IR 05000335/1994020
ML17228A890 | |
Person / Time | |
---|---|
Site: | Saint Lucie |
Issue date: | 10/14/1994 |
From: | Landis K, Mark Miller, Prevatte R, Sartor W, Schin R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
To: | |
Shared Package | |
ML17228A889 | List: |
References | |
50-335-94-20, 50-389-94-20, NUDOCS 9411010124 | |
Download: ML17228A890 (22) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900 ATLANTA,GEORGIA 303234199 Report Nos.:
50-335/94-20 and 50-389/94-20 Licensee:
Florida Power 5 Light Co 9250 West Flagler Street Miami, FL 33102 Docket Nos.:
50-335 and 50-389 License Nos.:
R. L.
P evatte, Seni Inspector
~(.
M. S. Mil er, Residen R.
P.
Sch n, reactor W.
. Sartor, Senior Speciali Resident Inspector neer adiation Approved by:
~
a K. D. Landis, hief Reactor Projects Section
Division of Reactor Projects Facility Name:
St.
Lucie I and
Inspection Conducted:
August 28 - September 30, 1994 D te Signed e
igned D te Signed Date Signed Date ig ed SUMMARY
=-
Scope:
This routine resident inspection was conducted onsite in the areas of plant operations review, maintenance observations, surveillance observations, plant support, followup of previous inspection findings, and other areas.
Inspections were performed during normal and backshift hours and on weekends and holidays.
Results:
,In the areas inspected, violations or deviations were not identified.
An unresolved item involving IA Emergency Diesel Generator Operability Concerns and Control Room Logkeeping (URI 335/94-20-01)
was identified, paragraph 3.c.
9411010124 941018 PDR ADOCK 05000335
Plant Operations area:
The licensee conducted plant operations in a safe manner during the inspection period.
The inspectors identified an unresolved item involving operators placing operable emergency diesel generator IA in a lineup (with the safety-related swing bus powered from it) for which the TS-required surveillance testing had not been performed.
Also, control room log entries on this item appeared to be inaccurate.
The inspectors will assess the safety significance of this item after the licensee determines and performs the required testing during the refueling outage that is scheduled to begin on October 31, 1994.
During plant tours on Unit I, inspectors noted a
significant number of steam and water leaks.
They also identified a
weakness involving valve position indicating devices and the procedures and training provided to operators on how to verify valve positions.
Maintenance and Surveillance area:
During the inspection period, the licensee conducted maintenance in a safe and effectiv'e manner.
Inspectors noted that the accuracy and ranges of required test equipment were not always specified in procedures.
The licensee experienced a near miss involving work on the wrong train by electricians.
This appears to have been the result of less than fully effective work control and communications.
Inspectors also found that plant personnel have not been trained on their Individual Plant Examination and were not using it as a part of work planning and scheduling.
In addition, inspectors identified several minor deficiencies in the area of labeling.
Plant Support area:
The plant's support functions continued to be effective.
The licensee modified their process and procedures for accountability during a site evacuation.
Drill results verified that this can now be accomplished in acceptable time limit REPORT DETAILS Persons Contacted Licensee Employees R. Ball, Mechanical Maintenance Department Head W. Bladow, Site guality Manager L. Bossinger, Electrical Maintenance Department H. Buchanan, Health Physics Supervisor C. Burton, St.
Lucie Plant General Manager R. Church, Independent Safety Engineering Group R.
Dawson, Licensing Manager D. Denver, Site Engineering Manager J.
Dyer, Maintenance guality Control Supervisor H. Fagley, Construction Services Manager P. Fincher, Training Manager R. Frechette, Chemistry Supervisor J. Goldberg, President Nuclear Division K. Heffelfinger, Protection Services Supervisor J. Holt, Plant Licensing Engineer G. Madden, Plant Licensing Engineer J. Harchese, Maintenance Manager C. Harple, Assistant Operations Supervisor K. Hohindroo, Site Engineering Supervisor W. Parks, Reactor Engineering Supervisor C. Pell, Outage Manager L. Rogers, Instrument and Control Maintenance De D. Sager, St.
Lucie Plant Vice President J. Scarola, Operations Manager and Acting Plant J. Spodick, Operations Training Supervisor D. West, Technical Manager J.
West, Site Services Hanager C.
Wood, Operations Supervisor W. White, Security Supervisor Head Chairman partment Head General Manager NRC Personnel Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personnel.
- R. Prevatte, Senior Resident Inspector
- H. Hiller, Resident Inspector
- R. Schin, Reactor Engineer, Region II
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragrap.
Plant Status and Activities a ~
b.
Unit
Unit 1 began the inspection period at 65 percent power.
Power had been reduced on August 27 to perform a leak repair on the DEH system and replace expansion joints on the CW piping.
The turbine was taken off line on August 28 to repair the leak in the Digital Electro-Hydraulic System.
Repairs were completed and the unit returned to power on the afternoon of August 28.
The unit operated at approximately 65 percent power until the CW system repairs were completed on September 2.
The unit. then returned to and operated at essentially 100 percent power until power was reduced to approximately 65 percent on September 29 to permit work on TCW 1A heat exchanger and to clean condenser waterboxes.
These repairs were completed on September 30 and the unit was in the process of returning to full power at the completion of the reporting period.
Unit 2 C.
Unit 2 operated at essentially 100 percent power throughout the inspection period.
NRC Activity During the period, W. J. Tobin and L. C. Stratton of the Division of Reactor Safety and Safeguards, Region II, were onsite from September 26 through September 29.
Their inspection results are documented in IR 335,389/94-21.
J.
H. Hoorman and S. J. Cahill of the Division of Reactor Safety also were on site for Licensed Operator Requalification exams during the same period.
Their inspection results are documented in IR 335,389/94-19.
W. H. Sartor of the Division of Reactor Safety and Safeguards was on site on September 30 to evaluate a site evacuation drill. His inspection results are contained in this report.
3.
Plant Operations (71707, 37551)
a ~
Plant Tours The inspectors periodically conducted plant tours to verify that monitoring equipment was recording as required, equipment was properly -tagged, operations personnel were aware of plant conditions, and plant housekeeping efforts were adequate.
The inspectors also determined that excess equipment or material was stored properly, and combustible materials and debris were disposed of exp'editiously.
During tours, the inspectors looked for the existence of unusual fluid leaks, piping vibrations, pipe hanger and seismic restraint settings, various valve and breaker positions, equipment caution and danger tags, component positions, adequacy of fire fighting equipment, and instrument cal,ibration dates.
Some tours were conducted on backshifts, weekends, and holidays.
The
frequency of plant tours and control room visits by site management was noted.
The inspector accompanied NLOs on their daily rounds of Unit
reactor building and turbine building on September
and 22.
It took each operator two to two and one half hours to make their required rounds, examine equipment and spaces for abnormal conditions, and perform tasks such as making flow or level adjustment on equipment, sumps, or tanks.
The inspector observed that the operators performed general inspections of each assigned area.
They appeared to be alert and demonstrated a good practice of touching and feeling equipment as needed to detect overheating or excessive vibrations.
The inspector questioned the operators extensively about previous equipment problems,'ow negative trends are detected, equipment functions and operation, frequency of rounds, plant and equipment labeling, and the responsiveness of maintenance and other support organizations to equipment failures and management and supervisory expectations.
Both operators appeared to be very knowledgeable in all the above areas.
They also appeared to be conscientious and motivated and proud of their plant and its past accomplishments.
The inspector found the overall condition of the plant and observed equipment to be satisfactory.
He did note approximately 25 steam and water leaks that required repair.
In each case these had been previously identified by plant personnel and a
PWO tag was attached.
The unit is scheduled for a refueling outage on October 31.
When these items were discussed with the plant manager, he stated that all leaks and temporary leak repairs will be worked during the refueling outage.
The inspectors conducted a main flowpath walkdown of the Unit 1 HPSI and LPSI systems, the Units 1 and
AFW systems, and support systems.
Valve, breaker, and switch lineups as well as equipment conditions were randomly verified both locally and in the control room.
No deficiencies were identified on the AFW systems.
During the main flowpath walkdown for the Unit 1 HPSI and LPSI systems, the inspector identified a licensee weakness involving valve position indicating devices and the procedures and training given to operators on how to verify valve positions.
AP 0010120, Conduct of Operations, directed operators to determine the position of MOVs for system lineups by using the stem position indicators or position pointers, by a functional test (i.e., flow through the valve), or by having the ANPS determine an alternate method.
The inspector found four local MOV position indicators to be unusable (i.e., illegible or indicating 50% open when the valve was closed);
this was about 15% of all the MOV position indicators inspected.
The inspector asked the auxiliary operator on shift to show how he would determine the position of HPSI header MOVs in the Unit 1 lower
level pipe tunnel for a system lineup (including valves with unusable position indicators).
The operator stated that the local valve position indicators were known to be unreliable so he would not use them.
He showed the inspector position indicating lights in a nearby room that he would use.
He showed how, for those valves-that did not have nearby position indicating lights, he would use grease marks on the valve stem to tell valve position.
The inspector noted that procedure AP 0010120 did not address the use of position indicating lights or grease marks on the valve.stem.
The
.
inspector concluded that the licensee's maintenance of HOV local position indicators did not support AP 0010120 and placed the operators in the position of having, to "work around" that deficiency.
The inspector also concluded that the procedures and training of operators on how to determine HOV valve positions were weak.
The inspector identified another "operator work-around" on NOV valve position:
procedure OP 1-0410020, HPSI/LPSI - Normal Operation, required HOV V3653, 1B/1C HPSI Pump Discharge Cross-Tie, to be locked open.
However, the inspector found it to be closed, with the handwheel locked and the breaker tagged open on an administrative clearance.
There was no clearance tag on the valve, and a review of the clearances in the control room indicated that the valve position was not addressed by a clearance.
The NPS and ANPS stated that the desired position for the valve was closed, since the 1C HPSI pump was inoperable and had been abandoned in place (with the motor removed) for several years.
The inspector reviewed the last system lineup that had been performed, in Hay 1993, and found that operators had not verified the position of V3653, but had stated (incorrectly)
on the system lineup sheet that V3653 was on an administrative clearance.
The inspector concluded that OP 1-0410020 was in error on the required position of V3653 and that operators had been erroneously working around this procedure error.
The inspector also found that several valves had locks on their handwheels that were not required by OP 1-0410020.
Also, the plant operating drawings for the HPSI and LPSI systems showed some valve handwheel locks but did not show many others.
The licensee stated that they had recognized a deficiency in the area of documentation for valve handwheel locks, and had begun to correct the operating procedures and drawings.
The inspector reviewed AP 1-0010123; Administrative Control of Valves, Locks, and Switches; rev.
96; dated September 1,
1994.
for periodic verification of the status of locked valves, AP 1-0010123 directed operators to use control room or other remote indication as appropriate.
The procedure also provided a more thorough and correct listing of locked valves, including reasons why the locks were on the valves.
The inspector concluded that the licensee had made a good start on correcting the weakness with procedure and drawing documentation of locked valve During the HPSI and LPSI systems walkdown, the inspector observed about 23 deficiencies with equipment or procedures (i.e.,
unusable valve position indicators, valve packing leaks, unsealed electrical flexible conduits, room lights not working, and an instrument air leak, all without PWO tags; handwheel locks not shown on system lineup procedures; and other errors in system lineup procedures).
The NPS and ANPS were responsive in initiating maintenance work requests and procedure changes to. address these deficiencies.
Plant Operations Review The inspectors periodically reviewed shift logs and operations records, including data sheets, instrument traces, and records of equipment malfunctions.
This review included control room logs and auxiliary logs, operating orders, standing orders, jumper logs, and equipment tagout records.
The inspectors routinely observed operator alertness and demeanor during plant tours.
They observed and evaluated control room staffing, control room access, and operator performance during routine operations.
The inspectors conducted random off-hours inspections to ensure that operations and security performance remained at acceptable levels.
Shift turnovers were observed to verify that they were conducted in accordance with approved licensee procedures.
Control room annunciator status was verified.
No deficiencies were observed.
During this inspection period, the inspectors reviewed the tagout (clearance)
on reactor drain pump 2A 2-94-09-068.
No deficiencies were identified.
Technical Specification Compliance Licensee compliance with selected TS LCOs was verified. This included the review of selected surveillance test results.
These verifications were accomplished by direct observation of monitoring instrumentation, valve positions, and switch positions, and by review of completed logs and records.
Instrumentation and recorder traces were observed for abnormalities.
The licensee's compliance with LCO action statements was reviewed on selected occurrences as they happened.
The inspectors verified that related plant procedures in use were adequate, complete, and included the most recent revisions.
During a Unit 1 control room tour conducted at approximately 4:00 p.m. August 29, the inspector noted that the 1AB 4. 16 KV bus was aligned to the 1A3 4. 16 KV bus and that the 1C (swing)
ICW pump was operating in lieu of the lA ICW pump.
The lineup had been made to support maintenance activities in the Unit 1 intake bays.
The 2AB bus was normally aligned to the 1B3 bus and was the source of power for the 1C ICW pump.
During a postulated LOOP, the IA3 bus would be powered by the 1A EDG.
The electrical lineup in question was effected at 1:26 p.m.
on August 2 As documented in IR 94-12, the 1C ICW pump has never been tested for load shedding capabilities when powered with the 1AB bus aligned to the 1A3 bus.
As a result, TS surveillances 4.8. 1. 1.2.e.3.a and 4.8. 1. 1.2.e.5.a, which verified load shedding capabilities in response to LOOP and LOOP/SIAS signals, had never been satisfied.
As these surveillance tests formed part of the bases for lA EDG operability, the operability requirement of TS LCO 3.8. 1..1 was not satisfied when the IAB bus was aligned to the 1A3 bus with the 1C ICW pump operating.
During a postulated DBA involving a loss of offsite power, the ICW pumps were designed to load shed from their respective busses and sequence back onto the busses in 9 seconds.
The design feature was provided to.prevent EDG overload conditions during reenergization of 1E busses.
A failure of an.ICW pump to load shed woul'd have the effect of moving the pump from the 9 second to the 0 second EDG load block, increasing the EDG's starting load.
The inspector questioned the ANPS as to the operability of the lA EDG, given that the 1AB bus was aligned to the 1A3 bus.
The ANPS stated that the electrical lineup in question resulted in 1C ICW pump inoperability and that the pump had been declared inoperable accordingly.
The ANPS stated that the basis for his determination was a Night Order which stated that the pumps powered from the 1AB bus could not be taken credit for when aligned to the 1A3 bus.
A caution tag had been hung on a 1A3-to-lAB breaker handswitch to that affect.
The inspector raised his concern regarding EDG operability to Operations Department management.
After discussions with engineering and other plant personnel, Operations management directed that the 1A EDG be declared inoperable based upon the noted failure to perform required surveillance testing.
The 1A EDG was declared inoperable at approximately 5:00 p.m.,
however the licensee chose to establish the time of inoperability at 1:26 p.m., the time the noted electrical lineup was established.
In response to this issue, the licensee performed an evaluation of 1A EDG performance for the subject electrical.lineup.
As the load shedding capabilities of the 1C ICW pump had never been tested, the analysis assumed that the pump would not load shed, effectively moving the pump to the 0 second load block of the IA EDG.
The licensee found that the combination of the 1A HPSI pump (400 HP)
and the 1C ICW pump (600 HP) alone was enough to exceed the motor starting capability of the EDG, described by Figure 3 of the EDG system DBD as approximately 980 HP.
The licensee subsequently reported that a more detailed evaluation of 1A EDG accident loading
.was being conducted.
The inspector concluded that, in a Night Order dated Hay 3, 1994, the licensee failed to accurately convey to operators the findings of IR 94-12, paragraph 4.d, which stated, in part:
"On Unit 1, the swing pumps have been normally aligned to the B-train safety bus...The inspector...found that the same failure to adequately test load shed capability existed; however, the failure
involved not testing the 1C ICW and CCW pumps when powered from the Unit 1 A-train safety bus.
I
[The failure to properly test the load shedding characteristics of the Unit 2 swing pumps]...resulted in the
EDG not being demonstrated operable for the periods in which the C
ICW pump, was aligned to the B-train safety bus..."
In response to this issue, the licensee generated a new Night Order which correctly described the impact of aligning operating 1AB bus pumps to the 1A3 bus.
The failure to adequately convey operational limitations to control room operators resulted in a recurrence of operating a Unit's electrical plant in a configuration for which EDG operability had not been demonstrated.
At approximately 11:00 a.m.
on August 31, the inspector reviewed the Unit 1 control room log and found the following:
~
An entry, made at 1:26 p.m.
on August 29, described the change in the electric plant detailed above.
At the end of the description, the entry stated "... 1A EDG OOS."
~
An entry, timed at 2:26 p.m.
on August 29, stating
"1C AFW Pump operable, offsite power available, redundant
'B'omponents operable."
As the 1A EDG was declared inoperable at approximately 5:00 p.m.
as a result of the inspectors observations, the inspector questioned control room operators about the log entries (the operators questioned had been on watch when the electrical lineup was changed on August 29).
The operators had no knowledge of the log entries detailed above.
The inspectors discussed the issue with the Operations Supervisor, who stated that the entries were most probably made by the peak shift ANPS on August 29 to reflect the fact that the EDG was declared inoperable.
The Operations Supervisor also stated:
~
The time of EDG inoperability had been declared to be the time when the 1AB bus was aligned to the lA3 bus (1:26 p.m.
on August 29).
~
The entry describing the availability of offsite power supplies and the operability the 1C AFW pump and B side ECCS components had been made to satisfy AS (b) of TS LCO 3.8. 1. 1, which required such checks when an EDG was declared inoperable.
The entry was said to take credit for normal control room walkdowns and log entries in the RCO, control room and out-of-service logs.
~
The method of log entries in this case was not in accordance with site procedure The inspector*discussed the matter with the ANPS who had been on duty during the peak shift on August 29.
The ANPS stated that he did make the log entries in question and that the entries were the result of a discussion with the Operations Supervisor, who had directed the ANPS to make log entries describing inoperability of the lA EDG.
The ANPS stated that his understanding of the Operations Supervisor's directions was that the logs from the day shift of August 29 should be augmented to include the EDG inoperability.
The ANPS stated that, in the course of the discussion, he informed the Operations Supervisor that, if inoperability was taken from 1:26 p.m.,
then the one hour period for completion of AS (b) of TS LCO 3.8.1. 1 had been exceeded.
The ANPS stated that the Operations Supervisor directed that RCO board walkdowns and various control room logs be taken credit for as satisfying the AS, a practice which had been used in the past under similar circumstances.
Finally, the ANPS stated that he had made the noted log entries with hesitation, but believing that the actions were made under the direction of the Operations Supervisor.
The Operations Supervisor acknowledged the discussion, stating that he had directed the ANPS to declare the IA EDG inoperable effective at 1:26 p.m.
on August 29.
The Operations Supervisor stated that it was not his intent that the previous shift's logs be altered and that an apparent miscommunication had existed between himself and the ANPS.
The inspector reviewed the Bases for TS LCO 3.8. 1. 1 which, with regard to the verification of offsite power and component operability required in AS (b) of the LCO, stated:
"The term verify as used in this context means to administratively check by examining logs or other information to determine if certain components are out-of-service for maintenance or other reasons.
It does not mean to perform the surveillance requirements needed to demonstrate the OPERABILITY of the component."
Consequently, the inspector found that the methodology employed for making the 2:26 p.m. log entry of August 29 was in keeping with the TS.
However, the inspector found that the time logged for the activity was misleading both in the statement of when the activity occurred and by whom the activity was performed.
Specifically:
~
The portion of the August 29 1:26 p.m. log entry stating that the 1A EDG was 00S, was misleading in that the EDG was declared OOS at approximately 5:00 p.m. that day.
Further, the entry did not reflect the activities of the day -shift operators.
~
The August'9 log entry of 2:26 p.m., stating that offsite power sources were available and that the 1C AFW pump and redundant B side components were operable, was misleading in that the subject verifications were not performed on that shif In response to this event, the licensee issued a Night Order on August 31 reiterating procedural requirements for maintaining logs chronologically.
The inspector reviewed Administrative Procedure 0010120, Revision 63,
"Conduct of Operations,"
and found that Appendix F covered log keeping.
Section 2 of the appendix stated, in part, "...entries are to be made in chronological order.
Where this is NOT possible, entries shall be preceded by the words Late Entry."
The ANPS's
'actions, relative to the modification of the logs of the previous shift were counter to the requirements in the procedure.
The licensee has scheduled testing of the IAB bus's load shedding capabilities (when aligned to the 1A3 bus) for the upcoming refueling outage.
The inspectors will follow the testing at that time.
The combined issue of IAB bus load shed testing and the noted discrepancies in control room logkeeping will be resolved following the performance of the subject surveillance tests and will be tracked as an unresolved item (URI-94-20-01, IA EDG Operability Concerns and Control Room Logkeeping).
As a result of this issue, the licensee designated a team to review the adequacy of integrated safeguards testing.
The testing is performed each refueling outage and used to satisfy the 18-month EDG surveillance test requirements of TS.
The team will complete this review and incorporate any necessary changes to the Unit
Integrated Safeguards Test procedure prior to the Unit 1 refueling outage, currently scheduled for late October.
Parallel to the licensee's review of integrated safeguards testing, the inspector began a review of selected portions of the test procedure.
With respect to the ICW pumps, the inspector found the following:
~
The licensee's testing, performed in accordance with OP 1-0400050 revision 32, "Periodic Integrated Test of the Engineered Safety Features,"
appeared to adequately test the IA and 1B ICW pump control circuitry as described on schematic diagrams 8770-B-326 sheets 832 (revision 8)
and 833 (revision 7).
~
The licensee's testing per OP 1-0400050 appeared to inadequately test the 1C ICW pump control circuitry as described on schematic diagram 8770-B-326 sheet 834 (revision 7) in the following regards:
- ~
Relay 27X-3 contacts have not been adequately tested for LOOP conditions when the 1C pump is aligned electrically to the IA3 bus.
This is a restatement of the findings of IR 94-12.
The testing of this feature would demonstrate load shedding capabilities of the 1C ICW pump when aligned
to the 1A3 bus and is a requirement of TS 4.8.1.1.2.e.3.b and 4.8.1. 1.2.e.5.b.
~
4YA1 relay contacts, which prevent 1C ICW pump automatic starts under SIAS conditions if the 1A ICW pump is running and the 1C ICW pump. is aligned electrically to the 1A3 bus, have not been tested.
The testing of this feature would assure that a start of a second ICW pump would not occur during the loading sequence of the 1A EDG with the 1C ICW pump aligned electrically to the 1A3 bus under SIAS conditions.
3YA2 relay contacts, which provide for a sequenced 1C ICW start if the 1C ICW pump is operating in lieu of the 1A ICW pump, have not been tested.
The.testing of this feature would demonstrate the automatic sequencing feature of the 1C ICW pump and is a requirement of TS 4 '.1.1.2.e.3.b and 4.8.1.1.2.e.5.b.
Additionally, the inspector noted the following conditions, which were transmitted to the licensee and were being considered in the licensee's ongoing review:
~
The load sequence timing for the 1A and 1B ICW pumps was found to be 9 seconds; the timing for the 1C ICW pump was 10 seconds.
The timing for the 1C ICW pump was selected to bring about a
standby start of the 1C pump upon receipt of a SIAS signal unless the operating (IA or IB)
ICW pump starts first.
The timing tolerance provided for these sequencing times are provided in OP 1-0400050 as +/-
1 second.
The inspector found that this tolerance allowed for an unfavorable stackup which could result in the 1C pump acceptably starting in 9 seconds with the 1A/1B pu'mp acceptably starting in 10 seconds.
As no interlock was provided to prevent a 1A/1B pump start if the 1C pump started first, an unfavorable stackup resulting from setpoint drift could result in two ICW pumps starting nearly simultaneously.
In discussing this issue with the licensee, the inspector was directed to maintenance procedure 1-0910055,
"Periodic Test of Automatic Load Sequence Relays," which provided instructions for testing and setting the time delay relays which provide ICW pump sequencing.
The procedure specified tolerances of.5 seconds which, while more favorable than the tolerances specified in OP 1-0400050, still allowed for identical pump starting times.
~
The inspector noted that, should the lA/1B ICW pump trip following a LOOP/SIAS start, the timing sequence for the 1C pump would begin.
This scenario would lead to
1C ICW pump start 10 seconds after the lA/1B pump trip, effectively adding
a load to another load block.
The EDG's ability to support the load is being evaluated by the licensee.
The inspectors will continue to follow the licensee's review of the adequacy of integrated safeguards testing and will review the licensee's responses to the issues'aised above.
No violation or deviation was identified in the Plant Operations area.
One unresolved was identified:
URI 335/94-20-01, IA Emergency Diesel Generator Operability Concerns and Control Room Logkeeping.
4.
Maintenance and Surveillance (62703, 61726)
a.
Maintenance Observations Station maintenance activities involving selected safety-related systems and components were observed/reviewed to ascertain that they were conducted in accordance with requirements.
The following items were considered during this review:
LCOs were met; activities were accomplished using approved procedures; functional tests and/or calibrations. were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; and radiological controls were implemented as required.
Work requests were reviewed to determine the status of outstanding jobs and to ensure that priority was assigned to safety-related equipment; Portions of the following maintenance activities were observed:
(I)
NPWO 63/2068 HPSI Flow Transmitter Calibrations The inspector witnessed portions of HPSI flow transmitter calibrations conducted August 9.
Work was performed per the noted NPWO and I8C procedure IC I-1400064F revision 29,
"Installed Plant Instrument Calibration (Flow)."
The calibration process required that differential pressures be established with an air source and that transformer output be measured with a milliammeter.
Differential pressure was initially measured with an analog Heise gage with a range of 0-830" H,O and minimum subdivisions of I" H~O.
Technicians performing the calibration exhibited good radiological controls practices and HP involvement with initial swipes and surveys was good.
A number of MME-related problems were experienced during work on the first transmitter.
The first ammeter employed in the process yielded suspect results and was eventually replaced.
The use of a regulated air supply to establish required differential pressures proved difficult to control accurately (due to a lack of sensitivity in the regulator)
and was replaced with a hand pump.
The hand pump
provided the required sensitivity, however the technician controlling pressure stated that the could not read the Heise gage to the required level of accuracy.
The calibration sheet required pressures be established with an accuracy of
. 1" H,O with no tolerances established and the inspector agreed that the minimum subdivision size and denomination made the required level of accuracy impossible to achieve (the inspector estimated the distance between subdivisions of the gage at approximately 1/16").
The technicians then replaced the analog Heise gage with a digital model accurate to
. 1" H,O.
The inspector observed a series of calibration checks with the new test arrangement and found it adequate to the task.
The inspector concluded that the I&C personnel performing the calibration had acted conscientiously in dealing with the METE problems which developed.
However, the inspector found that the difficulties encountered in establishing the required differential pressures could have been prevented in a number of ways:
~
The calibration sheet established a series of required differential pressures which were specified to
. 1" H,O, while the acceptance criteria for transmitter output was in whole milliamps.
Had the differential pressures been expressed in whole inches of water, the analog Heise gage could have been employed for the calibration.
~
The governing procedure specified that required test equipment would be specified on individual calibration sheets.
While the subject sheets described parameters to be measured and ranges required, it did not specify test equipment specifically.
Had the need for a digital Heise gage and a hand pump been specified, several changes in required MME could have been avoided.
~
No tolerances were established for the independent variable (differential pressure).
This forced technicians to conclude that the.analog Heise gage was inadequate to obtain the required accuracy.
While the inspector concluded that the governing procedure had several shortcomings, it was adequate to direct the activities of the I8C personnel performing the c'alibration.
The inspector provided his observations to the IEC Supervisor responsible for the calibration.
(2)
NPWO 63/2403 IA2 SIT Level Loop Calibration Check The inspector witnessed portions of this calibration check, which was initiated when sporadic changes in lA2 SIT level were noticed by operators.
The level transmitter in question had
been previously blown down in containment, where a small amount of water was found in the transmitter's dry reference leg.
The calibration check involved the input of a test signal to the lA2 SIT level versatile circuit and a comparison of input to output.
The inspector verified that HRTE was within its calibration period.
18C personnel performing the calibration check had appropriate procedural guidance on the job scene and performed the test well, with good communications between themselves and control room operators.
The calibration check indicated that the level indicating loop was performing withi,n its calibration specifications.
I&C determined that the observations of the control room operators was most probably due to the water that was found in the transmitter's reference leg.
Wrong Train Near Hiss On September 14, during normal control room rounds, the inspector noted that clearance 1-94-09-050 had been placed on the Unit
RWT suction valve (HV-07-IA) to train A HPSI, LPSI, and CS pumps to permit VOTES testing on the motor operated valve.
Removal of a ECCS train for service is permitted by TS 3.5.2 with a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> AS.
Since the licensee's IPE shows HPSI as the highest risk system, the inspector questioned the need to accomplish this task at power.
He also asked if any precautionary measures had been put in place to protect the remaining ECCS train.
They stated
,
that no additional precautions other than required by TS had been implemented.
The inspector questioned control room operators on their familiarity with their IPE as to which systems were the most critical.
The operators did not appear to be very familiar with the plant's IPE.
The inspector met with the plant manager and discussed operator training on the IPE.
The discussion also covered how and why a decision was made to remove critical systems from service to perform VOTES testing with the unit at power.
The plant manager stated that the plant needed to complete VOTES testing and had accelerated this effort to complete the requirements of NRC GL 89-10.
He also said that an engineering study had been done which showed that the small risk associated with this testing was overshadowed by the overall improvement in safety.
The inspector discussed this study with engineering and found that the study had determined that the testing could be accomplished without a significant increase in risk.
The study had not attempted to prioritize valves and determine if low risk valves should be done at power and high risk valves done during a refueling outag At approximately 10:00 a.m.,
two electricians assigned to partially disassemble the valve met the VOTES testing supervisor at the RWT.
The VOTES testing supervisor had not attended the prejob briefing and was under the false impression that the testing was to be done on HV-07-18 instead of HV-07-1A which is adjacent.
The supervisor pointed out to the electricians that the lock was still attached to the valve's handwheel which would prevent testing of the valve.
The work crew called the control room and requested that an operator remove the lock.
When the operator arrived and compared the valve tag with the electrician's work order, he found that the electricians were starting to work on the wrong valve.
The work which had been started on the valve did not render it inoperable.
The licensee is performing a detailed evaluation of this incident to determine the root cause and required corrective action.
Since this was the second event in the past six months involving electricians, all work involving VOTES testing was stopped until this event could be evaluated and additional controls and training could be accomplished.
This event was a near miss that could have resulted in rendering both trains of ECCS inoperable with the unit at power.
The plant manager and staff appear to realize the significance of this item and are taking corrective actions.
The inspector will monitor these actions as they are completed.
b.
Surveillance Observations Various plant operations were verified to comply with selected TS requirements.
Typical of these were confirmation of TS compliance for reactor coolant chemistry, RWT conditions, containment pressure, control room ventilation, and AC and DC electrical sources.
The inspectors verified that testing was performed in accordance with adequate procedures, test instrumentation was calibrated, LCOs were met, removal and restoration of the affected components were accomplished properly, test results met requirements and were reviewed by personnel other than the individual directing the test, and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
The following surveillance tests were observed:
('1)
OP 1-0700050, REV 44, "Auxiliary Feedwater Periodic Test" The inspector witnessed portions of this surveillance test performed on the 1A and 1B AFW pumps.
NLOs performing the test had appropriate portions of the procedure in hand.
Preoperational checks of the pumps were satisfactory and H&TE used for the test was properly calibrated.
The inspector noted good attention to detail on the part of an NLO in correcting another NLO who had recorded pump suction and discharge
(2)
pressures before the procedurally-required 5 minute run time had been satisfied.
The data was discarded and new data was taken following the 5 minute run time.
The results for both pumps were satisfactory.
OP 2-0400053, REV 18, "Engineering Safeguards Relay Test" The inspector observed the performance of a majority of the semiannual Engineering Safeguards Relay Test on Unit 2 on September 7 and 16.
This surveillance tests the instrumentation and relays for safety injection (SIAS),
Containment
'Spray (CSAS), Containment Isolation (CIAS), Main Steam Line Isolation (MSIS),
and Containment Sump Recirculation (RAS).
This test is considered a load threatening and sensitive test so no other significant tests are conducted at the same time.
In the prejob briefing, the ANPS stressed the prerequisites and precautions associated with the tests.
He clearly defined the
'ssignment of each individual and covered the steps to take if a malfunction or unexpected result should occur.
In addition, the procedural requirements for infrequently performed evolutions and the jumper lifted lead procedure were also reviewed.
The rule for good repeat-back communications was also stressed.
The NPS and IRC supervisor were present during the job briefing and provided oversight and supervision as needed during the test.
This test generally takes eight to ten hours to complete and since other critical tests were also scheduled, it was completed to an appropriate break point and the remainder of the test was scheduled for the following week.
The test went well and all components operated correctly.
Two temporary procedure changes had to be initiated due to equipment out-of-service and/or plant conditions.
These were correctly processed.
Overall, the test crew, operations, and ISC maintenance displayed teamwork, excellent communications, and good procedural compliance during the test.
The inspector did identify that on several instances the ANPS directed the operators to restore equipment in a different sequence than shown in the procedure.
This is permissible but could result in a step being missed.
The licensee agreed to review these steps and incorporate human factors improvements as needed.
The inspector also identified that six test pushbuttons in actuation cabinets had been labelled with a marking pen.
ILC submitted PMOs 94013863 and 94013921 to have permanent labels made and installe (3)
OP 1-1200054, REV 19, RAB Fluid Systems Periodic Leak Test The inspector accompanied engineers of the licensee's Technical Staff during inspections of selected Unit 1 fluid systems during system operation.
The inspections were targeted at the early identification of leaks.
The inspector observed the preparations for a LPSI walkdown, which included walking down the system beforehand to identify all accessible piping runs and a delineation of responsibilities among the 3 engineers involved.
Inspections were carried out expeditiously, with good ALARA practices displayed.
The inspections were successful in identifying a number of minor packing and union leaks.
The inspector found this practice to be noteworthy in its potential for early identification of failures in fluid system integrity and to control contamination.
c.
Licensee Action on Previous Haintenance Findings (92902)
(Closed)
IFI 50-335,389/92-05-01, Seismic gualification of Racked Out Circuit Breakers This IFI had been initiated in response to an inspector observation on Harch 9, 1992, of a 1B ICW breaker that was removed from its switchgear housing and was sitting unrestrained in front of other safety-related switchgear.
The inspector reviewed the licensee's REA 92-104, 4KV Circuit Breaker Seismic Condition in Racked Out Position, dated Harch 10, 1992, and the related engineering evaluation, JPN-PSL-SECS-92-012, Seismic gualification of 4KV Switchgear with Breakers in the Racked Out Position, dated August 19, 1992.
The engineering evaluation concluded that racked-out breakers will not adversely affect the seismic qualification of the 4KV switchgear or introduce any seismic interaction concerns.
The inspector found the evaluation to be timely, detailed, and reasonable.
The engineering evaluation did not address breakers that were removed from their switchgear housing.
The inspector discussed this with the electrical maintenance department head who stated that, in response to this issue, maintenance department expectations that any removed breakers be stored away from the front of safety-related switchgear had been stressed to electrical maintenance personnel.
The inspector toured safety-related electrical switchgear rooms and found several removed breakers stored in the corner of a switchgear room and no removed breakers in front of safety-related switchgear.
This item is closed.
No violation or deviation was identified in the Haintenance and Surveillance are.
Engineering (37551)
Licensee Action on Previous Engineering Findings (92903)
(Closed)
IFI 50-335,289/92-20-01, Heat Load Calculations and Resultant FSAR Changes This IFI was opened to follow NSSS vendor containment analysis heat load calculations that were due to be completed by December, 1992, and subsequent FSAR changes.
The inspector reviewed the heat load calculations and verified that they were in the Unit 1 and Unit 2 FSARs.
The inspector also reviewed the licensee,'s engineering evaluations JPN-PSL-SENP-93-017 and JPN-PSL-SENP-93-018, St.
Lucie Units 1 L 2 Safety Evaluations for the Updated LOCA Containment Analysis, dated April 29, 1993.
The inspector found the engineering evaluations to be adequate.
This item is-closed.
No violation or deviation was identified in the Engineering area.
6.
Plant Support (71750)
a.
Fire Protection During the course of their normal tours, the inspectors routinely examined facets of the Fire Protection Program.
The inspectors reviewed transient fire loads, flammable materials storage, housekeeping, control hazardous chemicals, ignition source/fire risk reduction efforts, fire protection training, fire protection system surveillance program, fire barriers, fire brigade qualifications, and gA reviews of the program.
No significant deficiencies were noted.
b.
Physical Protection The inspectors verified by observation during routine activities that security program plans were being implemented as evidenced by:
proper display of picture badges; searching of packages and personnel at the plant entrance; and vital area portals being locked and alarmed.
No deficiencies were identified.
C.
Radiation Protection The inspectors verified that HP policies and procedures were being followed.
This included routine observation of HP practices and a
review of area radiation survey, RWPs, postings, and equipment operation.
No deficiencies were identifie d.
Licensee Action on Previous Plant Support Findings (92904)
(Closed)
IFI 50-335,389/94-04-02, NRC observation of a site accountability drill in 1994.
The senior resident inspector and a regional emergency preparedness inspector observed the licensee's site accountability drill conducted on September 30, 1994.
The drill was initiated from the control room with a drill message for an alert.
The TSC and OSC were activated while nonessential personnel reported to staging areas outside the protected area.
At the site area emergency level, personnel evacuated the owner controlled area (in reality the personnel left the site with shift completion which approximately coincided with the SAE).
The drill was well controlled and met the designated objectives.
The inspectors determined an adjusted time for site accountability of approximately 39 minutes considering the time for exiting the protected area, security providing the list of personnel reported to be on site and the cross checking of the list with facility accountability forms.
The accountability identified three.personnel as unaccounted, one of which was a controlled input.
The drill was considered to be on the outer edge of meeting the desired approximately 30 minutes.
Improvements to the system were discussed that should result in better times.
This item is closed.
No violation or deviation was identified in the Plant Support area.
7.
Other Areas Evaluation of Licensee Self Assessment (40500)
The inspectors attended two FRG meetings during the inspection period.
On September 6, the FRG reviewed six procedure changes, an instruction manual change, one temporary change, and a plant change/modification.
Two of these items were returned to the presenter for.additional improvement and/or clarification.
The meeting was conducted in a professional manner and the plant manager gave explicit comments on his expectations of quality for plant procedures.
On September 8, the FRG discussed a planned PC/H for ten HFA relays and several procedural changes.
A construction group procedure discussed at the previous days FRG was again sent back for further rework to ensure that it provided the same guidance used by plant maintenance to perform essentially the same task.
The plant manager again reiterated his expectations for all plant construction procedures.
No violation or deviation was identified.
8.
Exit Interview The inspection scope and findings were summarized on September 30, 1994, with those persons indicated in paragraph I above.
The inspector described the areas inspected and discussed in detail the inspection
results listed below.
Proprietary material is not contained in this report.
Dissenting comments were not received from the licensee.
Item Number 335/94-20-01 Status open Descri tion and Reference URI - IA Emergency'Diesel Generator Operability Concerns and Control Room Logkeeping, paragraph 3.c.
335,389/92-05-01 closed 335,289/92-20-01 closed 335,389/94-04-02 closed IFI - Seismic gualification of Racked Out Circuit Breaker, paragraph 4.c.
IFI - Heat Load Calculations and Resultant FSAR Changes, paragraph 5.
IFI -
NRC Observation of Site Accountability, paragraph 6.d.
Abbreviations, Acronyms, and Initialisms AC AFW AFWS ALARA ANPS AP AS ATTN CCW CFR CIAS CS CSAS CW DBA DBD DC DEH DPR ECCS EDG FPL FRG FSAR GL HFA, HP HPSI IKC ICW IFI IPE Alternating Current Auxiliary Feedwater (system)
Auxiliary Feedwater System As Low as Reasonably Achievable (radiation exposure)
Assistant Nuclear Plant Supervisor Administrative Procedure Action Statement Attention Component Cooling Water Code of Federal Regulations Containment Isolation Actuation Signal Containment Spray (system)
Containment Spray Actuation System Circulatory Water Design Basis Accident Design Basis Document Direct Current Digital Electro-Hydraulic (turbine control system)
Demonstration Power Reactor (A type of operating license)
Emergency Core Cooling System Emergency Diesel Generator The Florida Power
& Light Company Facility Review Group Final Safety Analysis Report
[NRC] Generic Letter A GE relay designation Health Physics High Pressure Safety Injection (system)
Instrumentation and Control Intake Cooling Water
[NRC] Inspector Followup Item Individual Plant Examination
IR KV LCO LER LOCA LOOP LPSI M&TE MOV HSIS HV NLO No.
NPF NPS NPWO NRC NSSS OOS OP OSC PC/H PWO gA RAB RAS RCO REA Rev RII RWP RWT SAE SIAS SIT St.
[NRC] Inspection Report KiloVolt(s)
TS Limiting Condition for Operation Licensee Event Report Loss of Coolant Accident Loss of Offsite Power Low Pressure Safety Injection (system)
Measuring 5 Test Equipment Motor Operated Valve Hain Steam Isolation Signal Motorized Valve Non-Licensed Operator Number Nuclear Production Facility (a type of operating license)
Nuclear Plant Supervisor Nuclear Plant Work Order Nuclear Regulatory Commission Nuclear Steam Supply System Out of Service Operating Procedure Operations Support Center Plant Change/Mocification Plant Work Order equality Assurance Reactor Auxiliary Huilding Recirculation Actuation Signal Reactor Control Operator Request for Engineering Assistance Revision Region II - Atlanta, Georgia (NRC)
Radiation Work Permit Refueling Water Tank Site Area Emergency Safety Injection Actuation Signal Safety Injection Tank Saint Turbine Cooling Water Technical Specification(s)
Technical Support Center UFSAR
[NRC] Unresolved Item Valve Operation Test Evaluation System