IR 05000335/1990016
| ML17223A886 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 08/13/1990 |
| From: | Crlenjak R, Elrod S, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17223A885 | List: |
| References | |
| 50-335-90-16, 50-389-90-16, NUDOCS 9008240113 | |
| Download: ML17223A886 (35) | |
Text
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos.:
50-335/90-16 and 50-389/90-16 Licensee:
Florida Power and Light Company 9250 West Flagler Street Miami, FL 33102 License Nos.:
l u
Dat Signed S.
A. El o'd, Senior Resident Inspector Docket Nos.:
50-335 and 50-389 Facility Name:
St.
Lucie 1 and
Inspection Conducted:
ne
- July 23, 1990 Inspectors:
M. A." Scott, Res dent Inspector j
Approved y:
r Nichard V. Crlenjak, Chief Reactor Projects Section 2B Reactor Projects Branch
Division of Reactor Projects h
Date Si ned Date S gned SUMMARY Scope:
This routine resident inspection was conducted onsite in the areas of plant operations review; maintenance observations; surveillance observations; review of nonroutine events; and followup of post-TMI action items, NRC Bulletins, and previous inspection findings.
Results:
During this period, an Unusual Event and a forced shutdown were well handled 'by the plant staff.
Also the licensee discovered a
long-standing set point discrepancy affecting the Unit 1 480 V undervoltage relays.
That problem was resolved expeditiously.
The review of LERs and previous enforcement items found the licensee to be reviewing problem areas in depth and taking appropriate corrective action.
Within the areas inspected, the following noncited violations were identified associated with events reported by the licensee:
NCV 335/90-16-01, Inoperable Effluent Monitor, paragraph 5.
NCV 335/90-16-02, Missed Sealed Source Leak Check, paragraph 5.
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NCV 335/90-16-03, Improperly Set MSIS Input, paragraph 5.
NCV 335/90-16-04, Failure to Perform Battery Surveillance, paragraph 5.
NCV 335/90-16-05, Failure to Perform CEA Block Circuit Surveillance, paragraph 5.
NCV 389/90-16-01, Failure to Translate TS Bus Undervoltage Setpoints Into Proper Surveillance Procedure Requirements, paragraph 3.
NCV 389/90-16-02, Failure to Post Test Containment Isolation Valve Repairs, paragraph I
REPORT DETAILS Persons Contacted Licensee Employees D. Sager, St.
Lucie Site Vice President
- G. Boissy, Plant Manager J.
Barrow, Operations Superintendent J.
Barrow, Fire Prevention Coordinator R. Church, Independent Safety Engineering Group H. Buchanan, Health Physics Supervisor C. Burton, Operations Supervisor C. Crider, Outage Supervisor D. Culpepper, Site Juno Engineering Manager R.
Dawson, Maintenance Superintendent R. Frechette, Chemistry Supervisor R. Englmeier, equality Assurance Manager-C. Leppla, 18C Supervisor L. McLaughlin, Plant licensing Supervisor L. 'Rogers, Electrical Maintenance Supervisor N. Roos, Service Manager D. West, Technical Staff Supervisor J. West, Mechanical Maintenance Supervisor W. White, Security Supervisor G. Wood, Reliability and Support Supervisor E. Wunderlich, Reactor Engineering Supervisor Chairman Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members and office personnel.
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.
/
Review of Plant Operations (71707)
Unit
began the inspection period at power.
On June 14, a dropped CEA event resulted in a shutdown that was reported as an Unusual Event.
The unit was restarted that same day.
On July 2, the unit was shut down due to excessive 1A1 RCP vibration and seal leakoff.
The unit remained shut down for the remainder of the inspection period while rebuilding the 1Al RCP.
Unit 2 began and ended the inspection period at power - day 187 on lin Plant Tours The inspectors periodically conducted plant tours to verify that monitoring equipment was recording as required, equipment was properly tagged, operations personnel were aware of plant conditions, and plant housekeeping efforts were adequate.
The inspectors also determined that appropriate radiation controls were properly established, critical clean areas were being controlled in accordance with procedures, excess equipment or material was stored properly, and combustible materials and debris were disposed of expeditiously.
During tours, the inspectors looked for the existence of unusual fluid leaks, piping vibrations, pipe hanger and seismic restraint settings, various valve and breaker positions, eq'uipment caution and danger tags, component positions, adequacy of fire fighting
'quipment, and instrument calibration dates.
Some tours were conducted on backshifts.
The frequency.
of plant tours and control room visits by site management was noted to be adequate.
The inspectors routinely conducted partial walkdowns of ESF, ECCS and support systems.
Valve, breaker, and switch lineups and equipment conditions were randomly verified both locally and in the cont'rol room.
The following accessible-area ESF system walkdowns were made to verify that system lineups were in accordance with licensee requirements for operability and equipment material conditions were satisfactory:
Unit lA LPSI room, Unit 1B LPSI room, Unit
pipe tunnel between RAB and RCB, Unit
SFP pumps and heat exchangers, and Unit 2 AFW pump areas.
b.
Plant Operations Review The inspectors periodically reviewed shift logs and operations records, including data sheets, instrument traces, and records of equipment malfunctions.
This review included control room logs and auxiliary logs, operating orders, standing orders, jumper logs and equipment tagout records.
The inspectors routinely observed operator alertness and demeanor during plant tours.
They observed and evaluated control room staffing, control room access, and operator performance during routine operations.
The inspectors conducted random off-hours inspections to assure that operations and security remained at an acceptable performance level.
Shift turnovers were observed to verify that they were conducted in accordance with approved licensee procedures.
Control room annunciator status was verified.
Except as noted below, no deficiencies were noted.
During this inspection period, the inspectors reviewed the following tagouts (clearances):
1-4-2, Control Room ILRT Test Isolation Valves; 1-6-162, 1A Heater Drain Pump repair;
2-6-47,'CV 25-13 repair; 2-5-152, HVS 4B repair.
On June 25, the 1A heater drain pump was taken out of service due to motor lower bearing failure.
The resulting reduction in MFP suction pressure reduced MFP flow capacity below that needed to maintain SG levels at 100 percent power.
Reactor power was reduced to approximately
percent and SG levels were satisfactorily maintained.
On June 14, Unit 1 declared an Unusual Event, which was reported in LER 90-008.
The unit was at 100 percent power when CEA 8 in the B
shutdown bank spuriously dropped three times and was recovered per procedure each t'ime.
Upon the fourth CEA drop, the operators shut down the reactor from 45 percent power.
The Unusual Event was exited after Unit 1 entered mode three.
The licensee determined that the cause for the dropped CEA was a
loose control power fuse for CEA 8.
The bayonet-style fuse holder cap was not completely secured in the fuse holder body.
Over time, the halves of the fuse holder separated sufficiently to cause intermittent control circuit power disruption.
The licensee checked all other CEA control circuit fuses for tightness and found them to be satisfactory.
Also, they determined that this failure mode did not apply to Unit 2, since it had a different CEA control arrangement.
LER 335/90-08 was issued and is discussed in paragraph 5.
For several days after the dropped CEA event, while Unit 1 was returning to power,
=the core flux profile was slightly skewed, requiring operator attention and power. escalation holds until it stabi 1 i zed.
Oropped CEAs have previously occurred about one to two times a
refueling cycle.
CEAs have generally dropped during power changes when they were actively being moved.
The NSSS vendor had previously recognized this problem and had designed CEOMCS upgrades, which the licensee had installed, in an effort to reduce the recurrence rate.
Starting on the afternoon of June 30, the 1A1 RCP upper seal pressure increased by 90 psig; by midnight, RCP vibration and seal leakoff flow had increased slightly.
Early on July 1, the loose parts monitor for the 1A SG alarmed concurrent with an increase in RCP vibration.
Monitoring of RCP parameters was increased.
By the morning of July 2, 1A1 RCP vibration had risen to
mi ls from about
mi ls and RCP seal leakoff had increased from a norm of about
gpm to about 1.6 gpm.
Then in a period of about two hours, it increased to about 3.5 gpm.
At
'I
- that point, FPL management ordered an orderly shutdown.
The unit was in hot shutdown by that afternoon, and then proceeded to Mode 5.
During the remainder of the inspection period, the 1A1 RCP restraints, motor, seal package, and pump rotating assembly were, removed.
Initial investigation found that the motor-to-pump-shaft spool piece could not be removed without lifting the motor.
The hydrostatic bearing hub, located inside the pump casing and providing impeller centering/motion dampening, had rub spots and was jammed on the shaft bearing surface.
At the end of the inspection period, the licensee and assisting vendors were preparing a spare pump rotating assembly for installation.
They were also performing a
root cause analysis of the failed rotating assembly.
Examination activities that could be reasonably conducted on site were essentially completed and plans were being made to ship the failed shaft to a yet-to-be-identified vendor for more detailed examination.
During the inspection period, Unit
entered a
reduced RCS inventory condition to support the RCP work.
The following items were observed during this evolution:
Containment Closure Capability - Instructions were issued to accomplish this; personnel and tools were on station.
RCS Temperature Indication Normal mode
CETs were available for indication.
RCS Level Indication -
Independent RCS wide and narrow range level instruments which indicated in the control room were operable.
An additional Tygon tube loop level gage in the containment was manned during level changes and checked every two hours during static conditions.
RCS Level Perturbations
-
When RCS level was altered, additional operational controls were invoked.
At plant daily meetings, operations took actions to ensure that maintenance did not consider performing work that might effect RCS level or shutdown cooling.
RCS Inventory Volume Addition Capability - Nominally one (of three)
charging pumps and a
second LPSI pump were available for RCS addition.
During one period in the evolution, the two other charging pumps were out of service for repairs.
The HPSI pump breakers were racked-out as required to meet
.TS LTOP requirements, but the HPSI pumps were otherwise available for servic RCS Nozzle Dams -
Due to the type of outage, the nozzle dams were not installed this time.
Vital Electrical Bus Availability - Operations would not release busses or alternate power sources for work during this outage.
c.
Technical Specification Compliance Licensee compliance with selected TS LCOs was verified. This included the review of selected surveillance test results.
These verifications were accomplished by direct observation of monitoring instrumentation, valve positions, and switch positions, and by review of completed logs and records.
Instrumentation and recorder traces were observed for abnormalities.
The licensee's compliance with LCO action statements was reviewed on selected occurrences as they happened.
The inspectors verified that related plant procedures in use were adequate, complete, and included the most recent.revi'sions.
d.
Physical Protection The inspectors verified by observation during routine activities that security program plans were being implemented as evidenced by: proper display of picture badges; searching of packages and personnel at the plant entrance; and vital area portals being locked and alarmed.
As a result of routine plant tours and operational observations described above, the inspectors determined that the general plant and system material conditions were being satisfactorily maintained, the plant security program was being effective, and that the overall performance of plant operations was good.
Operations sensitivity to abnormal RCS conditions was exemplary.
No violations or deviations were identified.
3.
Surveillance Observations (61726)
Various plant operations were verified to comply with selected TS requirements.
Typical of these were confirmation of TS compliance for reactor coolant chemistry, RWT conditions, containment pressure, control room ventilation and AC and DC electrical sources.
The inspectors verified that testing was performed in accordance with adequate procedures, test instrumentation was calibrated, LCOs were met, removal and restoration of the affected components were accomplished properly, test results met requirements and were reviewed by personnel other than the individual directing the test, and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
The following surveillance tests were observed:
The 1B and 1C HPSI. pump, and 1B LPSI pump monthly tests were observed in accordance with OP 1-0410050, Rev 27, HPSI/LPSI Periodic Test.
The overall test results were satisfactory.
Inspector questions
regarding the test were discussed with the plant staff and resolved expeditiously.
The startup transformers were taken out of service for general maintenance by the,FPL transmission and distribution group.
Unit
was required by TS to start and operate their EDGs every eight hours with these transformers inoperable.
The inspectors observed the proper operation of the EDGs during one of these starts.
Following the Unit
shutdown on July
and subsequent cooldown, a
new AFW system cold shutdown pump and valve test was observed.
OP 1-0700050, Rev 31, TCs 1-90-316 and 1-90-318, Auxiliary Feedwater Periodic Test, contained modifications to demonstrate check valve performance and full pump flow per GL 89-04.
Data sheets E and F,
addressing A and B
pumps respectively, were performed by personnel stationed in both the control room and the AFM station.
Test control by radio was good.
The test sequence and the data sheets were well laid out.
Check valve data was also recorded in AP 1-0010125A, Rev 16, Data Sheet ll, Check Valves Cycled During Cooldown, Cold, and Heatup Conditions.
This revision was also just issued in response to
'L 89-04.
During the test, V-09108, 1A AFW Pump Discharge Isolation Valve, was observed to have a bent packing gland follower.
This was pointed out to the licensee for evaluation.
Pump vibration test points were located on bearing cooling fan shrouds rather than bearing housings.
The fan shrouds were generally higher displacement areas and perhaps not directly related to trending bearing performance.
This was also pointed out for consideration by the licensee.
On July 13, an FPL off-site engineering reviewer informed a plant staff member that the Unit
480 V load center degraded grid relay setpoints did not appear to meet Unit
TS Table 3.3-4.
This was found during a
review to support possibly spreading the relay operating band to accommodate setpoint drift.
The TS specified that settings be greater than or equal to 432 V, which translated via a 4: 1 potential transformer to 108 V at the relay.
FPL engineering letter EPM-PSL2-83-181, dated April 6, 1983, authorized relay settings of:
LOAD CENTER 2A2,2B2 2A5,2B5 DROPOUT SETTING 107.2 V + or - 0.5
L 107.8 V + or -
0.5'ICKUP SETTING 107.6 V + or - 0.5%
108.2 V + or - 0.5:o
These settings had been used by the licensee's transmission and distribution group to perform 18 month surveillances on the relays, as required by TS.
The plant staff immediately issued NCR 2-338 on July 13:
(1) to obtain a formal engineering management determination whether or not a problem existed, and (2) to establish engineering approved corrective actions.
The plant and system protection group staffs staged equipment and stood ready to make relay setting changes as needed.
The NCR resolution issued a
few hours later concluded that the 1983 relay setting authorizations were based on analytical work to satisfy NRC PSB-1 requirements and that those settings were within the design basis for the plant.'he resolution also concluded that higher settings that would satisfy the TS were not detrimental to safety but were not technically necessary.
New settings for all four load centers were authorized with relay drop out at 109.1
+ or-0.5 V and Pickup at 109.7
+ or - 0.5 V.
These were reset that evening under a
RNWO.
Some of the as-found relay settings had drifted into the TS-approved range, others were still outside the TS.
Since the latest authorized relay setpoints were high for artificial reasons, the licensee intended to pursue a
TS change through normal channels.
The licensee also intended to include, in the forthcoming LER, a corrective action to review other TS setpoints for proper implementation.
Failure to set the degraded grid voltage relay settings as specified violated TS 3.3-2 (Table 3.3-4).
This licensee identified violation is not being cited because criteria specified in Section V.G. 1 of the NRC Enforcement Policy were satisfied.
The licensee identified the problem, took initial corrective action promptly upon discovery, and plans further extensive corrective action.
The licensee also reported the event in a timely manner via the ENS upon finding relays actually set outside the TS range.
Also, the licensee's analysis performed prior to the event showed that, while the undervoltage relay setpoints had been maintained slightly below the TS allowable range, they had been within the design basis for the unit.
This is NCV 389/90-16-01, Failure to Translate TS Bus Undervoltage Setpoints into Proper Surveillance Procedure Requirements.
The inspectors determined that, other than previous degraded grid relay setpoints, the current testing activities above were performed in a
satisfactory manner and met TS requirements.
4.
Maintenance Observation (62703)
Station maintenance activities involving selected safety-related systems and components were observed or.
reviewed to ascertain that they were conducted in accordance with requirements.
The following items were considered during this review:
LCOs were met; activities were accomplished using approved procedures; functional t'ests and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were
I
accompl i shed by quali fi ed personnel;
'parts and materi al s used were properly certified; and radiological controls were implemented as required.
Work requests were reviewed to determine the status of outstanding jobs and to assure that priority was assigned to safety-related equipment.
Portions of the following maintenance activities were observed:
NPWO 4944/61 performed a 36-month PM on MOV HCV-3625, LPSI Feed to Loop 1Al. Additionally, the pinion-gear-to-motor-shaft Woodruff key in the actuator was replaced per IN 88-24, Defective Motor Shaft Keys in Limitorque Motor Actuators.
The electrical maintenance department had completed a small percentage of the valves covered by this IN and had a
schedule to complete key replacements during the next three years.
NPWO 4083/62 completed a
36-month PM.on HCY-3635, Loop 281 LPSI Injection Valve.
The work involved an extensive valve operator inspection that included grease condition in three locations, torque switch material, limit switch contact condition, and seal inspections.
The work was performed thoroughly and efficiently.
NPWO 2630/62 completed transfer ring used ion exchange bed resin from the Unit 1 collection tank to a shipping container.
Work was per procedure HP 40,
.Rev 35, Shipment of Radioactive Material.
ALARA considerations were evident and work was expedited.
HP personnel overseeing the evolution were vigilant during each work step.
NPWO 5890/61 was initiated this peeiod to replace the Unit
CEA MG set output voltage coarse adjustment.
PCM 342-189 controlled this modification.
Work was progressing smoothly.
For those maintenance activities observed, the inspectors determined that they were conducted in a satisfactory manner and that the work was properly performed in accordance with approved maintenance work orders.
No violations or deviations were identified in the performance of the above NPWOs.
Onsite Followup of Written Nonroutine Event Reports (Units
and 2)
(92700)
LERs were reviewed for potential generic impact, to detect trends, and to determine whether corrective actions appeared appropriate.
Events that were reported immediately were reviewed as they occurred to determine if the TS were satisfied.
LERs were reviewed in accordance with the current NRC Enforcement Policy.
(Closed - Unit 1)
LER 335/89-05, Reactor Trip Due to Inadequate Pre-Maintenance Review.
This event was extensively discussed in IR 335/89-23, paragraph 6.
The LER accurately reported the event.
Corrective actions were
l
reviewed as follows:
AP 0010120, Rev 46, Duties and Responsibilities of Watchstanders, included responsibilities regarding sensitive systems and referred to the sensitive systems procedure.
AP 0010142, Rev 5, Unit Reliability - Manipulation of Sensitive Systems, included extensive changes.
A number of 18C procedures had been changed to include a
caution to ensure that all TCBs were closed prior to procedure performance.
Standard work descriptions for replacement of RPS power supplies were forwarded for insertion in the vendor manuals.
The inspector found the licensee's corrective actions to be acceptable.
This item is closed.
(Closed - Unit 1)
LER 335/89-06, TS Effluent Monitor Inoperable Due to Personnel Error While Performing Maintenance.
This LER reported a
licensee-identified violation of Unit
TS 3.3.3. 10 which required that the low-range noble gas activity monitors for the plant vent system be operable at all times.
A personnel error by maintenance technicians swapped two high voltage (signal)
cables serving a
noble gas monitor and an iodine monitor.
This was undetected for about two days because the readings appeared normal, but was discovered during routine surveillance tests.
Lack of equipment, detector, and high voltage cable labeling was identified as the primary causal factor.
Recent NRC inspection of the corrected labeling found all in place but one cable label and one detector label.
These had been labeled but the equipment had been subsequently replaced, without labels.
The licensee immediately installed new labels.
The, inspector found the licensee's corrective action to be acceptable.
This item is closed.
The licensee's corrective actions associated with this event met NRC Enforcement Policy Section V.G. 1 criteria for not issuing a Notice of Violation.
The event is identified as closed NCV 335/90-16-01, Inoperable Effluent Monitor.
(Closed - Unit 1)
LER 335/89-07, 1B3 4160 V Bus Undervoltage Relay Fails Surveillance Due to Equipment Malfunction.
This LER focused on difficulties encountered when placing a
4160 V
undervoltage load shed channel in the tripped condition [within one hour3 by installing jumper s when the relay failed.
The activity had not been pre-planned and the division of work at the plant involved three groups'he activity exceeded the one hour allowed by TS 3.3.2. 1, and placed the unit in TS 3'.3.
TS 3.0.3 then required that, within one hour, action be initiated to shut down the unit.
The relay jumpers were installed prior to this one hour limit, and initiation of a unit shutdown was not required.
Long term corrective action included addition of guidance to AP 1-0010125A, Data Sheet 38, Rev 15, Functional Test of Degraded Grid Voltage, for placing the undervoltage relay channels in the tripped
condition.
Unit 2 requirements were different such that the urgency was not as great.
The Unit 2 test was routinely scheduled during refueling shutdowns and Unit
TS 3.3.2 had a
48-hour action statement for an inoperable undervoltage relay.
(Closed - Unit 1)
LER 335/89-08, Missed Sealed Source Leak Test Surveillance Due to Personnel Error.
This LER reported a
licensee-identified Violation of Unit
TS 4.7.9. 1.2 and Unit
TS 4.7. 10.2.
which required semi-annual leak tests of certain radioactive sources.
Because of missed leak test surveillances at another site, the licensee re-inventoried these sources at St.
Lucie in conjunction with the scheduled leak test.
They identified one such source that had been on site since June, 1988, but was not on the HP semi-annual test list. It was leak tested, found to:be intact, and added to the list; The licensee's corrective actions associated with this event met NRC Enforcement Policy Section V.G. 1 criteria for not issuing a Notice of Violation and is identified as closed NCV 335/90-16-02, Missed Sealed Source Leak Check.
(Closed Unit 1)
LER 335/90-01, Low Steam Generator Pressure Trip to Main Steam Isolation Signal Set Below Technical Specification Allowed Minimum Value Due to Procedural Error.
This LER reported a licensee-identified Violation of TS 3.3.2, Table 3.3.4.
The minimum allowed setpoint for the low SG pressure input to the MSIS of the ESFAS was 585 psig.
The setpoint specified in 18C procedure 1"1400052 was 12.00 +/- 0. 10 mi lliamps, corresponding to 577.5 - 592.5 psig.
In the past,.
some setpoints had actually been set below the TS value.
A licensee analysis showed the setting remaining at least 14.2 psig above the assumed value in the limiting accident, the Steam Line Rupture Event.
Review of IEC procedure 1-1400052, Rev 27, found the setpoints changed to 12. 10 12.30 mi lliamps, corresponding to 592.5 607.5 psig.
Review of NPWO 6460/61 showed that the corrected settings were made in April, 1990.
The inspector found the licensee's corrective action to be acceptable.
This item is closed.
The licensee's corrective actions associated with this event met NRC Enforcement Policy Section V.G. 1 criteria for not issuing a Notice of Violation and is. identified as closed NCV 335/90-16-03, Improperly Set MSIS Input.
(Closed - Unit 1)
LER 335/90-02, Missed Surveillance on 125 Volt DC Batteries Results in TS Violation Due to Personnel Error.
This LER reported a licensee-identified Violation of TS
~ 8.2.4.2 which required that weekly battery surveillances be performed.
The
l l
surveillance included speci'fic gravity, electrolyte levels, and pilot cell float voltage.
Review of circumstances surrounding the violation found that the violation was an isolated case involving a marginally administered program coupled with the vacation turnover between supervisors during an outage.
Review of subsequent corrective action found a three-pronged approach:
MP-0930021, Electrical Maintenance Department Surveillance/
Testing Schedule, was changed in Rev
to enhance program administrati'on by describing in detail the planning and management process required to successfully manage surveillances or PMs.
This included monthly checklists for the supervisor to use.
The computerized NPWO process was fully integrated into electrical PM administration.
The monthly and more frequent PMs were scheduled on a specific day of the week rather than a date to enhance the ability to remember repetitive tasks.
PMs, and then all electrical NPWOs, have recently been issued for work in easy-to-find color coded notebooks containing technical and work control documents, qualified mechanic lists, and the job performance requirements for qualifying new persons on that task.
The inspector found the licensee's corrective action to be acceptable.
This item is closed.
The licensee's corrective actions associated with this event met NRC Enforcement Policy Section V.G. 1 criteria for not issuing a Notice of Violation and is identified as closed NCV 335/90-16-04, Failure to Perform Battery Surveillance.
(Closed Unit 1)
LER 335/90-03, Spurious Containment Isolation Signal Actuation Resulting From Radiation Monitor Noise Spike.
This event was extensively reported in IR 335/90-08, paragraph 2.b and Appendix A.
The issues were satisfactorily resolved at the time.
The LER accurately reported the event.
This item is closed.
(Closed - Unit 1)
LER 335/90-05, Emergency Diesel Generator Automatic Start due to Loss of Electrical Bus Caused by Breaker Failure.
This event, involving large Westinghouse brand circuit breaker models 50DHP250, 50DHP350, and 75DHP500, was previously reported in IR 335,389/90-13, paragraphs 2.'b and 4.
Local corrective action resolved the issue for Unit 1 circuit breakers and plans have been made to resolve the issue for Unit 2 during the September, 1990; refueling outage.
This issue appears to have generic implications at other sites and has been forwarded to NRC Region II for consideration
of expanded action.
The licensee notified other utilities via an industry network.
A 10 CFR 21 report was not required because these breakers were not installed in safety-related applications in either unit.
This item is closed.
(Closed
- Unit 1)
LER 335/90-06, Missed Surveillance on Control Element Assemblies Due to Procedural Deficiency.
This LER reported a
licensee-identified TS violation where survei llances 4. 1.3. 1.2 (Unit 1)
and 4. 1.3. 1.3 (both units),
involving CEA block circuits, were not performed each startup but were performed once a
month on a certain day.
It was possible, if the reactor was in a shut down mode on the normal performance day, to miss that month's surveillance.
Subsequent testing showed that this block circuit had been operable during the time the surveillance was overdue.
Review of OP 1-0030122, Rev 38, and 2-0030122, Rev 24, Reactor Startup, showed that new procedure step 8. 11 and 8. 10, respectively, conducted the tests unless they had been completed within the last
days.
The inspector found the licensee's corrective action to be acceptable.
This item is closed.
'he licensee's corrective actions associated with this event met NRC Enforcement Policy Section V.G. 1 criteria for not issuing a Notice of Violation and is identified as closed NCV 335/90-16-05, Failure to Perform CEA Block Circuit Surveillance.
(Closed - Unit 1)
LER 335/90-07, Manual Reactor Trip Following Severe Leakage of Main Turbine Digital Electro-Hydraulic Control Fluid Due to the Installation of Improperly Sized O-Rings.
This event was previously reported in IR 335/90-14, paragraph 2.b.
The LER accurately reported the event.
The licensee's corrective actions were acceptable.
This item is closed.
(Closed
-
Unit 1)
LER 335/90-08, Reactor Shutdown Due to Unrecoverable CEA Caused by an Improperly Installed Fuse.
This LER reported an event where one CEA dropped several times over about a
seven hour period.
At each CEA drop, turbine power was decreased to match reactor power and corrective actions were taken for the apparent causes.
Power was not increased during this time period.
When the CEA dropped the fourth time, the licensee shut down the reactor from
percent power and declared an Unusual Event because the cause was not apparent.
A loose bayonet-type fuse cover in a timer module was found to be the proximate cause.
Corrective actions included checking other fuse holders and notifying shop and training personnel of the occurrence.
The inspector found the licensee's actions to be acceptable.
This item is close I
~
~
(Closed
- 'Unit 2)
LER 389/89-01, Water in Ductwork Results in Inoperability of Fuel Handling Building Cross-Tie to Shield Building Ventilation Due to Personnel Error.
This LER discussed the flooding of the ventilation cross tie ductwork between the Unit
spent fuel pool and the shield building ventilation.
Unit 1 does not have such a"'cross tie.
The immediate actions restored the systems to operability.
The personnel error involved compensatory measures for an inoperable fuel pool level annunciator and could not be traced to one person.
The licensee issued a night order to sensitize persons to fuel pool level alarms and revised Units 1 and 2 normal and off-normal fuel pool operating procedures to require a dedicated level watch during level changes if the control room level annunciation were out of service.
The licensee also revised OP 2-1630022, Refueling Sequencing Guidelines, to require that the fuel pool ventilation be demonstrated operable prior to refueling operations.
Subsequent NRC inspection of ductwork portions and an isolation damper found good material conditions.
The licensee's corrective actions were acceptable.
This item is closed.
(Closed - Unit 2)
LER 389/89-02, Containment Isolation Valve Fails Leak Test Because Post Maintenance Testing Not Performed Due to Procedural Deficiency.
This LER reported a
licensee-identified TS violation where a,.
containment isolation valve had a leak rate exceeding the allowed leak rate for a period of two years and four months.
The high leak rate occurred when the valve was repacked such that it would not seat properly.
Procedure QI ll-PR/PSL-2, Rev 14, Mechanical Test Control, identified the valve and required both pre and post maintenance testing.
The check sheet implementing the procedure had only one column for initials and the planner assumed the initial in the column meant post maintenance testing had been completed.
This was subsequently found during routine local leak rate testing.
Corrective action included repairing the valve, retesting, and procedure check sheet changes to clearly separate pre and post, maintenance testing status.
The inspector found these corrective actions acceptable.
This item is closed'he licensee's corrective actions associated with this event met NRC Enforcement Policy Section VS G. 1 criteria for not issuing a Notice of Violation and is identified as closed NCV 389/90-16-02, Failure'o Post Test Containment Isolation Valve Repairs.
(Closed Unit 2)
LER 389/90-01, Automatic Reactor Trip on Low Steam Generator Water Level During Power Ascension Due to Personnel Error.
This event was previously discussed in detail in IR 389/90-02, paragraph 2.b.
and NOV 389/90-02-01.
The LER accurately described the event.
The licensee's corrective actions, described in report
paragraph 8, were acceptable.
This item is closed.
6.
Onsite Followup of Events (Units 1 and 2)(93702)
Nonroutine plant events were reviewed to determine the need for further or continued NRC response, to determine whether corrective actions appeared appropriate, and to determine that TS were being met and that the public health and safety received primary consideration.
Potential generic impact and trend detection were also considered.
On June 14, Unit 1 declared an Unusual Event, which was reported in LER 90-008.
The unit was at 100 percent power when CEA 8 in the B
shutdown bank spuriously dropped three times and was recovered per procedure each time.
Upon the fourth CEA drop, the operators shut down the reactor from 45 percent power.
The Unusual Event was exited after Unit 1 entered mode three.
This event is discussed further in paragraph 2.b.
Between the afternoon of June
and morning of July 2, RCP 1Al vibration had risen to" 9 mi ls from about 5 mi ls and RCP seal leakoff had incr eased to about 3.5 gpm from about 1 gpm.
At that point, FPL management ordered an orderly shutdown.
The unit was in hot shutdown by that afternoon.
This event is discussed further in paragraph 2.b.
7.
Followup of Post-THI Action Items and NRC Bulletins (Units
and 2)
(92701)
The inspectors were requested by NRC Region II to determine the status of certain generic items, as follows:
(Closed Unit 1)
TMI Item II.E.4. 1.2, Dedicated Hydrogen Penetrations.
This item was item 2. 1.5 in NUREG 0578, July 1979.
It was renumbered as II.E.4. 1 in NUREG 0660, August, 1980; clarified as II.E.4. 1 in NUREG 0737, November 1980; initially tracked as II.E.4. 1. 1.b; and recently renumbered to II.E.4. 1.2.
The item had two essential elements:
Install dedicated Hydrogen control penetrations if the unit did not have internal Hydrogen recombiners
~
Review and revise combustible gas control procedures if necessary.
These elements were inspected and reported closed in IRs 335/80-35, November 7,
1980, paragraph 7.h.,
and 335/81-18, August 10, 1981, paragraph (Closed - Unit 1)
BL-79-08, Office of Inspection and Enforcement Bulletin 79-08, Events Relevant to Boiling Water Reactors During the TMI Accident.
'
This bulletin was closed for Unit 2 in this inspector's IR 335/82-05, 389/82-04 as not applicable to PWRs.
It was not applicable to Unit
either but not closed for Unit 1 at that time due to oversight; (Closed
- Units
and 2)
TMI Item III.D.3.4.3, Control Room Habitability Implement Modifications.
This was Item III.D.3.4 in NUREG 0660 and NUREG 0737.
It was tracked as item III.D.3.4, sub-item 2,
and has been recently renumbered to III.D.3.4.3.
The licensee's analysis of this item was submitted in letter L-81-4 dated January 2,
1981.
This item was subsequently reviewed for Unit 1 during the period of June 8-19, 1981, and discussed in Emergency Preparedness Appraisal ( IR) 335/81-13, paragraph 4. 1. 1. 1. Ii was
- found to be acceptable.
Unit 2 was evaluated as acceptable in NUREG 0843, St.
Lucie 2 Operating License Safety Evaluation Report.
The item was closed for both units in subsequent IR 335/81-35, 389/81-26 dated February 18, 1982.
(Closed - Unit 2)
TMI Item II.B.4.2.A, Training for Mitigating Core Damage - Initial Implementation.
This was item II.B.4 in NUREG 0660 and II.B.4.2.a in NUREG 0737, enclosure 1.
The NUREG 0737 companion item was II.BE 4.2.b, Complete the Program Implementation.
Program implementation was initiated prior to Unit 2 licensing and tracked under the Unit 1 docket number.
The operators for Unit 2 came from Unit 1 ranks.
Program initiation and progress were addressed in IRs 335/81-18 and 82-04.
The applicability of the Unit 1 program to Unit 2 was found acceptable by the NRC in NUREG 0843, St.
Lucie
Operating License Safety Evaluation Report, Supplement 1,'hapter 22.
Program completion ( II.B.4.2.b)
for both units was documented in IR 335/84-02, 389/84-03.
Since the Unit
and 2 programs were actually only one program, the Unit 2 program was considered to have been initiated simultaneously with the Unit 1 program.
(Closed - Unit 2)
TMI Item II.K.3.5.b, B80 Task Force - Auto Trip of RCPs, Modifications.
This was one of two sub-items under NUREG 0737 item II.K.3.5, Automatic Trip of RCPs During LOCA.
Sub-item "a" addressed utilities proposing modifications for NRC approval.
Sub-item
"a" was not to occur until computer LOCA analysis models were validated against Loss of Flow Test L3-6.
No NRC field inspection of power plants was involve Sub-item
"b" addressed completion of the modifications, when approved.
Sub-item
"b" was left open in IR 335/84-33, 389/84-39, dated January 14, 1985, pending NRC evaluation of CE owners group recommendations.
Future NRC field inspection of completed modifications was intended.
NRC evaluation and acceptance of the owners group proposal to use a
'trip-two/leave-two'pproach was documented in GL 86-06, dated May 29, 1986.
No hardware changes were proposed.
NRC specific plant concerns were addressed in FPL letters L-86-325, dated August 6, 1986; L-87-265, dated July 1, 1987; and L-88-176, dated April 11, 1988.
NRC closed TMI item II.K.3.5 for St.
Lucie Units 1 and 2 in a
letter to FPL dated March 15, 1989.
That letter stated that FPL has adopted and implemented the CE owners group methodologies.
Subsequent EOP inspections 335,389/88-08 and 89-27 discussed implementation of the 'trip-two/leave-two'pproach.
The inspector concludes that TMI item II.K.3.5.b is closed because there were no equipment modifications to complete.
(Closed - Units
and 2) TMI Item I.D.2.3, Fully Implement a Safety Parameter Display Console per NUREG 0696, Rev 2.
This item was NUREG 0660 item I'.2, Plant Safety Monitor Display Console, and NUREG 0737 item I.D.2, sub-item 3, Fully Implement a
Plant Safety Parameter Display Console.
NUREG 0737 also referred to NUREG 0696 as the guidance document.
Subsequently, on December 17, 1982, GL 82-33 forwarded NUREG 0737 Supplement 1,
Requirements for Emergency Response Capability.
IR 335,389/84-10 closed for both units related item I.D.2.2, Install a
Safety Parameter Display Console, but left open item I.D.2.3 concerning full implementation.
NUREG 0843, St.
Lucie 2 Operating License Safety Evaluation Report, discussed item I.D.2 but left it open for later completion.
License condition 2.C. 17.f, Inadequate Core Cooling Instrumentation ( II.F.2, SSER 1) required certain QSPDS items be operable.
It was inspected in IR 389/88-08 and the license condition closed in License Amendment 34, dated September 3,
1988.
Subsequent GL 89-06 forwarded NUREG-1342, A Status Report Regarding Industry Implementation of the Safety Parameter Display System, and a checklist.
The GL requested utility certification that their SPDS met NUREG 0737, Supplement 1,
requirements taking into account NUREG 1342 information.
FPL letter L-89-244, dated August 14, 1989, provided that certification. It was then inspected on March 21-23, 1990, by the DCRDR team from NRC Headquarters.
NRC letters dated April 23 and May 9, 1990, discussed these issues and concluded that St Lucie Units 1 and 2 met all NUREG 0737 Supplement 1 requirements.
This item is closed.
(Closed - Unit 2) TMI Item II.B.3. 1, Post Accident Sampling - Interim System.
This item was from NUREG 0737, Enclosure 1, Post-TMI Requirements for Operating Reactors.
It did not apply to St Lucie Unit 2, which was
~
I
~
being constructed.
NUREG 0737, Enclosure 2,
TMI Action Plan Requirements for Applicants for an Operating License, was the operative enclosure and did not address an interim system.
Regarding the Unit
status of TMI item II.B.3, the item was discussed in NUREG 0843, St.
Lucie
Operating License Safety
'valuation Report, and supplements 1,
2, and 3.
License condition 2.C. 17.d required the licensee to have the post accident sampling system installed and operational prior to initial criticality.
The condition was satisfied and deleted in license amendment 34.
IRs 389/82-62 and 83-25 discussed the system and IR 389/84-07 evaluated and closed the TMI item.
8.
Followup of Corrective Actions for Violations and Deviations (92702)
(Closed - Units
and 2)
VIO 335,389/89-20-01, Containment Cooler Access Doors Not Properly Sealed in Required Modes.
FPL letter L'-89-384, dated October 20, 1989, responded to this Notice of Violation.
The violation involved inadequate controls for the containment fan cooler access doors and for the use of filter media to cover the fan cooler coils.
Corrective action included immediate correction of the conditions found, procedure reviews, stenciling of instructions on the doors, and revis'ion to the fan cooler technical manual.
Inspectors observed the immediate correction of the conditions found and, on July 10, 1990, verified that the Unit 1 fan cooler doors were closed properly and stenciled with instructions to close and latch all dogs upon completion of work.
Review of procedure AP 1-0010728, Rev 2, Post Outage Review, found a required plant management tour of the containment building and a list of attributes
-
including fan cooler doors and filter media.
AP 1-0010125, Rev 81, Check Sheet 5,
required that the containment cooler doors be checked to be dogged closed during the bi-weekly anomaly inspections.
Vendor manual 8770-6772, Rev 2, dated September 1,
1989, contained changes to sections 1.3.6 and 3.5, which addressed roughing filters, to require that they be removed prior to power operation of the reactor.,
These corrective actions have been reviewed and found to be acceptable.
This item is closed.
(Closed Unit 1)
VIO 335/89-20-03, EDG 1B Fuel Oil Transfer System Inoperable.
FPL letter L-89-384, dated October 20, 1989, responded to this Notice of Violation.
The violation included the licensee's failure to use the procedure for administrative control of valves, locks, and switches to control a
fuel oil transfer pump discharge valve position, such that the valve was shut rather than locked-open as required, and failure to detect the out-of-position valve during a
weekly valve lineup check.
The licensee investigated this occurrence and found that it was caused by two personnel error Failure to obtain permission to reposition the valve.
Inadequate method of subsequently determining valve position.
The system lineup was immediately corrected.
A review of AP-0010123 was included in the then-current cycle of non-licensed operator requalification and a hands-on
'approach was specified when verifying valve position.
Review of training material showed that the hands-on approach to verifying valve positions came from INPO good practice OP 216, which was taught during the training cycle.
Furthermore, this particular event and its causes were again addressed during the operating experience review portion of the requalification program and then again the next year.
Administrative control of valves, locks, and switches was an integral part of each non-licensed watch station qualification, so it would be readdressed for each advancement made by the non-licensed operator.
These corrective actions were reviewed and found to be acceptable.
This item is closed.
(Closed Units
and 2)
VIO 335,389/89-23-01, Inadequate PM Procedures for ICW Pump Bearing Cooling Water Strainers.
FPL letter L-89-440, dated December 13, 1989, responded to the Notice of Violation.
This violation involved PM procedures that did not incorporate vendor technical information such as inspection acceptance criteria, service limits, or repair specifications.
The shortcomings contributed to equipment failures.
Corrective action included upgrading the specific procedures involved and reviewing a
sample of other PMs for similar problems.
Unit
PMs 153-156, Rev 15, and Unit
PMs 00501-00504, Rev 16, were reviewed and found acceptable.
The licensee's sample review failure rate was such that all mechanical PMs were reviewed and about
percent found to require upgrade.
FPL letter L-90-138, dated April 13, 1990, and responding to subsequent violation 389/90-02-02, expected, procedure upgrade completion by December, 1990.
Since the specific procedures were upgraded and general upgrading is being tracked under 389/90-02-02, this item is closed.
(Closed
-
Unit 1)
VIO 335/89-23-02, Inadequate Procedure and Management Control of Resin Replacement.
FPL letter L-89-440, dated December 13, 1989, responded to this Notice of Violation.
The violation involved incomplete restoration of the resin fill systems and station following use.
Licensee evaluation determined that this violation resulted from a combination of an inadequate procedure and a personnel error.
The inspectors observed at the time that the offending fill funnels were immediately removed; the gasketed flanges installed; and the metal trench covers replaced.
OP 1-0520020, Rev 25, was reviewed and found to have
specific steps added to resin fill appendices A and B to insure adequate interface with the mechanical maintenance and chemistry departments.
Current Rev 26 retained those steps.
OP 2-0520020, Rev 15, had similar steps added to section 8. 13 which controlled Unit
resin additions.
(Closed - Unit 2)
VIO 389/90-02-01, Failure to Properly Implement Unit 2 Startup Procedures.
FPL letter L-90-138, dated April 13, 1990, responded to the Notice of Violation.
The licensee determined that this incident was caused by personnel error.
Corrective action focused on three areas:
Counseling of shift supervision concerning attention to detai
and procedure compliance.
Changes to procedures OP 182-0030124, Turbine Startup 7ero to Full Load, to require that, at the appropriate power levels, power ascension be actually stopped until the second condensate pump or second feedwater pump is started.
Procedure revisions
and 35, respectively, were confirmed to contain these changes.
Issuance of Standing Night Order A-1 which had three major provisions:
First, it required.the NPS to remain in the control room during any significant changes in power level unless an emergency existed on the other unit.
Second, it required a
second experienced supervisor be present in the control room in an advisory capacity during reactor startups, turbine rolls, power escalations, and plant shutdowns.
Third, it required that such major evolutions would stop during shift change and not restart until after a shift briefing by the NPS/ANPS.
Standing Night Order A-1 was confirmed to still be in effect on June 20.
Additionally, review of NPVO 7568/62 showed that the MFP low suction pressure trip setting, a contributing factor, was reset to it'
proper operating band.
These actions were found to be effective during several major evolutions observed during the Spring of 1990.. This item is closed.
9.
Exit Interview (30703)
The inspection scope and findings were summarized on July 27, 1990, with those persons indicated in paragraph 1 above.
The inspector described the areas inspected and discussed in detail the inspection findings listed below.
Proprietary material is not contained in this report.
Dissenting comments were not received from the licensees
Item Number Status Description and Reference 335,389/89-20-01 Closed VIO - Containment Cooler Access Doors Not Properly Sealed in Required Modes, paragraph 8.
335/89-20-03 335/89-23-01 335/89-23-02 389/90-02-01 335/90-16-01 335/90-16-02 335/90-16-03 335/90--16-04 335/90-16-05 389/90-16-01 Closed Closed Closed Closed Closed Closed Cl osed Closed Cl osed Closed VIO -
EDG 1B Fuel Oil Transfer System Inoperable, paragraph 8.
VIO - Inadequate PM Procedures for ICW Pump Bearing Cooling Water Strainers, paragraph 8.,
VIO Inadequate Procedure and Management Control of Resin Replacement, paragraph 8.
VIO - Failure to Properly Implement Unit 2 Startup Procedures, paragraph 8.
NCV - Inoperable Effluent Monitor, paragraph 5.
NCV - Missed Sealed Source Leak Check, paragraph 5.
NCV Improperly Set MSIS Input, paragraph 5.
NCV - 'Failure to Perform Battery Surveillance, paragraph 5.
NCV Failure to Perform CEA Block Circuit Surveillance, paragraph 5.
NCV - Failure to Translate TS Bus Undervoltage Setpoints Into Proper Surveillance Procedure Requirements, paragraph 3.
Cl osed 389/90-16-02 NCV Failure to Post Test Containment Isolation Valve Repairs, paragraph 5.
I 10.
Abbreviations, Acronyms, and Initialisms A
Auxiliary Building ASEA Brown Boveri (company)
Alternating Current Automatic CEA Timing Module
ADV A/E AFAS AFW ALARA ANPO ANPS ANSI AP ASME Code ATI ATWS 88(0 BCS BQAP CAR CCW CE CEA CEDM CEDMCS CET CFR CIAS CIS CRAC CRT CS CST CT CVCS CWD CWO DC DCN DCRDR DDPS DEH DEV DPR ECC ECCS EDG ENS EOP EPA EPRI ERDADS ESF Atmospheric Dump Valve Architect/Engineer Auxiliary Feedwater Actuation System Auxiliary Feedwater (system)
As Low as Reasonably Achievable (radiation exposure)
Auxiliary Nuclear Plant [unlicensedj Operator Assistant Nuclear Plant Supervisor American National Standards Institute Administrative Procedure American Society of Mechanical Engineers Boiler and Vessel Code Automatic Test Instrument (in the ESF cabinets)
Anticipated Transient Without Scram lNRC] Bulletins and Orders (Task Force)
Backfit Construction Sketch Backfit Quality Assurance Procedure (EBASCO Services Corrective Action Request Component Cooling Water Combustion Engineering (company).
Control Element Assembly Control Element Drive Mechanism Control Element Drive Mechanism Control System Core Exit Thermocouple Code of Federal Regulations Containment Isolation Actuation Signal Containment Isolation System Control Room Auxiliary Control (panel)
Cathode Ray Tube Containment Spray (system)
Condensate Storage Tank Current Transformer Chemical
& Volume Control System Control Wiring Diagram Construction Work Order Direct Current Design Change Notice Detailed Control Room Design Review Digital Data Processing System Digital Electro-Hydraulic (turbine control system)
Deviation (from Codes, Standards, Commitments, etc.)
Demonstration Power Reactor (A type of operating lic Estimated Critical Position Emergency Core Cooling System Emergency Diesel Generator Emergency Notification System Emergency Operating Procedure Environmental Protection Agency Electric Power Research Institute Emergency Response Data Acquisition Display System Engineered Safety Feature Pressure Inc.)
ense)
ESFAS F
FCV FI FIS FPL FRG FSAR FT GDC GE GL GMP gpm HCV HFA HJTC HP HPSI HVE HVS HX I&C ICW IFI ILRT IN INPO IR ISI IX JPE JPN KV KW LC LCO LER LIV LOCA LOI LPSI LT LTOP M&TE MCC MFIV MFP MFA(
MG Engineered Safety Feature Actuation System Fahrenheit Flow'ontrol Valve Flow Indicator Flow Indicator/Switch The Florida Power
& Light Company Facility Review Group Final Safety Analysis Report Flow Transmitter General Design Criteria (from 10 CFR 50, Appen General Electric Company
[NRCj Generic Letter General Maintenance Procedure Gallon(s)
Per Minute (flow rate)
Hydraulic Control Valve A GE relay designation Heated Junction Thermocouple Health Physics High Pressure Safety Injection (system)
Heating and Ventilating Exhaust (fan, system, Heating and Ventilating Supply (fan, system, e
Heat Exchanger Instrumentation and Control Intake Cooling Water
[NRC] Inspector Followup Item Integrated Leak Rate Test(ing)
[NRC] Information Notice Institute for Nuclear Power Operations
[NRC] Inspection Report InService Inspection (program)
Ion Exchanger (Juno Beach)
Power Plant Engineering (Juno Beach) Nuclear Engineering KiloVolt(s)
Ki 1 oWatt( s)
Load Center (electrical distribution)
TS Limiting Condition for Operation Licensee Event Report Licensee Identified Violation Loss of Coolant Accident Letter of Instruction Low Pressure Safety Injection (system)
Level Transmitter Low Temperature Overpressure Protection (syste Measuring
& Test Equipment Motor Control Center (electrical distribution)
Main Feed Isolation Valve Main Feed Pump Main Feed Water Motor Generator dix A)
etc.)
tc ~ )
m)
min MOV MOVATS mrem MP MSIS MSIV MSR MTI MV MW NCR NCY NDE NPF NPO NPS NPWO NRC NSSS NUREG OI ONOP OP PAP PBT PCM PCV PAID PI PIC PIS PM PORV PSB psig ppm PT PWO PWR QA QC QI QSPDS RAB RCB RCFC
- RCO RCP RCPB minute Motor Operated Valve Motor Operated Valve Test System mi 1 1 irem Maintenance Procedure Main'team Isolation Signal Hain Steam Isolation Valve Moisture Separator/Reheater Maintenance Team Inspection Motorized Valve Megawatt(s)
Non Conformance Report NonCited Violation (of NRC requirements)
Non Destructive Examination Nuclear Production Facility (a type of operating license)
Nuclear Plant Operator Nuclear Plant Supervisor Nuclear Plant Work Order Nuclear Regulatory Commission Nuclear Steam Supply System Nuclear Regulatory (NRC Headquarters Publication)
Operating Instruction Off Normal Operating Procedure Operating Procedure Post Accident Panel Performance Based Training Plant Change/Modification Pressure Control Valve Piping 6 Instrumentation Diagram Pressure Indicator Pressure indicator/Controller Pressure Indicator/Switch Preventive Maintenance Power Operated Relief Valve
'lant Systems Branch (of NRC Headquarters)
Pounds per square inch (gage)
Part(s)
per Million Pressure Transmitter Plant Work Order Pressurized Water Reactor Quality Assurance Quality Control Quality Instruction Qualified Safety Parameter Display System Reactor Auxiliary Building Reactor Contaipment Building Reactor Compartment Fan Cooler Reactor Control Operator Reactor Coolant Pump Reactor Coolant Pressure Boundary
RCS RDT Rev RG RNWO RO RPS RTGB
. RVLMS RWT SAL SALP SAS SDC SDCHX SDCS SER SFP SG SI SIT SNOW SNPO SPDS SRO SSER STA Tavg TC TCB TCW TDI TE TEDB TI TMI TR TS URI V
VCT VIO Reactor Coolant System Reactor Drain Tank
.
Revision
[NRC] Regulatory Guide Relay Nuclear Work Order Reactor [licensed] Operator Reactor Protection System Reactor Turbine Generator Board Reactor Vessel Level Monitoring System Refueling Water Tank Service Advice Letter Systematic Assessment of Licensee Perf Safety Assessment System Shut Down Cooling Shut Down Cooling Heat Exchanger Shut Down Cooling System Safety Evaluation Report Spent Fuel Pool Steam Generator Safety Injection (system)
Safety Injection Tank Short Notice Outage Work Senior Nuclear Plant [unlicensed]
Oper Safety Parameter Display System Senior Reactor [licensed] Operator Supplemental Safety Evaluation Report Shift Technical Advisor Reactor average temperature Temporary Change Trip Circuit Breaker Turbine Cooling Water Training Department Instruction Temperature Element Total Equipment Data Base
[NRC] Temporary Instruction Three Mile Island Temperature Recorder Technical Specification(s)
[NRC] Unresolved Item Volt(s)
Volume Control Tank Violation (of NRC requirements)
ormance ator