ML20129B631
| ML20129B631 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 07/09/1996 |
| From: | Jordan M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20129B601 | List: |
| References | |
| 50-282-96-07, 50-282-96-7, 50-306-96-07, 50-306-96-7, 72-0010-96-07, 72-10-96-7, NUDOCS 9609230164 | |
| Download: ML20129B631 (25) | |
See also: IR 05000282/1996007
Text
-
-
. - .
.
'
.
t
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos:
50-282, 50-306, 72-10
License Nos: DPR-42, DPR-60, SNM-2506
.
4
Report No:
50-282/96-07,50-306/96-07,72-10/96-07
,
1
Licensee:
Northern States Power Company
Facility:
Prairie Island Nuclear Generating Plant
,
Location:
1717 Wakonade Drive East
Welch, MN 55089
,
Dates:
May 25 - July 9, 1996
1
Inspectors:
S. Ray, Senior Resident Inspector
M. Bailey, Chief Operator License Examiner
R. Bywater, Resident Inspector
M. Dapas, Senior Reactor Analyst
S. DuPont, Reactor Engineer
1'
J. Guzman, Reactor Inspector
M. Holmberg, Reactor Inspector
.
M. Kunowski, Resident Inspector, Braidwood
J. Lara, Resident Inspector, Monticello
i
A. Stone, Senior Resident Inspector, Monticello
'
c.
Approved by:
N
'
M.~Jdrpap, Chief, Projects Branch 7
Division of Reactor Projects
i
l
J
'
_
9609230164 960913
ADOCK 05000282
G
_ . .
-.
.. _
_ _ _.
_
..
.
__
_
. . _ .
_ _
_
f.
-
,
i
EXECUTIVE SupMARY
'
Prairie Island Nuclear Generating Plant, Units 1 & 2
{
NRC Inspection Report 50-282/96-07,50-306/96-07,72-10/96-07
!
l'
This integrated inspection included aspects of licensee operations,
i
maintenance, engineering, and plant support. The report covers a 6-week
period of resident inspection; in addition, it includes the results of
,
announced inspections by a regional operator license examiner, the lead
'
engineering assessment person, and an inservice inspection specialist.
.
,
!
Operations
1
Response to a dual unit trip from full power and a partial loss of
i
.
i
offsite power was rapid, thorough, and effective.
Operators effectively
used the proper procedures to stabilize the plant and conduct recovery
i
actions. All operating evolutions were conducted in a calm, deliberate,
and prudent manner.
(Section 01.2)
5
Plant equipment including all four emergency diesel generators responded
..
'
as designed to the trips and loss of power indicating excellent material
condition.
(Sections 01.2 and 02.1)
4
!
!
Two procedural deficiencies were noted during operator license exams.
.
The procedures were revised to correct the problems. This deficiency is
being treated as a non-cited violation.
(Section 03.1)
i
j
Maintenance
i
!
All maintenance and surveillance activities observed were professional
.
l
and thorough.
(Section M1.1)
l
Deviations from the American Society of Mechanical Engineers (ASME) Code
.
L
Section XI requirements for the inservice inspection (ISI) plan and
i
ultrasonic testing requirements for dissimilar metal welds, indicated
l
that opportunities exist for improvement in oversight of the ISI
j
prograr..
(Section M3.1)
i
Enaineerina
!
One apparent violation was identified involving a design control issue.
.
'
Engineers did not consider all potential sizes of secondary side pipe
!
ruptures during development, implementation, and review of design
i
modification 80L579 in 1982. PINGP's design controls did not assure that
'
the AFW system design basis was appropriately translated when specifying
the AFW pump low pressure switch trip setpoint. As a result of this
design control issue, both unit's AFW pumps were effected and may have
been inoperable if they were not protected from pump run-out damage for
i
all postulated secondary system line break sizes.
Corrective actions
,
taken upon identification of this issue, in May 1996 by a licensee self
.
'
assessment initiative, were thorough and aggressive. No Notice of
Violation is currently being issued pending further NRC management
consideration of this violation.
(Section El.1)
'
2
i
.
- --i-
--
_ _ ,
w
w
m
u
--r,
yv--
y
y
-
--- - My
-
-
1
..
,
'
e
The results of the licensee's inspection of the intake line indicated
there may have been some flow degradation due to silting.
(Section
,
E2.1)
i
The decision to install a replacement stem without verification of
e
material flaws via nondestructive testing marred an otherwise
conservative approach in corrective action for the feedwater regulating
valve failure.
(Section E2.2)
'
The inspectors noted an editorial discrepancy in the Updated Safety
e
Analysis Report regarding the location of the hydrogen monitor system
!
data acquisition and control assemblies.
(Section E2.3)
j
e
Several weaknesses were noted in the events resulting in a violation of
Techr.: al Specifications for having containment hydrogen monitors
inoperable. Those included:
(Section E8.1)
Performing work outside the scope of a work order and then failing
to document all the work performed.
Failure to specify post-maintenance testing.
Filling calibration gas bottles to a significantly higher pressure
'
,
than that specified by procedure.
Failure to perform an adequate review and document a configuration
j
change to pressure regulator settings.
'
Design control and configuration management procedures which did
not address control of pressure regulator settings.
e
The licensee's self-assessment of its safety evaluation program was
aggressive and thorough.
(Section E8.2)
Plant Suncort
e
The NRC identified a failure to submit a report required by Technical
i
Specifications. The failure is being treated as a Non-Cited Violation.
(Section R3.1)
,
o
The licensee properly classified and reported the dual unit trip and
loss of offsite power event. They conservatively activated the
emergency response organizations, and used them to provide excellent
l
support to the operators for recovery.
Lessons learned from exercises
i
and drills were effectively used in this response to an actual event.
(Section Pl.1)
3
-
.
Report Details
Summary of Plant Status
Both units operated at full power until June 29, 1996, when severe winds
caused damage to offsite power lines and both units tripped simultaneously.
Unit I was taken critical on June 30 and unit 2 on July 1.
Both unit's
generators were placed on line on July 2.
During this period the fourth dry cask, loaded with 40 spent fuel assemblies,
was moved to the Independent Spent Fuel Storage Installation (ISFSI).
In
addition, the fifth dry cask was inspected and moved to the ISFSI empty. The
licensee intended to move it back into the plant and load it at a later date.
I. Doerations
01
Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent
reviews of plant operations.
In general, the conduct of operations was
acceptable; specific events and noteworthy observations are detailed in
the sections below.
01.2 Partial loss of Offsite Power and Dual Unit Trio
a.
Inspection Scope (93702)
At 2:29 PM on June 29, 1996, a severe wind storm in the area caused
damage to several offsite power lines, a partial loss of offsite power,
and simultaneous reactor trips from 100 percent power on both units.
The inspectors responded to the site and monitored the licensee's
response to the event and recovery actions.
b.
Observations and Findinas
Seauence of Events
Accurate reconstruction of the events was hampered somewhat by a lack of
data.
The electrical disturbances caused a loss of the emergency
response computer system on unit 1 and a loss of the balance of plant
annunciator recorder on unit 2.
The following is a sequence that
represented the best information available at end of the inspection
period.
e 2:18 PM Blue Lake 345 KV line disturbance caused switchyard breakers
8H14 and 8H15 to open.
i
4
-
-
- -
.
e 2:29 PM Red Rock 1345 KV line disturbance caused switchyard
breakers 8H17 and 8H18 to open.
o 2:29 PM Red Rock 2 345 KV line disturbance caused switchyard
breakers 8H7 and 8H8 to open. That completely opened the
ring bus, isolating both unit's generators from the
remaining offsite power lines. Generator loads decreased
drastically and turbine speeds increased.
2:29 PM Turbine governor valves closed due to turbine overspeed of
o
103 percent. Reactor cold leg temperature increased rapidly
toward hot leg temperature because heat was not being
removed by the steam generators. The warmer water being
returned to the reactor downcomer area resulted in decreased
neutron attenuation and higher indicated reactor power.
2:29 PM Indicated reactor power increased to about 102.7 percent in
e
about one second. That caused a reactor trip on both units
due to high positive rate on nuclear instrumentation.
Actual reactor power never increased,
2:29 PM Both unit's turbines tripped due to the reactor trip signal.
e
Then the turbines had reached speeds of 109.7 percent and
would soon have tripped on overspeed.
That also would have
caused a reactor trip if the positive power rate had not.
o 2:30 PM Both unit's generator output breakers tripped 30 seconds
after the turbine trips as expected.
That resulted in a
complete loss of AC power to unit 2, a trip of reactor
coolant pumps, and startup of the D5 and D6 emergency diesel
generators (EDGs).
e 2:30 PM There were two remaining offsite lines (the 345 KV Byron
line and the 161 KV Spring Creek line) feeding switchyard
bus 2 and the unit 1 buses. However, there was little
nearby generating capacity on those lines. They also
experienced degraded voltage conditions resulting in
tripping of the unit I reactor coolant pumps, and starting
of the D1 and D2 EDGs.
Several other nonsafeguards loads on
unit I also tripped due to the degraded voltage.
Stable Condition
Both plants were stabilized in the hot shutdown condition with natural
circulation of reactor coolant. All control rods were verified fully
inserted. The EDGs powered all the safeguards buses and appropriate
loads. Unit I non-safeguards buses remained powered from offsite power
through the IR auxiliary transformer from switchyard bus 2.
Unit 2
nonsafeguards buses were not powered. Decay heat was removed by use of
the steam dumps and auxiliary feedwater (AFW) pumps.
Later operators
secured the turbine-driven AFW pumps and steam generator levels were
5
'
.
maintained with the motor-driven AFW pumps alone.
Later operators also
closed the main steam isolation valves to help maintain hot shutdown
'
conditions. The plants were maintained in those conditions until
recovery actions were successful in restoring some offsite power.
Licensee Response and Recovery Actions
At 3:05 PM the shift supervisor declared a Notification of Unusual Event
(NUE) and elected to call out the emergency response organization (ERO)
to help support the recovery. Notifications were made to the ERO and
the NRC inspectors. The inspectors responded to the site and monitored
the recovery actions from the technical support center and control room.
The licensee notified the NRC via the emergency notification system at
3:41 PM. Major recovery actions were as follows:
j
June 29
6:00 PM Bought power from another utility to raise the voltage on
e
!
j
the remaining 345 KV (Byron) line to enable starting of
reactor coolant pumps. Also transferred the 2R auxiliary
transformer from dead switchyard bus 1 to live switchyard
bus 2.
Thus offsite power was restored to the unit 2
'
nonsafeguards buses.
e
7:53 PM Started one of two reactor coolant pumps on Unit 1.
,
- 8:28 PM Started one of two reactor coolant pumps on Unit 2.
,
e 9:00 PM Declared one normal offsite power source to each unit
completely operable through the IR and 2R auxiliary
'
transformers.
)
June 30
,
2:55 AM The 345 KV Blue Lake line was repaired and connected to the
switchyard. Damage was reported to have consisted of one
phase down on one tower. Also about that time the licensee
completed lineups for the second normal path of offsite
power to the safeguards buses through the cooling tower
transformers.
e
10:00 AM
Completed transferring power to the safeguards buses
from the EDGs to offsite power and secured the EDGs.
e
10:35 AM
Exited from the NUE. Three of five offsite power
lines to the switchyard were operable and two
independent paths from the switchyard to the
safeguards buses were available for each unit.
Switchyard bus I was still out of service.
e
11:57 AM
Started the second reactor coolant pump on unit 1.
6
. _ .
'
.
l
6
1:10 PM Started the second reactor coolant pump on unit 2.
e 6:07 PM Switchyard bus I was restored. The ring bus was
established.
,
e 8:20 PM Commenced a startup of unit 1.
e
11:01 PM
Unit I was made critical.
July 1
.
10:40 AM
Comnienced a startup of unit 2.
e
12:14 PM
Unit 2 was made critical.
.
3:54 PM The unit I generator was placed on the grid.
e
4:29 PM Experienced problems with exciter bearing vibrations and the
l
e
electro-hydraulic turbine control system. The unit 1
j
generator was manually tripped,
i
July 2
- 12:20 AM
The unit 2 generator was placed on the grid.
3:39 AM The unit 1 generator was placed on the grid.
Total power
e
output from the site was limited to 750 MW due to grid
stability considerations with both the Red Rock lines still
out of service.
4
July 4
e 9:50 PM The Red Rock 2 345 KV line was restored.
Damage was
reported to have consisted of five wooden tower structures
damaged.
Power output restrictions were lifted from the
site.
July 8
e 7:51 PM The Red Rock 1345 KV line was restored.
Damage was
reported to have consisted of seven wooden tower structures
damaged.
c.
Conclusions
The plants responded as designed to the event. All reactor, turbine,
generator, and electrical protection systems functioned as expected.
All four EDGs worked properly and powered their respective safeguards
buses for extended periods without major problems.
In addition, the
security diesel generator and cooling water pump diesels functioned as
expected. Natural circulation of reactor coolant with AFW pumps and
7
,
-
. _ _.
. _ . _ . _ . _
_.
_
_
_ . _ _
_ _ _ _
_ . _ _
_ _ _ _ . _ _ _
.
!
,
I
steam dumps effectively removed the decay heat from extended full power
operations. The licensee effectively dealt with some minor equipment
i
problems during the event and there was never a significant threat to
4
public health and safety.
'
5
Operators effectively used the proper procedures to stabilize the plant
.
4-
and conduct recovery actions. All operating evolutions were conducted
in a calm, deliberate, and prudent manner. No precipitous actions were
taken in an attempt to speed up recovery. Technical Specification
-
limiting conditions for operations were conservatively implemented and
followed. The ERO provided excellent support to operations as discussed
1
in Section Pl.1 of this report.
4
i
-
The event was considered highly unusual and was a significant challenge
I
to the plant and its operators. However, the effective operator
L
training program, outstanding material condition of the plant equipment,
1
and excellent support by the ERO resulted in the event being handled in
i
what seemed to be an almost routine manner.
,
The licensee intended to issue a Licensee Event Report (LER) with
1
additional details and any remaining corrective actions.
The inspectors
1
will conduct further reviews of the event in conjunction with evaluating
i
the LER when issued.
)
02
Operational Status of Fac111tios and Equipment
!-
l
02.1
Enaineerina Safety Feature System Walkdowns
!.
a.
Insoection Scone (71707. 92903)
!
The inspectors used Inspection Procedure 71707 to walk down selected
portions of the following ESF systems:
e
Emergency Diesel Generators (EDGs)
i
b.
Observations and Findinas
i
l
The inspectors were concerned that starting air pressures of the unit 1
!
EDGs were not set according to the Updated Safety Analysis Report
(USAR).
Section 8.4.2 of the USAR stated, "Each dicscl engine is
.
automatically started by compressed air stored at a pressure of
j
approximately 250 psi." Preliminary discussions with the system
i
engineer indicated that the starting air compressors were set to cycle
'
between 219 psi and 245 psi. Thus, the starting air accumulators would
never normally be pressurized to 250 psi. However, further review by
'
the system engineer determined that the compressors were actually set to
cycle between 219 psig and 245 psig (234 to 260 psi). This confirmed
.
that the plant was being operated according to the USAR.
The system
,
i
engineer initiated actions to clarify the setpoints.
!
i
i
8
.
'
i
w
-
- , _ ,
-
-.
.
-
-- - -
.
In addition, the inspectors noted that the same section of the USAR
stated that eacii diesel had "two accumulators each of sufficient
capacity to crank the engine for 20 seconds."
In case of failure of the
starting air compressors, the operators would not normally be aware of
the situation until . starting air low pressure alarms were received.
Those alarms were set at 175 psi. The inspectors were concerned that
175 psi might not be sufficient for the engines to meet the 20 second
i
cranking design specification. Discussions with the system engineer
indicated that the preoperational and subsequent testing of the engines
l
proved that the air pressure was sufficient for at least 20 seconds of
j
cranking starting from slightly less than 175 psi initial pressure.
j
c.
Conclusions
The inspectors. identified no additional concerns with t'ne E0Gs.
.
Material condition of the systems appeared excellent.
The inspectors
noted that all four EDGs were challenged shortly after the walkdown by
'
the loss of offsite power event discussed in Section 01.2.
All EDGs
performed as designed.
,
03
Operations Procedures and Documentation
j
03.1 Doerations Procedural Deficiencies
l
a.
Insoection Scone (71707)
r
,
i
The inspectors reviewed selected operating procedures for accuracy as a
j
part of a licensed operator examination review and validation.
!
b.
Observations and Findinas
l
On April 5,1993, procedure C20.1, " Electrical Power System - System
L
Underfrequency Disturbance," was removed from the Operations Manual.
j
That procedure had contained guidance on actions for recovery from
,
'
degraded voltage and/or frequency conditions. A new procedure C20.3,
-
" Electrical Power System - Security Analysis," was issued on the same
day to clarify conflicting information regarding the operation of the
,
substation. The inspectors reviewed C20.3 and associated abnormal
i
'
procedures with a licensee representative. The inspectors did not find
.
operational guidance that would aid the operators in taking appropriate
8
!
actions to mitigate a degraded grid voltage event. The licensee did not
provide any additional procedural guidelines or management expectations
i
'
to addren apara Mr actions during such an event.
During the
!.
performo se ti tue dynamic simulator scenarios with a degraded grid
voltage event, alarm annunciator C47006-0504,"345 KV SYS UNDERFREQ," was
U
actuated.- The alarm response procedure directed the operators to refer
j
to procedure C20.1 for guidance. Without C20.1 guidance, two crews
performed different actions for the same initiating event.
4
4
During the performance of surveillance procedure SP-1295, "D1 Diesel
Generator Fast Start Test," the inspectors identified a procedural
inconsistency. Test accaptance criteria in Steps 7.9, 7.11, and 7.12
9
,
' l.
,-
-
~-
,-
__
_ _ _ . _ _
__
__
_._ __ _ _ _
!
-
,
!
I
were identified and those steps provided recording space for
the "as found" data. Steps 7.25 and 7.35 also contained acceptance
criteria information, but they did not provide recording space for nor
required the operator to record the "as found" data.
Furthermore, the
t
inspectors identified in review of the " Purpose and General Discussion"
section of SP-1295, that the acceptance criteria of Step 7.25 was a
p
Technical Specification requirement for operability determination.
'
I
c.
Gnclusions
The licensee acknowledged the procedural deficiencies. On the first
!
ites, the licensee noted that procedure revisions to incorporate the
,
guidance formerly in C20.1 were in the final stages of approval.
In
addition, the licensee chane
the annunciator response procedure to
delete the reference to 02c.2
A licensne representative stated that
the revisions had been in progress before the discrepancy had been noted
i
by the-inspectors. Therefore, the violation will not be cited because
'
the licensee's efforts in identifying and correcting the violation meet
the criteria specified in Section VII.B of the " General Statement of
Policy and Procedure for NRC Enforcement Actions," (Enforcement Policy,
10 CFR Part 2, Appendix C) (282/96007-01).
l
05
Operator Training and Qualification
l
05.1 General Comments
,
A licensed operator examination was conducted at the licensee's training
,
center and in the plant during the week of May 6,1996. The examination
j
was administered in accordance with NUREG-1021, Revision 7, " Operator
i
Licensing Examiner Standards" to six reactor operator applicants.
The
!
examination was in the form of individual written and operating
l
L
examinations for licensing determination. Details of this examination
are contained in examination report number 282/306/0L-96-01.
l
,
[
II. Maintenance
j
i
i
M1
Conduct of Maintenance
M1.1 General Comments
l
.
I
a.
Inspection Scone (61726. 62703)
'
The inspectors observed all or portions of the following maintenance and
i
surveillance activities.
SP 2136.2
Unit 2 Containment Maintenance Airlock Volumetric Test
SP 1037
Unit 1 Turbine Overspoed Trip Test
i
'
Inspect and Clean Cooling Water Emergency-Intake Line
'.
e
i
10
.
.
i
!
!
'
-
.
,
-
-
_
.- .
,
'
,
e
WO 9604137 Receipt Inspect TN-40 #06 Spent Fuel Cask
e
WO 9604730 Move Spent Fuel Cask TN-40 #06 to Storage
b.
Observations and Findinas
No discrepancies or weaknesses were noted in the performance of the
above maintenance activities.
c.
Conclusions
The inspectors found the work performed under these activities to be
professional and thorough. All work. observed was performed with the
work package present and in active use. Technicians were experienced
)
and knowledgeable of their assigned tasks. The inspectors frequently
i
observed supervisors and system engineers monitoring job progress, and
quality control personnel were present whenever required by procedure.
'
When applicable, appropriate radiation control measures were in place.
Surveillance activity acceptance criteria was checked against the
appropriate Technical Specification and Updated Safety Analysis Report
requirements. Additional comments on certain maintenance activities are
discussed below.
M2
Maintenance and Material Condition of Facilities and Equipment
,
M2.1
(Onen) Licensee Event Report (LER) 282/96-11 (92700): Degraded Steam
Generator Tube Sleeves. On May 28, 1996, the licensee discovered that
>
unit I was outside the licensing basis due to steam generator tube
sleeves indications of weak welds. They found four steam generator tube
sleeves in service may have had insufficient weld fusion to make them
completely leak tight. The licensee had come to that conclusion after
!
re-evaluating ultrasonic examination data gathered during the last
refueling outage. They initiated the re-evaluation due to information
learned from destructive examinations of tubes sleeves removed during
that outage. After the original report, the licensee determined that
one of the four tubes was actually plugged so only three tubes were
still in service.
!
The licensee had been performing extensive evaluations and operability
assessments of the problems with sleeve welds.
Some of those efforts
!
were documented in Inspection Reports 282/306/96-04, Section 2.8, and
282/306/96-06, Section M8.1. The licensee also documented their efforts
in LER 282/96-07 and the letter to the NRC dated June 27, 1996, entitled
" January 1996 Steam Generator Sleeving _ Issues Ninety Day Response
'
,
Letter." The licensee performed a safety evaluation for the three tubes
i
i
left in service as discussed in the LER. The LER will remain open
pending NRC Office of Nuclear Reactor Regulation review of the
evaluation and other steam generator sleeving issues.
"'
!
!
,
l
,
l
11
i
-
,
>
l
.
. . .
.
,
- .
. . , _ . . _
, , _
-.
..
.-
.
-
--
..
.
- - -
- . - . - - .
. -
.
.
. . .
'
.
M3
Naintenance Procedures and Documentation
M3.1
Inservice Insoection - Review of Non Destructive Examination Data
a.
Inspection Scone (73753 and 73755)
.The NRC inspectors reviewed data recorded during inservice inspection
i
'
(ISI) activities performed in the 1996 refueling outage at Monticello to
determine compliance with the American Society of Mechanical Engineers
(ASME) Code and NRC requirements.
b.
Observations and Findinas
,
For ultrasonic test (UT) examinations of dissimilar metal welds,
.
'
paragraph III-3411(b) of Appendix III of Section XI, 1986 Edition of the
ASME Code required the following:
"If the examination will be conducted
,
from both sides, calibration reflectors shall be provided in both
'
materials." Contrary to the above, at Monticello, the inspectors
,
identified that a dissimilar metal weld was ultrasonically examined from
t
both sides and a single calibration block had been used for calibration.
As a result, the inspectors requested the licensee to identify all
examinations that were performed according to paragraph 3.5 of procedure
i
ISI-UT-16, Revision 11, "UT Examination of Welds of Austenitic and High
Nickel Alloy Materials," for Monticello and Prairie Island.
Those
j
examinations were considered examples of a deviation from paragraph III-
1
i-
3411(b) of Appendix III of Section XI, 1986 Edition, of the ASME Code
requirements for performing UT examinations of dissimilar metal welds.
J
The affected examinations identified for Prairie Island were:
!
e
Report 94-0206, Nozzle to Safe End Examination, Cal block #6.
e
Report 96-0146, Safe End to Nozzle Examination, Cal block #54.
c.
Conclusions
'
1
.
The Notice of Deviation was issued with the Monticello Inspection Report
263/96-06, Section M3.2 (Deviation 263/96006-02).
The discussion
included findings for both the Monticello and Prairie Island plants.
Since the ISI examinations were conducted by the sarc licensee
employees, and corr (ctive actions would affect both sites, a separate
Notice of Deviation vas not issued for Prairie Island.
>
12
1
_ , _
-
[
'
.
.
i
III. Enaineerina
I
j
l
El
Conduct of Engineering
.
E1.1 Modification Failed to Ensure Desian Adeauacy Resultina in Inonerable
,
Auxiliary Feedwater (AFW) Pumos.
,
i
a.
Insnection Scone (37551)
On May 20, 1996, with both units operating at 100 percent power, Prairie
,
j
Island declared all four AFW pumps (two per unit) inoperable because
!
j
they were not protected against run-out for all accident conditions.
j
The licensee informed the NRC per 10 CFR 50.72 requirements, and
j
subsequently completed actions in time .to allow the pumps to be declared
operable before any actual power reduction. The inspectors reviewed the
principal root causes for the inoperable pumps as well as short term
!
corrective actions and the long term corrective action plans. This
included reviews of the License Event Report (LER) 96-0010, and GL 91-18
i
evaluations as well as 50.59 safety evaluations relating to this issue.
.
.
'
b.
Observations and Findinas
d
Brief History of AFW Pumo Run-out Protection at PINGP
,
Pressure switches were installed to protect the AFW pumps against run-
out via Modification 80L579. The modification was a commitment added in
response to Bulletin 80-04 " Analysis of a PWR Main Steam Line Break With
,
Continued Feedwater Addition" and NUREG 578, "TMI-2 Lessons Learned Task
Force Status Report and Short-Terms Recommendations." The modifications
i
were to prevent the pumps from being damaged by cavitation while in run-
out conditions due to a secondary system break.
In January 7, 1982
'
correspondence to the NRC, NSP stated that the discharge pressure
,
switches would be set below the minimum differential head at maximum
1
flow (887 psig at 320 gpm).2 NSP further stated that the setpoints
I
!
would have 100-150 psi margin below the total differential head (TDH) to
prevent spurious trips with actual setpoints to be selected following
~,
installation and testing.
(Although setting the switches below the
minimum TDH does not appear conservative, pre-operational test data and
vendor information supported operation without cavitation for a certain
range below the minimum TDH).
These pressure switch installations were completed on December 12, 1982,
and contrary to the setting values discussed in the correspondence, the
i
discharge pressure switch setpoints were set at 500 psig for the motor-
.
driven AFW pumps and 200 psig for turbine-driven AFW pumps.
PINGP could
!
not provide adequate justification or bases for these setpoints.
i
- The pump's desien head Is 1250 psie at 220 spm.
13
-
!
I
-
-
.
- -
.
- - . - - - - . -
,
-
- - -
-
-
.
.
.
,
i
4
i
l
Identification of Lack of Protection for AFW P=as
j
In May of 1996, PINGP's self-assessment of implementation of the 10 CFR
j
50.59 safety evaluation program questioned the appropriateness of the
1
AFW pump low discharge pressure trip setpoints. The primary concern was
i
that the as-left switch setpoints would not protect the pumps against
pump run-out for intermediate sized secondary side pipe breaks.
Based
on pre-operational testing data the licensee surmised that the onset of
cavitation was in a range below 750-800 psig.
5
i
Per Prairie Island's Accident Analysis, a faulted SG would be isolated
within 10 minutes and the- AFW pumps would be required for delivery of
'
AFW flow to the unfaulted loop.
For large secondary side cracks or
'
i.
breaks, a faulted steam generator would quickly depressurize, placing
j.
excessive demand on the AFW pump resulting in a pump trip on low
a
discharge pressure.
For very small crack sizes the secondary side
pressure could, theoretically, provide sufficient backpressure to the
pumps to prevent run-out until operator action could be taken to isolate
the faulted SG. -Thus, the concern relates to a range of postulated
1
secondary side break / crack sizes where the pump discharge pressure would
hover above the trip setpoint but below the onset of cavitation, and
'
(without operator intervention) pump damage could occur.
For these
,
!
scenarios, the absence of protection would result in the failure of the
}
AFW pumps to provide the necessary flow to remove decay heat during
i
accident mitigation.
Since the potential for damage to both AFW pumps
,
l
in either unit could be postulated, all four pumps were declared
3
inoperable on May 20, 1996, and Technical Specification 3.0 was entered.
l
CORRECTIVE ACTION
!
For short term corrective action, the licensee implemented special order
i
to prevent run-out (cavitation) by requiring that AFW pump discharge
pressure be maintained greater than 900 psig by throttling the discharge
motor operated valves. Throttling of the discharge valves will not
i
affect design heat removal capabilities. Guidance in the operations
procedure ensures that minimum flow requirements are satisfied for heat
'
removal. As discussed in NRC inspection report (IR) 50-282/306/96-006,
-
'
l
this order was supported by a temporary change to operations
l
instructions to add the responsibility of maintaining AFW pump discharge
,
pressure to one of the minimum complement of licensed operators required
i
i
to be in the control room. A 50.59 safety evaluation satisfactorily
evaluated the manual operator actions against the criteria contained in
,
NRC Generic Letter 91-18. The inspectors had noted that the Operations
'
.
Committee review of this issue was thorough and training was conducted
'
'
on the manual operator actions for all operating crews.
Interviews with
- selected licensed operators indicated that they understood their
responsibilities detailed in the special order. The pumps were returned
'
to operable, but degraded, status after implementation of the manual
>
,
actions,
i
$
14
,
,
.
,,.
--
.
, - , , ,
,
,
,,
_
-
']
-
--
--
-.--
.
. .
-
_
- .-. -
- . _ - ._ - -
- - - _
.
l-
For long term corrective action, PINGP had initiated development of an
AFW system hydraulic model with the objective of removing reliance on
-
operator. action to preclude potential pump damage. The information from
,
the hydraulic model will support a modification that had been initiated
to install flow restriction orifices so that the pumps will not be
.
operated in run-out regions of the pump curve. The inspectors noted
!
l
that these actions had been given high priority.with scheduled
implementation to begin during the next refueling outage scheduled for
January 1997. Further, other ongoing efforts by PINGP are targeted at
identifying any similar issues. These efforts included USAR reviews,
j
system design reviews and reconstruction efforts, resolution of DBD
,
i
i
follow-on items, and verification that other earlier plant activities
'
that had not been reviewed under 50.59 safety evaluations were re-
reviewed.
NRC's review of NSP's long term corrective actions and
resolution of this issue will continue to be tracked under the
i
unresolved item opened in IR 96001 (50-282/306/96006-01). The
!
inspectors concluded that the corrective actions taken had been
comprehensive and these actions were pursued aggressively by the
,
j.
licensee without NRC intervention.
j
ROOT CAUSE
!
The inspectors concluded that the principal root cause for the
inadequate pump trip setpoint and thus, the lack of protection for all
j
postulated breaks was a lack of design control during implementation of
4
i
Modification 80L579. The basis for the chosen pump trip setpoints was
never clearly elucidated. Available information indicated that the
designers assumed that if run-out conditions occurred, the pump
discharge pressure would drop off immediately allowing the pressure
switches to trip the pump (when, in fact, the pump may operate in the
'
run-out regime in a stable but cavitating mode where the pump internals
would be damaged). The inspectors did not identify other design control
!
problems during the early 1980s to indicate that this was a programmatic
i
problem with PINGP design modifications.
The ori0inal design of PINGP's AFW system did not include run-out
.
protection for the pumps. The plant's architect engineer had no basis
.
for dismissal of this protection. Therefore, NSP's 1982 implementation
of design modification 80L579 provided an opportunity to fully address
this concern. However, the design modification did not consider all
'.
potential sizes of secondary side pipe ruptures during development and
-
,
j
'
implementation.
PINGP's design controls did not assure that the design
basis (i.e. for all- potential sizes of secondary system pipa ruptures,
J
provisions must be made in the design of the AFW system to ensure the
.
minimum flow to the remaining unfaulted loops, USAR 11.9.3.b) was
appropriately translated when specifying the pressure switch trip
setpoint.
Further, the modification's design reviews did not identify
i
i
and correct the design error or fully verify the design adequacy until
re-reviewed by PINGP in May 1996.
j
.
.
M
l
15
b
.
d
4
-
- - -
-- -- ---
-
, - - -
~
n--
.m-,
.-
,
I
.
1
c.
Conclusions
PINGP's design controls during development and implementation of
modification 80L579, installed in December 1982, appeared not to assure
that the plant's design basis was appropriately translated when
specifying the AFW pump low pressure switch trip setpoint.
Further, the
'
modification's design reviews appeared not to identify or correct the
design error or fully verify the design adequacy until re-reviewed by
PINGP in May 1996.
PINGP's corrective actions upon identification of
this issue were thorough and aggressive. This is an apparent violation
(282/96007-02). No Notice of Violation is currently being issued
pending further NRC management consideration of this violation.
E2
Engineering Support of Facilities and Equipment
E2.1
Inspection and Cleanina of Coolina Water Emeroency Intake Line
a.
Insnection Scope (62703. 92903)
As discussed in Inspection Report 282/306/95-14, Section.3.13, the
,
licensee determined that the cooling water emergency intake line did not
pass sufficient flow to meet its original design basis. One of the
i
problems was thought to be possible silting in the line. During this
inspection period the licensee contracted for inspection and cleaning of
the emergency intake pipe,
b.
Observations and Findinas
The licensee determined that the intake pipe contained from one to five
inches of silt on the bottom. No large items of debris, asiatic class,
or zebra mussels were found. A layer of algae covered most of the pipe.
l
During preparations for cleaning the pipe, the licensee determined by
observation of the results that surveillance procedure SP 1528,
"Backflush of Emergency Bay Intake Pipe," Revision 18, may not have been
completely effective in removing the silt when performed for the
,
specified 30 minutes. However, when performed for 60 minutes, the
j
surveillance removed most of the debris and silt. The licensee was in
the process of changing the surveillance to specify a 60 minute
i
backflush.
!
SP 1528 was not a surveillance required by Technical Specifications.
j
The surveillance was conducted monthly per a licensee commitment in a
i
letter to the NRC dated January 29, 1990. The commitment was in
'
response to NRC Generic Letter 89-13, " Service Water System Problems
Affecting Safety-Related Equipment."
r
The licensee intended to complete a safety evaluation and perform a flow
verification test later in 1996, when river temperature and cooling
water demand conditions allowed. This was to determine the overall
-
effectiveness of the cleaning and backflushing, and to determine whether
,
even a clean line could meet the original design basis.
f
16
_
_
_
_ _
_ _ _ _ _ _ _ _ _ _ _ _ _ _ . .
1
-
J
f
!
c.
Conclusions-
The results of the inspection of the intake line indicated that there
,
may have been some flow degradation due to silting. However, the
-
licensee had not determined whether even a clean line could meet the
,
original design basis. The acceptability of the licensee's temporary
-
corrective actions remains an Unresolved Item (282/95014-02) pending
completion of a review by the NRC Office of Nuclear Reactor Regulation.
'
!
E2.2
(Onen) License Event Report (LER) 306/96-01:
Reactor Trip Caused by
Failure of Feedwater Regulating Valve.
l
'a,
Inspection Scone (37550)
,
j
The inspectors examined LER 96-01, Nonconformance Report (NCR) 2010410,
,
!
and proposed corrective actions, including the proposed modifications to
the valve internals. The inspectors also discussed corrective actions
,
!
taken and planned with systems engineering personnel.
b.
Observations and Findinas
.7
i
As discussed in inspection report 282/306/96-06, a unit 2 reactor trip
occurred because of failure of the feedwater regulating valve CV-31135.
,
'
During disassembly of CV-31135 it was observed that the valve plug had
'
separated from the stem.
I
The licensee had determined that one of the primary causes of the valve
failure was the torsional force on the valve plug which had not been
-
accounted for in the design of the stem / plug interface.
That root cause
was supportable because the through-pin used in the stem / plug connection
-
had sheared under obvious torsional loads, plus the licensee observed
i
torsional loads on the visible portion of the stem during low power / low
,
flow operation.
For the short term, the licensee replaced the valve
'
internals with like components and restarted the plant pending a design
modification on the stem / plug connection. The design of the stem / plug
modification was in progress and was a collaborative ef fort between the
valve vendor and plant engineering.
The proposed changes to the connection (extension of the stem so that it
passes through the plug assembly and allows torquing of the nut and
welding of the nut to the stem) qualitatively appeared adequate and
reasonable and would distinctly increase the joint resistance to any
applied torsional moment.
However, the design changes had not been
qualified quantitatively via analysis. The licensee intended to
complete the qualifications after obtaining strain measurements from the
valve stems to quantify the magnitude of the applied force and the flow
conditions where the highest loads are exhibited.
Those corrective
actions will be reviewed in a future inspection.
As discussed in the LER, any pre-existing material flaws, such as the
' stem crack noted in the failed stem, would expedite the stem / plug
separation after the assembly was weakened via the torsional loads.
For
17
s
..
-- .
_.
.-
.
4
that reason, and in view of the interim like-for-like solution, the
-
inspectors asked why the replacement stem had not been non-destructively
.
l
examined with a relatively expeditious exam such as dye-penetrant
,
testing prior to installation.
In response, the licensee maintained
that the stem cracks had been re-evaluated and were considered ancillary
-
causes to the valve failure, therefore minimal value would be added by
nondestructive testing.
s
c.
Conclusions
j
Overall, actions taken to address the failed feedwater regulating valve
j
have been comprehensive e,nd methodical. The depth of the system
engineer's knowledge of individual component history, qualifications and
design parameters was very good. The inspectors noted that the planned
'
'
-
design modification to the stem / plug assembly was not quantitatively
qualified and was awaiting testing of stem torsional loads during a
,
future power ascension to fully validate the design. The decision to
i
a
install the replacement stem without verification of material flaws via
,
nondestructive testing marred an otherwise conservative approach in
y
corrective action for the valve failure.
,
j
E2.3 Review of USAR Commitments
.
J
i
A recent discovery of a licensee operating their facility in a manner
j
contrary to the Updated Safety Analysis Report (USAR) description
l
highlighted the need for a special focused review that compares plant
j
practices, procedures, and/or parameters to the USAR descriptions.
While performing the inspections discussed in this report, the
inspectors reviewed the applicable portions of the USAR that related to
,
the areas inspected. The following inconsistency was noted between the
'
wording of the USAR and the plant practices, procedures, and parameters
observed by the inspectors:
i
_
As discussed in Section E8.1 of this report, USAR Section 5.4.2.2.3
i
incorrectly stated that the hydrogen monitor system data acquisition and
control assemblies were located in the control room.
Those components
<
were located in the environmental monitoring equipment rooms.
The
'
!
associated strip chart recorders were located in the control room.
The
!
discrepancy was considered an editorial error and turned over to the
i
licensee for resolution. This is an open inspection item pending review
of the licensee's resolution (282/96007-03).
E8
Miscellaneous Engineering Issues
E8.1
(Closed) Unresolved item 282/96006-04 and (Closed) Licensee Event Report
j
282/96-09:
Exceeding Technical Specifications Limiting Conditions for
Inoperability of Post Accident Containment Hydrogen Monitors due to
'
Pressure Regulator Drift of the Calibration Manifold.
4
)
l
4
L
18
.
j
.
.
.
.
.
.
.
_-~
_-
-em,
,
vr-r
.
_
._
_ _ _ . .
_ _ _ . . _ _ _ ,
j
.
1
'
l
l
a.
Insoection Scone (92700. 92903)
!
'
'
This issue was previously discussed in Inspection Report 282/306/96-06,
l
Section M2.2. During this inspection period the inspectors continued
j
their review of the circumstances surrounding the event.
.
i-
j-
b.
Observations and Findinas
.
.
!
LER 282/96-09 described the events leading up to the licensee's finding
that three of four containment hydrogen monitors were inoperable for a
,
period of time longer than allowed by Technical Specifications. The
L
inspectors review disclosed the following additional information and
,
clarifications:
l,
e
On February 14, 1996, Work Order (WO) 9600752 to perform leak
l
j
i
checks of the hydrogen sensor platforms was conducted.
During
l
that job the following activities were performed on verbal
instructions of the system engineer, there were no instructions to
e
[
perform them written in the work package:
.
,
,
All eight regulator settings were set to 12 psig nominal (12
!
!
- 14 psig actual). That was documented only in a note
!-
attached to the WO.
i
The capability of each sensor's calibration equipment to
i
function at the 12 psig regulator setting was tested. That
i
was not documented in the W0.
j
,
A calibration gas usage rate test was performed on one
!
sensor and the results improved after the regulator setting
!
was changed. That result was documented only in a note
!
attached to the WO.
l
There was no instruction in WO 9600753 to perform post-maintenance
i
testing. However, the quarterly calibration surveillance was
successfully performed on February 16.
l
!
e
On February 20, per WO 9600753, all eight calibration gas bottles
!
i
were filled. The work package specified that it be performed in
accordance with procedure D87, Revision 1, " Containment Hydrogen
Monitor Calibration Gas Fill." Procedure D87 instructed the
l
4 .
technicians to fill the gas bottles to 1800 psig.
Instead, the
technicians filled the gas bottles to 2250 - 2400 psig.
l
{
WO 9600753 was then closed out.
l
e
As discussed in the LER, one of the four sensors did calibrate
l
properly on May 14, 1996. However, the . control room display for
I
i
containment hydrogen was the auctioneered high sensor from each
i
train. Since three inoperable sensors were reading falsely high
after the calibration, operator actions would have been required
i
<
j:
to recognize the condition and eliminate the faulted sensor from
j
4
l
1
19
l
{
'
l-
!
.
. _ . _ _ ,
_
_
. .
.
~
3
.
the auctioneering circuitry to provide the valid sensor's output
to the control roon;. Therefore, that train was considered
inoperable even with anc operable sensor.
The licensee performed an inadequate evaluation of the regulator
e
setting change. Changing of pressure regulator settings was
apparently not covered by the licensees design control or
. configuration management procedures. The LER corrective actions
did not address that issue.
The Updated Safety Analysis Report (USAR), Section 5.4.2.2.3,
e
incorrectly stated that the hydrogen monitor system data
acquisition and control assemblies were located in the control
room. Those components were located in the environmental
monitoring equipment rooms. .The associated strip chart recorders
were located in the control room. The same error was also present
in procedure H8-D.5.2, "EX0 Sensors (Whittaker) - Containment
Hydrogen Sensor."
c.
Conclusions
The containment hydrogen monitoring system was providing valid
containment hydrogen concentration data until the system was calibrated
on May 14, 1996.
If an accident were to have occurred, the sensors
would have provided valid indications until calibration 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> later.
Upon calibration, a significant change in concentration would have been
indicated (> 6 percent). A hydrogen environment of this magnitude would
not be expected for several days.
Updated Safety Analysis Report (USAR), Figure 5.4-2, indicated that if
uncontrolled, hydrogen concentration would not exceed 4 percent for
approximately 16 days. Alternate methods of hydrogen monitoring for
consistency checking were available, including the automatic gas
analyzer system (non-safeguards power) and containment atmosphere grab
,
sample analysis (USAR Section 5.4.2.2.3).
Thus, as stated in the LER,
,
L
the event posed little threat to health and safety of the public.
!
!
However, the condition would have caused unnecessary confusion during a
design basis event and would have complicated analysis and recovery
.
actions. Thus the condition was cited even though licensee-identified.
'
Technical Specification 3.15.A required that 2 channels of containment
hydrogen monitors shall be operable in Modes 1 and 2.
Technical Specification 3.15.B required that with two hydrogen monitor
channels inoperable, the Licensee must restore one channel to operable
'
status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least Mode 3 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
.
Contrary to the above, from March 3 through May 15, 1996, while in Modes
1 or 2, both Unit I hydrogen monitor channels (train A sensors IXE-719
- .
and IXE-720; train B sensor IXE-722) were inoperable because calibration
- .
!
~
20
,
-
.
!
equipment was degraded and action was not taken to restore at least one
channel to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or to be in at least Mode 3
t
within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. This was a violation.
(282/96007-04)
The LER associated with the event was considered closed and remaining
.
corrective actions in the LER will be followed when the violation
corrective actions are reviewed.
'
E8.2
(Closed) Violation 282/306/95014-03 (40500. 92903):
Safety Evaluation
Not Performed Prior to Special. Test.
This issue was discussed in
Inspection Report 282/306/95-14, Section 3.14.
The violation concerned
the failure to perform a safety evaluation in accordance with 10 CFR 50.59 prior to performing a special test of the emergency intake line.
'
In response to this violation, the licensee conducted a detailed self-
assessment of the safety evaluation process. The self-assessment
evaluated whether safety evaluations were appropriately initiated,
'
whether they contained enough detail, and whether the right conclusions
were reached. Additionally, the licensee had reviewed previous changes,
,
tests, and experiments where a safety evaluation was not performed to
ensure that the screening criteria of 10 CFR 50.59 or 72.48 were
appropriately applied.
i
The licensee also revised the procedure for performing safety
evaluations to include a screening form to be used when safety
evaluations were determined not to be necessary. The NRC inspectors
reviewed the self-assessment and the findings and concluded that the
self-assessment was aggressive and thorough.
The screening form
!
appeared to provide reasonable questions to ensure that safety.
'
evaluations would be performed when required. The inspectors concluded
that the licensee's corrective actions were sufficient to prevent
recurrence of the violation,
f
IV. Plant SuDDort
R1
Radiological Protection and Chemistry Controls
R1.1
Small Chemical Discharae to the River (93702)
>
i
On July 7, 1996, the licensee reported to the NRC in accordance with
i
10 CFR 50.52 that they had made a small release of diluted sodium
-
hydroxide to the Missi.e m pi River and reported it to the State of
Minnesota and the Nations.1 Response Center.
The release was reported to
be of less than a reportable quantity and not a violation of the state
discharge permit. The inspectors had no further concerns with this
issue.
'
i
i
.
21
!
!
3
-
.
R3
Radiological Protection and Chemistry Procedures and Documentation
R3.1 Technical Specifications Reauired Reports Submitted late
a.
Insoection Scone (92904)
3
.
In June 1996, while conducting a review of occupational exposure data
for various reactors, the NRC Office of Nuclear Regulatory Research
noted that the licensee did not submit routine annual reports of
,
occupational exposure, safety and relief valve failures and challenges,
!
and primary coolant iodine spikes required by March 1 of each year in
accordance with Technical Specification 6.7.A.1.
The NRC Project
Manager contacted the licensee and asked about the report.
b.
Observations and Findinas
The licensee discovered that they had drafted the report in a timely
manner but, through an administrative oversight, had apparently failed
to route the letter for signature and mail it.
The licensee then
2
submitted the required report on June 20, 1996. As part of the
corrective action for this error, the licensee obtained an index of all
correspondence received by the NRC Document Control Desk for the Prairie
"
Island dockets in the last year to compare to their data base of
required reports and their files of submitted reports. No additional
missing reports had been identified at the end of the inspection period.
Additional actions were taken by the licensee to address the personal
performance issues.
c.
Conclusions
Failure to submit the required report was a violation of Technical
Specifications but was the result of an administrative oversight and had
no safety significance.
This failure constitutes a violation of minor
significance and is being treated as a Non-Cited Violation, consistent
with Section IV of the NRC Enforcement Policy.
(282/96007-05)
'
P1
Conduct of EP Activities
-
i
Pl.1 Notification of Unusual Event (NVE)
a.
Inspection Scope (71750. 93702)
On July 29,1996, at 3:05 PM, the licensee declared an NUE as a result
of a dual unit trip and partial loss of offsite power discussed in
Section 01.2 of this report. The inspectors responded to the site and
monitored the activities in the technical support center (TSC) and
control room.
b.
Observations and Findinas
The licensee properly evaluated the event and made the proper emergency
classification. After making the required initial notifications to
22
. . _ . _ _ . . _
_ _ _ _ ..
_ _ _ . . _
_
_ _ _ _ . . _
._.
.
.
4
h
j
offsite officials, the shift manager initiated a callout to the
emergency response organization (ERO) to provide managerial, technical,
'
-
and maintenance support for the recovery.
The TSC provided excellent support to the operators during the event.
.
J
TSC staff prioritized work, provided technical assessments of the
remaining offsite power capabilities, coordinated offsite power
,
'
i
restoration efforts with the system load dispatcher, and performed
. numerous other functions.
Status boards were maintained up to date.
i
Frequent status briefings were held. Schedules were established to
'
J
facilitate manning for long-term support.
Lessons learned from
exercises and drills were used and all activities were performed
!
smoothly.
,
1
i
The TSC would not normally be manned at the NUE level.
Because of the
complexity of the initiating event and recovery actions, the decision
j
was made to man the center and direct activities from there was prudent.
'
The emergency operations facility (EOF) was also manned. The inspectors
did not observe activities in the E0F.
EOF staff also provided support
.
for the event recovery. The operational support center was not manned.
!
'
Instead, extra support personnel were directed to report to their normal
work stations until needed.
!l
The NUE was terminated at 10:35 AM on June 30, 1996, when both units met
the Technical Specifications requirements for offsite power sources and
all emergency diesel generators were secured and returned to normal
'
j
standby condition.
i
c.
Conclusions
\\
<
l
The licensee properly classified and reported the event, conservatively
'
j
activated the ERO, and used the ERO to provide excellent support to the
!
operators in recovery from the event.
Lessons learned from exercises
j
and drills were effectively used in this response to an actual event.
l
'
.
!
V. Manaaement Meetinas
,
i
i
X1
Exit Meeting Summary
}
The inspectors ) resented the inspection results to members of the licensee
i
management at tie conclusion of the inspection on July 11, 1996.
The licensee
acknowledged the findings presented.
1
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary.
No proprietary information was
-
identified.
)
i
23
f
'
.
.
.-
-.
.
.
.
.
.
- -
s
.
PARTIAL LIST OF PERSONS CONTACTED
Licensee
M. Wadley, Plant Manager
M. Agen, Senior Consultant, Emergency Planning
K. Albrecht, General Superintendent, Engineering
J. Goldsmith, General Superintendent, Design Engineering
- J. Hill, Manager, Quality Services
G. Lenertz, General Superintendent, Plant Maintenance
D. Schuelke, General Superintendent, Radiation Protection and Chemistry
- M. Sleigh, Superintendent, Security
J. Sorensen, General Superintendent, Plant Operations-
INSPECTION PROCEDURES (IPs) USED
IP 37551:
Onsite Engineering
IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and
Preventing Problems
IP 61726:
Surveillance Observations
- IP 62703:
-Maintenance Observations
IP 71707:
Plant Operations
IP 71750:
Plant Support Activities
IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power
Reactor Facilities
IP 92903:
Followup - Engineering
IP 92904:
Followup - Plant Support
IP 93702:
Prompt Onsite Response to Events At Operating Power Reactors
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
282/96007-01
Failure to provide adequate operating procedures for
degraded voltage or under frequency condition.
,
l
282/96007-02
Removal of feedwater pump cavitation protection
282/96007-03
IFI
Resolution of incorrectly stated hydrogen monitor
system data acquisition in USAR Section 5.4.2.2.3.
4
282/96007-04
Failure to Meet Technical Specification Limiting
Conditions for Operation of the Containment Hydrogen
Monitoring System
'
282/96007-05
Failure to Submit Annual Report Required by Technical
'
>
.
Specifications On Time
Closed
282/95014-03
Safety Evaluation Not Performed for Special Test
306/95014-03
Safety Evaluation Not Performed for Special Test
282/96006-04
Exceeding Technical Specifications Limiting Conditions
for Inoperability of Post Accident Containment
Hydrogen Monitors due to Pressure Regulator Drift of
,
i
.
.
the Calibration Manifold
282/96007-02
Failure to Submit Annual Report Required by Technical
Specifications On Time
24
-
d
. ..
m
m
.
. .
-
-
.---mw
--
e.
__
,
,
Exceeding Technical Specifications Limiting Conditions
for Inoperability of Post Accident Containment
Hydrogen Monitors due to Pressure Regulator Drift of
the Calibration Manifold
Discussed
282/95014-02
Acceptability of Manual Operator Actions During a
Design Basis Accident
263/96006-02
DEV
Failure to Follow ASME Code for Ultrasonic Tests of
Dissimilar Metal Welds (Monticello Report Item)
Reactor Trip Caused by Failure of Feedwater Regulating
Valve
Degraded Steam Generator Tube Sleeves
LIST OF ACRONYMS USED
American Society of Mechanical Engineers
CFR
Code of Federal Regulations
Design Basis Document
DEV
Deviation
Emergency Response Organization
GL
Generic Letter
IP
Inspection Procedure
Independent Spent Fuel Storage Installation
Inservice Inspection
i
KV
Kilo (Thousand) Volts
LER
Licensee Event Report
MW-
Mega (Million) Watts
Nonconformance Report
Non-Cited Violation
NRC
Nuclear Regulatory Commission
Northern States Power Company
Notification of Unusual Event
Public Document Room
Pounds Per Square Inch
Pounds Per Square Inch Gauge
i
Pressurized Water Reactor
i
Surveillance Procedure
Total Differential Head
i
TN
Transnuclear Corporation
Unresolved Item
Updated Safety Analysis Report
Ultrasonic Testing
Violation
.