ML20034B917
| ML20034B917 | |
| Person / Time | |
|---|---|
| Site: | Trojan File:Portland General Electric icon.png |
| Issue date: | 04/17/1990 |
| From: | Mendonca M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML20034B913 | List: |
| References | |
| 50-344-90-06, 50-344-90-6, NUDOCS 9005010160 | |
| Download: ML20034B917 (31) | |
See also: IR 05000344/1990006
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U. S. NUCLEAR REGULATORY COMMISSION
REGION V
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Report No.
50-344/90-06
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Docket No.
50-344
License No.
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Licensee:
Portland General Electric Company
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121 S.W. Salmon Street
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Portland, OR 97204
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Facility Name: Tro3an
Inspection at: Rainier, Oregon
Inspection conducted:
February 11, 1990 through March 24, 1990
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Inspectors:
D. F. Kirsch, Chief
Reactor Safety Branch
R. C. Barr
Senior Resident Inspector
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J. F. Melfi
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Resident Inspector
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Approved By:
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4 /#7/90
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M. M. Mendonca, Chief
Date Signed
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Reactor Projects Section 1
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Summary:
Inspectign_on:
February 11 - March 24, 1990 (Report 50-344/90-06)
Areas Inspected:
Routine inspection by the resident inspectors of control
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room operations, maintenance program, surveillance program, operational safety
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verification, event follow-up, and open item follow-up.
During the
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inspection, inspection procedures 30703, 37702, 61726, 62703, 71707, 71710,
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90712, 92700, 92701, 92702, 92710, 92712, 92720, and 93702 were used.
Results
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General Conclusions and Specific Findings
The inspection identified concerns in the following areas:
design control
with respect to safety instrument setpoints; corrective' action system
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implementation to assure timely evaluation and correction of safety-related
nonconformances; supervisor / management oversight of maintenance and
non-routine plant activities; and a large backlog of overdue commitments.
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Significant Safety Matters
None.
Summary of Violations and Deviations
Two cited violations were identified.
One violation resulted from documenting that a safety component had been-
Engineered Safety Feature (ESF) ph 4).
replaced when it hadn't (paragra
The other. violation resulted from an
trip setpoint being set greater than Technical
Specification allowed values (paragraph 5).
Open Items Summary
Five LERS, six 10 CFR 21 reports and one followup item were closed
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unresolved item and two open items were identified in addition to the
previously discussed violations.
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DETAILS
1.
Persons Contacted
- T. D. Walt, Acting Vice President Nuclear
- C. P. Yundt, Plant General Manager
- G. A. Lieuallen, General Manager, Trojan Excellence
- C, K. Seaman, General Manager, Nuclear Quality Assurance
- D. W. Swan, Manager, Technical Services
- M. J. Singh, Manager, Plant Modifications
J. D. Reid, Manager, Quality Support Services
- J. W. Lentsch, Manager, Personnel Protection
- A. R. Ankrum, Manager, Nuclear Security
- J. A. Reinhart, Manager, Operations.
- R. M. Nelson, Manager, Nuclear Safety and Regulation Department
- M. W. Hoffman, Acting Manager, Nuclear Plant Engineering
- S. A. Bauer, Branch Manager, Nuclear Regulation
- J.
Whelan, Branch Manager, Maintenance
J. F. Mody, Branch Manager Plant Systems Engineering
D. L. Nordstrom, Branch Manager. Quality Operations
J. P. Fischer, Branch Manager, PM/EA
G. L. Rich, Branch Manager, Radiation Protection
A. N. Roller, Outage Manager
R. N. Prewitt, Supervisor, Quality Systems
R. L. Russell, Branch Manager, Operations
N. A. Regoli, Instrument and Control Supervisor
J. A. Benjamin Supervisor, Quality Audits
J. D. Guberski, Nuclear Safety and Regulation Department Engineer
- W. J. Williams, Compliance Engineer
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- D.
Couch, Compliance Engineer
The inspectors also interviewed and talked with other licensee employees
during the course of the inspection. These included' shift supervisors,
reactor and auxiliary operators, maintenance personnel, plant technicians
and engineers, and quality assurance personnel.
- Denotes those attending the exit interview.
2.
Plant Status
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The facility operated at 100% power from February 11, 1990 through March
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19, 1990. At 5:55 pm, on March 19, 1990, a reactor shutdown was
initiated because an Engineered Safety Feature, high steam flow setpoint,
was identified to be greater than allowed by the Trojan Technical
Specifications. At 6:35 am, March 20, 1990, the facility entered Mode 4
and began the 1990 Refueling Outage. Major planned outage activities
include refueling, annunciator replacement, anticipated transient withoutl
scram mitigation circuitry installation, steam generator tube inspection
and sleeving, low pressure turbine inspection, and containment air cooler
coil sleeving.
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3.
Operational Safety Verification (71707)
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During this inspection period, the inspectors observed and examined
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activities to verify the operational safety of the licensee's facility.
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The observations and examinations of those activities were conducted on a
daily, weekly or biweekly basis.
Daily the inspectors observed control room activities to verify the
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licensee's adherence to limiting conditions for operation as prescribed
in the facility Technical Specifications.
Logs, instrumentation,
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recorder traces, and other operational records were examined to obtain
information on plant conditions, trends, and compliance with regulations.
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On occasions when a shift turnover was in progress, the turnover of
information on plant status was observed to determine that pertinent
information was relayed to the oncoming shift personnel.
Each week the inspectors toured the accessible areas of the facility to
observe the following items:
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(a) General plant and equipment conditions.
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(b) Maintenance requests and repairs.
(c) Fire hazards and fire fighting equipment.
(d) Ignition sources and flammable material control.
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(e) Conduct of activities in accordance with the licensee's
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administrative controls and approved procedures.
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(f)
Interiors of electrical and control panels.
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Implementation of the licensee's physical security plan.
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Radiation protection controls,
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Plant housekeeping and cleanliness.
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(j)) Radioactive waste systems.
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Proper storage of compressed gas bottles.
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Weekly, the inspectors examined the licensee's equi," ;nt clearance
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control with respect to removal of equipment from service to determine
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that the licensee complied with technical specification limiting
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conditions for operation.
Active clearances were spot-checked to ensure
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that their issuance was consistent with plant status and maintenance
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evolutions.
Logsofjumpers, bypasses,cautionandtesttagswere
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examined by the inspectors.
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Each week the inspectors conversed with operators in the control room,
and with other plant personnel.
The discussions centered on pertinent
topics relating to general plant conditions, procedures, security,
training and other topics related to in progress work activities.
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The inspectors examined the licensee's corrective action reports (CARS)
to confirm that deficiencies were identified and tracked by the system.
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Identified corrective actions reports were being tracked and followed to
the completion of corrective action.
Routine inspections of the licensee's physical security program were
performed in the areas of access control, organization and staffing, and
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detection and assessment systems.
The insaectors observed the access
control measures used at the entrance to tie protected area, verified the
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integrity of portions of the protected area barrier and vital area
barriers, and observed in several instances the implementation of
compensatory measures upon breach of vital area barriers.
Portions of
the isolation zone were verified to be free of obstructions.
Functioning
of central and secondary alarm stations (including the use of CCTV
monitors) was observed.
On a sampling basis, the inspectors verified
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that the required minimum number of armed guards and individuals
authorized to direct security activities were on site.
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The inspectors conducted routine inspections'of selected activities of
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the licensee's radiological protection program.
A sampling of radiation
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work permits (RWP) was reviewed for completeness and adequacy of
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information.
During the course of inspection activities and periodic
tours of plant areas, the inspectors verified proper use of personnel-
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monitoring equipment, observed individuals leaving the radiation.
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controlled area and signing out on appropriate RW5's, and observed the
posting of radiation areas and contaminated areas.
Posted radiation
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levels at locations within the fuel and auxiliary buildings were verified
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using both NRC and licensee portable survey meters.
The involvement of
health physics supervisors and engineers and their awareness'of
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significant plant activities was assessed.through conversations and
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review of RWP sign-in records.
Enoineered Safety Feature Walkdowns (71710)
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The inspectors verified the operability of selected enginc.ered safety
features.
This was done by direct visual verification of the correct
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position of valves, availability of power, cooling water supply, system
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integrity and general condition of equipment, as applicable.
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The Auxiliary Feedwater (AFW) System was one of'the ESF systems walked
down by the inspector.
During the walkdown
of the AFW system, the inspector noted two items.
One was that the heat
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trace, which assures the AFW line does not freeze during cold weather and
provides accurate flow indication on AFW flow element (FE) 3043D sensing
line had been removed from the piping and was hanging suspended away from
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the pipe.
The inspector informed the licensee of this and the licensee
wrote a priority 1 maintenance request to fix this item.
During followup
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on this item, the licensee was unable to determine when the heat trace
had been removed.
The other item was the bypass flow orifices (FO).
F0-2202, -2203 and -2204 appeared to be installed backwards based on the
word inlet being stamped on the outlet of the orifices.
The bypass flow
orifices keep the steam line to the AFW turbine warm.
The licensee wrote
priority I maintenance requests (MRs) 90-2631, -2632, -2635
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this item.
Subsequently, the ins)ector determined that the bypass
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orifices had no previous MRs on tiem, and probably had been installed
this way during construction.
On February 20, the licensee determined
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the orifice orientation was acceptable, i.e. the orifice plate is a
single 3/16 inch hole in a 2 5/8 inch plate and is not direction
dependent.
The three priority 1 MRs were subsequently canceled.
No violations or deviations were identified.
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4.
Maintenance (62703)
Motor operated valve MO-10011 is the outside containment isolation-
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valve for the hydrogen ventilation system.
Two technical specific 6tions
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(TS) are applicable to this valve: TS 3/4.6.3.1 for containment isolation
and TS 3/4.6.4.3 for an operable flow path for combustible gas control in
containment.
On February 16, 1990, breaker B2245 for the motor operator of MO-10011
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was found with its thermal overloads tripped after plant operators
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attempted to remotely open the valve from the control room. After the
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thermal overloads were reset and the breaker reclosed, the valve was
remotely cycled opened and closed, then declared operable.
No
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maintenancewasperformedonMO-10011(MR)90-2524
but operators did generate a
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Priority 1 (P-1) Maintenance Request
to evaluate the valve's
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performance by running current traces on the motor operator to ensure the
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overloads were not tripping prematurely.
The maintenance history of the
valve was not assessed as a result of the motor operator tripping.
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On February 20, 1990 M0-10011 was declared inoperable when the breaker
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again tripped as the plant q)porators were opening the valve to initiate
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pressure reduction (venting of containment. The current traces
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requested by the operators in MR 90-2524 had not yet been performed. 'The
Electrical Maintenance Supervisor reviewed the maintenance history
associated with MO-10011. He found an active MR (89-06447), which was
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still in the planning stage, to investigate M0-10011's performance, and
noted M0-10011 had a higher than expected running current in the open
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direction after Preventative Maintenance (PM) work was performed on the
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valve in 1989.
Because MR 90-2524 had also been written to investigate
the performance of MO-10011. MR 89-06447 was cancelled. MR 90-2524 was
modified to troubleshoot and investigate'.
work per MR 90-2524 was performed. As a result of
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On February 21, 1990 3
the electrical traces obtained while conducting this maintenance, the
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Electrical Maintenance Supervisor concluded the valve had a mechanical
problem since the valve, a motor operated butterfly valve with a rotating
stem vice a rising stem, had higher opening current than closing current.
He wrote MR 90-2687 to support mechanical work if the valve was
determined to have a mechanical deficiency.
Because MO-10011 is located
in elevated portions of the auxiliary building electrical facade area,
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scaffolding was erected to evaluate valve operation as the valve was
manually stroked. However, due to a small leak in the primary coolant
sampling line, which is in the vicinity of M0-10011, the facade area was
contaminated and the erection of the scaffolding was delayed until March
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On February 22, 1990, at the maintenance organization's request, two
Nuclear Plant Engineering (NPE) engineers inspected and evaluated the
performance of M0-10011.
On February 26, 1990, the maintenance engineering group initiated a
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Corrective Action Request (CAR), a Quality Assurance document to track
nonconformances and plant deficiencies, C90-5007 on breaker B2245.
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During the initiation of the CAR, the assigned maintenance engineer also
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spoke with plant electricians about replacing the breaker.
A qualified
replacement breaker was found.
The maintenance engineer noted on
C90-5007 that the breaker was tripping at currents higher than the
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licensee's specifications allowedj however, it was also noted the
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National Electrical Manufacturers
Association (NEMA) rating would allow
continued use.
The maintenance engineer spoke with the electrician about
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replacing the breaker.
The maintenance engineer left with the
understanding that the breaker was going to be replaced.
Without
verifying that the breaker had been replaced he noted on the CAR that
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the breaker had been replaced.
TheelectricIanswere,how;ver, waiting
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for another MR to be generated to replace the breaker, ber,ause MR 90-2524
was to troubleshoot the malfunctioning breaker and not replace the
breaker.
The licensee stated that MR 90-2524 had not gone through final
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approval yet, and believed the review would have identified that the
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breaker had not been replaced.
The licensee then wrote Priority 2 MR-
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90-3146 to replace the breaker.
As of the end of the inspection period,
the breaker had not been replaced.
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On February 28, 1990 to document that circuit breaker B2245 tripped at
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valuesgreaterthanlicenseespecifiedvaluesforinstantaneouscurrent
but less than National Electrical Manufacturing Association (NEMA)
values, CAR C90-5007 was issued by QA.
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On March 1, 1990, C90-5007 was closed by the Management Corrective Action
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Committee (MCAC), a group of two or more managers or supervisors that
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determine the significance and the priority of the CAR, based on the
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breaker B2245 being replaced.
No documentation was attached to the CAR
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that provided reasonable assurance-the breaker had been replaced.
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On March 2, 1990, while licensee electricians were electrically opening
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the valve to measure the motor current per MR 90-2524, the motor operator
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circuit breaker for M0-10011 again tripped.
To verify that there was no
mechanical binding of the valve, the dust cap to the valve actuator was-
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removed to see how the stem was rotating.
No further. maintenance was
performed on March 2.
On March 5, 1990, the inspector, prior to observing the field work on
MO-10011 discussed the previous operating history of M0-100' 3 with the
supervisIngmaintenanceelectrician.
The inspector found that the
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supervisor was aware that the valve had high running current in the
opening direction and that MR 89-6447 had been previously written and
cancelled as a result of MR 90-2524 being written.
The supervisor was
not aware of any other historical problems with this valve. The inspector
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then observed the continuing maintenance activities on M0-10011 required
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by MR 90-2524.
The electricians had the MR with them and discussed their
actions to observe valve operations as the valve was remotely operated
from the control room.
The electricians took a current trace on all
three phases and found that the A phase did not have current indication
in the o)en direction.
Phase B and Phase C currents were equal and 50%
higher taan when the valve was operated in the closed direction.
The
currents on all three phases were the same in the closed direction.
The
electricians did not believe the motor could have operated the valve with
power on only two phases, even though it a peared the A phase was open.
Since the motor operated the valve smoothi
in the closed direction, the
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electricians concluded that there was no problem with the motor. The
electricians then checked for loose connections and high resistance
contacts per procedure.
Initially, they found no loose connections, but
did note a higher resistance on phase A versus the other phases (38 ohms
versus 0.1 ohms). The licensee refurbished contacts with a flexible
abrasive burnishing stone and rechecked the resistance. The inspector
noted that licensee procedure MP 1-7, "480 Volt Motor Control Circuit
Breakers and Molded Case Circuit Breakers," Revision 0, of April 8,1988,
permitted the electricians to refurbish contacts using a file while the
vendor manual prohibits the use of a file. The resistance values did not
significantly change. The electricians then rechecked the connections
again and during this check found the screw connections of the A phase
contactor loose (1/2 to 3/4 of a turn). After retightening the screw,
they measured the resistance across the contactor and the A phase read
the same as the other phases (0.1 ohms). The valve was then stroked in
the open and closed direction several times and the current measurements
in both the open and closed directions for all three phases were
approximately equal. The valve was then returned to service and declared
operable. The electricians returned the MR to their supervisors for-
review. During this maintenance observation, the inspector noted no
licensee supervisory or management oversight of this work. This and other
ot,servations of little maintenance supervisory oversite were discussed
with the Maintenance Manager.
The Maintenance Manager concurred that
additional emphasis in this area was needed, and plans to provide
additional policy direction to maintenance supervision.
On March 6, 1990, the inspector reviewed the maintenance request and
found Corrective Action Request (CAR) C90-5007 with the MR package. The
CAR noted the circuit breaker for M0-10011 had been replaced. The
inspector was not aware that the circuit breaker had been replaced and
requested to be provided a copy of the MR for review. The licensee's
maintenance organization searched for the MR, but could not locate an MR
that replaced the breaker. Subsequent inspection identified that the
breaker had never been replaced.
In discussions with the personnel
participating in the c1Nure of C90-5007, the inspector found that the
licensee's Management Corrective Action Committee (MCAC) closed out the
CAR on March 1, 1990, based on their understanding that the breaker had
been replaced. The MCAC concluded that the breaker had.been replaced
based on a conversation with the cognizant maintenance engineer. The
closure of the C6R without sufficient supporting information to verify ).
the breaker had been replaced is an apparent violation (50-344/99-06-01
After the inspector identified this to the licensee. C90-5007 was
reopened to evaluate how closure of the CAR had occurred.
C90-5007
remained open at the end of the inspection period. The inspector noted
that the instruction for the CAR program neither allows or prevents
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reopening of a CAR once it has been closed.
Subsequent inspector review of MO-10011's equipment history found that
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MO-10011 had higher than expected operating current in the valve's open
direction since May 1988. He found that MR 88-0764, completed on May 18,
1988, showed that MD-10011 had an opening current of five amps and a
closing current of three amps.
Licensee review, that included a QC
observation, of this MR did not identify the high current as an unusual
condition or a condition requiring additional evaluation.
On March 6, 1990, the inspector toured the valve area and the breaker
area after MR 90-2524 work had been completed.: The inspector found that
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the dust cap for the motor operator had not been replaced since its
removal on March 2.
The dust cap prevents foreign materials from
entering the valve's operator mechanism. When the inspector informed the
licensee electricians of this deficiency, the dust cap was replaced.
On March 7, 1990, during review of the licensee's preventive maintenance
with respect to electrical switchgear, the inspector noted that the
vendor manual for the Motor Control Centers (MCCs) stated that the MCCs
should be inspected every six months.
The licensee's current PM
requirement is to inspect MCCs every three years.
The licensee informed
the inspector that the MCCs had been inspected every six months after
initial receipt of the MCCs in 1973; inspections were subsequently
changed to every year in 1974, and then sometime in the mid 1970s the
frequency was changed to once every three years.
The licensee provided
the reasoning for the PM frequency on the Limitorque motor operators (36
months) and the molded case circuit breaker (6 years).
The licensee
could find no safety evaluation that assessed the change in MCC PM
frequency.
The licensee noted that the present MCC PM frequency appeared
acceptable since they had not found many problems when the PM was
performed at a periodicity of three years.
The licensee also stated that
the vendor may sell these components to other industries, and the MCCs
may be located in harsher environments than Trojan and may require more
frequent inspection.
This item will be followed up during a future
inspection. (50-344/90-06-02).
In summary, this maintenance observation identified the following
weaknesses or deficiencies:
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The licensee did not exhibit an intrusive attitude with respect to
the tripping of MO-10011 motor operator breaker or conduct a timely
evaluation of the tripping.
Licensee trending did not identify or take appropriate additional
measures for an abnormally high operating current for M0-10011 as a
result of preventative maintenance in 1988.
The licensee's corrective action system (CAR) did not require
sufficient documentation to assure deficiencies were corrected,
Licensee supervisory / management oversight of maintenance activities
was not sufficient to assure equipment was restored to originally
installed condition.
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The licensee deviated frem vendor recommendations for safety related
components without documentation.
One violation was identified,
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Surveillance (61726, 92701, 93702)
Background and Observations
The Engineered Safety Features Actuation System (ESFAS) acts to limit the
consequences of accidents.
The ESFAS continuously monitors certain plant
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instrumentation to provide this function.
The licensee checks
periodically and calibrates these channels to the requirements of Trojan
Technical Specification 3/4.3.2, " Engineered Safety Features Actuation
System Instrumentation."
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One of the accidents that the ESFAS limits the consequence of is a main
steam line break accident.
Some of the conditions indicative of a main
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steam line break would be steam line low pressure when compared to other
steam lines, or a high steam line flow when compared to a reference steam
flow coincident with low steam pressures or RCS average temperature.
The
reference steam flow is provided from turbine impulse pressure, which
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inputs into an electronic device that generates the reference steam flow
(functiongenerator).
This steam flow value is then compared to actual
steam flow and is then input into the ESFAS logic if the actual steam-
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flow is greater than the reference steam flow.
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Early in plant life, the plant used the setpoints established by
These setpoints and methodolo
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Precautions, Limitations and Setpoints (PLS)gy were contained in the-
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document furnished by
In 1981, the Instrumentation and Control (I&C) maintenance group
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performed a calculation for the function generator which provides
reference steam flow.
This calculation was used to obtain a greater
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understanding of the Westinghouse set)oint.
For conservatism, the
function generator was set at values melow the setpoint values prescribed
by the calculation.
In July 1985, a Plant Setpoint Change (PSC) 85-06, was performed due to
fouling of the steam flow and feed flow venturis.
The indicated steam
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flow at 100% reactor power was higher than 100%, producing high steam
flow alarms.
The function generator setpoints were changed, to
correspond to these higher indicated steam flows.
In 1986, Request for Design Change (RDC)84-124 installed new steam flow
instruments so that variations in the steam flow due to fouling could be
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compensated for electronically.
Also, new turbine impulse pressure
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instruments were installed at new locations.
The function generator
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setpoints were not readjusted after the turbine impulse pressure
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instruments were moved and installed, or after the flow instruments were
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installed.
In July 1986, Calculation TE-113 " Scaling Calculation, Reactor Trip and
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Safety Injection," was finalized and the setpoint for the function
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generator was calculated.
This calculation provided the trip setpoints,
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or how to readily obtain the trip setpoints, for most of the reactor
protection system.
This setpoint was not effectively transmitted to the
I&C department, and therefore was not changed.
The instrument data card
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(I&C-4) reflected the function generator setpoint of PSC 85-06 vice the
function generator setpoint required by TE-113.
On March 7, 1990, the resident inspector observed the-licensee conduct
Periodic Instrumentation and Control Test (PICT) 3-1, " Steam Flow - Feed
Flow, Steam Line Pressure and Turbine First-Stage Pressure, Protection
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Set 1," Revision 25.
This monthly PICT performs Channel Functional
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Tests (CFTs) for steam flow, feed flow, steam generator pressure and the
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turbine first stage pressure.
The specific functions checked were: the
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steam flow / feed flow mismatch with low steam generator pressure or low
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average RCS temperature, steam generator differential pressures greater
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than 100 psi, and the protection functions off of the turbine first stage
pressure.
The licensee uses PICT 3-1 in conjunction with PICTs 3-2, 8-1,
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ard 8-2 to verify these functions for the four protection sets.
The inspector observed that the surveillance testing was performed by
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qualified technicians using calibrated instruments.
The protection set
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was put in the tripped state to perform the CFT.
The licensee adhered to-
the Limiting Condition for Operation (LCO) of the Technical Specification
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(TS) during the surveillance.
During the conduct of the test, the
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inspector noted that the licensee followed the procedure and compared the
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voltage settings, stated on the data sheet, to actual values.
It was not
apparent that all of the voltage values were directly comparable to the
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technical specification requirements.
To verify the values specified in
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the technical saecifications, one can refer to the instrument data card
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(I&C-4) or to t1e scaling calculation.-
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To verify that the voltage values were correct, the inspector reviewed
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the procedure, procedure data sheets and previous calibration data for
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the instruments.
The ins)ector noted discrepancies in the data sheets
[
for the various PICTs.
T1e inspector mentioned these to the licensee on
-
March 14, 1990, and noted that these discrepancies were not
safety-related, but the data sheets could be improved to help reduce
confusion.
The discrepancies noted were:
PICT Discrepancy
-
3-1 The data sheet checks for one signal condition " Auto Rod Permissive.
e
Trip" had two different values (1.246 and 1.286 volts).
The
inspector was informed that one value is an input into the 10% power
permissive and the other is an auto rod withdrawal block at 15%
i
power.
3-1 The labeling for comparing Steam Generator (S/G) three pressure less
-
than S/G four pressure was not clear, though the other S/G prtssure
,
comparisons were clear.
8-1 This PICT had a value of 3.685 volts versus all the other PICT
-
values of 3.683 volts when comparing steam flow setpoints.
The
licensee stated that this was a typographical error.
'
The inspector reviewed the last four previous calibrations for these
instruments and noted that the licensee was meeting the required
frequency.
The inspector also noted that the calibration record for Flow
.
Transmitter (FT) 522, dated April 23, 1988, was apparently
out-of-calibration (000), but there was no 000 investigation data sheet.
The licensee has a program to analyze the effects of an instrument being
000.
This is similar to previous NPC concerns about the licensee's 000
investigation program as noted in the notices of violation contained in
NRC inspection reports 50-344/89-24 and 50-344/89-31.-
,
t
.
--,
v
, ,
c
-
e
.
< : s .
-
3 ..
10
.
(
-
.
The inspector attempted to verify that the technical s)ecification-
..
l
setpoints were equivalent to the setpoints in the caliaration data sheet.
'
The inspector compared the I&C-4 data cards to the scaling calculation
L
TE-113.
One of the purposes of the calculation was to establish'the'
i
scalingequationsforreactortrip.andsafetyinjectioninstrumentloops.
<
This calculation established the majority of the reactor trip setpoints-
l
and all the functions checked.by PICT-3-1.
The inspector, noted one item
where the scaling calculation basis for.the setpoint was not clear and
'
another where the setpoint apparently was not correctly set.
The first item.(raised by the inspector on March 15, 1990, to Nuclear-
1
The 100%gineering (NPE)) concerned pressure-compensation for steam flow.
Plant En
t
4
steam-flow pressure was 895 psig; however, due to changes (such
-
as. steam generator tube plug % steam pressure is 850 psig.'ging and operatin
4
temperature).the present 100
-The effects of
q
these changes are currently being evaluated for the licensee by the
vendor (Westinghouse) and will be followed by the inspector
l
(50-344/90-06-03)..
The second item that was discussed with the NPE' electrical supervisor at
10:00 a.m. on March 16, 1990 concerned the trip function. generator ..
'3
setpoint.
The inspector noted that the I&C-4. calibration cards for the
function generator specified setpoints different than those specified.in
'
the calculation TE-113.
This trip function varies steam flow trip-
reference values from low power (0 to 20%) to a full power value.
The
,
i
functional unit, trip setpoint,-and allowable value is-defined in table
1
3.3-4 of the technical specifications as follows:-
FUNCTIONAL UNIT
TRIP SETPOINT
ALLOWABLE VALUES
-
Steam Flow in Two
< A function defined as < A function defined.as-
-'
Lines - High Co-
Tollows:
40% of full
Tollows:
44% of full
incident with Tavg steam flow between 0%
! steam flow between 0%
- Low or Steam
and 20% load and then
and 20% load and'then
Line Pressure
increasing linearly to
increasing linearly to-
- Low
110% of full steam flow 111.5% of full steam
.,
at full load
flow at full load
a
,
!
L
The voltage values noted in the I&C-4 hard card stated a function lower
limit of 1.331 volts to 20% power and upper function limit of 4.114; volts
c
'
at 100% power.
The calculat. ion (TE 113) notes that the function lower
limit is 1.317 volts and the upper voltage limit was 3.9856 volts.
It
was subsequently determined by the NPE engineers.that this function
.!
generator was calibrated to the following equivalent approximation:
1
40.87% of full steam flow between 0% and 20% load and then' increasing
linearly to 112.34% of full steam flow at full load.
'
- l
'
The NPE engineers immediately began evaluation of.this safety concern,
'i
since the trip setpoint was set nonconservatively from the values assumed
in the accident analysis.
The engineers looked to their controlled
engineering drawing E-3, which provides information on instrument error
and allowable margin available to the safety limit.
The engineers also
contacted a licensing engineer for his-input into this nonconservative
trip setpoint.
The engineers determined quickly that there was margin
+
. .
.
.
.
.
.
_
a'
-%
O
11-
,
.
..
available to the safety limit, even accounting for where the function
4
generator was set and instrument inaccuracies.
They did not evaluate
specificallythesettingagainsttherequiredTrojanTechnical
Specification setpoint. =The setting of the function generator was -less
conservative than the technical specification requirement and above the
a
allowable limit of the technical specifications which is an apparent
violation (50-344/90-06-04).
The engineers also informed the manager of the electric branch of NPE of
the setting, and started to write a Lorrective Action Request (CAR).
The
CAR (C90-1005) did not get completed on March 16, 1990 (Friday), but was
completed the next business day (Monday, March 19,1990), as allowed by.
their procedure NDP 600-0, " Corrective Action Program."- The NPE
3
engineers took the CAR to the shift supervisor at approximately 4:45 p.m.
'
on March 19, 1990 for his signature, per NDP 600-0.
The inspector was in
the control room performing routine inspection at approximately 5:00 p.m.
Plant Reduction-In Power
The Shift Supervisor and Assistant Shift Supervisor discussed the CAR-
with the engineers so they could understand it.- The discussion went on-
for about 60 minutes.
This discussion raised technical specification
operability issues with the shift' supervisors, since-they would not meet
Limiting Condition for Operation (LCO) 3.3.2 and be outside the limits of
that specification.
The Duty Plant Manager (DPM), operations managers,-
3
and the acting Vice President, Nuclear were informed.
It was decided
j
that they were in technical specification 3.0.3 at 5:55 p.m. which
requires that if a condition is discovered outside'the technical
j
s)ecification, the plant reduces power until the point is reached white
q
tie specification does not apply.
The acting-Vice President, Nuclea-
i
also wanted to make sure that the emergency plan was considered when
shutting down the plant.
At the critique on this event, the branch
H
manager for operations said that he had not considered the' Emergency Plan
. !
at that time.
The plant started down at that time and the NPE engineers
!
were asked to calculate a 1oint where the as-calibrated function
!
generator would be below tie allowable value in table 3.3-4.
One
engineer calculated that the point where the allowable value and
_
i
calibrated curve met was about 83% power,_and the other engineer double
checked that result.
The initial plan was to decrease'to-approximately
-
75% power and then recalibrate the function generator.
To guarantee that
the plant power remained below 83%, the reactor high power trip yetpoint
would be reset below 83% power (i.e. 78%).
-
t
The licensee continued to review TS 3.3.2, table 3.3-3 and table 3.3-4,
'
and this review revealed that the plant would still not meet LC0 3.3.2.
i
Specifically, LCO 3.3.2a states than when a trip setpoint is set less
conservatively than the specifications allow,-to do-the required actions
associated with that action statement.
Since the trip function would
still be set less conservatively than the allowable value column,
channels were inoperable.
Since.all channels were inoperable, they could
not be complying the-action statement and would still be in technical
'
specification 3.0.3.
This was realized at approximately 6:33 p.m. and
the plant would have to go below 0% power (mode 3), less than the P-12
setpoint (553 degrees-Tavg).
This particular power value, where the
4
i
f
h
- J
'12
L ,-
. _ -
.
. .
.
-
specification would not apply,.was based from Table 3.3-3, functional
unit 1.f(Safety' Injection,SteamFlowintwo.'steamlineshigh)s.An
unusual event was-declared at 6:35 p.m.', based on the licensee
-
Emergency Plan (EP) 001-7, step 2, which states that an unusual event is--
to be declared for a shutdown required by the technical specification.
3.3.1 or 3.3.2, in modes 1 or 2.
The licensee's plan at this time was to
go to mode 3, approximately 530 degrees Tavg.
The inspector observed portions of the shutdown.
The shutdown proceeded
smoothly and the licensee implemented their emergency plan.. The unusual
event was terminated at 10:32 p.m., when the plant entered Mode 3.
The oncoming crew'was briefed on the events, and this crew independently-
~
reviewed-the technical specifications.
The oncoming crew discovered-that
table 3.3-3, functional unit 3.d (Steam Line Isolation, steam flow in twoi
steam lines high), was another part of the technical specification which
specified that this steam-flow reference function was required to be
operable in all of mode 3 for steam line isolation purposes.
The crew
discussed this finding with the DPM, the Nuclear _ Safety and Regulation-
Department Branch Manager, and the Operations Branch Manager.
The crew
wanted to know.if it was permissible to shut all the main steam isolation
i
valves'and remain at 530 degrees F. with the steam:line Power Operated
Relief Valves (PORVs).
There was no adverse comments and this crew then-
manually shut all of the main steam'line isolation valves (MSIVs)-to meet
this specification.
The 0)erations Branch. Manager called-the control
room later, after he had t1ought-about it.
The Operations Branch Manager
felt more comfortable in mode 4 to meet the technical specification and
!
said that the plant should go to mode 4.
The. licensee.then 03ened.up the
1
The C MSIV_ remained closed since tie main
'
steam line aypass (CV.2279) around the MSIV was closed previously
(November 16,1989), and-the valve could not be opened. .The plant then
a
_;
continued cooldown to mode 4 where the specification does not apply.
The
plant continued with the technical specification 3.0.3 requirement to
1
shut down and' reached mode 4 at 6:35 a.m. on March 19,1990'.(12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and
!
40 minutes after 3.0.3 was declared).
!
Previous Events
{
During the critique of.this event, the inspectors became aware of a
1
similar event that happened previously.
This similar event is noted in
-l
Licensee Event Report (LER) 88-16.
This LER describes an event where the
i
setpoints, described in the same scaling calculation TE-113, were not the -
same as in the plant.
The particular setpoint in question was the steam
generator high water level-feedwater isolation and turbine trip (at' 75%
of narrow range span).
The inspector reviewed this LER and three
corrective actions were described.
These were:
j
-
.
1)
Revise the setpoint on the level bistables to a value within the
technical specifications
'
2)
For Plant Systems Engineering to perform a review of calculation
- '
TE-113 for other reactor trip and ESF instruments to identify
discrepancies.
I
l
4
-
.
. .
13
.-
.
.
3)
To formally transmit future calculations of instrument calibration
data to plant system engineering
Item I was tracked by the licensee's Commitment Tracking List (CTL), but
items 2 and 3 were not.
Item I was performed via a Plant Setpoint Change
88-10, Revision 1 (CTL 21677).
The inspector asked for:a description of
what was reviewed and what was performed for item 2 above.
Plant Systems
Engineering (PSE) could not provide any documentation on what was-
reviewed.
The only internal documentation ^available was a statement in
j
the licensee's internal Event Report (ER)88-069. which stated that the.
i
review was complete. _The engineer and his supervisor,.who did the
review, are no longer working at Trojan.
The inspector discussed what
was reviewed with an engineer who shared an office'with'the previous
engineer.
It was this engineer's recollection that the previous
engineer's review took much less than 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> and.was basically _
verifying where the trip bistables settings were;
This engineer also
stated that to do a thorough independent check for RCS. average
Temperature alone would take more than 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />.
The review performed-
did not-identify the trip setpoint discrepancy for-steam flow even though-
.
the voltage high and low setpoints are explicitly stated in-TE 113.
The
j
inspector wanted to know the mechanism by which results from NPE are
i
transmitted to PSE for item 3 above.
The inspector was informed that
1
this was via a memo signed out by the manager of electrical NPE.
The
'
inspector was also informed that this depended on the manager's
discretion on what was to be sent. The inspector was also informed that
.
this approach had not changed since 1988.
.!
i
- Other Identified Problems
.]1
Information Notice (IN) 89-68, " Evaluation of Instrument Setpoints'During
1
Modifications," dated September 25, 1989, was evaluated by Operational
j
Assessment _ Review (0AR) 89-79.
IN 89-68 addresses the. implementation of
i
the methodology of setpoint changes in I&C safety-related systems.
The
1
inspector asked to review the CTL items generated by the OAR and an
,
associated Action Plan (89-07) that related to' instrument setpoints.
The
OAR review (evaluated December 22,1989) identified several-actions.to be
!
put into the action plan (89-07) including, in part, the need to develop
a program to evaluate setpoint changes; provide.one consistent method for
scaling calculations; and provide a central clearing point-for all change
requests to be evaluated prior to implementing the change.
It was found
during this review, that the items had not been implemented-into the
i.
licensee's commitment tracking list as of the end of the inspection
period.
The inspector noted that the action plan was scheduled to havet
been revised by December 31, 1989.
In discussing this with the cognizant
licensing engineer, he noted that the update was late and would probably '
l
,
be later.
The action plan had an item to compare technical specification
j
values with the loop inaccuracies.
This is scheduled to be done by
j
December 1991.
9
,
1
Since the inspector became aware of the problem with steam generator-
.
'
level, additional followup was done in that area.
The inspector noted
a
1
1
.-
m
. . . . . .
. . . . . . . . .
.
-
.
.
..
-.
.
. . . - . . .
.
..
' .I.
.
'14-
a,
.-
.
.
that the steam generator levels have been discovered out of calibration
~(00C)whentheplantenteredits':refuelingoutage.
In-1987, nine of-12
instruments were 000.
In 1988, 10 of 12' instruments were 000.
In 1989,
five of 12 instruments were 000. The inspector also reviewed calculation
TE-161, which is a hot calibration for the steam generator narrow-range
level instruments. The height of the level transmitters were surveyed in
containment last year and the temperatures surrounding-the instruments -
were taken. The inspector's review of this calculation.noted a mistake
with Level Transmitter (LT) 518. This_later proved to be transposed
c
digits in'the calculation, which were not caught by the_ second level of
review for the calculation. These items will be followed up by the
inspector as a part of routine inspection..
In summary, this surveillance observation identified the following ~
j
weaknesses or deficiencies:
"
The licensee control over instrument data setpoints'is based on:the-
'
180-4 card, but the correct values are not always reflectedf ontthe
card.
-
-
.
l
The licensee had an ESF setpoint set higher than the technical
j
specifications allow.
l
The' calculated setpoints were not effectively transmitted to the
j
plant.
The licensee's actions- to preclude repetition were not effective in
that a similar event could have identified this' higher trip setpoint
and the formal proceduralized mechanism to . implement _ setpoints was
not established.
The licensee did not immediately recognize.that the higher trip
setting involved exceeding the technical-. specification and the
operability determination was not made until about 78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br /> later,
q
i
One violation was identified and no deviations were identified.
,
6.
Event Follow-up (62703, 92701, 93702)
'
Degraded Voltage Protection for 4.16 KV buses not Surveilled Correctly
i
At approximately 1:00 pm on February 13, 1990,'the resident inspector
became aware of an issue identified by a licensee Quality Inspections
(QI) inspector. The issue concerned the testing of the undervoltage and
degraded voltage relays performed by Periodic Instrumentation and Control
Test (PICT) 20-1 and 20-2.
Both PICTs perform channel functional tests
on the undervoltage and degraded voltage relays for vital busses Al and
i
A2. The QI inspector noted that by procedure and his February 12, 1990
'
observation, the time required by technical specification 3/4.8.3.1 for
'
the relay to actuate was not noted in the procedure or tested.
Following this, the resident inspector conducted a review of technical-
specification allowable values for response testing and the guidance
,
given in the procedurps (noted below in seconds). The times were not
!
.
%.
,
15-
.
.
.
required to be recorded by the procedure.
Only qualitative assessments
were made (satisfactory or unsatisfactory).
Therefore, the inspector
concluded the procedure was not specifically verifying the relay timing.
setpoint.
TS
PICT 20-1
PICT 20-2
l
UnderVoltage Relays
El +.1
About 1.5
About 1.5
Degraded Voltage Relays 55 f5
Not noted
5 seconds
1
At 9:45 am on February 14, 1990, the resident inspector spoke with the QI
electrical supervisor about the corrective actions that had been taken-
for this apparent deficiency.
The QI supervisor stated the issue was'
still being evaluated.
The resident inspector noted that no internal
event report had been written, nor had the control operators been-
informed to make an operability determination.
Subsequent to this
discussion, the supervisor. initiated discussions with Plant Systems-
Engineering, Operations, and Maintenance to determine the events'
significance.
The QI supervisor the QI inspector wrote an, event' report,.
and informed the QA manager of.these findings.
The resident inspector
then discussed this concern with the office of Nuclear Reactor Regulation-
(NRR) and Region V management.
The discussion determined that_further
followup as an unresolved item was. required (90-06-06).
The licensee briefed operators on the concern and-issued them stop
>
watches.
If a degraded grid voltage was annunciated, the operator was
directed to start the stopwatch, attempt to stabilize the voltage and, if
the degraded voltage condition exists for longer than 50 seconds, open
i
the normal feeder breaker to the bus and verify that the diesel started.
3
The licensee determined that they did not have a technical specification-
l
compliance issue.
The licensee based this on the definition of a channel
in IEEE 279-1971 that states, "a channel: loses its identity where single
action signals are combined." The licensee defines the channel as ending.
,
basically where the sensor and the internal time delay ends.
The licensee wrote Justification for Continued Operation'(JC0) 90-05,
!
Revision 0, on February 16, 1990.
In this JCO, the licensee concluded
.;
that the requirements of T.S. 3/4.8.3.1 were met.
The licensee concluded
j
-
they were testing and calibrating the channel per the technical
j
specifications.
j
The technical specification states that the trip setpoint for the
degraded voltage relays is 3850 volts with a 55 second time delay, with
'!
.
an allowable value of 3850 + 80 volts with a 55 + five second delay.
The
i
55 second delay consists of a four second relay and a 51 second agastat
i
relay.
The four second relay is recalibrated every refueling and the 51
second relay is recalibrated every three years.
The licensee states that
the 51 second time delay relay is in the logic part of the circuit and
the technical specification does not apply to this relay.
The licensee
i
concluded that the three year calibration confirms-the relay timing.
!
,
-
,n.
16
-
.
.
.
Unplanned Control Room Isolation.
On March 19, 1990, an inadvertent' Control Room idolation-occurred while
Instrumentation and Control (I&C) technicians were performing PICT 25-1,
"502 Detectors". -The I&C technicians received permission frcm the
control room to proceed with the PICT, including-informing the control
operator that an isolation signal would be received.
When they reached-
the sensor, they noticed that light was burned out for the 502 power
indication switch = Pushing the switch turns the detector off and on, and-
the light on and off (MR 90-2794).
The I&C technician checked the-
attached maintenance tag, and it said the light was burned out.
The.
technician pulled the cap off, an accompanying operator replaced,the
+
bulb, and t u I&C technician-restored the cap.
In restoring the cap,-the-
!
-
I&C technician de-energized the detector, causing a control-room
'{
ventilation isolation. -The control room was notified of the unexpected
ESF actuation.
l
The I&C technician informed the ins 3ector_ that he believed he was- acting.
within the guidance of Maintenance Procedures (MP) 3-8-to change the .
_
l
light bulb.- The I&C' technicians were then trying to locate-MR 90-2794 to-
!
close it out (10:00 am) but had'not found it yet.
The inspector:went to
the MR coordinator and found the MR within five minutes.
The MR provided
no further precautions for changing out this bulb.
The I&C technicians
had not found the MR at the time of the critique of this event (three.
,
hours later).
The licensee determined this event was: reportable under-10
-
CFR 50.72 unplanned ESF actuations.
The residents will perform.further
.
followup as part of LER review.
No violations or deviations were identified.
!
)
7.
Follow-up of Licensee Event Reports (92700)
LER 89-07, Revision 2, (Closed), "Contral Room Isolation Damper
I
Closure Time Exceeds Required Maximum."' This revised-LER corrected a
!
misstatement as to a procedure that was stated to have been changed:but
i
had not been changed.
To prevent future inctances of misreporting, the
!
licensee is now requiring documentation to verify-completion of committed
-]
action. The inspector verified that surveillance procedure PET 10-4,
" Test of Control-Room Isolation for Toxic Gas and Radiation," was revised
on March 9, 1990 to incorporate the committed changes.
LER 89-29, Revision 2, (0 pen), " Fire Dampers, Penetrations and
Sprinkler / Deluge Surveillances Not Performed Within Required Time
Frames Due to Cognitive Personnel Errors." This revised LER provided the
detailed description, causes and corrective actions for the event.
The
licensee concluded the cause of missing the subject surveillances was due
<
to cognitive personnel error that resulted from a lack of administrative
controls and monitoring to ensure surveillances were properly scheduled,
i
performed and documented.
Specifically, surveillance data entry errors
,
were made such that partially. completed surveillances'were recorded as
'
being totally completed.
The licensee recognized that fire protection
engineers did not have an acceptable level of knowledge on surveillance
periodicity requirements and that this was a repeat event (LER 88-35).
The licensee noted that the surveillance data entry errors reported in
N .
o
17-
L.
.
.
this LER occurred before coicective actions for LER 88-35 Revision 2,
had been fully implemented.
The date:of the event for LER 88-35 was
October 10, 1988.
The corrective action to train personnel making data
entries was August 22, 1989.
Therefore, while the event was identified
on November 15, 1989, the data entry errors occurred on or before January
19, 1989.
Licensee corrective actions for LER 89-29, Revision 2 included the
-i
following:
immediateestablishmentofcompensatoryfirewatches, testing
of Ruskin fire dampers with actual flow conditions, and establishment of
two task forces that evaluate aspects of the Trojan Surveillance Program.
The licensee concluded this event did not cause a significant degradation
of operational safety.
The inspector verified that compensatory fire watches were surveilling
the affected plant areas.
The inspector also reviewed the test data
- l
obtained during the: testing of the Ruskin dampers.
The' test data review
!
identified that the licensee intended not to perform full flow testing'on'
l
some of the Ruskin curtain fire dampers.
The licensee instead concluded-
!
that these dampers don't require periodic testing because the dampers
were initially tested under flow conditions by.the manufacturer.
The
.
licensee had not performed a safety evaluation to support.this position.-
j
Additionally, the licensee is locating the original vendor testing data
j
for the inspectors review.
Since there had been documented industry concerns associated with the
operation of Ruskin Dampers, licensee actions in response to these.
concerns were insaected.- On' November 6, 1984, Ruskin transmitted a 10
1
CFR 21 report to iRC regarding curtain-type fire dampers failing to close
during duct air flow tests.. The inspector reviewed the licensee
i
operational assessment review (OAR) files to evaluate PGE's disposition
i
of the concern.
No record was identified to indicate:the 10 CFR 21
report was reviewed in the OAR program.
In reviewing lant procedures,
the inspector found that in 1986, procedure MP-12-13,' p' Penetration Fire
Barrier Inspection for Protecting Safety-Related Areas,! Revision 9,-
referenced the 1984 Ruskin-10 CFR 21.
Additionally, the procedures did-
,
'
require fire damper testing under full flow conditions,:however, because
the inspection ports for some of the dampers were on the supply side of
4
the dampers, full flow testing could not be performed.
Licensee
'!
management was slow to address the concern and a 1989 QA audit raised
this as an issue.
,
'
This LER will. remain open for further review of licensee testing records,.
i
safety-evaluations and 0AR records associated with Ruskin fire dampers.-
LER 89-30, Revision 1, (Closed), " Chlorine Detector Response Time-
Greater Than Used in Toxic Gas Analysis Due to Not Specifying a
Response Time in the Design Specification for the Detector." This
revised LER orovided additional information with respect to the -
description, causes and corrective actions for the event.
The' licensee,
on Decem'ar 12, 1989, while conducting.a design review of an improvement
for the Control Room Emergency Ventilation System, determined the
chlorine detectors that isolate the control room ventilation systems on
high chlorine concentration had a response time that. exceeded the
q
l
l
_
%.,A.,.,,..,,,
\\:
.(
j
.'
18
,
.
'
designed required time.
ThelicenseecompliedwiththeTrojanTechnical
Specifications by-securing the normal control room ventilation system and
establishing emergency control room ventilation.
Additionally, on
December 28, 1989, the licensee obtained a temporary technical
specification amendment that-allowed ventilation of the control room for
up to one hour until the chlorine detectors were replaced.
On March'14,
1990, chlorine detectors that met the time response requirements were.
installed and tested to verify compliance with design requirements.
The licensee concluded the.cause of the event was inadequate design
,
specification for the chlorine detectors. The original purchase order
-did not specify a required response time. -Additionally, subsequent to
the installation response time, testing was-not required.
As corrective
action, the. licensee replaced the chlorine detector.
Inspection associated with this event was previouslyl documented in NRC
' inspection reports 50-344/89-33 and 50-344/90-02.
Additionally, the-
-
inspectors, during this inspection period, observed selected portions of
the installation and testing of.the-new chlorine detectors.
The
inspector also discussed the thoroughness of the corrective actions with-
the licensee.
Because the licensee determined the primary-cause of the
event was an inadequate design specification, the inspector was concerned
that additional instrumentation with required response times may have'
been procured with inadequate design specifications, e.g.', S02 detectors.
1
The licensee committed, at the March 23, 1990 weekly exit meeting..to
'
randomly sample safety instruments, that require specific response times,
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design specification adequacy.
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LER 90-02, Revision 0,-(Closed), " Low Temperature Overpressure _
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Protection System (LTOPS) Evaluation Limits Violated During Plant
,
Operation Due to Procedural Inadequacies." This licensee event report
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described the potential to overpressurize the: reactor coolant'systein
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(RCS) when at low temperature and pressure, due to not disabling a
sufficient number of Emergency Core Cooling System pumps when less that
200 degrees F.
On January 9, 1990, the licensee determined operating
procedures that control plant heatup (G01-12) and plant cooldown (G0I-4)
did not require disabling one of the two centrifugal charging pumps
(CCPs) immediately prior to reducing RCS temperature to less than 200
degrees F.
Therefore, the potential would have existed to overpressurize
the RCS when t,oth CCPs were operable.
.
The licensee concluded the cause of the event was procedural inadequacy'
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due to the failure to implement the LTOPS analysis in operating
procedures.
As corrective action, the licensee changed plant procedures
to require disabling of one CCP at 220 degrees F.
"
The inspector reviewed the LTOP analysis, the Final Safety Analysis
Report (FSAR), the Trojan Technical Specifications and'the licensee's
operating procedures associated with RCS pressure protection at low
temperature.
The inspector found .that on March 13, 1990, the licensee
had revised plant operating procedures, G01-4, " Plant Cooldown-Hotstandby
Through Cold Shutdown," Revision 28; however, the plant operating
procedures such as G01-12, " Reactor Coolant System Reduced Inventory and
Recovery From Refueling," had not been changed.
Additionally, in
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reviewing the FSAR and the Technical. Specification (T.S.)-Basis, the
inspector noted that the Basis did not include the restriction or an
explanation of the description.
The licensee, at the March 23, 1990
weekly NRC exit, committed to amend the Basis.
The-inspector also
discussedthesubjectofLTOPwithtwoShiftSupervisors.
The Shift
Supervisors were aware that G01-4 had been changed to~ require a CCP be
disabled, but they were not knowledgeable'as to the reason for the-
change.
The inspector's review of operator training found no formal
training had been conducted.
The licensee committed to provide a-
training session for the operators on LTOP.
1
LER 90-03, Revision 0, (Closed), " Procedural Inadequacy Caused Both-
{
Centrifugal Charging Pumas (CCPs) to be Inoperable During Mode 4 Due
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to Closure of Nonactive iotor 0?erated Vaives.".On January 19, 1990,
during a design basis review, tie licensee determined-a surveillance -
test,, POT 25-2c, " Safeguards Test Panel Actuating Tests," Revision 9,
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that was conducted to. evaluate the. operability of a protection' system
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relay rendered both CCPs inoperable when Trojan Technical-Specifications
required one:or both CCPs to be OPERABLE.
The licensee determined the
4
cause of the event was a failure to place the Boron Injection Tank; inlet
a
suction valves, M0-8803A and B, under adequate administrative and
procedural controls to prevent their use as active components following a
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design change.
As immediate corrective action, the licensee changed the
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procedure to perform the test in compliance with. technical
specifications.
The licensee committed to provide a supplemental LER
when their investigation of this event is complete.
The inspectors reviswed the LER and-POT 25-2c after the procedure was
changed to verify that the change corrected the testing deficiency.-
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LER 90-04, Revision 0, (Closed), " Personnel Error caused Both Trains '
of Control Room Ventilation to be Inoperable." -On January 24, 1990,-with
the facility in Mode 1, Technical Specification 3.0.3 was entered for
approximately one minute because neither train of control room emergency-
4
ventilation was OPERABLE per T.S. 3.7.6.1.
Licensee investigation.
1
identified that the B train of control room emergency ventilation was out
of service due to conducting surveillance testing, and the A train of
control room emergency ventilation was out of service due to inadvertent
removal from service when a licensed operator repositioned the wrong (A
vice B) emergency diesel generator shutdown control switch while hanging
a clearance.
The licensee concluded the cause of the event was personnel
error with human factors related contributing causes.
Corrective actions
1
included immediate restoration of the A'EDG to service, an HPES'
evaluation of the event, relabeling of the electrical distribution
control pr.1 (C-11), procedure changes and a long term action to review
the fac': ty's labeling policy.
The inspectors attended the critique conducted for the. event, examined
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the C-11 control panel and verified 01-5-1, " Diesel Generators and Fuel"
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had been revised.
The inspector acknowledged that the human factor
engineering of C-11 could be improved; however, did not find that this
was a significant contributing cause to the event because all the control
switches for the B EDG are located on one side of C-11 and s11 the
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control switches for the A EDG are located on the other side
approximately six' feet away.
8.
Followup on Open Items, Corrective Actions for' Violations and
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Unresolved Items (92701, 92702)
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Open Item 50-344/89-17-07, (0 pen), " Improvements To Plant
Modifications Department Training." Quality Hotline item 89-04,
!
expressed an employee concern over the quality of training in the Plant
Modification. Department.
Specifically, the employee was concerned that
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new employees were'not properly indoctrinated to the facility, trained on
their work assignment and counselled on work expectations.
.
The Performance Monitoring / Event Analysis:(PM/EA)' organization evaluated
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the employee concern and substantiated that training improvements were
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needed in the Plant Modification training program.
The Plant
Modification supervisor committed to implement. improvements; however, the
improvements were not specified.- The PM/EA review had no recommendation
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other than recognizing the need for Plant Modification training program
improvements.
In response to the concerns, the Manager of Plant Modifications
implemented the-following Plant Modification' training program
improvements:
PMT-1, " Plant Modification Department Training,"-Revision-
5, was revised to include requirements for employee self-study of.the
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Plant Modification Conduct Manual, Lower Tier Department Procedures:and
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FSAR figures 1.2-1 through 1.2-21 (plant layout drawings), and enrollment
of coordinators in the Technical Staff training program.
Additionally,-
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the majority of Plant Modification Coordinators have voluntarily
participated in craft discipline training.
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The inspector noted that no specific improvements were identified and no
tracking of commitments occurred.
Additionally, there appeared to.be no-
formal mechanism for tracking corrective actions on~QHL issues. Nuclear.
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Division Procedure (NDP) 6004 , " Excellence Response' Program," was
revised (section 5.3.c) to require identification and tracking of
corrective actions to address the deficiency.
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The inspector-reviewed the revised Plant Modification training. program
and had the following observations.
The training provided to Plant
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Modifications personnel consists of self-study.of selected Plant-
Administrative Orders, Maintenance Procedures, Nuclear Department
Precedures, Plant Modification Procedures, Plant Safety Procedures and
Quality Inspection Procedures.- The trainee is not provided with a set of
learning objectives for the review of the procedures nor is an assessment-
-t
made of what he learned from the self-study.
The inspector's review of~
the Plant Modification personnel training records indicated that the
self-study was generally completed over the period of'one to two weeks
and received very limited review by supervision.
The quality'of the
documentation was not consistent.
The training program did not include
periodic retraining on the procedures nor is there a mechanism to update
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the worker on changes (revisions) to the procedures.
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By not defining and tracking specific corrective actions to correct
programmatic deficiencies, the improvements implemented by Plant.
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Modifications appear not to have corrected the employee's concern. The
licensee has committed to re-evaluate this concern. This item will-
remain open following evaluation of the licensee's review.-
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Open Item 50-344/89-17-03 (Closed), "As-Building of Design Change
Packages Completed by the Plant Modification Department." . Revision 0 to -
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Plant Modificatior procedure PMT-4, which is in the review and approval
process, requires the as-building of a modification within 10 working
days of completing the modification. The inspector also noted that the
as-building backlog had been reduced from 59 on December 26, 1988 to 15
1
on March 18, 1990.
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9.
Followup of 10 CFR 21 Reports (92701)
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89-07-P, (Closed), " Automatic Switch Company (ASCO) Valve Solenoid
Return Spring May Disengage." The licensee was notified via letter dated
January 30, 1989, that.PGE had purchased one ASCO rebuild kit that, if
,
installed, could result in the solenoid return spring (core spring) on!
certain ASCO Series NP valves disengaging from the solenoid core.
Disengagement of the solenoid spring could result in; leakage of the valve
or failure of the valve to shift when de-energized. ^ Licensee
.;
investigation found'that the rebuild kit had been used on a shop spare -
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ASCO solenoid valve. The rebuild of the solenoid valve did not refurbish
the solenoid return spring. .The repair that used the rebuild kit .
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replaced the takeup spring. An April- 7,1989-telephone conversation
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between the licensee and ASCO resulted in the licensee concluding the use
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of the rebuild kit to replace the takeup spring-would not adversely
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affect valve operation.-
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89-08-P, (Closed), "K-Line Circuit Breakers (K-225 through K-2000)
Rebound Spring on Slow Close Lever Missing." On January 13, 1989 the
licensee was notified that K-line circuit-breakers PGE had purchased
!
prior to July 1974 did not have rebound springs on'the slow close lever
'
and, therefore, may not function as designed duringsa seismic event. .The
licensee implemented a program to inspect all K-line circuit breakers
,
prior to the 1989 Refueling Outage. Upon verifying that the subject
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installed plant circuit breakers did not have rebound springs on the' slow
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close lever, the licensee performed.a safety evaluation, documented in a
Justification for Continued Operation, that supported continued use-of
the circuit breakers until the rebound springs could be: installed. The
licensee ordered the rebound springs and, during the 1989 Refueling
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Outage, installed the springs on all the deficie'it safety related circuit
,
breakers. The rebound springs for the deficient nonsafety breakers are
scheduled to be installed during the 1990 Refueling Outage,
a
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89-23-P, (Closed), " Bunker-Ramo Corporation Containment Electrical
Penetration Assemblies." On April 26, 1989, the licensee identified that
small gauge wire (AWG 14 and 16) pulled out of the penetration with
little or no force. The licensee concluded that the small gauge wires
had not been acceptably crimped in the module. The licensee filed this
10 CFR 21' report. Licensee corrective actions were documented in NRC
Inspection Reports 50-344/89-10 and 50-344/89-17.
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89-25-P, (Closed), "Limitorque-Potential Common Failure of SMB-000!
and SMB-00 Cam-Type Torque Switches."
The licensee was notified via a
vendor letter dated September- 29, 1989, of a potential defect in SMB-00
and SMB-000 torque switches.
Specifically, the potential defect results
from stationary contact screws loosening on the side of the torque switch
i
that had a fiber spacer.
The vendor' recommended these types of torque
switches be replaced during the next available maintenance period. -The-
licensee, via OAR 89-78, is evaluating this concern.
To date, the
licensee has identified 42 safety related SMB-000 and SMB-00 actuators
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that are likely to have torque switches that use fiber spacers.
Nonconformance. Report (NCR)89-517 was generated that documented the need
to inspect the likely 42 actuators. LMaintenance Requests have been;
wri' ten to inspect the actuators during:the 1990 Refueling Outage.-.The:
inspectors reviewed 0AR 89-78 and verified NCR 89-517-acceptably
addressed the 10 CFR 21 concern.
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89-26-P, (Closed), "Foxboro Transmitters / Amplifiers (N-Ell and N-E13)
Workmanship deficiencies." -The licensee was notified via letter dated-
October 6, 1990, of a potential workmanship deficiency in-10-50 milliamp
Foxboro Transmitters / Amplifiers (models N-Ell and N-E13).
The deficiencies consisted of incorrect ssidering~of component ~1eads,
potential grounding or arcing of connections and possible~ omission'of a
{
jumper.
The vendor indicated PGE may have purchased seven of the-
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potentially defective components.
The licensee, via OAR 89-76,
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determined the seven procured transmitters were 4-20 milliamp vice 10-50
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milliamp models.
The vendor specifically-noted'4-20 milliamp
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transmitters were not affected.
The inspector verified'that licensee
procurements from the Foxboro Company did not include purchase of 10-50
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ma amplifiers.
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89-27-P, (Closed), "Morrison-Knudsen ' Company, EMD 645#4 Tandem-Diesel
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Generators Air Start Control System Defect." On October 15, 1989, the
[
licensee was provided with Morrison-Knudsen Corporation 10 CFR 21 report
89-4 that described the potential to defeat the redundancy of the-
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emergency diesel air start system.
Specifically, the recycle feature on-
the air start solenoids would continuously recycle due to the starting
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air system air supply tank configuration and. electrical contact
arrangement of a time delay-feature.
The licensee, via:0AR'89-74,
compared the Trojan air start system to the: subject 10.CFR 21 report.
The licensee ~ identified two major differences: _ Trojan.has a single ^ air
storage system for each emergendy diesel generator vice an. air supply
system for each engine, and at Trojan, the wiring of the recycle pressure
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switches is in series for all four pressure switches vice in two parallel
.
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sets.
Based on these differences, the licensee concluded this 10 CFR 21
was not applicable to the Trojan emergency diesel generator air start-
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system.
The licensee generated a commitment tracking list (CTL) item to
evaluate alternative electrical contact recycle schemes that would
improve the reliability of their engines.
The inspector verified the as
built diesel air tank arrangement and reviewed the electrical wiring
diagram for air start contact arrangement.
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10.
Engineering Program Review (37702, 40702, 92720)
Commitment Control System
The inspector reviewed the licensee's commitment control. system and found
that the system contained 1,010 itens of which 409 were overdue. The
inspector subsequently concluded, following discussion with the.
licensee's staff, that-the licensee did not have a system in place for
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prioritizing items on the commitment tracking list (CTL) and that,
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apparently, responsible line managers did not pay appropriate attention
to notifications of delinquency that are provided monthly. The inspector
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also found that the licensee's CTL: dNr not contain all corrective action -
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commitments of the line organizations; some are contained elsewhere, such-
as the Corrective Action Report list. The inspector concluded that the
licensee needs to pay more attention-to the management of internal
commitments and corrective actions.
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The licensee had recently recognized this situation and has initiated
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action to consolidate cumitment and corrective action lists, prioritize
items on the CTL, requi<e line managors to prioritize their work
assignments, and schedule with manpower loading the work assignment
completion.
Engineering Improvement Initiative
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The licensee has developed a set of seven major objectives ~to achieve
engineering excellence and assigned responsibilities and due dates for
each. The licensee has assigned a system design engineer'to each system
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and has instituted action to im
Nuclear Plant Engineering (NPE) prove communications and-teamwork between
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, system engineering,.and quality
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assurance. Actions are underway to decrease.the. number of technical-
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errors to a minimum and improve engineering analytical skills and tools.
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The licensee has established a prioritization system to prioritize the
engineering design workload. The licensee'has about 150 open requests
for Design Change but has not translated this into man-hour backlog.
)
Engineering has, hwever, established a manpower loaded schedule for
'
engineering design work in this calendar year.
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The licensee has established-a detailed and extensive Action Plan (AP
89-053) for Nuclear Division Improvement, complete with responsibility
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assignments, due dates, and status coninentary. The Engineering ~
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Improvement Plan is a subset of the Nuclear Division Plan. The licensee.
appears to be making progress in all major areas identified for
4
improvement.
The NPE organization has established a goal of reducing design error
'
Field Change Notices from 16% to 12% this calendar year. The licensee
anticipates that implementation of Design Change package walkdowns, prior
to issuance for construction, will result in-a reduction of FCNs
attributable to construction errors and unanticipated conditions such as.
plant system operation status, construction schedule changes and work
coordination.
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The. licensee has established a good start on improving engineering work
but needs to continue to focus attention on improving on the individual
task schedules.
Quality Assurance
The inspector reviewed audits _of NPE and Fire Protection and observed
that these audits were substantial and resulted in good findings.
However, the inspector identified th'at QA'and' NPE' missed' opportunities to
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identify poor safety evaluations.
For example;-the. audit of NPE pointed
out that a Maintenance Request (MR) can be a Design' Change. - QA
identified that the safety evaluation of the fuse replacement Job was
poor and Engineering missed an opportunity to _ identify a significant
oversight. The problem here appears to involve the fact that safety
evaluations may be performed by organizations.other than NPE and'it-is
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not apparent that NPE has provided these other. organizations-with.
sufficiently clear guidance regarding the criteria under which NPE must.
be involved in conducting the safety evaluation. Another safety
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evaluation that was not well done involved assessing the safety-
. implications.of industry identified problems with Ruskin Fire-dampers.
For emple, the failure of the damper presents the potential for a
common mode failure; a question which the licensee' answered negatively.
This was missed by both QA and NPE.
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- The following potential improvements were identified to licensee managment
for their consideration:
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Design engineering could provide a more comprehensive overview of
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maintenance and provide maintenance with a clear set of guidelines and
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instructions within which the Maintenance department can conduct
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independent safety evaluations and to refer the MR to engineering'if.
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there is any question regarding the existence of a' potential design
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change.
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-The schedule for revising the safety. evaluation procedure, currently
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scheduled for about the third quarter, could be moved up.
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Design engineering, as the design experts, could have a greater role in
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safety evaluation process to assure a consistently high level of quality.
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Design Basis Document Initiative
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The licensee is well underway to-establishing a complete set of system-
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design basis documents. The current status / schedule is:
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Total Planned
about 70
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Issued to date
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In final approved cycle
7
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Scheduled for 1990
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Scheduled for 1991
8
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Scheduled for 1992
9
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Scheduled for 1993
9
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Scheduled for 1994
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The licensee has established administrative controls governing the
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generation of Design Basis Documents (NDP-200-6) and a process for System
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Design Basis Validation, detailed by procedure No. . NDP-200-9. . This
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procedure provides for physical walkdowns of the systems using
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pre-established checklists; and review of-system design basis documents,
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FSAR, system descriptions, technical manuals, drawings, and
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maintenance / operating and test procedures to validate the installed plant
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configuration against the documented design basis.
The walkdowns are
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performed-by.a-team consisting of the responsible design engineer,o the_
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system engineer, and-a QA engineer.
Deficiencies /open items are-
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identified, prioritized, assigned responsibility and due dates, and
tracked to completion,
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The licensee has implemented a system to review calculations to verify
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Design Basis implementation.
The reviews are being conducted by;
contractors.
The licensee has found that about 25% of the calculations
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have. gaps; for example, assumptions may not be-fully identified or do not'
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support the design basis, the. calculation logic process may not be valid,.
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or mathematical errors exist. -Deficiencies in calculation
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methodology / accuracy are identified, prioritized, assigned correction'
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responsib'lity and due dates, and tracked to completion.-
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System Engineerina Initiative
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The inspector reviewed the following administrative control documents _
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governing the System Engineering training program.
TAP-603:
Technical' Staff / Technical. Manager Training Program
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PSEP-10-2:
Nuclear Plant Engineer Training Program
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PSEP-10-6:
System Engineer Checkouts
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The inspector found that these documents prescribe a comprehensive
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training program, consisting of self-study,Lformal classroom training,.
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and written and oral examinations.
The program is designed to assure
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that system engineers attain a base level of' knowledge on-their. assigned
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systems.
In addition, the program describes theLinformation which should
be contained or referenced in the system files' maintained by the system
engineer.
The inspector discussed the progress of the system engineer program with-
program management representatives. .The licensee has plans for the
following initiatives to improve system engineer performance:
a.
In the area of staffing, the licensee plans a small increase in the
,
staff size converting contractor staff to PGE staff and is
considering adding-five technicians to relieve the system engineers
of administrative, non-engineering tasks,
b.
The licensee has embarked upon a program to send two system
engineers per year through a training program equivalent to SR0
certification.
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c.
The licensee has initiated measures to improve communications
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between the. System Engineering and: Corporate (NPE) Engineering staff
and has noted improvements in this area in the past 8-10 weeks.
d.
The licensee.has recently' accomplished a comprehensive listing and-
prioritization of work tasks for each individual system engineer to
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assure that the important issues.are receiving attention,
e.
A:new salary scale for Electrical Engineers has improved retention :
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and reduced Electrical Engineer turnover, a problem observed in the-
past.
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The inspector noted that the licensee recognizes several, problems and-is
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evaluating actions to deal with~ those problems.
The problem areas are:
a.
There is a- high backlog of work remaining with each engineer.. The
inspector noted that each engineer has'a high workload of system-
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assignments.
The licensee-recognizes that this-situation may be
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alleviated partially by increasing the system engineer staff and-
relieving tie engineers of administrative tasks; however, lack of.--
the-
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licensee recognizes that a contributing cause may be the
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clear definition of responsibilities supportive by a valid job-task
analysis.
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b.
The licensee recognized that.the level of cooperation and
communication between the system engineers-and the maintenance
engineers needs improvement to. assure-that system engineers maintain
awareness of maintenance activities, system / component problems, and
trends.
c.
The total. turnover rate for the past year is high, approaching 30%.
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The licensee has recognized this problem and initiated action-to
deal with it.
As a result, during:the past six months only one
system engineer has been lost.
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d.
The licensee recognizes that the trending program is in need of
management attention.
This has been pointed out'before, but'the
licensee has not dealt with this~ issue very effectively. .The
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trending program is fragmented between system engineering and
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maintenance department with little overall management direction and
review.
e.
The licensee does not have a clear set of' criteria to be used for
prioritizing system engineer work activities.
The licensee was embarked upon activities designed to:
(1)'cl'early
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define system engineer responsibilities and functions; (2) clearly define
a criteria set for prioritizing system engineer work activities; (3)
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improve the management and data review functions of the trending program;
and (4) institutionalize actions / activities to promote increased
communication and cooperation between system engineering, maintenance
engineering and Nuclear Plant Engineering.
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Events Evaluation Proram-Initiative-
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The inspector discussed the licensees Events Evaluation and Human
Performance Evaluation programs with responsible licensee personnel and.
reviewed the following documents:
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Human Performande Evaluation
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Procedure'NDP 600-8, dated 1/16/90
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Syster[ (HPES)
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Procedure PMEAP 103, dated 11/18/88
- PM/EA Department New
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Employee Indoctrination,
Orientation, and Training
NDP No. 600-3, dated 2/23/90
- Event Reports.
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Human Performance Evaluation System Program Status and Trend Report,
dated 2/8/90
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Event Evaluation Reports No.89-252, regarding I&C calibration problems,
and 89-254,1 regarding Service Water Check Valve problems.
Action Plans Nos.89-061 (Surveillance Improvement Program),89-007
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(Instrument Uncertainties in Technical Specification Values), and 89-056
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(Resolution of Instrument Calibration Procedure Deficiencies)/
The program procedures establish the licensee's administ'rati e controls
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governing the HPES system, Events Evaluation-Program,-and personnel
training programs, and are generally comprehensive and acceptable.
The
procedures assign appropriate responsibilities for the administration of
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the programs.
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The inspector examined d e licensee's HPES program progress'.
The program.
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is in the formative stages and the licensee has completed 12 HPES.d
evaluations to date.
These evaluations have evolved in format an
completeness and currently represent a quality product.
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The licensee's event evaluations are performed by personnel in the
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responsible line organizations and reviewed.by the PM/EA staff for
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technical and quality substance.
Assignment.of the person responsible to
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perform the evaluation is the responsibility of the line organization
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management.
PM/EA during their evaluation, makes no assessment of the
line organization evaluator's training and qualification to perform' event
evaluations.
This'is a potential gap in the PM/EA evaluation program and
worthy of licensee consideration.
During a review of the Event Evaluation Report No.89-262, the inspector
observed that the licensee's specification of the primary cause did not.
address.the situation which allowed the failure to occur, and was, thus,
incomplete.
Further, the inspector observed.that none of the corrective
action statements addressed the licensee's specified primary failure;
The rest of the ' licensee's corrective action statements appropriately
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addressed the contributory causes.
However, when each corrective action
plan was evaluated in detail it became soparent that Action Plan 89-007
did not accomplish the specified correct.ive action of " Review and
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generate a cross reference document ofiequipment and components
associated with each TTS surveillance requirement." Further, the
specified corrective action did not include'the additional necessary step
of reviewing surveillance procedures to-assure that.the-necessary-
equipment and components so identified were tested'by the procedure.
It was apparent to the inspector that the licensee needs to pay
additional attention to assure a complete specification.of corrective
actions which address all-causative factors and= pay more. attention'to
assure that the substance of action plans accomplish the intended
corrective action.
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11.
Review of Licensee Plans for Coping with Strikes-(92709)-
The inspectors reviewed the licensee's Strike Contingency Action Plan of-
February 21, 1990 to ensure the minimum number of qualified and
proficient personnel were available for proper plant operation and
safety, plant security would be maintained at levels' consistent with
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security plan requirements,- and the ' Strike Contingency Action Plan-was
consistent with regulatory requirements,
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The proposed strike would have ' impacted maintenance crafts '(mechanical,
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electrical, and instrumentation and control), licensed reactor operators
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and auxiliary operators, chemists and radiation protection technicians,
and Plant Modification craftsmen.
Had the strike occurred.. it would have
been the first strike since commercial operation:of Trojan.
The
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inspectors found that the licensee had: identified nonunion'PGE employees
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to meet the technical specification-requirements for licensed and
non-licensed operator staffing.
Substantial training of'a number of the
ensure proficiency. g non-licensed operators would have been required to
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individuals replacin
For example, several of the personnel designated as
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replacement auxiliary operators had at one time been qualified but either
stood a-very limited number of watches and had not retained their
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proficiency or not stood auxiliary operator watches for threeLyears or
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more.
The licensee had established an accelerated program to train the
personnel to assure an acceptable knowledge.n:The inspe: tors attended
accelerated training associated with fire-brigade. training.
The training
appeared to be thorough and well presented.
Some of those personnel who
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were to have been replacement fire brigade members had not had'recent
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hands-on experience at controlling and combating small scale fires nor-
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maintained proficiency as fire brigade members.
The identified'
replacement licensed operators had maintained proficiency throughout the.
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past three or more years.
The licensee uses the Rainier-Fire Department
to augment permanent staff in the event of a large scale fire.
The
Rainier Fire Department had been notified of an impending strike.
With respect to maintenance craftsmen, chemists and radiation protection
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technicians, the licensee lacked personnel who were not in the bargaining
unit and had previous experience in their respective area.
Therefore,
the licensee would have had to contract nonunion skilled personnel and
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limit work to high priority tasks.
The contracting of these personnel
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was in the initial stages during the inspection.
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The licensee was -in the process of notifying principal off-site support
agencies of the potential for a strike and supporting actions that may be-
required.
No deviations or violations were identified.
12.
Unresolved Item
An unresolved item is a matter about which more information is required
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to ascertain whether it is an acceptable item a deviation, or a
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violation.
AnunresolveditemisdocumentedInparagraph6.
13.
Exit Interview (30703)
The inspectors met'with the licensee representatives denoted in paragraph
1 on April 2, 1990, and with licensee. management'throughout the
inspection period.
In these meetings the inspectors summarized the scope
and findings of the inspection activities-.
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