
One violation with three examples was identified:
Inadequate procedure resulting in an inadvertent reactor trip; failure to follow procedures resulting in the inadvertent draining of water from the spent fuel pool and an inadequate clearance resulting in an inadvertent increase in reactor coolant level.
One licensee identified violation with no written notice of violation regarding the failure to have an emergency backup power supply for the "A" residual heat removal pump.
8904040018 8 o 0~50 PDR ADOCK 0500
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I Persons Contacted REPORT DETAILS Licensee Employees
- J O'J L.
- J
- J
- R.
T.
- S R.
- D
- R.
V.
J.
- E R.
- L*+
- G
- F
- R.
J.
M.
M.
J.
Arias, Jr., Technical Assi"stant to Plant Manager W. Anderson, Supervisor (}uality Assurance Regulatory Compliance W. Bladow, guality Assurance Superintendent E. Crockford, Operations Support Supervisor E. Cross, Plant Manager-Nuclear J. Earl, guality Control Supervisor A. Finn, Training Department Superintendent T. Hale, Engineering Project Manager D. Hart, Regulatory and Compliance Supervisor W. Haase, Safety Engineering Group Chairman J. Gianfrancesco, Maintenance Superintendent A. Kaminskas, Reactor Engineering Supervisor A. Labarraque, Project Manager Lyons, Compliance Engineer G. Mende, Operations Supervisor S.
Odom, Site Vice President W. Pearce, Operations Superintendent Salamon, Compliance Engineer M. Smith, Services Manager-NucTear H. Southworth, Technical Department Supervisor J.
Stevens, Manager-Plant Licensing C. Strong, Assistant Superintendent, Mechanical Maintenance Stanton, Instrument and Control Department Supervisor B. Wayland, Assistant Superintendent,Eldctrical Maintenance D.
Webb, Planning and Scheduling Assistant Superintendent Other licensee employees contacted included construction craftsman, engineers, technicians, operators, mechanics, and electricians.
- Attended exit interview on February 24, 1989 Note:
An alphabetical tabulation of acronyms used in this report is
. listed in paragraph 14.
. Followup on Items of Noncompliance (92702)
A review was conducted of the following noncompliances to assure that corrective actions were adequately implemented and resulted in conformance with regulatory requirements.
Verification of corrective action was achieved through record reviews, observation and discussions with licensee personnel.
Licensee correspondence was evaluated to ensure that the responses were timely and that corrective actions were implemented within the time periods specified in the repl (Closed)
Violation 50-250,251/88-11-02, Inadvertent Closing of the Main Diesel Fue1 Oil Suction Valve.
The licensee responded to, the violation in
,letter L-88-384, dated September 2, 1988.
Their response to the event was found to be prompt and adequate for the circumstances involved.
This violation is closed.
Followup on Inspector Followup Items (IFIs) and NRC Requests (92701)
r (Open)
TI 2515/100, Proper Receipt, Storage, and Handling of Emergency Diesel Generator Fuel Oil.
The resident inspectors attended discussions between the licensee and the regional based inspector responsible 'for this TI.
The discussions concerned a fifteen question survey on selected emergency diesel generator fuel oi'I issues.
The licensee provided answers to all questions and the results of the survey will be documented in the regional based inspector's report (50-250,251/89-07).
(Closed) IFI 50-250,251/88-26-03.
Procedures 3/4-0P-094, Containment Post Accident Monitoring Systems, dated 12/2/88 corrected the identified nomenclature discrepancies.
This item is closed.
(Closed)
IFI 50-250,251/88-30-05.
A speciale inspection by Region II inspectors on the resolution of Unit 3 drawing discrepancies was documented in Inspection Report 50-250,251/88-39.
-The inspectors concluded that the actions taken by the licensee to correct"etisting problems with the operating drawings were adequate to permit Unit 3 startup.
Although the complete resolution of the drawing discrepancy backlog is not scheduled to be completed until later, the immediate concern for safe plant operation has been satisfied.
This item is closed.
(Closed)
IFI 50-250,251/88-39-04.
The 1'icensee modified procedures 3/4-0P-201, Filling/Draining the Refueling Cavity and the Spent Fuel Transfer Canal, to ensure the passive seals were tested with the cavity full and the inflatable seal deflated.
This item is closed.
Onsite Followup and In-Office Review of Written Reports of Nonroutine Events (92700/90712)
The Licensee Event reports (LERs)
discussed below were reviewed and closed, 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 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 applie (Closed)
LER 50-251/88-03, Inoperability of Three Battery Chargers due to the Failure of a Gate Filter Module.
This event was discussed in detail in inspection report 50-250,251/88-02 and the inspectors considered the licensee's actions to be adequate.
This LER is closed.
(Closed)
LER 50-251/88-11, Spent Fuel Leakage Caused by Equipment Failure.
This event was discussed in detail in inspection reports 50-251/88-25 and 50-250,251/88-29 and resulted in one violation (50-251/88-25-01)
and three inspector followup items (50-251/88-25-02,03 and 04).
This LER is closed.
(Closed)
LER 50-250/88-27, Hot Particle Contamination of an Individual During Maintenance.
The inspectors consider the licensee's corrective actions to be prompt and adequate for the event.
This LER is closed.
Monthly Surveillance Observations (61726)
The inspectors observed TS required surveillance testing and verified:
that the test procedure conformed to the requirements of the TS, that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that limiting conditions for operation (LCO) were met, that test results met acceptance criteria requirements and were reviewed by personnel other than the individual directing the test, that deficiencies were identified, as apptopriate, and were properly reviewed and resolved by managemefft 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.
I The inspectors witnessed/reviewed portions of the following test activities:
3-0SP-049.1 3-OSP-075. I 3-0SP-075.'6 O-OSP-094.1 3-OSP-089 Reactor Protection System Logic Test Auxiliary Feedwater Train I Operability Test Auxiliary Feedwater Train I Backup Nitrogen Test Post Accident Sampling System Flow Path Verification Main Turbine Valves Operability Test On January 31, 1989, at approximately 4:25 a.m.,
Unit 3 control rod P-10 did not drop fully into the core during performance of 3-PMI-028.3, Rod Drop Test.
The licensee estimated that the rod dropped and then stopped at the 200 steps out position.
The rod was then withdrawn to its full out position and the visicorder, attached to monitor the rod, indicated satisfactory operation.
The rod drop test was repeated and the rod dropped to full in the core without any indication of problems and a
satisfactory drop time.
The licensee contacted the Nuclear Steam System Supplier (NSSS),
Westinghouse, to review the data obtained for P-IO.
The licensee performed the following actions recommended by Westinghouse:
a.
The Rod Cluster Control Assembly (RCAA) was stepped full out and full in and recorder traces showed satisfactory operatio b.
The RCCA was dropped from the full out position five additional times and all times were consistent with the other RCCAs.
Based on the satisfactory test results, following the initial test, the NSSS vendor concluded that the Driveline at core location P-10 was functioning properly.
The licensee believes a possible cause of the rod malfunction during the initial test could'be that P-10's moveable gripper fuse was not removed prior to pulling the stationary coil fuse.
Since P-10 was the last rod in the group to be tested, when the stationary coil fuse was pulled, the control cabinet received an urgent -failure alarm.
This would cause the moveable gripper to activate and engage, thus stopping the rod.
The licensee interviewed personnel conducting the test
'ho indicated that the proper fuses were pulled for this rod test.
Since all the fuses were re-installed after the initial test in order to step the rod out, the actual test conditions were not known.
The licensee also requested Westinghouse to perform an analysis to verify adequate shutdown margin, considering rod P-10 sticking out of the core in addition to the most reactive rod (N-9).
This conservative analysis showed that adequate shutdown margin would exist with the condition described above.
The inspectors reviewed Maintenance Procedure (MP)
0732, Testing and Replacement of BFD/NBFD Relays in Reactor Protection and Safeguards Systems, dated December 28, 1988.
The procedure was recently changed dae to problems identified by the licensee with'revious test results.
During a review of MP 0732 for Unit 3 for 1987 and 1988, questionable timing results were identified.
There were six relay replacements during this time frame and of these, four 'had suspect timing.
The acceptance criteria for'he relay times is 30 milliseconds yr less.
The four suspect relays tested less than this limit, however the time frames were in the micro seconds.
A response time in the microseconds is not possible with these relays.
The four relays were retested using a storage oscilloscope and all four relays tested satisfactorily.
The licensee noted that the questionable times were obtained using substitute test equipment (HP 5315A).
MP 0732 allowed the ISC specialist to use the Electronix Timer Tektronic DC503, the HP 5300B or equivalent.
When properly set up, the HP 5315A gives excellent test results, however, the procedure did not provide set up instructions.
When set up improperly the HP 5315A gives random numbers.
When the Tektronix teste was used, the times were consistent with the original test times.
The licensee has retested all the relays not tested by the Tektronix tester back to January 1986, when the HP 5315A was placed in service.
These additional four relays tested satisfactorily.
The licensee changed MP 0732 to require the use of the electronic oscilloscope and to provide specific set up instructions.
These measures should ensure proper testing of the relays prior to installation.
'o violations or deviations were identified in the areas inspected.
Engineered Safety Features Walkdown (71710)
The inspectors performed an inspection designed to verify the operability of the Unit 3 Safety Injection System (SIS)
and the Residual Heat Removal (RHR)
system flowpath outside containment.
This was accomplished by
performing a complete walkdown of all accessible equipment.
The following criteria wqre used, as appropriate, during this inspection:
a.
System lineup procedures match plant drawings and as built configuration.
b.
Housekeeping is adequate and appropriate levels of cleanliness
- are being maintained.
C.
d.
Valves in the system are correctly installed and do not exhibit signs of gross'packing leakage, bent stems, missing handwheels or improper labeling.
Hangers and supports are made up properly and aligned correctly.
e.
Valves in the flow paths are in the correct position as required by the applicable procedures with power available and valves are locked/lock wired as required.
f.
Local and remote position indication agree and remote instrumenta-tion is* functional.
g.
Major system components are properly labeled.
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Inspector comments regarding minoP'ousekeeping discrepancies were given to licensee management for action.
No violations or deviations were identified.in the areas inspected.
7.
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:
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 RHR pump 4B seal.
Repair of ruptured extraction steam line inside condenser for 4A feedwater heater.
Cleanup of Unit 3 turbine lube oil.
Repair of 4A HHSI pump cracked casing weld at equalizing line.
Troubleshooting 3B Safety Injection Accumulator Level Transmitter LT-924.
No violations or deviations were identified in the areas inspected.
8.
Operational Safety Verification (71707)
The inspectors observed control room operations, reviewed applicable logs, conducted discussions with control Cboth operators, observed shift turnovers and confirmed operabili'fy 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 prioritizatioo 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.
Plant housekeeping/cl eanl iness logical controls were observed.
auxiliary, control and turbine equipment conditions including excessive vibrations.
conditions and implementation of radio-Tours of the intake structure and diesel, buildings were conducted to observe plant potential fire hazards, fluid leaks and 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
The inspectors reviewed procedure 4-0SP-204, Accident Monitoring Instrumentation Channel Checks, dated 6/16/88.
The procedural require-ments for acceptable deviation between instrument channels was compared to procedure 4-OSP-201. I, RCO Daily Logs, dated I/31/89.
The following discrepancies were noted:
Containment Pressure (Narrow Range)
4-OSP-204 1.2 psig 4-0SP-201.1 I psig 20 inches 5 inches Containment Water Level Monitor (Wide Range)
Containment Water Level Monitor 5 inches 6.5 inches (Narrow Range Correction of the noted discrepancies will be followed by the residents as Inspector followup Item 50-250,251/89-06-01.
Other minor discrepancies in 4-OSP-204 are noted. below for information.
Paragraph 2.1.1, TS Table 4.1-1 references, should include Item 30, Safety Valve Position Indicator.
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Paragraphs 7. 1, 7.2, 7.3', 7.4 and 7.5 have acceptance criteria listed as (+/-)
a noted tolerance.
It.would be more correct to state a maximum deviation between channels.
I No violations or deviations were identified in the areas inspected.
Evaluation of Licensee Self-Assessment Capability (40500)
The inspectors evaluated the effectiveness of the licensee's sel f-assessment programs.
The inspectors reviewed the Company Nuclear Review Board (CNRB) to determine compliance with TS 6.5.2 requirements.
The CNRB met the required composition as specified.
Also, a standing subcommittee has been formed to independently examine, evaluate and review technical aspects of nuclear activities, to report the results and to. provide recommendations to the board.
The subcommittee is charged with performing the CNRB TS functions as a minimum.
A CNRB subcommittee Charter has been issued defining the purpose, authority, composition, meeting frequency and activities.
Subcommittee Guidelines have also been issued to define in greater detail the frame work of the subcommittee activities.
A CNRB meeting at Juno Beach, Florida, was attended.
Previous CNRB meeting minutes were reviewed along with CNRB subcommittee meeting minutes.
A Plaht Nuclear Safety Committee meeting was also attended.
All action items are identified and tracked to completio The latest major independent review was the Independent Management Appraisal (IMA) completed in April 1988.
The licensee has initiated a
tracking program for each action item resulting from the IMA.
The inspectors have reviewed the licensee's tracking program and the program appears comprehensive.
No violations or deviations were 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;
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and proposed corrective actions.
On February 6,
1989, at 4: 15 p.m.,
the licensee noted smoke and fire eeming from lagging on a
steam line near 'th6'umber 1 bearing area on the high pressure turbine of Unit 3.
The fire brigade responded and had the fire out within 8 minutes.
The licensee dropped power from lOOX to approximately 92K during the event.
No offsite fire support was required.
This event did not meet an emergency class'ification per Emergency Plan Implementation Procedure 20101 and was not reportable.
However, the licensee did notify the resident inspectors.
The lagging that caught fire appeared to have been oil soaked.
A fire watch was stationed at the Unit 3 front standard area.
On February 7, 1989, at 3:39 p.m.,
the Unit 3 fire watch noted smoke from the lagging on steam exhaust lines near the number I bearing area on the high pressure turbine.
Smoldering insulation was the source of the smoke.
The smoldering insula-tion was extinguished.
The lagging has been determined to contain asbestos, and further removal is being carefully controlled.
Also, there were steam leaks in the vicinity of the lagging which further hampered efforts to remove lagging.
Unit 3 shut down on February 9, 1989, and went back on line February 15, 1989, and no further problems have been noted due to lagging catching fire.
On February 9, 1989, at ll:10 a.m.,
the Unit 3 Reactor Control Operator noticed that the unit output had decreased about 25 megawatts.
Based on the initial indications the licensee determined that the most likely cause was a ruptured extraction steam line expansion joint inside the condenser going to the 4A feedwater heater.
A unit shutdown was commenced at 12:45 p.m.,
and the unit entered Mode 2 at 4:03 p.m.
Subsequent inspec-tion of.the expansion joint inside the condenser found that the joint had ruptured.
The licensee replaced the failed joint.
The unit was returned to service on February 15, 198 On February 9, 1989, at 2:50 p.m., with Unit 4 in Mode 6, the licensee notifed the NRC of a significant event in accordance with 10 CFR 50.72-(b)(2)(iii)(B).
The event occurred when the
"A" Emergency Diesel Generator (EDG)
was taken out of service to test the diesel to ensure operability, in accordance with 0-OSP-23. I, pr ior to removing the "B" EDG from service for planned maintenance.
The procedure required isolating the starting air to the diesel, for personnel safety, to allow manually turning over the engine prior to starting.
The "A" diesel was inoperable for approximately 15 minutes while the starting air was isolated.
At the time the
"A" diesel was out of service, the
"A" Residual Heat Removal (RHR)
pump was in service for decay heat removal and the "B" RHR pump was out of service for maintenance.
Due to the electrical distribution at the plant, the emergency backup power supply to the
"A" RHR pump was not available during the period the "A" diesel was out of service.
The licensee considers the event reportable because the event or condition could have prevented the fulfillment of the safety function of a system needed to remove residual heat in the event of a total loss of off-site power.
The failure to have the emergency backup power supply for the "A" RHR pump is a violation of TS 3.10.7.1 as the licensee's current TS requires that both the normal and the emergency electrical power sources.
be available for operability determination.
However, this violation meets all of the criteria delineated in lO CFR 2, Appendix C, regarding licensee identified violations and therefore no written notice of violation will be
~'ssued.
On February 10, 1989, at 6:40 p.m.,
the licensee reported a Significant Event in accordance with
CFR 50:72(b)(1)(v)
due to a loss of the Emergency Notification System (ENS)
and commercial telephones.
The licensee notified the NRC via a cellular telephone.
At 8:05 p.m., the ENS was restored and a satisfactory communications check was performed.
The telephone company reported at 8:35 p.m., that the main telephone transformer had been shot three times with 9 mm ammunition.
As a pre-cautionary measure, the plant security force was put on alert until 6:00 a.m.,
February ll, 1989.
On February 10, 1989, with Unit 3 in Mode 2, a reactor trip occurred during the performance of OP-14004.1, Steam Generator Protection Channels-Periodic Test.
The trip occurred when bistable BS-3-446-1, turbine first stage pressure, was placed in the test position as required by step 8.3.72 of OP-14004. 1.
Placing the bistable in this position caused the reactor protection system to see reactor power as greater than 10%, thus energizing the P-7 reactor trip relays which then enabled the turbine trip-reactor trip relays.
Since the turbine was already tripped due to the shutdown, the reactor tripped as soon as the bistable was placed in the test position.
The 'root cause for the trip was a procedural inadequacy in that a Caution in the procedure recognized that a reactor trip would occur if the power level was below 10Ã and P-7 was unblocked.
However, due to an editorial error in the procedure, the Caution referenced the wrong steps where the trip would occur.
Although the procedure had been performed in the past without problems, it had b en done with the turbine latched or with the reactor trip breakers open which
would have prevented the reactor trip.
The licensee took immediate corrective, action and. modified the procedure to reference the correct steps in the Caution which will prevent this event from occurring in the future.
TS 6.8. 1 requires that written procedures and administrative policies shall be established, implemented and maintained that meet or exceed the requirements and recommendations of Appendix A of USNRC Regulatory Guide 1.33 and Sections 5.1 and 5.3 of ANSI N18.7-1972.
'Contrary to the above, OP-14004. 1 contained an editorial error, referencing the wrong procedural steps in a Caution, which resulted in a reactor trip.
This is the first example of violation 50-250,251/89-06-02.
On February 15, 1989, the licensee reported a Significant Event due to an Auxiliary Feedwater (AFW) system actuation.
During Unit 3 startup, the Reactor Control Operator (RCO) attempted to start the 3B Steam Generator Feedwater (SGFW)
pump from the control room console.
The switch was released and the pump did not start.
The 3A SGFW pump was off at the time, therefore, the logic for AFW actuation was completed.
The AFW system performed as designed and was subsequently secured by the RCO.
This event had happened previously, therefore, the licensee decided to perform a point to point wire check for the.
3B SGFW pump breaker 3AC14.
The licensee found that internal wiring did not match Elementary Diagram 5610-E-26, sheet 1B.
The internal wiring did match the vendor drawings,
, therefore, this wiring discrepancy existed since installation of the breaker.
The problem associated with the"dfs'crepancy was intermittent such that the breaker would not "close when a
low voltage condition
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existed.
Additionally, the licensee suspects that the 4B SGFW pump has similar wiring, therefore, a walkdown will be performed to verify proper wirirtg configuration.
The A SGFW pumps are supplied by a different vendor and are not suspected to have this problem.
The licensee issued a
Non-Conformance Report (NCR 89-0095)
and t'e engineering disposition was to correct the internal wiring to match the elementary diagram and to update the vendor drawings.
The work was completed under Plant Work Order (PWO)
63-4005 and the 3B SGFW pump was started from the control room successfuly.
On February 18, 1989, with Unit 4 in Node 6 and reactor vessel water level approximately two feet below the flange, the RCO notified the PSN of an unexpected rise in the reactor vessel water level.
The operators attempted to stop the level increase by securing the primary water pumps and closing the emergency boration manual isolation valve (4-358).
The level continued to -increase, therefore, 4-358 was reopened.
The operators determined that the most likely cause of the increasing water level was ongoing MOVATS testing of NOV-4-843A (Boron Injection Tank'outlet isolation va'ive).
The interdisk relief line isolation valve (4-836) for 4-843A was found in the open position.
Therefore, as 4-843A was opened for testing, water from the Unit 3 Refueling Water Storage Tank (RWST)
entered the Reactor Coolant System (RCS).
Valve 4-836 was closed and the reactor vessel level remained constant.
The licensee determined, based on reactor vessel level indications, that the water level remained three to five inches below the vessel flange.
TS 6.8. 1 requires that written procedures and administrative policies shall be established, implemented
and maintained that meet or exceed the requirements and recommendations of Section 5.,1 of ANSI N18.7-1972.
ANSI N18.7-1972, Section 5.1.2 specifies that procedures shall be followed.
Administrative Procedure 0103.4, In-Plant Equipment Clearance Orders, revision dated January 5,
1989, specifies the required instructions to obtain, issue and release clearances to ensure safety and protection of plant personnel and equip-ment.
Contrary to the above, the clearance used to test 4-843A was
'inadequate in that valve 4-836 was not included and required 'to be in the closed position.
This resulted in the uncontrolled transfer of approximately 1000 gallons of borated water from the Unit 3 RWST to the Unit 4 RCS.
This is the second example of violation 50-250,251/89-06-02.
On February 19, 1989, at 4:15 a.m., Unit 4 received a
SFP low level alarm.
The SFP low level alarm comes in at 2 inches below the normal water level of 57 feet.
The operators verified that SFP level was decreasing.
The problem was the result of miscommunication between tw'o nuclear operators (NOs) performing Section 7.4 of 4-0P-201, Filling/Draining the Refueling Cavity and SFP Transfer canal.
Isolation valve 4-796 was opened prior to closing the SFP drain valve 4-12-029 and the SFP Transfer Canal Drain Valve 4-12-028.
This permitted a drain path from the SFP to the SFP Transfer Canal.
4-0P-201, paragraph 7.4.2.R states to close the
'SFP drain valve 4-12-029, paragraph 7.4.2. 10 states to close and lock the SFP transfer canal drain valve 4-12-028 and then paragraph 7.4.2. 11
+tates to open the SFP upper suction valve 4-796.
Contrary to the above, the operators failed to follow procedure 4-0P-201, Section 7.4, resulting in the inadvertent draining of SFP water to the SFP transfer canal.
Failure to follow procedure 4-OP-201 is the third example of violation 50-250,251/89-06-02.
Management Meeting (94702)
On February 13, 1989, Dr.
Thomas E. Murley, Director, Office of Nuclear Reactor Regulation, met with-the resident inspectors and toured the facility.
Meetings were also held with Mr. James E. Cross, Plant Manager, Mr. John S.
Odom, Site Vice President, Mr. William E. Conway, Senior Vice President-Nuclear, and Mr. C. 0.
Woody, Executive Vice President.
Topics of discussion included organization, personnel background and experience, identified plant problems and management initiatives to correct those problems, plant condition and schedules for modifications to plant safety systems.
Allegation RII-88-A-0021 a.
Concern The NRC RII office received an anonymous allegation expressing concerns related to the licensee's program to develop and upgrade preventive maintenance (PM) procedures.
Specifically, the alleger was concerned that the process for specifying acceptance criteria, torque values, setpoint values, etc.
was inadequat Discussion The inspectors discussed the preventive maintenance procedure upgrade program with personnel responsible for the Analytical Based Preventive Maintenance (ABPN)
program and reviewed Administrative Procedure O-ADM-0705, Guideline for the Analytical Based Preventive Maintenance Program, revision dated August 2, 1988.
The purpose of the ABPN program is to support the plant in preserving the oper-ability and safety of plant systems, structures and components.
The administrative procedure provides guidance for the evaluation and upgrade of existing preventive maintenance (PN) tasks, the develop-ment of new PN tasks and the implementation of preventive maintenance.
Part of the licensee's PH procedure revision and generation process consisted of identifying the source documents, from which values were obtained, in the procedure basis document.
The sources from which acceptance criteria, torque requirements and setpoint values were obtained include:
Technical Specifications, Plant Change/Modifications (PC/N),
Final Safety Analysis Report (FSAR), existing Maintenance Instructions (NI) and vendor manuals.
If a vendor recommendation conflicted with a MI value, the NI value was used and a Request for Engineering Assistance (REA) was initiated identifying the conflicting values prior to submitting the procedure for Independent Review Committee ( IRC) distribution.
If no value could'e determined, the department-head decided what value would be used.
The department head could establish or modify any value unless specified otherwise in Technical Specifications, PC/N, FSAR or engineering resolution.
If the department head chose to establish or modify values, then signature approval was. necessary for inclusion into the basis document.
Additionally, a
REA was submitted for system compatibility evaluation.
Upon completion of the basis document and draft procedure, a review was performed by the Planned Maintenance Group (PNG),
IRC and subsequently the Plant Nuclear Safety Committee (PNSC).
The PNSC review ensured that the new and revised PN procedures did not create an unreviewed safety issue as defined in 10 CFR 50.59.
Findings The alleger's concern was not substantiated.
Based on discussions w'ith responsible licensee personnel and review of the PN procedure upgrade program, the inspectors concluded that the method used for determining values in basis documents are adequate.
The licensee was using a process where regulatory required values would be identified and used in the upgraded procedures.
In cases where no regulatory requirement existed, the licensee was using values obtained from existing documentation or that were derived through an engineering evaluation.
Additionally, the review process established ensures that safety significant issues are resolved before the procedure is approved for us No violations or deviations were identified in the areas inspected.
Exit Inter view (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, February 24, 1989.
The areas requir'ing management attention were reviewed.
No proprietary information was provided to the inspectors during the reporting period.
The inspectors had the following findings:
50-250,251/89-06-01, Inspector Followup Item.
Discrepancies in acceptable deviations for accident monitoring instrumentation channel checks.
(paragraph 8)
50-250,251/89-06-02, Yiolation.
Failure to meet the requirements of TS 6.8.1, three examples:
Inadequate procedure resulting in 'an inadvertent reactor trip; failure to follow procedure resulting in inadvertently draining water from the spent fuel pool, and inadequate clearance resulting in inadvertent increase in reactor coolant level water.
(paragraph 10)
Licensee identified violation with no written notice of violation regarding the failure to have an emergency backup power supply for the "A" INR pump.
(paragraph 10)
Acronyms and Abbreviations ABPM ADM a.m.-
AFW ANSI AP ASME CCW CFR CNRB CS.
EDG ENS FPL FSAR I8(C ICW IEB IEC IEN IFI IMA IRC Ahalytical Based Preventive Maintenance Administrative ante meridem Auxiliary Feedwater American National Standards Institue Administrative Procedures American Association of Mechanical Engineers Component Cooling Water Code of Federal Regulations Company Nuclear Review Board Containment Spray Emergency Diesel Generator Emergency Notification System Florida Power 8 Light Final Safety Analysis Report Instrumentation and Control Intake Cooling Water Inspection and Enforcement Bulletin Inspection and Enforcement Ci rculars Inspection and Enforcement Notice Inspector Followup Item Independent Management Appraisal Independent Review Committee
,NCR NRC NSSS OOS OP PC/M PM PHG PMI PSN PWO gA gC RCO RCP RCS REA RHR RCCA RWST SFP SGFW SIS SRO TI TS URI Limiting Condition for Operation Licensee Event Report Licensee Identified Violation Maintenance Instruction Motor Operated Valve Analysis and Test System Motor Operated Valve Maintenance Procedures Non-Conformance Report Nuclear Regulatory Commission Nuclear Steam System Supplier Out of Service Operating Procedure Plant Change/Modification Preventive Maintenance Planned Maintenance Group Preventive Maintenance Instruction Plant Supervisor Nuclear Plant Work 9rder equality Assurance guality Control Reactor Control Operator Reactor Coolant Pump Reactor Coolant System Request for Engineering Assistance Residual H'eat Removal Rod Cluster Control Assembly Refueling Water Storage Tank Spent Fuel Pool Steam Generator Feedwater Safety Injection System Senior Reactor Operator Temporary Instruction Technical Specification Unresolved Item