ML20029A168
| ML20029A168 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 01/28/1991 |
| From: | Jorgensen B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20029A167 | List: |
| References | |
| 50-282-90-19, 50-306-90-20, NUDOCS 9102050002 | |
| Download: ML20029A168 (15) | |
See also: IR 05000282/1990019
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U. S. NUCLEAR REGULATORY COMMISSION'
REGION Ill
Reports No. 50-282/90019(DRP);50-306/90020(DRP)
Docket Nos. 50-282; 50-306
License Nos. OPR-42; DPR-60
Licensee: Northern States Power Company
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414 Nicollet Mall
Minneapolis, MN 55401
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Tacility Name:
Prairie Island Nuclear Generating Plant
Inspection At:
Prairie Island Site, Red Wing, MN
Inspection Conducted:
November 20, 1990 through January 14, 1991
Inspectors:
P. L. Hartmann
D. C. Kosloff
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Approved By:
B.'L. J rg sen, Chief
i/m/pt
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Reactor rojects Section 2A
Date
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Insp_ection Summary
Inspection on November 20, 1990 through January 14, 199_1
50-282/90019(DRP); 50-306/90020(DRP))
TheportsNo.
K'reas Inspected:- Routinh unannounced inspection by resident inspectors of
-Licensee Action-on Previous Items, Plant Operational Safety, Maintenance.
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Surveillance, Licensee Event Reports, Regional Initiatives,'and Cold Weather
-Preparations.-
=Results:
In the seven areas inspected, two non-cited violations of NRC
requirements were identified and are discussed below. One unresolved item
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identified in the security area is-also' discussed below.
1
Operations
Unit 1 operated at- full power, interrupted by one reactor trip an'd a brief
power reduction for main condenser cleaning. Unit 2. operated at full power,
interrupted by one reactor trip. Each trip was from full power and recovery-
_
The component failures which initiated each trip are-
was prompt in each case.
A non-cited
discussed below in the Engineering and Technical Support Section.
violation, involving f ailure to establish a continuous fire watch within one
,
The event had minimal safety impact because an hourly.
hour, was identified. fire watch patrol was initially _ established (instead of a continu
9102050002 910128
ADOCK 05000282
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and the one hour requirement was exceeded by only six minutes.
This event is
discussed in paragraph 6.c.
In addition, a shift supervisor found a valve open
in a 3/4-inch line penetrating containment. This event also had minimal safety
impact; there were other closed valves in the line.
Maintena_nce and Surveillanc_e
No deficiencies were noted by the inspectors' observation of work activities.
Engineering _and Te_chnical Support
Two reactor trips occurred which involved equipment failure and system design
wea knes ses . On November 21, 1990, the Unit I reactor tripped from a turbine
trip at 100 percent power.
The turbine trip was caused by a generator trip
on high bus duct temperature. A failed circuit breaker for one bus duct
.
cooling fan led to the elevated bus duct temperature.
This event is discussed
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c
in paragraph 6.d.
On December 29, 1990, the Unit 2 reactor tripped from a high
negative flux rate caused by rod control system component failures.
This event
is discussed in paragraph 3.b.
In addition, engineers found that, due to an
inadequate understanding of the cooling water design, several cooling water
valves and chill water velves had not been included in the inservice test
program.
This event is discussed in paragraph 6.e.
Also, a non-cited
violation for exceeding a Technical Specification cooldown rate for the
Unit 1 pressurizer was identified.
This event is discussed in paragraph 6.a.
Security
A fitness-for-duty is.ue is discussed in paragraph 7.b.
An unresolved item is
assigned to an event involving unescorted access screening.
Safety Assessment / Quality Verification
The insoectors determined that there were several discrepancies between the
containnent penetration table in the Technical Specifications (TS) and the
contairnnent penetration table in the Updated Safety Analysis Report. This
combined with other deficiencies in the containment penetration TS text make
it difficult to understand the intent of the TS. This situation is discussed
in Paragraph 6.e.
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DETA_I L_S
1.
Per_s_o_ns_ Contacted
_No_rthern States Power Company _(NS_P)
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- L. Eliason, Vice President Nuclear Generation
- C
Blair, Executive Vice Precident ' Power Supply
- E. Watzl, General Manager, Prairie Island Site
- H. Sellman, Plant Manager
- M. Wadley, General Superintendent, Operations
- D. Mendele, General Superintendent, Engineering
- G. Lenertz, General Superintendent, Maintenance
A. Snith, General Superintendent, Planning and Services
- R. Lindsey, Assistant to the Plant Manager
- D. Schuelke, General Superintendent, Radiaticn Protection
- G. Miller, Superintendent, Operations Engineering
- K. Beadell, Superintendent, Technical Engineering
T. Breene, Superintendent, Technical Engineering
- M. Klee, Superintendent, Quality Engineering
- D
Musolf, General Manager, Nuclear Support
- B. Stephens, Superintendent, Design Standard Engineering NPD
- G. Goering, Manager, Nuclear Projects Department
- A. Hunstad, Staff-Engineer
R. Conklin, Supervisor, Security.and Services
J. Leveille, Nuclear Support Services
'*E. Eckholt, Plant Licensing Engineer
U._._S. Nuclear Regulatory Commission (U.S. NRC)
- C, Paperiello, Deputy Regional Administrator
- H. Miller, Director, Division of Reactor Projects
- T. Martin, Director, Division of Reactor Safety
- M. R'ng, Chief, Engineering Branch
- H Clayton, Chief, Projects Branch 2
- M. Phillips, Chief, Operational Programs Section
- B. Jorgensen, Chief, Projects Section 2A
- I
Yin, Senior Mechanical Engineer
- P. Hartmann, Senior Resident Inspector
- E. Schweibinz, Senior Project Engineer
- R. Bywater, Reactor Engineer
- N. Choules, Reactor Engineer
- R. Langstaff, Reactor Inspector
- D. Kosloff, Resident Inspector
- C
Brown, Reactor Engineer-
- Denotes those present at the exit interview of January 15, 1991.
'
- Denotes those present at the Management Meeting in Region III on
December 6, 1990.
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'2.
Li_cen_s_ee_ Action on_P_revious Inspection Findings (92701, 92702)
-a.
(Closed) Violation __(50_-282/88012-02(DRP)): Failure to Stoke Time
Test" Pressurizer Power Operated Relief Valves (PORVs)
The inspector identified that the h
urizer PORVs had never been
stoke time tested prior to January of 1988.
Because the-licensee had
not classified these valves as ASME Code Classes 1, 2, or 3 valves,
it had not included-them in its ASME Section XI testing program.
The
licensee had developed testing requirements and added the pressurizer
PORVs to'the testing program prior to the issuance of the violation.
Surveillance Procedures (SP) 1291 and 2291, " Pressurizer PORV Stoke
Timing'l, were also implemented prior to the issuance of the violation.
The inspector verified _the surveillances-have been performed at the
frequency required since the violation was issued.
This matter is
closed.
(
Failure to Perform
lClosed) Violation (50_-282/88019-01(DRP)):
b.
ersonnel Airlock Door Seal Test
Technical-Specification,-4.4.A.2 Containment Leakage Tests, requires
thatthecontainmentpersonnelalrlockdoorsealsbeseal-tested-by
SP 1132 (2132) within three days of opening the personnel-airlock. A
violation was issued following a second example of not performing
this surveillance when required.
In response, the licensee performed
the test and emphasized testing'requireuents to involved personnel.
The inspector identified several recent containment entries and
reviewed the' tests completed following the entries.
No anomalies
were noted.
Licensee performance related to this surveillance
requirement appears adequate. This matter is closed.
c.
(Closed) Unresolved Item (282/89024-01(DRP); 306/89024-01(DRP)):
-Ti1Tegral Welded Attachments (IWA) with Increased Loads Were not
Evaluated for Acceptability
A Region III inspector reviewed Calculation No. 0910-242-001,
" Prairie Island IWA Criteria / Evaluation", Revision 0, February 1990.
This calculation, generated by the licensee to address this issue,
evaluated 159 IWAs with load increases. These loadt were derived
from IE Bulletin 79-14 reanalyses or later modification calculations.
All of the welds associated with the IWAs were shown to be acceptable.
The effects of localized stresses on the piping components were also
shown to meet the original design code. The IWA evaluation
methodology will be proceduralized to prevent future questions
and to assure consistent application of acceptance criteria.
No discrepancies or inconsistencies were noted in the calculation by
the inspector.
In all cases the methodology appeared to be
conservative. Since no modifications were required to any of the
pipe supports with IWAs, the licensee concluded that the original
design criteria was sufficiently conservative.
Based on the above
discussion, this item is closed.
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d._
(Closed) Violation (282/880201-01; 306/880201-01):
Inadequate
evaluations f or use of commercial ~~g'FWe items BTal's) in
safety-related systems
By letter dated November 29, 1990, the licensee committed to improve
the CGI evaluaticn process.
Based on a review of these proposed
actions, the inspector determined that the process-described is
adequate and this item is closed.
No violations, deviations, unresolved, or open items were identified.
3.
Operational _ Saf_e_ty Verificatf o_n (7_1707, 93702)
a.
Routine Inspection
The inspector observed control room operations, reviewed applicable
logs, conducted discussions with control room optrators and observed
shif t turnovers.
The inspector verified operability of selected
emergency systems, reviewed equipment control records, and verified
the 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, and to verify that maintenance work requests had been
initiated for the equipment in need of maintenance. The inspectors
reviewed a third party audit of plant performance for a two-year
period which revealed no significant safety issues.
-b ,
Event Followup.
On November 21, 1990, at 3:45 p.m., the Unit I reactor tripped from
a main turbine trip while the unit was at full power.
The cause of
the turbine trip was determined to be a breaker tripping open for
the in-service main transformer bus duct cooling fan without the
-standby bus-duct fan starting.
The intent of the circuit design was
for the standby bus duct fan to be energized and prevent a generator
lockout (and generator trip) from high bus duct temperature.
However, the circuit design did not achieve the intended design
function.
Followino replacement of an intermediate range detector
ana-other minor repairs in the secondary plant, the unit was
restarted at 10:29 a s , and was placed on-line at 3:41 p.m.
on November 22, 1990. This event is discussed further in
paragraph 6.d.
At approximately 3:45 a.m. on December 10, 1990, a shift supervisor
(SS) found valve 2S1-20-16, Test Line Flow Instrument inlet
Isolation, open.
By procedure the valve should have been closed.
The SS immediately closed the valve.
Initially, the licensee
considered the valve to be a containment isolation valve.
Therefore, since the valve was found open and not administratively
controlled, this was considered to be contrary to Technical Specification 3.6.C.1.
However, upon further review, the licensee
concluded that the Technical Specifications did not require the
valve to be closed. After discussing the event with the inspectors,
the licensee stated that it would report the event and its
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evaluation in a'su?plement to LER 50-282/90018 (discussed in
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paragraph 6.e of_tais inspection report). The inspectors will -
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complete their evaluation of this event during their review of the
LER supplement.
On December 29,1990, at 10:34 p.m., the Unit 2 reactor tripped from
a negative flux rate trip while the unit was at full power.
All
safety systems functioned as designed. The cause of the negative
flux rate trip was determined to be a failure of the stationary coil
group B regulator circuit card in the rod control system.
The
reference voltage (v-ref) provided by this card fell to zero, which
removed current to the stationary coils for the four control bank 0
rods. _These rods fell into the reactor, causing the negative flux-
rate trip. The intent of the rod control circuit design is for the
alarm card to detect a loss of v-ref and generate an " urgent failure"
condition. This 3revents-the affected rods from dropping by applying
hold current to t1e moveable coils.
However, due to a simultaneous
or previous alarm card failure, this intended design function was not
achieved.
Following replacement and testing of the alarm and
regulator cards, the unit was restarted at 10:34 a.m. and-placed
on-line at 1:32 p.m. on December 30, 1990.
The licensee has experienced previous reactor trips on Unit 2 due to
similar rod control component failures (December 21 and 26, 1989).
In response, the licensee conducted rod control circuitry
refurbishment during the winter 1990 Unit I refueling outage and the
fall 1990 Unit 2 outage. The licensee is evaluating the merits of
that activity, which is conducted by a vendor. The inspectors will
review the licensee corrective actions within LER 50-306/90013.
No violations, deviations, unresolved or open items were
identified.
4.
MaintenanceObservation(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 removed from service,
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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 during the
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inspection period:
Troubleshooting and Repair of Unit 2 Rod Control Power Cabinet 2BD
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Troubleshooting and Repair of Unit 1 Rod Position Indication
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Preventive Maintenance of No. 12 Diesel Cooling Water Pump
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Troubleshooting of Unit 1 Intermediate Range Nuclear Instrumentation
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Pouring of Concrete Wall for New Emergency Diesel Generator (EDG)
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Building. While a contractor was pouring concrete for the north
wall of the new EDG building, the forms allowed concrete to escape
into the space between the new EDG building and the existing metal
wall of the turbine building.
The licensee's initial evaluation of
this condition concluded that the structural integrity of the wall
was not adversely affected. The inspectors discussed the condition
with a Region III specialist, who has discussed the condition
further with the licensee. The Region-III inspector will review the
licensee's documentation and verification activities related to this
condition in a future inspection.
No violations, deviations, unresolved, or open items were identified.
5.
Surveillance (6_1726,_71707)
The inspector witnessed portions of surveillance testing of
safety-related systems and components. The inspection included
verifying that the tests were scheduled and performed within
Technical Specification requirements, observing that procedures
were being followed by qualified operators, that Limiting Conditions
for Operation (LCOs) were not violated, that system and equipment
restoration was completed, and that test results were acceptable to
Technical Specification and procedural requirements.
Portions of the following activities were observed:
SP 1093
D1 Diesel Generator Slow Start and Train A Auto Load
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Sequencer Test
SP 1091'
Containment Fan Coil Units Surveillance Test
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While testing the operation of the Fan Coil Units' motors,
the licensee found that one of the associated ventilation
dampers appeared to have failed in its safety position.
Licensee personnel entered containment and verified that
the damper was in its safety position.
Later, the
licensee determined that the failure resulted from a
fuse losing continuity with its fuse holder. This is an
example of a plant aging issue which has been previously
identified on other plant systems. The licensee is
continuing with its plant-wide program to eliminate this
problem. The inspectors will continue to monitor the
licensee's progress with this program.
SP 1158
Cooling Water Valve Test (Unit 1)
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The inspectors observed testing of valves which had
mistakenly been excluded from the test. The test was
used to establish a base line operating time and was
controlled as a maintenance activity so the test
procedure was not used.
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SP 2158
Cooling Water Valve Test (Unit 2)
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This test was performed in the same manner as SP 1158.
No violations, deviations, unresolved, or open items were identified.
6.
LER Fol_lowup (92700)
a.
(Closed) LER_ 50_-282/9000_2_-LL :
Excessive Pressurizer Cooldown Rate
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and Excessive Spray / Pressurizer Temperature Difference
This LER described a Technical Specification (TS) violation in which
the cooldown rate limit of 200 degrees F/ hour for the pressurizer and
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the limiting temperature difference of 320 degrees F between the
pressurizer auxiliary spray and the pressurizer had been exceeded.
In this case, the licensee violated TS 3.1.B.2.
Specifically, the
maximum cooldown rate for the pressurizer was 265 degrees F/ hour
measured by the pressurizer water space temperature.
During the
cooldown, the operators verified the temperature difference between
the pressurizer and the pressurizer auxiliary spray as being less
than 320 degrees F by using the control board indication.
Later, a
more precise determination was obtained by using the Emergency
Response Computer System (ERCS) which indicated an actual temperature
difference of 349 degrees F.
The ERCS was used on the cooldown to
gather surge line thermal stress information.
Upon discovery of
these anomalies, the licensee modified the cooldown procedure (C.1.)
so that the pressurizer water space temperature is used in computing
the cooldown rate and the ERCS is used to determine the temperature
difference between the pressurizer and the pressurizer auxiliary
spray.
In addition, the licensee contracted Westinghouse Electric
Corporation to determine whether the repetitive pressurizer cooldowns
and heatups had any effect on the vessel protection against brittle
failure and on the approach to fatigue limits for transients of-this
type.
By letter dated May 23, 1990, Westinghouse Electric Corporation
issued a report titled, " Rapid Pressurizer Cooldown and Heatup
Evaluation for Northern States Power Company, Prairie Icland Unit 1"
(MT-SMDT-167 Rev. 1). This report, which was reviewed by NRR staff,
assesses the structural stability of the pressurizer vessel when
subjected to the cooldown and heatup transients described in the LER.
The report covers fracture mechanics and fatigue analyses at the
critical locations of the pressure vessel when subjected to 50
thermal transients. The analysis considered the possibility of
vessel failure by an abrupt and brittle fracture mechanism which is
conservative relative to other failn ~ modes. The effects on the
fatigue limit-being approached were aise considered. The report
concludes that transients have not compronMed the structural
integrity of the pressurizer.
NRR agreed witi the conclusions o'ren
in the report based on review of the analyses.
In additic.,, NRR
found the corrective action, revising the plant cooldov;, procedure,
would ensure that the fatigue limits would not be c.npromised in the
future.
The inspector verified the cooldown procedure was revised.
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This licensee-identified violation (50-282/90019-01(DRP)) of TS is
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not being cited because the criteria specified in 10 CFR 2, Appendix
C, Section'V.G. of the NRC Enforcement Policy were satisfied.
This
exercise of discretion is being given because the NRC wants to
encourage and support licensee. initiative for self-identification and
-correction of problems. A non-cited violation must meet all of the-
following_ criteria: _(:) It was identified by the licensee; (b) It is
normally classified as a Severity Level IV or V; (c) It was reported,
if required; (d) It was or will be corrected, including measures to
prevent recurrence, within a reasonable time; and (e) It was not a
willful violation or a violation that could reasonably be expected to
have been prevented by the licensee's corrective action for a
previous violation,
b.
(Closed) LER 50-306/90009-LL:
Unit 2 Reactor Trip from Zero Power
Wen Fuses Were Removed From the Wrong Nuclear Instrumentation
Channel Drawer
On October 7, 1990, Unit 2 was critical at zero power following a
refueling outage.
Zero power physics testing had just been completed.
The reactivity computer used for physics testing was to be
disconnected from Nuclear Instrumentation Power Range Channel N41.
An instrument and control (I&C) technicier, when assigned to do_the
work,. reviewed the controlling procedure and the logic diagrams to
determine required actions. With procedure in hand, he removed the
control power and instrument power fuses from the front panel of NIS
Intermediate Range Channel N35 instead of Power Range Channel N41.
This caused a unit trip signal, because the intermediate range
nuclear instruments utilize a one of two logic verses the two of four
logic utilized by the power range instruments.
Cause of the event was personnel error in removing fuses from the
wrong NIS channel drawer.--Channel N35 $s immediately above Channel
N41 on the NIS rack which led to the error.
The technician failed to
use self-checking when removing the fuses.
The licensee corrective action included counseling the I&C-technician
regarding the self-checking-plant policy and revising the controlling
procedure D-30, " Post Refueling Start-Up Testing". - The inspector
verified the procedure was changed (Rev. 20) to utilize power range
channel N44, since an intermediate range channel is not above this
power range d-awer.
The licensee also improved labeling of the
nuclear instrument panel covers and the inspector verified the
change.
This matter is closed.
c.
(Closed)-LER 50-282/90016-LL:
Failure to Establish a Continuous Fire
Nitch When Removing a Sprinkler System from Service Caused by
Inadequate Procedure
On November 6,1990, both units were at 100 percent power.
Surveillance procedure SP 1196, " Fire Protection Safety-related
Sprinkler System Test," was in progress. This 18 month surveillance
checks operation of deluge valves, so fire suppression supply water
must be isolated to prevent actual system actuation.
Since the
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procedure would require the sprinkler system in the emergency diesel
generator rooms to be isolated, aersonnel performing the test asked
the Shift Supervisor _to establisi a continuous fire watch in the
rooms. The Shift Supervisor reviewed Technical Specification 3.14.C.2,
and at 9:14 a.m. he ordered the isolation of the zone.and started an
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B;ckup fire suppression equipment had also been
made available to compensate for isolation of the sprinkler system.
When the personnel performing the test entered the zone at 10:20 a.m.
and realized no continuous fire watch was present, they called the
Shift Supervisor to discuss the matter.
The Shif t Supervisor made a
further review of Technical Saecification 3.14.C.2, realized his error,
and at 10:25 a.m. he establis1ed a continuous fire watch.
The licensee identified the cause of-the event as an inadequate
procedure. The surveillance procedure references Technical Specification 3.14, Fire Detection and Prctection Systems, but does
not specifically require establishment of a continuous fire watch
with backup fire suppression equipment.
The procedure contains only
a note that warns that a continuous fire watch is required if the
sprinkler system is out of service for more than an hour.
The Shift
Supervisor misread the fire watch requirement and instead of
establishing _a continuous fire watch within one hour, he established
an hourly fire watc_h.
Technical Specification 3.14.C.2 requires a continuous fire watch
with backup fire suppression equipment to be established within one
- hour whenever the spray and sprinkler system is inoperable.
Backup
fire suppression equipment had been established, but a continuous
fire watch was not established for one hour and six minutes, although-
an hourly firewatch was established.
The inspector discussed the event with licensee management following
the event.
The inspector verified the surveillance procedure was
revised as described in the LER.
Thislicensee-identifiedviolation-(50-282/90019-02(DRP))of
Technical Specification 3.14.C.2 is not being cited because the
criteria specified in 10 tpfs 2, Appendix C,Section V.G. of the NRC
Enforcement Policy were satisfied. This exercise of discretion is
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being given because the_NRC-wants to encourage and support licensee
initiative for self-identification and correction of_ problems.
A
non-cited violation must meet all of the following criteria:
(a)It
was identified by'the licensee; (b) i+ is normally classified as a
Severity Level IV or V;-(c) It was r; parted, if required; (d) It was
or will be corrected,-including measures to prevent recurrence,
within a reasonable time; and (e) It was not a willful violation or a
violation that could reasonably be expected to have been prevented by
the licensee's corrective action for a previous violation,
_C_losed) LER 50-282/900_ _7_-LL:
Reactor Trip Caused by Inadequate
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d.
Design of Main Generator Bus Duct Cooling System
On November 21, 1990, while Unit I was at full power, a non-licensed
operator noticed that there was no indication that either Unit 1 Bus
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Duct Cooling Fan was operating.
Normally one fan is operating and
-one is in standby.
Af ter finding the breaker tripped for No.11 Bus
Duct Cooling Fan, the operator discussed the condition with the
control room and was instructed to start the No.12 Bus Duct Cooling
Fan. 'There were no alarms in the control room and the bus duct
temperature indication in the control room was not abnormally high.
The unit tripped shortly af ter the fan was started.
The inspector
responded to the control room and observed trip recovery activities.
One rod-at-bottom light was not lit immediately after the trip but it
did light a short time later.
The licensee concluded that this
problem was due to dirty electrical contacts on a signal conditioning
circuit card. The contacts were cleaned and the system was restored
to normal. An intermediate range flux detector also failed and was
replaced. All of the manufacturer's recommended diagnostic tests on
the detector had normal results and the failure mechanism is unknown.
Minor balance-of-plant problems occurred and were repaired prior to
restart or shortly thereaf ter.
The licensee determined that the trip was caused by high bus duct air
temperature.
The main generator bus is normally cooled by a bus duct
cooling fan that circulates hot air from the bus duct through a
cooling coil.
The bus duct cooling system is not a safety-related
system. At about 10:45 a.m. on November 21, 1990, Qe circuit
breaker for the operating fan tripped open.
No direct indication of
this condition was provided in the control room.
The bus duct air
resistance temperature detectors (RTDs) are located in the fan
suction duct. When the fan stopped, heated bus duct air was no
longer drawn past the RTDs and the temperature at the RTDs was no
longer representative of the temperature in the bus ducts. The
temperature at the RTDs began to drop (to ambient) as the temperature
in the bus duct began to rise.
The RTDs were inputs for a high
temperature alarm and a computer temperature indication in the
control room.
When the standby fan was started at about 3:45 p.m.,
it blew the hot air from the bus duct past the RTDs and the indicated
temperature quickly exceeded the control room high temperature alarm
setpoint and the main generator trip setpoint. The main turbine
tripped, providing the trip signal which tripped the reactor.
The
licensee's system description (B22B, Rev.1, July 14,1989) for the
main generator incorrectly states that."The standby fan starts
automatically if the primary fan trips . . ." Neither B22B nor the
operatingprocedureforbusductcooling(C22.5, August 1,1975)
describes the location of the temperature detector.
Had these
procedures been more detailed, the operators might have restored the
plant to normal operating conditions without a plant trip.
The licensee concluded that the cause of the event was inadequate
design of the bus duct cooling control system. The inspectors
concluded that the root causes of the event were design weaknesses
in the bus duct cooling control system and alarms, and a lack of
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trainino and procedural guidance to compensate for the design
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weaknesses.
Although th.s LER was more thorough than some past LERF, the
inspectors observed several deficiencies in the LER.
These
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deficiencies were discussed with licensee personnel. The most
significant deficiency was that the LER did not completely describe
the event from the perspective of the operator.
The inspectors verified that the licensee disabled the high bus duct
temperature generator trip, improved procedure C22.5, and initiated a
modification to provide en annunciator alarm to indicate when both
bus duct fans are not operating.
This LER:is closed.
e.
(0 )en) LER__ _5_0 _282/_90018-LL: Discovery That Certair Valves Should Be
Su) ject to AS74E Section XI Testing Found through Design Basis
Reconstruction
The licensee found that several valves in the ;ooling water and
chilled water systems should have been includei in its ASME Section
XI inservice testing program, but they were not
The l_icensee
discussed the findings with the inspectors and A scribed its plans
for verifying the operability of the valves.
The inspector observed
valve operability verification testing and discussed the results with
licensee engineers.
The valves are considered operable.
The
licensee is continuing its evaluation and has committed to submission
of a supplement to this LER.
During the review of this event, the
inspectors discovered errors in the containment penetration table in
_the Technical Specifications and discrepancies between the containment
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penetration table in the TS and the containment penetration table in
the Updated Safety Analysis Report.
These errors and discrepancies
make the intent of the TS unclear.
The inspectors discussed these
errors and discrepancies with the licensee.
The licensee is
developing a method to correct these errors which will be
discussed in the supplement to_the LER. The licensee also stated
that the mispositioning of valve 2SI-20-16 would be discussed in the
supplementtotheLER(seeparagraph3.b.).
The inspectors will
continue to inspect the licensee's efforts in this area fn future
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inspection.
This LER will remain open until the inspectors review
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the licensee's LER supplement.
Two violations (not cited) and no deviations, unresolved, or open items
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were identified.
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7.
_ Regional Initiative _(92701,'TI2515/106)
a.
NRC Region III management has reviewed the existing open items for
the Prairie Island Station and determined that the following open
items will be closed administratively due to their safety
significance relative to emerging priority issues and to the age of
the item. The licensee is reminded that commitments directly
relating to these open items are the responsibility of Lthe licensee
,
and should be met as committed.
NRC Region III will review licensee
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actions by periodically sampling administratively closed items.
(Closed) Bulletin 85003: Motor Oper:ted Valve Common Mode Failures
,
During Plant Transients Due to Improper Switch Settings
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(50-282/85003-BB(DRS);50-306/85003-BB(DRS))
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(Closed) Bulletin 79002, Rev. 1_ Supplement ___1:
Pipe Support Base
PTaWDesigns Using concrete Expansion Anchnr Bolts
(50-306/79002-BB(DRS))
b.
Fitness For Duty _(TI2515/106): One unresolved item was identified
regarding the apparent tailure to conduct a management and medical
determination of fitness for duty for an individual who had received
treatment for alcohol abuse.
During an audit conducted on October 24, 1990, a representative of
the licensee's Corporate Security Department discovered information
that appeared to indicate that a guard at Prairie Island should not
have been granted unescorted access to the site. The licensee
conducted an extensive investigation of the contractors who were
responsible for conducting the background investigation and
evaluating the information.
The investigation disclosed that the
individual's background screening records appeared to indicate that
about two years prior to being hired, the individual had
unsuccessfully participated in an alcohol rehabilitation program
and was, as a result, terminated from his employment.
The records
contained no information to show that those facts were evaluated, as
required by 10 CFR 26.27, prior to the guard being granted unescorted
access.
When this situation was identified, the licensee suspended the
individual's site access. A management and medical evaluation was
conducted and the licensee determined that the individual must
enroll in an alcohol treatment program.
The guard began the program
and unescorted access was temporarily reinstated. The individual is
to perform duties as an unarmed watchman pending successful
completion of the treatment program.
Thisisconsideredanunresolveditem(50-282/90019-03(DRSS);
50-306/90020-03(DRSS)). An unresolved item is a matter about which
additional information is required in order to determine whether it
is acceptable, a violation, or a deviation. Currently, no
additional information or written response is needed from the
licensee. The resolution of this issue will be addressed by
separate correspondence.
No violations, deviations, or open items were identified. One unresolved
item was identified.
8.
M_anagement Meeting (30702)
_
A management meeting was held at the Region III office on
December 6, 1990, between the NRC represented by Dr. C. J. Paperiello,
and Northern States Power, represented by Mr. C. J. Blair. Others in
attendance are indicated in Paragrapn 1 above.
Mr. E. L. Watzl provided a briefing on the development of the Site
Organization structure at Prairie Island.
The management reorganization,
including creation of the Site General Manager position, places more
responsibility, accountability, and authority at the site.
The
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reorganization also consolidates redundant activities and removes
activities from the plant- staff that may not directly contribute to the
safe and reliable operation and maintenance of the plant.
Mr. G. Goering-and Mr. B. Stephens provided an update of the
Configuration Management (CM) program. The Design Basis Document (DBD)
element of the CM program was discussed. All safety-related plant
systems and structures and key topical areas are scheduled to be
addressed by December 31, 1994
Discrepancies and open items identified
by DBD development and verification are evaluated, prioritized, and
resolved in a Follow-on Item program.
Mr. M. Sellman and Mr. D. llendele provided an update on " attention to
detail" issues.
Improper work practices and inadequate written
communications were found to be root causes for personnel errors at
prairie Island during the previous 12 months.
Several specific steps
have been undertaken to improve these areas, including:
development of
awareness programs, quality teams, and a video tape presentation to all
employees including management emphasis on the need to self-check work;
revision of maintenance procedures, development of procedure writing
guides, and training in procedure writing; and enhancement of technical
support through the recent plant reorganization.
9.
C_old Weather _ Preparatio_ns1(71714_)
In conjunction with the requirements of HRC Inspection Procedure 71714,
Cold Weather Preparations, the inspectors reviewed-the licensee's
surveillance procedure, SP-1637, " Winter Plant Operation," Revision 9.
Additionally, the inspectors performed tours during cold weather (-22
degrees F) to determine the adequacy of the licensee's program.
Tours
of the turbine building, auxiliary building, radioactive waste buildings,
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and screenhouse revealed temperatures well above freezing with
safety-related fluid systems appearing properly heat-traced or contained
within heated structures.
Some minor operational problems occurred during cold weather during this
inspection period. A level indicator for the 121 Diesel (0-1) Fuel Oil
Storage Tank operated sporadically during diesel generator operation.
The rapid turnover of air within the diesel room during operation cooled
the 3/8-inch sensing line for this level transmitter to a point where an
inline air regulator did not function adequately.
The licensee put a
portable heater in the area, which restored normal indication.
The
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licensee plans to begin routine preventive maintenance on the four air
regulators for Diesel Fuel Oil Tank indicators to prevent recurrence of
the problem. The licensee also plans to blow down the air supply to the
Emergency Diesel Generator air start control valves each month.
No violations, deviations, unresolved, or open items were identified.
10. Management _ Interview
The inspectors met with the licensee representatives denoted in aaragraph
1 at the conclusion of the report period on January 15, 1991.
T ;e
inspectors discussed the purpose and scope of the inspection and the
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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
any documents or processes as proprietary.
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