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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
	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: ML20236N990; ML20236N994; ML20236P011;
References
	50-282-98-10, 50-306-98-10, NUDOCS 9807160111
	Download: ML20236P011 (15)
	v • d • e

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U.S. NUCLEAR REGULATORY COMMISSION

REGIONlli .

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Docket Nos: 50-282;50-306

License Nos: DPR-42; DPR-60

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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 l

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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

PDR 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

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

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)

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During subsequent actions to stabilize the plant, a lack of three part communication, a

lack of consistent plant oversight, and unfamiliarity of SG PORV response contributed to

failure to adequately remove decay heat. (Section 04.1)

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Operator training and practical experience at maintaining the plant in a hot shutdown

condition with the MSIVs closed and using SG PORVs for decay heat dissipation was

limited. (Sections 04.1 and 05.1)

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The simulator SG PORV fidelity was dissimilar to the plant and the licensee wrote a non-

conformance report. (Section O5.1)

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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

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 3

atmospheric steam dumps to initially remove decay heat. Operators closed the MSIVs as a l

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. l

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

l panels,

b. Observations and Findinos

The following information describes the sequence of events (Central Daylight Time)

i commencing with the automatic reactor trip of Unit 1 from 100% power as reconstructed

l by the NRC inspection team:

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Fridav. June 5.1998

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06:58 pm Unit 1 received an automatic reactor trip, operators identified the first out i

annunciator as the negative flux rate trip. Operators entered 1E-0, * Reactor Trip

Or Safety injection," Revision 17. Operators verified all control rods fully ,

inserted, one of two operating MFPs (#11) received automatic trip, #11 TDAFW l

and #12 MDAFW pumps started automatically with discharge flow at 550 gpm.

, Average RCS temperature (Tave) dropped from 559 to 539 'F, and SG levels

i dropped from 45% to 0% NR.

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l 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

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. i

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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 l

60 gpm and caused SG level to decrease from 30% to 25% over the next four

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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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reduce pressure.

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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, l

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 !

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 i

steam safety valves on "A" SG lifted and reseated which swelled the "A" SG level '

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 !

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%.

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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

j 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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03 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

l 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. i

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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 ,

reactor trip had occurred and promptly entered EOP 1E-0, * Reactor Trip Or Safety l

Injection," Revision 17. After completing the specified procedural actions, the crew '

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

on a Tave decrease to 538 'F. The control room operators responded to the excessive j'

primary cooldown and closed the MSIVs and bypass valves. The single operating MFP

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 !

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

l pressure was greater than 1050 psig. The plant was stabilized and in hot shutdown

l 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 i

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 l

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 <

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; l

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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f c. Conclusions

Operator training and practical experience at maintaining the plant in a hot shutdown

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limited. The simulator SG PORV fidelity was dissimilar to the plant.

lit. Engineering

E1 Conduct of Engineering

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E1.1 - Root Cause of Rod Droo (G7)

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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.

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L 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 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

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. 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

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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. !

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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 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

i 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

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

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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 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

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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 VIO Inadequate procedure for dumping steam with steam generator l

poweroperated relief valves. i

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Closed

I None.

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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

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ERCS Emergency Response Computer System

F Degrees Fahrenheit

FWH Feedwater Heater

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gpm Gallons Per Minute

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IP Inspection Procedure

LER Licensee Event Report

LRO Lead Reactor Operator

MDAFW Motor Driven Auxiliary Feedwater I

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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

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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

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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

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ML20236P011

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