ML20236P011
| ML20236P011 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 07/10/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20236N992 | List: |
| References | |
| 50-282-98-10, 50-306-98-10, NUDOCS 9807160111 | |
| Download: ML20236P011 (15) | |
See also: IR 05000282/1998010
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U.S. NUCLEAR REGULATORY COMMISSION
REGIONlli
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Docket Nos:
50-282;50-306
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License Nos:
1
Report Nos:
50-282/98010(DRS); 50-306/98010(DRS)
Licensee:
Northem States Power Company
Facility:
Prairie Island Nuclear Generating Plant
Location:
1717 Wakonade Drive East
,
Welch, MN 55089
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Dates:
June 5 through 12,1998
Inspectors:
M. Bielby, Reactor Engineer / Team Leader
S. Ray, Senior Resident inspector, Prairie Island
R. Winter, Reactor Engineer
~ Approved by:
M. Leach, Chief, Operator Licensing Branch
Division of Reactor Safety
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9907160111 990710
ADOCK 05000282
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EXECUTIVE SUMMARY
Prairie Island Nuclear Generating Station, Unit 1 and Unit 2
NRC Inspection Reports 50-282/98010; 50-306/98010
This special inspection report covers a period of on-site inspection into the circumstances
surrounding the Unit i reactor trip due to a dropped control rod and the actions taken for the
recovery to safe shutdown conditions on June 5,1998. The conduct of operations of the Prairie
Island staff for this event generally was good during the initial stages of the event; however, the
inspectors noted some equipment problems, and weaknesses in procedures, communications,
training, and performance.
Ooerations
The operator's initial response and actions taken based on indications for the dropped
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rod event were good; however, subsequent operator actions to stabilize the plant and
dissipate decay heat were not completely effective as evidenced by the inadvertent rise
in Tave and lifting of the steam generator (SG) #1 A safety valve. (Sections 01.1 and
04.1)
The operators lacked adequate procedural guidance for stabilizing the plant and
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dissipating decay heat by dumping steam using the SG power operated relief valves
(PORVs) during a hot shutdown condition with main steam isolation valves (MSIVs)
closed. A violation of 10 CFR Part 50, Appendix B, Criterion V was issued. (Sections
O3.1 and 04.1)
During subsequent actions to stabilize the plant, a lack of three part communication, a
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lack of consistent plant oversight, and unfamiliarity of SG PORV response contributed to
failure to adequately remove decay heat. (Section 04.1)
Operator training and practical experience at maintaining the plant in a hot shutdown
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condition with the MSIVs closed and using SG PORVs for decay heat dissipation was
limited. (Sections 04.1 and 05.1)
The simulator SG PORV fidelity was dissimilar to the plant and the licensee wrote a non-
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conformance report. (Section O5.1)
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Report Detalls
Brief Narrative of the Rod Droo Event
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The Unit i reactor was operating at 100% power on June 5,1998, and experienced an
unexpected automatic trip. The operators verified all control rods fully inserted and identified
that the first out indication was a negative flux-rate trip. The control room received reports of
steam release in the turbine building (TB) that was later identified as an unexpected relief valve
lift on the 15A feedwater heater (FWH). One of the two operating main feedwater pumps
(MFPs) tripped, as expected, and operators tripped the remaining MFP to minimize secondary
inventory loss. This action reseated the lifted FWH relief valve. The operators used the
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atmospheric steam dumps to initially remove decay heat. Operators closed the MSIVs as a
result of excessive reactor coolant system (RCS) cooldown and in response to the report of
steam in the TB. Both the #11 turbine driven auxiliary feedwater (TDAFW) and #12 motor
driven auxiliary feedwater (MDAFW) pumps automatically started and remained in service to
supply auxiliary feedwater (AFW) to both SGs. One control room operator was dedicated to
maintain both SG water levels 35% - 37% as indicated on narrow range (NR) meters.
Approximately two hours after efforts to stabilize the plant, one of the five SG "A" main steam
safety valves (#1 A) unexpectedly lifted and reseated. The resulting swell caused indicated NR
level in SG "A" to increase to 50%, and SG "B" to 45%, respectively. The licensee later
identified that the operator had placed both SG PORVs in the manual mode just prior to the
unexpected SG main steam safety valve lift.
l. Operations
01
Conduct of Operations
O1.1 Seouence of Events
a.
Insoection Scoce (71707. 93702)
The inspectors formulated a sequence of events based on the following information:
interviews conducted with the licensee's management, operations and engineering staff;
review of operator logs, parameter recorders, process computer and Emergency
Response Computer System (ERCS) information; and observation of control room
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panels,
b.
Observations and Findinos
The following information describes the sequence of events (Central Daylight Time)
commencing with the automatic reactor trip of Unit 1 from 100% power as reconstructed
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by the NRC inspection team:
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Fridav. June 5.1998
06:58 pm
Unit 1 received an automatic reactor trip, operators identified the first out
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annunciator as the negative flux rate trip. Operators entered 1E-0, * Reactor Trip
Or Safety injection," Revision 17. Operators verified all control rods fully
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inserted, one of two operating MFPs (#11) received automatic trip, #11 TDAFW
and #12 MDAFW pumps started automatically with discharge flow at 550 gpm.
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Average RCS temperature (Tave) dropped from 559 to 539 'F, and SG levels
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dropped from 45% to 0% NR.
07:01 -
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07:04 pm
Tave continued to drop to 538 'F, control room received Zone 15 TB fire alarm
and report of steam release in the TB. Operators completed Ugcedure 1E-0 and
entered 1ES-0.1, Reactor Trip Recovery, Revision 13. AFW tiow was throttled to
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200 gpm to limit cooldown, MSIVs closed to limit cooldown and stop steam
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release.
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. 07:15 pm
Operators received report that steam was due to the lift of the 15A FWH tube
side relief. Operators stopped the running #12 MFP and condensate pump to
minimize secondary inventory loss and reduce 15A FWH tube side pressure.
The lifted 15A FWH relief closed, Tave increased to 547 'F, and continued to
rise.
07:17 pm
AFW flow was increased to 270 gpm.
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07:19 pm
Tave at 555 *F, SG steam pressure at 1050 psig (SG PORV setpoint) and both
PORVs automatically opened.
07:45 pm
SG levels at 10% and continued to rise.
07:53 pm
12 SG PORV setpoint dialed down in automatic to open valve more and reduce
pressure. However, opening 12 SG PORV caused 11 SG PORV to close and
cycle.
08:08 pm
SG level approached normal band of 33 +/- 5%; however, AFW flow throttled to
60 gpm and caused SG level to decrease from 30% to 25% over the next four
- minutes.
08:10 pm
11 SG PORV setpoint dialed down in automatic, caused valve to open more and
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reduce pressure.
08:12 -
08:24 pm
AFW flow increased to 200 gpm in several steps, SG levels at 25% and started
to increase again.
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08:45-
09:04 pm
SG levels approached normal band of 33 +/- 5%, AFW flow throttled down to 50
gpm in several steps. SG levels continued to rise slowly from 33% to 36%.
During this period it appeared that the operator decreased the SG PORV
automatic setpoints in an attempt to open the PORVs more and reduce SG
pressure. On the average, SG PORVs swung open and closed 10-15% while
the controller output changed 30-40%. SG levels shrank and swelled
approximately +/- 2% while the overall level slowly increased toward the
administrative procedurallimit of 38%.
NOTE:
At 09:03 pm both SG PORV setpoints appeared to have been increased while in
automatic which closed the valves more and reduced the level swells. However,
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the decay heat removal was decreased which caused Tave to start increasing
from 552 *F.
09:07 pm
Both SG PORVs placed in manual with "11" at approximately 22% demand, and
"12" at 28%. The manual SG PORV demand was considerably less than when
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in automatic which closed the valves more and caused Tave to increase rapidly
from 553 *F.
09:12 pm
Tave at 557 'F, SG steam 9. essure at 1070 psig and one (#1 A) of five main
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steam safety valves on "A" SG lifted and reseated which swelled the "A" SG level
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from 37% to 50%, and the "B" SG level to 45%.
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09:16 pm
Tave bottomed out at 547 'F due to the SG safety valve lifting and reciosing, and
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then started to rise again.
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09:24 pm
Tave at 555 *F, both SG PORVs retumed to automatic mode and rapidly opened
and closed when SG steam pressure was greater than the PORV setpoint (1050
psig).12 SG level briefly swelled from 38% to 45%.
09:25 -
11:00 pm
Plant stabilized and slowly brought to normal hot shutdown conditions. Plant
staff investigating failure of 86G relay to lockout generator output breakers, lack
of procedural guidance in 1ES-0.1 to bypass a recently installed backup synch
check relay to allow reclosing the generator output breakers, cause of the
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automatic reactor trip, and unexpected lifting of the 15A FWH relief valve.
c.
Conclusions
The operators' initial response and actions taken based on indications for the dropped
rod event were good; however, subsequent operator actions to stabilize the plant and
dissipate decay heat were not completely effective as evidenced by the inadvertent rise
in Tave and lifting of the SG #1 A safety valve.
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Operations Procedures and Documentation
O3.1 Lack of Guidance for Dumoina Steam Usino SG PORVs
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a.
Insoection Scoce (71707. 93702)
The inspectors performed the following to determine the adequacy of guidance for
dumping steam using SG PORVs: reviewed 1ES-0.1, * Reactor Trip Recovery," Revision
13; interviewed licensed operators and managernent personnel; reviewed parameter
recorders, process computer and ERCS information.
b.
Observations and Findings
The Unit 1 EOP,1ES-0.1, Step 5 (bullet under " Response Not Obtained" column)
directed the operator to " Dump steam with SG PORVs," but did not provide any further
guidance or reference that described how to perform the evolution. During the plant
stabilization phase of the reactor trip recovery, the operator was required to maintain SG
levels 28 - 38%. The operator initially left both SG PORVs in the normal automatic
configuration and was very slowly adjusting the controller pot down from the normal
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operating setpoint of 75% (1050 psig) to the no Ioad setpoint of 71.5% (1005 psig). The
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PORVs' responsiveness resulted in erratic SG level swings. In lieu of procedural
guidance and with the PORV auto setpoint at approximately 74.2% (1040 psig), the lead
reactor operator (LRO) placed both SG PORV controllers in manual to reduce the erratic
SG ievel swings and attempted to maintain SG level ! ass than the 38% administrative
limit by controlling AFW flow. However, the operdor failed to open the PORVs
sufficiently and the dissipation of decay heat was inadequate. As a result, Tave
continued to increase which caused the SG pressure to increase to the 1 A SG safety
valve setpoint of 1075 psig and it cycled open and close. The lack of adequate
procedural guidance for dumping steam using SG PORVs was considered a violation of
10 CFR Part 50, Appendix B, Criterion V," Instructions, Procedures, and Drawings,"(50-
282/98010-01(DRS)); (50-306/98010-01(DRS)).
Subsequent to the event, the licensee revised both unit EOPs,1ES-0.1 and 2ES-0.1, to
direct reduction of the SG PORVs auto setpoint to 71.5% (1005 psig)if MSIVs are
closed. Additionally, the same procedures were changed to direct the operator to stop
feed flow to a SG if level reaches 40%, vice 50%.
c.
Conclusions
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The operators lacked adequate procedural guidance for stabilizing the plant and
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dissipating decay heat by dumping steam using the SG PORVs during a hot shutdown
condition with MSIVs closed. A violation of 10 CFR Part 50, Appendix B, Criterion V
was issued.
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04
Operator Knowledge and Performance
04.1 -Coerator Resoonse to Rod Droo Event
a.
Insoection Scone (71707. 93702)
The inspectors reviewed operator performance based on their initial response to the
reactor trip and mode change to hot shutdown conditions. The inspectors based their
findings on the following: Interviews conducted with operations and engineering staff;
review of operator logs, parameter recorders, process computer and ERCS information;
review of alarm response, emergency, abnormal, and normal operating procedures.
b.
Observations and Findinas
The Unit 1 control room operators' initial response to the rod drop event was good. The
shift manager (SM) assumed the role of shift technical advisor (STA), the Unit 1 shift
supervisor (SS) assumed the role of emergency operating procedure (EOP) reader, the
Unit 1 LRO took control of the secondary plant, and the other Unit i reactor operator
(RO) took control of the primary plant. The crew correctly identified that an automatic
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reactor trip had occurred and promptly entered EOP 1E-0, * Reactor Trip Or Safety
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Injection," Revision 17. After completing the specified procedural actions, the crew
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correctly transitioned to 1ES-0.1, " Reactor Trip Recovery," Revision 13. The LRO
appropriately throttled AFW flow to limit cooldown. A TB fire alarm was received, and
after investigating, field operators identified an unexpected steam release in the TB.
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Concurrently, control room personnel identified an excessive primary cooldown based
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on a Tave decrease to 538 'F. The control room operators responded to the excessive
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primary cooldown and closed the MSIVs and bypass valves. The single operating MFP
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and condensate pump were stopped to minimize secondary inventory loss. Further
reports from the TB clarified the steam release had come from an unexpected lifted tube
side relief on the 15A FWH that reseated after tripping the MFP As a result of those
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actions, Tave increased to 547 'F and continued to slowly rise. The operators attempte.,d
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to stabilize the plant in a hot shutdown condition with the MSIVs closed and maintain the
following parameters as specified by 1ES-0.1: pressurizer (PRZR) pressure between
2220 and 2250 psig; PRZR level between 19 and 23%; SG NR level between 30 and
36%; and RCS Tave between 545 and 549 'F.
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The crew was directed to maintain a plant condition that had not been practiced during
simulator training. The crew had used PORVs for post accident cooldown in several
simulator scenarios; however, they had not maintained a hot shutdown condition with
the MSIVs closed and using SG PORVs for decay heat removal. Additionally, they
determined the plant was stabilized and transitioned from 1ES-0.1, " Reactor Trip
Recovery," to 1C1.3, " Unit 1 Shutdown," Revision 40. However, even though plant
parameters were not changing rapidly, the SG levels continued to trend toward the
administrative and design limits, and Tave was actually 552 'F vice the required
545 - 549 'F.
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The STA/SM and SS determined the plant was stable because they had transitioned to
the shutdown procedure. Consequently they relaxed their continued oversight of the
plant status and became focused on their administrative duties. The STA observed that
no critical safety functions had been entered and resumed the SM duties of notifications.
Likewise, the SS focused his attention on followup of equipment problems with the FWH
relief valve and generator output breaker relays, procedure problem with the backup
bypass for the synch check relay, restoring the fire alarms, diagnosing the cause of the
reactor trip, and completing logs.
The lack of adequate procedural guidance was a contributor to the subsequent poor
operator performance. The LRO was required to maintain SG levels 33+/-5%, and had
been periodically throttling AFW flow. The LRO was also directed to dump steam with
SG PORVs in accordance with 1ES-0.1, but was not provided with any further guidance
that described how to perform the evolution. The LRO initially left both SG PORVs in
the normal automatic configuration and very slowly started to adjust the controller pot
down from the normal operating setpoint of 75% (1050 psig) to the no load setpoint of
71.5% (1005 psig).
The erratic response of the SG PORVs was unexpected. The LRO had very slowly
decreased the SG PORV setpoint to 74.2% (1040 psig). However, the PORV operation
was very responsive and wesed erratic SG level swings which was unexpected to the
LRO. The PORVs opened every 5 - 10 seconds and caused SG level swell and shrink
of about 2%.
An instance of poor communications and lack of communications contributed to the
indicated SG level exceeding the design limit, inadequate dissipation of decay heat, and
lifting of the main steam safety valve. The LRO tried to maintain both SG levels within
the procedurallimits. The automatic response of the PORVs and erratic SG level
swings were unexpected. The LRO stated he made a verbal announcement that he
was placing the SG PORVs in manual; however, no acknowledgment was made by any
of the other control room operators. As such the communications were not in
accordance with Section Work Instruction (SWI) O-24, " Operation Section
Communications," Revision 4. When one SG level approached the 38% limit the LRO
placed both SG PORVs in manual with each PORV approximately 50% open. The
operator decreased AFW flow to maintain SG levelless than the 38% limit. The PORVs
were insufficiently opened to dissipate the decay heat and Tave continued to increase
which caused the SG pressure to increase to the 1 A SG safety valve setpoint of 1075
psig, and it cycled open and close. The cycling of the safety valve resulted in a large
SG swell to 45-50% which alerted the SS. The LRO informed the SS that both SG
PORVs were in manual. The SS checked safety valve tailpipe temperatures and
determined the 1A safety on 11 SG had cycled. Teve decreased to a minimum of 547 *F
due to the open safety valve. The LRO returned the SG PORV control to automatic
within about 12 minutes at which time the PORVs briefly cycled because steam
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pressure was greater than 1050 psig. The plant was stabilized and in hot shutdown
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conditions within about another 30 minutes.
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c.
Conclusions
During subsequent actions to stabilize the plant a lack of three part communication, lack
of consistent plant oversight, and unfamiliarity of SG PORV response contributed to
failure to adequately remove decay heat.
05
Operator Training and Qualification
05.1 SG Level / SG PORV / Hot Shutdown With MSIVs Closed
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a.
Insoection Scoce (71707. 93702)
The inspectors interviewed training and operations staff and management, and
observed a scenario run under hot shutdown conditions with MSIVs closed.
b.
Observations and Findinos
The inspectors requested the training staff to run a scenario under hot shutdown
conditions with MSIVs closed to observe operation of the SG PORVs and resulting SG
level shrink and swell. The inspectors observed that the simulator SG PORV response
was much smoother and resulted in no erratic SG shrink and swell when compared to
the recorder traces for SG level and PORV position taken during the plant event. The
licensee identified the plant SG PORV gain was set at "20", and the integral at "0", but
was not sure if the simulator modeling corresponded to the plant. The licensee stated it
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noimally reviewed all plant modifications and work packages to determine applicability
to potential simulator hardware or software changes. The licensee wrote a
non-conformance report to verify the plant SG PORV operation and to determine
the simulator SG PORV fidelity to actual plant operation and to investigate how the
simulator modeled SG level and AFW flow.
During the post event interviews, several operators identified they had been directed to
maintain a plant condition that they had little training and practical experience
performing. Operators had used PORVs for post accident cooldown in several simulator
scenarios; however, they had not maintained a hot sheldown condition with the MSIVs
closed and using SG PORVs for decay heat dissipation. The training staff verified that
little time had been spent in dynamic scenarios under hot shutdown conditions, but
stated that training would be set up for the next requal training cycle (mid July,1998) to
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discuss the rod drop event and maintenance of hot shutdown conditions in detail;
emphasize the importance of the SG PORVs to safety; discuss the conflict of SG level,
AFW flow, and maintaining RCS temperature; discuss new operational guidelines;
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discuss the expectation for use of three part communications and plant oversight; and
run a similar dynamic scenario event on the simulator. The licensee stated that an
e-mail would be sent to all operators describing the event, equipment, procedural and
operator performance weaknesses identified during the event, and Just-in-Time training
would be scheduled.
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c.
Conclusions
Operator training and practical experience at maintaining the plant in a hot shutdown
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condition with the MSIVs closed and using SG PORVs for decay heat dissipation was
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limited. The simulator SG PORV fidelity was dissimilar to the plant.
lit. Engineering
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Conduct of Engineering
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E1.1 - Root Cause of Rod Droo (G7)
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a.
Insoection Scone (71707. 93702)
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On June 5,1998, the plant experienced a negative rate reactor trip as the result of a
dropped control rod (G7). The inspectors assessed the licensee's investigation team
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review of the root cause for the dropped control rod.
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b.
~ Observations and Findinas
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. The licensee's initial root cause identification of the control rod drop was inconclusive.
The licensee identified the stationary gripper coil fuse had blown on control rod #G-7
due to a ground in the wiring somewhere between the edge of the reactor cavity and the
reactor head. The affected control rod cable and four other potentially' degraded control
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rod cables were replaced. Two of the cables exhibited lower than expected cable
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resistance readings, and the other two cables were located in the center, higher
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temperature, region of the reactor. The licensee added a moisture barrier tape,
model on all 29 rods, and scheduled rod timing checks.
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meggered and pin to pin resistance checked connectors, replaced all fuses with a new
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The failed cable was shipped to the vendor for analysis. The preliminary report
identified that a black carbonized material in the connector had created an arc between
the conductors when a meggering voltage was applied. Further chemical analysis was
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scheduled to identify the source of the material and the root cause determination was
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inconclusive as to whether the failure mode was based on a manufacturing flaw or if the
condition developed over time due to environmental effects such as moisture intrusion.
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At the end of this report period, the licensee's investigation team had not yet issued the
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final report of their findings.
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c.
Conclusions
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'On June 5,1998, the plant experienced a negative rate reactor trip as the result of a
dropped control rod (G7). The licensee assigned a root causs investigation team;
however, a final report haa not been issued.
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E1.2 Root Cause of 15A PNH Tube Side Relief Lift
- a.
Insoection Scone (71707. 93702)
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On June 5,1998, the plant experienced an automatic reactor trip that resulted in an
unexpected lift of the 15A FWH tube side relief valve. The inspectors assessed the
licensee's investigation team review of the root cause for the unexpected event,
b.
Observations and Findinas
The licensee's initial root cause identification of the FWH tube side relief lift after the
reactor trip was inconclusive. The licensee wrote a non-conformance report and
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identified that the relief lifted at the expected pressure setpoint. The licensee verified
that all FWH system components mechanically worked as designed. However, the
system engineer identified the condensate pump and MFP pressure was higher than
indicated on the characteristic pump pressure curves. The system engineer identified
the impellers had been modified which could have resulted in the pump curve
inaccuracy and inappropriate relief valve setpoint. The system engineer further
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identified that a design change may be required for changing the FWH relief setpoint
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based on the new pump curves. At the end of this report period, the licensee's
. investigation team had not yet issued the final report of their findings.
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c.
Conclusions
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On June 5,1998, the plant experienced an automatic reactor trip that resulted in an
unexpected lift of the 15A FWH tube side relief valve. The licensee assigned a root
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cause investigation team; however, a final report had not been issued.
V. Management Meetings
X1
Exit Meeting Summary
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The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on June 12,1998. The licensee acknowledged the findings
presented. The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary. No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED
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Licensee
K.- Albrecht, General Superintendent Engineering, Electrical / Instrumentation & Controls
T. Amundson, General Superintendent Engineering, Mechanical
T. Breene, Superintendent Nuclear Engineering
J. Hill, Manager Quality Services
M. Ladd, Training Process Manager
G. Lenertz, General Superintendent Plant Maintenance
R. Lindsey, General Superintendent Safety Assessment
T. Silverberg, General Superintendent Plant Operations
J. Sorensen, Plant Manager
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INSPECTION PRCCEDURES USE3
IP 71707:
Plant Operations
IP 93702:
Response to Events
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-282/98010-01
50-306/98010-01
Inadequate procedure for dumping steam with steam generator
poweroperated relief valves.
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Closed
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None.
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Discussed
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None.
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LIST OF ACRONYMS USED
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AWI
Administrative Work Instruction
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CFR
Code of Federal Regulations
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Division of Reactor Projects
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Division of Reactor Safety
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Emergency Operating Procedure
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ERCS
Emergency Response Computer System
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Degrees Fahrenheit
gpm
Gallons Per Minute
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IP
Inspection Procedure
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LER
Licensee Event Report
LRO
Lead Reactor Operator
Motor Driven Auxiliary Feedwater
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Main Feedwater Pump
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NR
Narrow Range
NRC
Nuclear Regulatory Commission
Northern States Power Company
Power Operated Relief Valves
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PRZR
Pressurizer
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psig
Pounds Per Square Inch-Gauge
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Reactor Operator
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Shift Manager
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Shift Supervisor
SWI
Section Work Instruction
Turbine Building
Turbine Driven Auxiliary Feedwater
Tavg
Average Reactor Coolant System Temperature
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Violation
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LIST OF DOCUMENTS REVIEWED
Procedure #
Revision #
Ijilg
Revision 17
Reactor Trip Or Safety injection
1 ES-0.1
Rev 13
Reactor Trip Recovery
1C1.3
Rev 40
Unit 1 Shutdown
SWI O-24
Rev 4
Operation Section Communications
5AWI 3.1.2
Rev 8
Shift Manager Program
SWI 0-10
Rev 30
Operation Manual Usage
2ES-0.1
Rev 12
Reactor Trip Recovery
1
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15
l
1