IR 05000397/1992023
| ML17289A817 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 08/10/1992 |
| From: | Johnson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17289A816 | List: |
| References | |
| 50-397-92-23, NUDOCS 9209010023 | |
| Download: ML17289A817 (48) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
.
REGION V
Report No:
Docket No:
License No:
Licensee:
Facility Name,:
Inspection at:
50-397/92-23
'0-397 NPF-21 Washington Public Power Supply System-P. 0.
Box 968 Richland, WA 99352 Washington Nuclear Project No.
(WNP-2)
WNP-2 site near Richland, Washington Inspection Conducted:
June 1 - July 12, 1992 Inspectors:
R.
C. Sorensen, Senior Resident Inspector D. L. Proulx, Resident Inspector R. L. Nease, Acting Resident Inspector Approved by:
P.
H.
hnson, Chief Reac Projects Section
~j/s (0a Date Signed
~Summar:
Ins ectio on June
- Jul
50-397 92-23
~l<<d:
R tt t
p tt tytt td tt p t f
t room operations, licensee action on previous inspection findings, operational safety verification, surveillance program, maintenance program, licensee event reports, and special inspection topics.
During this inspection, Inspection Procedures TI/2515-113, 40500, 61707, 61726, 62703, 71707, 71711, 90712, 92700, 92701, 92702 and 93702 were used.
Safet ssues Mana ement S stem SINS tems:
None.
~esul ts:
Gene al Conclus'ons and S ecific d'
Si nificant Safet Matters:
None.
Summar of Violations and Deviations:
One non-cited violation was identified involving the failure to perform a safety evaluation for a temporary modification.
0 en Items Summar
- Two followup items and
LERs were closed.
9209010023 920810 PDR ADOCK 05000397 Q
III
~ET (~IS ersons Contacted 2.
V. Parrish, Assistant Managing Director for Operations
- J. Baker, Plant Manager L. Harrold, Assistant Plant Manager
- G. Sorensen, Regulatory Programs Manager
- D. Pisarcik, Health Physics and Chemistry Manager J.
Harmon, Maintenance Manager A. Hosier, Licensing Manager S. Davison, guality Assurance Manager
- J. Peters, Administrative Manager
- W. Shaeffer, Acting Ope} ations Manager-
- R. Webring, Plant Technical Manager
- D. Feldman, Assistant Maintenance Manager
- J. Bass, guality Assurance Engineer
'C. Fies, Compliance Engineer The inspectors also interviewed various control room operators, shift supervisors and shift managers, maintenance, engineering, quality assurance, and management personnel.
"Attended the Exit Meeting on July 16, 1992.
lant Status 3.
At the start of the inspection period, the plant was in Mode 5 with reload of the core in progress.
On June 5, reload of the core was completed.
On June 27, the vessel head was reinstalled, the head studs were retensioned, and the plant entered Mode 4 (Cold Shutdown).
All outage work and surveillances were completed, and the plant entered Hode 2 (startup)
on July 4.
On July 6, with the reactor in Mode 1 (Power Operation)
at 14% power, safety-relief valve (SRV) HS-RV-3B stuck in the open position during surveillance testing.
The SRV remained stuck open for greater than two minutes, which required a manual reactor scram.
The licensee declared an unusual event (UE) in accordance with the emergency plan implementing procedures,(EPIPs).
Shortly after the scram, the SRV reseated and the licensee completed cooldown of the plant to Mode 4.
After troubleshooting and repairing HS-RV-3B, as well as work on RFW-FCV-10B and the Reactor Core Isolation Cooling (RCIC) turbine controller, the plant was restarted on July 10.
On July ll, HS-RV-3B stuck open again during testing.
The plant was manually scrammed from 14% power again, and cooled down to Mode 4, where it remained until the end of the inspection period.
reviousl Identified NRC Ins ection Items 92701 9270 The inspectors reviewed records, interviewed personnel, and inspected plant conditions relative to licensee actions on previously identified inspection findings:
II
i
a ~
Closed Violation
91-04-0:
ailure to Test Standb Gas eatment S
P c
S c
c o
e u'rne ts b.
The inspector had identified a failure by the licensee to test the SGT system per Technical Specification requirements.
Specifically, the licensee did not test the charcoal beds and HEPA filters per Regulatory Guide 1.52.
As corrective action, the licensee revised two surveillance procedures to include the proper method for testing the charcoal adsorbers and the HEPA filters.
The procedures revised were PPH 7.4.6;5.3.5,
"SGT System HEPA Dioctylphthalate (DOP) Test and Visual Inspection" and PPH 7.4.6.5.3.6,
"SGT System Adsorber Bypass Leakage Test."
Further, the licensee affixed permanent. labels to the 'SGT filtration units to identify the locations where testing media are to be injected and samples 'are to be taken.
Finally, the licensee reviewed the surveillance procedures for other systems that utilize charcoal adsorbers and HEPA filters to ensure that those systems were being tested properly in accordance with Technical Specifications requirements.
The inspector verified the above actions and was satisfied with the licensee's response.
This item is closed.
Closed Unresolved Item
9 -44-03 'nvi onmental uglification of Containment tmos her'c Cont o
C C
ressure T a smitter Indeterminate The inspector had discovered a conduit plug for CAC-PT-lA (a pressure transmitter for CAC Fan 1A) on the floor and found another plug that was loose on the same transmitter.
The missing plug left an opening in the side of CAC-PT-1A, and electrical leads were visible inside.
The inspector questioned the environmental qualification of CAC-PT-lA in this configuration.
The licensee's equipment qualification group determined that the condition of the transmitter plugs would not affect the environmental qualification of the transmitter.
While the transmitter is in a zone of the reactor building that is affected by a high energy line break (HELB), the CAC equipment is not required to function to mitigate a
HELB condition.
Consequently, any HELB design basis environmental effects are not part of the design basis for CAC.
The CAC system is required to function to mitigate a
LOCA condition.
However, moisture intrusion into the CAC pressure transmitter from a LOCA is not of concern.
This item is closed.
No violations or deviations were identified.
4.
eactor Scrams While Conductin Safet Relief Valve Testin 93702 On the morning of July 6, while conducting testing of acoustic monitors for safety relief valves (SRV), the plant was manually scrammed from 14K
'N
-3-power.
Technical Specificatio'ns require the acoustic monitors to be calibrated every refueling outage.
This is typically accomplished by manually opening SRVs with the reactor in the run mode.
Seventeen of the
, eighteen SRVs had been lifted successfully from the control room.
Dn
.
this particular occasion however, SRV HS-RV-3B would not operate from the control room.
As part of a routine surveillance, the valve was also'cheduled to be lifted from the alternate remote shutdown panel (ARSP).
The valve was successfully lifted from the ARSP and the required
'calibration of the acoustic monitor was performed.
However, the-valve would not reseat when the control switch was taken back to the closed position.
Control power was transferred back and for'th from the ARSP to the control room twice in an attempt to reseat the valve, with no success.
Technical Specifications require that the reactor mode switch be placed'in shutdown (reactor scram) after an SRV has been stuck open for two minutes.
This was accomplished at 4:58 a.m.,
and the reactor scrammed from approximately 14X power.
The valve reseated a few seconds after the scram when plant pressure was about 850 psi.
An Unusual Event was declared a few minutes later and was terminated at 5:48 a.m.
Two entry conditions to the Emergency Operating Procedures (EOPs)
were met'on high, suppression pool temperature and low vessel level, and the EOPs were entered for about five minutes.
Recovery from the scram was uneventful except for the loss of the reactor feedwater pumps when reactor vessel water level reached Level 8.
This was due to the feedwater level control valve (RFW-LCV-10B) behaving in a sluggish manner.
This was later determined to be the result of an air regulator in the supply air to the valve operator being set at 25 psi vice the required 80 psi'.
The licensee conducted extensive troubleshooting in an attempt to determine why the valve would not reseat.
Voltages were checked from the ARSP and the control room down to the valve and were found to be normal.
The valve actuator was disconnected and stroked from both the control room and the ARSP.
The valve was stroked cold.
The only abnormality noticed was a stickiness in the solenoid valve.
Three other SRVs had
their actuators disconnected from the valve and stroked several times in a effort to uncover any hidden problems; No problems were identified.
Other issues addressed by the licensee during this time period included:
Replacement of all bolts and studs of less than Grade 5 hardness fastening Limitorque motor oper'ators to valve yokes or bonnets.
Discovery that certain diesel building exhaust air fans, as well as fans in certain other vital areas,.did not automatically restart after a loss of offsite power.
This was r ectified for the short term by revising the abnormal event procedure for loss of offsite power directing operators to restart the fans.
A Basic Design Change to cause this to occur automatically was planned for September.
In some cases certain fans were determined not to be needed after a loss of offsite power.
Troubleshooting the cause for the inability to properly operate the RCIC turbine from the remote shutdown panel.
The cause was
determined to be a dust cover over a terminal box pinching certain leads causing a lack of continuity. The dust cover was removed until a modification to the dust cover could be completed.
The solenoid valve on NS-RV-38 was replaced and.the plant was restarted during the evening of July 10.
SRV testing was resumed on the after noon of July ll.
HS-RV-3B was chosen to be lifted first and was successfully lifted from the control room.
However, as on July 6, the valve would not reseat.
Control room operators reduced plant pressure twice in an attempt to reseat the valve.
After two minutes the reactor was scrammed from 14X power, and the valve reseated a few seconds later when plant pressure reached about 880 psi.
The EOPs were entered briefly; an Unusual Event was declared and then terminated about a half hour later.
This time RFW-LCV-lOB operated smoothly and level was restored to normal with out the loss of the running feedwater pump.
At the end of the inspection period the licensee had quarantined HS-RV-10B and developed an extensive root cause analysis plan to determine the cause of failure.
This plan included removal of the valve from the main steam piping and the formation of an experienced team of individuals, many of them from outside of the Supply System, to evaluate the failure and determine the root cause.
No violations or deviations were identified.
ro 'sion for C
ow st b ti r
uta e
5
C osed The inspector reviewed the licensee's practices for maintaining DC power to Technical Specification (TS) required systems during maintenance and testing of DC systems.
The class 1E DC power supply at WNP-2 includes three independent and separate 125 VDC batteries, chargers and buses (Divisions 1, 2, and 3) and one 250 VDC battery, charger, and bus (Division 2).
The 125 VDC buses associated with Divisions 1 and
provide control and motive power for various safety-related load groups, including annunciators, and power to the exciter cabinets for diesel generators (DG), 1 and 2.
The 250 VDC bus (Division 2) provides power to plant controls and to selected Reactor Core Isolation Cooling (RCIC),
Residual Heat Removal (RHR), and Reactor Water Cleanup (RWCU) motor operated valves.
The Division 3, 125 VDC bus provides control and motive power for the High Pressure Core Spray (HPCS)
system and provides field flashing for the HPCS DG.
Generally, it is WNP-2 policy to perform routine maintenance and testing of systems associated with a division (including the DG) only when that division is declared inoperable, and only when that division is not required by TS.
Shutdown cooling (SDC)'an be considered operable for TS purposes even when the associated DG or its battery is inoperable.
TS do not require DG backing for SDC to be operable.
During testing or maintenance that requires the Division 1 or 2 batteries to be isolated, the DC bus remains energized and the loads powered from it are considered operable, being powered through the battery charger.
With the DC bus energized, the field flashing function is available to the DG.
When load testing a Division 1, 2, or 3 battery charger, the DC
e
bus and those systems powered from the bus are considered inoperable, including the DG.
The inspector noted that the FSAR states that Division 1 and 2 battery chargers will not maintain a stable load when supplying the DC bus unless the batteries are connected.
The FSAR is silent concerning the stability of the HPCS battery charger without the batteries.
Conversely, cogniiant technical staff personnel stated that the Division 3 (HPCS) charger will not provide stable loads without being connected to the battery but that the Division 1 and 2 battery charger are stable without the associated batteries.
Cognizant technical staff personnel provided a record of a telephone con-versation with the battery charger vendor that indicated that the charger was able to provide a stable power supply to the DC loads without the batteries.
However, the inspector stated to plant management that they were still obligated to revise the FSAR to ensure its accuracy.
No violations or deviations were identified.
Based on the inspection activity documented above and in NRC Inspection Report No. 50-397/92-15, TI 2515/113 is closed.
6.
0 erational Safet Verif cat'o a.
Plant Tours The following plant areas were toured by the inspectors during the course of the inspection:
Reactor Building Control Room Diesel Generator Building Radwaste Building Service Water Buildings Technical Support Center Turbine Generator Building Yard Area and Perimeter b.
The. following items were observed during the tours:
(1)
0 eratin Lo s and Records.
Records were reviewed against Technical Specification and administrative control procedure requirements.
The inspectors periodically reviewed the night orders, locked valve checklists,'the limiting condition for operation log, and the temporary modification record (TMR) log.
On June 17, during a review of the THR log, an inspector noted a THR that had installed a jumper around the alternate power supply regulating transformer associated with inverter IN-3.
The regulating transformer supplies regulated 240 VAC to certain safety related loads in place of inverter IN-3, if the inverter trips.
The licensee intended to retain this jumper until the next refueling outage, when a replacement transformer can be procured.
This regulating transformer is shown on
(2)
Figure 8-3.2 of the FSAR.
The purpose of this regulating transformer was to ensure that a relatively constant voltage supply was provided to the safety-related loads normally sup-plied by the IN-3, if IN-3 trips.
Installing a. jumper around this transformer would subject the uninterruptible power supply (UPS) loads to the voltage swings that unregulated plant loads occasionally experience.
The licensee stated that the significance of modifying the alternate power supply in any way appeared to be low because an inverter trip and transfer to the alternate supply was a low probability event.
The events described in paragraph 6 below do not appear to confirm this logic.
Because this THR was installed but did not have a safe-ty evaluation conducted to determine if an unreviewed safety question exists per
CFR 50.59, nor was it approved by the Plant Operations Committee (POC)
as required by TS 6.5.1.6.d.,
it appears that the licensee violated NRC requirements.
The licensee apparently reviewed the text of the FSAR, section 8.3.1.1.5, and did not adequately review Figure 8.3-2 of the FSAR wherein the UPS is described.
Figure 8.3-2 is referenced by section 8.3.1.1.5.
Use of the licensee's computer FSAR search program apparently did not identify this equipment as part of the FSAR either.
Subsequently, due to the inspectors'oncerns, the licensee performed a safety evaluation for this THR and did not identify an unreviewed safety question.
This modification was then approved by POC on July 2, and the previous entry in the THR log was updated with the revised version, containing a safety evaluation and POC approval.
Therefore, it appears that the licensee has met the criteria for a noncited violation in accordance with 10 CFR 2, Appendix C, Paragraph.V.G.
(NCV 397/92-23-01, Closed).
onitorin In'strumentat on Process instruments were observed for correlation between 'channels and for conformance with Technical Specification requirements.
~hfdf II i.'C i
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'I d
for conformance with 10 CFR 50.54.(k), Technical Specifica-tions, and administrative procedures.
The attentiveness of the operators was observed in the execution of their duties and the control room was observed to be free of distractions such as non-work related radios and reading materials.
(4)
E ui ment Lineu s
Valves and electrical breakers were veri-
'ied to be in the position or. condition required by Technical Specifications and administrative procedures for the applicable plant mode.
This verification included routine control board indication reviews and conduct of partial system lineups.
Technical Specification limiting conditions for operation were verified by direct observation.
(5)
E ui ment Ta in
.
Selected equipment, for which tagging requests had been initiated, was observed to verify that tags were in place and the equipment was in the condition specifie e m
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(6)
(8)
(10)
(ll)
(12)
General lant E ui ment Cond tions.
Plant equipment was observed for indications of system leakage, improper lubrica-tion, or other conditions that would prevent the system from fulfillingits functional requirements.
Annunciators were observed to ascertain their status and.operability.
~F<<i
.Fl Flgttl g
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observed for conformance with administrative procedures.
~PI l<<gt I
I lg d
d reviewed for conformance with Technical Specifications and administrative control procedures.
ad at'o ote t o o t s.
The inspectors periodically observed radiological protection practices to determine whether the licensee's program was being implemented in conformance with facility policies and procedures and in compliance with regulatory requirements.
The inspectors also observed compliance with Radiation Mork Permits, proper wearing of protective equipment and personnel monitoring devices, and personnel frisking practices.
Radiation monitoring equipment was frequently monitored to verify operability and adherence to calibration frequency.
Plant Housekee in Plant conditions and material/equipment storage were observed to determine the general state of clean-liness and housekeeping.
Housekeeping in the radiologically controlled area was evaluated with respect to controlling the spread of surface and airborne contamination.
At the end of the outage, just prior to plant startup, the inspectors noted that plant housekeeping was well below that normally seen during plant operation.
Various temporary scaffolding structures still existed, much miscellaneous equipment was present that had not been returned to its proper storage, and large areas of the plant that were normally clean areas were still contaminated.
The plant manager acknowledged the inspectors'omments at the exit meeting.
~Securit
.
The inspectors periodicelly observed security prec-tices to ascertain that the licensee's implementation of the security plan was in accordance with site procedures, that the search equipment at the access control points was operational, that the vital area portals were kept locked and alarmed, and that personnel allowed access to the protected area were badged and monitored and the monitoring equipment was functional.
Overtime.
The inspectors reviewed the licensee's overtime records to determine if the licensee was adhering to the TS requirements for hours worked.
The inspector noted that a
large number of individuals in the operations department and the technical staff were given approval to work overtime hours in excess of the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> per seven day period recommended in TS.
Equipment operators routinely exceeded these limits with
the plant manager's approval.
Although the licensee was strictly adhering to the letter of the TS, the inspectors questioned whether the intent was being met.
Specifically, TS 6.2.2.e.4 states that routine deviations from the overtime guidelines are not authorized.
Some. equipment operators were working 80 to 90 hours0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br /> per seven day period.
Although the unit was in an outage for most of the inspection period, and the TS recognize outage periods as being unusual circumstances, the inspector was concerned that the equipment operators were potentially working excessive overtime.
This was of concern given the safety related nature of their activities.
A number of events involving equipment operators had occurred (see Inspection Report No. 92-14, paragraph 4), including a number of events that involved movement of liquids about the plant.
At the exit meeting, licensee management acknowledged the inspectors'omments and agreed that action would be taken 'to rectify the situation.
A number of new equipment operators had recently been hired that may help alleviate the problem,.
although a number of equipment operators will be taken off shift to start a license training class.
n ineered Safet Featu es Walkd w Selected engineered safety features (and systems important to safety)
were walked down by the inspectors to confirm that the systems were aligned in accordance with plant procedures.
During the walkdown of the systems, items such as hangers, supports, electrical power supplies, cabinets, and cables were inspected to determine that they were operable and in a condition to perform their required functions.
Proper lubrication and cooling of major components were also observed for adequacy.
The inspectors also verified that certain system valves were in the required position by both local and remote position indication, as applicable.
'ccessible portions of the following systems were walked down on the indicated dates.
~Sstem Diesel Generator Systems, Divisions I, 2, and 3.
Hydrogen Recombiners Low Pressure Core Spray (LPCS)
Residual Heat Removal (RHR), Trains IIAII and 11 BII Dates June 12,
July 7 June
June
Scram Discharge Volume System Standby Liquid Control (SLC) System Standby Gas Treatment System (SGTS)
July 7 July 7 July 7
I
Standby Service Water System 125V DC Electrical Distribution, Divisions 1 and 2.
July 10 June
250V DC Electrical Distribution One violation was identified, as discussed above.
June
Un'nterru tib e Power Su UPS v
te a lures 93702 On June 28, 1992, IN-3 automatically transferred to its alternate power supply with no adverse consequences.
The transfer to the alternate power supply was characterized as "bumpless" (occurring within I/4 of a cycle)
such that all safety related loads remained energized with no inadvertent engineered safety feature (ESF) actuations.
The licensee postulated that the transfer was the result of the static switch button being bumped by mechanics working in the room.
More significantly, on June 30, a
mechanic, who was working in the overhead above IN-3, bumped into IN-3
"
again, but this time a bumpless transfer to the alternate power supply did not occur resulting in several ESF actuations due to a momentary loss of power.
Reactor building HVAC tripped off, SGT initiated, certain nuclear steam supply shutoff system (NSSSS) isolations were locked in (RWCU-V-4 closed, RRC-V-19 closed, EDR-V-395 closed, and FDR-V-220 and 222,closed)
'and shutdown cooling would have been isolated had it not already been secured for other reasons.
The control room annunciators powered from IN-3 remained functional.
The root cause assessment for the ESF actuations focused on two possible causes.
One postulated scenario offered by the licensee was that the mechanic bumped the inverter with a force so hard that the shock impacted the inverter's inte) nal relay logic, causing an interruption of power for a short period of time.
The second theory was that the mechanic accidentally depressed both the "Forward Transfer'"
and "Reverse Transfer" buttons on the inverter simultaneously.
These buttons control whether or not the safety related UPS loads will be powered from the inverter or the alternate power supply, respectively.
Per the licensee's discussion with the vendor, if this had occurred the reaction of the inverters internal control circuitry would be unpredictable and may well cause a temporary interruption of power, and the ESF actuations described above.
Interviews with the individual involved did not confirm either of these potential ro'ot causes.
The licensee initiated temporary corrective action by placing a plastic protective covering over the face of IN-3, which was removed at the completion of the outage.
No other corrective actions to prevent recurrence were evident at the inverter at the end of the inspection period.
Discussions with cognizant licensee personnel revealed that IN-3 had spuriously tripped four other times in the past, with the attendant transfer to the alternate power supply.
However, the licensee had not determined whether this was unique to IN-3 or was also a
characteristic of IN-2.
The licensee agreed to also research the material history for IN-2.
The inspectors also inquired at the exit meeting whether a permanent cover could be placed over the various pushbuttons on the front of the inverters.
Plant management stated that
f f(
h0
-10-they would evaluate the need for this.
The inspectors will further review this issue when the LER describing the ESF actuations is issued.
No violations or deviations were identified.
8.
Surveilla ce es i
6 Surveillance tests required to be performed by the Technical Specifica-tions (TS) were reviewed on a sampling basis to verify that:
(1)
a technically adequate procedure existed for performance of the surveil-lance tests; (2) the surveillance tests had been performed at the frequency specified in the TS and in accordance with the TS surveillance requirements; and (3) test results satisfied acceptance criteria or were properly dispositioned.
Portions of the following surveillance tests were observed by the inspectors on the dates shown:
Procedure escri tio ates erformed PPM 8.3.125 PPH 6.3.5 RCIC Turbine Uncoupled Overspeed Test Run Full Core Verification PPH 7.4.3.7.6.2 Source Range Monitor "A" Channel Functional Test June
June
June
PPH 10.24.17 Control Rod Oscilloscope dp June
Test PPH 7.4.8. 1.1.2.20 Division 2 Diesel Generator June
Semi-annual Operability Run PPH 7.4.8. 1.1.2.5C Diesel Generator DG2 Loss of Power Test June
PPH -7.4.3.3.2.15 RHR B/C Low Pressure Coolant June
Injection Logic System Functional Test PPH 7.4.8. 1. 1.2.7A Diesel Generator DG2 LOCA June
Test PPH 7.4.3.3.2.36 4.16 KV Emergency Bus Degraded-Logic System Functional Test June
An inconsistency was noted in one procedure.
Step 39 of PPH 7.4.8. 1. 1.2.20 was signed indicating that no abnormal alarms were in, but an alarm was in showing that DEA-FN-23 was not operating.
Abnormal Condition Procedure 4.DGHV.2 was deviated to require a temporary fan to be used if FN-23 was inoperable.
This was not done.
When questioned as to why this was not done, licensee personnel stated that an evaluation
-11-had been completed to show that FN-23 was not needed for DG operability.
However, this had not been reflected in either PPH 7.4.8.1.1.2.20 or PPM 4.DGHV.2.
Cognizant licensee representatives agreed to issue a
deviation to one of the above procedures to show that FN-23 was not needed.
No violations or deviations were identified.
9.
lant Maintenance 62703 During the inspection period, the inspector observed and reviewed documentation associated with maintenance and problem investigation activities to verify compliance with regulatory requirements and with administrative and maintenance procedures, required gA/gC involvement, proper use of clearance tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspector verified that reportability for these activities was correct.
The inspector witnessed portions of the following maintenance activities:
escr t on ates Performed AR-4312, Refurbish Motor Operator for June
RHR-V-64B AR-8749, Inspect HPCS Pump and Replace Motor Air Deflector AR-9264, Repair CMS-CP-1301 (Hydrogen/
Oxygen Monitor for Containment)
AR-9485, Repack SLC-P-1B No violations or deviations were identified.
10.
lant Startu from Refuelin 71711 June
July 7 July 9 The inspector reviewed the licensee's procedures, conducted interviews with selected personnel, and witnessed portions of the licensee's initial startup from refueling.
The inspectors used PPMs 3.1.1 and 3.1.2 (Haster Startup Checklist and Reactor Plant Cold Startup) for guidance.
The inspector performed an independent spot check of 25X of the prerequisites which had been signed off as complete in PPM 3.1.1 in anticipation for plant startup.
No deficiencies were noted.
The inspector reviewed 3. 1.2 to ensure that the procedure had been changed to implement lessons learned from past LER's, NOV's, and gA findings, as well as plant modifications that were implemented during the R7 refueling outage.
No deficiencies were noted.
The inspector also witnessed portions of plant startup up to and including SRV testing at 15K power, which resulted in a manual scram due to a stuck open SRV., Operators appeared to conduct these startup activities in a deliberate and formal manner.
The inspectors will perform additional inspection of plant
-12-startup in future inspections to verify performance of startup conditions from cold shutdown to IOOX power.
No violations or deviations were identified.
t'
to o
ec S
tdo
The inspector reviewed the licensee's methodology for determining shutdown margin and reactivity anomaly in accordance wi.th the applicable technical specifications and vendor guidance.
In addition, the inspector performed independent calculations, using the licensee's procedures, to ascertain their usability and technical adequacy.
PPH 7.4.1.1, SDH and PPH 7.4.1.2, Reactivity Anomaly, as well as the Siemens Nuclear Power (SNP) Corporation's
"Startup and Operations Letter Report" (SOLR), were used.
The inspector found that the licensee's procedures were in agreement with the guidance provided by General Electric (GE) in the GE "Station Nuclear Engineering Manual" (NEDO-24810A).
The licensee's procedures appeared to be more user-friendly than during previous cycles because guidance was added to the procedure to interpolate reactivity values of rod worth for temperatures different than those provided in the SOLR.
The inspector's independent calculations agreed with the licensee's results, and all values were well within Technical Specification limits.
The inspector observed that the SOLR was referenced for a number of reactivity values in PPM 7.4.1.1, but had not been POC approved for use in a TS surveillance procedure, nor was it marked as "Safety-Related" or as a "controlled copy".
However, preliminary or out of date copies of the SOLR were not being used.
The licensee stated that they would evaluate the need for additional management controls for use of the SOLR in safety related procedures.
No violations or deviations were identified.
valuatio of Licensee Self-Assessment Ca abilit 40500 The inspector attended meetings of onsite and offsite review committees, such as the Corporate Nuclear Safety Review Board (CNSRB), Hanagement Review Committee (MRC), Plant Operations Committee (POC),
and Incident Review Boards (IRBs); reviewed monthly reports from the Nuclear Safety Engineering (NSE)
and Operational Experience Assessment (OEA) groups; reviewed meeting minutes from CNSRB, and conducted interviews with personnel affiliated with these oversight groups.
The licensee appeared to have satisfactory oversight capability and to be in compliance with technical specifications.
Although not required by TS, the HRC functions in an advisory capacity to the Plant Manager and provides the first management review of Problem Evaluation Requests (PERs).
The HRC consists of the Plant Hanager or his assistant and the gA Manager plus other managers, such as the Operations Manager, Maintenance Manager, and the Plant Technical Manager.
The HRC decides whether a problem is reportable or potential'ly reportable, the resolution method (nonconformance report, maintenance work request, etc),
-13-and whether the PER is required to be reviewed by POC.
The threshold for writing a PER is low which allows management to see all problems.
However, this increases the number of PERs written and the amount of time management must spend to review them.
POC functions in an advisory capacity to the plant manager on all safety matters, such as responses to notices of violations (NOVs), procedure changes, TS amendments,
'LERs, etc.
POC is required by TS to meet at least once a month; however, during this inspection the licensee was undergoing a refueling outage, and POC met nearly every day.
This allowed POC to remain closely involved with the issues and to reach resolution in a timely manner so as not to impact the outage/start-up schedule.
Generally, the meetings were run smoothly and POC members contributed to the discussion; however, at times there appeared to be a
tendency to embrace the first plausible resolution with little or no discussion of alternatives.
When it seemed that there was not enough data to make a decision or there were differing opinions, the chairman halted the discussion and called for the issue to be tabled until further information was obtained.
Recently, the licensee established an IRB concept to provide timely investigation of plant'vents that involve apparent personnel error'r require immediate review to preserve or gather evidence.
The IRB determines what actually occurred and recommends immediate corrective actions, but does not provide an in-depth root cause analysis.
IRB reports do not preclude the necessity for preparing more formal reports, such as NCRs and LERs.
Although still in its infancy, several IRBs have
'been convened.
The inspector observed the IRBs in progress, attended IRB briefings to POC, and reviewed IRB written reports.
The IRBs responded very quickly to the incidents, gave informal updates to plant management and POC, and provided written reports within a few days of the incident.
~
The reports appeared to be objective and self critical.
The independent safety engineering group function at WNP-2 is provided by the Nuclear Safety Assurance Group (NSAG).
NSAG responsibilities include review of internal and external technical information which may affect safe operation of the plant, root cause analysis of events, recommenda-tions on corrective actions, oversite of issue resolution, and assessment of overall safety of operations.
TS has stringent educational and expe-rience requirements that are exceeded by NSAG personnel.
Four of the NSAG staff hold masters degrees, ten hold or have held reactor operator (RO) or senior reactor operator (SRO) licenses, nine hold SRO certifica-tions, and three are licensed professional. engineers.
NSAG has made its presence known in POC meetings, by pressing questions that broaden the discussion.
At times, NSAG, in performing root cause analysis has identified generic problems which affect other systems.
For example, in reviewing the PER identifying DG fans that would not auto start as required, NSAG investigated all HVAC equipment required to auto start on a loss of offsite power, identifying other fans (in the DG areas and cable spreading room) that would not autostart.
The inspector attended a
CNSRB meeting held on site and reviewed meeting minutes from a previous meeting.
The CNSRB is required by TS to meet every six months.
The CNSRB includes members from other utility groups
t If
-14-as well as WNP-2 personnel.
This group appeared particularly well prepared and was aggressive in posing questions to plant management.
The discussion among the members demonstrated knowledge and experience in the nuclear industry.
No violations or deviations were identified.
13.
icensee Event Re ort L
R ollowu 90712 92700 The following LERs associated with operating events were reviewed by the
'nspector.
Based on the information provided in the report it was concluded that reporting requirements had been met, root causes had been identified, and corrective actions were appropriate.
The below LERs are considered closed.
L R NUMBER 91-03-01 92-13 92-14, 92-14-01 92-16 SCRIP IO Inadequate Technical Specification Testing of Standby Gas Treatment Residual Heat Removal Pressure Switch Found Isolated During Startup High Pressure Core Spray, Low Pressure Core Spray, and RHR Flow Setpoint Error RCIC System Not Adequately Transferable to the Remote Shutdown Panel 92-21 92-22 92-23 Inadequate Electrical Separation of Certain Post-Accident Radiation Monitoring Instrumentation Circuitry Replacement CAC Blowers Installed With Unqualified Seals Missed Technical Specification Surveillance and Fire Tour Data Due to Less Than Adequate Work Practices 92-24 92-25 Inadvertent Emergency Ventilation Actuation Inoperability of the High Pressure Core Spray System Due to Partial Failure of the Upper Air Deflector in the Pump Motor In addition the inspector reviewed the following LER and concluded that additional followup was warranted:
0 en 92-13-01 Residua Heat Removal essure Switch ound Isolated Durin Startu On March 18, 1992, with main steam pressure at 913 psig, an annunciator was found lit by a control room operator indicating that
~
(,
-15-the RHR "C" injection, valve open permissive was still actuated.
This annunciator should have extinguished by the time r'eactor pressure exceeded 470 psig.
This would have allowed the RHR "C" injection valve to open with reactor pressure greater than the.
design pressure of the RHR system.
Pressure switch HS-PS-413D was found isol'ated.
The event was deemed by the licensee to have had no safety significance.
The'inspector disagreed and noted that 'the only redundant protection for the RHR system from an intersystem LOCA was a downstream check valve.
The root cause of the event could not be determined by the licensee.
However, the licensee committed to taking actions to identify possible causes and further corrective actions.
This LER will remain open until the actions committed to in the LER have been completed.
No violations or deviations were identified.
14.
eet n
to Discuss Fi anci atte s
On June ll, 1992, members of Supply System and BPA management met with NRC Region V management representatives in the Region V office.
The following persons were in attendance:
A. L. Oxsen, Deputy Managing Director G. J. Kucera, Controller F. Bartel, Industrial Engineer, BPA D.
E. Grover, Financial Analyst, BPA During the meeting, licensee representatives outlined the Supply System's strategic goals, plans regarding future capital improvements to the
'lant, and Supply System ownership and organization arrangements.
A copy of the materials provided during the meeting is enclosed with this inspection report.
15.
Ei N
The inspectors met with licensee management representatives periodically during the report period to discuss inspection status, and an exit meeting was conducted with the indicated personnel (refer to paragraph 'I)
on July 16, 1992.
The scope of the inspection and the inspectors'indings, as noted in this report, were discussed with and acknowledged by the licensee representatives.
The license identified the SOLR and the SNE manual, reviewed by the inspector to support the inspection activity in paragraph 10, as proprietary informatio PPLY Y TE FI A IALI F R I
JUNE 11, 1992
ORGANIZATION NET-BILLINGAGREEMENT FLOW OF FUNDS FINANCIALSTABILITY STRATEGIC GOAL COST HISTORY ck PLAN
'OMPARATIVEDATA
PPLY Y TE R A ZATI
~
ORGANIZED,IN19$ 7.
I
~
CURRENTLYTHERE ARE 13 MEMBERS OF THE BOARD OF DIRECTORS.
~
1981 AND1982 "ACT"AMENDEDTO CREATE NEWEXECUTIVEBOARD WITHSIX OUTSIDE DIRECTORS.
~
EACH PROJECT IS FINANCEDANDACCOUNTED FOR AS A SEPARATE UTILITYS YSTE ~
~;
.
P-2 ETBILI A R E T E
~
PROJECT PARTICIPANTS (104) HAVE CONTRACTED TO PURCHASE THE PROJECT CAPABILITYAND TO PROVIDE THE SUPPLY SYSTEM WITHNECESSARY FUNDS TO MEET COSTS.
~
SIMULTANEOUSAGREEMENTS WERE EXECUTEDASSIGNINGPROJECT CAPABILITYFROM PARTICIPANTS TOBONNEVILLEANDCREATEDANOBLIGATIONOF BONNEVILLETOPAY THE PARTICIPANTS FOR THEIR RESPECTIVE SHARE OF PROJECT COSTS.
~
BONNEVILLEIS ULTIMATELYOBLIGATEDTO MEET PROJECT COST.
~
PAYMENTS ARE MADE TO SUPPLY SYSTEM BY PARTICIPANTS, AND PARTICIPANTS'OWER BILLSARE CREDITED BYSUCH AMOUNTS.
~
BONNEVILLEIS OBLIGATEDTO PAYDEFICIENCYAMOUNTS.
~
NET BILLINGIS A BONNEVILLE"PRIORITYPAYMENT."
~
'
I A IAL ABIL TY
~
REVENUE BONDS OUTSTANDING $'2.$ BILLION (COMBINATION OF REFUNDED AND NONDEFEASED ORIGINALBONDS).
~
SINCE 1989 HAVEISSUED $'1.5 BILLIONREFUNDING BONDS.
~
. BONDS ARE RATED "AA"BY THREE MAJOR RATINGAGENCIES.
~
AS OFMAY3,1992, WNP-2 HOLDS$32$ MILLIONINCASHANDGOVERNMENTSECURITIES.
~
RESERVE AND CONTINGENCYFUND OF $3-22 MILLION NEVER USED INHISTORY OF PROJECT.
S WNP-2 FY-92 BUDGET IS $455 MILLIONINCLUDINGDEBT SERVICE.
~
EVERY SUBMITTED OPERATING AND AMENDED OPERATING BUDGET HAS BEEN APPROVED.
~
SUPPLY SYSTEM PARTICIPATES INBPA REGIONAL RATE PROCESSES.
~
FERC REVIEWS BONNEVILLERATES FOR ADEQUACYTO MEET COST BONNEVILLEPOWER ADMINISTRATION Fiscal Year 1990 FIow of Funds(1)
Hot Avalable for Net Bitang (2)
$199A Potentially Available for.
Net BISlng If Net Badng Par6dpant Shares were Reasslgned as Provided by Net Billing Agreements(3)
$37.0 Avallabte for Hat Biidng
$852A Revenues Oue Bonnev'4e From Partkfpenta tn Supply System and EWEB Net Billed ProJects for Power and other Purchases Pro(act
Exchange Agreementa(4)
Other Funds Received by BonnevNe(5)
$1.15S.9 Total Annual COSls of Net Billed ProJects(8)
Credits through Net Bllang(7)
$8S2 4 Pro(ect 1 Exchange Agreementa 88.1 ln-Neu Paymenta(d)
224 Total Annual Costa of Hat Bleed Pro(acts
$ 7d1.0 THE BONNEVILLEFUND Paymenla Other Than Those To The United States Treasury(9)
~ porthn of Annual Costa of Net Bated proJects (Including Oebt Service) paid by Bonnevle rdrecdy ln deu ol Net Sling Credits or paymenta to Pardclpants(8).
~
~
~
~ ~ ~ ~ ~ ~ ~ ~ ~
$ 22 5 BonnevNe Operations and Maintenance Expenses
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ r ~ ~ ~ ~ ~ ~ ~ ~ ~
281 7
~ Net Costs ol the Reildentlal Exchange.
159.8
~ Other.
~
~
~ ~ ~ ~ ~
~
27.8 Psyme'nts to the United States Treasury From Net Proceeds
~ Corps and Bureau Operadon & Maintenance Expenses.................
$ 105.0
~ Bond Principal Amortlzatton & Interest (Het) Paymenls........................
280.3
~ Appropriauon Amortlaetton & Interest Payments..............
233A
Figures ln this table are from audited flnancfal statements andi or accounting records for Bonneville's fiscal year ended September 30, 1990.
For other years, see "THE BONNEVILLE POWER ADMINISTRA-TION-Bonneville Financial Operations Hfstorfcal Federal System Flnanclal Oata" herein.
Amount by which certain Net BllllngPartfcfpants'ower purchases exceed (a) their respective shares of Net Billed proJects'nnual costs, and (b) the amount by whfch their shares of such annual costs could be Increased as a result of mandatory reasslgnmsnts under the Net Bllllng Agreements.
(3)
. Approximate amount by whfch certaIn Net BIOlng Particfpants'hares of net billed proJects'nnual costs could be Increased by mandatory reasalgnments:
I.e., If Bonneville had reallocated proJect shares as provided In the Net Bllllng Agreemsnts In fiscal year f990, Net Bllllng credits would have been larger by approximately $37 mllllon.
ProJect 1 Exchange agreement revenues are paid dfrectfy to the Supply System by the ProJect
Companies.
They are treated In the Supply System's Annual Budget as amounts payable from sources other than the ProJect 5 Net BllllngAgreements and thereby reduce the amount payable through net bllllng.
(~)
(8)
(7)
(8).
(9)
These Include revenues received by Bonneville from other customers ($ $.105.9 mlmon) and proceeds ot Issuing and selling bonds to the United States Treasury ($50 mllllon).
The costs shown are those of both the Supply System and Eugene Water and Electric Board ("EWEB")
net billed proJects.
These annual co'sts are net ot Investment Income and other miscellaneous receipts by the Supply System and EWEB..
The amounts credited by Bonneville are paid by the Net Blfllng Participants to the Supply System ($58).t mllllon) or EWEB ($71.3 mllllon), as appropriate to pay the costs of the respective Net Billed proJect for whfch such credits were provided.
The portion ot the annual costa pafd directly to the Supply System. and EWEB by Bonneville consists ot
$l8.0 million ln payments to the Supply System and $8.5 million to EWEB.
The listing of payments wfthln this section (Payments Other Than Those to The United States Treasury)
does not imply a priority among such payment STRATEGIC GOAL COST OF POWER (21.78)*
M ILLS/KV/H 33.4
25
21.78 26.9 25.2 24.8 21.8 21.8 21.8
10 FISCAL YEAR CAPACITY FACTOR GOAL 66.0 89A 62.9 90A 87.7 91A 69.1 92AB 48.7 93P 70.0 94P
? 0.7 96P 71.6 96P 71.8 97P 71.6 FULL POWER DAYS SPRING DOWN TIME~~
FORGED/LOSS DAYS OKM - 1989 $
OKM " NOMINAL$
GENERATION MAX DEP CAPACITY-NE 238
49 102 230
69 118 6263 6034 1096 1096 247
47 126 216
91 128 6496 6870 1096 1096 171
126 127 146 4460 1086 266
~ 80
126 161 6830 1116 268
47 124 168 8911
.
1116 281
44 122 163 7300 1184 281
44 122 171 7300 1184 281 80'4 122 180 7300 1164
~ INGREMENTAL PRoJEcTED CONTROLLABLE/INCREMENTAL
~ ~ INCLUDES PLANNED OUTAGE/ECON DISPATCH REVISED 3/2/92
WNP-2 CAPITAL INVESTMENT 80.0 IN MILLIONS 6 ES N----
40.0 20.0 0.0
87
89
91
93
96
97
99
ESCALATION MIP SPARES REQ PGMS GENERAL PLANT 1.6 7.9 1.3 19.3 1.2 3.3 9.9 2.6 1.7 11.3 1.0 1.4 3.1 27.8 0.8 O.B 2.2 B.B 26.2 9.8 3.8 6.4 8.4 34.7 18.8 2.0 4.7 9.6 30.8 2.0 17.8 2.0
?.1 10.2 23.9 4.0 B.O 2.0 8.2 7.0 2?.4 8.1 0.7 2.0 4.0 9.8 2B.3 8.6 2.0 4.0 7.3 30.2 10.9 11.8 2.0 3.0 10.9 8.0 30.9 26.9 20.1 6.8 49.3 18.9 19.8 9.7 9.9 29.9 30.1 FISCAL YEAR PLANT EH SPARES KB GENERAL EZ MIP K~3 REQ PGMS m ESCALATION
WNP-2 OEM COST 160.0 140.0 120.0 100.0 80.0 IN MILLIONS 60.0 40.0 20.0 0.0 ACTUAL COST AMENDED BUDGET ORIGINAL BUDGET 1986 94.6 91.5 91.8 1987 97.4 97.7 96.0 1988 103.0 100.8 9?.6 1989 118.1 112.9 108.6 1990 132.4 128.0 122.8 1991 139.1 139.3 134.2 1992 14B.O 14B.O 146.9 FISCAL YEAR
~ORIGINAL BUDGET KQ AMENDED BUDGET EQACTUAL COST
WN~CAP
~BaseHne'MR Management PMRs Industrhl Capital Movoablo Capital AKGAlbcation Support Services Admlnlstratbn PMR Tmnsfor from 82 Basomne Sub-Total 1+46 7,362
'l,500 2,000 964 I,ols 600 I@48 7,362 1,627 1,7I4 9S4 1,018
13,973 14,932 1+48 7,362 1,500 2,000 964 1,OIS
14,132 1+48 7,362 1,500 2,000 964 1,018
14,132 I+48 7,362 1,500 2,000 964 1,018
14,132 fY97 1,24S 7,362 1,500 2,000 984 1,018
14,132 Y
Unescahted 000's FY98 1+48 7e362 1,500 2,000 984 1,018
14,132 1+48 7,382 1,500 2,000 964 1,018
14,132 1448 7,382 1,500 2,000 984 1,018
14,132
~FYO 1+48 7,382 1,500 2,000 984 1,018
14,132
,
~It-OeHI1 01:03 PM biota 12,480 73,820 15,127 19,714 9,64O 10,160 600 141,961 Changes lo Baseline Revhed BLTotal LG~ QR ~iL1W~HR DRD Phnt ComponenVEq Db DB Roconstitution Safety Chssificatbn Spent Fuel Casks On-Site Spnt Fuel Store PMR Proj Capital Growth Maint Training FaciTity NonGon Fac-Corp Bldgs RCM Moveable Equipmonl Circ Water MoeHtyhce Secunty Conlpltef Rophce Turbhe 8otor Rephcement Upgrade Radwaste Pioc Sys Retube Cond vtfTItanfum Rophce CTL Rod Bhde AAC Pump Shaft Rophce Radwaste Fac (Phase 162)
Upgrade MU Water Trtmnt TSW Pipes Cbg vsfCorr CAD Accumuhtors Pipe Repair-Tiger Stripe Arm Rad Monitor Upgrade Install Perm Ldrs/Pltfrms Instam A Dsl Gen MntrSys Erect PhtSMod Sao Sld Dr RAC Adjust Speed Drives Instai WdRng NouMonSysGE Install Coro Sstbil Montr Status Aprvd
Apvd
Apvd
Apvd
40 Apvd
Aprvd
Aprvd
Aprvd
50 Apvd 50.
Aprvd
Apvd
Apvd
Aprvd
Apvd
50 Aprvd
Aprvd
Apvd So
50
50
50
50
~BS QoJ 280010
2R0030
282310
2R232C
2W0000
924010
92130A
92211T
'92 922IIX
92311R
92401M
9240IS
924020
92409A
92409B
92409D
92409F
92411X
9241 3X
92414X
924158
92415 D
924I5E
9241 5F
9241 5H
92415 J
92415K
92415P
9241 5S
2,601
1,766 1,000
0
0 292
331
. 'I8,522
0
0 376
0
0
0
0
0
2,524
1,576 1,000
0 450
0
0
358
0 4 I2
0
0 234 321
75
1,350 4+92
618 2,524 2,000 1,576 1,000
0 2,624
0
0
0
0 463
,0
123 234 43S
350 610 1,600
0 1,406 2,444 2,000
~ 290 1,500
105 2,615
0
0
0
.200
515
950 15S 903 234 536
350 330 0.
5S 779
2,000
2,000
263 2,916
0
0
0 420
206
1,296 420 903 234 436
350
0 650
0
2,000
2,000
2,146
75
0
1,350
452
0
6,600 368 649 234 216
350
0
600
0 2,000
0
'I,859 1,358 175
0
210
0
0
6,0000'
234
0
0
0 2,700
0 3,000
0 2,929 965 1,603 125
0
0
0 500
800 2,500
0 234
0
0
0 1,300
0
0
2,929
0 1,700
0
0
0 25,963
610
0
234
0
0
0
0
0
0 2,929
1,762 1,600
0
0
0
0 6 I0
,0
0 234
0
0
0
0 10,093 13,000 5,232 8,500 8,767 5,338 13,548 3,875 292
331 1,610 18,878 1,066 26,463 1,596 2,140 I7,922 966 2,578 2,106 1,947
1,475 990 2,950 4,942 4,658 2,603-10-
l1
H
~
Long Ufe Pwr. Rg Monitor Rept. Stuoud Head..Bolts Telesc. Refuel Mast Inst.
Install Elect Mtr Dnm FP Feedwnter Control System Mah Steam RADMonitor Organh Reduction Syst.
MOVATSTesting Equip TMUASD MSR Tube Bunde Rephce InstaN AIDSys-Main Oen Rephce FW Heaters 6ArB Mod CR Back Panel Flr Sys InstaN ATtab Dhg Sys RPS/lso Logh Sys Rephce Power Supply Rephcement Prime Cable Marking OSB RenovaNon WNP2 Rephce Slmutator Work Control Center
50'0 Aptvd
50
50
50 50-
Apwd
50
50
50
Aprvd
60 92415U 92415V 9241 5W 82415X 9241ST 92415Z 9241 6A 92416 D 92416E 9241 8X 92419X 92420X 92421 X'24 23X 92425X 92426X 9242?X 92211S 924030 924070
~ 92
92
82
92
92
92
92
82
92
92
0
0
0
0
0
118
0
0
0 5,526
280
0
75
0 500
50
0
0
14
0
180 160
0 575
0
250 1,500
0
0
0
0 200
"
0
?5 1'19
0
0 162
"75 3,000
14
75
50
0
0 180
0
0
0
0
600 100
1~5
0 1,000 125
0 180 160 160 180
0
0 O
O
O
0
0
0 0 '
0
0
0
0
0 0,
0
=
0
0
2,500 126
0
?04 1,758
0 113 1,000
0 134
0
0
0
117 3 I8 334 334
0
0 750 250
0
0,
0
250
"'75 250 160
0
0
0
0 7,476
0
0
334
0
0
.
1,720
575
1,825
0 500
10,226 1,040 2,600 1,120 1,605 3,174 1,45'I 1,134 1.175 5,526 1,175
0
0
0
0
0
0
0
0
0 Ptogram Totah Sub-Total (Baseline t Programs)
Long4tange Forecast'
(Exdudes MWIP, Indudes ISF Bldg Mods)
, Variance (BLtNP) O.RF)
30 555 14 316 44,528 29+48 44 528 28 S96 16 397 19 030 15 743 19 611 18 312 15 345 34 700 15 345 IS9 354 341,315 39 857 272 29 875 29 677 29,677 29,477 29 477 2S,477 341 315
-11-30,529 33,162 29,675 33,743 32,444 29,477 4$,632 29,477
~CAP Qfg~ELO 6~~63r PINING QNPPg OBM
>>>>>>>
Controlhble Maht Effictoncy Integrathn Benofit Spare Parts LOE-Tmnslthn Eng Etfidoncy PMR Tmnster to 92 Baseline Sub-Total 135+01 135,301
0
0
0 (34)
(ISO)
13S,301 134,317 135,301
(1,800)
(300)
133+01
~Y U>>>>>l>>>d OM'>
~95
@98
~YS 135,30 I (1,000)
(2,700)
(600)
131,001 135,301 (1,500)
(6,000)
(750)
127,051 135,301 (2,000)
(6,700)
(850)
125,751 FYSS 135,301 (2,000)
(6,7oo)
(850)
125,751 135,301 (2,000)
(6,700)
(850)
125,751 135,301 (2,000)
(8,700)
(850)
125,751 135,301 (2,000)
(6,700)
(850)
125,751 17-Dao@
01:03 PM
~otal 1,353,010 (12,500)
(44,034)
(6,050)
800 1+89,626.
Changes to Baseline Rovhed BLTohl Programs SSFI/SSOMI Implement Corr Act B/L Reduction WNP-2 Docket Ffio DB Tech Spec Improve Pcog State (EFSEC) Foes Rog Commit Tmcldng Sys Outage Reserve Unknown Ptograms 10 Year Hydro Tost Eng Backlog Reduction Pcotosshnal Dov. Rohte IPE tnt/Ext Events Roaclor Press Vessel Test Code Sec XI,App VillImp EPRI NDE Center Support Automated NDE Support Operations PcocoduresO/S Operator Tmlnlng-0/8 Procedure Vority/Vafidato Technkat/Enginoonng Tng HP Chem Training-0/S Maht Tcairdng-O/S Rotiab Cntrd Malnt Pcog Maint Pcoc Upgrade Pcog Concfiuon/Poctorm Monitor PhnHVido Painting Pcimary Sys Chem Decon HCU Overhaul Motor Oporator Refutb MOV Program Dlr WBS No
261910
22241 A
22261 B
22261 D
22262B
SBOIOO
269999
269999
'0 26167H
2621 2A
262140
262230
26233B
26233 H
26233I
26719l
26111B
26112X
26161 A
264 62X
26474 X
2671 3X
267151
267153
267160
267180 So 2671 9A
26719 B
26719C
26719D
82
82
82
82
82
82
82
82
82
82
82
82
82
82
82 189 485 281 693
0
0
500 186 676 1,100
0
SS7 300 200 176 360 360 1,508 682 308 779
0
0 2IO 437
640
0 1,950
0 750 186 769
40
250 431
200
0 420 200 1,034 350 1+50
0 550 350 2IO 443
300
0 1,900
100 750 186 819
40
250 431
40
0
200 1,034 350 1,750
0 550 350 210
"200
0
0 1,900
0 750 186
'19
260
250
0
0
0 200 1,034 350 1,750 750
550 3SO-12-2IO 200 2,000
0 2,000 188 417
260
mo
0
0
0
259
2,000
0 210 200
0
0 2,000 5,761
2,000 186 317
260
250
0
0
0
0
2,000
0
0
0
0
0 2,000 5,728
2,000 186 312
260
250
0
0
0
0
1,500 750
0
0
0
0
2,000 S,OBB
0 186
0 280
250
0
0
0
0
'1,000
0
0
0
0
0 2,000 9,388
0 186
0 260
250
0
0
0
0
500
0
0
0
0 2,000 8,438
0 186
0 260
250
0
0
0
500 750
0
18,000 1,239 1,965 281 1,633
0 17,750 3S,401 100 S,750 1,860 4.129 1,100 1,900 675 2.250 1,499 300 440 176 360 780 2>1 08 4,043 1,358 13,029 2,270
2.200 1,400
Pos Ind Ptobe Pen Rpl GE ECCS Motors Igyr Overhl HP Ahra Operatfng Crew 7 Major Maintenance Growth Refuel Floor Servfces New Slmuhtor OQA
26719 E
~
50 26719 F
~ 82
26719 J
~
26719K
50 26831 X
50 924150
60 2611 3X
0
0
169
761
0
0 550
1,590
500
0
0"
0 1+09 1+00
0 1+75 I+40 3,500
0
0
0
0
0
0
0
3,027 3,350 3,550 4,150
0
0 1+40 1@40 1,240 1,240
.
4,000
0
24,905
12.406
0
0
0 0 '
0
0
0
0
0
0
0
0
0
0
0
Program Totals Sub-Total (Basetfne+ Programs)
I.ong-Range Forecast Varhnce (BLtNP) (LRF)
10 300 145,601 145 601 12 252 12 362 12 599 18 549 17 849 17 849 17 849 17 849 17 849 153 307 144,569 143,563 141,600 141,600 141,600 141,600 141,600 141,600 141,600 1,424,933 144,569 143 563 141 600 141 600 141,600 14'I 600 141 600 141 600 141 600 I 424 933
~Q
+
9-13-
>1
~ i'
EUCG 08 M COSTS SINGLE UNIT PLANTS*
'1 20.0%
happ p 86.5%
93.7%
100.8%
97.8%
80.0%
60.0%
40 0%
20.0%
.p.p 1988
1989
4 OF PLANTS
PLANTS (COMPARABLE SIZE) AS A PERCENT OF INDUSTRY AVERAGE-14-1990
'1991
T46
0