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| {{Adams
| | #REDIRECT [[IR 05000282/1998010]] |
| | number = ML20236P011
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| | issue date = 07/10/1998
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| | title = Insp Repts 50-282/98-10 & 50-306/98-10 on 980605-12. Violations Noted.Major Areas inspected:on-site Insp Into Circumstances Surrounding Unit 1 Rt Due to Dropped CR & Actions Taken for Recovery to Safe Shutdown on 980605
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| | author name =
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| | author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
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| | addressee name =
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| | addressee affiliation =
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| | docket = 05000282, 05000306
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| | license number =
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| | contact person =
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| | document report number = 50-282-98-10, 50-306-98-10, NUDOCS 9807160111
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| | package number = ML20236N992
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| | document type = INSPECTION REPORT, NRC-GENERATED, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
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| | page count = 15
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| }}
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| See also: [[see also::IR 05000282/1998010]]
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| =Text=
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| {{#Wiki_filter:- _ _ _ _ - _ _ _ _ _ - _ _ - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ . _ _ __ . _ _ _ . _ _ _ _ _ _ - - _ _ _ _ _ _ _ .
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| U.S. NUCLEAR REGULATORY COMMISSION
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| REGIONlli .
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| Docket Nos: 50-282;50-306
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| License Nos: DPR-42; DPR-60
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| 1
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| Report Nos: 50-282/98010(DRS); 50-306/98010(DRS)
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| Licensee: Northem States Power Company
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| Facility: Prairie Island Nuclear Generating Plant
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| Location: 1717 Wakonade Drive East ,
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| Welch, MN 55089 l
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| Dates: June 5 through 12,1998
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| Inspectors: M. Bielby, Reactor Engineer / Team Leader
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| S. Ray, Senior Resident inspector, Prairie Island
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| R. Winter, Reactor Engineer
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| ~ Approved by: M. Leach, Chief, Operator Licensing Branch ;
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| Division of Reactor Safety
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| 9907160111 990710
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| PDR ADOCK 05000282
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| !. G PDR l.
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| ______ _ - _____. . - - . .-
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| EXECUTIVE SUMMARY
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| Prairie Island Nuclear Generating Station, Unit 1 and Unit 2
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| NRC Inspection Reports 50-282/98010; 50-306/98010
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| This special inspection report covers a period of on-site inspection into the circumstances
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| surrounding the Unit i reactor trip due to a dropped control rod and the actions taken for the
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| recovery to safe shutdown conditions on June 5,1998. The conduct of operations of the Prairie
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| Island staff for this event generally was good during the initial stages of the event; however, the
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| inspectors noted some equipment problems, and weaknesses in procedures, communications,
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| training, and performance.
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| Ooerations
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| .
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| 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
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| dissipate decay heat were not completely effective as evidenced by the inadvertent rise
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| in Tave and lifting of the steam generator (SG) #1 A safety valve. (Sections 01.1 and
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| 04.1)
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| .
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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 power operated relief valves
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| (PORVs) during a hot shutdown condition with main steam isolation valves (MSIVs)
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| closed. A violation of 10 CFR Part 50, Appendix B, Criterion V was issued. (Sections
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| O3.1 and 04.1)
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| .
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| 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
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| failure to adequately remove decay heat. (Section 04.1)
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| .
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| 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. (Sections 04.1 and 05.1)
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| .
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| 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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| 2
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| Report Detalls
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| Brief Narrative of the Rod Droo Event l
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| The Unit i reactor was operating at 100% power on June 5,1998, and experienced an
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| unexpected automatic trip. The operators verified all control rods fully inserted and identified
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| that the first out indication was a negative flux-rate trip. The control room received reports of
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| steam release in the turbine building (TB) that was later identified as an unexpected relief valve
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| lift on the 15A feedwater heater (FWH). One of the two operating main feedwater pumps
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| (MFPs) tripped, as expected, and operators tripped the remaining MFP to minimize secondary
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| inventory loss. This action reseated the lifted FWH relief valve. The operators used the 3
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| atmospheric steam dumps to initially remove decay heat. Operators closed the MSIVs as a l
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| result of excessive reactor coolant system (RCS) cooldown and in response to the report of
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| steam in the TB. Both the #11 turbine driven auxiliary feedwater (TDAFW) and #12 motor
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| driven auxiliary feedwater (MDAFW) pumps automatically started and remained in service to
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| supply auxiliary feedwater (AFW) to both SGs. One control room operator was dedicated to
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| maintain both SG water levels 35% - 37% as indicated on narrow range (NR) meters. l
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| Approximately two hours after efforts to stabilize the plant, one of the five SG "A" main steam
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| safety valves (#1 A) unexpectedly lifted and reseated. The resulting swell caused indicated NR
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| level in SG "A" to increase to 50%, and SG "B" to 45%, respectively. The licensee later
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| identified that the operator had placed both SG PORVs in the manual mode just prior to the
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| unexpected SG main steam safety valve lift.
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| l. Operations
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| 01 Conduct of Operations
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| O1.1 Seouence of Events
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| a. Insoection Scoce (71707. 93702)
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| The inspectors formulated a sequence of events based on the following information:
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| interviews conducted with the licensee's management, operations and engineering staff;
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| review of operator logs, parameter recorders, process computer and Emergency
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| Response Computer System (ERCS) information; and observation of control room
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| l panels,
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| b. Observations and Findinos
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| The following information describes the sequence of events (Central Daylight Time)
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| i commencing with the automatic reactor trip of Unit 1 from 100% power as reconstructed
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| l by the NRC inspection team:
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| ___ .
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| Fridav. June 5.1998
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| 1
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| 06:58 pm Unit 1 received an automatic reactor trip, operators identified the first out i
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| annunciator as the negative flux rate trip. Operators entered 1E-0, * Reactor Trip
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| 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 l
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| 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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| i dropped from 45% to 0% NR.
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| 07:01 -
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| l 07:04 pm Tave continued to drop to 538 'F, control room received Zone 15 TB fire alarm
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| and report of steam release in the TB. Operators completed Ugcedure 1E-0 and
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| entered 1ES-0.1, Reactor Trip Recovery, Revision 13. AFW tiow was throttled to
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| l
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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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| 07:07 -
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| . 07:15 pm Operators received report that steam was due to the lift of the 15A FWH tube
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| side relief. Operators stopped the running #12 MFP and condensate pump to
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| minimize secondary inventory loss and reduce 15A FWH tube side pressure.
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| The lifted 15A FWH relief closed, Tave increased to 547 'F, and continued to
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| rise.
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| 07:17 pm AFW flow was increased to 270 gpm. i
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| 07:19 pm Tave at 555 *F, SG steam pressure at 1050 psig (SG PORV setpoint) and both
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| PORVs automatically opened.
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| 07:45 pm SG levels at 10% and continued to rise.
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| 07:53 pm 12 SG PORV setpoint dialed down in automatic to open valve more and reduce ;
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| pressure. However, opening 12 SG PORV caused 11 SG PORV to close and
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| cycle.
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| 08:08 pm SG level approached normal band of 33 +/- 5%; however, AFW flow throttled to l
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| 60 gpm and caused SG level to decrease from 30% to 25% over the next four
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| - minutes.
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| 08:10 pm 11 SG PORV setpoint dialed down in automatic, caused valve to open more and I
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| '
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| reduce pressure.
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| 08:12 -
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| 08:24 pm AFW flow increased to 200 gpm in several steps, SG levels at 25% and started
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| to increase again.
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| 4
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| _ _ _ _ _____ _ _ ____
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| 08:45-
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| 09:04 pm SG levels approached normal band of 33 +/- 5%, AFW flow throttled down to 50
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| gpm in several steps. SG levels continued to rise slowly from 33% to 36%.
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| During this period it appeared that the operator decreased the SG PORV
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| automatic setpoints in an attempt to open the PORVs more and reduce SG
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| pressure. On the average, SG PORVs swung open and closed 10-15% while
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| the controller output changed 30-40%. SG levels shrank and swelled
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| approximately +/- 2% while the overall level slowly increased toward the
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| administrative procedurallimit of 38%.
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| NOTE: At 09:03 pm both SG PORV setpoints appeared to have been increased while in
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| automatic which closed the valves more and reduced the level swells. However, l
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| the decay heat removal was decreased which caused Tave to start increasing
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| from 552 *F.
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| 09:07 pm Both SG PORVs placed in manual with "11" at approximately 22% demand, and
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| "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
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| from 553 *F.
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| 09:12 pm Tave at 557 'F, SG steam 9. essure at 1070 psig and one (#1 A) of five main i
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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
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| and closed when SG steam pressure was greater than the PORV setpoint (1050
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| psig).12 SG level briefly swelled from 38% to 45%.
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| 09:25 -
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| 11:00 pm Plant stabilized and slowly brought to normal hot shutdown conditions. Plant
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| staff investigating failure of 86G relay to lockout generator output breakers, lack
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| of procedural guidance in 1ES-0.1 to bypass a recently installed backup synch
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| check relay to allow reclosing the generator output breakers, cause of the
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| j automatic reactor trip, and unexpected lifting of the 15A FWH relief valve.
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| c. Conclusions
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| The operators' 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
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| dissipate decay heat were not completely effective as evidenced by the inadvertent rise
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| in Tave and lifting of the SG #1 A safety valve.
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| 5
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| 03 Operations Procedures and Documentation
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| O3.1 Lack of Guidance for Dumoina Steam Usino SG PORVs
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| 1
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| a. Insoection Scoce (71707. 93702)
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| The inspectors performed the following to determine the adequacy of guidance for
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| dumping steam using SG PORVs: reviewed 1ES-0.1, * Reactor Trip Recovery," Revision
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| 13; interviewed licensed operators and managernent personnel; reviewed parameter
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| recorders, process computer and ERCS information.
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| b. Observations and Findings
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| The Unit 1 EOP,1ES-0.1, Step 5 (bullet under " Response Not Obtained" column)
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| directed the operator to " Dump steam with SG PORVs," but did not provide any further
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| guidance or reference that described how to perform the evolution. During the plant
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| stabilization phase of the reactor trip recovery, the operator was required to maintain SG
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| levels 28 - 38%. The operator initially left both SG PORVs in the normal automatic
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| 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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| l PORVs' responsiveness resulted in erratic SG level swings. In lieu of procedural
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| guidance and with the PORV auto setpoint at approximately 74.2% (1040 psig), the lead
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| reactor operator (LRO) placed both SG PORV controllers in manual to reduce the erratic
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| SG ievel swings and attempted to maintain SG level ! ass than the 38% administrative
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| limit by controlling AFW flow. However, the operdor failed to open the PORVs
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| sufficiently and the dissipation of decay heat was inadequate. As a result, Tave
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| continued to increase which caused the SG pressure to increase to the 1 A SG safety
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| valve setpoint of 1075 psig and it cycled open and close. The lack of adequate
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| procedural guidance for dumping steam using SG PORVs was considered a violation of
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| 10 CFR Part 50, Appendix B, Criterion V," Instructions, Procedures, and Drawings,"(50-
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| 282/98010-01(DRS)); (50-306/98010-01(DRS)).
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| Subsequent to the event, the licensee revised both unit EOPs,1ES-0.1 and 2ES-0.1, to
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| direct reduction of the SG PORVs auto setpoint to 71.5% (1005 psig)if MSIVs are
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| closed. Additionally, the same procedures were changed to direct the operator to stop
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| feed flow to a SG if level reaches 40%, vice 50%.
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| c. Conclusions
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| ,
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| The operators lacked adequate procedural guidance for stabilizing the plant and !
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| I
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| dissipating decay heat by dumping steam using the SG PORVs during a hot shutdown
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| condition with MSIVs closed. A violation of 10 CFR Part 50, Appendix B, Criterion V
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| was issued. i
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| 04 Operator Knowledge and Performance
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| 04.1 -Coerator Resoonse to Rod Droo Event
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| a. Insoection Scone (71707. 93702)
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| The inspectors reviewed operator performance based on their initial response to the
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| reactor trip and mode change to hot shutdown conditions. The inspectors based their
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| findings on the following: Interviews conducted with operations and engineering staff;
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| review of operator logs, parameter recorders, process computer and ERCS information;
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| review of alarm response, emergency, abnormal, and normal operating procedures.
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| b. Observations and Findinas
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| The Unit 1 control room operators' initial response to the rod drop event was good. The
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| shift manager (SM) assumed the role of shift technical advisor (STA), the Unit 1 shift
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| supervisor (SS) assumed the role of emergency operating procedure (EOP) reader, the
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| Unit 1 LRO took control of the secondary plant, and the other Unit i reactor operator
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| (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 l
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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
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| appropriately throttled AFW flow to limit cooldown. A TB fire alarm was received, and
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| after investigating, field operators identified an unexpected steam release in the TB. ,
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| '
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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 j'
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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
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| reports from the TB clarified the steam release had come from an unexpected lifted tube ;
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| side relief on the 15A FWH that reseated after tripping the MFP As a result of those !
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| ,
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| '
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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
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| following parameters as specified by 1ES-0.1: pressurizer (PRZR) pressure between
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| 2220 and 2250 psig; PRZR level between 19 and 23%; SG NR level between 30 and
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| 36%; and RCS Tave between 545 and 549 'F.
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| l
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| The crew was directed to maintain a plant condition that had not been practiced during
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| simulator training. The crew had used PORVs for post accident cooldown in several
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| simulator scenarios; however, they had not maintained a hot shutdown condition with
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| the MSIVs closed and using SG PORVs for decay heat removal. Additionally, they
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| determined the plant was stabilized and transitioned from 1ES-0.1, " Reactor Trip
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| Recovery," to 1C1.3, " Unit 1 Shutdown," Revision 40. However, even though plant
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| parameters were not changing rapidly, the SG levels continued to trend toward the
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| administrative and design limits, and Tave was actually 552 'F vice the required
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| 545 - 549 'F.
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| l
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| 1
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| *
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| 1
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| The STA/SM and SS determined the plant was stable because they had transitioned to
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| the shutdown procedure. Consequently they relaxed their continued oversight of the
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| plant status and became focused on their administrative duties. The STA observed that
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| no critical safety functions had been entered and resumed the SM duties of notifications.
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| Likewise, the SS focused his attention on followup of equipment problems with the FWH
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| relief valve and generator output breaker relays, procedure problem with the backup
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| bypass for the synch check relay, restoring the fire alarms, diagnosing the cause of the
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| reactor trip, and completing logs.
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| The lack of adequate procedural guidance was a contributor to the subsequent poor
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| operator performance. The LRO was required to maintain SG levels 33+/-5%, and had
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| been periodically throttling AFW flow. The LRO was also directed to dump steam with
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| SG PORVs in accordance with 1ES-0.1, but was not provided with any further guidance
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| that described how to perform the evolution. The LRO initially left both SG PORVs in
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| the normal automatic configuration and very slowly started to adjust the controller pot
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| down from the normal operating setpoint of 75% (1050 psig) to the no load setpoint of
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| 71.5% (1005 psig).
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| The erratic response of the SG PORVs was unexpected. The LRO had very slowly
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| decreased the SG PORV setpoint to 74.2% (1040 psig). However, the PORV operation
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| was very responsive and wesed erratic SG level swings which was unexpected to the
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| LRO. The PORVs opened every 5 - 10 seconds and caused SG level swell and shrink
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| of about 2%.
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| An instance of poor communications and lack of communications contributed to the
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| indicated SG level exceeding the design limit, inadequate dissipation of decay heat, and
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| lifting of the main steam safety valve. The LRO tried to maintain both SG levels within
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| the procedurallimits. The automatic response of the PORVs and erratic SG level
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| swings were unexpected. The LRO stated he made a verbal announcement that he
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| was placing the SG PORVs in manual; however, no acknowledgment was made by any
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| of the other control room operators. As such the communications were not in
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| accordance with Section Work Instruction (SWI) O-24, " Operation Section
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| Communications," Revision 4. When one SG level approached the 38% limit the LRO
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| placed both SG PORVs in manual with each PORV approximately 50% open. The
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| operator decreased AFW flow to maintain SG levelless than the 38% limit. The PORVs
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| were insufficiently opened to dissipate the decay heat and Tave continued to increase
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| which caused the SG pressure to increase to the 1 A SG safety valve setpoint of 1075
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| psig, and it cycled open and close. The cycling of the safety valve resulted in a large
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| SG swell to 45-50% which alerted the SS. The LRO informed the SS that both SG
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| PORVs were in manual. The SS checked safety valve tailpipe temperatures and
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| determined the 1A safety on 11 SG had cycled. Teve decreased to a minimum of 547 *F
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| due to the open safety valve. The LRO returned the SG PORV control to automatic
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| within about 12 minutes at which time the PORVs briefly cycled because steam
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| l pressure was greater than 1050 psig. The plant was stabilized and in hot shutdown
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| l conditions within about another 30 minutes.
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| 8
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| -
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| c. Conclusions
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| During subsequent actions to stabilize the plant a lack of three part communication, lack
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| of consistent plant oversight, and unfamiliarity of SG PORV response contributed to
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| failure to adequately remove decay heat.
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| 05 Operator Training and Qualification
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| 05.1 SG Level / SG PORV / Hot Shutdown With MSIVs Closed i
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| a. Insoection Scoce (71707. 93702)
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| The inspectors interviewed training and operations staff and management, and
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| observed a scenario run under hot shutdown conditions with MSIVs closed.
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| b. Observations and Findinos
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| 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
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| level shrink and swell. The inspectors observed that the simulator SG PORV response
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| 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
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| licensee identified the plant SG PORV gain was set at "20", and the integral at "0", but
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| was not sure if the simulator modeling corresponded to the plant. The licensee stated it l
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| noimally reviewed all plant modifications and work packages to determine applicability
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| to potential simulator hardware or software changes. The licensee wrote a
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| non-conformance report to verify the plant SG PORV operation and to determine
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| the simulator SG PORV fidelity to actual plant operation and to investigate how the
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| simulator modeled SG level and AFW flow.
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| During the post event interviews, several operators identified they had been directed to
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| maintain a plant condition that they had little training and practical experience
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| performing. Operators had used PORVs for post accident cooldown in several simulator
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| scenarios; however, they had not maintained a hot sheldown condition with the MSIVs
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| closed and using SG PORVs for decay heat dissipation. The training staff verified that
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| little time had been spent in dynamic scenarios under hot shutdown conditions, but
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| 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;
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| emphasize the importance of the SG PORVs to safety; discuss the conflict of SG level,
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| AFW flow, and maintaining RCS temperature; discuss new operational guidelines; l
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| discuss the expectation for use of three part communications and plant oversight; and
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| run a similar dynamic scenario event on the simulator. The licensee stated that an
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| 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.
| |
| 9
| |
| | |
| - _ - _ _ - _ - _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _
| |
| '
| |
| ,
| |
| f c. Conclusions
| |
| Operator training and practical experience at maintaining the plant in a hot shutdown
| |
| l condition with the MSIVs closed and using SG PORVs for decay heat dissipation was
| |
| '
| |
| limited. The simulator SG PORV fidelity was dissimilar to the plant.
| |
| lit. Engineering
| |
| E1 Conduct of Engineering
| |
| ; e
| |
| '
| |
| E1.1 - Root Cause of Rod Droo (G7)
| |
| i
| |
| L a. Insoection Scone (71707. 93702) '
| |
| l 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
| |
| j review of the root cause for the dropped control rod.
| |
| I: .
| |
| L b. ~ Observations and Findinas
| |
| ]
| |
| . 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 -!
| |
| .
| |
| rod cables were replaced. Two of the cables exhibited lower than expected cable i
| |
| resistance readings, and the other two cables were located in the center, higher 1
| |
| l- temperature, region of the reactor. The licensee added a moisture barrier tape, I
| |
| '
| |
| ; . meggered and pin to pin resistance checked connectors, replaced all fuses with a new
| |
| ''
| |
| ;. model on all 29 rods, and scheduled rod timing checks.
| |
| 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
| |
| !
| |
| scheduled to identify the source of the material and the root cause determination was
| |
| 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. !
| |
| !
| |
| '
| |
| At the end of this report period, the licensee's investigation team had not yet issued the
| |
| final report of their findings.
| |
| l
| |
| c. Conclusions
| |
| .
| |
| '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.
| |
| ,p
| |
| 10
| |
| | |
| _ _ _ _
| |
| .
| |
| -
| |
| i
| |
| s.
| |
| s
| |
| l
| |
| E1.2 Root Cause of 15A PNH Tube Side Relief Lift
| |
| : a. Insoection Scone (71707. 93702)
| |
| i:
| |
| 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
| |
| _
| |
| 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
| |
| i inaccuracy and inappropriate relief valve setpoint. The system engineer further ,
| |
| '
| |
| l
| |
| identified that a design change may be required for changing the FWH relief setpoint
| |
| 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.
| |
| l c. Conclusions
| |
| l 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
| |
| l cause investigation team; however, a final report had not been issued.
| |
| V. Management Meetings
| |
| l
| |
| 4
| |
| X1 Exit Meeting Summary
| |
| n
| |
| 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.
| |
| j
| |
| 11
| |
| p
| |
| | |
| _ - _ _ _ _ _ - _ . - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - .
| |
| :
| |
| .
| |
| PARTIAL LIST OF PERSONS CONTACTED l
| |
| 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
| |
| l
| |
| 1
| |
| l
| |
| !
| |
| i
| |
| 1
| |
| 1
| |
| l
| |
| !
| |
| 1
| |
| I
| |
| l
| |
| 1
| |
| l
| |
| '
| |
| 12
| |
| ;
| |
| | |
| (::
| |
| \-
| |
| : ,
| |
| 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 VIO Inadequate procedure for dumping steam with steam generator l
| |
| poweroperated relief valves. i
| |
| i
| |
| Closed
| |
| I None.
| |
| !
| |
| l Discussed
| |
| !
| |
| None.
| |
| !
| |
| ! *'
| |
| !
| |
| > 1
| |
| :
| |
| !
| |
| l
| |
| !
| |
| l
| |
| !
| |
| 13
| |
| .
| |
| | |
| _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - - _ _ _ .
| |
| .
| |
| LIST OF ACRONYMS USED
| |
| l AFW Auxiliary Feedwater
| |
| l AWI Administrative Work Instruction
| |
| l CFR Code of Federal Regulations
| |
| l DRP Division of Reactor Projects
| |
| l DRS Division of Reactor Safety
| |
| l EOP Emergency Operating Procedure
| |
| l
| |
| '
| |
| ERCS Emergency Response Computer System
| |
| *F Degrees Fahrenheit
| |
| FWH Feedwater Heater
| |
| ,
| |
| gpm Gallons Per Minute
| |
| '
| |
| IP Inspection Procedure
| |
| LER Licensee Event Report
| |
| LRO Lead Reactor Operator
| |
| MDAFW Motor Driven Auxiliary Feedwater I
| |
| ,
| |
| MFP Main Feedwater Pump
| |
| l MSIV Main Steam isolation Valve
| |
| NR Narrow Range
| |
| NRC Nuclear Regulatory Commission
| |
| NSP Northern States Power Company
| |
| PORV Power Operated Relief Valves I
| |
| PRZR Pressurizer l
| |
| ,
| |
| psig Pounds Per Square Inch-Gauge l
| |
| l RCS Reactor Coolant System !
| |
| RO Reactor Operator
| |
| SG Steam Generator l
| |
| SM Shift Manager j
| |
| SS Shift Supervisor
| |
| STA Shift Technical Advisor
| |
| SWI Section Work Instruction
| |
| TB Turbine Building
| |
| TDAFW Turbine Driven Auxiliary Feedwater
| |
| Tavg Average Reactor Coolant System Temperature l
| |
| VIO Violation
| |
| l
| |
| l
| |
| ,
| |
| 14
| |
| 1
| |
| ______________a
| |
| | |
| . _ _ _ _ _ _ _ _ . - _ . _ - _ - _ - _ - _ _ - - _ _ _
| |
| _ _ _ - _ _ _ - _ _ _ _ -
| |
| -
| |
| LIST OF DOCUMENTS REVIEWED
| |
| Procedure # Revision # Ijilg
| |
| EOP 1E-0 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
| |
| !
| |
| >
| |
| 15
| |
| l
| |
| 1
| |
| }}
| |