IR 05000344/1988010
| ML20151M416 | |
| Person / Time | |
|---|---|
| Site: | Trojan File:Portland General Electric icon.png |
| Issue date: | 04/07/1988 |
| From: | Mendoca M, Pereira D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML20151M412 | List: |
| References | |
| 50-344-88-10, IEIN-87-028, IEIN-87-034, IEIN-87-059, IEIN-87-065, IEIN-87-066, IEIN-87-28, IEIN-87-34, IEIN-87-59, IEIN-87-65, IEIN-87-66, NUDOCS 8804250048 | |
| Download: ML20151M416 (10) | |
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U. S. NUCLEAR REGULATORY. COMMISSION
REGION V
Report No:
50-344/88-10 Docket No.
50-344 License No. NPF-1 Licensee:
Portland General Electric Company 121 S. W. Salmon Street Portland, Oregon -97204 Facility Name:
Trojan Nuclear Plant Inspection at:
Rainier, Oregon Inspection cond cted:
Ma/ch14-
, 1988 Ir.spector:
dur'
- 4//m D' B. Pereira, Reactor Inspector Date Signed
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Approvt.d by:
%'N' % dN'-
V/7/f8 M. M. Mendonca, Chief,-
Date. Signed Reactor Project Section 1 Summary:
Inspection During the Period of March 14-18, 1988 (Report 50-344/88-10)
Areas Inspected:
This routine, unannounced inspection by the Project Inspector involved the Annual Review of the Licensee's Program to handle Information Notices, review of Procedures, and onsite followup of written reports of non-routine events.
During this inspection, inspection modules 30703, 92701, 92700, and 42700 were used.
Results: No violations or deviations were identified.
8804250048 880407 PDR ADOCK 05000344 Q
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DETAILS 1.
Persons Contacted a.
Licensee Personnel
- C A. Olmstea'd, Plant Manager
- D. W. Swan, Manager, Technical Services J. D. Reid, Manager, Plant Services
- D. Nordstrom, Engineer, Nuclear Safety and Regulation Department R. A. Reinart, Supervisor, Instrument and Control A. M. Puzey, Office Supervisor R. C. Rupe, Manager, Performance Monitoring and. Event Analysis Group R. L. Russell, Operations Supervisor
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b.
U. S. Nuclear Regulatory Commission
- R. Barr c.
Oregon Department of Energy H. Moomey, Oregon Resident Inspector
- Attended the Exit Heeting on March 18, 1988.
2.
Annual Review of Licensee's Program to handle Information Notices The purpose of this inspection was to ensure the followup performance of IE information notices and IE bulletins sent to the licensee for information.
The inspector reviewed five information notices sent to the licensee and verified the performance of the following actions:
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1.
Each Information Notice (IN) was reviewed for applicability.
2.
Proper IN distribution was given to the appropriate personnel at the corporate and site levels.
3.
In general, the licensee scheduled or performed the appropriate corrective actions deemed necessary in the IN.
Since neither a bulletin issued for information nor an IE information notice requires a response from the licensee, the inspector verified that an adequate review was conducted to determine applicability to the facility.
When the licensee determined that the information is applicable to the facility, then the licensee assigns an Operational Assessment Review (0AR) to review what actions should be taken or
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planned.
The OAR is assigned a number and js followed in the licensee's Commitment Tracking Log (CTL) with the responsible individual or_
organization assigned action.
These actions may be corrective or preventive in nature and include such actions as informing the plant
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operating staff, training, procedure revision, design review, safety evaluation, or change to the facility.
The inspector reviewed the. licensee actions for the following information notices 87-28, Supplement 1, 87-34, 87-59, 87-65, and 87-66 and determined that the licensee was performing appropriate actions as-detailed in the notices.
Information notice 87-34 was determined to be closed and will be discussed later in this report.
The inspector determined that che licensee's actions were acceptable.
No violations or deviations were identified in this area.
3.
Plant Procedures Program The purpose of this inspection was to determine whether overall plant procecures, temporary procedures and procedure changes were in accordance with regulatory requirements, Technical Specifications, and licensee commitments.
The technical adequacy of the reviewed procedures were to be verified with the desired actions and modes of operation.
The inspector reviewed General Plant Operating Procedures, Startup, Operation, and Shutdown of Safety-Related System Procedures, Abnormal Condition Procedures, Maintenance Procedures, and Administrative Procedures to ensure that the review and approval process was in accordance with the Technical Specifications.
The inspector's review determined that procedurts have been developed for safety related systems, functions, and activities and have been approved by the General Manager.
The overall procedure content appeared to be consistent with the technical specification requirements, and the technical content of several procedures were checked to verify that they acceptably controlled safety-related operations.
The inspector interviewed system engineers and reviewed procedures in the revision process to determine whether procedure changes were in conformance with 10 Code of Federal Regulations (CFR) 50.59 rem irements, which involves unreviewed safety questions or a change in the ts-hnical specifications incorporated in the license.
Administrative Order (AO)-4-4 provides the mechanism by which the Plant Operating Manual (POM)
procedures are initiated, deviated, revised, deleted, and corrected.
System engineers are the r.ormal initiators of system changes or revisions
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to the procedures.
During t;.* interview process, the inspector determined that the system eng1.'eers appear to be the most qualified to make system procedure changes or i9 visions.
l Nuclear Department Procedure (NDP) 100 9, entitled "Preparation of Safety Evaluations" provided guidance for the safety evaluations necessary to ensure that unreviewed safety questions or changes to the technical
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specifications are performed prior to the issuance of a procedure
revision or prior to necessary NRC approval.
This procedure required technical review by a Qualified Technical Reviewer with appropriate experience and expertise to make an evaluation of the change.
In order
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to retain independence of this review, the people who initiated the
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change are not allowed to perform the technical review.
The technical review may be performed by more than one individual in order to ensure l
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review by personnel with experience and expertise in the area.
After plant procedures have the technical review completed, then the approval process begins.
The inspector verified that procedures were in effect for assuring that safety-related systems / components which could be exposed to a freezing environment remain functional after such exposure.
Periodic Operating
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Test (P0T)-24-2 entitled "Daily Operating Routines" provides tables for l
tha operating personnel to check safety-related systems / components for operability after freezing weather.
The inspector reviewed procedures in the Control Room, the Technical Support Center (TSC), and in the Instrument and Control shop to verify l
that they were current with respect to the Effective Revision Master List.
No discrepancies were noted in this review.
All areas reviewed indicated correct revisions in place.
The review indicated that procedures are checked or audited each month.
The inspector's only comment to the plant procedures program was the length of time the licensee gives for revising procedures in the Licensee Event Report (LER) corrective action area.
This inspector noted excessive time periods in some LERs, e.g., greater than two months for
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performing revisions to procedures.
It would be appropriate to give the
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reason for the time naeded to revise the procedure, if excessive.
The inspector determined that the licensee has a plant procedures program which provides procedures that are in accordance with regulatory requirements, provides procedure changes that are in~accordance with technical specification requirements, and has procedures which have the technical content to perform the desired actions and modes of oparation.
No violations or deviations were icientified.
4.
Followup on Previous Inspection Findings a.
IE Information Notice No. 87-34 (Closed) Single Failures in Auxiliary Feedwater Systems Information Notice No. 87-34 was provided to alert licensees of a l
potential single failure of auxiliary feedwater pump start and i
protective pump trip circuitry that could cause partial or complete loss of capability to supply auxiliary feedwater (AFW) in conflict-i with the design basis.
A description of the circumstances of the safety problem was reported by the Indian Point Unit 2 on April 30, 1987 which identified a potential single failure in a portion of the pump start circuitry that is common to both motor-driven auxiliary feedwater pumps and that could prevent both pumps from starting automatically in the event of cither low-low steam generator level or loss of main feedwater.
Such a single failure is in conflict with the design basis for the system.
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The pump start circuitry at Indian Point Unit 2 was designed so that the steam generator level and loss of feedwater start signals were routed through contacts of the safety injection inhibit relays.
The purpose of these relays is to delay pump starts under safety
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injection conditions until the safety injection sequencer calls.for the pumps to start at the appropriate time.
If the contacts of oither inhibit relay failed in the open position, neither the low steam generator level nor the loss of feedwater start signals would cause the motor-driven pumps to start automatically.
Both inhibit relays are normally deenergized and closed.
m Trojan Nuclear Plant issued Operationai Assessment Review (OAR)
87-54 to verify the nonapplicability of a single failure problem in the control circuitry of the AfW pumps at Trojan.
At Trojan, there are three AFW pumps which consist of a Turbine-driven pump (P-102A),
a Diesel-driven pump (P-1028), and an Electric-driven pump (P-182).
The turbine and diesel driven pumps are safety-related and have an autostart feature.
The electric-driven pump is non-safety-related and does not have an autostart feature.
The electric-driven pump is normally used for startup and shutdown only.
The turbine and diesel driven pumps can be started automatically by one of the following signals:
a.
Undervoltage on engineered safeguard Busses Al and A2.
b.
Steam generator low-low level from two out of three level transmitters of any of the four steam generators.
c.
Safety injection.
d.
Main Feedwater Pumps P-101A and P-1018 both tripped.
In Trojan's review of the start circuitry of pumps P-102A and P-1028 (indicated on Schematic Drawings E-332, E-372A, E-333, E-373, and E-374), it was determined that the autostart components in the circuitry of P-102A are independent from the autostart components in the circuitry of P-102B and there is not any interlock existing between the components.
Failure of a single component _will only prevent one pump from starting but not both at any given time.
The control switches in the start circuitry for the two pumps are also independent.
0AR ~ 87-54 determined that no single-failure problem was found in the start circuitry of the safety-related AFW pumps P-102A and P-1028.
The review of the trip circuitry of pumps P-102A and P-102B (indicated on Schematic Drawings E-333 E-332, and E-332A) found no component that is_ common of both trip circuitry of the pumps.
Failure of any single component will not cause both
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pumps to trip at the same time.
Similar findings were determined for the Electric-driven pump P-182, i.e, no single-failure problem was found in the circuitry of pump P-182.
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The final conclusion of 0AR 87-54 was that there was no single-failure problem in the control circuitry of the AFW pumps P-102A, P-1028, and P-182 at the Trojan Nuclear Plant. Failure of a-single component in a control circuitry for one of the pumps will not prevent the other two from starting or cause them to trip at the same time.
Based on the Licensee's evaluation per their 0AR 87-54, the inspector considers Information Notice 87-34 closed.
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No violations or deviations were identified.
5.
Onsite Followup of Written Reports of Non-Routine Events a.
Licensee Event Report 87-09-L0 (Closed) Raychem Splices Improperly Installed Licensee Event Report (LER) 87-09-L0 discovered on April 16, 1987 that Raychem splices used on electrical connections for the pressurizer power-operated relief valve (PORV) solenoid valves were not installed in accordance with Raychem requirements.
The bending radius for the splices was less than the minimum allowed by Raychem.
Additional Raychem splice deficiencies (insufficient splice overlap and improper use range) were found in other areas.
The
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environmental qualification of the splices is not certified by j
Raychem when the bending radius, overlap, or use range is improper.
i The root cause of this event was improper installation of the Raychem splices during initial construction.
In addition, a bending radius was not specified in the Raychem installation guidelines at the time of initial construction. A contributing cause was a lack of knowledge and training of personnel installing the Raychem splices.
The corrective actions initiated by the licensee was an inspection of Raychem splices, and those which were determined not to meet the
Raychem installation standards were replaced prior to startup from the 1987 refueling outage.
Personnel involved in the inspection and replacement of Raychem splices were trained by Raychem on the proper-inspection and installation standards of Raychem splices.
The Raychem In-line Splice Application Guide is included with the installation procedure used by personnel.
All licensee corrective actions have becn completed during the 1987 refueling outage.
In addition, the Raychem splices have not caused inoperability of corkponents during normal operating conditions.
The licensee concluded thct the Raychem installation criteria was conservative, and the splices would have performed acceptably in a harsh environment.
Based on the abcVe licenspe's corrective actions, the inspector considers LER 87-09 L0 closed.
b.
Licensee Event Reports 87-14-LO&L1 (Closed) Charging Pump Cladding Corrosion Oue to Apparent Manufacturing Def kiency LERs 87-14-LO&L1 detailed the results of an inspection on May 23, 1987 of the "A" centrifugal charging pump (CCP), which indicated corrosion on a portion of the stainless steel cladding on the inside
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surface of the pump casing., Corrosion of the pump casing was through the stainless steel cladding into the carbon steel base'
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material.
Inspection of the "B"'CCP revealed similar corrosion.
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The root cause of this event was determined to be a manufacturing 1 l
deficiency.
The corrosion observed at the pump casing discharge nozzle was attributed to 2 cladding breakthrough during final-machining.
Corrosion observed at the pump casing inlet end was
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attributed to either overmachining of the cladding or inadequate overlay of two adjacent weld beads.
The licensee's corrective actions were to replace the "A" and "B" CCP with stainless steel pump casings.
The licensee determined.that there were no other safety-related pumps in the Emergency Core i
Cooling System with stainless steel cladding.
Based on the licensee's corrective actions, the inspector considers LERs 87-14-LO&L1 closed.
c.
Licensee Event Report 87-22-L0 (Closed) Accumulator Water Levels Inadvertently Allowed to Decrease Below Technical Specification Limit LER 87-22-L0 described a leak test of the "A" accumulator discharge check valves to the Reactor Coolant System on August 22, 1987.
During the test, the water level in the "B" and "C" accumulators inadvertently decreased below the Technical Specification limit of 64% by 58% and 59% respectively.
The root cause of,this event-was personnel error in that the operators had allowed the "A" accumulator level to drop below the low level alarm setpoint and were not attentive to subsequent level decreases in the "B" and "C" accumulators.
The reason the
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accumulator levels decreased below the Technical Specification limit is still being investigated, but the licensee believed that l
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suspected leakage during plant heatup past the accumulator SI test line isolation valves for the "B" and "C" accumulators caused the decrease in levels.
A contributing cause was that there is only one
common control room annunciator for low water level for all four J
This annuncidtor does not have reflash capability, which would have alerted the operator to the decreasing levels in the other acCumJlators.
The licensee's corrective action was to refill the accumulators to within the Technical Specification limit.
Operators were counseled on the need to closely monitor accumulator levels during Periodic Operating Test (POT)-2-4, eatitled "ECCS Pressure Boundary and Acculumator Valve Leakage Inservice Test".
In addition, a caution was added to P0T-2-4 in Revision 15 alerting operators of the need to maintain sufficient water level in the accumulators and the potential for decreasing accumulator wate' level due to leakage of various contrcl valves on lines that connect the accumulators to.the safety injection system test line.
Reflash capability for the
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control room accumulator low level annunciator will be provided as part of the annunciator system replacement planned for 1989.
Based on the licensee's corre'ctive and future annunciator system replacement plans,.the inspector considers LER 87-22-L0 closed.
d.
Licensee Event Report 87-30-LO (Closed) Low CCW Flow to RHR
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Heet Exchanger Procedure Inadequacy LER 87-50-LO described the event on October 21, 1987 during a
- Temporary Plant Test, in which 'it was _ discovered that the Component Cooling Water (CCW) flow to the "A" Residual Heat Removal (RHR) heat exchanger, was only 4460 gallons per minute (gpm).
The Final Safety Analysis Report (FSAR) _ specifies a minimum CCW flow to each RHR heat exchanger of 5000 gpm.
The CCW flow rate to the "B" RHR heat exchanger was confirmed to be greater than 5000 gpm.
The root cause of this event was procedure inadequacy.
The CCW valve lincups performed per 014-1 are done independent of the accident alignment for the CCW system.
The temporary plant test revealed that the as-left throttled position of valve CC-213 without CCW system in an accident configuration yielded an acceptable CCW flow to the "A" RHR heat exchanger.
However, with the CCW system in an accident configuration, insufficient CCW flow was available to the "A" RHR heat exchanger.
A contributing cause was that the control room annunciator for low CCW flow to the RHR heat exchanger has an alarm setpoint of 4500 gpm.
This was misleading because this alarm setpoint is less than the minimum required flow of 5000 gpm as specified in the FSAR.
The licensee's corrective actions were to adjust valve CC-213 to increase the CCW flow to the "A" RHR heat exchanger to 5100 gpm with the "A" CCW system in the accident configuration.
Operating Instruction (0I)-4-1, entitled "Residual Heat Removal" has been
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revised to ensure that the throttling of CC-213 and CC-214 provides adequate flow to the RHR heat exchangers while in the accident configuration.
Revision 23 to 01-4-1 in paragraph 2.3.8 adjusts either RHR heat exchanger CCW outlet valve as necessary to establish flow of 5000 to 5200 gpm to each heat exchanger.
A note in this paragraph cautions that adjustment to the RHR heat exchanger CCW outlet valve CC-213 (train A) or CC-214 (train B)-should be made only on the train which has its SCI /SCII supply and return valves closed.
The inspectr'r was informed that the licensee hlans a revision to this LER in order to elaborate on operator actions in the event of an accident to assure RHR cooling.
This will independently evaluated on a subsequent inspection.
Based on the licensee's corrective actions, the inspector considers LER 87-30-LO closed.
e.
Li ensee Event Report 87-31-LO (Closed) Steam Flow Channel
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Bistable Not Tripped Per Technical Specification, Due to Personnel Error LER 87-31-L0 described the circumstances of October 21,1987, in which the "C" steam line flow indicator FI-532 failed the channel check required by Technical Specifications 4.3.1.1 and 4.3.2.1.
Contrary to Limiting Condition for Operation 3.3.2, the inoperable steam flow channel was not placed in the tripped condition within one hour.
The channel was tripped within approximately 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.
The cause of the failure to trip the bistables was ' personnel error.
A contributing cause was that the plant was recovering from a shutdown following a dropped control rod and operator attention was diverted from the inoperable steam flow instrumentation.
The cause of the incorrect indication from FI-532 was a square root extractor FY-5328 drifting high at the low end of the indicator range.
The licensee's corrective action was to review Periodic Operating Test (POT) 24-2, "Daily Operating Routines" and confirmed that sufficient procedural guidance is provided on Technical Specification required actions upon discovery of a nonconforming condition.
The failure to trip the bistables associated with FT-532 was considered an isolated event.
Personnel were counseled on the Technical Specification requirements.
The square root extractor FY-532B was recalibrated.
Based on the licensee's corrective actions, the inspector considers LER 87-31-L0 closed, f.
Licensee Event Reports 87-34-LO&L1 (Closed) EDG not Demonstrated Operable Per Technical S?ecification Personnel Error LERs 87-34-LO&L1 describes the event on November 2, 1987, in which upon the removal of the "A" EDG f rcrs..,h a for routine maintenance, the redundant EDG was in derno. ;trated operable within one hour as required by Technical Sa " rier ion 3.8.1.1.
The redundant EDG was demonstrated operabit 2.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after the "A" EDG became inoperable.
The root cause of this event was personnel error.
The personnel involved did not comply with the Technical Specifications nor procedures.
The licensee's corrective action was to demonstrate operability of the "B" EDG.
Periodic Operating Test (P0T) 21-2, "Engineered Safety Features and Offsite Power Availability" was reviewed and it was confirmed that this P0T specifically required that the redundant EDG be demonetrated operable when an EDG is removed frorr cervice.
The personnel involved were strongly counseled on the need to ensure required actions are taken in a timely manner and on the requirements of Technical Specification 3.8.1.1 and POT-21-2.
Based on the licensee's corrective actions, the inspector considers LERs 87-34-LO&L1 closed.
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5.
Exit Interview The inspector met with the licensec representatives denoted in paragraph 1 on March 18, 1988, and summarized the scope and findings of the inspection activities.
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