ML20045C040
| ML20045C040 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 06/11/1993 |
| From: | Jorgensen B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20045C035 | List: |
| References | |
| 50-282-93-08, 50-282-93-8, 50-306-93-08, 50-306-93-8, NUDOCS 9306220014 | |
| Download: ML20045C040 (28) | |
See also: IR 05000282/1993008
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Reports No. 50-282/93008(DRP); 50-306/93008(DRP)
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Docket Nos. 50-282; 50-306
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Licensee: Northern States Power Company
414 Nicollet Mall
Minneapolis, MN 55401
Facility Name:
Prairie Island Nuclear Generating Plant
Inspection At:
Prairie Island Site, Red Wing, MN ,
Inspection Conducted: March 30 through May 31, 1993
Inspectors:
M. L. Dapas
R. L. Bywater
D. S. Butler
T. J. Kozak
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Approved By:
B. L.
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Reactor Proje ts Section 2A
D~ ate
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Inspection Summary
Inspection on March 30 through May 31, 1993 (Reports No. 50-282/93008(DRP);
50-306/93008(DRP))
Areas Insnected: Routine, unannounced inspection. by resident and regional
inspectors of plant operational safety including onsite followup of events,
maintenance, surveillance, engineering and technical support, radiological
controls, licensee followup on previously identified items, licensee event
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report followup, allegation followup, and response to Regional requests.
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9306220014 930611
ADOCK 05000282~
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Executive Summary
Enforcement
Two cited violations of NRC requirements, one unresolved item, and one
inspection followup item were identified in the areas inspected.
Operations
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No new strengths or weaknesses were identified. One violation was identified
involving the failure to maintain Technical Specification required
administrative controls for an inoperable containment isolation valve
(paragraph 1.b).
One inspection followup item was identified involving the
effects of temperature on Regulatory Guide 1.97 event monitoring equipment and
the relationship between the safeguards chilled water system and 480 Volt
switchgear operability (paragraph 1.c).
A concern was identified with the-
licensee's implementation of its empowerment philosophy relative to ensuring
that an appropriate level of management is involved in the decision making
process, and that those individuals entrusted with making decisions; keep their
respective supervisors informed (paragraph 1.d).
A concern was also
identified with the-increased incidence of equipment found in an off-normal
condition (paragraphs 1.e and 2.a).
Maintenance and Surveillance
No new strengths were-identified. One violation and associated weakness were
identified involving the improper setting of overtemperature delta temperature
and overpower delta temperature reactor protection system trip setpoints
(paragraph 6.a).
One unresolved item was identified-involving the apparent.
failure to perform required ASME Section XI testing of certain valves -
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(paragraph 7.c).
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Enaineerina and Technical Support
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No new strengths or weaknesses were identified.
Inadequate review of the
design assumptions used to determine the weight of the spent fuel pool covers.
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resulted in .the licensee qualifying the spent fuel pool crane as single-
failure proof for a maximum critical load less than the actual weight of the
covers (paragraph 4.a).
Radioloaical Controls
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No new strengths or weaknesses were identified. The licensee implemented the
use of a new thermoluminescent dosimeter on April 1, 1993 (paragraph 5.a).
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REPORT DETAILS
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1.
Operational Safety Verification (71707. 93702)
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The inspectors observed control room operations, reviewed applicable
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logs, conducted discussions with control room operators, and observed
shift turnovers. The inspectors verified operability of selected
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emergency systems, reviewed equipment control records, verified the
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proper return to service of affected components, conducted tours of the
auxiliary building, turbine building and external areas of the plant to
observe plant equipment conditions, including potential fire hazards,
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and to verify that maintenance work requests had been initiated for
equipment in need of repairs.
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a.
General
Both units operated at full power throughout the inspection period
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except as noted below.
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Unit I was reduced in power for turbine valve testing on
April 24-25, 1993.
Unit 2 was reduced in power for turbine valve
testing on April 18, 1993.
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Unit I had a brief reduction in load of'approximately 8 MW on
May 17, 1993.
This occurred when a control room operator was
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replacing a control panel light bulb for CV-31023 ~(ISA feedwater
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heater drain to 14A feedwater heater) without a light _ bulb removal
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tool.
During the bulb removal, a short occurred,'a fuse was
blown, and CV-31023 failed closed. The resulting increase in
feedwater heater level caused CV-31024 (15A feedwater. heater drain
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to B condenser dump) to open and caused the load reduction due to
reduced feedwater heating.
Replacement of the fuse was prompt and
full power operation was restored shortly thereafter. Although
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this was a minor transient, it could have been avoided by proper
use of the light bulb removal tool .
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b.
Loss of Administrative Control for a Containment Isolation Valve
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On April 3,1993, while performing SP 2272, " Quarterly Cycling of
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Pressurizer Relief Tank (PRT) Reactor Makeup Water and Nitrogen
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Control Valves," containment isolation valve CV-31342 (Reactor
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Makeup Water to Unit 2 Containment) exceeded its maximum allowable
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time to close. As a result, CV-31342 was declared inoperable.
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Technical Specification (TS) 3.6.C.3 states that with one or more
valves listed in Table TS 4.4-1 inoperable, within four hours:
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(a) restore the inoperable valve (s) to operable status, or (b)
deactivate the operable valve in the closed position, or (c) lock
closed at least one valve in each penetration having one _
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inoperable valve. Table TS 4.4-1 lists containment penetration
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No. 45, Reactor Makeup to PRT, which includes CV-31342.
To comply
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with Technical Specification (TS) 3.6.C.3, CV-31342 was shut and'
its air supply was lockwired closed.
Safety tags, which are used
to administratively control equipment status, were placed on both
the control switch. in the control room and the air supply
isolation valve for CV-31342.
On April 5, 1993, No. 45 containment penetration upstream
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isolation valve 2RM-8-4 (Supply to PRT) was closed and normally
capped vent valve 2RC-9-4 (penetration leak test connection) was
verified closed. This established dual / redundant isolation.
Safety tags were attached to each of these valves. On April 9,
1993, the system engineer requested control room operators to
stroke CV-31342 for troubleshooting purposes.
The Unit 2 shift
supervisor (SS) determined that valves 2RM-8-4 and 2RC-9-4 should
be lockwired closed to ensure compliance with TS 3.6.C.3 before
cycling CV-31342.
2RM-8-4 was lockwired closed, however, 2RC-9-4
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could not be lockwired because there was no hole in the valve
handwheel to pass the lockwire through.
A maintenance work
request was initiated to drill a hole in the valve handwheel for
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On April 13, 1993, after maintenance personnel had completed
drilling a hole in the valve handwheel, the system engineer
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requested that 2RC-9-4 be lockwired so that CV-31342 could be
stroked. The system engineer removed the isolation and
restoration (I&R) sheet that listed valves 2RC-9-4 and 2RM-8-4
from the Unit 2 shift supervisors 1&R record book, circled 2RC-9-
4, and added a note to install lock wire.
The I&R sheet that
contained the air supply isolation valve and control switch for
CV-31342 was also removed from the 1&R record book.- The Unit 2 SS
gave both I&R sheets to the Unit 2 reactor operator (RO) and
provided verbal instructions to install lock wire on 2RC-9-4, to.
remove the safety tag from the air supply' isolation valve for
CV-31342 and then open that valve, and to remove the safety tag on
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the control switch for CV-31342.
The Unit 2 R0 then contacted the
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Auxiliary Building Operator and requested that he come to the
control room to perform a valve restoration.
The R0 gave both I&R
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sheets to the Auxiliary Building Operator with instructions to
remove the safety tag on the air supply isolation valve and open
the valve and to install lock wire on-2RC-9-4.
At approximately
11:00 a.m., the Auxiliary Building Operator removed the safety tag.
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and opened the air supply isolation valve for CV-31342.
He then
removed the safety tags for 2RM-8-4 and 2RC-9-4, cut the lock wire
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off of 2RM-8-4 and opened the valve.
(Note: With 2RM-F-4 open and
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CV-31342 no longer disabled, action requirements of TS 3.6.C.3
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came back into effect.)
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The Auxiliary Building Operator then installed lock wire on 2RC-9-
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4 as indicated on the I&R sheet.
He then called the control room
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and system engineer and reported that the reactor makeup
restoration was complete. Apparently, the Auxiliary Building
Operator misunderstood the directions he had received from the R0
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and assumed he was making a routine system restoration after
maintenrnce. At this time the Unit 2 R0, Lead Plant Equipment
Operator (LPED), and SS and the system engineer-thought that both
2RM-8-4 and 2RC-9-4 were lockwired closed with safety tags hung.
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At approximately noon, SP 2272 was performed and CV-31342 cycled.
The stroke time for this valve was within the specified acceptance
criteria. After completing the surveillance procedure, CV-31342
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was left in the open position. However, CV-31342 was not declared
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operable. At about 5:00 p.m. while preparing for ' shift turnover,
the Unit 2 LPE0 noted that the system engineer had not informed
the control room of the current status of CV-31342.
The Unit 2 SS
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decided to shut the valve.
During shift turnover, the Unit 2 SS,
R0, and LPE0 each reported to their respective reliefs that CV-
31342 was closed and still considered inoperable, that the air
supply isolation valve for CV-31342 was open, and both 2RM-8-4 and
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2RC-9-4 were lockwired closed.
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At approximately 12:30 a.m. on April 14, 1993, a control room
operator making a plant tour decided to check the status of the
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CV-31342 containment penetration. The operator found the air
supply isolation valve for CV-31342 open, 2RM-8-4 open, 2RC-9-4
lockwired closed, and safety tags on 2RM-8-4 and 2RC-9-4 removed.
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The Unit 2 SS instructed the operator to close and lockwire
This re-established conditions required by TS.
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Administrative control of containment isolation valve 2RM-8-4 was
lost for approximately 13% hours from 11:00 a.m. on April 13 to
12:30 a.m. on April 14, 1993.
During this 13% hour period
containment integrity was maintained by the redundant containment
isolation valve for containment penetration No. 45, 2RC-3-1
(Reactor Makeup to PRT check valve). The failure to maintain
either 2RM-8-4 locked closed or CV-31342 closed with its
associated air supply isolated is considered a violation of TS 3.6.C.3. (50-306/93008-01(DRP)).
The inspectors reviewed the Error Reduction Task Force (ERTF)
report generated for this event and discussed the apparent causes
for the T.S. violation with the licensee.
Poor communications
between the system engineer, shift supervisor, and control room
operators was one of the primary causes of this event.
The use of
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safety tags issued by the SS rather than a work request to
maintain administrative control of 2RM-8-4 and 2RC-9-4, caused
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confusion concerning the status of containment penetration No. 45.
I&R sheets did not contain specific conditions for removing'the
isolations or indicate that the purpose of the isolation was' to
maintain containment integrity. The inspectors reviewed'the
Licensee Event Report (LER) submitted by the licensee for this TS
violation and concluded that the planned corrective action,~as
documented in the LER, does not sufficiently address all of the
apparent causes for this violation. The inspectors requestad the
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licensee to describe its comprehensive corrective action to
prevent recurrence in its response to the associated Notice of
Violation.
c.
Train A Hydroaen Monitor Lockup due to Hiah Ambient Temperature
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Train A hydrogen monitor is located in 480 Volt safeguards bus
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room No. 120.
The hydrogen monitor is a Regulatory Guide 1.97
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Category 1 Type A instrument and as such,.is required to be
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seismically and environmentally qualified for the environment in
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which it is expected to operate during a design basis accident.
Bus room 120 contains Unit 1 Train B 480 Volt safeguards buswork,
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and Train A event monitoring (EM) equipment for both units. Two
unit coolers are installed in bus room 120, one from each train of
the safeguards chilled water system.
Both unit coolers are
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safety-related and each cooler is sized to remove the maximum
postulated heat generation in the room;
i.e., train A cooler
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(102A) to ensure the EH equipment is operable, and train B cooler
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(102) to ensure the switchgear is operable.
On April 5,1993, Panel 134 (power supply to unit cooler 102A) was
deenergized for maintenance on an associated motor control center
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(MCC).
This resulted in removing unit cooler 102A from service.
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After completing the MCC work on April 6, the licensee reenergized
Panel 134. The licensee expected unit cooler 102A to restart
based on review of electrical schematic and wiring diagrams during
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preparation of the work request. However, starting'and' stopping
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of this cooler is controlled by a magnetic starter which was not
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identified on the drawings. To restart the. cooler after power has
been restored, the start pushbutton must be depressed. Contrary
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to the licensee's expectation, unit cooler 102A did not restart
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when power was restored to Panel 134. This was not recognized at
the time.
On April 7,1993, Panel 135 (power supply to unit cooler 102) was
deenergized for MCC work. This removed the only running cooler in
bus room 120 from service. As a result, ambient temperature in
the bus room began to increase. During a routine system walkdown,
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the EM system engineer discovered the hydrogen monitor locked up
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and noted that the room temperature was about 95 degrees
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Fahrenheit. The system engineer notified the control room and a
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work request was initiated to investigate the instrument failure
and high temperature condition. The connecting door between bus
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rooms 110 and 120 was opened to reduce ambient temperature and a
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fire watch was stationed. During the investigation, the reset and
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start pushbuttons for unit cooler 102A were depressed and the
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cooler started. The licensee also generated a nonconforming item
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report (866) for the failure of unit cooler 102A to restart after
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power was restored to- Panel 134.
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On April 8,1993, the inspectors noted the reactor log entry for
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the failed hydrogen monitor. The inspectors questioned the
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licensee. regarding the environmental- qualification of the EM
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equipment installed in bus room 120. The licensee initially
stated.that the hydrogen monitor computer is designed to operate
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in an ambient environment up to 120 degrees Fahrenheit, and that
the maximum ambient room temperature under an accident condition
would be 105 degrees. The inspectors questioned why the hydrogen
monitor had failed at a lower than expected temperature. The
licensee stated that there had been a previous history of the
hydrogen monitor locking up due to high ambient temperature and
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decided to further investigate the apparent temperature
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susceptibility of this instrument.
After further review of the design specifications for the hydrogen
monitor, the licensee stated that the-instrument would operate-in
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an ambient environment up to 105 degrees versus the prev._iously
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stated 120 degrees.
Subsequent testing verified that the hydrogen
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monitor would operate up to a temperature of 105 degrees inside
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the instrument rack that houses the hydrogen monitor. However,
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since the instrument rack is not ventilated, the temperature
inside the instrument rack is 10-15 degrees higher than the
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ambient room temperature.
The licensee's original statement that the maximum ambient room
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temperature under an accident condition would be 105 degrees was
based on a calculation that used the design specifications of the
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cooler. The calculation showed that for a cooler air inlet
temperature of 105 degrees, the temperature of the air leaving the
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cooler would be 74 degrees. The licensee stated that this
calculation used rather conservative assumptions. The licensee
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initiated an evaluation 'as part of its configuration management
follow-on item (FOI) assessment program to verify that one unit
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cooler can maintain ambient temperature in bus room 120 at or
below 90 degrees, to account for the temperature differential
between ambient room temperature and the 105 degree internal
instrument rack limit. A calculation demonstrated this
capability. This calculation was based on a maximum air inlet
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temperature of 88.4 degrees assuming that the ambient room
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temperature would be between 66 and 88.4 degrees depending on.the
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location in the room. Based on the results of this calculation,
the licensee cor.cluded that there was no operability concern
associated with the EM equipment installed in bus room 120. The
inspectors reviewed the licensee's calculations and concluded that
the licensee's operability determination was adequately supported.
The licensee noted that there is no specific Technical
Specification applicable to the safeguards chilled water system.
Technical Specification Interpretation (TSI) 3.13-6 regarding
control room cooling, discusses administrative controls for the
chilled water system to prevent temperature excursions relative to
equipment life concerns.
However, TSI 3.13-6 states that the
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safeguards chilled water system is not required to maintain
equipment operability in any of the rooms that it serves.
This
statement appeared invalid, considering the apparent need for at
least one unit cooler in bus roon 120 to satisfy EM equipment
qualification requirements.
Further, during a plant tour, the inspectors noted that the unit
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cooler for bus room 16 was removed from service. The cooler was
being relocated to another part of the room to support cable
routing for the station blackout / electrical systems upgrade
(SB0/ESU) project.
The inspectors reviewed the work request for
relocating the unit cooler. The work request contained a note
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stating that removal of the unit cooler from service does not
affect the operability of bus-16 room components.
The inspectors
questioned the licensee regarding the impact of the out-of-service
unit cooler on the operability of 4KV safeguards bus No.16. The
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licensee responded that a safety evaluation (No. 321) had been
performed to address the event of a loss of integrity of the
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safeguards chilled water system due to a seismic event.
The
licensee stated that this safety evaluation provided a documented
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justification for continued operation for a loss of the safeguards
chilled water system.
The inspectors reviewed safety evaluation
No. 321, F0I A0617 (Heat Removal Calculations for the Safeguards
Chilled Water System), and associated reference calculations.
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Thse documents indicated that no equipment thermal limits would
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be exceeded for equipment located in the 4KV switchgear rooms upon
a loss of the chilled water system.
However, for equipment in the
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480 Volt switchgear and relay rooms, these same documents
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indicated that thermal limits would be exceeded,. unless operator
action is taken.
This action would include shedding equipment
loads to minimize heat generation and opening room doors to
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provide supplemental cooling. The inspectors concluded that the
relationship of the chilled water system to switchgear room
equipment operability, as stated in TSI 3.13-6 needs to be
reevaluated.
The licensee informed the inspectors that it would evaluate
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current guidance in TSI 3.13-6 regarding operability of the
safeguards chilled water system in relation to 480 Volt switchgear
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and relay room operability. The licensee also concluded that
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further evaluation of EM equipment capabilities relative to
ambient room temperatures was needed. This is considered an
inspection followup item (50-282/93008-02; 50-306/93008-02)
pending the inspectors review of the results of the licensee's
evaluation.
d.
Defective Anti-Rotation Key in Motor-0perated Valves
The inspectors informed the licensee of a 10 CFR Part 50.72
notification by the licensee for the Kewaunee Nuclear Power Plant
involving a safety injection (SI) system recirculation valve to
the refueling water storage tank (RWST) which failed to close
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during' dynamic motor-operated valve (MOV) testing.
The valve
failure was attributed to a broken anti-rotation device which
caused binding of.the valve stem.
The anti-rotation device
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consists of an approximate 2.25 by 0.90 inch "L" shaped key that
fits into the valve upper yoke bushing and prevents the valve
shaft from rotating while allowing the shaft to traverse up and
down.
The subject valve is a two inch globe valve manufactured by
Vel an. The licensee for Kewaunee identified six broken
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anti-rotation keys in the nine applications of this Velan globe.
valve in various safety related systems.
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The licensee reviewed this potential generic problem under.'its
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operating experience assessment program. The licensee identified ~
12 applications of the Velan globe valve in the SI system and 4
applications in the chemical and volume control system (CVCS).
The licensee noted that valve actuators for all of the SI-valves
were overhauled and then tested both statically and dynamically
during the 1992 dual-unit outage. To address concerns with loss
of thrust due to key interaction with the stem, the keys and
keyslots for each SI valve were inspected, cleaned, and
lubricated.
In addition, rough edges were eliminated.
During
this maintenance activity, the key for Unit 1 MOV SI-32067, SI to
Reactor Vessel, was broken during removal. * The licensee contacted
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the valve manufacturer, Velan, since no spare part was available.
The vendor informed the licensee that replacement keys were being
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manufactured from a different material than the original hardened
440 C stainless steel due to brittle fracture concerns. 'Upon
receipt from Velan, a replacement key was installed in SI-32067,
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This material change was implemented under Alteration 92A257
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-which was reviewed by the Operations Committee-(onsite safety
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review).
Following replacement of the broken key in SI-32067, two
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additional keys were found broken in Unit 2 MOVs SI-32170, SI to
Reactor Vessel, and SI-32204, SI pump recirculation to RWST.
Both
were replaced.
For both keys, the break occurred at the 90 degree-
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angle that connects the shorter leg to the longer leg.
Based on
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the location of the break, the length of the key and keyslot, and
the arrangement of the keyslot in' the valve stem and yoke bushing,
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the licensee concluded that the anti-rotation key would still have
performed its intended function. This operability determination
was made by engineering personnel based on discussion with those
individuals involved in the original outage maintenance activity
and did not involve the Operations Committee. While it is likely
that the Operations Committee would have reached a similar
conclusion, the inspectors were concerned that the Operations
Committee was not involved in the operability determination.
The
licensee strongly promotes the philosophy of empowerment in which
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decision making is forced down to lower levels of management.
The
inspectors discussed with the licensee the need to ensure that an
appropriate level of management is involved in the decision making
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process and that those individuals entrusted _ with making decisions
keep their respective supervisors informed.
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As part of its operating experience assessment, the licensee
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checked the Nuclear Plant Reliability Data System (NPRDS) data
base for other reported failures of Velan globe valves to operate
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due to a broken anti-rotation key.
No reported failures were
identified.
However, the licensee search of the NPRDS data base
is of limited utility in that sub-component degradation such as a
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broken anti-rotation key, would not typically be reported unless
the degradation would have obviously prevented the component from
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functioning.
Based on the fact that 12 of the 16 identified Velan
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valves had recently been inspected, which involved cleaning and
lubricating the anti-rotation key, and then dynamically tested,
the licensee concluded that the 16 valves were operable.
This
operability determination was conducted by the Operations
Committee.
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Based on a preliminary evaluation by the licensee for Kewaunee
that the reported anti-rotation key failure may have been caused
by low cycle fatigue, the inspectors expressed a concern that the
dynamic testing conducted during the recent dual-unit outage may
have imposed sufficient stress on the subject valves to cause the
associated anti-rotation key to fail.
The broken key could then
potentially prevent the valve from operating upon demand. As a
result, the licensee decided to visually inspect selected,
normally closed valves for evidence of key failure. The long leg
of any broken "L" shaped key would slide down tiie key slot and
become visible below the yoke bushing.
The licensee conducted at-
power entries into Unit I and Unit 2 containment to verify key
integrity of certain valves in the CVCS and SI system. The
inspectors accompanied the licensee's MOV engineer to' inspect
three valves in Unit 2 containment: MV 32172 - SI to Reactor
Vessel, MV 32170 - SI to Reactor Vessel, and MV 32235 - RHR to
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Reactor Coolant System- Letdown.
The keys for MV 32170 and MV
32235 appeared intact. The licensee was not able to inspect MV
32172 since it was inaccessible due to high radiation levels.
The
licensee plans on inspecting this valve during the next refueling
outage.
Based upon verification of key integrity for other
valves, the licensee concluded there was a high degree of
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confidence that MV 32172's key was intact.
The licensee for Kewaunee submitted a 10 CFR Part 21 report for
the anti-rotation device failure in the Velan globe valves. The
inspectors did not have any further questions regarding this
issue.
e.
Pressurizer Heater Control Power Selector Switch Mispositioned
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Unit 1 pressurizer heater group B can be powered from either bus
120 (safeguards power supply) or bus 180 (non-safeguards power
supply).
Heater group B receives power from 480 Volt motor
control center (MCC) 1RI.
A transfer switch is used to power MCC
1R1 from either bus 120 through breaker 124 or from bus 180
through breaker 181.
Control power to breakers 124 and 181 is
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- provided through selector switch CS-19328, located in the control
rod drive room.
Pressurizer heater group B is normally aligned to -
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bus 180 with CS-19328 and the 1R1 transfer switch-each in the bus
180 position.
In this coniiguration, breaker 181 would be shut
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and breaker 124 would be open.
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On April 28, 1993, the Unit 1 Plant Attendant entered the Unit I
control rod drive room and noticed both bus 120 and bus 180
indicating lights on CS-19328 lit.
The operator found CS-19328
selected to the bus 120 position and the IR1 power supply transfer
switch selected to the bus 180 position. The operator notified
the control' room and was instructed to place CS-19328 in the bus
180 position. After switching CS-19328 to'the bus 180 position,
the operator noticed that both indicating lights on CS-19328 were
still lit. He then checked the position of breakers 124 and 181'
and noted that they were both closed. The operator notified the
control room of the breaker positions and was instructed to open
breaker 124. After opening this breaker, the operator noted that
only the bus 180 indicating light remained lit.
-
On April 29, 1993, the inspectors noted a reactor log entry for
.
the abnormal pressurizer heater control power selector switch
(CS-19328) and 1R1 power supply transfer switch lineup.
The
inspectors questioned the control room operators on the effect
this abnormal switch lineup would have on control of the
pressurizer heaters. The licensee determined that with this
'
switch lineup, all manual and automatic controls for the group B
pressurizer heater were disabled. The heaters would not have
deenergized on a low pressurizer level, resulting in potential
',
damage to the uncovered heaters. No indication of the
-
micpositioned centrol power selector switch was available in the
control room.
Control room operators would likely not have become
aware of this condition until an attempt was made to deenergize
the heaters. The licensee conducted an ERTF review of this event
but was unable to determine how or when the abnormal switch lineup
occurred. The inspectors reviewed the ERTF report and discussed
-
the results of this review with the licensee.
There are five groups of pressurizer heaters; one group of
,
variable heaters (C) and four groups of backup (A,B,D, and E)
heaters. The backup heaters cycle between 2210 and 2218 psig.
If
a transient occurred res'11 ting in a reactor coolant system (RCS)
pressure increase and pressurizer heater group B did not
deenergize at 2218 psig, the pressurizer spray valve would begin
i
to ramp open at 2260 psig to reduce RCS pressure.
If a
loss-of-offsite power occurred pressurizer heater group A
(safeguards) and pressurizer spray would both be available. - If
heater group B was needed to control pressure, operators would
have to align CS-19328 and the IRI power supply transfer switch to
the bus 120 position.
This same action would be required if the-
original switch lineup had been correct. The inspectors concluded
that the abnormal switch lineup for the B group of pressurizer
11
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heaters had minimal safety Significance. However, the inspectors
expressed a concern for the apparent lack of a questioning
attitude regarding the potential operatioral impact of this
off-normal condition.
The inspectors discussed this issue with
the licensee. The inspectors noted that the licensee has taken
-
action to communicate to the operations staff the need for a
questioning attitude when an off-normal condition is discovered.
The inspectors will evaluate the effectiveness of this action
during their ongoing inspection activities.
One violation and one inspection followup item were identified. No
deviations or unreselved items were identified.
2.
Maintenance Observation (71707. 37700. 62703)
Routine preventive and corrective maintenance activities were observed
)
to ascertain that they were conducted in accordance with approved
procedures, regulatory guides, industry codes or standards, and in
conformance with Technical Specifications. The following items were
considered during this review:
adherence to Limiting Conditions for
Operation while components or systems were removdd from service,
approvals were obtained prior to initiating the work, activities were
accomplished using approved procedures and were inspected as applicable,
functional testing and/or calibrations were performed prior to returning
components or systems to service, quality control records were
,
maintained, activities were accomplished by qualified personnel,
!
radiological controls were implemented, and fire prevention controls
were implemented.
!
Portions of the following maintenance activities were observed or
'
reviewed during the inspection period:
a.
Bus 16 CT-11 Source Breaker Relay Gl"
Scement. On May 19,
1993, the licensee identified that th g us. cover plate for the C
'
phase time overcurrent relay on the C1 1] cf1 ite power source
breaker for Unit I safeguards bus 16 was .
.
Bus .16 can also
receive offsite power from the IRY transformer and via 'a manual
bus-tie from Unit 2 bus 26 (alternate AC source).
.
Once identified, the licensee promptly-began'an investigation to
i
evaluate operational consequences of the cracked glass, the cause,
,
and possible time of occurrence. The licensee examined and tested'
'
the relay to determine if, when the glass broke, if there were any
shards of glass interfering with relay operation or if the relay
was damaged in any other way. The relay was clean and intact, and'
was tested satisfactorily.
The licensee's investigation of how the glass was broken or
exactly when it was broken was inconclusive.
Scaffolding was
present in the vicinity of the bus to support SB0/ESU modification
activities in the bus room, but no particular incident was
identified as the possible cause for the broken cover glass.
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b.
Non-Safeguards Chilled Water System Modification.
+
c.
Repair of No. 12 Charging Pump suction stabilizer and desurger.
,
No violations, deviations, unresolved items or inspection followup items
were identified.
3.
Surveillance (37700. 61726. 71707)
The inspectors reviewed Technical Specification required surveillance
testing as described below, and verified that testing was performed in
accordance with adequate procedures, test instrumentation was
calibrated, and Limiting Conditions for Operation were met.
The
inspectors further verified that the removal and restoration of affected
.
components were properly accomplished, test results conformed with
Technical Specifications and procedure requirements, test results were
reviewed by personnel other than the individual directing the test, and
deficiencies identified during the testing were properly reviewed and
,
resolved by appropriate management personnel.
Portions of the following test activities were observed or reviewed:
a.
SP 1106C, "121 Cooling Water Pump Test." At a meeting of the
Operations Committee (onsite safety review), a member of the
i
engineering staff presented an issue regarding the apparent
degradation of No. 121 CW pump performance.
As part of the
SB0/ESU project, No. 121 CW pump was provided with a Class IE
power supply and it was designated a safeguards pump and included
in TS.
This occurred following completion of the 1992 dual-unit
outage.
Following the completion of CW header and annubar
!
replacement work after the 1992 dual-unit outage, SP 1106C, "121
,
Cooling Water Pump Test," was performed.
During the performance
i
of this test, the licensee observed that the pump was operating
about 11 percent below its pump performance curve (10 percent.
degradation defines the " alert" threshold).
Flow measurement
instrumentation was recalibrated and when SP 1106C was
!
subsequently performed, pump performance was in the acceptable
range.
However, the licensee believes that it will not take much
additional pump wear before No. 121 CW pump is degraded to the
point where it can no longer be considered a safeguards pump.
This pump was last replaced in 1989 and there is a spare pump
available onsite which could be installed. in about 5-7 days. The
timetable for pump replacement is dependent upon temperature
considerations (affecting demand for CU flow) and ASME Code.
testing requirements.
If the pump is not operable from a safeguards point of view, it
may still be available for normal operation.
However, TS state
that four out of the five CW pumps are required to be operable
except that two of the five pumps may be inoperable for 7. days.
The decision of whether or when to replace the pump had not yet
been made at the conclusion of the inspection period.
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13
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b.
SP 1106B, "No. 22 Diesel Cooling Water Pump Test."
c.
SP 2272, " Quarterly Cycling of PRT Reactcr Makeup Water and
Nitrogen Control Valves."
No violations, deviations, unresolved items or inspection followup items
'
were identified.
4.
Enaineerina' and Technical Support (377001
a.
Spent Fuel Pool Covers and Spent Fuel Crane
The spent fuel storage pool at Prairie Island is a two compartment
(interconnected) pool.
Pool No.1 is located in a position that
is in the load path of the auxiliary building crane (125-ton rated .
!
load).
Pool No.1 is provided with three, sectional protective
covers which allow loads up to 24,800 pounds to be transported (at
,
a maximum height of 6 inches) through the spent fuel enclosure
j
when fuel is stored in pool No.1, to preclude damage to the fuel
if tnere is a crane failure.. The covers also provide protection
for fuel. in pool No. I when maintenance is being performed on pool
No. 2.
In 1992, the licensee installed a new spent fuel crane in the
spent fuel pool enclosure. This crane has two hoists, designated
the East hoist and the West Hoist. The East hoist is a 2-ton
capacity hoist, used for general fuel handling and Unit I
refuelings.
The West hoist is a redundant, 3-ton design-rated
load, 3700-pound maximum critical load (MCL) hoist, intended to be
i
used for general fuel handling, Unit 2. refuelings, and lifting
heavy loads.
The crane with its West hoist is single-failure-
i
'
proof, meeting the criteria described in NUREG-0554, " Single-
Failure P oof Cranes for Nuclear Power Plants," and NUREG-0612~,
" Control of Heavy Loads at Nuclear Power Plants," for a load of up
to 3700 pounds.
Prior to installation of the new crane, the licensee used a non-
single-failure proof crane consisting of two 3-ton capacity hoists
i
for movement of heavy loads such as the pool covers.
The NRC
'I
approved this crane as acceptable for use for movement of the pool
covers in correspondence relating to Generic Letter 81-07,
" Control of Heavy Loads," if procedures were-in place such that
the covers were not raised to a height greater than 6 inches and
such that the ends of the covers were maintained over the edge of
the fuel pool and over the floor at all times'.
During a maintenance activity'on April 13, 1993, which required
ac ass to Pool No.1, the licensee discovered that the actual
weight of each spent fuel pool cover, as measured by a load cell,
was approximately 4550 pounds (not including approximately 250
)
pounds of rigging). This was in excess of the historically
assumed weight of 3700 pounds.
The assumed weight of 3700 pounds
14
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k
was a calculated value based on the drawing details of a 1977
construction drawing. The licensee, therefore, procured its
single-failure proof crane based on an erroneous value for the
-
weight of the MCL.
Before this. discrepancy was discovered, the
single-failure proof crane (with a MCL rating of about 1100 pounds
less than the actual weight of the covers plus rigging) had been
'
used on four occasions. However, because the actual weight of the
covers plus rigging was still less than the normal capacity of the .
hoist (3 ton), and the other administrative controls on load path
of the covers was maintained, the probability of dropping the
covers on the fuel was low.
Following its review of this event, the licensee has revised its
procedure 058, " Control of Heavy Loads," to again require two,
3-ton hoists when moving the pool covers over fuel. Also,
,
controls on the lift height and overlap are still required. This
method is consistent with the licensee's original NRC-approved
method of transporting heavy loads in the spent fuel . pool
enclosure with the exception that the actual weight lifted is
about 1100 pounds greater than that originally evaluated. This
'
increased weight, however, is still within the dual-hoist
arrangement capacity of 6 tons.
The inspectors concluded that an inadequate review of the design
assumptions used to determine the weight of the spent fuel pool
covers resulted in the licensee qualifying the spent fuel crane as
,
single-failure proof for an MCL less than the actual weight of the
covers.
b.
Primary Water Stress Corrosion Crackina (PWSCC) of Control Rod
Drive (CRD) Penetrations
,
In November 1991, the licensee was notified that cracks had been
I
found on a CRD penetration on the reactor vessel head at a plant
located in France (reference NRC Inspection Report 50-
282/91024(DRP);.50-306/91024(DRP)).
The mechanism of degradation
was determined to be PWSCC. This issue received prompt attention
by the NRC and groups within the U.S. nuclear industry represented
l
by the Nuclear Utilities Management and Resources Council
(NUMARC), Electric Power Research Institute (EPRI)', the
i
pressurized water reactors (PWR) Owners Group, and the
'
Westinghouse Owners Group, in order to ascertain whether there was
an immediate safety concern for nuclear. reactors in this country.
Several meetings have been conducted between the NRC and these
groups and safety evaluations (SEs) have been performed with the
conclusion that this issue does not present an immediate safety
hazard. Northern States Power has used:an SE. performed by
-
Westinghouse, .which envelops the Prairie Island reactor . vessels,
in performing its own SE (SE No. 343) to provide justification for
continued safe plant operation.
15
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h
Additional meetings are planned between the NRC and the industry
groups. Also, plans for performing inspections of CRD
penetrations using non-destructive examination techniques are
being developed and scheduled, and techniques are being studied
for the mitigation of PWSCC. Although the NRC agrees.that CRD
penetration cracking is not a significant safety issue at this
-
time, the NRC considers this a serious matter and additional
information or future events could cause a reassessment of the
safety significance of the cracking.
No violations, deviations, unresolved or inspection followup items were
identified.
5.
Radioloaical Controls (83750)
Radiological control practices were observed.to ascertain if they were
performed in accordance with regulatory _ requirements.
No problems were
'
noted in this area during the inspection.
Controls on the radiological
condition of the plant remained essentially unchanged from previous
inspection periods and were excellent. The dose expended for the year
,
through the end of the inspection period was under the licensee's
estimate and vary low at approximately 11 person-rem.
The following specific items were observed during the inspection period:
.
a.
As of April 1,1993, the licensee changed vendors for
thermoluminescent dosimeter (TLD) processing. The vendor will
report doses at 7, 300, and 1,000 milligrams per square
centimeter, which conforms to_ dose reporting requirements of 10 CFR Part 20, Revision 1.
TLDs will now be processed quarterly
instead of monthly. The licensee's TLD quality assurance program
will consist of verifying the vendor's ability to produce accurate
and precise results for TLDs exposed to known gamma, beta, and
neutron sources. The inspectors verified that the new TLD vendor
held current personnel accreditation from the National Voluntary.
Laboratory Accreditation Program of the National Bureau of
Standards for each type of radiation for which personnel are to be
monitored.
No problems were noted.
b.
The inspectors reviewed an audit report (AG 92-38) conducted by
the licensee's power supply quality assurance organization. The
audit reviewed the licensee's performance during the dual-unit
outage which was completed in early 1993.
Specific to radiation
protection, one finding was issued with regards to. contamination
control (FG 92-42), which discussed problems encountered during a
letdown system modification and the observance of some personnel
not frisking upon exit from the radiologically controlled area.
The problems identified during the letdown modification were
discussed in a previous NRC Inspection Report (50-282/92028(DRSS);
50-306/92028(DRSS)), and the licensee's assessment of the event
was similar to the NRC's assessment.
16
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y..
-
y,,-_
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,.
,.
. . . - . . . . -
w.
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No violations, deviations, unresolved items or inspection followup items
were identified.
6.
Licensee Followup on Previousiv Identified Items (92701. 92702)
a.
(Closed) Unresolved item 50-282/93002-02:
Ali four Nuclear
Instrumentation System (NIS) bottom detector flux (Q bottom)
isolation amplifiers were miscalibrated.
The top and bottom detector flux signals are used to calculate the
overtemperature delta temperature (OTAT) and overpower delta
temperature (0 PAT) reactor protection system trip setpoints.
The
Prairie Island FSAR/USAR, Chapter 14, Design Basis Events, uses
these setpoints as primary trip functions for uncontrolled rod
cluster control assembly withdrawal at power (slow rate) and a
chemical and volume control system malfunction at power.
Technical Specifications (TS) 2.3.A.2.d (OTAT) and 2.3.A.2.e
(0 PAT), " Limiting Safety System Settings, Protective
Instrumentation," specifies a delta flux [F(4I)] penalty be
applied for each percent that the magnitude of Al (Q top - Q
bottom) exceeds +9 percent.
The AT trip setpoints are
automatically reduced by an equivalent 2.5 percent of rated
thermal power at this point.
Based on the miscalibration, the AT trip setpoints would not begin
automatic f(41) reduction until +15 percent.
The 4T trip
functions (channel dependent) would remain nonconservative until
the penalty ramp intersected the TS trip function at a worst case
f(AI) of +38 percent (see Figure 1 below).
The licensee identified the miscalibration on February 4, 1993,
during the periormance of surveillance test SP 1007, " Nuclear
Power Range Functional Test."
Subsequent root cause investigation
identified that the four Q bottom isolation amplifiers were
miscalibrated on January 22, 1993, during the performance of
surveillance test SP 1006B, "NIS Power Range Axial Offset
Cal i brati on . "
The inspectors concluded the following conditions contributed to
the miscalibration:
(1)
Permanently installed test lead NIS-3 was used during the
calibration and was not labeled as having an internal surge
suppression network.
The network caused each Q bottom
amplifier's output to read approximately 10 percent high.
The instrument technician was unaware that NIS-3 contained a
suppression network and followed existing procedure steps in
adjusting each Q bottom amplifier within its required output
value.
(2)
The instrument technician adjusted each Q bottom amplifier
without questioning the adjustment range.
Typically, no
17
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?
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g
adjustment is required.
In addition, the technician did not
notify plant supervision that a significant adjustment had
been made to all four Q bottom amplifiers.
(3)
Even though procedure SP 1006B was used successfully for
approximately 18 years, the procedure permitted an internal
adjustment to be made with only a signoff that the step had
been completed satisfactorily.
The_ licensee implemented the following corrective actions: (a) the
test leads were properly labeled for both units; (b) procedure SP
1006B was revised to notify the system engineer or plant
supervision prior to making any internal NIS adjustments; and (c)
the event was discussed with the instrument technicians
emphasizing the need for self-checking and the need for
-
questioning a calibration shift outside of the acceptance
criteria.
The inspectors concluded the licensee's actions were
satisfactory.
The inspectors concluded that the miscalibration had minimal
safety significance. Diverse backup trip functions, such as high
neutron flux overpower, high pressurizer pressure, and high
pressurizer level, were operable.
During the out of calibration
period, the largest f(AI) experienced was 7.67 percent. The
operators attempt to maintain the target flux difference between
3.31 percent i 5 percent when operating above 50 percent power.
The licensee modeled the two Chapter 14 events by applying the
f(AI) penalty at +20 percent (see figure).
In both design basis
events, no core safety limits were exceeded.
,
>
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18
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Figure 1
QL Signal Miscalibration - Prairio Island
120.000
Msca!!bration
k,'.-
100.000 -@
50%,,', %
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80'000 I
T.S.
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1,50 %
-
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60.000 -
%s
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E 2.60%
'
'
40.000
.-
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20.000
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Ar'Mysis PCht
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i
19
,
.
Technical Specification 2.3. A.2.d (OTAT) and TS 2.3. A.2.e (0 PAT)
require that for each percent that the magnitude of *I (Q top - Q
bottom) exceeds +9 percent, the AT trip setpoints be automatically
reduced by an equivalent 2.5 percent of rated thermal power. The
i
licensee operated in a condition where the OTAT and OPAT reactor
trip setpoints would not have been automatically- reduced when al
exceeded +9 percent.
Failure to meet the requirements of TS 2.3.A.2.d and 2.3.A.2.e is considered a violation
(50-282/93008-03(DRP)). The inspectors were particularly
concerned with this violation because one individual adjusted four
redundant reactor trip channels out-of-specification without
questioning the magnitude of adjustment or informing appropriate
licensee staff and without any management oversight or review.
The inspectors discussed this issue with the licensee emphasizing
,
the need for broadly focused and comprehensive corrective action
'
to identify any potential similar situations.
b.
(Closed) Inspection Followuo Item (50-282/93002-01:
50-306/93002-01):
NRC Inspection Report 50-282/93002(DRP);
50-306/93002(DRP) discusses the quality assurance (QA)
classification of valve stem bushings in flow control valves. of
the residual heat removal (RHR) system.
The licensee has
classified the RHR system as ASME Code Class 2, and has designated
RHR system flow control valves as safety-related, QA level 1.
However, the subject bushings are considered non-safety related,
QA level III. The inspectors questioned the licensee regarding
the apparent QA classification of these bushings.
The licensee
f
stated that RHR system flow control valves are considered safety
related, pressure retaining valves, and as such, in accordance
with ASME Code Case N-62-2, " Internal and External Valve Items",
various internal valve components that are not related to the
pressure retaining function of the valve, can be considered
non-safety related, QA level III. As documented in NRC Inspection
Report 50-282/93002(DRP); 50-306/93002(DRP), the inspectors
concluded that since the RHR system flow control valve bushings
are not related to the pressure retaining function of the parent
valve, classification of these bushings as QA-level III appears
justified. However, based on administrative controls referenced
in Corporate Nuclear Administrative Control Directive NIACD 1.3,
and Operations Manual procedure H1-A, all internal valve
,
components for Q-listed valves are by definition QA-level 1,
absent a documented review stating otherwise.
The licensee stated that although a specific technical evaluation
had not been performed per HlACD 1.3 and procedure H1-A in
determining the quality classification of the RHR system flow
control valve bushings, safety evaluation No. 257, dated January
20, 1991, adequately documented a basis for considering these
The inspectors reviewed safety
evaluation No. 257 which was prepared to clarify procurement
requirements.for various internal valve and pump parts such as
flexitallic gaskets, packing, and mechanical seals.
The safety
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evaluation references subsections NB, NC, and ND of the ASME Code
'
(1980 Edition) and associated articles NB-2000, NC-2000, and
ND-2000 that define material requirements for Code Class 1, 2, and
3 components, respectively.
In discussing material requirements
for pressure retaining components, the subject safety evaluation
,
references the following statements common to each of the NB-2000,
!
NC-2000, and NC-2000 articles.
"The term pressure retaining
material as used in this subsection applies to items such as
'
vessel shells, heads, and nozzles; pipes, tubes, and fittings;
valve bodies, bonnets, and disks; pump casings and covers; and
bolting which joins pressure retaining items. The requirements of
l
this article do not apply to items not associated with the
pressure retaining function of a component, such as shafts, stems,
trim, spray nozzles, bearings, bushings,_ springs, and wear plates,
nor to seals, packing, gaskets, valve seats, and ceramic
insulating material and special alloys used as seal material in
electrical penetration assemblies."
'
Safety Evaluation No. 257 also references ASME Code Case N-62-2
q
which discusses rules for construction of internal and external
valve items other than valve bodies and bonnets.
The inspectors
-
reviewed this code case. The code case classifies valve
components into eight categories and states that material
manufacturers or material suppliers for Category 4 through 8 valve
,
items are not required to comply with Section III Part NCA-3800,
" Metallic Material Manufacturer's and Material Suppliers Quality
.
System Program," of the ASME Code. The code case lists shaft
bearings (bushings) as a Category 7 item and therefore, these
bushings are not subject to Code requirements for material
i
traceability.
Based on review of safety evaluation No. 257 and
'
ASME Code Case N-62-2, the inspectors concluded that
classification of the RHR system flow control valve bushings as QA
level III is justified.
l
The licensee stated that Operations Manual procedure H1-A would be
-
revised to reference ASME Code Cases N-119-4, " Pump Internal
Items," and N-62-2 in determining the quality classification of
'
internal components for pumps and valves, respectively, that
perform a pressure retaining function. The inspectors did not
have any_further questions regarding this issue.
This item is~
t
closed.
One violation was identified.
No deviations, unresolved or inspection
.
followup items were identified.
'
7.
Licensee Event Renort (LER) Followun (92700. 92701. 37700)
a.
(Closed) LER 50-282/92007: Design basis reconstitution effort
!
identified a condition outside the plant design basis.
The licensee identified.in a 1992 Design Basis Reconstitution
Effort finding that emergency diesel generator (EDG).D1 was
t
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potentially vulnerable to damage due to a tornado-driven missile.
Incapacitation of EDG D1 due to a tornado and an assumed single
failure of EDG D2 could have resulted in a loss of all AC power.
-As discussed in NRC Inspection Report 50-282/92011(DRP);
50-306/920ll(DRP), the licensee installed an interim missile
barrier, pending the completion of a detailed analysis of the
as-built configuration.
The inspectors reviewed the licensee's safety evaluation,
No. 328 - Addendum 1, "D1 Generator Tornado Missile Protection,"
u
and Calculation Gen-PI-002, Rev.1, "Probabilistic Risk Assessment
'
of D1 EDG Room Door Vulnerability to Tornado Missiles," and the
NRC's Standard Review Plan. The Standard Review Plan identifies
that 10 CFR Part 100 requirements are met if the probability of
site proximity missiles impacting the plant and causing
radiological consequences greater than 10 CFR Part 100 exposure
guidelines is less than about 10" per year. The results of the
licensee's probabilistic risk analysis indicated that the
probability of incapacitation of D1 due to a tornado missile and
the simultaneous failure of D2 is about 10-* per year, a result
which indicates that the as-built configuration is acceptable.
The Operations Committee reviewed the safety evaluation and
requested that EDG availability be considered in addition to
reliability. This review, however, was not complete at the
conclusion of the report period.
Based upon the inspectors'
,
review of the LER, the safety evaluation, analyses, and
discussions with engineering staff, this LER is closed.
b.
(0 pen) LER 50-282/93006:
Automatic start of No. 121 Cooling Water
Pump on low header pressure while aligned for safeguards
'
operation.
At 3:24 p.m. (CST) on March 25,1993, No.121 motor-driven cooling
water (CW) pump started automatically on low header pressure while
aligned for safeguards operation.
The licensee was performing
surveillance test SP 1106B, "No. 22 Diesel Cooling Water Pump
Test," to satisfy post-maintenance testing requirements for No. 22
diesel-driven CW pump.
This event is further discussed in NRC
Inspection Report 50-282/93002(DRP); 50-306/93002(DRP).
The licensee's corrective action to prevent recurrence for this
event, as described in the LER, was to discuss the event with
those individuals involved in the weekly work planning meeting.
In addition, the licensee vill revise the surveillance procedures
j
for testing the diesel-driven CW pumps to. clarify the instructions
,
for disposition of the pump discharge header valves. The
j
inspectors will evaluate the adequacy of the licensee's corrective
actions during a future inspection.
c.
IClosed) LER 50-282/93007: Discovery that certain valves should
be subject to ASME Section XI testing.
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During a review of the feedwater system as part of the design
basis reconstitution program, the licensee identified that four
feedwater system valves required to mitigate the consequences of
an accident were not included in the ASME Section XI inservice
inspection and testing program.
Subsequent to this discovery
while developing the inservice inspection and testing program for
the third ten-year interval, the licensee identified.40 additional
valves that had not been included in the original program.
The
subject valves were originally classified as ASME Code Class MC
(metal containment) and were therefore not included in the
licensee's original inservice testing (IST) program implemented.in
1976. These valves should have been classified as ASME Code Class
2 valves. The licensee performed an evaluation, referenced = in the
LER, to determine if the failure to perform required Section'XI
testing for these valves constituted an operability issue. This
evaluation included valve position verification and a review of
historical data, testing and inspection results. The licensee
concluded that there was no operability concern with the missed
testing,
The licensee's corrective action for this event, as addressed in
the LER, will be to test the subject valves in accordance with
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Section XI requirements during the next cold shutdown for the
respective units for 32 of the 44 valves.
The remaining 12 valves
will be tested by August 1,1993.
In addition, all 44 valves will
be included in the third ten-year IST program.
The failure to perform required ASME Section XI IST is an apparent
violation of Technical Specification 4.2.A.2 which states that IST
of ASME Code Class 1, 2, and 3 pumps and valves shall be performed
in accordance with Section XI of the ASME Boiler and Pressure
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Vessel Code and applicable Addenda as required by 10 CFR Part 50,-
Section 50.55(g), except where specific written relief has been
granted by the NRC.
This issue will be reviewed by an NRC Region
,
III IST specialist during the next scheduled IST inspection. This
is considered an unresolved item 50-282/93008-04 pending an
evaluation of the safety significance and adequacy of the
corrective action addressed in the LER.
This LER is therefore
closed.
d.
(Closed) LER 50-306/93002:
Loss of administrative control of an
inoperable containment isolation valve due to personnel error.
This event is discussed in paragraph 1.b.
The inspectors will
evaluate the adequacy of the licensee's corrective action for this
event, as described in the licensee's response to the Notice of
Violation during a future inspection.
This LER is closed.
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One unresolved item was identified.
No violations, deviations or
inspection followup items were identified.
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8.
Contacts With Members of the Public (94703)
A management meeting was conducted at the Prairie Island Training Center
on April 23, 1993, to present the NRC's Systematic Assessment of
Licensee Performance (SALP) Report for Prairie Island.
Following the
meeting, the inspectors met wit l1 members of the public who were in
attendance. Two individuals requested information regarding issues
affecting the nuclear industry and their specific relevance to Prairie
Island.
These issues included the use of Thermo-Lag Fire Barrier
Material and primary water stress corrosion cracking of control rod
drive penetrations.
Copies of materials available in the NRC Public
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Document Room such as NRC Bulletins, Information Notices, licensee
correspondence, inspection reports, and SALP reports were provided under
separate cover to the individuals.
penetrations is discussed further in paragraph 4.b.
B
9.
(Closed) AMS No. RIII-93-A-0009
The inspectors performed a review in response to concerns regarding the
inability to perform inspections of encapsulated welds in the main. steam
system and possible design deficiencies in the auxiliary building
ventilation system. The concerns were not substantiated.
,
a.
Encapsulated Main Steam System Welds
Section XI of the ASME Boiler and Pressure Vessel Code provides
rules that nuclear plant owners must follow for the inservice
inspection of plant components.
10 CFR 50.55a requires nuclear
plant licensees to adhere to the ASME Code.
However, in cases
,
where a licer,see has determined that it is impractical to conform
with a code requirement at its facility, it may request NRC-
approval for relief from the requirement.
The licensee requested relief from performing code-required;
inspections of certain welds in the main steam piping at Prairie
Island Units 1 and 2 that are inaccessible due to their-
encapsulation within sections of guard piping.
The NRC staff
reviewed this request for relief from inspection of these~ welds
,
and documented approval of the relief request, with certain
contingencies, in Safety Evaluations (SEs) dated
November 14, 1980, and December-28, 1984. -These SEs documented
NRC approval of the licensee's inservice inspection program per
the requirements of 10 CFR 50.55a.
The contingency imposed by the NRC in approval of the request for
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relief from inspecting these encapsulated welds, was that the
licensee must perform a visual-inspection of the' surrounding area
to look for leaks during a main steam pressure test, to be '
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conducted-at 3 1/3 year intervals.
The inspectors verified that
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this inspection had been completed for both units within the
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required time interval. This visual inspection of the area,
combined with the routine code-required inspection of other welds,
provides reasonable assurance of continued safe plant operation.
b.
Auxiliary Buildina Ventilation System
The ventilation of the auxiliary building is provided by the
normal ventilation system and the auxiliary building special
ventilation system (ABSVS), a safeguards system.
The ABSVS serves
to collect and filter any potential post-accident coniainmr '
leakage before reaching the environment.
The normal venti.s ,i
system uses a fresh air supply and no filtration before ext.aust to
the environment.
If there is an accident, receipt of a high
radiation signal or a safety injection signal actuates the ABSVS,
trips normal ventilation system supply and exhaust -fans, and -
closes normal ventilation system supply and exhaust dampers. This
design provides for the collection and filtration, by the ABSVS,
of air in the auxiliary building before it is exhausted to the
environment.
No violations, deviations, unresolved or inspection followup items were
identified.
10.
Followup on Reaional Reouests
a.
Inadvertent Reactivity Insertion from Reactor Coolant Pump (RCP)
Restart
The NRC has recently issued NUREG/CR-5822, " Analysis of Thermal
Mixing and Boron Dilution in a PWR." This document identifies a
scenario which could result in an unintended positive reactivity
The scenario described a plant in the beginning of its
fuel cycle, in_ hot standby with RCPs running, and with a boron
dilution in progress. The analysis evaluated the amount of
thermal mixing and boron mixing that would occur if the RCPs
tripped and boron dilution continued via seal injection.
The
results indicated that boron mixing in the reactor coolant system
(RCS) would be minimal in these conditions because there would be
little flow due to natural circulation. An unborated slug of
coolant could develop and upon RCP restart, a significant positive
reactivity insertion could occur.
The inspectors reviewed licensee controls for precluding a similar
event from occurring at Prairie Island. The_ licensee's nuclear
analysis department has not performed a detailed analysis
regarding this'particular transient.
However, NRC Information
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Notice (IN) 91-54, " Foreign Experience Regarding Boron Dilution,"
which was received by the licensee, discusses a scenario similar
to the one addressed in_NUREG/CR-5822. After reviewing the IN,
the licensee implemented procedural and administrative controls Lto-
preclude a similar event from occurring. These measures include:
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1.
A precaution in the RCP operating procedure and a limitation-
in the unit startup procedure stating, "Do not restart a
tripped RCP if the trip occurred while dilution was in
progress, until sufficient time has elapsed to ensure
thorough mixing of the RCS."
2.
A precaution in the reactor makeup control system operating
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procedure stating, "A minimum of one RCP or RHR pump.must be
operating during any boron dilution step."
3.
An initial action in the alarm response guide for RCS low
flow to "stop any dilution, if in progress."
Based upon review of the licensee's administrative controls, the
inspectors concluded that the licensee had implemented measures to
prevent this inadvertent positive reactivity insertion transient,
b.
Low Temperature Overoressure Protection (LTOP)
'
An issue was identified at another nuclear power plant involving
calculations to determine the setpoints for LTOP which did not
compensate for pressure drops due to piping and other components
between' the reactor pressure vessel and the pressure transmitters.
This issue had potential generic applications.for all Westinghouse-
PWRs.
The presence of improper /non-conservative LTOP setpoint
settings could allow an overpressure condition to exist which
could potentially cause brittle fracture of the reactor pressure
vessel.
The inspectors reviewed the licensee's engineering evaluation of
the applicability of this issue to the Prairie Island units. At
the plant at which this issue was identified, RCS pressure
transmitters are located in the intermediate leg of the RCS.
In
addition to accounting for instrument error and the pressure drop
associated with the hot leg and intermediate leg piping, this
location necessitates compensation for the significant pressure
drop across a steam generator. The pressure transmitters for the
Prairie Island units are located on the hot leg of the RCS.
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Compensation for a steam generator pressure drop is therefore not
required.
The licensee's reactor vessel heatup and cooldown limit curves
contain a margin of 60 psig, intended to allow for instrumentation-
error. The actual pressure transmitter error value ' calculated by
the licensee is +/- 29.1 psig. The calculated pressure drop due
to the reactor vessel itself was determined to be about 20 psig,
and.the pressure drop from the hot leg piping to the transmitters
was considered negligible.
The combination of the instrumentation
error and pressure drops is still less than the margin inherent'in
the limit curves. Therefore, the licensee concluded the LTOP
settings are adequate. The inspectors concluded that the
licensee's review of this issue was adequate.
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No violations, deviations, unresolved or inspection followup items were
identified.
11.
Safety Audit Committee Meetina (40500)
<
The inspectors attended portions of the licensee's Safety Audit
Committee (SAC) meeting on April 1, 1993. The SAC is the licensee's
offsite safety review committee and meets quarterly to discuss plant
events, organizational changes, iicense amendment requests and other
regulatory correspondence, quality assurance audits, and other various
.
items of interest.
During the April 1 meeting, the inspectors observed
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discussions on the review of selected plant events for closecut, the
status of the station blackout / electrical systems upgrade project, the
response to Notices of Violation concerning security of safeguards
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information, an investigation summary of fitness-for-duty concerns at
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Prairie Island, and the annual security audit.
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The inspectors noted that the meeting was characterized by an open
exchange of information, discussions were detailed and accurate, and
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that the committee exhibited an appropriate safety perspective as
reflected in the nature of questions to the licensee's staff.
No violations, deviations, unresolved or inspection followup items were
identified.
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12.
Independent Spent Fuel Storace Installation (ISFSI) (37700)
The inspectors reviewed activities associated with the construction and
planned operation of the licensee's ISFSI.
Review of the licensee's
application to operate an ISFSI under the regulations contained in
10 CFR Part 72 is the responsibility of the NRC's Office of Nuclear
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Material Safety and Safeguards (NMSS) and is in progress. The
inspectors' activities included a review of the proposed technical
specifications for the ISFSI, (comments were forwarded to NRC personnel
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in HMSS), and tours of the ISFSI construction site, including
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observations of the construction of the earthen berm surrounding the
concrete ISFSI storage pads.
13.
Unresolved Items
Unresolved items are matters about which more inforriation is required in
order to ascertain whether they are acceptable items, violations, or
deviations. An unresolved item is discussed in paragraph 7.c.
14.
Inspection Followup Items
Inspection followup items involve activities which were not completed
within the inspection period, where additional inspection is necessary
and planned.
An inspection followup item is discussed in paragraph 1.c.
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15.
Manaaement Interview (71707)
The inspectors met with the licensee representatives denoted in
paragraph 16 after the conclusion of the report period on June 4, 1993.
The inspectors discussed the purpose and scope of the inspection and the
findings. The inspectors also discussed the likely information content.
of the inspection report with regard to documents or processes. reviewed
>
by the inspectors during the inspection. The licensee did not identify
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any documents or processes as proprietary.
16.
Persons Contacted
E. Watzl, General Manager, Prairie Island
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- M. Wadley, Plant Manager
K. Albrecht, General Superintendent, Engineering
- G. Lenertz, General Superintendent, Maintenance
R. Lindsey, Assistant to the Plant Manager
D. Schuelke,. General Superintendent, Radiation Protection
and Chemistry
J. Sorenson, General Superintendent of Plant Operations
G. Miller, Superintendent, Technical Support
- M. Reddemann, General Superintendent, Electrical and
Instrumentation Systems
- G. Rolfson, General Superintendent, Nuclear Projects Department
- J. Mcdonald, Superintendent, Site Quality Assurance
- A. Hunstad, Staff Engineer
- J. Hill, Superintendent, Instrumentation and Controls
Systems
- P. Ryan, Operations Shift Manager
M. Klee, Superintendent,. Quality Services
- J. Maki, Superintendent, Electrical Systems
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E. Eckholt, Nuclear Support Services
- J. Leveille, Nuclear Support Services
- G. Aandahl, Superintendent Design Standards
C. Mundt, Production Engineer
J. Donatell, Production Engineer
S. Schaefer, Production Engineer
R. Waterman, Nuclear Engineer
- M. Dapas, NRC Senior Resident Inspector
- R. Bywater, NRC Resident Inspector
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- Denotes those present at the management interview of June 4,1993.
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