IR 05000335/1995010
| ML17228B214 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 06/23/1995 |
| From: | Landis K, Prevatte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17228B213 | List: |
| References | |
| 50-335-95-10, 50-389-95-10, NUDOCS 9507120115 | |
| Download: ML17228B214 (40) | |
Text
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Cy oO UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARINASTREET, N.W., SUITE 2900 ATLANTA,GEORGIA 303234199 Report Nos.:
50-335/95-10 and 50-389/95-10 Licensee:
Florida Power 8 Light Co 9250 West Flagler Street Hiami, FL 33102 Docket Nos.:
50-335 and 50-389 License Nos.:
DPR-67 and NPF-16 Facility Name:
St.
Lucie 1 and
Inspection Conducted:
April 30 through June 3, 1995 Lead Inspector:
R. Prevatte, Senior Resident Inspector R. Baldwin, License Examiner H. Hiller, Resident Ins tor Da e Signed Approved by:
K. Landi
,
C ie Reactor rojects Section 2B Division of Reactor Projects SUHHARY te signed Scope:
Results:
This routine resident inspection was conducted onsite in the areas of plant operations review, maintenance observations, surveillance observations, engineering support, plant support, and other areas.
Inspections were performed during normal and backshift hours and on weekends and holidays.
Plant operations area:
System walkdowns identified missing identification labels and operator aids, procedural weaknesses, and drawing errors.
A review of clearances also identified several administrative errors.
A deficiency involving the lack of filter maintenance on the reactor building and emergency core cooling system pump room ventilation system was also identified, paragraph 3.a.4)B.(2).
Individually, these errors were not safety significant.
However, they indicate a
lack of attention to detail.
Overall performance continued to be satisfactory
'P507i20ii5 950623 PDR ADOCK 05000335
Haintenance and Surveillance area:
Several weaknesses involving procedures and strict procedural compliance were identified during online maintenance activities.
Discrepancies involving the tracking of electrical maintenance training and qualification were also identified, paragraph 4.a.3)C.
A weak surveillance tracking system for emergent surveillances resulted in a non-cited violation for missing several surveillances on diesel generator 18, paragraph 4.b.4).
Engineering Support:
Completion of the review for Anticipated Transient Without a Scram (Temporary Instruction 2500/020)
found that the licensee had installed and implemented an approved design, paragraph 6.a.
Plant Support area:
Performance in this area continued to be satisfactory.
Within the areas inspected, a non-cited violation was identified involving a missed surveillance:
NCV 335/95-10-01,
"Hissed Surveillance on 18 Emergency Diesel Generator",
paragraph 4.b.4).
REPORT DETAILS 1.
Persons Contacted Licensee Employees R. Ball, Mechanical Maintenance Supervisor W. Bladow, Site guality Manager L. Bossinger, Electrical Maintenance Supervisor H. Buchanan, Health Physics Supervisor C. Burton, St.
Lucie Plant General Manager 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 K. Heffelfinger, Protection Services Supervisor J. Holt, Plant Licensing Engineer G. Madden, Plant Licensing Engineer J.
Harchese, Maintenance Manager W. Parks, Reactor Engineering Supervisor C. Pell, Outage Manager L. Rogers, Instrument and Control Maintenance Supervisor D. Sager, St.
Lucie Plant Vice President J. Scarola, Operations Manager D. West, Technical Manager J.
West, Site Services Hanager C.
Wood, Operations Supervisor W. White, Security Supervisor Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personnel.
NRC Personnel R. Baldwin, Reactor Examiner, Region II H. Hansik, Non-Power Reactors and Decommissioning Projects Directorate, NRR H. Miller, Resident Inspector J. Norris. St Lucie Project Manager, NRR B. Parker, Radiation Specialist, Division of Radiation Safety and Safeguards, NRC, Region II R. Prevatte, Senior Resident Inspector S. Reynolds, Environmental Review Project Di.rectorate, NRR S. Sandin, Senior Operations Officer, AEOD S.
Y. Jang, Korea Institute of Nuclear Safety
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragrap.
Plant Status and Activities a ~
b.
C.
Unit 1 operated at essentially 100 percent power for the inspection period.
Unit 2 began the inspection period at 100 percent power.
On Hay 22, power was reduced to approximately 65 percent to permit turbine valve testing and condenser sea water side cleaning (shake and bake).
These activities were completed and the unit returned to full power on Hay 23.
NRC Activity Hr.
R. Baldwin, Reactor Examiner, NRC, Region II, assisted the resident inspectors during the week of Hay 1.
His inspection results are contained in this report.
Hr. J. Norris, St.
Lucie Project Hanager, NRR, visited the site on Hay 23 through Hay 26.
He attended the NRC, FPL, NHFS, FDEP Environmental Consultation meeting that discussed sea turtle intake on Hay 23, toured the site and held several informal meetings on current issues and schedules with the licensee.
Hr. S.
Reynolds, Environmental Review Project Directorate, NRR, and Hr. H. Hasnik, Non-Power Reactors and Decommissioning Projects Directorate, NRR, visited the site on Hay 23 and met with the licensee, NHFS, and FDEP for consultation on the current status of sea turtle intake.
Hr. B. Parker, Radiation Specialist, Division of Radiation Safety and Safeguards, NRC Region II, conducted onsite inspection during the week of Hay 29 in the health physics area.
The inspection results are reported in IR 335,389/95-11.
Hr. S.
Y. Jang, Foreign Assignee from Korea (KINS) reported to the site on Hay 30 for "hands on" training in NRC inspection techniques.
He is assigned to the site until June 22, 1995.
3.
Plant Operations a ~
Plant Tours (71707)
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 appropriate radiation controls were properly established, critical clean areas were being controlled in accordance with procedures, excess equipment or material was stored properly, and combustible materials and debris were disposed of expeditiously.
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 calibration dates.
Some tours were conducted on backshifts.
The frequency of plant tours and control room visits by site management was noted.
The inspectors routinely conducted main flow path walkdowns of ESF, ECCS, and support systems.
Valve, breaker, and switch lineups as well as equipment conditions were randomly verified both locally and in the control room.
The following accessible-area ESF system and area walkdowns were made to verify that system lineups were in accordance with licensee requirements for operability and equipment material conditions were satisfactory:
1)
Units
and 2 Hydrogen Purge System.
All valves and breakers were found to be in the correct position for mode 1.
The following is a listing of drawing, procedural, equipment labelling, and miscellaneous deficiencies identified to the licensee for correction:
A.
Control Room (1)
The nameplate for CNTNT PURGE REFUEL DAMPER has no damper or associated control power fuse identification.
B.
Reactor Auxiliary Building (1)
Nameplates do not match descriptions in OP 1-2000023, Rev 7, for Ckt 27 (120VAC PP-101),
Ckt 27 (120VAC PP-102),
Ckt 5 and Ckt 24 (120VAC PP-103).
(2)
OP 1-2000023, Rev 7, for Ckt 5 (120VAC PP-103)
identifies HE-25-3 as Humidity Recorder.
Review of CWD and installed equipment confirmed that the instrument referenced is indication only, i.e., HI-25-3.
A PCR was submitted by operations to correct this deficiency.
(3)
Ckt identification missing for Ckt 24 (120VAC PP-101),
Ckts 17, 35,
(120VAC PP-102).
The circuits have since been labeled properly.
C.
Reactor Auxiliary Building - Fan Room (1)
OP 1-2000023, Rev 7, positions FCV-25-9 and FCV-25-10 partially open prior to system operation.
Both valves were verified fully open.
This was the result of the operability run alignment, which positioned the valves fully opened.
The inspector discussed the issue with operations personnel who stated that the
post-operability test alignment constituted the system's
'standby'ineup and that a realignment would be required per section 8.2 of the subject procedure prior to operation.
The inspector found this method of system alignment unclear.
2)
Unit 2 Continuous Containment/Hydrogen Purge System A.
Control Room (1)
ONP 2-0030131, Rev 48, "Plant Annunciator Summary" listed Point
on TR-25-3.
From CWD 480, point 1 was TE-25-56 (before HEPA filter), which was not an input for Annunciator X-l, "Contns Cntmt/H2 Purge Air Temp Hi".
Operations submitted a
PCR to correct this deficiency.
(2)
ONP 2-0030131, Rev 48, "Plant Annunciator Summary,"
for Annunciator X-17 "H2 Purge Fans Flo Lo/Ovrld":
a)
Incorrectly identified purge fans as HVE-71/17B rather than 17A/17B.
Operations submitted a
PCR to correct this deficiency.
b)
Did not indicate 10 second time delay in the setpoint column as shown for other annunciators.
This item was under investigation at the close of the inspection period.
(3)
Engineering Drawing 2998-G-879 Sh 3 (HVAC-Control Diagrams-Sheet 3):
a)
b)
c)
Time delay associated with FS-25-17B was
seconds rather than 10 seconds as shown on CWD 486.
A Change Request Notification (JCN)
was submitted to JPN to correct this item.
Interlock for FCV-25-26 was not shown.
This item was under investigation at the close of the inspection period.
FF-25-1-1 shown on the above drawing was not on the instrument list.
A Change Request Notification was submitted for correction.
(4)
OP 2-2000023, Rev 14,
"Continuous Containment/Hydrogen Purge System Operation":
a)
Valve alignment specified in step 4 of Appendix A listed the position of FCV-25-29 and FCV-25-34 as closed.
These are Locked Closed valves using keys 95 and 96, respectively.
A PCR was generated to correct this ite b)
c)
d)
Opening and adjusting FCV-25-9, specified in step 6 of Appendix A, required the operator to observe flowrate on FR-25-2 or FI-25-1.
Indicator referenced in procedure should have been FI-25-1-1.
A PCR was being generated.
The NOTE following FCV-25-26 and FCV-25-36 valve alignments in step 4 of Appendix A stated
"Momentarily, place switch in open.
Valve will not open until HVE-7A pr 7B starts and negative differential pressure exists in Containment".
Step 2 of Appendix B opened these valves.
Step 8 tasked the operator with verifying that these valves were open when either HVE-7A or 7B started.
Operations confirmed that step 2 is required to makeup an electrical interlock, however, Appendix B did not have this NOTE.
There was no reference to which instrument should be used in step 9 of Appendix B to maintain a hydrogen purge rate of approximately 100 CFM.
A PCR was to be generated to correct this item.
B.
Reactor Auxiliary Building - Electrical (1)
Nameplates did match descriptions for switches and breakers in OP 2-2000023, Rev 14, for FCV-25-35, FCV-25-28, FCV-25-9 and Breaker 2-HVE-7.
Operations prepared a
STAR to EH to resolve the breaker and switch list discrepancies.
C.
Reactor Auxiliary Building - Fan Room (1)
No nameplate existed for local indication on the Continuous Containment/H2 Purge Humidity instrument.
A nameplate was placed on order.
D.
Reactor Auxiliary Building -
HVAC Enclosure through Door 245.
(1)
A light bulb in the entry way was burned out.
EH was notified of this deficiency.
(2) It was impossible to verify instrument air pressure on 'FCV-25-26 without a ladder.
The gage was installed approximately 9 ft above the floor facing upward and could not be visually checked on routine operator rounds.
The above discrepancies, though lacking in significance individually, indicated that additional attention was needed to ensure procedural accuracy and adequac )
Unit 1 Reactor Auxiliary Building/ECCS Area Ventilation A.
Control Room (1)
OP 1-1900020, Rev 11, "Reactor Auxiliary and Control Room Ventilation System Operation:"
Did not perform or reference an initial breaker/switch alignment.
(2)
ONOP 1-0030131, Rev 59, "Plant Annunciator Summary:"
a)
b)
c)
Incorrectly identified HVE-12 as HV-12 in column 3 of P-13.
Did not list CWD 477 as a reference for TS-25-9 of P-13.
Setpoints for annunciators P-33, P-43, P-53, P-34, P-44 and P-54 did not list the 10 second time delay associated with the respective FS.
(3)
Nameplates for HVS-4A, HVS-4B, HVE-10A and HVE-10B did not have AUTO mode identified.
(4)
Control Board SIAS donuts missing on HVE-10A and HVE-10B.
(5)
Engineering drawing 8770-G-879, Rev 26 (HVAC-Control Diagrams-Sheet 2) identified TE 25-22 and TE-25-23 as associated with pump rooms A 5 B.
Recorder TR 25-1 points 16 5 17 did not identify which TE supplies input to which data point.
B.
Reactor Auxiliary Building - Electrical (1)
Breaker nameplates were worded differently between A
and B trains for HVS-4A and HVS-4B C.
Reactor Auxiliary Building - Fan Room (1)
HVE-10A Fan Housing to Plenum connection on West side had an air leak.
(2)
HVE-9A flexible boot on the fan housing to duct connection had a small tear.
4)
Unit 2 Reactor Auxiliary Building/ECCS Area Ventilation A.
Control Room (1)
OP 2-1900020, Rev 5, "Reactor Auxiliary and Control Room Ventilation System Operation" did not contain or reference an initial breaker/switch alignment.
(2)
ONOP 2-1900030, Rev 17, "Reactor Auxiliary Building, Diesel Generator Building and Control Room
(3)
(4)
(5)
Ventilation, " step 7. 2,
"CONTINGENCY ACTIONS, " 1. B refers to TS Section 3.7.81, typographical error.
ONP 2-0030131, Rev 48, "Plant Annunciator Summary,"
listed
"ENG SFGD PP RH 2A/2B TEMP HI" (Annunciator W-21) setpoint as 150'F.
CWD ¹483 and Engineering Drawing 2998-G-879 Sh 2 show setpoint as 110'F.
Control board SIAS donut missing on ECCS Isolation Damper D9A.
Engineering Drawing 2998-G-879 Sh 2 location G-11 showed TE 25-4 vice TE 25-41, typographical error.
B.
Reactor Auxi 1 iary Bui1 ding - Fan Room HVE-10B access port clamp (1) loose.
(2)
Filters for HVS-4A/B not maintained.
The Inspectors accompanied the System Engineer and HP during entry into the normally locked RAB air intake room.
The overall condition of the bag filters was poor.
The inspector requested documentation of the required and completed maintenance and surveillance for the filters.
The System Engineer provided a summary sheet for the HVS-4 and 5 Filters with attachments that revealed the following:
As early as February 14, 1990, licensee purchasing received a letter from the filter manufacturer (AHPROG) recommending wholesale replacement of the filters, as they would no longer be manufactured.
Procurement Engineering received this letter in 1993 as part of a bid response.
Haintenance withdrew 36 filters from stores on Hay 12, 1993.
Since this reduced stock below minimum, inventory material management initiated a request for a quote on Hay 24, 1993.
The filter distributor (Leonard Designs, Inc.)
responded to the request for quotation indicating that the NS line of filters was no longer available.
Procurement Engineering initiated the normal obsolescence process July 1993 to identify and procure an acceptable replacement.
Two additional inter-office letters were sent on June 9 and October 26, 1994, from Plant Support to Corporate Site Engineering requesting assistance in identifying suitable replacement filters.
As a result of excessive dirt accumulation on the filters, engineering performed an evolution which determined that the filters and system was still operable.
The
licensee anticipates that the filters will be replaced by mid July.
The review of this problem also found that two Maintenance Procedure Change/Review Requests for gI 5-PR/PSL-1,
"Mechanical Maintenance Safety-Related Preventative Maintenance Program,"
were partially processed on March 9, 1993, and March 1, 1994, to include a quarterly inspection of the filters for Unit 2.
Neither of these changes had been issued.
The current revision of this procedure did not contain any filter inspection r equirement.
Maintenance has stated that this procedure will be updated and implemented by mid July.
The above system walkdown discrepancies were provided to the Operations Supervisor.
He, in turn, noted that the identified items may indicate a weakness involving procedures and maintenance on the ventilation systems.
He stated that operations procedures dealing with ventilation systems will be evaluated, including:
Verifying initial lineup procedures are adequate to ensure operability prior to mode change.
Verifying procedures, normal and off-normal, are technically correct.
Verifying labeling, in the control room and the plant, is consistent with procedures.
Verifying that operator aids, such as main control board safeguards doughnuts, are properly placed.
Walking down system to identify any material condition or degraded or failed equipment problems.
The expected completion date for the above is August 1,
1995.
The walkdown of the RAB/ECCS Ventilation Systems verified that lineup was correct for the current mode/condition.
The licensee response to the list of deficiencies was appropriate and will be followed up by the Inspectors.
The HVS-4 filter deficiency was problematic in that it:
Demonstrated that although the issue of replacement filters was recognized early on, the licensee's followup was ineffective in resolving the problem.
Revealed that the maintenance program for inspection of the filters was not implemented due to the licensee's inability to procure a suitable replacement.
These weaknesses need to be addressed by the licensee.
The licensee is conducting an investigation into the history of the maintenance performed in this area and will provide the results to the inspectors for evaluatio b.
Plant Operations Review (71707)
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, night 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.
The following deficiencies were identified:
1)
Reviewed CNN PSA Evaluation HRA-95-008.
This assessment was used to determine the increase in core damage frequency due to removal of A train ECCS system for online maintenance.
The HPSI, LPSI and Core Spray train A components were removed from service.
The assessment found the increase in core melt potential was well below the allowed limit.
The inspector questioned operators concerning the work on the Unit 2 ECCS "A" components.
The operators appeared familiar with the work but did not appear to be familiar with the use of PRA/IPE in evaluating online maintenance and entry into an LCO AS.
Operations training in this area is scheduled to be completed in June 1995.
C.
2)
A review of Unit 2 Control Room Deficiency Log identified that tag 95-006495 was attached to Channel D SG 2A pressure gage but there was no paperwork associated with this PWO in the deficiency log.
The SCRO, when questioned, looked up the PWO on the computer.
He found that the tag on PI-8013D (pressure gage)
should have been placed on pressure recorder PR-8013D.
The SCRO moved the tag to the proper recorder and corrected the Control Room Deficiency log sheet.
3)
Reviewed the Unit 1 L 2 Control Room Discrepancy Log and the Night Order Book.
It was noted that each document in each of these books has a grid pattern that allows for signature of operators for review.
These signatures were not being done consistently.
An operator told the inspector that this grid was not required to be signed because it is redundant to the turnover sheet which is signed by the operators and the requirements for signature are on the turnover sheet.
This appears to be operations general policy.
Plant Housekeeping (71707)
Storage of material and components, and cleanliness conditions of various areas throughout the facility were observed to determine
whether safety and/or fire hazards existed.
The plant continues to paint and upgrade appearance in preparation for th'e June INPO evaluation.
No violations or deviations were identified.
d.
Clearances (71707)
During this inspection period, the inspectors reviewed the following clearances:
1)
Unit
a)
Clearance 1-95-04-093 (HV-09-13 Hotor Valve for AFW Pump 1A Discharge X-Tie to S/G 1B TRSL/21/n-T5/W-TA).
All tags were found to be in place and the components were correctly positioned.
Three Danger Tags were issued; two for breakers at HCCs and one on a handwheel for an HOV.
All three tags were signed and verified at 1630, 1635 and 1638 hours0.019 days <br />0.455 hours <br />0.00271 weeks <br />6.23259e-4 months <br /> on April 20, 1995.
The clearance order authorized the tags at 2020 hours0.0234 days <br />0.561 hours <br />0.00334 weeks <br />7.6861e-4 months <br /> on the same date with the positioned and tagged times of 2030, 2035 and 2038 hours0.0236 days <br />0.566 hours <br />0.00337 weeks <br />7.75459e-4 months <br />.
These times were also verified.
The ANPS was informed of the discrepancy which was corrected by the operator on the tags using a single line-out, initials and entering the time recorded on the clearance.
The operator stated that he sometimes had problems with 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> time.
b)
Clearance 1-95-03-046 (FCV-25-2 Isol Vlv (Penetr P-11) for HV Containment Purge Supply RCB/33/S-58/E-43).
One Danger Tag was issued and a fuse had been removed as required.
No discrepancies were noted.
c)
Clearance 1-95-05-025 (D-3 Damper on Supply Register for Containment Spray Pump 1B Room RAB/15/S-RA2/RA).
One Danger Tag was issued for an HCC breaker.
It was in place and the breaker was in the correct position.
Step 83 required repositioning the breaker maintenance/bypass switch to the "maintenance test" position after the breaker was opened.
There was no associated Danger Tag issued for this switch repositioning.
According to one of the Unit 2 SROs, the switch was not part of the electrical isolation and served only to ensure that when the clearance was removed and the breaker was repositioned
"on".
Power would not be available to any loads until the maintenance/bypass switch was repositioned to "normal/bypass."
This strategy used the clearance procedure as a means of sequencing or controlling the manner in which electrically isolated components were reenergized without the use of danger tags.
The argument made was that with the breaker open,
the position of the maintenance/bypass switch was irrelevant since there was no hazard to personnel or equipment.
However, a safe work practice to follow when closing breakers is to have this switch in the
"maintenance test" position, close the breaker, then reposition the switch to "normal/bypass position."
This practice appeared to be more of an electrical lineup or sequencing rather than procedure for work isolation.
2)
Unit 2 a)
b)
c)
Clearance 2-95-05-015 (TCV-2223 Temp Control Valve for Letdown Heat Exch Disch (CC System)
RAB/21/S-RAIZ/W).
Two Danger Tags were issued; both for valves.
On the Equipment Clearance Order, item ¹7 (IV Required)
was checked.
Tag No.
1 for SB14254 Bypass Valve had a
required position as throttled with the I.V. space
"N/A"d.
An SRO in the Unit 1 Control Room stated that item ¹7 of the Equipment Clearance Order should have been annotated next to the "IV Required",
"applies to Tag No.
2 only."
The inspector agreed with this conclusion and found all tags and components correctly positioned.
Clearance 2-95-04-067 (Cont 02 Anlyzr Continuous Oxygen Analyzer Assembly RAB/20/N-RA2/E-RA).
One Danger Tag was issued for a mode switch and was verified to be in place.
No discrepancies were noted.
Clearance 2-95-05-022 (V23114 Primary Root Valve for PI-23-1A RAB/51/N-RA2/E-RA).
Nine Danger Tags were issued; two for fuses removed on the RTGB and seven for isolation of vent and drain valves.
No discrepancies were noted.
3)
General Remarks a)
b)
OP 0010122, Rev 58, Instruction 8.5, step 2 required that
"An up-to-date index (similar to Figure 6) shall be maintained in the log."
The inspector examined the index on Hay 9 and found that index for Unit 1 Working Equipment Clearance Order Log was dated Hay 5, 1995 and did not include clearances issued between Hay 5 and Hay 9.
The index for Unit 2 Working Equipment Clearance Order Log dated Hay 9, 1995 did not list open Clearance 2-95-04-067 (Cont 02 Anlyzr Continuous Oxygen Analyzer Assembly RAB/20/N-RA2/E-RA) which was issued on April 20, 1992.
The effective date listed in Index was not consistent with all clearances, i.e., in some cases it was the authorization date which differed from the issued-to date,
in other cases it was the issued date, and in a few cases it was the positioned and tagged date.
c)
The locator code used in items of the Equipment Clearance Orders (Fig 2) was incomplete, e.g.,
tag showed
"RAB/30/S-RAIZ/W-R" instead of "RAB/30/S-RAIZ/W-RAE."
The clearance SROs stated that the computer data field is limited and would not accept additional characters.
d)
A large number Equipment Clearance Orders did not contain the NPWO number.
OP 0010122, Rev 58, Instruction 8.3, step 8 required that the NPWO number and the clearance holder(s)
name(s)
be printed and that the clearance holder sign to signify acceptance of the clearance prior to commencement of work.
It also required that the date and time of day the clearance is accepted be indicated.
The above deficiencies again indicate a lack of strict attention to detail in the area of procedural compliance.
e.
Technical Specification Compliance (71707)
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'as 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.
No deficiencies were identified.
4.
Haintenance and Surveillance
'a ~
Maintenance Observations (62703)-
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:
NPWO 63/3555 - Replace assembly
¹1 CEDM ¹56 power supply 12D This power supply is part of a dual unit auctioneered power supply. 'eplacement of this component was accomplished under the control,s of AP 0010142, Rev 12, "Unit Reliability and Manipulation of Sensitive Systems" and MP l-IHP-66.02, Rev 1,
"Replacement of Auctioneered Power Supply in CEDH Power Cabinet."
The inspector observed the prejob briefing conducted in the control room and the work activities at the power cabin'ets.
The test equipment was calibrated and the task was performed without incident.
The technician's work efforts were directed by an IKC engineer.
Both individuals were very knowledgeable of the procedural requirements and work practices needed to accomplish this task.
No deficiencies were identified.
NPWO 66/0992
- Troubleshoot and repair Unit 2 reactor trip breaker TCB-1.
This breaker could not be closed after being tripped during RPS testing.
This NPWO directed removal of the breaker, a physical inspection for damage and mechanical manipulation to verify freedom of movement of mechanical parts.
This was followed by electrical continuity checks and manually cycling the breaker.
No deficiencies were identified.
Since operation with this component removed increased the potential for a plant trip, a decision was made to replace the breaker with one from stores.
A spare was obtained, calibrated, tested, installed and returned to service.
The inspector witnessed these activities, verified that appropriate procedures were used, that test equipment was calibrated, and that engineering support and supervision was provided as needed.
This task was accomplished in a timely manner without incident.
The removed breaker was still being analyzed to determine the cause of failure at the end of the reporting period.
Unit 2 conducted a two day online maintenance outage on Unit 2 train B
ECCS components on Hay 14 through May 16.
These work activities were scheduled and performed under the licensee's procedure AP 0010460, Rev 2, "Critical Maintenance Management Procedure."
This procedure was recently implemented and evaluated the risk of accomplishing, work activities online and included strict controls over the remaining ECCS train.
The procedure also provided for added management and supervisory oversight to ensure that the work was accomplished in a timely manner.
The following activities were observed:
A.
The prejob briefing conducted in the TSC at 7:15 am on Hay 15, for craft and supervisory personnel working on the CMH activities.
This meeting started at 7: 15 am and lasted
approximately ten minutes.
The shift CMM director covered all work activities that were underway or planned for the shift.
He covered existing problems, priorities, and identified key personnel available to provide assistance if needed.
The inspector felt that he did a good job in this briefing.
However, the inspector noted that a large number of craft personnel were late for the briefing and some showed up near the end of the briefing.
It was also noted that only one question was asked out of about thirty people present.
Several of the people did not appear interested in the briefing.
This was discussed with plant management immediately after the prejob briefing.
PWO 62/4160
- Locate and repair leaking tube on 2B CCW HX.
This work involved isolating and draining of the HX; removing the end covers; cleaning as needed; locating and plugging the leaking tube(s);
and reassembling and returning the HX to service.
The majority of these activities were completed and the cover bolts were being torqued when the inspector arrived at the work site.
The inspector verified that the bolts were torqued to the correct value with a calibrated torque wrench.
A review of the paperwork by the inspector found that only the first four steps of this work procedure were signed off at the completion of work.
The inspector was assured that the required steps in the maintenance procedure had been performed.
When questioned, the work personnel signed off all applicable portions of the procedure.
This item was discussed with the job foreman who stated that the master copy of the paperwork was back in the shop and it was routine not to sign off on the individual steps until the job was completed.
The inspector met with the acting maintenance manager who stated that the work should be signed off at the work location as each step in accomplished, but that it was acceptable to do this later in the shop.
It was also identified to the inspector that gC had also covered the job and had only signed off on the shop master PWO.
The manager of licensing and the maintenance manager stated that each procedural step should be signed as they are completed in the field.
The maintenance manager stated that this did not meet the intent of the "Conduct of Maintenance" procedure and would be corrected.
PWO ¹0524, 18 month PM on Valve V3457 [Shutdown Cooling Heat Exchanger 2B outlet cross-tie to LPSI Header B].
The maintenance was performed on the operator with the valve in the closed position using HP 0940072, Rev 9,
"Preventative Maintenance of Environmentally gualified
Limitorque Hotor Operated Valve Actuators."
The Inspector observed the work activities involving TOL device inspection and overcurrent testing of the TOL per HP 0940061, Rev 17,
"Haintenance of Thermal Overloads."
Two electricians performed the TOL inspection and testing.
The procedure required that the TOL lead be lifted to insert an AC current using a portable high current test set Hodel HS-2.
The electricians determined that a 9.30 amp test current was required and that the allowable range for trip times was 24-47 seconds from the above maintenance procedure.
The test current was inserted and the TOL trip time measured and recorded on Data Sheet l.
The electricians when adjusting the test current appeared uncertain whether the display mode switch should be in the
"Normal" or "Hemory" position.
The inspector questioned the function of this switch, but was not satisfied with the explanation provided.
The electricians did not appear to be thoroughly knowledgeable on the operation of the Hulti-Amp test set.
The first TOL test was aborted prior to tripping the TOL device.
A repeat test was performed.
The inspector noted that the electrician adjusted the test current momentarily exceeding the 9.30 amps prior to stabilizing.
The TOL device tripped at 42 seconds which was within the acceptance criteria.
The electricians recorded the results and then reviewed the procedure for completeness.
A prior signoff for step 9.3.2.G was then initialed as completed based on verbal verification.
The final step 9.4.8 re-terminated the lead to the TOL contact.
This completed testing of the TOL device.
The inspector noted that there was a separate
"verified by" signature and an initial block in step 9.4.8.
In'
discussion with another electrician who completed TOL testing of an adjacent valve (V-3658),
he stated that he did not believe that the "verified by" signature was an independent verification requirement.
He based this on the fact that step 9.6.3 contains a "verified by" and
"independent reviewer" signoff.
For the test that the inspector observed on V3457, the second electrician present during testing verified that the lead was relanded.
When the Acting Haintenance Hanager was asked if the
"verified by" signature in step 9.4.8 is an independent verification, he, also, did not believe so since an operability check would verify that the lifted lead had been properly re-terminated.
Other licensee management disagreed, referring to Administrative Policy, AP17.06,
Rev 0, "Independent Verification" which required that relanded electrical leads on safety systems be independently verified.
The maintenance procedure appeared to be unclear in this regard.
The maintenance activity on V3457 shifted from the breaker cubicle to the actuator located in the ECCS Pump Room.
A third electrician assisted this effort by directing the steps in the procedure.
Inspection of the limit switches discovered that two rotors were damaged and required replacement.
Work performed on this valve was well controlled and effective in identifying components that required replacement.
The following day, the i'nspector reviewed both electricians training records and discovered only one had completed formal training on the Multi-Amp test set on November 12, 1992.
This electrician failed the first written test.
Ke passed a second written test and the JPM on the same day after being remediated.
The other electrician who operated the test set had not completed this training.
The procedure references the Multi-Amp test set operators manual.
The signout card located in the HSTE cage, reviewed by the inspector, showed that this manual was last signed out in late 1992.
The inspector extended his review of individual electrician training to that of training at the Department level to better understand how an electrician could be assigned work using test equipment without formal training.
He found that initial qualification, training was tracked on a separate database by the training department.
This separate database listed courses completed with test scores.
Once an electrician completed initial qualification training, their name, SSN, and date of initial qualification was entered by the training department into a
FOXPRO database.
This database provided a listing of electricians who have completed initial qualification and a record of other preoutage/infrequent training received.
Supervisors and Chief Electricians used this list when assigning work; however, they did not have access to the separate database used by the training department.
As a consequence, they were not able to determine whether a qualified electrician has or has not received specific training if the initial qualification training requirements had been augmented over time.
The previous method of maintaining training records was the on-line Training Record Information Managements System, or TRIMS.
TRIMS printed an attachment to procedures listing qualified electricians by task.
However, due to difficulty in maintaining this system, the
licensee recently adopted the FOXPRO database method.
The weakness in this area is that those individuals assigning work cannot easily determine if a specific training requirement has been met.
The last meeting of the Training Review Committee (TRC-5/95)
had also recognized this as a loophole and developed a matrix listing electricians who lacked courses currently required for initial qualification.
The Electrical Haintenance Hanager stated that he intended to provide training as expediously as possible.
This matrix listing has been provided to Supervisors and Chief Electricians as an interim measure when assigning work.
PWO 50733 was issued during this critical maintenance activity to perform maintenance and repair on HCV-3616
[High Pressure System Injection Feed to Loop 2A2 through High Pressure Header B].
The maintenance was performed to the operator with the valve in the closed position using HP 0940067, Rev 7, "Haintenance and Repair of Limitorque Valve Actuators Type SMB/SB-OO."
The inspector observed those work activities involving reassembly of the actuator up to replacement of the torque switch.
The two electricians working the job were organized, had their tools prestaged and signed off procedural steps as completed.
Supervision periodically observed the work and ensured that it proceeded in a timely fashion.
Work was interrupted for bench testing of the replacement torque switch removed from Unit 1 HV-09-13 (Auxiliary Feedwater Cross-tie valve) per PWO 88821.
The inspector verified traceability of the replacement torque switch to the original purchase order.
As a result of the deficiencies pointed out during several of the CHH activities, the inspectors held a meeting with the managers of maintenance, scheduling, and training to ensure that the identified deficiencies were being corrected.
The licensee has or plans to implement the following corrective actions:
Conducted immediate training on the use of the multi amp tester for the two involved electricians.
Revise the Conduct of Haintenance Procedure to standardize and clarify the use and treatment of procedure sign off.
Develop and employ methods to improve routing of.
routine procedure changes to ensure affected personnel are updated on the changes.
This will be accomplished more frequently than periodic training.
Develop and use alternate methods to reducing overtime hours for staffing and shift coverage of CH Improve Maintenance Training Qualification Tracking.
As an interim provide a listing of individual qualifications to foreman who assign work.
Revise procedures as needed to ensure that independent verification is accomplished where required.
Outline expectations for management and for department heads on backshift.
Complete training of OPS and Maintenance personnel on IPE and CHH process.
Develop a standard tailboard agenda and annotate attendance at future CHH meetings.
Ensure that tailboard start time is conducive to shift change schedules.
Develop generic schedule for CHH windows and start preparations earlier.
Place additional emphasis on CHH work package review for potential problems, parts availability, and contingencies.
Evaluate spreading CMM work over more windows.
Increase QA/QC participation in risk significant work.
In addition to the above, the licensee conducted a work standdown at the end of the above CMH activities to provide training on lessons learned.
The above items indicated weakness in the CHH process involving unclear procedures, a lack of strict procedural compliance, a less than fully disciplined approach to CHH work activities, and a need for improvement in craft training and the qualification tracking system.
The inspector discussed each of the above actions with the licensee and concluded that this corrective action will strengthen the licensee's conduct of maintenance and provide improved control of CHH activities.
4)
PWO 65-0984 1B Emergency Diesel Generator Governor Failure.
During the monthly surveillance of EDG 1B conducted the morning of May 17, 1995, control room operators observed a 50 percent step decrease from full load approximately 30 minutes into the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> run.
EDG 1B was quickly unloaded and shutdown.
On-the-scene Tech Support recommended that the EDG be restarted within 15 minutes for a preliminary evaluation.
Otherwise, the EDG would have to be allowed to cooldown for three hours for prelubrication prior to a normal restart.
When the EDG was restarted, the cognizant engineer determined by manual fuel rack manipulation that the actuator in the Woodward Governor on the 1B2 Diesel Engine had failed (EDG 1B is a tandem generator consisting of two diesel engines, i.e., the 1BI 16 cylinder and 1B2 12 cylinder connected by a shaft with the electric
.
generator between them).
EDG 1B was secured and declared inoperable at 9: 17 am.
Unit 1, which was operating at 100 percent power, entered the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LCO Action Statement and verified the breaker lineup for offsite power.
PWO 865-0984 was issued to replace the Woodward Governor on the 182 Diesel Engine per HP 1-EHP-59.02,
"1B Emergency Diesel Electric Periodic Haintenance and Inspection."
A replacement governor was procured from central stores and bench tested prior to installation.
Part of the bench test involved an inspection of the condition of the limit switches for the governor's electric drive motor.
All bench inspections were satisfactory.
The replacement governor was installed late in the evening of May 17, 1995, and EDG 1B started.
At this point, due to difficulty in adjusting speed, an inspection of the installed replacement governor discovered that the limit switches were defective, i.e., the internal spring in the microswitch did not extend the plunger when off-cam.
The defective limit switches were replaced and a second run performed the morning of Hay 18, 1995.
Instead of starting at the idle speed of approximately 450 rpm, EDG 1B increased speed to approximately 900 rpm.
The cognizant engineer quickly determined that the indexing of 1B2 replacement governor was not correct.
In a discussion with the inspectors, the cognizant engineer identified, the cause as poor communication to the electricians who installed the replacement governor.
He had instructed the electricians that the splined shaft could only be installed in one position based on a machined flat on the spline shaft, when in fact it could be installed in any position.
This problem was identified during the second run when adjustment of the governor to zero position did not place the fuel rack in the shutoff position.
At this point, EDG 1B was secured and plans developed to disconnect/reconnect the splined shaft to reindex the governor (determined to be one spline tooth off).
Also, the assistance of a technical representative was requested.
Since this work would require more than 15 minutes, a third run was not possible until late in the afternoon.
Heanwhile, control room operators successfully completed the operability run of EDG lA as required by the LCO Action Statement.
The governor was removed and realigned correctly.
A post maintenance test was satisfactorily conducted and the DG was declared operable at 8: 17 am on Hay 19, 1995.
Although problems were experienced in performing the above troubleshooting and repairs, the personnel performing this task worked well as a team.
An additional deficiency noted was that the repair effort was very dependent on one engineer who
directed the activity.
His absence could lead to problems on future repairs of this nature.
b.
Surveillance Observations (61726)
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 test(s)
were observed:
1)
OP 2-0410026,
"Unit 2 HPSI Recirc Valve 3659 Delta Pressure Measurement for A Loop."
The test was satisfactory.
The inspector identified that the valve number for the isolation valve that was used for the DP gage was written on the lagging and the piping support.
The ANPS was notified of this situation and took action to have it corrected.
2)
3)
OP 2-04100050,
"Unit 2 HPSI/LPSI Periodic Test, for 2A LPSI Pump."
This test ran the 2A LPSI pump for vibration measurement.
No discrepancies were identified.
OP 1-0700050,
"Monthly Periodic Test of the 1A and 1B Auxiliary Feed Water Pump."
There were no discrepancies for the lA pump; however, the 1B pump bearing cooling line produced a small leak on the coupling between the front and aft bearing.
A PWO was written to repair the coupling leak.
4)
TS 3/4.8. 1. 1 Table 4.8. 1 requires increasing the frequency of diesel generator surveillances to every 7 days if 2 or more failures occur in the last 20 valid tests or if greater than
failures occur in the last 100 valid tests.
Footnote ** states that test frequency of 7 days shall be maintained until
consecutive failure free demands have been performed and the number of failures in the last 20 valid demands has been reduced to 1 or less.
However, Table 4.8. 1 also requires that the number of failures must be less than 5 in the last 100 valid tests to increase the test frequency to 31 days.
On October 28, 1994, the 1B EDG failed it's sixth surveillance in the last 100 valid tests and was placed on a seven day surveillance schedule.
On December 21, 1994, the seventh consecutive failure free test was achieved.
The Diesel Generator System Engineer, who is responsible for tracking failures and determining surveillance frequency, then directed
that 1B EDG be returned to the regular 31 day surveillance period.
This error was identified by the licensee on Hay 17, 1995.
As a result of this incorrect interpretation of TS, the seven day surveillance on 1B EDG was not accomplished from December 28, 1994 to Hay 17, 1995.
Upon identification of this error, the EDG was tested and testing will continue until the requirement of TS for failures in the last 100 valid tests is less than five.
The licensee is currently conducting a root cause evaluation to determine the required corrective action for this item.
The licensee has missed two other surveillances in the past six months; VIO 335/95-01-01 on sampling of a SIT after filling in January 1995, and 389/95-09-01 on the Containment Air Lock Leakage Test in April 1995.
The corrective action to review all Technical Specifications and verify that procedures are in place to initiate unscheduled surveillances and the review to identify TS surveillance testing that relies on a single person to schedule are currently ongoing.
Since this event occurred prior to the above items, the corrective actions for those two items could not have prevented this occurrence.
However, the corrective action for the violation and the NCV should help prevent occurrence of this type.
It is generally accepted that increased testing of EDGs do not increase EDG reliability and availability.
The new Standard TS for CE Plants does not include the requirement for increased testing based on the number of failures in the last 100 starts.
NRC GL 94-01 permits licensees to submit a licensing amendment to remove the accelerated testing requirements for TS.
The licensee has submitted this request and it is currently being evaluated by the NRC.
Since the missed surveillance has minimal safety importance, and corrective actions are currently planned or underway'o prevent recurrence and the licensee efforts in identifying and correcting this items meet the criteria specified in Section VII of the NRC Enforcement Policy it will not be cited.
It will be identified as NCV 335/95-10-01,
"Hissed Surveillance on 1B Emergency Diesel Generator".
6.
Engineering Support Anticipated Transient Without Scram Review (TI 2500/020)
The inspector examined various aspects of the licensee's ATWS modifications, made pursuant to
CFR 50.62.
These activities covered the areas of:
Design conformance to the FSAR and SER guality controls applied to components installed for the modifications
~
Installation of the design modifications
~
Testing and operational procedures A review of the ATWS prevention and mitigation design provisions applied to both units indicated that the licensee's design has remained consistent with that described in the FSAR and endorsed in the NRC Safety Evaluation.
Aspects of the Diverse Scram System were confirmed to be classified as nuclear safety related and seismic category I, as described in the SER.
NRC approval of the licensee's design was noted, in the SER, to be contingent upon a human factors review of the (then)
proposed use of a single annunciator to indicate both ATWS actuation and ATWS bypass for testing.
The inspector verified that the licensee has since modified the design to employ two annunciators in each control room; one For actuation and one for bypass status.
The SER noted that, in the originally proposed design, an inadequate level of diversity existed between matrix relays employed in the RPS and AFAS systems and that, accordingly, the licensee modified the reed switches of AFAS matrix relays to increase diversity to an acceptable level.
The inspector verified that the subject matrix relays were still employed in their respective applications and that sufficient diversity remained.
The inspector questioned the licensee as to the provisions in place to assure that the current level of diversity would be maintained over time (in many applications, the licensee has modified component designs due to a lack of replacement parts).
The licensee referred the inspector to VTM 2998-15437, which included a discussion on the diversity bases for the AFAS matrix relays.
Additionally, the FSAR contained discussions of diversity in AFAS and ESFAS sections.
The inspector then questioned whether similar provisions were included in the RPS VTM or FSAR.
The licensee stated that such provisions were not included, but committed to include a discussion of RPS diversity from ESFAS and AFAS in the RPS section of the FSAR.
The inspector reviewed selected component designations within the licensee's material management system.
Components included I/I converters, actuation bistables, logic relays, and isolation relays.
The inspector found that the components were categorized as nuclear safety related, as specified in design documentation.
Installation of the ATWS equipment was observed by the inspector at the time of the installation.
The inspector noted extensive involvement on the part of personnel from design/vendor engineering, vendor/site gC, and system engineering.
Minor errors in printed circuit board manufacture and CEAMG disconnect contactor wiring workmanship were identified and corrected.
Post-modification testing was observed and found to be satisfactory.
The inspector reviewed testing procedures associated with ATWS considerations.
The procedures included:
I&C 140071, Rev 0,
"ATWS Functional Test" I&C 1-1400153D, Rev 3, "Reactor Protection System
- Engineered Safeguards System Loop Instrumentation Calibration of Pressurizer Pressure" I&C 1-1400052, Rev 32,
"Engineered Safeguards Actuation System
- Channel Functional Test" I&C 1-1400166, Rev ll, "Engineered Safeguards Actuation System
- ATI Alignment Check" Similar procedures were available for Unit 2.
The inspector found that the procedures provided a comprehensive methodology for periodic testing of ATWS DSS components.
Together, the procedures enveloped the system from detection to actuation devices.
The inspector also verified that on-line.testing of DSS components was being performed by the ATI function of the ESFAS cabinets, as described in the FSAR and SER.
The inspector reviewed operational procedures associated with ATWS concerns.
The following procedures were reviewed:
~
ONOP 1-0030030, Rev 6, "Anticipated Transient Without SCRAM (ATWS)"
~
ONOP 2-0030030, Rev 5, "Anticipated Transient Without SCRAM (ATWS)"
In both cases, the procedures indicated symptoms of an ATWS and described immediate operator actions to be taken in such an event.
Actions included:
Verifying that automatic actions occurred Manually tripping the reactor and turbine Initiating emergency boration Ensuring AFAS flow Opening TCBs locally Securing CEA MG sets locally and, if CEAs were still not inserted, reenergizing CEA busses and manually driving CEAs into the core.
The inspector found that, while the procedures included numerous options for reactivity control in the event of an ATWS, they did not include the manual insertion of an ATWS signal into the DSS.
The inspector verified that such a provision was available within the system design, consistent with the SER; however, discussions with operators indicated that the methodology was not included in procedures and was not known to them.
The inspector provided this information to the licensee; however, the use of a manual DSS actuation was not a code requirement.
Consequently this was solely an observation.
In conclusion, the inspector found that the licensee had appropriately implemented the approved ATWS design and has maintained the approved levels of diversity, and provisions were in
place, or have been committed to, to ensure that diversity is maintained in the future.
Test procedures were found to address testing from sensor to actuation device for the DSS.
Levels of quality committed to in FSAR and approved in the SER were found to be maintained.
This completes inspection activity based upon TI 2500/20 (Closed).
7.
Plant Support (71750)
'a ~
Fire Protection b.
During the course of 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 deficiencies were identified.
Physical Protection During this inspection, the inspector toured the protected area and noted that the perimeter fence was intact and not compromised by erosion or disrepair.
The fence fabric was secured and barbed wire was angled as required by the licensee's PSP.
Isolation zones were maintained on both sides of the barrier and were free of objects which could shield or conceal an individual.
The inspector observed personnel and packages entering the protected area were searched either by special purpose detectors or by a physical patdown for firearms, explosives and contraband.
The processing and escorting of visitors was observed.
Vehicles were searched, escorted, and secured as described in the PSP.
Lighting of the perimeter and of the protected area met the 0.2 foot-candle criteria.
c ~
In conclusion, selected functions and equipment of the security program were inspected and found to comply with the PSP requirements.
Radiological Protection Program Radiation protection control activities were observed to verify that these activities were in conformance with the facility policies and procedures, and in compliance with regulatory requirements.
These observations included:
Entry to and exit from contaminated areas, including step-off pad conditions and disposal of contaminated clothing;
'rea postings and controls; Work activity within radiation, high radiation, and contaminated areas;
~
RCA exiting practices; and,
~
Proper wearing of personnel monitoring equipment, protective clothing, and respiratory equipment.
d.
Emergency Preparedness Drill (82301)
The inspector observed the off year annual emergency exercise conducted on Unit 2 on May 3.
The drill scenario consisted of:
evacuation of an injured contaminated worker; fire in a startup transformer with offsite fire fighting assistance; loss of offsite power; failure of all control rods to insert on a reactor trip; and fuel failure followed by a catastrophic failure of main steam piping to the auxiliary feedwater pump.
The drill senario led to the declaration of an Unusual Event, Alert, Site Area and General Area Emergency.
This exercise had limited participation by local and state agencies.
The following observations were made by the inspector during the exercise:
1)
Control Room (Simulator)
Operations personnel responded to the medical emergency in an expeditious manner.
Offsite medical assistance was requested and an ambulance transported the injured contaminated worker to the Lawnwood Regional Hedical Facility at Ft. Pierce.
An HP Technician accompanied the worker and assisted in the decontamination offsite.
The licensee's response was observed to be timely and appropriate.
Shortly thereafter, a fire occurred in the "2B" Startup Transformer with a failure of the deluge system to actuate.
The licensee declared an Unusual Event which escalated to an Alert when the fire lasted longer than ten minutes in an area containing equipment important to safety.
Offsite fire fighting assistance was requested and provided.
The licensee's response was, again, both timely and effective.
The control room ordered the affected transformer deenergized and made all required notifications and requests for offsite assistance.
An actual failure of the HRD phone delayed notification to the state for several minutes until an alternate communications path could be established.
This failure, although not part of the scenario, added an element of.
realism to the drill.
2)
Technical Support Center The TSC was activated when the Alert was declared for the transformer fire.
The PGN assumed responsibility as the EC when the TSC became operational.
Shortly thereafter, the control room reported that the 2B steam generator tube leakage had increased to 10 gpm.
Operators commenced an orderly shutdow Approximately 30 minutes later, the control room reported entering the off normal procedure for loss of instrument air due to a piping failure.
Station Air was out of service for maintenance.
The Problem Solving Team in the TSC began evaluating alternate means of restoring instrument air, which included a temporary patch or connecting portable compressors.
Within about 5-10 minutes, the reactor was manually tripped and steam generator tube leakage increased to 200 gpm.
An offsite release occurred due to actuation of the SG safety and atmospheric dump valves.
Offsite dose assessment was initially hampered due to computer operator's difficulty in obtaining data from the ERDADS.
Two plant support staff working in the ERDADS equipment room were unable to provide the time when ERDADS was activated and whether the simulator was interfaced to ERDADS for the drill.
Although the two individuals may not have been players, in a real emergency support staff should be knowledgeable of system interconnects and configuration.
It was also noted there was a delay of approximately several minutes in announcing the LOOP and stuck control rods.
However, following this announcement, the Problem Solving Team shifted their emphasis to developing a procedure for reenergizing non-vital buses from Unit 1.
Status boards were maintained and the EC exerted positive control in focusing recovery efforts.
Overall, the TSC functioned effectively.
Operations Support Center A cursory inspection of the OSC showed that a status board was being updated for changes in plant conditions and tracking of recovery teams.
The OSC was organized by discipline, i.e.,
ILC, Electrical, Hechanical, etc., to support the drill.
No other observations were made in this area.
Emergency Offsite Facility The EOF assumed responsibility for offsite communications after being declared operational.
The state of Florida and licensee offsite dose assessment results were updated on the EOF status board approximately every thirty minutes.
A notable exception occurred after the 12: 15 pm results which were not updated for about an hour.
The Recovery Hanager maintained positive control of the EOF and performed briefings to ensure all personnel were informed.
A post drill critique was held which identified the lapse in updating the status board and the one hour delay in briefing the media after declaring a General Emergency.
Overall, the EOF functioned well.
Post Drill Critique on 5/4/95 Controllers/Evaluators attended the post drill critique held by the Emergency Planning Department from 8:00 am until ll:30 am.
Discussions were frank and thoughtful.
Areas in which the
drill highlighted both strengths and weaknesses were identified.
One area that may have warranted additional discussion was the evaluation of the effectiveness of the Problem Solving Team.
With respect to the TSC, discussions focused on the coordination difficulties between the offsite dose assessment teams in the TSC and EOF.
Overall, the critique was meaningful and, if all the recommendations discussed are implemented, will further enhance the licensee's emergency response capability.
The exercise was well planned and effectively tested the ability of the licensee and local and state agencies to respond to plant events:
Overall exercise communications were excellent.
Management control and discipline was strong.
Post exercise critiques were detailed and thorough.
The TSC problem solving team was slow and ineffective in responding to repairs on the start up transformer and loss of instrument air.
It was noted that the above problems, with the exception of the problem solving team, were also identified by the licensee's observances and discussed in the critiques.
e.
Hurricane Preparedness Drill The licensee conducted a hurricane preparedness drill on May 23, 1995.
This drill verified the operability of their satellite telephone, HF-ALE and VHF radio equipment.
Training was conducted to refamiliarize the STAs and OSC administrative personnel with this equipment and operating instructions were verified to be current.
The stop logs used to limit flooding in the RAB were verified to be in place.
The conex boxes containing prestaged hurricane supplies were also inventoried.
The inspector did not observe the above drill but discussed it with drill personnel.
The licensee plans to critique the drill and present the results to the FRG by mid June.
8.
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems (40500)
a.
Facility Review Group Meetings I)
The inspector attended a special FRG meeting conducted on May 9.
A quorum was present and the agenda covered changes to EOPs.
The changes incorporated feedback response record changes of CEN-152 Rev 3 and included simulator feedback recommendations and human factor improvements.
The majority of the changes resulted from incorporating changes in the TRIP 2/LEAVE 2 RCP LOCA ANALYSIS.
This analysis now permits operation of two RCP'S at less than 1300 PSIA if subcooling is greater than 20 degrees F.
This meeting included a
presentation by operations staff and the technical staff reviewer of these changes.
The presenters were very knowledgeable on the proposed procedure changes and their effects on EOPs.
It was noted that all FRG members actively participated in discussions on agenda items.
2)
The Inspector attended the Facility Review Group (FRG) Meetings held on Hay 31 and June 1,
1995, where the
CFR 50.59 evaluation and plans for an alternate arrangement of the NIS Excore Detectors on Unit 1 were reviewed.
This alternate arrangement involved connecting the Control Channel 2 detector signal to Linear Power Range Channel D.
This was required to return failed NIS channel D to service and restore the reactor trip logic to a two out of four coincidence.
This arrangement is feasible since the linear power range and power range control channel use the same design detectors and cables.
The licensee's plans called for making this change by disconnecting the failed linear range detector input to RPS channel D in the RPS cabinet and routing a jumper from RTGB 104 through the control room overhead to RPS channel D cabinet to connect control channel 2 to RPS channel D.
The
CFR 50.59 evaluation; compensatory action being taken until the activity could be accomplished, i.e.,
channel D variable High Power, SUR, TNLP, LPD, and LOL trips in trip; work instructions to perform this task; and testing required to place channel D back in operation were discussed in detail in the meeting.
All issues appeared to be adequately addressed.
An information call to the NRC was made to inform them of the actions being taken on this item.
The Inspector observed portions of the work associated with this activity which was accomplished on June 1,
1995.
No deficiencies were identified.
b.
Licensee Self Assessment (40500)
The inspector reviewed the QA Fire Protection Audit, QSL-OPS-95-02, completed in April 1995.
The evaluation appeared to be a detailed evaluation of the plant fire protection program.
This included a
review of procedures, records, and in-plant inspection activities.
Strengths were identified in the roving fire patrol training and identification of deficiencies and the fire protection groups aggressive promotion on verification of fire protection requirements.
Areas needing improvement included; fire barrier description provided in fire fighting strategies; fire barrier inspection procedure TS 10.36 review and approval; and the lengthy extension permitted on fire breaches.
The audit also contained a
technical recommendation that engineering evaluate the adequacy of detail provided in the PSL Safe Shutdown Analysis regarding failed
c ~
d.
cables from a postulated fire.
STARS were issued to ensure that appropriate corrective action is taken on the above items.
The inspector found the above audit to be a detailed review of the fire protection program, and changes that have occurred in the past two years.
The report was well written and indicated that the licensee has an acceptable program in this area.
QA Quarterly Activities (40500)
The inspectors met with QA on Hay 26 and discussed the results of their activities for the last quarter.
The agenda included QA reorganization plans, the site industrial safety program, plant oversight, a summary of recent audits and monitoring activities, QC inspection activities and findings, cross training of QC inspections, and receipt inspection activities.
No site wide issues or negative trends were identified by QA.
This review indicates that QA/QC is still performing all required audit and inspection activities and continues to support safe plant operation.
Corporate Nuclear Review Board (40500)
The inspector attended the monthly CNRB meeting on Hay 16, at the St.
Lucie site.
A quorum was present and the meeting agenda included:
St.
Lucie Plant General Manager's report on plant performance, reportable events, NRC violations, staffing changes, and other miscellaneous items.
QA review of LERs Proposed license amendments Review of inspection reports.
Report on plant tours by CNRB.
The inspector attended approximately two hours of the meeting and noted that the board asked detailed and searching questions on safety significant items.
9.
Other Areas a ~
Consultation with National Marine Fisheries Services
- TAC 9201415 The inspector attended an initial meeting for the consultation process between the NRC and NHFS regarding protected species of marine turtles on Hay 23, at the St.
Lucie site.
The attendees included FPL plant and corporate personnel, NRC (Environmental and Project Management Branch), State (FDEP),
and the NHFS.
The discussions focussed on the increase in turtles appearing in the plant intake canal in recent years.
This meeting included a site orientation, a tour of the intake canal areas, and equipment installed to prevent turtle entry into the intake pump area.
A discussion on the licensees preliminary biological assessment of
this item was held in the afternoon.
The licensee provided information on additional equipment they plan to install in the intake canal in Decemb'er 1995.
They also discussed an assessment of the increase in turtle intake and established a time table for a submittal of this assessment to the NRC and NHFS.
b.
Public Document Room The inspector and the Licensing Project Manager, NRR, visited the St. Lucie Plant Public Document Room in the library at the Indian River Community College in Ft. Pierce on Hay 24, 1995.
The documents were neatly stored and indexed for easy retrieval.
The majority of files are now on microfiche and the microfiche reader was verified to be operable.
The librarian was able to access NUDOCS through a computer and modem and appeared to be familiar with this equipment.
The latest NUDOC document available was dated Hay 19.
The latest microfiche file was dated Hay 22, 1995.
The librarian stated that NRC assistance was easily available by dialing 1-800-638-8081.
She also stated that this document room received very limited use, and primarily by media personnel.
The public document rooms overall condition was found to be excellent.
10.
Exit Interview The inspection scope and findings were summarized on June 2,
1995, with those persons indicated in paragraph 1 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.
~T e
Item Number NCV 50-335/95-10-01 Closed
"Missed Surveillance on IB Emergency Diesel Generator",
paragraph 4.b.4).
ll.
Abbreviations, Acronyms, and Initialisms AC AEOD AFAS AFW ANPS AP AS ATI ATTN ATWS CC CCW CE CEA Alternating Current Analysis and Evaluation of Operational Data, Office for (NRC)
Auxiliary Feedwater Actuation System Auxiliary Feedwater (system)
Assistant Nuclear Plant Supervisor Administrative Procedure Action Statement Automatic Test Instrument (in the ESF cabinets)
Attention Anticipated Transient Without Scram Cubic Centimeter Component Cooling Water Combustion Engineering (company)
Control Element Assembly
CEAMG CEDM CFM CFR CMM CNRB CWD DC DG DP DPR DSS EC ECCS EDG EM EMP EOF EOP ERDADS ESF ESFAS FCV FDEP FI FPL FR FRG FS FSAR gpm HCV HF-ALE HPSI HRD HV HVAC HVE HVS HX IEC I/I INPO IPE IR IV JCN JPM JPN KINS LCO LER Control Element Assembly Motor Generator Control Element Drive Mechanism Cubic Feet per Minute Code of Federal Regulations Critical Maintenance Management Company Nuclear Review Board Control Wiring Diagram Direct Current Diesel Generator page 13, 95-04 Demonstration Power Reactor (A type of opera Diverse Scram System Emergency Coordinator Emergency Core Cooling System Emergency Diesel Generator Electrical Maintenance Electrical Maintenance Procedure Emergency Operations Facility Emergency Operating Procedure Emergency Response Data Acquisition Display Engineered Safety Feature Engineered Safety Feature Actuation System Flow Control Valve Florida Department of Environmental Protecti Flow Indicator The Florida Power
& Light Company Flow Recorder Facility Review Group Flow Switch Final Safety Analysis Report Gallon(s)
Per Minute (flow rate)
Hydraulic Control Valve High Frequency Automatic Link Establishment High Pressure Safety Inject'ion (system)
Hot Ring Down Heating Ventilation Heating Ventilation and Air Conditioning Heating and Ventilating Exhaust (fan, system Heating and Ventilating Supply (fan, system, Heat Exchanger Instrumentation and Control Current to Current Institute for Nuclear Power Operations Individual Plant Examination
[NRC] Inspection Report Independent Verification Juno Change Notice Job Performance Measurement (Juno Beach)
Nuclear Engineering Korea Institute of Nuclear Safety TS Limiting Condition for Operation Licensee Event Report ting license)
System on
, etc.)
etc.)
LOCA LOL LOOP LPD LPSI M&TE HCC HG HOV HP HRA MV NCV NIS NHFS No.
NPF NPWO NRC NRR NUDOC ONOP ONP OP OPS OSC PCR PGH PI PM PRA PSA psia PSL PSP PWO QA QC QI QSL RAB RCA RCB RCP Rev RII rpm RPS RTGB RWT SCRO SER Loss of Coolant Accident Loss of Load Loss of Offsite Power Local Power Density Low Pressure Safety Injection (system)
Measuring
& Test Equipment Motor Control Center (electrical distribution)
Motor Generator Motor Oper'ated Valve Maintenance Procedure Maintenance Risk Assessment Motorized Valve NonCited Violation (of NRC requirements)
Nuclear Instrumentation System National Marine Fisheries Service Number Nuclear Production Facility (a type of operating license)
Nuclear Plant Work Order Nuclear Regulatory Commission NRC Office of Nuclear Reactor Regulation Nuclear Documents Off Normal Operating Procedure Off Normal Procedure Operating Procedure Operations Operations Support Center Procedure Change Request Plant General Manager Pressure Indicator Preventive Maintenance Probabilistic Risk Assessment Probabilistic Safety Assessment Pounds per square inch (absolute)
Plant St.
Lucie Physical Security Plan Plant Work Order Quality Assurance Quality Control Quality Instruction Quality Surveillance Letter Reactor Auxiliary Building Radiation Control Area Reactor Containment Building Reactor Coolant Pump Revision Region II - Atlanta, Georgia (NRC)
Revolutions per Minute Reactor Protection System Reactor Turbine Generator Board Refueling Water Tank Senior Control Room Operator Safety Evaluation Report
STA STAR SUR TAC TCB TCV TE TI TMLP TOL TR TRC TRIMS TS TSC VHF VIO VTH
Steam Generator Safety Injection Actuation System Safety Injection Tank Type of valve actuator Senior Reactor [licensed] Operator Social Security Number Saint Shift Technical Advisor St.
Lucie Action Request Startup Rate Task Assignment Code Trip Circuit Breaker Temperature Control Valve Temperature Element
[NRC] Temporary Instruction Thermal Margin Local Power Thermal Overload Temperature Recorder Training Review Committee Training Record Information Managements System Technical Specification(s)
Technical Support Center UFSAR Very High Frequency Violation (of NRC requirements)
Vendor Technical Manual