IR 05000219/1990011
| ML20058Q443 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 08/15/1990 |
| From: | Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20058Q439 | List: |
| References | |
| 50-219-90-11, NUDOCS 9008220079 | |
| Download: ML20058Q443 (63) | |
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION I
Report No.
50-219/90-3 Docket No.
50-219 License No.
DPR-16 Priority --
Category C Licensee:
GPU Nuclear. Corporation 1 Upper Pond Road
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parsipgtny, new Jersey 07054 Facility Name: Oyster Creek Nuclear' Generating Station
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Inspection Conductedi June 10,1990 - July 11,1990 i
i Participating Inspectors:
M. Banerjee, Resident Inspector, Oyster Creek
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E. Collins, Senior Resident Inspector, Oyster Creek
D. Dempsey, Resident Inspector, Millstone 1 Approved By:
M EkuTand, tiiief~_ _
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ate Reactor Projects Section 4B
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i I_nspection Summary:
Inspection Report No. 50-219/90-11 for June'10,1990 - July 11,1990 Areas Inspected:
The inspection consisted of 168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br /> of direct-inspection by
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the inspectors.
The areas inspected included observation and~ review of plant operations (paragraph 1.0); review of radiological controls (paragraph 2.0);
routine observations of maintenance ' activities and surveillance' tests (para-t graph 3.0); a review of the diesel generator switchgear mounting and the control rod drive hydraulic system repair (paragraph 4.0); and general employee training (paragraph 5.0).
Resuly:
An unresolved item related to the operation of the plant at a power level above the licensed power limit is being closed as a non-cited violation. The licensee identified a non-cited violation when a reactor operator failed to trip the running CRD pump after a scram as required by the emergency operating
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procedures.
An executive summary follows, 9008220079 900913 PDR ADOCK 05000219
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TABLE OF CONTENTS
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E x e c u t i v e S umma ry. ;.................... -...
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l II. Details...............................
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1.0. Operations (71707, 93702)....
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o 1.1 Chronology of Operational Events _..............
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1.2 Reactor Trip on Low Vacuum........ -...
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.1 1.3 Selected Procedure Reviews <
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1.4 (closed) Unresolved Item 50-219/90-09-01..........
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1.5 -Control Room Tours'.-....... s.
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1;6 Facility Tours
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2.0 Radiological Controls (71707)........:......
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2.1 Uptake Received by Workers........
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j 2.2 Radiation Protection...,..................
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3.0 Maintenance / Surveillance (62703, 61726)...-.......
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i 3.1 Monthly Maintenance Observation..
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q 3.2 Monthly Surveillance Observation...............
3 4.0 Engineering and Technical Support (93702)....=....
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j 4.1 Diesel Generator Switchgear Mounting.'..',......-....
4.2 Control Room habitability....
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4.3 Control Rod Drive.......................
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5.0 Safety Assessment / Quality Verification-(71707).....
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I 5.1 General Employee Training,...........,.-
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L 6.0 Inspection Hour Summary.. :.......
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7.0 Meetings (30703, 30702)......... '
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l 7.1 SALP Management Meeting,......
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L 7.2 Preliminary Inspection Findings'...............
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7.3 Attendance at Exit Meetings Conducted by. Region Based j
Inspectors.-.........
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i-ATTACHMENTS-
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Attachment I:
List of SALP Meeting Attendees-Attachment-II:
NRC SALP Overview and_ Findings
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Attachment III:: Licensee SALP Presentation-
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION I
EXECUTIVE SUMMARY
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Oyster. Creek Routine Resident Inspection Report No. 90-11
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Operations q
Overall, the plant was operated in a safe manner.
Operator. action during: a reactor scram on low condenser vacuum resulted in an orderly shutdown of the plant. The low condenser vacuum condition occurred during.backwashing when a.
d circulating water system valve malfunctioned.
The licensee.has established additional precautions for condenser backwashing and is reviewing the need to'
provide further procedural guidance and additional instrumentation for the control room operators.
Licensee's corrective actions-were found adeauate for the May 11, 1990 event
during which the reactor was operated slightly above the licensed power limit e
of 1930 MWth for about five hours.
An input to the computer heat balance
calculation was deleted when the reactor water cleanup system was removed for-i
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service, bat this input was not inserted when the system was brought back to service.
The licensee has established additional controls on inputs.to the
computer heat balance calculation and is reviewing the need for hardware changes.
e Radiological Controls r
Two incidences of radiological intake by plant workers were reviewed.. In.both l
cases, the amounts of intake were well below the regulatory limits. One
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incident involved skin contamination and. intake while repacking a valve in the shutdown cooling heat exchanger room.- During'the other' incident, workers
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received intake while decontaminating pipes in the condenser bay area. These events indicate inadequate planning and poor understanding of the radiological hazards involved in working with contaminated systems.
Licensee's. root cause analysis and corrective actions for the incident in the condenser bay. area has.
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been determined to be adequate. At the end of this inspection period, the.
licensee was' completing needed corrective actions for the incident-in the shutdown cooling room.
Maintenance / Surveillance
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During tightening of an 1,olation co'ndenser steam valve packing, the inspector-
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noted certain discrepancies.
The licensee deviated from the-work package requirements in that a higher torque was applied to the packing in response to.
vendor engineering representative's verbal directions.
The increased torque t
value was technically acceptable. The licensee stated that they needed to.
revise station procedu es to address the acceptability of verbal guidance and approval from enginee'ing.
Engineering and Technical-Support
The licensee found that the station emergency diesel generators and the associ-ated switchgear cubicles were not anchored to the concrete floor.
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determined that the diesel skid _was configured according to plant drawin.gs and did not require any anchoring to the concrete floor for functionality during a seismic event. The switchgear cubicle, however, was required to be anchored to the floor.
-The licensee's calculation showed that the switchgear cubicle would not overturn during the original safe shutdown earthquake (SSE) level and also no. sliding would occur at an operating basis earthquake (OBE).. The licensee concluded that based on the conservatism involved in the calculation, the functionality of the switchgear was assured during a seismic event.
Instead of a detailed analysis to-prove functionality of the switchgears at the-SSE level, the licensee decided to anchor the switchgear cubicle to prevent.
sliding. During a conference call with the NRC on June 13, 1990, the licensee committed to provide the anchors within seven days. The anchors were installed within this time frame.
Extensive maintenance work to the control rod drive (CRD) system was necessary
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af ter the licensee experienced problems with notch withdrawing the control
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rods.
Flow through the stabilizing valves was found out of calibration with
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filters plugged.
Various control valves and the re:ctor manual control system timer needed maintenance.
Lack of an effective preventive maintenance program resulted in a degraded control rod drive hydraulic system.
The licensee is implementing a preventive maintenance program for this' system.
Safety Assessment / Quality Verification Increased instructor involvement and commitment to improve radiological l
awareness of workers were noted during a General Employee Training session.
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DETAILS
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1.0 Operations 1.1 Chronology of Operational Eveng Inspectors reviewed details associated with key operational events that occurred during the report period.
A summary of these inspection activities follows..
06/10/90 T'he inspection period began with the' reactor at full
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power.
06/17/90 Control rod 18-11' could not be moved using the rod -
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notch switch during performance of Surveillance Test' 617.4.002,_
kcvision 8, "CRD Exercise -and Flow Test /IST." The. rod could be moved using the notch override switch..The rod was declared inoperable and valved out of service fully inserted, i
Later, on 06/17/90, an engineering evaluation fetermined that
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control rod 18-11 cou'.d be withdrawn ~to position 06 while still-meeting Technical Specification requirements in 3.2.a for core reactivity.
The centrol rod.was withdrawn to. position 06.and-valved out of servsce.
06/21/90 Reactor power was reduced to' lower radiation;1evels in
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the condenser bay to redure ine radiation exposure associated with work on the 1-2 auxiliary flashtank drain pump motor.
The pump motor was grounded the day before when the 1-3 sump had a high water level due to improper functioning'of.the sump pumps.-
Control rod.18-11 was declared operable 'per engineering evaluation.
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Repairs were completed to the 1-2 auxiliary flashtank pump motor, and power ascension was started, j
Late on 06/21/90, difficulty was experienced using-the control:
rod notch switch.
Notch override was necessary for 'most 'of the
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control rods. The licensee began investigating _possible reactor manual control system timer problems.
Inspectors observed portions of the power-ascension,on 6/21/90.
No unacceptable conditions were identified.
06/22/90 Troubleshooting of the difficulties.in notching
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control rods led the licen'see to perform corrective maintenance on both pairs of_ control rod drive hydraulic stabilizing valves.
This is reviewed in paragraph 4.3.
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06/23/90 Reactor power was reduced by approximately 200 MWe to
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perform main condenser backwash evolutions.
This was done because of concerns with the "C" condenser vacuum which was indicating low relative te the other condenser bays.
The licensee concluded that the vacuum indication was not operable and was falsely indicatiag low. After completion of backwash evolutions, power ascennion was started.
Full power was achieved Ot approximately.30:55 p.m. on 06/23/90.
06/25/90 A't 6:18 a.m., a reactor _ scram on condenser low vacuum
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was received during backwash evolutions on the "A" condenser.
v The cause of scram was a malfunctioning' circulating water valve.
This malfunction led to loss of cooling water to the condenser and the resulting loss of vacuum.
This event is reviewed in
paragraph 1.2.
06/26/90 At 8:55 p.m. a spill was reported on the 51 ft. and 23
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ft. elevations of the reactor building.
The spill occurred
during filling and venting evolutions on the Shutdown Cooling i
System. At the end of the inspection period the licensee was completing a critique on this event.
06/26/90 Stroke time testing of control rods showed that maintenance on th: :.tt.bilizing valves and the filters had caused control rod stroke times to move out of specification.
This is reviewed in paragraph 4.3.
06/27/90 At 8:00 a.m., reactor temperature was below 212
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degrees.
07/03/90 While performing an IRM front panel test, a test
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jumper fell off.
This generated an MSIV isolation and the open MSIVs closed.
Since the reactor temperature was less than 212
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degrees F and the mode switch was in the refueling position, no transient occurred.
The licensee made the required-
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notification, prepared a deviation report, reinstalled the jumper and opened the MSIVs.
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07/04/90 At 5:08 a.m., a reactor startup was begun and the
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licensee placed the mode switch-in sta'rtup.
Criticality was achieved at 6:13 a.m.
The mode switch was placed in run at 6:55
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p.m. and the turbine generator was placed on line at 10:07 p.m.
07/06/90 At 7:10 a.m.,
a spill from the boiler house occurred
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when a relief valve in auxiliary boiler No. 2 lifted.
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licensee estimated that 50 gallons of water were' sprayed on the boiler house roof in the form of fine mist.
Earlier, the-boiler-had been secured with the steam supply-valves closed.
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to the boiler was left open with the level consroller in normal.
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The level controller then malfunctioned, thus pressurizing the
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'3 boiler, resulting in the spill.
The licensee sampled the, soil around the boiler house and the storm drain outside the boiler house._ The sample analysis showed no detectable radioactivity.
The licensee monitors boiler water activity daily. The boiler water sample showed a 1.47E-04 vei/ml activity level. The licensee estimated 0.28 pc1 were released.
Personnel who were sprayed were frisked for radioactive contamination, and none was found.
Based on this information, the inspector concluded that the release presented no radiological hazards.
At the end 'of the inspection, the licensee was evaluating the event to identify the root cause and corrective actions.
07/09/90 At 7:05 a.m. the plant entered a seven-day. Technical
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Specification action statement when the No. 2 emergency diesel generator did not meet the surveillance test acceptance criteria after prevantive maintenance.- During diesel unloading, the load osc111ated ar.1 the breaker did not trip at 350 + 100 kw as
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required.
The breaker was manually tripped.
Also, the operator
noticed slow cranking during reduced voltage start of the
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diesel. The diesel generator was declared inoperable. At the end of the inspection period the licensee was troubleshooting the problem.
07/11/90 The licensee made an emergency notification system
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(ENS) notification when 10 out of 58 emergency notification sirens failed the. biweekly silent test.
The-licensee determined the failure to be related to the storm and-lightening strike that happened two days prior.
The quarterly emergency plan drill was performed.- The NRC did not participate.
1.2 Reactor Trip on Low Vacuum On June 25, 1990, at approximately 6:18 a.m., while performing backwash evolutions on the "A" condenser waterbox, one circulating water valve, V-3-18, started to open and then stopped when its electrical breaker tripped. This valve is the backwash outlet valve and must'open to establish circulating water path during backwash evolutions.
Because of the loss of cooling water, vacuum decreased from approximately 27.2 in. Hg to 24.6 in. Hg in about a minute.
Reactor operators responded to the lowering vacuum by initiating -
actions to reduce reactor power.
The operator also called an electrician and directed him to the motor control center to reset the breaker for valve V-3-18.
A reactor scram signal was received on low vacuum.
The reactor was at full power.
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Although the post transient reactor water level was controlled within acceptable bands, the licensee decided to have Technical Functions perform-a detailed review of the level response by Technical Functions.
The target completion date for.this review is July 31, 1990.
Not tripping the control rod drive hydraulic pump at 170 inches reactor water level is a violation-of the plant emergency-operating procedures (EOP). However, this is not cited, as the criterion of-
10 CFR Part 2 Appendix C paragraph G.1 was met, in that'the nonconformatince was identified by the licensee, timely corrective action was taken, and the intent of the E0P to: maintain water level below 180 inches was achieved.
Inspectors had no other questions regarding control room operator response to control reactor water level.
(NCV 50-219/90-11-01)
- During the transient, the low vacuum scram was received at control room indication of 24.6 inches in the affected waterbox. The actual scram setpoint. is between 23.65 and 2;.0 in. Hg vacuum.
The licensee evaluated the adequacy of the &ctual trip setpoints. During subsequent plant cooldown and loss of_ vacuum under_relatively steady
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conditions, the licensee verified the low vacuum scram was received at approximately 23.9 inches as indicated by control room instrumentation.
Licensee evaluation concluded the actual scram setpoint had not drifted high. The difference in vacuum indication and the scram setpoint are due to transient conditions'in' the condenser.
The inspector had no other questions regarding the scram setpoint for low vacuum.
l Two control rods,18-23 and 38-47, settled at position 02 af ter the scram. Station Procedure 617.4.0 10 requires testing control rods-that settle at position 02 after the scram. The testing checks for leaHng scram outlet valve or insert directional control valve and verifier stall flow.
This testing identified'no deficient
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conditions. A control rod settling at 02 after a scram does not pose a reactivity concern.--The inspector had no other questions.
Licensee _ troubleshooting of circulating water system valve V-3-18 identified loose and cocked auxiliary contacts _in the motor control center.
These contacts'were' replaced.
A motor operated valve current trace showed full travel with no valve binding. During the l
outage, two other circulating water system valves-indicated a problem l
during cycling and were found to have deficiencies associated with-the' breakers.
The licensee replaced or cleaned the' contacts. _The l
current traces on the remaining 20 circulating water valves were
reviewed. No deficient conditions were identified as a result of
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this testing.
The licensee is reviewing'the periodic preventive maintenance program for the becakers for needed. improvements.
The licensee is also installing _ chart recorders on certain circulating water valves to monitor performance.
The inspector had no other-i e
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4-After the receipt of the reactor scram, reactor water level decreased, reaching a low of approximately 97 inches.-
Reacter level setdown actuated, and the operator secured two feedpumps.
Reactor water level recovered to normal (about.160 inches) and then continued to rise.
The operator secured the remaining feedpump and closed the feedwater heater train outlet valve. Concurrently, reactor water cleanup letdown flow was increased and reactor recirculation flow was
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slowly lowered.
Level reached a peak of about 175 inches and was
then controlled in the normal band.
Plant Transient Response and Control Room Operator Response The licensee convened a Post Transient Review Group (PTRG) to review plant response and control room operator response.
Inspectors observed portions of the PTRG review, Licensee review of the reactor water level control during the event concluded that level setdown and feedwater level control systems worked properly. Manual operator actions adequately controlled level i
below 180 inches.
N erator actions to control reactor water level l
were adequate ex the control rod drive hydraulic pump was not
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tripped at 170,in,
.2 as' directed by procedures. To remind operators of this need, the PTRG report is required reading for all operators.
Licensee troubleshooting of feedwater regulating valve:s identified that the "A" regulating valve leaks approximately 200 gallons ~per minute, but this was not considered to be the'cause of the higher than expected level.
This was attributed to the reduction in recirculation flow which caused the reactor water level to " swell" above its normal band.
Because of the increased level, control room operators raised reactor water cleanup letdown flow to approximately 300 gallons per minute.
This flow rate caused heat addition to the nonregenerative heat
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exchanger (NRHX) above-its capacity, and the system isolated on high a
temperature. Operators responded-to establish a-gravity letdown flowpath to control reactor water level.
The. licensee has identified the need to improve the procedure guidance on the reactor water cleanup system.
Currently the reactor water cleanup procedure, Station Procedure 303, does not provide specific guidance on limitations for operation while using the letdown-flowpath Target
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completion date for this change is August 31, 1990, Licensee evaluation of the chemistry and the resins'in the reactor water cleanup system identified no deficient conditiont The licensee is also evaluating the possibility of-adding NRHX outlet temperature indication to the control room to assist-with operation of the system.
Current indication isLlocal.
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questions regarding the operation of the motor operated circulating water valves.
Licensee practice during condenser backwash evolutions has been to have an electrician available in case a circulating water valve-malfunctions.. In this event, the electrician was available but was
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unable te operate the circulating water valve in time to avert an automatic reactor scram..The licensee has revised the backwash
procedure to require'the electrician to be stationed at the appropriate motor control center during backwash.
In addition, the-licensee has revised the procedure to specify-a 10 second time delay between backwash switch manipulations.
This time delay will allow the control room operator to verify correct valve operations before isolating circulating water flow to the condensers.
No unacceptable conditicns were identified.
The initiating event for this reactor scram was equipment malfunction.
All plant safety systems functioned as required, and overall operator response was, acceptable. Whi.< reactor water level was controlled within a safe band, the failure to trip the operating
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control rod drive hydraulic pump contributed to high reactor water
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operator establishing high reactor water cleanup letdown flows r 'd a
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subsequent high temperature, isolation.of the system.
Licensee identification of these conditions and subsequent corrective actions are adequate. Overall plant equipment response was acceptable. The
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inspector had no other questions.
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1.3 Selected Procedure Reviews Inspectors reviewed Station Procedure 303. " Reactor Cleanup.
Demineralizer System," Rev 32, Sections 3.3 and 5.4.
These sections give operating instructions to establish:the letdown flowpath from.
the reactor water cleanup system.
The instructions were reviewed against process and instrumentation drawing GE 148F444. No.
l unacceptable conditions were identified.
See paragraph 1.2 for
additional discussion on Procedure 303.
Inspectors reviewed Station Procedure 305, " Shutdown Cooling System Operation," Rev. 38, Section 2.0, for filling and venting the Shutdown Cooling System.
The instruction steps of-this' procedure were compared to process and instrumentation drawing GE 148F711, Revision 24.
The inspector identified two valves (V-17-82 and
V-17-83) which were open in procedure step 2.3.7 and not subsequently instructed to be closed.
The licensee implemented a procedural
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change to incorporate the closing instructions for these valves.
The-inspector concluded that this procedural deficiency did not contribute to.the spill which occurred on June'26,'1990, during filling and venting of the Shutdown Cooling System.
The inspector also concluded that this procedure deficiency had little safety
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significance since the operator would have to shut the vent va.lves to stop the flow of water.
The inspector had no other questions.
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Inspectors reviewed Station Procedure 201.2, " Plant Heatup to Hot Standby," Rev. 38, and questioned the basis for step 4.16.1.1 which requires that if the condenser vacuum alarms have not automatically.
reset, one must manually reset the switches at the front standard of the turbine.
The licensee resp aded that under conditions of high canal water temperatures during a plant startup, the vacuum estab-lished in the condenscr is not always sufficient to reset the low vacuum alarm.
There is a dead band between the nominal low vacuum alarm setpoint of 25 inches and the reset point.
The purpose of this step is to direct manual action to reset the alarm if it is above the alarm setpoint and has not automatically reset.
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inspector also reviewed surveillance test 619.3.0.14, " Condenser Low Vacuum Calibration,"' test results from April 1990 and observed that the reset point for the low vacuum alarm varied from approximately 26.5 to 27.5 in. Hg vacuum.
The as left trip setpoints for the low vacuum alarm and the low vacuum scram were within specification, j
No specification exists for the low vacuum alarm reset. point.
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inspector had no questions.
Inspectors reviewed Station Procedure 310. "Containmen. Spray System
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Operation " Rev. 37, Step 9.3.8.6 which specified using a bolt tightening sequence shown using a torque value of 130 ft-lb.
However, the procedure does not provide any information on the
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sequence.
Inspectors questioned the adequacy of this step to nrovide sufficient instruction and verification for the torquing of the bolts for valves V-21-8 and V-21-10, system I pump discharge check valves.
The licensee responded that a required diagram showing the sequence was inadvertently left out in the last revision (dated June 1990) and plans to incorporate it during the biennial review which is currently in progress.
The inspector did not have any other questions.
1.4 (Closed) Unresolved Item 50-219/90-09-01 [LER 90 906)
Licensed Thermal Power Limit Exceeded as a Result of Changes made to
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Computer input to Heat Balance Calculation.
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On May 11, 1990, the licensee operated.the reactor above its licensed power limit of 1930 MWth for approximately five hours.
The maximum-core thermal power was 1931.65 MWth and was less than 0.1'4 above the licensed limit. This happened when the input for the reactor water cleanup system was not reinserted into the computer heat balance calculation after the system was returned to service.
This input was removed two days prior when the system was taken out of service.
The licensee performed a critique and prepared a Licensee Event Report (LER No.90-006).
The root cause was determined to be personnel error in performing an activity not covered by plant
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procedures.
The licensee plans to issue procedure changes.to
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adequately control inputs to the computer heat balance calculation by December 31, 1990. As an interim measure, the Operations Department has issued a directive which prohibits adjustments to heat balance calculation without an approval from the Plant Operations Director or the Manager - Plant Operations.
The LER was made required reading for all cor. trol room licensed personnel, including the Shif t Technical Advisors.
Additionally, the licensee is evaluating the need to add instrumentation and computer points to enhance the
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accuracy of the heat balance: calculation.
The information contained in the LER was adequate except the licensee did not indicate if there were any prior similar events as required by 10 CFR 50.73(b)(5).
The licensee told the inspector there were none.
Operating the plant with a reactor power level above the licensed
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maximum power limit is a violation of the operating license.
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Additionally, Criterion 5 of 10 CFR Appendix B requires'that i
activities affecting quality shall be prescribed and accomplished in j
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accordance with documented instructions and procedure.
Changing
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computer inputs to the heat balance calculation could adversely affect core thermal power level and the core limits information-available to the control room operators.
Hence, performing this activity without documented instructions or procedures is a violation of the Criterion 5 in 10 CFR Appendix B.
The deviation of the core power level from licensed limit was small.
The Oyster Creek loss of coolant accident analysis assumes 102% of s
rated power level of 1930 MWth.
The licensee's analysis also indicated there was ample margin to the maximum average planar linear
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heat generation rate (MAPLHGR) and the critical-power. ratio-(CPR)
limits.
Additionally, the licensee concluded that operating the reactor at a power level of 1931.64 MWth would virtually have no effect on transient response.
Based on.the low' safety significance of the violation, adequate corrective action undertaken'by the l
licensee to be completed within a reasonable amount of time, no previous similar occurrence, and that the event was identified by the
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licensee and reported to the NRC as required, a Notice of Violation will not be issued (NCV 50-219/90-11-02) (Closed 50-219/90-09-01)
1.5 Control Room Tours
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The inspector conducted routine tours of the control room.
The following documents were reviewed:
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Control Room and Group Shift Supervisor's Logs;
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Technical Specification Log;
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Control Room and Shif t Supervisor's Turnover Check Lists;
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Standing _ Orders; and,
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Operational Memos-and Directives.
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No significant. problems lwere identified.
Site management involvement; and presence in control-room activities were noted.:
1.6-Facility' Tours LThe inspectors con' ducted routine plant tours to assess equipment-conditions, personnel. safety hazards.L procedural adherence and compliance with regulatory -requirements. : The-following: areas.were.
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Reactor Building i-
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Turbine Building
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4160 Volt Switchgear Room
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"C" Battery Room
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A/B Battery Room
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4160 Volt Room
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Lower Cable Spreading Room
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Control Room
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Radwaste Yard
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New Radwaste Building
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- Old Radwaste Building Augmented Offgas Building
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Auxiliary Boiler Building-
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~ Emergency Diesel-Generator Building
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Intake Structure.
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In Lthe new radwaste building, the-inspector noted in the' resin q
precoat room that decontamination by the radwaste operators had
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recovered most of_the room.
The inspector also observed;the use of a b
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i demineralizing cleanup system to process and return plant water.
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use of this system minimizes the use of radwaste evaporators.
The following. additional items were observed or selectively verified:
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Fire Protection:
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Randomly selected fire-extinguishers were accessible and
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inspected on schedule, ij Fire doors were unobstructed and in their proper position.
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Ignition' sources and combustible materials were controlled j
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in~accordance with the licensee's approved procedures.
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Appropriate fire watches or fire patrols were stationed:
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when fire protection / detection' equipment was out of
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Equipment Control:
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Jumper and equipment mark-ups did not conflict with
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technical specification requirements.
t Conditions requiring the use of jumpers received the prompt i
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attention of the licensee, i
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Vital Instrumentation:
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Selected instruments appeared functional and demonstrated
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parameters within Technical' Specification Limiting Conditions for Operation..
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Housekeeping:
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Plant housekeeping and cleanliness were in accordance with
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p approved licensee programs.
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After unplanned outage 120-L,-the general housekeeping
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conditions degraded to some extent. At the'end of.the
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inspection period, increased licensee effort 'to improve
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-housekeeping was. observed.
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2.0. Radiological Controls
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2.1-Intake Received by Workers
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On July 2,1990, two mechanics went inside.the shutdown cooling heat
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exchanger room'to repack valve V-17-56.
Due.to contamination': levels-i present in the area and extremely high contact. dose rates on the valve,'an ALARA review was performed for the job. ~This. review-
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required use of respirators to remove the old packing. The Grpup Radiation Control Supervisor was permitted by the ALARA review to decide if respiratory protection was to be requind during packing
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installation based on the results of the current survey.
The ALARA review also required the use of HEPA ventilation. This was to be
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verified by the radiological controls technician.
The mechanics were in the area for approximately 1-1/2 hours and each received a dose of 58 mrem. They contaminated their faces and
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received an intake of 9.39 and 2.69 MPC-hr. respectively. They were wearing face. shields and no respirators.
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The licensee conducted a critique and prepared a radiological investigation report. Wetting only the packing gland area and not
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the general work area and movement of installed shielding during work i
were considered to be possible causes. Additionally, during i
installation of the new packing, workers had to force the packing
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into the stuffing box.
Inadequate HEPA filter air flow could have caused increased airborne activity due to high loose surface
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contemination levels.
The HEPA filter suction should have been
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placed within 6 in, of the work area, but was placed at a distance of 18 in, to provide the mechanics room to work, y
At the end of the inspection period the licensee was finalizing their critique report and formulating corrective actions.
NRC review of
the event was ongoing at the end of the inspection period.
The second incidence of radioactive intake. happened during repair of a drain line in the condenser bay area.
The survey data of the work site indicated a moderate level of smearable contamination.
The
- survey also showed a major beta contributor, indicating the presence t
of fixed activity in the pipe.
However, the survey did not clearly indicate the specific location of this beta contributor. A job specific RWP was prepared which required a plastic hood but no respirators.
Use of a HEPA filter was also not specified for the decontamination effort.
On July 1, 1990, a work crew consisting of three mechanics without the radiological controls technician (RCT) entered the condenser bay area to decontaminate the pipe before repair. The decontamination
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effort was undertaken to eliminate the need for respirators or HEPA ventilation during cutting and welding of the pipe. A pre-job l
discussion was held by the RCT. The mechanics used a file to remove
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larger deposits of rust and then emery cloth to clean the remainder.
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After the use of the file when the mechanic switched to emery cloth,
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a smear was given to the RCT, followed by a second smear a little later, to monitor decontamination effort.
The first smear showed 800 cpm and the second 4000 cpm on a wipe of the 1/2 in. band of the 1 in. pipe.
At this point the RCT stopped the job, pulled the workers out and had the air sample counted.
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i The air sample indicated a total MPC fraction of 2.59 MPC. Th,e whole body count of the workers indicated a highest body burden of 1.1's on
The crew spent approximately 95 minutes on the job and
received between 10 and 12 mrem dose.
The licensee performed an investigation which indicated the root cause to be the lack of engineering control to effectively control airborne activity generated by work.
Poor understanding of potential radiological conditions present internal to the pipe, the marginal survey data and management oversight and poor planning were also noted as contributing causes.
A " lessons learned" was prepared.
The group radiation control supervisors were assigned to provide the " lessons learned" items to their crew as part of on the job training.
The inspector found the licensee's corrective actions adequate and did r
not have any other questions.
2.2 Radiation Protection During entry to and exit from the RCA, the inspectors verified that
proper warning signs were posted, personnel entering were wearing j
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proper dosimetry, personnel and materials leaving were. properly monitored for radioactive contamination, and monitoring instruments
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were functional and in calibration.
Posted extended Radiation Work permits (RWPs) and survey status boards were reviewed to verify that they were current and accurate.
The inspector observed activities in the RCA to verify that personnel complied with the requirements of
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applicable RWPs and that workers were aware of the radiological conditions in the area.
3.0 Maintenance / Surveillance 3.1 Monthly Maintenanca Observation On June 2, 1990, the inspector observed a maintenance crew tightening the packing on the No. 1 isolation condenser steam valve V-14-31 which had a steam leak.
This valve is located overhead in the 75 ft.
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elevation of the reactor building and was reached by a scaffold.
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area was roped off as a conttminated area due to the leak.
The inspector verified that the requirements of the job' specific
Radiation Work Permit (RWP) were followed and the radiation controls ~
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survey adequately evaluated the radiation hazard.
t The job package contained an engineering evaluation which determined the allowable maximum torque on the packing gland nuts to be 46
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ft-lb.
The job supervisor and packing vendor engineering t
representative were present at the jobtite to review the ongoing
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work.
Af ter cycling the valve several tines, the maximum torque was
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increased to 51 ft-lb upon the vendor representative's verbal direction.
The inspector questioned the acceptability of this change which was not covered in the work pactage.
The inspector was told
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that to minimize radiation exposure to the work crew and eliminate the need for multiple entry into a contaminated area, verbal
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direction of the vendor' engineering representative was utilized. The
work package was revised after complet. ion of the work, _ The inspector asked if any procedural guidance existed for this practice. The
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licensee stated that Station Procedure 105, " Conduct of Plant Engineering," will be revised to provide guidance on verbal engineering direction, and verbal approval of work package revision.
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The inspector did not have any other questions.
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3.2 Monthly Surveillance Observation
On June 8, 1990, the inspector observed the licensee completing'the I
drywell to torus vacuum breaker operability and inservice test procedure 604.4.016 Revision 12.
The operator stationed at the
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23 ft elevation of the reactor building _in front of the vacuum
breaker position indication panel had the controlled copy of the
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procedure data sheets. Approval was obtained_from the Group Shift
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Supervisor, but the next step, to verify prerequisites of the test,
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was not filled in before the test:was started. The operator stated-
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that the required verification was completed but the step was not'
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filled in due to oversight, Procedure 116, Revision 28, j
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"Surveiliuce 4 rogram," requires that if documentation of an action is reqv the necessary data shall be recorded as the task
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is performed.
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The operator documented completion
of the step, herequisites had been satisfied.
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The inspector had no other questions.
4.0 Engineering and Technical Support
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4.1 Diesel Generator Switchgear Mounting l
On July 7, 1990, during a review of licensee planned activities to
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upgrade the physical condition of the Diesel Generator' Building.
inspectors questioned the licensee regarding.the affects of corrosion
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on the mounting of the diesel generator switchgear and the' diesel
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generator.
This room is open to the atmosphere, and rain water that entered the room rusted some diesel generator skid and switchgear
mounting supports, i
The licensee responded that the amount of material that had corroded l
did not affect the structural integrity of the mounting supports.-
However, the inspector discovered that neither the diesel generator switchgear cubicle nor the diesel skid were anchored to the concrete floor.
The inspector asked the licensee if this condition satisfied-the seismic criteria for the diesel' skid and the diesel generator
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switchgear.
Licensee review of the mounting of the diesel-skid concluded the skid was configured in accordance with the original drawings and that
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anchoring of the skid to the concrete was not required for-functionality during the seismic event ~
The. inspector had no other'
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questions regarding the mounting of the diesel skid.
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Licensee review concluded the mounting of the diesel generator, switchgear cubicle was not in accordance with original drawings.
Original drawings showed the switchgear cubicle anchored to the floor.
This deficiency was documented in a Material Nonconformance Report, the diesel generators were reviewed for operability, and i
corrective actions were. identified to repair the deficiency.
The licensee evaluated the potential effects of a seismic event on
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the as found configuration in the Diesel Building.
The original licensing basis.for Oyster Creek used an operating basis earthquake of.119 and a safe shutdown earthquake of. 22g.
However, during the Systematic Evaluation Program, using refined seismic methodologies, NRC concluded that a more accurate safe shutdown earthquake acceleration was.165g.
Licensee calculations showed that, assuming accelerations of.22g, the switchgear and cubicle would not overturn.
Licensee calculations also showed that for the operating basis earthquake with a safety factor.of four, no sliding would occur.
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Based upon the conservatisms of this estimate, the licensee concluded
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that it was highly likely that no sliding would occur for the
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systematic evaluation program acceleration of.165g. Based on this l
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review, the licensee concluded that the diesel generators were
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The results of this calculation were discussed with the NRC on June 13, 1990, in a conference call with Nuclear Reactor Regulation and Region I.
During this conference call the licensee committed to designing and installing anchors on the diesel generator switchgear
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cubicles with the installation to be complete by June 21, 1990.
This commitment was documented to the NRC in a letter date June. 14, 1990.
NRC inspectors verified by walkdown and visua1' observation that anchors had been designed and installed on the diesel generator switchgear cubicles before June 21, 1990. The inspectors had no other questions regarding diesel generator switchgear mounting.
4.2 Contro Room Habitability NRC inspectors reviewed the:11censee's use of using auxiliary boiler heating steam in the control room ventilation system. The inspector questioned the impact of a steam heating coil break on control room
. habitability. ' Licensee analysis did not consider this'in their evaluation but concluded that a coil break did not have any impact on
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control room habitability because-of the size of the ventilation
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ducting in relation to the small size of the steam heating coils.
The inspsetor had no other questions.
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4.3 Control Rod Drive
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On June 17, 1990, while performing control rod drive (CRD) exercise, control red 18-11 could not be notch withdrawn with control rod drive pressure at 390 psid.
The rod could be withdrawn using the notch override with drive pressure around 280 psid. CRD 18-11 was fully inserted and valved out. A deviation report was written and an-engineering review commenced. After engineering determined that control rod 18-11 would meet the Technical Specification criteria _ for core reactivity, the rod was moved to "06" position to improve the rod pattern and valved out of service.
The control rod was declared operable per engineering evaluation.
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On June 21, 1990, during a power maneuver, notch override was necessary to withdraw most of the control rods. The licensee found that the CRD system insert and withdraw flows were out of specification by a considerable amount.
To maintain a constant charging water flow and to prevent the flow control valves from hunting, stabilizing valves are installed in'the system which
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i maintain a constant insert and withdraw flow. There are two sets of
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stabilizing valves, and one set is used as a spare and normally valved out. Each set contains two valves arranged in parallel. One
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valve passes 4 gpm flow and the other 2 gpm.
These valves are normally open, On a withdraw' signal, the valve that passes 2 gpm closes, so this flow is diverted to the drive water header to drive the rod out. During an insert signal, the other valve that passes 4 gpm closes, and this flow is diverted to the drive water header,
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enabling the rod to be inserted.
During a notch withdrawal, an
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insert signal is automatically entered to unlatch the collet fingers, followed by a withdraw signal to withdraw the rod one notch. The j
sequence and duration of these signals are controlled by a timer in j
the rod manual control system.
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Each set of stabilizing valves is supplied with a filter. These filters were found clogged and were replaced. The solenoid in one valve was also replaced.
After adjustment of the stabilizing valves, all control rods were exercised.
About 80% of the rod stroke times
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were found out of specification, a majority showing faster withdrawal and slower insert times.
The licensee reviewed the stroke time acceptance criterion and widened the band from 43.65 - 53.0 seconds to 40 - 60 seconds. The rod control timer settings were adjusted per GE recommendation (insert time was found to be too long). The control valves on various hydraulic control units (HCU) were also adjusted.
Nineteen out of the 137 HCOs needed further replacement of some of the control valves.
In three HCUs, leakage through cooling line check valves was repaired by replacing._the valve internals.
Af ter these adjustments, four control rods still had fast withdrawal times. The licensee suspected seat leakage through the cooling line check valves.
Procedure changes were made to allow reactor startup with the cooling water valves tagged in a closed position. The valve was to be opened after each rod reached position 48.
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prepared a safety evaluation which indicated that based on
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information available from GE, the lack of cooling for the amount of time involved does not adversely affect the control rod drives.
The licensee is currently reviewing the PM program and the detailed diagnostic procedure for required improvements.
A diagnostic test will be performed on all 137 CRD units either before or during the 13R outage. Maintenance work on the control rod drive hydraulic system currently planned for the 13R outage will be reevaluated based on the current information and results of this diagnostic test.
Meanwhile, a check for this stabilizing valve flow will be performed during the weekly control rod exercise. Also, the licensee is reviewing the need to periodically interchange the two sets of stabilizing valves.
The stabilizing valve filters will also be periodically replaced.
The inspector reviewed the licensee's engineering evaluation for declaring control rod 1841 operable, the safety evaluation for changing the stroke time acceptance criteria, and changes to the i
operating procedure.
Lack of an effective preventive maintenance
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program allowed the enntrol rod drive hydraulic system to be degraded. This provided uneccesary challenges to the control room operators and required extensive troubleshooting and maintenance work.
The licensee is developing corrective action to address maintenance of this system.
The inspector did not have any other questions.
5.0 Safety Assessment / Quality Verification 5.1 General Employee Training
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During annual requalification training for site access, the inspector i
noted improvements in the practical factors portion of the training.
The instructors were more involved in monitoring and correcting mistakes made by the trainees and reflected a strong commitment to improve radiological controls at the plant.
6.0 Inspection Hours Summary Inspection consisted of 168 direct inspection hours, 42 inspection hours were performed during backshift periods-and 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> during deep backshift times.
7.0 Meetings
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7.1 SALP M'.nagement Meeting A public meeting on the recently issued SALP report was held on July 2, 1990, at the Forked River site adjacent to the plant. This provijed a public forum for the NRC to present the SALP findings _and'
the licensee to respond. A list of attendees is included in
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in L-Attachment I.
The NRC' presented an overview of the SALP process and a summary of its findings for'the 13_-month period which ended in March 1990. The NRC presentation is' contained in Attachment II.='The
.ltcensee's response included a detailed presentation of. improvements t
underteken in two major areas, namely radiologicalicontrols, and plant o
maintenance. A copy of theflicensee's presentation,is' contained in-Attachment III.
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7.2 Preliminary Inspection Findings
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- A verbal summary of preliminary findings was provided to seniori
' licensee management after the inspection. The. inspectors routinely-briefed licensee management.of the preliminary findings.
No' written inspection material.was provided to the licensee _during the;
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inspection. No proprietary information 'is included:in thisLreport.-
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7.3 Attendance at Exit Meetings Conducted by Region Based. Inspectors-
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During this inspection period,'the resident inspectors attended the exit meeting for Inspection 50-219/90-80. At:this'meetingLthe. lead j
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inspector discussed inspection activities and~ findings:with senior licensee management..
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ATTACHMENT I_
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NRC SALP MANAGEMENT MEETING, July 2.1990 t
Licensee Personnel I
R. Barrett, Plant Operations Director
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J. Barton, Oyster Creek Deputy Director
W. Behrle, Director Startup and Test
R. Brown, Radwaste Operations Manager:
i G. Busch, Licensing Manager, Oyster Creek
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P. C1 ark, President'GPUN
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J. De Blasio, Plant Engineering Manager i
T. Dempsey, Mgr. Plant Engineering
R. Fenti. QA. Mod /0PS Mgr.
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R. ' Fitts, site QA Auditor -
E. Fitzpatrick. Vice President and. Director.0yster Creek
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G. Giangi, Corporate Mgr. Emergency Preparedness
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C. Hager, Engineering Sr'. II
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V. Harris, Nuclear Safety Compliance. Committee i
r J. Hildebrand. Dir. Rad /Env. Controls
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R. Hillman,lMgr. Plant Chemistry
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R. Keaton, Director QA/GPUN'
S. Kempf, Emergency Preparedness-
J. Knubel, Nuclear Security '
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J. Kowalski, Mgr. Training
.M. Laggart, Mgr. Licensing GPUN L. Lammers, Plant Maintenance Director
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K. Neddenien, Media Relations Mgr.
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J. Pfadenhauer, Site Services Division-j C. Pollard,'Mgr. Rad. Con. Field /0PS>
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T, Quintenz, Plant Materiel-Director i
A. Rone, Plant Engineering Director
P. Stallon, Plant Operations Mgr..
M. Slobodein, Radiological, Controls Director D. Smith, Corp Radiological and Safety Assessor i
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R. Stintzcum, Security Mgr.-
J. Sullivan, Licensing / Reg. Aff. Director i
R. Tilton, Quality Assurance
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D. Tuttle, Radiological Controls' Deputy Director j
State of New Jersey DEP l
'C. Dell-
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N. Di Nucci-
D. Zannoni;
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NRCfersonnel
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e M. Banerjee, Resident. Inspector
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e" R. Bellamy, Chief FRSS Branch, DRSS -Region 1
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E Collins, Senior Resident Inspector
A. Oromerick, Senior Project Mgr., PDI-4/NRR-
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1. Martin, Region'I Administrator'
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5. Rubin-Chief, DE11B, AEOD, NRC.
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W. Ruland.,Section Chief, PB#4, DRP-l J.!Stolz, Project Director, PDI-4/NRR
E. Wenzinger, E. Chief,-PD#4,'DRP
'R? Wessman, Acting Assistant Director, RI/NRR..
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i J. Wiggins, Deputy. Director, DRP
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Others
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W.-Andrews,.0cean County Observer'.
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N. Mc Greevy, Ocean County Citizens & Handicapped Services Coord./Wead Start
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5. Mc.Veigh 0cean' County Citizens for Clean' Water.
T. O'Connor, Lucien J. Lockel Associates-l l-j
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Richmond, WOBM
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L.c Schuster, Health Physicist, Lakehurst, NJ
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L. Seusene i;
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_& OPERATIONS
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WEAKNESSES o Plant operation was adversely affected by material problems.
o While generally adequate,, attention to detail in the use of procedures and some procedure inadequacies continue to contribute to plant events.
STRENGTHS
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o Control rogm operators have performed well in response to plant transients j
and challenges.
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o Control room operators are professional, knowledgeable of system status and exercise good control over plant activities.
o Operations Department involvement in plant activities was evident and
effective.
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o Operations Department management responsiveness to control room operator
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questions and concerns has improved, o Staffing of control room operators and Operations Department management has improved, o Operations Department managers and supervisors generally exercise good safety judgment, o Operations Department use of the a!!e critique process is commendable.
RECOMMENDATIONS o Complete operations self assessment and implement corrective actions, o Expedite implementation of plant procedure improvements.
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RADIOLOGICAL CONTROLS
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i o Collective exposure remains high.
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o Resc% tion of radiological, issues / events remains inconsistent. Root caur.,nalysis was sometimes narrow in scope.
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o Instances of failure to follow procedure and poor radiological control.
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STRENGIES'
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o Management attention increased as evidenced by improvement programs now in place.
l o Increased training given to middle managers, supervisors and staff, t
o Staffing levels were generally adequate with field technicians and engineering staff at minimum levels.
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o Radioactive effluent monitoring and control program was strong.
o Solid radwaste volume shipped was significantly reduced.
t o No problems were identified with radwaste packages shipped for burial, o Enforcement history improved since last assessment period.
RECOMMENDATIONS o Translate improvement plans into performance improvements.
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MAINTENANCE / SURVEILLANCE WEAKNESSES
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o Equipment problems have resulted in a number of plant trips and shutdowns.
l This has cesulted in challenges to site personnel and resources.
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o The major initiatives to develop a reliability centered life of system maintenance plan has had limited impact on improving the plant's material condition.
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o Some examples of inadequate work control have been seen. Although generally good, some weakness was observed in surveillane, procedural adherence and procedural adequacy.
STRENGTHS o The Material Conditions Issue List has been successful in the identification and prioritization of equipment issues.
o Commitment to improve the plant reliability has been shown in several significant projects. To date, the impact has been limited, o Progress has been seen in your effort to document and correct rework problems, o In general, maintenance activities are well planned and executed.
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l E.MERGENCY PREPAREDNESS WEAKNESSES
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o ~ Annual exercise and dress rehearsal were technically identical,
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requiring a remedial exercise.
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- s STRENGTHS
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o Good results from the remedial exar tise. No exercise weaknesses were identihed.
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o Extensive management involvement supporting emergency preparedness was I
demonstrated, o Resolution of technical issues demonstrated a commitment to quality.
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H o. Emergency preparedness audits.were performed.with a diversified and l'
expert staff.
o Reporting and classification of actual events were prompt and accurate.
I o Staf2ng was ample and stable.
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SECURITY
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WEAKNESSES
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o Several personnel errors led to security events.
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o Several equipment-related weaknesses were identified.
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o There is a very effective vital area' access control program.
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o Increased management attention was noted along with an active
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corporate security management, a
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o Self-assessments and audits continued to provide effective oversight.
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o The Fitness-for-Duty %) rule was in place. prior to the required -
date. Indepth revL ws c.'FFD issues were conducted.
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o Security training u
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program performed by.
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ality trhining aids..
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ENGINEERING AND TECHNICAL SUPPORT
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WEAKNESSES o Several problems were found with engineering documentation, procedure discrepancies, and implementation delays; o Several instancer o9sMgjed responses occurred.-
STRENQDlS.
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o Implemente'd a major cathodic protection modification for dryweil shell.
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o Design changes were released.well in advance of outages, with active engineering help during installation.
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o Internal SSFIs and system design basis documentation efforts were
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started.
o Knowledgeable engineering staff provided necessary support.
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understanding of the issues and a generally: conservative approach, o Engineering evaluations were generally acceptable with some noted
exceptions.
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SAFETY ASSESSMENT /OUALITY VERIFICATION
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WEAKNESSES
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o Weaknesses in site corrective action systems have been seen. Corrective actions have been effective in increasing site personnel awareness of the importance to document deficient conditions. Improvements are continuing
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to be made in this arco
o Although an improvement in the quality of site critiques has been seen, in
some cases the causes of root cause determination remains inconsistent.
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o Informality'ic resc!ving deficiencies by site personnel in some cases has resulted in ineffective corrective actions'.
STRENGTHS o Site management involvement is evident in day to day activities, and decisions affecting quality are usually made at the level receiving adequate
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o Site policies stress high standards of performance, o Licensing issues and Licensing Department problems are effectively addressed, usually in a timely manner.
l
- o Improvements have been seen in the timeliness of correcting QA findings, o Increased involvement of safety review groups has been scene c Comprehensive plans are in place to improve overall' site performance, o Positive initiatives have been seen, especially in the Plant Operations Department by the fostering of an atmosphere which solicits concerns and questions so that issues can be identified and addressed.
o An improvement in the timeliness of addressing Quality Assurance findings has been seen.
o Effective safety reviews are conducted.
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SALP EROCESS
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POR OC 12 MONTHS
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(TYPICAL 15 MONTHS)
3/15/90 - 3/15/91 2. GIVE FEEDBACK TO LICENSEES RE: THEIR PERFORMANCE 3. ALLOCATE NRC (INSPECTION); RESOURCES
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B.. EFFORTS.REQUIREDt
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INPUTS FROM PM, AEOD IN HQ DRS,' DRSS IN REGION
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b.~ANEASCOVERED-----------------------REPORTINPUTRESPONSIBILITY 1.
OPERATIONS----------------------------(DRP, SRI & S/C)
2. RADIOLOGICAL CONTROLS----------------------(DRSS)
3. MAINTENANCE / SURVEILLANCE--------------(DRP, SRI & S/C)
4. ENGINEERING / TECHNICAL SUPPORT--------------(DRS)
.
5. EMERGENCY PREPAREDNESS----------------------(DRSS)
6. SECURITY / SAFEGUARDS------------------------(DRSS)
7. SAFETY ASSESSMENT / QUALITY VERIFICATION--(HQ, NRR PROJECT DIR)
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- D.~ FACTORS CONSIDERED IN EACH AREA -
1.' MANAGEMENT INVOLVEMENT AND CONTROL IN ASSURING QUALITY 22. APPROACH USED TO RESOLVE ISSUES'FROM A' SAFETY STANDPOINT
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- NO PROPOSED SCORES *
- BOARD'MEMGERS COMMENTS *
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BASED ON 7l FACTORS CONSENSUS OF BOARD' MEMBERS
- SALP REPORT REVIEWED AND SIGNED BY REGIONAL ADMINISTRATOR:
- SENT TO LICENSEE.(GIVEN TIME TO STUDY)
- SALP MANAGEMENT MEETING (USUALLY ON SITE)
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- EACH EVENT IS EVALUATED FOR:
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- RESULTS OF'THE REVIEW ARE'USED-TO ASSESS THE SIGNIFICANCE OF THE EVENT ON THE FUNCTIONAL AREA BEING. CONSIDERED (WHAT. ASPECT OF THE FUNCTIONAL AREA NEEDS IMPROVEMENT BECAUSE THE EVENT TOOK PLACE).
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= PERFORMANCE SUBSTANTIALLY EXCEEDS REQUIREMENTS
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- TWO - PERFORMANCE ABOVE THAT NEEDED TO MEET REQUIREMENTS-INSPECTION 4 NORMAL
- THREE - PERFORMANCE DOES NOT SUBSTANTIALLY EXCEED-MINIMUM REQUIREMENTS-GREATER TRAN NORMAL INSPECTION-
-IMPROVING-PERFORMANCE IMPROVING OVER MOST OF THE, PERIOD
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- HAS' REACHED NEXT HIGHER LEVEL
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2. FOR THE NRC - ACTION (S) TO IMPROVE NRC'S UNDERSTANDING OF THE AREA l
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2. RESPONSE REOUIRED IN' WRITING WITHIN 30 DAYS TO PROVIDE
- LICENSEE'S PERSPECTIVES'ON STRENGTHS'AND WEAKNESSES
- PROPOSED CORRECTIVE ACTIONS l
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3. NRC.MAY REVISE THE'SALP BASED ON ABOVE INPUTS a
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I. MID-CYCLE SALP 1.-REVIEW OF PROGRESS SINCE THE END OF THE LAST PERIOD 2.
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RATES THEIH OWN PERFORMANCE IN EACH AREA 5. NRC DESCRIBES OBSERVATIONS BY INSPECTORS (MOSTLY RESIDENT OBSERVATIONS)
- NO NUMERICAL RATINGS
- MAY SUGGEST PARTICULAR AREAS TO WORK ON.
J. USE OF SALP SCORES
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MANY HAVE MISUSED NRC NUMERICAL SALP SCORES
- COMPARE PLANTS IN A REGION, UTILITY, ACROSS COUNTRY
- USE FOR REWARDS OR. PENALTIES
- COMPARED PLANTS IN DIFFERENT SITUATIONS SCORES ARE DEVELOPED BY'SALP BOARD
- BASED ON CHANGES IN PERFORMANCE AT THE PLANT BEING: EVALUATED
- SCORES ARE REFLECTION OF NRC VIEW OF PERFORMANCE OF THAT PLANT AS COMPARED WITH THE PREVIOUS SALP CYCLE
- PERFORMANCE OF OTHER FACILITIES IS NOT CONSIDERED BY SALP BOARD-
- PERFORMANCE IS RATED COMPARED:TO THE PREVIOUS PERIOD, AND A RATING IS ASSIGNED. PERFORMANCE DURING'THE PERIOD IS ALSO RATED, AND A~ TREND IS ASSIGNED, IF APPROPRIATE.'
COMPARING SALP SCORES OF VARIOUS PLANTS IS NOT' CORRECT USAGE BECAUSE:
- SALP BOARD ONLY CONSIDERED PERFORMANCE OF THE FACILITY BEING EVALUATED
- EACH PLANT HAS A DIFFERENT SET OF CHALLENGES THE RATINGS ARE AN EVALUATION OF HOW WELL A FACILITY HAS MET THE CHALLENGE 8 IT HAS FACEDI
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- ALL FUNCTIONAL AREAS ARE NOT OF EQUAL IMPORTANCE
- UNACCEPTABLE' PERFORMANCE NOT INCLUDED IN AVERAGES
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LIFE OF SYSTEM MAINTENANCE PLAN I
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1 o REACTOR RECIRC PUMP / MOTOR / SEAL
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o INTAKE SCREENS - OVERHAUL / UPGRADE l
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o ISO CONDENSER VALVES - UPGRADE
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o FEEDMTER PUMP > MOTOR - IMPRO\\/ED VENTILATION
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- MAINT CNANCE SACKLOG (IMPROVING)
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- RATIO PREVENTIVE / TOTAL MAINT. (IMPROVING).
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- CONTAMINATED AREA (LOWEST IN 10 YRS)
- NRC PERFORMANCE INDICATORS (IMPROVED)
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PLANT DIVISION O&M RESOURCE ALLOCATIONS ON MATERIEL CONDITION PROJECTS
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