ML20126B411
| ML20126B411 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 12/11/1992 |
| From: | Phillips M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20126B311 | List: |
| References | |
| 50-341-92-17, NUDOCS 9212220080 | |
| Download: ML20126B411 (16) | |
See also: IR 05000341/1992017
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No. 50-341/92017(DRP)
Docket No. 50-341
License No. NPF-43
Licensee:
Detroit Edison Company
2000 Second Avenue
Detroit, MI 48226
Facility Name:
Fermi 2
Inspection At:
Fermi Site, Newport, Michigan
Inspection Conducted: October 14, 1992 through December 8, 1992
Inspectors:
W. J. Kropp
K. Riemer
R. Twigg
S. Stasek
T. Colburn
R. Stransky
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Approved By:
'M.
P. Phillips, Chief
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Reactor Projects Section 2B
Date~
Inspection Summary
inspection from October 14. 1992 mthrough December 8. 1992
(Recort No. 50-341/92017 (DRP))
Areas Insoected: Routine, unannounced safety inspection by the resident
inspectors of action on previous inspection findings and a concern;
operational safety verification; engineered safety feature systems; onsite
event followup; reactor startup; current material condition; housekeeping and
plant cleanliness; radiological control::; security; safety assessment / quality
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verification; maintenance activities; surveillance activities; and performance
evaluation activities.
Results: Of the thirteen areas inspected, no violations were identified in
twelve areas, and one violation was identified in one area pertaining to
overtime (paragraph 3.a).
Two Unresolved Items were identified that pertained
to: the failure of notifying the NRC of an Unusual Event within the specified
time frame (paragraph 3.c), and the process of reviewing Service Information
Letters (Sils) (paragraph 4).
In addition, three Inspection Followup Items
were identified that pertain to the use of computer analysis for simulator
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taodeling (paragraph -3.c); the contrcl of fire doors (paragraph 3.d); and use
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of procedures (paragraph 5.a).
The licensee's performance in operations was
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considered good. The operator's initial response to the loss of feedwater
transient was considered excellent. However, subsequent notification to the
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9212220080 921211
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NRC of the event was-not timely.
Shift briefings were thorough which allowed-
on shift personnel to be cognizant of' plant conditions. Operator's response
to annunciator alarms were good, however,-repeat backs pertaining to equipment
manipulations were not consistently implemented.
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DETAILS
1.
Persons Contacted
Detroit JJ11 son C_ompaDI
C. Cassise, General Supervisor, Mechanical Maintenance
- W. Colonnello, Supervisor Plant Evaluation, Plant Safety
J. Contoni, Supervisor, Plant Systems
- R. DeLong, Manager, Radiation Protection
R. Eberhardt, Superintendent, Radiation Protection
P. Fessler, Director, Nuclear Training
- D. Gipson, Vice President, Nuclear Operations
- L. Goodman, Director, Quality Assurance
- E. Hare, Senior Compliance Engineer, Nuclear Licensing
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J. Hughes, General Supervisor, Electrical Maintenance
J. Korte, Director, Nuclear Security
- A. Kowalczuk, Superintendent, Maintenance and Modifications
- R. Matthews, Assistant Superintendent, Maintenance
- R. McKeon, Plant Manager, Nuclear Production
- W. Miller, Superintendent, Technical Engineering
- R. Newkirk, General Director, Regulatory Affairs
- W. Orser, Senior Vice President, Nuclear Operations
- D
Ockerman, General Superintendent, Training
- J. Plona, Superintendent, Operations
- R. Russell, Outage Manager
- A. Settles, Director, Licensing
- R. Stafford, General Director, Nuclear Assurance
- R. Szkotnicki, Director, Plant Safety
- J. Tibai, Supervisor, Compliance
- J. Walker, General Director, Nuclear Engineering
- Denotes those attending the exit interview conducted on
December 8, 1992.
The inspectors also had discussions with other licensee employees,
including members of the technical and engineering staffs; reactor and-
auxiliary operators; shift supervisors; electrical, mechanical,- a.id
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instrument maintenance personnel; and. security personnel.
2.
Action on Previous Insoection Findinos and a Concern'(92701)
a.
(Closed) Open Item (341/89008-15(DRP)): Due to a reactor water
cleanup (RWCU) isolation, the licensee had proposed-to relocate
the RWCU . blowdown flow control valve (FCV) G33 F033 downstream of
the flow control element G33-FE-N0ll. The licensee concluded that
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moving- the- valve-upstream of_ the flow element would decrease the-
probability of water: flashing to steam across the flow element.
The licensee had experienced:a- series of RWCU system isolation
trips due to' spurious signals from the blowdown transmitter. The
licensee had issued EDP.4885 to move the valve.
An evaluation by
the licensee concluded that moving the FCV was not necessary.
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Instead, the licensee added a caution to the RWCU operations
procedure 23.707, controlling the length of time that the two
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valves, downstream of FCV G33 F033, could remain open
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caution further stated a differential flow isolation could occur
when the instrument _ lines were not full of water. The item is
closed based on the administrative control of the two downstream
valves.
b.
(Closed) Open Item (341/90010-Ol(DRP)): Diversity requirements of
10 CFR 50.62. The licensee's design for the recirculation pump
trip and alternate rod insertion, as endorsed through the NRR SER,
was implemented acceptably with one exception. Regarding
diversity from the existing reactor protection system (RPS),'the
SER concluded that the use of the Rosemount analog
transmitter / master trip units (ATTUs) in both the ATWS'and RPS did
not meet the diversity requirements of 10 CFR 50.62.
The licensee
prepared PDC 12029. Rev 0, to replace 12 Rosemount trip units with
GE units.
In a letter to the NRC dated July 12, 1991, the
licensee committed to an implementation schedule to replace the
units. The inspector verified, via a review of licensee records,
that the work requests to replace the trip units had been
completed. This matter is considered closed,
c.
(Closed) Open item (341/90013-ll(DRP)): The use of uncontrolled
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handwritten labels attached to electrical cabinets. The licensee
recognized that during construction many uncontrolled labels were
installed on electrical cabinets to assist construction personnel
in locating specific components. As part of the corrective
actions to DER 90-0672, the licensee initiated a labeling upgrads
program for labeling plant equipment.
In addition, the licensee
issued procedure, FIP-0Pl-04, " Equipment Labeling," that
prescribed the method for generating, installing, maintaining, and
controlling plant equipment labels and signs. The licensee
recently completed the labeling upgrade system on the high
pressure coolant injection (HPCI) and residual heat removal (RHR)
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systems. The inspectors walked down part of the HPCI system'and
found that the old handwritten labels had been removed from the
HPCI electrical panels and motor control centers (MCCs).
In
addition, the inspectors noted that the new labels were consistent
with the guidance provided in procedure FIP-OPI-04 that required
labeling.be based on operator terminology. This item is closed
based on current corrective actions and the licensee's commitment
to complete the labeling upgrade program by 1994,
d.
(Closed) Open Item (341/90020-04(DRP)): Additional licensee
review for control room modifications;following operator
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inadvertent closure of a main steam isolation-valve. -The
inspectors reviewed records for additional occurrences of
inadvertent operations, the completed deviation event report, _and
the independent review. .The inspectors concluded that the
licensee's independent review appeared to be effective and
comprehensive. Additional identified human factors enhancement
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were tentatively scheduled for completion in refueling outage
RF04.
This matter is considered closed.
e.
(Closed) AMS-RIII4 ?-A-Oll2: A concern was received by Region III
regarding exceeding overtime limits without proper management
review and approval. This matter was referred to the licensee for
review and disposition by Region III letter dated October.20,
1992. The licensee respor.ded by letter dated November 23, 1992.
Even though the specific concern was not substantiated, the
subject of overtime use and approval was inspected by the resident
inspectors. This inspection resulted in a violation which is
addressed Ir iaction 3.a of this report. The followup will be
tracked tnder the violation and, therefore, this concern is
considered closed.
3.
Plant Operations
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On November 4, the licensee commenced a reactor startup following the
plant's third refueling outage. The outage, cheduled for 52 days, was
completed in 57 days. Major work completed during the outage includeo
the following items:
power uprate modifications, rea. tor vessel
inservice inspection (ISI), reactor vessel pressurc test, safety relief
valve (SRV) replacements, high pressure coolant injection (HPCI) turbine
inspections, addition of an eighth condensate filter demineralizer,
erosion / corrosion piping replacement, installation of the torus hardened
vent, and replacement of the 28 main transformer. The reactor was
placed in mode 2 at 3:30 p.m. on November 4 and criticality was achieved
at 11:57 p.m.
After the plant heatup, plant personnel commenced an
extended startup test program following a power uprate license change.
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The resident- inspector staff, augmented by NRR personnel, observed and
monitored the reactor startup and test program activities.
On November 11, 1992, during steady state operation at 98 percent power,.
the licensee experienced a manual reactor trip. The action was taken-
following a loss of feedwater to the reactor vessel when the heater feed
pumps tripped, followed-several seconds later by the tripping of both
reactor food pumps.
Following the investigation and subsequent
corrective action, the reactor was restarted and the generator
synchronized to the grid on November 11, 1992.
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On December 1, the-plant experienced a runback of the recirc pumps due-
to the loss of the Heater Drains System'. Subsequent investigation by
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the licensee determined the-cause of the event to be a leak in the
extraction steam line from the Center Low Pressure Turbine to the number
4 North Feedwater Heater. The licensee commenced a plant shutdown on
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December 4 to perform various repairs to leaking plant equipment.
Critical path during the outage will.be repairs to the extraction steam
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line to the number 4 North Feedwater Heater. Other items scheduled for
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the outage include repairs to the Moisture Separator Reheater drain line
bellows and repairs to the South Reactor Feed Pump Turbine High Pressure
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steam isolation -valve flange leak. A drywell entry was also planned to
perform work on a drywell equipment drains sump pump, investigate a
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possible low oil level on the
"B" reactor recirc pump, and troubleshoot
problems on the Loose Parts Monitor. The-licensee tentatively plans to
restart the plant December 13 and synchronize to the grid December 14.
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a.
Operational Safety Verification (71707)
The inspectors verified that the facility was being operated in
conformance with the license and regulatory requirements, and that the
licensee's management control system was effective in ensuring safe
operation of the plant.
On a sampling basis, the inspectors verified proper control room _
staffing and coordination of plant activities; verified operator
adherence with procedures and technical specifications; monitored
control room indications for abnormalities; verified that electrical
power was available; and observed the frequency of plant and control
room visits by station management. The inspectors reviewed applicable
logs and conducted discussions with control room operators throughout
the inspection period. The inspectors observed a number of control room
shift turnovers.
The turnovers were conducted in a professional manner
and included log reviews, panel walkdowns, discussions of maintenance
and surveillance activities in' progress or planned, and associated LC0
time restraints, as applicable. The inspectors considered the.
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operator's response to annunciator alarms as good. However, repeat
backs pertaining to equipment manipulations were' not consistently
implemented.
During the inspection period, the licensee informed the inspectors of an
overtime issue identified in a QA surveillance performed in. September
1992 (92-0134) and documented in DER 92-0592. The DER identified that'
administrative procedure FIP-AD4-03, " Overtime and Fitness For Duty
Guideline," had not been properly implemented during the recent
refueling outage (RF03). Specifically, on approximately 65 occasions,
noncomformance with the procedure occurred with some identified as
violations of Technical Specification when overtime limits were exceeded
without proper management approval. The September su veillance was
performed to assess the effectiveness of corrective actions taken after
a surveillance in May and April 1991 (No 91-0128) during RF02 on the
same subject and documented in DER 91-0542.
The inspectors issued a
non-cited violation (50-341/91015(DRP)) in August 1991 for the
deficiencies identified by the licensee during Surveillance 91.0128.
One additional _ surveillance (No. 91-0219) was conducted dur.ing a. forced
outage.in December 1991. .Each of the three surveillances consisted of a
sampling of the hours reportad by site personnel.- The inspectors
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identified the following common problems during each of the.
surveillances.
Failed to track seven consecutive days as a rolling seven days-
instead of a standard work week.
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DER 91-0542 noted that many groups on site were interpreting
seven consecutive days to mean the pay week,_rather than any
seven consecutive days which may have occurred over two pay
periods. The DER (No. 92-0008) resulting from the December 1991
surveillance was based on an individual's interpretation of the
seven day rule as a work week.
The inspectors noted that the
October surveillance data showed most of the violations were the
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result of hours extending across two work weeks.
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Confusion over the length of allowable shift turnover time.
DER 91-0542 stated that the amount of time allosed for shift
turnover varied from one-half hour to two hours per day.
The DER
issued during the December 1991 surveillance was closed based on
the Plant Manager's revised interpretation of FIP-AD4-03 from one
hour of allowed turnover per shift to one hour before and one hour
after the shift (Prior to RF03). The procedure was modified to
one 30 minute turnover per shift. A number of possible procedure
violations in the October 1992 surveillance were caused by site
personnel not appropriately reporting turnover time.
Failed to perform monthly reviews of overtime.
DER 91-0542 noted that there was no evidence that the plant
manager was reviewing personnel overtime at least monthly as
required by the procedure. The procedure was revised.to require
all section heads to document overtime in a monthly memo to the
plant manager to ensure excessive hours had not been worked by any
individual. This requirement was not uniformly complied with
during RF03.
Based on the above identified repetitive problems, the failure to
correct deficiencies noted in the overtime process in April 1991 is
considered a violation of 10 CFR 50, Appendix B, Criterion XVI
(341/92017-01(DRP)).
b.
Enaineered Safety Feature (ESF) System Walkdowns (71710)-
During the inspection, the inspectors selected accessible portions
of several ESF systems to verify status.
Consideration was given
to the plant mode, applicable Technical Specifications, Limiting
Conditions for 0peration requirements, and other applicable
requirements.
Through observation, the inspectors verified that the following-
was acceptable:
installation of hangers and supports;
housekeeping; freeze protection, if required, was installed and
operational; valve position and conditions; no potential ignition
sources; and major component labeling, lubrication, cooling, etc.
The inspectors also verified that instrumentation was properly
installed and functioning and that significant process parameter
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values were consistent with expected values; that instrumentation
was calibrated; that necessary support systems wve operational;
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and that locally and remotely indicated breaker and valve
positions agreed.
During the inspection, the accessible portions of the following
ESF systems were walked down:
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High Pressure Coolant Injection
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c.
Onsite Event Follow-up (93702)
On November 11, 1992, at 8:29 p.m., during steady state operations
at 98 percent power, the licensee experienced a loss of. feedwater
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to the reactor vessel when the Heater Feed Pumps tripped followed
several seconds later by tripping of both Reactor Feed Pumps.
During the transient, both High Pressure Coolant Injection (HPCI)
a7d Reactor Core Isolation Cooling (RCIC) automatically started to
restore reactor vessel water level. Upon identification that a
loss of.feedwater had occurred, operator actions were taken to
manually scram the reactor. This was accomplished just prior to
reactor water level decreasing to the low level scram setpoint and
was done within approximately 12 seconds of the loss of feedwater.
The inspectors considered the operator's response to the transient
as excellent. The operators entered the Emergency Operating
Procedures (EOPs) to recover reactor vessel water level and
declared an Unusual Event due to actuation of an engineered safety
feature (ESF). The lowest level reached was 77 -inches
(1.95 meters), approximately 120 inches (3.05 meters) below the
normal level . With level restored, the operators manually secured
HPCI and RCIC and utilized the Standby feed Water system (SBFW) to
maintain reactor vessel water level. At 9 p.m. all conditions
were stable and the licensee terminated the Unusual Event. 'The
resident-inspector responded to the event end monitored the
licensee's recovery actions.
The inspectors determined that all
- required 15 minute notifications were made within the specified
timeframe with the exception of the required one hour notification
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to the NRC which was made approximately-46 minutes after the one-
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hour limit. This is considered an Unresolved Item pending'further
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NRC review by Region III Emergency Pieparedness inspectors.
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(341/92017-02(ORP))-
All systems functioned as expected with the exception of valve-
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Gil-F019, the drywell equipment drain sump upstream isolation
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valve. The valve failed.to indicate fully closed at the control
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room panel.
Per Technical Specification requirements, the
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licensee deenergized closed another isolation valve in that line.
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Subsequent investigation revealed that the valve was actually
closed,- and the dual indication received was due to a limit switch
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problem. A work request was initiated to correct the position-
indication problem, and the work was completed prior to restarting
the plant.
The licensee subsequently determined the most probable root cause
of the transient was a personnel error by a non-licensed operator
during a backwash evolution of the "H" condensate filter
domineralizer. An inadvertent opening of a 10-inch (25.4 cm)
influent line to the demineralizer diverted flow from the heater
feed pumps causing all three pumps to trip on low suction
pressure.
This, in turn, caused the reactor feedpumps to trip on
low suction pressure, resulting in a loss of feedwater to the
reactor vessel.
The inspectors reviewed the response of the reactor and safety
systems after the scram through direct observation of control room
indications and discussions with licensee personnel.
Plant
parameters, emergency systems status, and plant effltsent levels
were verified to be within required limits during and following
the scram. The inspector reviewed operator and shift supervisors'
logbooks, sequence of events recorder (SOER) alarm printouts,
strip chart recorders, and other information relating to the
event, and verified that all systems responded per design. The
inspectors noted following the scram that the decrease in water
level to an approximately indicated 77 inches (1.95 M) was' as
predicted by the General Electric (GE) analysis and associated
power uprate submittals to the NRC.
However a Detroit Edison
RETRAN computer modeled analysis appeared to be inconsistent with
both the GE analysis and actual plant response.
The RETRAN
modeled analysis indicated that with a loss of feedwater, water
level would decrease to a minimum of 100 inches (2.54 M) versus
the 77 inches (1.95 M) that actually occurred. Although not
affecting the licensee's overall review and power uprate
submittals, there was a concern that simulator modeling could have
utilized the RETRAN analysis. Therefore, the present simulator
response could differ from actual plant response based on the
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recent power uprate.
Pending-further licensee review to ascertain
the use of the specific RETRAN analysis, this matter is considered
an Inspection Followup Item (341/92017-03(DRP)).
The inspector reviewed portions of the licensee *s preparations for
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restart. Overall, activities observed or reviewed were found to
be in conformance with applicable administrative requirements. The
reactor was subsequently restarted on November 23 and synchronized -
to the electrical grid the following day.
d.
Reactor Startuo
The inspectors attended the onsite safety review organizmtion
(0SRO) startup meeting to monitor that preparations for startup
were comp 1ete,-documented, and reviewed by-the= appropriate
management level. The meeting was conducted in a professional
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manner with good command and control exhibited by the OSR0
chairman. All power uprate related issues, modifications,
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signoffs, etc., were completed.
The chairman reserved signoff
authority until all open issues had been resolved.
Activities within the control room were observed by the
inspectors. The decorum within the control room was well
maintained with almost no exceptions.
Shift Supervisors and
Assistant Shift Supervisors were very aware and in control of
noise levels and personnel within the control room environment.
Control of evolutions was good. However, a drop in reactor level
of approximately 5 inches (12.7 cm) resulted-in a low level alarm
d en a feedwater heater feed pump was brought online.
Recovery
actions by the Assistant Shift Supervisor were very good.
Positive action to stabilize the plant on the start up level
controller was exhibited.
The inspectors also monitored the performance of the HPCI flow
test.
The Shift Supervisor displayed excellent command presence
and system knowledge in troubleshooting a high differential
pressure across the oil strainer. The Shift Supervisor did not
accept convenient explanations and recommendations to continue the
test. The cause was properly diagnosed as a malfunctioning
pressure gage. During the evolution, the control room noise level
was low and communications were professional.
The inspectors conducted numerous walkdowns of the reactor and
turbine buildings prior to and during the startup to assess the
licensee's readiness and material condition of_ the plant.
Several
minor material deficiencies were noted. The most significant of
these was the inability of fire door RA2-7 to close by itself.
The inspectors observed an operator pass through the door, and
even though the door did not fully close, the operator continued
on his rounds apparently unaware.of the door's conditicn.
Several
operations by the inspector showed that the door failed to fully
close most of the time. The door was-in the same fire area-as
RA2-6 whose latching mechanism was found taped open, presumably
because of the same door problem. The control of fire doors is an
Inspection Followup item (341/92017-04(DRP)).
e.
Current Material Condition (71707)
The inspectors performed general plant as well as selected system
and component walkdowns to assess the general-and specific
material condition of the plant, to verify that work requests had
been initiated for identified equipment problems, and to evaluate
housekeeping. Walkdowns-included an assessment of the buildings,
components, and systems for proper identification and tagging,
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accessibility, fire and security door _ integrity, scaffolding,
radiological controls, and any unusual conditions. Unusual
conditions included but were not-limited to water, oil, or other
liquids on the floor or equipment; indications of leakage through
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ceiling, walls or floors; loose insulation; corrosion; excessive
noise; unusual temperatures; and abnorma'i ventilation and
lighting.
The inspectors noted that the licensee continued to
experience some difficulties with respect to the heater drains
system.
Following the startup after the plant's third refuel
outage, maintenance personnel had to perform repairs _to correct
various leaks. Examples included a shaft seal leak on the south
heater drains pump (HDP), a union leak on the center HDP, a
discharge pressure tap on the center HDP, and a sensing element-
leak on the center HDP train. Overall, the inspectors considered
the material condition of the plant as satisfactory,
f.
Housekeepina and Plant Cleanliness (71707)
The inspectors monitored the status of housekeeping and plant
cleanliness for fire protection and protection of safety-related
equipment from intrusion of foreign matter. Housekeeping was
considered satisfactory. During an inspection of the drywell
prior to close out, the inspectors found cbbris that included a
piece of rope and a hard hat. The drywell had been previously
inspected by the licensee in the area where the debris was found,
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Radioloaical Controls (71707)
The inspectors verified that personnel were following health
physics procedures for dosimetry, protective clothing, frisking,
posting, etc., and randomly examined raoiation protection
instrumentation for use, operability, and calibration.
During routine inspection tours of the reactot , turbine', and
auxiliary buildings, the inspectors noted, on several occasions,-
candy wrappers, gum wrappers, gum, and cigarette butts within the
radiological controlled area (RCA). The inspectors' observations
were communicated to the appropriate radiation protection
supervisor.
h.
Security .(71707)
Each. week during routine activities or tcurs, the inspectors
monitored the licensee's security-program to ensure that observed
actions were being implemented according to the approved security
plan. The inspectors noted that persons within-the protected area-
displayed proper photo-identification badges,- and those
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individuals requiring escorts were properly escorted.
Additionally, the inspectors also_ observed that personnel and
packages entering the protected area were searched by appropriate
equipment or by hand.
One violation was identified.
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Safety Assessment /0uality Verificati9D (40500 and 92700)
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Through direct observations, discussions with licensee personnel, and
review of records, the following event reports were reviewed to
determine that reportability requirements were fulfilled, that immediate
corrective action was accomplished, and that corrective action to
prevent recurrence had been or would be accomplished in accordance with
Technical Specifications (TS):
LClosed) LEP (341/90-002) Revision 1:
Under this revision, the
licensee performed setpoint evaluations of all the Technical
Specification radiation monitoring alarm setpoints.
The
evaluations were performed under DER 87-398 as part of the
Technical Specification Improvement Program concerns. During the
previous review of this LER, the licensee had completed all but 20
discretionary items.
In September 1991, the licensee completed
all remedial and corrective actions associated with the radiation
monitoring alarm setpoints. This LER is closed.
(Closed) LER (341/90-011): On October 6, 1990, the reactor
scrammed due to low reactor water level.
Prior to the scram, the
instrumentation and controls (I&C) technicians were investigatin9
a 20 inch (50.8cm) discrepancy between the "A" and "B" reference
legs.
The instruments off the "A" reference leg were indicating
193-195 inches (490-495cm) while the instruments off the "B"
reference leg were indicating 20 inches lower. While
troubleshooting efforts were in progress, the low reactor water
level setpoint of 173.4 inches (440.4cm) was reached. The
licensee attributed the cause of the event to air voids in the "A"
reference leg which gave an erroneous high reading. -The licensee.
indicated that air bubbles may have been introduced into the:
reference leg when some of the transmitters were replaced during
the outage.
In September 1988, the licensee had received a General Electric
(GE) Service Information Letter (SIL) 470 from the vendor t.hich
identified concerns with reactor water level mismatches. Two of
the recommendations provided by the SIL for reducing the chances
of unexpected water level mismatches were: backfill the process
instrument piping after surveillance testing; and train-plant
operations personnel in appropriate methods for responding to
mismatches between water level instrument indications. At the
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time of the reactor water level scram, the licensee had -already
evaluated the SIL under DER 88-1833; however, the licensee decided-
not to implement the two recommendations mentioned above. The
licensee determined that the recommendation for backfilling the
reference legs should have been implemented. The licensee issced
DER 90-0625 to reevaluate GE SIL 470.
Pending a review of DER 90-
625, the SIL process is considered an Unresolved Item (341/92017-
05(DRP)).
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As part of the corrective actions to LER 90-011, the licensee
implemented the following corrective actions:
(1)
Lower heatup rate to allow additional time for monitoring
level instrument response.
(2)
Data collection to check the effectivehess cf corrective
action.
(3)
No steam draw until 125 p..ig (862 kPa) to minimize level
(4)
Conservative level control (use lowest reading instrument).
(5)
Following extended outages (29 or more days) a backfill
and/or flush of the reference leg will be performed.
The inspector verified that the lict :ee implemented all the
corrective actions listed above.
No violations or deviations were identified.
5.
Maintenance /Surveillante (62703 & 61726)
a.
Maintenance Activities (62703)
Routinely, station maintenance activities were observed and/or-
reviewed to ascertain that they were conducted in accordance with
approved procedures, regulatory guides and industry codes or
standards, and in conformance with technical specifications.
The following items were also considered during this review:
limiting conditions for operation were met while components or
systems were removed _from service; approvcis were obtained prior
to initiating the work; functional testing and/or calibrations
were performed prior to returning components or systems to
service; quality control records were maintained; and activities
were accomplished by qualified personnel.
Portions of the following maintenance activities were observed
and/or reviewed:
920902
Scale Changeout for RHR Disd.%e Pressure
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Indicator
920516
Calibration Charcoal Absorber Temperature
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controller for Standby Gas Treatment
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The inspectors identified concerns witn the above maintenance
activities-in the area of procedures.
In both cases, the
activities appeared not to have been performed in accordance with
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the maintenance procedure.
Procedure 44.030.219 used for-a' scale
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change out required steps 6 through 13 to be performed if the "As
Found" data was found to be out of tolerance.
For work request 920902, steps 6 through.13 were performed even though the "As
Found" data was acceptable. The maintenance aethity for
calibrating the charcoal absorber temperature controller for the
Standby Gas Treatment System utilized work request 920516 and
procedure 46.000.044. While observing the work, the-inspectors
noted that the maintenance personnel lifted leads to defeat the
lockin function when testing the control unit relays. The lockin
feature locks in the actuation relay for 10 minutes.
In order to
obtain the actuation relay's reset value without waiting 10
minutes,.the workers lifted leads to defeat the lockin relay
feature. The work request and procedure 46.000.044 did not
delineate in a step the lifting of these leads.
The workers did
document the lifting and relanding of the leads including an
independent verification. The concerns #,th procedures 44.030.219
and 46.000.044 are considered an Inspection Followup Item pending
further NRC review (341/92017-06(DRP)).
No violations or deviations were identified,
b.
Surveillance Activities (61726)
During the inspection period, the inspectors observed technical
specification required surveillance testing and verified that
testing was performed in accordance with adequate procedures, that
test instrumentation was calibrated, that results conformed with
technical specifications and procedure requirements and were
reviewed, and that any deficiencies identified during the testing
were properly resolved.
The inspectors also witnessed portions of the following
surveillances:
SOE 91-01
FW-C-1, Rev 0, Feedwater System Level
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Setpoint Changes
SOE 92-01
PR-C-1, Rev 0, Pressure F.rgulator Test-
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24.307.17
Emergency Diesel Generator No. 14
.
Start and Load Test, Slow Start
24.307.16
Emergency Diesel Generator No.13
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Start and Load Test, Slow Start
24.307.32
(EDG-13) 24 Hour Run Followed By Loss
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of Offsite Power Test
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82.000.04
Refuel'.ng and Core Post-Alteration
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Verification
82.000.14
Control Rod Friction Testing
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c.
Performance Evaluation Activities
The inspectors witnessed portions of tests performed under the
licensee's performance evaluation program.
Even though the tests
were not defined as Technical Specification (TS) surveillances,
the tests determined that support functions for TS components were
operable and not in a degraded condition which could jeopardize
the operability of the TS component. The folicwing performance
evaluations procedures were reviewed or portions witnessed by the
intt'ectors:
27.202.01, Revision 0, "HPCI Overspeed Trip Test"
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27.206.02, Revision 0, "RCIC Overspeed Trip Test"
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On November 5, 1992, the inspectors witnessed a portian of the
overspeed trip test on the High Pressure Coolant injection (HPCI)
turbine using procedure 27.202.01. The inspectors had the
following observations pertaining to procedure 27.202.01:
The criteria for the overspeed trip function was 5000 rpm,
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plus or minus 100 rpm.
The function was tested three times
during each overspeed test on June 1991 and November 1992.
The criteria was not always met during the three trips due
to oil temperature variances.
In each case when the
criteria was not met, there was justification documented on
the Performance Form.
Since the overspeed criteria has not
been consistently met during overspeed tests, the licensee
should evaluate the acceptability of the trip criteria.
Note (1) after step 5.35 in the current revision of
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procedure 27.202.01 states the next step will start the HPCI
turbina.
However, step 5.37, the opening of the bypass
valve, E4150-F600, will cause the HPCI start, not step 5.36.
Note after step 5.30 states that when valve E4150-F001 is
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opened, the HPCI turbine may roll if leakage occurs around
the turbine stop and control valves, (E4100-F067 and E4100-
F068) located downstream of E4150-F001. However, to have a
HPCI turoine roll would also require leakage past the E4150-
F003 bypass valve, E4150-F600, and the E4150-F003 valve.
These valves were closed in step 5.29.
The note should be
reviewed to clarify the leakage source that could.cause a
HPCI turbine roil when valve E4150-F001 is opened.
The licensee acknowledged the observations and will evaluate the
recommendations.
No violations or deviations were identified.
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6.
Inspection Followuo items
Inspection Followup items are matters which have been discussed with the
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licensee, which will be reviewed by the inspector, and which involve
some action on the part of the NRC or licensee or both.
Inspection
Followup Items disclosed during the inspection are discussed in
paragraphs 3.c, 3.d, and 5.a.
7.
Unresolved Items
Unresolved items are matters about which more information is required in
order to ascertain whether they are acceptable items, violations, or
deviations.
Unresolved items disclosed during the inspection are
discussed in paragraphs 3.c and 4,
8.
Meetinas and Other Activities
a.
Management Meetinos (30702)
On November 9 and 10, 1992, the Branch Chief for Branch 2 toured
the Fermi plant and met with licensee management to discuss plant
performance and plant material condition.
Also, on November 30 through December 2, the DRP Section Chief
toured the Fermi plant and met with licensee management to discuss
plant performance and plant material condition.
b.
Exit Interview (30703)
The inspectors met with the licensee representatives denoted in
paragraph I during the inspection period and at the conclusion of
the inspection on December 8, 1992. -The inspectors summarized the
scope and results of the inspection and discussed the likely.
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content of this inspection report. The licensee acknowledged the
information and did not indicate that any of the-information
disclosed during the inspection could be considered proprietary in
nature.
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