IR 05000413/1997012
| ML20199G046 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 11/10/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20199G029 | List: |
| References | |
| 50-413-97-12, 50-414-97-12, NUDOCS 9711250079 | |
| Download: ML20199G046 (27) | |
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-U.S. NUCLEAR REGULATORY _ COMMISSION-
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REGION II
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Docket:Nos:
50-413:50-4141-License Nos:
NPF-35 -NPF-52
- Report Nos.:=
-50-413/97-12, 50-414/97-12 d
Licensee:-
Duke Energy Corporation-
- Facility:-
Catawba Nuclear Station. Units 1 and 2'
Location:-
422 South Church-Street:
Charlotte NC 28242-Dates:
August-31 - October 11. 1997 LInspectors:
D. Roberts. Senior Resident Inspector-D. Seymour. Acting Senior Resident Inspector R. Franovich. Resident Inspector M.~ Giles.-Resident Inspector (In Training)
W. Stansberry. Safeguards Specialist (Sections S1.1 through S5.1)
Approved by:
C.'0gle. Chief Reactor Projects Branch 1 Division of Reactor Projects
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EXECUTIVE SUMMARY Catawba Nuclear Station Units 1 and 2 NRC Inspection Report 50-413/97-12, 50-414/97-12 This integrated inspection included aspects of licensee operations maintenance, engineering, and plant support. The report covers a 6-week period of resident inspection, as well as the results of an announced inspection by a regional security inspector.
Doerations Control room operators effectively precluded a Unit 2 turbine runback by
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performing a rapid power decrease in response to a main generator power circuit breaker air pressure decrease.
(Section 02.1)
The inspectors noted that only one unit would trip at Catawba if a non-
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safety auxiliary power instrument bus was lost.
The licensee was implemeilting corrective actions in response to the McGuire event.
(Section 02.2)
The Nuclear Safety Review Board was candid, provided good safety
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oversight of the plant's operation, and proposed suggestions for improving plant performance, which were documented for resolution.
(Section 07.1)
Maintenance The licensee responded appropriately to a choker failure that occurred
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during spent fuel pool weir gate manipulation in the cask pit area of the spent fuel pool.
However, examples of poor practices were noted during the inspectors * review, including skill-of-the-craft selection of padding material and an administrative error associated with the lift plan documentation.
(Section M1.1)
The licensee's failure investigation 3rocess for a second 1B emergency
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diesel generator test failure was metlodical and appropriate. A more aggressive investigation following an earlier failure could have resulted in a true root cause versus an " apparent" root cause being identified.
(Section M1.2)
An Inspector Followup Item was opened to address inspector concerns with
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continuing leakage problems with the nuclear service water system.
(Section M2.1)
A 52-day discreaancy between the Event Date and the Report Date for
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Licensee Event Report 50-413/97-06, which reported surveillance testing deficiencies, was the result of insufficient information contained in the Licensee Event Report.
(Section M8.2)
Enclosure 2
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Enaineerina The licensee's completed and planned actions to determine the root cause
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of two recent main generator 2B power circuit breaker failures were adequate.
Increased monitoring of the associated solenoid valve was appropriate, and plans to replace the valve after two months of service were considered conservative.
(Section 02.1)
The licensee's digital optical isolator testing activities have been
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appropriate to identify degrading resistors.
Plans to modify tnc main
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steam isolation valve control circuitry to alleviate the single faiiure vulnerability to inadvertent closure should be effective in reducing unnecessary reactor trips. (Section E8.1)
Plant Sucoort The licensee used compensatory measures that ensured the reliability of
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security-related equipment and devices.
(Section S1.1)
The access controls for vital areas were in compliance with the Physical
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Security Plan.
(Section S2.1)
Two violations of the access controls for personnel were identified.
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(Section S2.2)
Alarin stations, assessment aids, and communication were operating as
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required by appropriate commitments.
(Section S2.3)
The licensee used programs that will ensure the reliability of security-
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related equipment and devices.
The testing and maintenance program was a strength in the security program.
(Section S2.4)
Changes in Revision 6 of the Physical Security Plan did not appear to
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decrease the effectiveness of the Plan.
(Section S3.1)
One violation was identified concerning the Security Event
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logging /Reportability Program.
(Section S3.3)
The licensee appropriately analyzed. tracked, resolved, and documented
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nuisance alarm rate events through the problem investigation process investigation process program.
The security organization's application of the problem investigation program was a strength.
(Section S3.3)
The security force was being trained according to the Training and
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Qualification Plan and regulatory requirements.
(Section S5.1)
Enclosure 2
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Reoort Details Summary of Plant Status Except for a planned reduction to 97% power to facilitate the calculation of the moderator temperature coefficient near the end of core life, Unit 1 operated at or near 100% during the entire inspection period.
Unit 2 operated at or near 100% power until September 15, when operators reduced power to 50% to preclude an automatic turbine runback upon the anticipated failure of main generator power circuit breaker (PCB) 2B.
This action was taken after operators received a control room alarm associated with decreasing pneumatic pressure on the PCB.
A faulty solenoid valve was replaced and the unit was returned to 100% power on September 16.
The unit operated at or near 100% power for the remainder of the inspection period.
Review of Uodated Final Safety Analysis Reoort (UFSAR) Commitments While performing inspections discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that were related to the areas inspected.
The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures, and parameters.
I. Ooerations 01-Conduct of Operations 01.1 General Comments (71707)
The inspectors observed several operations shift turnover meetings in the control room, conducted several tours of the control room and observed unit operators' response to alarming conditions.
In general, the meetings were conducted satisfactorily: control room deficiencies and annunciators were few; and when questioned about alarms and annunciators, operators knew their status.
Operational Status of Facilities and Equipment 02.1 PCB 28 Solenoid Failure and Ranid Unit Downoower a.
Insoection Scoce (71707. 37551)
Operators performed a rapid Unit 2 down power to 50% on September 15, 1997, as a result of decreasing pneumatic pressure on the 2B main generator PCB.
The inspectors discussed the solenoid failure with engineering Jersonnel, inspected the affected component, and reviewed station 3roblem Investigation Process (PIP) report 0-C97-2998.
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Lb; Observations and Findinas
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-Control room operators received-a main generator PCB low air pressure alarm on September 15,1997. -Power Circuit. Breaker air pressure.was-monitored and operators determined that air pressure continued to:
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in,the event that tie PCB opened was performed. The air pressure decrease was attributed to a faulty solenoid valve in the PCB air
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A similar. problem occurred on July 2,1997, and is discussed in Inspection Report (IR) 50-413.414/97-09.
The solenoid was replaced and the unit was returned to full power on September 16.
The licensee initiated a' failure investigation to determine if the replacement solenoid valves were vulnerable to some form of degradation while in service. Work order 97081031 was generated to implement weekly monitoring of PCB 28 air. pressure in the interim.
.The licensee's failure investigation, which involved a metallurgical
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. analysis at the Duke test facility, revealed that the seals on the failed solenoid valves-(comarised of a fluorinated polymer) were
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yellowed-and swollen. The ) uke test facility was unable to identify the
= phenomena responsible for the seal degradation. The licensee planned to send the failed solenoid components to an outside consultant-specializing in polcomponent failure. ymer deoradation to determine the cause The solenoid valve that failed in July was installed in April 1997 during troubleshooting of an unrelated problem.
The licensee did not identify any problems with the solenoid valve removed in April, but a new one that contained a different type of seal was installed.
The licensee indicated that there had been no history of failure of the older type of solenoid. To address the potential generic vulnerability of the-new solenoid valves to polymer (or other) degradation over time, the licensee initiated efforts to obtain an old type solenoid valve from a Tennessee Valley Authority plant and has generated work order 97086699 for valve replacement in-mid-November.
Because the first failure e'
occurred after a 70-day service life, and the second one after a 75-day
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service life, the-licensee _ planned to return to the older type valve to preclude a third failure.
The inspector considered this approach, along
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with the weekly monitoring of the currently installed 2B PCB solenold.
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to be reasonable.
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Conclusions
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LThe inspector concluded that the control room operators effectively
! precluded a Unit'2. turbine runback by performing-a rapid power decrease in response _to the. decreasing main generator PCB air pressure.
The licensee's completed and planned actions to determine the root cause
were adequate.
Increased monitoring of the associated solenoid valve
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was appropriate, and plans to replace the valve after two months of service are conservative.
02.2 Catawba's susceotibilities to a Dual Unit Trio Uoon Loss of an Auxiliary Power Non-Safety Bus a.
Insoection Scoce (71707)
The inrpectors reviewed the susceptibility of Catawba to a dual-unit trip similar to that which occurred at McGuire on September 6. 1997.
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Observation and Findinas On September 6.1997. McGuire experienced a dual unit trip following deenergization of bus KXA, a 120-volt AC (VAC) non safety instrument bus.
Normally. KXA is energized by an inverter fed by a 125-volt direct current DC charger, and backed up by a 125-volt DC battery.
However, the inverter, battery and charger associated with uus KXA were removed from service while performing annual battery preventive maintenance
'PM), and the bus was being fed by its alternate source.
Bus KXA was de-energized when its alternate source sup)1y breaker tripped open on thermal overload caused by a loose lug on t1e breaker.
The resultant loss of equipment caused both units to trip.
In response to McGuire's dual unit trip Catawba initiated an investigation to identify whether Catawba would experience a dual unit trip under the same ciicumstances.
The inspectors' review of Catawba's susceptibilities to the McGuire dual unit trip included:
(1) review of one-line diagrams for the 120 VAC auxiliary Jower system. Operating Experience Data Base Reports, and McGuire P13s associated with the trips: (2) discussions with an electrical engineer who led the investigation of the McGuire dual unit trip; and (3) a walkdown of the potentially affected inverters and breakers at Catawba.
The inspector noted that the Catawba electrical line-up was different from McGuire in that Catawba has four 120 VAC auxiliary power buses, two per unit (McGuire only has 2 buses for both units). Additionally, the loads on McGuire's buses are not " unitized" in that there are mixed loaJs (Unit 1 and 2 loads) on each bus.
Catawba's buses are unitized and train oriented: if Catawba lost the bus analogous to McGuire's KXA bus (Catawba's bus KXPA), only one unit would trip.
In addition, at Catawba, bus KXPB's battery could supply power to both buses (KXPA and KXPB). so the KXPA's inverter does not need to be removed from service if its battery is removed for maintenance.
If the inverter failed, a fast transfer to an alternate power source would occur, preventing loss of the bus. This was verified by the insoectors when an actual event occurred on September 29. 1997, during wh'ich 1KXPB's inverter (1KXIB)
failed resulting in an automatic fast transfer to a regulated AC power supply.
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The licensee's investigation determined that Catawba has breakers on the
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alternate source similar to the McGuire breaker which tripped on thermal
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overload, and that the Catawba breakers would probably trip on thermal-overload. -The breakers at Catawba have not been periodically tested-and/ur inspected. - The licensee generated short-and long-term
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corrective actions in response to their findings about the McGuire dual unit tr.ip.
These included: postponement of inverter PMs until all affected breakers have been examined / tested: generate work orders (W0s)
to inspect / test the affected breakers: and set up PM inspection / testing of these breakers.
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Conclusions The inspector noted that only one unit would trip at Catawba if a non-safety auxiliary power instrument bus was lost.
The licensee was implementing corrective actions in response to the McGuire event.
07:
Quality Assurance in Operations
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07.1 Nuclear Safety Review Board (NSRB)(40500)
A NSRB meeting was conducted at the Catawba Nuclear Station on September 18. Site presentations to the NSRB involved plant performance indicators, reportable events, violations, trends, areas for improvement, and other general information associated with the station's safety performance.
In addition, a presentation specifically addressed
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two recent digital optical isolator (D01) failures that resulted in two se)arate Unit 2 manual reactor trips. The information presented to the NSlB constituted.a realistic portrayal of overall plant )erformance.
The NSRB-was candid, provided good safety oversight of t1e plant's o)eration, and proposed suggestions for improving plant performance, w11ch were documented for resolution, c
Miscellancous Operations Issues (92700)
08.1 (Ocen) Licensee Event Reoort (LER) 50-414/95-01:
Reactor Trip Due to Closure of a Main Steam isolation Valve
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The event described in.this LER involved an automatic reactor trip because ~of the failure of an optical.1solator in the B main steam isolation valve (MSIV) control circuit that caused the valve to close.
This LER was discussed in NRC Inspection Report 50-413.414/97-05 and remained o)en pending the licensee's completion of planned corrective action Num)er 2 (incorrectly referred to as corrective action Number 3 in the earlier inspection report).
Planned corrective action Number 2 was to develop a preventive maintenance PM program to periodically monitor continuously energized Electromax DOI with model numbers 175C156 and 175C157 in critical -
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applications. The inspector reviewed the status'of planned corrective action Number 2 and determined that-the licensee had initiated a PM
- program to periodically replace DOIs that perform a control ~ function and that have, alternating current input voltage prior to the end of
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The-ins)ector inquired about the change:1n the PM program to.
~ determine -if tie NRC had been apprised of-the change.
Neither the inspector nor:the licensee could locate correspondence communicating the
change in the PM program, This LER will; remain open pending further NRC
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II. Maintenance
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. Conduct of. Maintenance-M1.1 Soent Fuel Pit Weir Gate Choker Failure a.
Insoection Scone (62707)
The inspectors reviewed the circumstances of the September 4,1997,
. Unit 2 weir gate cbckcr failure.
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Observations and Findinas-I On September 4, maintenance personnel moved the Unit 2 weir gate from-its storage location in the s)ent fuel pool -(SFP) to the cask
' decontamination area, using tle two ton manipulator crane hoist. The weir gate was moved to allow replacement of the weir gate seal Initially, the weir gate was rigged to the two-ton manipulator crane and moved from the SFP to the cask pit. The weir gate was then transferred to the SFP. overhead crane ten-ton-hook.
The-manipulator crane was moved out of the way, and a second attachment (a choker) was rigged around the bottom half of the gate and connected to the 125-ton hook on the SFP--
crane. The choker was padded with a softener, an old weir gate seal, to
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protect the choker from the sharp edges of the weir-gun. After the choker was installed, the licensee attempted to move the gate to an angle off-vertical-(the gate-must be tilted to 3rovide clearance-in order to move the gate from the cask-pit into tie cask decontamination
area); - As the gate was moved from the vertical position. it cut through
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the softener and the choker.
Consequently, the gate moved back to the
vertical position while still safely suspended from the ten-ton hook.
At-this point, maintenance personnel stopped all activities associated with the weir gate.and consulted engineering for-guidance. The. weir r
gate was eventually transferred from the ten-ton book to the 125-ton SFP
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Dbuilding crane hook. Once rigged to the 125-ton hook, the weir gate was moved from-the cask pit into the cask decontamination area using a-tstraight lift.
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'The inspectors noted that there was no equipment damage. no personnel contamination, and that this incident did not occur over the fuel racks.
This~ evolution had been performed successfully several times in the past. The licensee initiated a team to investigate and determine root-
-causes for this-incident.
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The inspectors determined, through a review of computer records and discussions with the licensee, that advanced qualified' riggers performed the rigging. The inspectors reviewed the following procedures:
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MP/0/A/7150/062. Spent Fuel Pool Weir Gate Corrective Maintenance:
OP/2/A/6550/014 Oraining and Filling of' Spent Fuel Transfer Canal and Cask Area. Enclosure 4.5. Weir Gate Checklist: OP/0/A/6550/016. Overhead Lifting-Crane: HP/0/A/7650/104. Fuel Building Crane Operation and Fuel
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Building Safe Load Paths; and OP/2/A/6550/006. Transferring Fuel with -
the Spent Fuel Manipulator Crane. Enclosure 4. Startup and Shutdown of the S ent Fuel Pool Mani ulator Crane.
Other doct.nents reviewed inclu ed:
WO 970681125-1. Replace Weir Gate Seals, the Foreign Material Exclusion (FME) sheet. the maintenance pre-job briefing sheet.
the Lift Plan, and the Incident Investigation Report.
The inspectors noted that the verification space in the lift plan for meeting the requirements of NUREG 0612. Control of Heavy Loads at Nuclear Power Plants, was left blank. The riggers responsible for
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filling out this form left this space blank because they were not familiar with-NUREG 0612. The riggers were Duke Power riggers, and worked at other Duke Power sites where NUREG 0612 doesn't apply, and the lift lan was a new form. The lift coordinator approved the lift plan witho t noting this portion was not checked off.
The ins)ector concluded through discussions with the lift coordinator tlat the provisions of NUREG 0612 (single failure proof crane, mechanical stop on n
the crane, and evaluation of dropped equipment) were verified by the coordinator (not the riggers) prior to the lift being performed. The inspectors concluded that the failure to complete the form was an
administrative error and had no impact on the weir gate incident.
The licensee determined that the root cause of the incident was the use of an inadequate softener material used to pad the choker.
Discussions with the investigation's team leader indicated that the choice of a-softener by the riggers was considered to be skill-of-the-craft. and i-that this particular softener (an old weir gate seal) had not been used during the previous-successful lifts. The licensee's corrective actions-included specifying the use of an alternate softener or alternate
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rigging methods for future lifts of this type, and plans for welding lift lugs on the sides of the weir gates. The inspectors were informed that a 10 CFR 50.59 screening will be performed by the licensee-as part of-the lug modification package.
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The licensee's investigation also concluded that the control room was not notified of this incident until approximately two hours-later.
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The investigation team determined that management expectations regarding control room notifications were not clearly understood by all plant personnel and recommended issuance of a communication to plant personnel delineating management's expectations for control room notifications.
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Conclusions lhe inspectors noted two examples of poor practices related to this event: the failure of the lift coordinator to verify a signoff on the lift plan for NUREG 0612 provisions and the selection of inadequate softener material for manipulating the gate.
However, the licensee responded appropriately to the weir gate choker failure and initiated appropriate corrective actions to preclude repetition.
M1.2 Unit 1B Emeraency Diesel Generator (EDG) Failed Doerability Periodic lcit a.
insoectdon Stone (61726)
On September 23, during the operability run of the IB EDG, load swings occurred while the IB EDG was paralleled to the offsite power source.
Similar load swings were observed during an operability test on August 26, in which the IB EDG outptt breaker tripped on an overcurrent condition. The earlier failr a was discussed in NRC Inspection Report 50 413.414/97-11.
The inspectors monitored the licensee's trouble-shooting activities, reviewid PIPS 1-C97-2796 and 1-C97-3076, and the Failure Investigation Process (FIP) root cause evaluation.
b.
Obsertations and Findinas Following the EDG load swings on August 26, the FIP team conducted detailed discussions with the vendor, Power Control Systems, and performed several hours of runs and tests on the IB EDG, Load drift conditions were not repeated.
The FlP team identified the apparent root cause of the output breaker overcurrer.t trip as an intermittent bad connection (presence of contact oxidation) on the motor operated potentiometer (M0P) used for EDG speed and load control.
Prior to
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subsequent EDG runs, the MOP was exercised full-range to wipe contact surfaces of potential oxidation to preclude further load drifts.
The FIP team concluded that emergency operation of the EDG was not affected because the MOP was returned to the 60 hertz position following each test run or each emergency start.
A Plant Operations Review Committee (PORC) meeting was conducted on August 28 to review the FIP teams evaluation, and the 1B EDG was declared operable.
On September 23, during the performance of a scheduled operability test on the IB EDG, load swings were once again noted. The IB EDG was shutdown and declare
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Prior to securing the EDG, voltage readings were obtaint chat indicated that the speed reference input Enclosure 2
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signal to the electronic governor assembly (EGA) was increasing coincident with the unanticipated load increases.
The reference speed value should remain stable exce)t for periods whan the speed raise / lower pushbuttons are pressed.
Tho OG loading had been stabilized by operators at 2500 kW with no further manual load changes being perforned.
The FIP team contacted Woodward Governor Company, who identified three components that could have caused the voltage to increase at the output of the MOP:
(1) the speed raise / lower button. (2) the MOP. and (3) the EGA.
The speed raise / lower button was replaced first followed by the MOP. While re lacing the MOP the licensee disassembled it and noticed that the back late of the potentiometer was se)arated from the body of the r sing.
F rther examinetion revealed that )y lightly pressing on the
- k plate the resistance would increase.
The FIP team concluded that tnis was the root cause of the load drift problem and that the EGA governor was not not implicated and did not need to be replaced.
The defective MOP was sent to the McGuire qualification and testing facility for a detailed analysis.
Subsequent functional runs did not reveal any load drift 3roblems, and a PORC meeting held on September 24 approved declaring tle IB EDG operable.
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Conclusions The inspector concluded that the FIP process used a methodical approach in correcting the load drift occurrences once data were available during actual periods of load drifting.
Upon review of the original FIP team recomnended and completed actiont the inspector noted that the root cause evaluation relied strongly on the vendor recommendation of full-range MOP wiping, and no attemat was made at performing a visual inspection of the installed MO).
The inspectors also concluded that the observed MOP failure mechanism only prevented successful completion of the EDG tests and did not affect the EDG's ability to perform its safety function.
M2 Maintenance and Material Condition of Facilities and Equipment M2.1 helear Sersice Water (NSW) Leak in Yard and on Valve Bodies a.
Insoection Scone (62707)
The inspectors reviewed the circumstances surrounding several occurrences of NSW system leaks over the course of the inspection period, b.
Observations and Findings A NSW piping leak associated with a buried 42-inch B train supply line was identified in the yard on September 18.
Following excavation, a i
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total of 8 pipe repairs were made, including the leaking hole and other areas that were determined by the licensee not to have sufficient wall thickness.
On October 7. a pin-hole leak was discovered in the valve body of 1RN-351. the B train component cooling water (CCW) heat exchanger outlet valve, which was temporarily patched for housekeeping control until it could be repaired during the upcoming Unit i refueling outage (RFO).
Subsequent to the inspection aeriod on October 12.
anoth * pin-hole leak was discovered in the )ody of the corresponding A train valve. 1RN-291. The licensee performed operability determinations for the two valve body pin hole leaks and determined that the observed / measured leakage was within operability requirements for the system and for structural integrity.
The inspector learned of previous problems with system leakage that the licensee attributed to various causes, including nicked exterior coating during construction (in the outside yard cases) and either erosion or manufacturing flaws (e.g., the two CCW heat exchanger outlet valves).
The inspector was concerned with the number of recent leaks in the NSW system. The inspector determin?d that the system's performance warranted further review. This review will be tracked under Inspector Followup Item (IFI) 50 413.414/97-12-01: Assess Licensee's Activities to Resolve NSW Component Leakage Problems, c.
C.onclusions An Inspector Followup Item was o)ened to assess the licensee's activities to resolve leaks in t1e NSW system.
M8 Miscellaneous Maintenance issues (92700)
M8.1 (Closed) LER 50 413/95 d4:
Technical Specification 3.0.3 Entry Due to Annulus Ventilation System Inoperability.
On two separate occasions in August 1995. upper containment control access doors (CADS) did not fully close cecause of a damaged key lock bolt. rendering the annulus ventilation (VE) system inoperable until the doors could be repaired (40 and 35 minutes, respectively).
The inspector concluded that the corrective actions in the LER were adequate.
This LER is clased.
M8.2 (Doen) LER 50-413/97-06:
Missed Technical Specification (TS)
Surveillances on P-11 and P-13 Permissive Interlocks Due to inadequate Procedures.
This LER discussed deficient test procedures that resulted in P-11 low pressurizer pressure safety injection block) and P-13 (turbine impulse pressure 2 10%: input to P-7) permissive interlocks not being tested in accordance with TS 4.3.2.1 and 4.3.1.1 respectively.
This item was Enclosure 2 I
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previously discussed in Inspection Report 50 413.414/97-11.
A violation was issued in that report because the licensee's Generic letter 96-01 review of logic circuit test procedures failed to identify and correct the procedural inadequacies.
The inspector noted that the Event Date reported in block 5 of the LER was shown as August 4. 1997. The Report Date was shown as September 25, 1997, or 52 days past the Event Date.
No explanation was given in the text of the LER as to why the event was not reported within 30 days as required by 10CFR 50.73(a)(1). The inspector discussed this with licensee personnel involved in the investigation and reporting of the event and reviewed background documentation contained in PIP 0-C97-2554 and PIP 0 C97-2f46.
The inspector learned that when the licensee was notified of a potential P 11 testing deficiency on August 4. site personnel successfully tested P-11 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> as allowed by TS 4.0.3 without having to enter the action statement specified in TS Limiting Condition for Operation (LCO) 3.3.2 for an ino)erable interlock. The licensee later completed a review of ot1er test procedures (for P-11 and later P-13) and determined on August 29 that the P-11 and P-13 permissives had not properly been tested in the past, resulting in previous violations of TS 3.3.1 and 3.3.2.
August 29 was the day of discovery ana should have been recorded as the Event Date in block 5 of the LER. or a clear explanation of the apparent discrepancy between the Event Date and the Report Date should have been given in the text of the LER to avoid confusion.
This discrepancy was discussed with licensee management, who had no dissenting comments.
No violations or deviations were identified during the review of this LER. The LER will remain open pending the licensee's completion and the inspectors * review of corrective actions.
11LJnaineerina E8 Hiscellaneous Engineering Issues (92903.37551)
E8.1 DOI Failure Root Ca g e Evaluation ano Corrective Actions Uodate eriod, two separate DOI failures occurred.
During the 'ist inspection p! associated with the 2D steam generator to The failures caused the HSl close, and Unit 2 was manually tripped in response to both equipment failures.
(These events are documented in NRC Inspection Report 50-413.414/97-11.) The licencee hired a contractor to perform a failure analysh of five D01s. including the two from the affected MSIV circuitry and one that had failed in the EDG lube oil system.
Failure analysis results indicated that resistor failures, attributed to manufacturing defects, caused the DOI failures.
Enclosure 2
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_ _._
_
_ _..__ _ ___ _. _._ __. _ __
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The contractor also indicated that the operating history and size of the
!
!
population indicates that a small percentage of the modules are affected.- The licensee has continued to perform weekly testing on
!
continuously energized 00ls in critical applications and is currently
}
planning a modification (in upcoming refueling outages for both units)
'
to the HSIV control circuitry to eliminate the single failure
!
vulnerability to inadvertent closure.
The inspector concluded that the i
testing activities have been appropriate to identify degrading DOI
!
resistors.
Plans to modify the MSIV control circuitry {o alleviate the
'
<
single failure vulnerability to inadvertent closure should be effective in reducing unnecessary reactor trips.
l
- IV. Plant S m rt
R1 Radiological Protection
!
RI.1 General Observations (71750)
l l
Radiological control practices observed during the period were considered adequate.
S1 Conduct of Security and Safeguards Activities j
S1.1 comnensatorv Measures a.
Insoection Scone (81700)
,
The inspector evaluated the licensee's pcogram for compensatory measures
- '
of security equipment that was not functioning as committed to in Section 4.3.1 of the Physical Security Plan (PSP) and procedures.
This was to ensure that the implemented measures were met or exceeded the comitments made by the licensee.
b.
Observations and Findinas Three compensatory measures were operational at the beginning of the
,
inspection.
By the end of this inspection only one compensatory measure remained.
A1 T.ernal gate was inoperable due to a pipe break.
Extensive moi.1enance and repair work had caused the gate to be removed.
.
Appropriate.s ;urity measures compensated for the inoperable equipment i
and consisted of the a) plication of specific procedures to assure that the effectiveness of tie security system was not reduced, c.. Conclusions Through observations, interviews, and documentation review, the inspector-concluded that the licensee used compensatory measures that
ensured the reliability of security related equipment and devices.
This i
Enclosure 2
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evaluation verified that the licensee employed compensatory measures when security equipment failed or its performance was impaired. The inspector found no violations of regulatory requirements in this area.
S2 Status of Security Facilities and Equipment S2.1 Vital Area Access Controls a.
Insoection Stone (81700)
The inspector evaluated the licensee's access control program for allowing packages, personnel, and vehicles to enter the vital areas according to criteria in Section 5.3 of the PSP.
b.
Observations and findinas The inspector's review was to ensure that the licensee provided appropriate access controls for the vital areas.
,
Personnel, hand carried packages or material, delivered packages or material, and vehicles were searched before being admitteu to the protected area and, subsequently, the vital areas.
Security >ersonnel searcheo for firearms, explosives. incendiary devices, and ot1er items that could be used for radiological sabotage. These searches were either by physical search or by search equipment.
Vehicle searches included a search of the cab, engine compartment, undercarriage and cargo areas.
The inspector found the following circumstances concerning personnel access control.
A picture badge identification system was used for personnel who were authorized unescorted access to protected and vital areas. A coded, numbered badge system was used for personnel authorized unescorted access to vital areas. The code corresponded to vital areas to which individuals had authorized access.
Picture badges issued to non licensee personnel indicated authorized access areas and showed that no escort was required.
Personnel displayed their badges while within the vital and protected areas, and returned them upon leaving the protected area.
Visitors authorized escorted access to the vital areas were issued a badge that showed an escort was required, and were escorted by licensee-designated escorts while in the vital area.
Unescorted access to vital areas was limited to personnel who requir?d such access to do their duties.
Security personnel controlled access to the reactor containment when frequent access was necessary to assure that c,nly authorized personnel and material entered the reactor containment.
Access control program records were available for review and contained sufficient information for identification of persons authorized access to the vital areas. The licensee maintained access records of keys key Enclosure 2
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.. - _
.-.
- - -
--
.
cards, key codes, lock combinations, and other related equipment during
,
a person's employment or for the duration of use of these items.
The inspector found the following circumstances concerning control of the entry and exit of packages and material to vital areas.
Security personnel confirmed the authorization of, and identified packages and material at access control portals before allowing them to be delivered.
The licensee used security force personnel to identify 6nd confirm the authorization of material before allowing it to enter reactor containment.
The inspector.found the following circumstances concerning vehicle access control.
Individuals who controlled the admittance control hardware that allowed vehicle access to vital areas were armed, within tne vital area, and had control of the keys that opened the vital areas.
Security force personnel escorted non-designated vehicles while within the protected and vital areas. No vehicles entered the licensee's vital areas during this inspection.
c.
Conclusions This evaluation of the vital area access controls for Jackages, personnel and vehicles revealed that the criteria of tie PSP were implemented.
The inspector identified no violations of regulatory requirements in this area.
S2.2 Protected Area Access Control a.
Insoection Scone (81700)
The inspector evaluated the licensee's program to control access of personnel to the protected areas according to criteria in Chapter 6 of the PSP and appropriate directives and procedures, b.
Observation arid Findinas This was to ensure that the licensee had positive access controls of personnel 2ntering and exiting the protected area.
During a review of numerous PIP re) orts, the inspector noted that a significant number of protected area )adges of terminated personnel were not being deactivated in a timely manner.
Also, the inspector found examples of protected area badges-that were not being returned to security before exiting the protected area.
The licensee identified eight events of protected area badges not being deactivated and/or made unavailable to terminated employees.
These events involved 12 employees that were terminated under favorable conditions. None of the terminated individuals reentered any protected or vital areas. Two events were caused by security personnel and six Enclosure 2
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_______ __ _ _________ -___-_ ______
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events were caused by Duke Power Company (DPC) and contractor / vendor managers.
Dates of the events ranged from August 19. 1996 to June 20.
1997.
Each event was licensee-identified and not willful.
Howevei, the by the licensee'petitive issue that could reasonably have been prevented events were a re s corrective action for praious findings that occurred within the past two years.
The corrective actions were prompt; however, not comprehensive and effective to prevent recurrence.
The licensee's analysis and corrective actions for the eight events were documented in PIPS 0 C96 2418. 0 C96-2666. 0 C96-2958. 0 C96 3028. 0-C96 3238. 0-C97-0285. 0 C97-1444. and 0 C97-2125.
The cause of the events was human error, and was not considered to be programmatic.
These events violated the following directive and procedure:
Nuclear Policy Manual-Volume 2. Nuclear Station Directive 218.
- Notification Responsibilities for Termination, paragraph B.I.
Revision 0, dated June 27. 1996, which states. In ef fect. for voluntary and involuntary termination, that management shall be responsible for verbally notifying site security to delete the terminated individuals badge.
Nuclear Station Security Procedure (NSSP) No. 208. Badging
.
Officer / Specialist, Revision 29. dated March 17. 1997, paragraph 6 which states. in effect, that upon receipt of a Security Badge Transaction lequest form to terminate a picture badge, the badge shall be unassigned through the appropriate security computer program and destroyed, Because of the repetitiveness, ineffective corrective action, and the non compliance with the above references, this failure to destroy and unassign access badges is being identified as Violation 50-413.414/97-12-02:
Failure to Deactivate and/or Deny Protected Area Access to Terminated Employees.
The licensee identified five examples of protected area badges exiting the protected area, uncontrolled.
These examples violated the following:
10 CFR 73.55 (d)(8) states to the effect that access control
.
devices used to control access to protected and vital areas must be controlled to reduce the probability of compromise.
Duke Power Comoany Nuclear Policy Manual-2, Nuclear System
.
Directive: 217. Nuclear Security Program. Revision 2. dated September 16, 1997, paragraph 217.5.3.1. which stated. in effect.
that badges shall remain within the protected area except when under the control of site security personnel.
Further, it required security badges to be dropped into the chuta located at the exit turnstile prior to leaving the facility.
Enclosure 2
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Duke Power Company Nuclear Security and Contingency Plan. Revision
+
6. dated May 13. 1997. Chapter 6. " Access". Paragraph 6.3 which stated in effect. that protected area badges shall remain within the protected area.
NSSP No. 208. Badging Officer / Specialist. Revision 29. dated
March 17. 1997. Paragraph 3.1.4. which stated, in effect, that prior to exiting the protected area, all badges shall be placed in the drop chute at the badging office.
The dates of the events ranged from January 6, 1997, to August 22. 1997.
Each event was licensee-identified and not willful.
However, the events were a repetitive issue that could reasonably have been prevented by the licensee's corrective action for previous licensee findings that occurred within the past two years.
The corrective actions were prompt:
however, not comprehensive and effective to prevent recurrence.
The licensee's analysis and corrective actions of the five events were documented in PIPS 0 C97-0029. 0 C97-1164. 0 C97-1669. 0 C97-2409, and 0 C97-2753.
The causes of the events were human error, and were not considered to be programmatic.
Because of the repetitiveness of these events. ineffective corrective actions, and non compliance with the above references, these events are being identified as Violation 50 413.414/97-12 03:
Failure to Control Protected Area Access Badges.
'c,
Conclusion This evaluation found two violations of the access controls for personnel that were contrary to the criteria in 10 CFR 73.55. Chapter 6 of the PSP NSSP No. 208, and Nuclear Station Directive 218.
S2.3 Alarm Stations and Communications a.
Insoection Scooe (81700)
The inspector evaluated the licensee's dlarm stations assessment aids, and communication equipment to ensure that the application of the criteria in Chapter 8 of the PSP and NSSP No. 211. Central Alarm Station (CAS)/ Secondary Alarm Station (SAS) Operators. Revision 26. dated October 23. 1996. were implemented.
b.
Observations and Findinas The inspector verified that annunciation of protected and vital area alarms occurred audibly and visually in the alarm stations.
The licensee equipped both stations with closed circuit television (CCTV)
assessment capabilities and communication equipment.
Alarms were tamper-indicating and self-cherking, and provided with an Enclosure 2 i
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i
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uninterruptable power supply. These stations were continually manned by capable and knowledgeable security operators.
The stations were independent, yet redundant in operation. Alarm station's interiors were not visible from the protected area, and no single act could remove the capability of calling for assistance or otherwise responding to an alarm.
Alarm stations' walls, doors, floors, and ceilings were bullet-resistant.
The licensee provided means for monitoring and observing, by human eye or CCTV, persons and activities in the isolation zone and exterior areas within the protected area.
These means provided f r assessing intrusion alarms for possible threats occurring in the isolation zone and exterior areas within the protected area.
The transmission and control lines used in the CCTV intrusion alarm assessment system had line supervision and tamper indication.
The inspector evaluated the equipment, operation, and maintenance of internal and external security communication links, and determined that they were adequate and appropriate for their intended function.
Each security force member could communicate with an individual in each of the continuously manned alarm stations, who could call for assistance from other security force personnel and from local law enforcement agencies.
The alarm stations had the capability for continuous two-way voice comunication with local law enforcement agencies through rad 10 and the conventional telephone service.
The licensee had compensatory measures for defective or inoperable communication equipment, c.
Conclusions Based on this evaluation, the inspector concluded that the licensee was complying with the criteria in Chapter 8 of the PSP and NSSP No. 211.
No violations of regulatory requirements were found in this area.
S2.4 Testina and Maintenance a.
Insoection Scone (81700)
The inspector evaluated the licensee's program for testing and maintenance of security equipment. This was to ensure the reliability of physical protection-related equipment and security-related devices:
and the licentee's compliance with the criteria in Chapter 9 of the PSP:
NSSP No.311, Metal / Weapon Detection Equipment Operability and Test, Revision 5: NSSP No. 303. Explosive Detector Operability and Test, Revision 4: NSSP No. 301, Annual Protected Area Micro Wave Test, Revision 1. dated July 10. 1997: and NSSP No. 505. Control Access Door Performance Test Procedure, Revision 6. dated June 1, 1994.
Enclosure 2
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b.
Observations and Findinas The licensee's program for testing and maintenance of security equipment was established to ensure that physical protection related equipment met the general performance recuirements.
Two individuals were permanently assigned to the testing anc maintenance of security-related devices and equipment.
Each intrusion alarm v s tested for performance at the beginning and end of any period in which it was used and at least every seven days during continuous use. Alarm station operators tested the communication equipment required for onsite communication for performance at least at the beginning of each security work shift.
Communication equipment required for of fsite communication was tested at least once a day.
The inspector observed the testing and subsequent maintenance, if needed, of the metal and explosive detectors at the Personnel Access Portal, the Annual Protected Area Micro Wave Test, and the Control Access Door Performance Test.
Each area / item tested was found operable according the documented commitments.
c.
Conclusion Through observations and interviews, the inspector concluried that the licensee used programs that will ensure the reliability of security-related equipment and devices.
The testing and maintenance program was a strength in the security program.
No violations of regulatory requirements were found in this area.
S3 Security and Safeguards Procedures and Documentation 53.1 Security Proaram Plans a.
insoection Scone (81700)
The inspector reviewed aopropriate chapters of the licensee's PSP, Revision 06, dated May 13, 1997.
b.
Observations and Findinas The inspector reviewed Revision 6 to the hP and verified compliance to the requirements of 10 CFR 50.54( D.
Most of the changes were grammatical, and position / title c1anges.
Necessary coordinating changes were also incorporated for the consolidated PSP for each of the three Duke nuclear power plants.
Review of the PSP revealed no plan items that were contrary to regulatory requirements.
Enclosure 2
.
.
c.
Conclusions The random review of plans, records, re) orts, and interviews with a)propriate individuals verified that c1anges did not appear to decrease t1e effectiveness of the PSP.
No violations of regulatory requirements were found in this area.
53.3 Security Events Loos a.
Insoection Scone (81700)
Evaluate and verify that the licensee ;ppropriately analyzed, tracked, resolved, and docunented safevuoras events that the licensee determined did not require a report to the NRC within one hour.
b.
Observations and Findinos During the review of the PIPS documenting the issue of security not being notified of the termination of personnel who had unescorted access to the protected and vital areas. the inspector noted that a Duke Power Company Nuclear Security Manual. Reporting and Trending of Safeguards and Security Events Directive. Revision 11. dated August 1, 1996.
Appendix B. provided an exception to 10 CFR 73. Appendix G. " Reportable Safeguards Events."
In the above referenced directive, the licensee had authorized the following for security access badges being available for issue after personnel termination:
Nnn-safeguards Events (not reportable)
A security badge being available for issue to an individual whose
.
access should have been restricted (under favorable conditions)
and is identified and deleted during the appropriate 31 day review.
Logged (reportable)
Discovery of a security badge being avr.ilable for issue to an
.
individual whose access should have been restricted (under favorable conditions) and was not identified during the appropr'. ate 31 day review.
No access is gained.
Discovery of a security badge being available for issue that could
.
have allowed an unfavorably terminated employee access to the protected area and access is not gained by the terminated employee.
.
Enclosure 2
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-..... - _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
_
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10 CFR 73.71 (Reporting of Safeguards Events)(c) requires licensees subject to the provisions of 73.55 to maintain a current log and record the safeguards events described in paragra)h II (a) and (b) of Ap G to Part 73 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of discovery )y a licensee employee.pendix Appendix G to Part 73, pacagraph II(a). requires the following events to be recorded within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of discovery in the safeguards event log:
Any failure, degradation, or discovered vulnerability in a safeguards system that could have allowed unauthorized or (
undetected access to a protected area....
The licensee revised the Reportability Directive, effective January 1, 1994.
Thc licensee changed the period that a security badge can be available for a favorably terminated employee and not considered loggable to 31 days based on the requirement for a management review of vital area access authorization lists at least once every 31 days (10 CFR 73.55(d)(7)(1)(A)).
The licensee's Reporting and Trending of Safeguards and Security Events Directive. Ap)endix B under the Non-safeguards Events section is contrary to tie criteria of Appendix G to Part 73.
This issue is being identified as Violation 50-413.414/97-12-04:
Failure to Comply With Regulatory Requirements of Appendix G of 10 CFR Part 73.
As a result of Nuisance Alarm Rates (NAR) exceeding security plan commitments found at another Duke site. the inspector reviewed the PIPS for other adverse trends and similar nuisance alarm rate aroblems.
Five events since the beginning of the year were found where t7e NAR exceeded the cc Litment in the PSP. Chapter 8. paragraph 8.3.1.2.
This commitment states that a nuisance alarm (NA) rate of not more than one NA per zone per day, when averaged over a period of not more than 10 consecutive days for all zones shall be considered acceptable.
The licensee attributed the NAs to unusual severe weather and birds in the isolation zones.
These events were documented in the PIPS 0-C97-0571. 0-C97-1103, 0-C97-1379. 0-C97-1625. and 0-C97-2047.
Recognizing an emerging degrading trend the licensee initiated PIP 0-C97-2603.
This resulted in a program evaluation showing that the root courac Qr the degrading trend were:
(1) improper alarm response by 21.::r.i station operators: (2) severe weather: and (3) faulty equipment.
The NA rate has significantly decreased. and has not exceeded the PSP commitment since July 1997. The licensee's thorough analysis. timely corrective actions, and superior management support as a result of the last PIP. was considered a strength in the self-assessment program, c.
Conclusion The evaluation of the licensee's Security Event logging /Reportability program identified one violation of regulatory requirements. Otherwise.
Enclosure 2
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the licensee appropriately cnalyzed, tracked, resolved, and documented safeguards events through the PIP program.
Security's application of the DIP program was a strength.
SS Security Safeguards Staff Training and Qualification S5.1 Security Trainina and Qualification a.
Insoection Scoce (81700)
The inspector interviewed security personnel and reviewed security personnel training and qualification records to ensure that the criteria in the Security Personnel Training and Qualification Plan (T&OP) were met.
b.
Observations and findinas The inspector interviewed 7 security mn-supervisor personnel, 3 supervisors, and witnessed approximately 12 other security personnel in the performance of their duties.
Members of the security force were kr.owledgeable in their responsibilities, plan commitments and procedures.
Four randomly selected training records were reviewed by the inspectors concerning training, firearms, testing, job / task performance, and requalification.
The inspector found that armed response oersonnel interviewed had been instructed in the use of deadly force as required by 10 CFR Part 73.
Members of the security organization were requalified at least every 12 months in the performance of their assigned tasks, both normal and contingency. This included the conduct of physical exercise requirements and the completion of the firearms course.
Through the records review and interviews with security force personnel, the inspector found that the requirements of 10 CFR 73. Appendix B.
Section 1.F. concerning suitability, physical and mental qualification data, test results and other proficiency requirements were met.
During the evaluation of protected area search equipment at the protected area access portal and interviews with Personnel Accest Portal Officers (9AP0) and the Protected Area Access Officer (PAAO). the inspector observed that the search equipment had been rearranged.
This rearrangement changed the duty requirement of the two access officers.
The PAPO previously monitored two search equipment items.
The rearrangement increased the responsibilities to three search equipment items.
The PAA0 previously monitored one search equipment item.
The rearrangement reduced the responsibilities to no search equipment items.
Observation of the access process of plant personnel during a morning peak period indicated that the personnel traffic flow through the access area was congested and could not be controlled easily. However, due to the professional initiative and dedication of the two officers at the Enclosure 2
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_ _ _ _ _ _ - _ -
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search area, the situation was controlled.
Interviews with security management indicated that there should have been three officers at the search area to helo during this transition of the rearrangement.
Interviews with PA)0s and PAAQs indicated that there was a lack of training on the new responsibilities and expectations of these officers before the rearrangement.
The ins)ector noted that the Protected Area
,
Search / Ingress Process Directive.
Revision 0, dated October 1. 1995.
Security Procedure No. 206, Personnel Access Portal Officer, Revision 9.
dated July 10, 1997, and the PSP. Chapter 5 had not been changed / updated to reflect the physical rearrangement of the search equipment and duty responsibilities of the respective officers. After briefing security management on the observations of the search area durino the morning peak period, a " PRE-JOB BRIEF ITEM." subject Personnel 4ccess Portal, dated September 24, 1997, was issued.
There was no violation of existing commitments, and security managemt t's actions were timely to correct the inspector's observations.
This issue was considered a weakness in the security process to 3repare for the eventual installation of hand geometry into tle security program.
c.
Conclusions The security force was being trained according to the T&QP and regulatory requirements. A weakness was found in the training of access control personnel concerning the rearrangement of the search equipment.
There were no violations of regulatory requirements identified in this area.
V. Management Heetings X1 Exit Heeting Summary The inspector presented the inspection results to members of licensee management at the conclusion of the inspection on October 16. 1997.
Preliminary exit meetings were held on September 25 and 26 for the security inspection. The licensee acknowledged the findings presented.
No proprietary information was identified.
Enclosure 2
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PARTIAL LIST OF PERSONS CONTACTED Licensee M. Birch, Safety Assurance Manager M. Boyle, Radiation Protection Manager T. Byers Security Manager S. Copp Nuclear Regulatory Affairs Manager B. Emons Organizational Effectiveness Manager J. Forbes. Engineering Manager R. Glover Operations Superintendent R. Jones, Station Manager K. Nicholson, Compliance Specialist M. Kitlan, Regulatory Compliance Manager G. Peterson, Catawba Site Vice President R. Propst, Chemistry Manager l
IBC C. Ogle, Chief. Branch 1. DRP. Ril P. Tam, Project Manager, NRR Enclosure 2
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i INSPECTION PROCEDURES USED IP 37551:
Onsite Engineering IP 61726:
Surveillance IP 62707:
Maintenance Observation IP 71707:
Plant Operations IP 71750:
Plant Support Activities IP 81700:
Physical Security Program for Power Reactors IP 92700:
Onsite Review of Event Reports IP 92903:
Engineering Followup IP 40500:
Effectiveness of Licensee Controls in Idtntifying and Resolving Problems ITEMS OPENED. CLOSED, AND DISCUSSED Onened 50 413,414/97-12 01 IFI Assess the Licensee's Actions to Resolve Nuclear Service Water System Leaks (Section M2.1)
50 413.414/97-12 02 V10 Failure to Deactivate and/or Deny Protected Area Access to Terminated Employees (Section S2.2)
50 413.414/97 12 03 VIO Failure to Control Protected Area Access Badges (Section S2.2)
50-413.414'9-12-04 VIO Failure to Comply With the Regulatory Requirements of Appendix G of 10 CFR Part 73 (Section S3.3)
Closed 50 413/95-04 LER Technical Specification 3.0.3 Entry Due to Annulus Ventilation System Inoperability (Section M8.1)
Discussed 50 414/95 01 LER Reactor Trip Due to Closure of a Main Steam Isolation Valve (Section 08.1)
50-413/97-06 LER Missed Technical Specification Surweillances on P-11 and P-13 Permissive Interlocks due to Inadequate Procedures (Section M8.2)
Enclosure 2
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LIST.0F ACRONYMS USED j
i Control Access Door CAD
--
Central Alarm Station
'
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CCTV:
Closed Circuit Television
-
- - -
Component Cooling Water
. Code of Federal Regulations
~
CFR
-
.
Direct Current i
-
Digital Optical Isolator-i
- 001
-
Duke Power Company-i DPC
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Division of Reactor Projects
!
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EGA
--
- Electronic Governor Assembly
!
Emergency. Diesel Generator-EDG e
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Failure Investigation Process FIP
. -
- -
-
Inspector Follow up Item
'
IFI
-
IR
' -
' Inspection Report
,
- KW
'
Kilowatt n
-
LER
-
Licensee Event Report
!
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'
M0P
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Motor Operated Potentiometer-
- -
-
MSIV Nuisance Alarm NA
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Nuisance Alarm Rates
!
NAR
- -
Office of Nuclear Reactor Regulation NR"
-
Nuclear Safety Review Board NSRB
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Nuclear Station Security Procedure NSSP
-
. '
Nuclear Service Water
.
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PAA0 --
Protected Area Access Officer Protected Area Portal Officer i
PAPO
-
PCB
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Power Circuit Breaker
-
- -
- Problem Investigation Process (Report)
!
- PORC. -
Plant Operations Review Comittee
- -
Preventive Maintenance PM
PSP Physical Security Plan
-
= R I-
- '
Refueling Outage
RF0
-
Region Two-
-
Secondary Alarm Station
SAS-
-
"
Spent Fuel Pool SFP-
-
T&OP -
Training and Qualification Plan
- -
Technical -Specification
TS.
.
.
'
UFSAR~-
Updated. Final; Safety. Analysis Report
- -
Volts Alternating Current VAC
'
VE-
-Annulus Ventilation
= -
- VIO
- -
-Violation-
,
WO.
- --
. Work: Order
i Enclosure 2
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