ML20129D458

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Package Consisting of Sequence of Events Reviews Re 850609 Event
ML20129D458
Person / Time
Site: Davis Besse Cleveland Electric icon.png
Issue date: 07/26/1985
From:
TOLEDO EDISON CO.
To:
References
NUDOCS 8507300051
Download: ML20129D458 (68)


Text

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155:

0 ubl3 TRIP 1 35:29: 95 P864 RPS CH 2 HC HI PRESS TRIP 1:35:298100__ 0818._.

RPS..CH 2 CH_ TRIP._..

._.._.__. TRIP..-

1:35:29:990 P868 RPS CH 3 HC HI PRESS TRIP 1:35:293995 0826 RPS CH 3 CH TRIP TRIP 1:35:303_o0_. 0181 _.CRD CH b/D.ANY._ TRIP. DEVICE

._.. TRIP j

s 1:35:30 60 X038 1-G MASTER TURB TRIP TRIP 1:35:30 65 Q180 CHD CH A/C ANY TRIP DEVICE TRIP 135 : 30 L.95___ X 0 30 T-G MASTER. TRIP SBLLN010S.._

___ TRIP _

1:35:30:145 0266 CRD TRIP CONFIRM TRIP 4

1:35:30:190 P858 RPS CH 1 RC Hi PRESS TRIP 1:35:30:195 0810_

.RPS CH.1.CH_iRIP.

. __ TRIP 1 35:30:285 XO33 T-G MECH TRIP SOLEN 01D TURB TRIP TRIP

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1:35:30:310 x032 T-G MECH TRIP VLV TRIP

_ 1:35:30: 370,.

P873.__ RPS CH 4.RC_HI. PRESS.___.

_ _ __.__ TRIP _._._.

j 1:35:30:370 G834 RPS CH 4 CH TRIP TRIP 1 35:30:540 A850 RPS CH 1 FLUX-DFLUX-FLen BSTBL TRIP 1:35:30:545__A669_.

_RPS_CH.4 FLUX-DFLUx-FL0n 8STBL. __ TRIP.

1:35:30:550 A856 RPS CH 2 FLUX-DFLUX-FLen BSTBL TRIP 1:35:30:550 A862 RPS CH 3 FLUX-DFLux-FLen BSTBL TRIP

/ '

.__1:35:30:935_. 0963 SFRCS FULL TRIP NORM Q963___ SFRCS_ FULL. TRIP ______. ___ ______. TRIP _.

1:35:34: 70 1:35413675 P869 RPS CH 3 RC L0 PRESS BSTBL TRIP

__.1:35:41:710._ P859 RPS CH 1 RC L0 PRESS BSIBL.

TRIP TRIP _

1:35: 413745 P874 RPS CH 4 RC LO PRESS BSTBL 1:35 42:230 P863 RPS CH 2 RC LO PRESS BSTBL TRIP 1:35:54:930 J428 GEN REVERSE PWR 1:35:54 950 x026 Sn{D ACB 34561 TRIP WPEN 1:35:54:950 X025 SdVD ACB 34560 WPEN 1:35:54:955 1425 GLN GRdUND. CURRENT HIGH 1:35:55: 50 1425 GEN GHOUND CURRENT NORM 1:35:55:330 J428 GEN REVERSE PWR NORM 1:41: 4:345 0963 SFRCS FULL TRIP TRIP 1:43:23:255 0841 RPS SU RATE ROD HTHDRNL INHIBIT INHB 1:43:58:160 0841 HPS SU HATE ROD WTHDRnL INHIBIT NORM 1:48:51: 420 0841 RPS SV RATE R00 n1HDRnl INHIBIT INHB 1:48:51:745 0841 RPS SU RATE ROD nTHDRnL INHIBIT NORP 1:50:10:320 0841 RPS SU HATE ROD r.THDRnL INHIBIT INHB 1:50:10: 650 0841 RPS SU RATE ROD nTHDRnL INHIBIT NORM 1 51:20:535 0841 RPS SU HATE ROD HTHDwnL INHIBIT INHB 1:51:21: 45 0841 RPS SU HATE ROD nTHDRnL INHIBIT NORM 1:51:21: 85 P701 SFRCS DP HALF / FULL TRIP,SG 1 TRIP 1:51:213910 P702 SFRCS DP HALF / FULL TRIP,8G 2 TRIP 1:51:38:895 P702 SFRCS DP HALF / FULL TRIP,SG 2 NORM -

1:51 40:265 P701 SFRCS DP HALF / FULL TRIP,SG 1 h0RM 2

2: 4b: 990 0634 MFPT 2 TRIP i

8507300051 850726 DR ADOCK 0500 6

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y 19 P 1102.03.13 Post Trip Review

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The following review must be completed for each reactor trip (excep(,q 1

normal tripping of CRD during heatups and cooldowns) even if a unit p.

l restart is not in progress.

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1.1 Plant Pre-Trip Conditions (to be completed by the Shift Techai,.

Advisor and Operations persoasel after the plant stabilization complete).

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c (A) Reactor power prior to the trip:

70

~

,,u u Note any rumback that occurred:

G//ow*u +M #FF "/ -

o)

/

s An N$ lr?oerU Ns % Yvn5AL$ we4 rss'lr$1k'A A fle f

Y im el W P M S ro,*,L 4

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(B) List any ICS stations in manual prior to the trip:

MFP I-2 (H K sc A) wn,,.

,a,,ual l.

(C) List any testing in progress prior to the tript.

io n e a

-- -- ~

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(D) List any safety systems inoperable prior to the trip {*<'a#'

11.

.- :n n o,, e

...a : sn -

(E) List any other abaarmal plant conditions contributing to--

Moh6 Completed By % G/4~

Date

(, Y L/

6 1.2 Plant Post Trip Conditions (to be completed by the Shift Technical Advisor and Shift Supervisor after the plant stabilization is complete).

9.

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.s (A) Did any of the following occurf (Use Control Roon recorders,.

d computer information, or operator observations.)

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f,.

Did the FORY actuate?

s Did the pressuriser code safety valves actuate?

Did either steam 39 aerator level exceed 82.5%7 1

Did SG 1evel go below 14"?

gg g, ; g Was SFAS actuated?

x Did pressuriser level decrease below 8 inches?

' 1

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d,gp Did pressurizer level exceed 300 inches?

Was the Emergency Plan activated?

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.5 Did the SFRCS actuate?

q) rN

/

If any of the above did occur, determine the cause and'dAs'cribe._ '

~

below:

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I} A,.y /i$ted u) unh,/L/ o+ 2 esJ; ACs n,es JAW

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1) Pn <wiw-la u,. / irumd k Sto" A//owho, LoFY my.

Yus*?,sn kl. bed lU19

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3) As t/r, fiae of He, L ofw a Sik, An.a n. gas soll A ae, L.~ afel. r/smae. Im/m. 4te of as u te ed: AG\\v l

f v

we reskrid. At Me, M/V Suan a*ws titir ehh as /Mses/

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evea+ ws dec /* rr)

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(B)

Write a short d iption of the cause of the trip, the racger l

trip segnance of events which resulted is the trip, and say.. (g actions takaa to prevent recurrence.

(Review the Post Trip' Review, Alara Priatout, and Sequence of Events Priatouts,-if available.)

Ue reorden-h'e'and es }s *h nressors.sbie, IP aufb f ru. Laele.Ls,lt:rrouji Seilowk He. h4 FP 4-4a. *$$?

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Shift Technical Advisor \\ N b Date 6M f

Shift Supervisor 3.c Date dr/T!SE l

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eco#ple A g rs

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o f A S f & C.S l 4 4 h k.

For (c(se no w,.,ndalou)

.show li. +k.,seyveme af e venFr A, A6 p/co+ pora ureius were.

/n a sria +r h> 4.'p SfRCS e.~ceff f2e. s':sf c hijped.u F P -

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SFRcS purAbulhms wrs used.

No~e w, uHer than Inihkho;y SFRCS. on /cw /cval ; SFRCS pusA du// ens. fe 6ers 07sG fy fecssun. +ript were.yv.r/ad.

SFkct was parlity reset c,,d fryped an low level oi desfraJ,

8oYA A fps inlhi//y run, but h.rppd via fle ky +Arn Hk. valva.

A f SYS s-d Aftos JiucA closed osH/.nonunk opened, erff theie.ses/s.

y 5 etAw Ale anal sis ed idle <wk,t.ere nese.ssay lo y

ysf a e rp /s /c m s o /u h m.

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.i 1.3 Safety Review of Transient (to be completed by Shift Technical Advisor and Shift Supervisor).

(A) Verify no safety concerns

  • have been identified in the'rev 5 w of the trip.

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  • A safety cor. ern is defined as a' safety related system not performing the design function for which it was intenfeC.

fin V.

.1 Shift Supervisor Data r: w Shift Technical Advisor Date W

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(B) Verify no safety limits exceed during the transient (see Technical Specification 2.1).

If any safety limits has been exceeded,,..

operation shall not be resumed until authorized by the C_ennission as per 10CTR$0.36 Section C.

. ~~~~~

-k Date Shift Supervisor 1-8 i ;.

Shift Technical Advisor \\ 'f8 M N Date 6 9-W i

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I If the cause of the unit trip cannot be determined, or the Sequange Af.

Events for the reactor trip cannot be determined, or any safety concers identified, a unit restart cannot proceed until a Station Review Jesad review of the transient has been completed.

y? fy After this form is completed, it should be routed to the Operatisas.j Engineer for his review.

v;..;1 g

Operr.tions Engineer

=

Date

/

.a se?. es:t FMt i
Y After the Operations Engineer review, his attachment should.be rou,te( !.

to the Technical Section to be included in the trip files.

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(

e SEQUENCE OF EVENTS JUNE 9, 1985 TRIP Updated 1200 Hours June 18, 1985 i

The following is a summary of the Sequence of Events that occurred at l

Davis-Besse on June 9, 1985. The plant was originally at approximately 90% of full power. No surveillance testing related to the event was in progress. The plant was in full automatic control except for the #2 Main Feedpump which was in manual.

4 i

Time Event 01:35:00 The #1 Main Feedwater Pump (MFP) tripped on overspeed due to a control failure.

An automatic plant runback was automatically initiated. Due 3

j to the reduced feedwater flow available, Reactor Coolant System (RCS) temperature and pressure l

began increasing. The plant ran back to approximately 80% of full power prior to the reactor trip.

01:35:29 The reactor tripped on high RCS pressure (2300 Psig).

The turbine tripped from reactor trip.

i 01:35:31 The Steam & Feedwater Rupture Control System (SFRCS), Channel 2, spuriously half tripped on low SG level and cleared four seconds later.

A sequence of events monitor SFRCS full trip l

alarm was also received and cleared.

01:35:36 Main Steam Isolation Valve (MSIV) #2 closed.

i 01:35:37 MSIV #1-closed.

01:35 to Normal post trip equipment operation, such as 01:40 the auto transfer of housepower to the startup i

transformers, etc.

The #2 NFP continued to supply normal feedwater until approximately 0140 hours0.00162 days <br />0.0389 hours <br />2.314815e-4 weeks <br />5.327e-5 months <br />, when there was not adequate steam to operate ~ the MFP turbine due to the closure of the MSIV's.

01:41:04 Steam generator water levels decreased to the SFRCS low level trip setpoint. A full trip on low level occurred on SFRCS actuation Channel 1.

Actuation of SFRCS actuation Channel 1 related-components was initiated including alignment of Auxiliary Feed Pump'(AFP) I to feed Steam Generator (SG) 1.

Sequence of Evrnts Summary - 6/9/85 Page 2 4

01:41:08 The control room operator attempted to manually initiated SFRCS to start auxiliary feedpumps, i

however, he incorrectly actuated the SFRCS on low steam pressure instead of the desired low steam generator level. He performed the

. manual actuation by depressing the top switch in both strings of manual actuation switches for

'the respective SFRCS actuation channels. This generated a low pressure trip on SG 1 in SFRCS actuation Channel 1 and a low pressure trip in SG 2 on S?RCS actuation Channel 2.

Therefore, each SFRCS actuation channel sensed that its respective steam generator was inoperable while the opposite steam generator was still intact.

SFRCS actuation Channel 1 then attempted to align AFP 1 to feed steam generator 2 and SFRCS i

actuation channel 2 attempted to align AFP 2 to

~tced SG 1.

Both actuation channels, however, closed their respective steam generator isolation valves (AF599, AF608) which prevanted any auxiliary feed flow from reaching the steam generators.

Per the SFRCS design, some valves positioned by the low level trip on SFRCS Channel I were repositioned by the low pressure trip. The AFP 1 steam supply valve from SG 1, MS 106, started open in response to the SFRCS actuation Channel 1 low level trip. Following the manual initiation of the low pressare trip, the valve should have continued opening to its full open position before it cycled closed.

The entire open/close stroke time should have been about 50-60 seconds.

The valve returned to its closed position in about 18 seconds, however.

This indicates that the open command to the valve did not' seal in as designed.

01:41:13

'SFRCS actuation Channel 2 tripped on low steam generator level.

Since the low pressure trip already present had priority, no change in component actuation occurred.

)

i n,.

,a

~

Scqu:nca of Evsnta Summary - 6/9/85 Page 3 i

1 01:41:31 AFP 1 tripped on overspeed.

01:41:44 AFP 2 tripped on overspeed.

01:42:00 The-Operator's error was corrected by clearing i

the manual SFRCS actuation on low steam pressure.

Since both SFRCS actuation channels were already tripped on low steam generator level, the SFRCS attempted to realign valves in the normal configuration with AFP 1 feeding SG 1 and AFP 2 feeding SG 2.

The SFRCS attempted to open steam generator isolation valves AF599 and AF608, but the valves did not open. With these valves closed and the AFPs tripped, no feedwater was being supplied to the steam generators.

01:45 Both Steam Generators had steamed down to approximately 12-13 inches of indicated level.

RCS Tave at this time was approximately 562*F.

01:45 - 01:51 RCS Tave was increasing due to the lack of primary to secondary heat transfer. RCS pressure was increasing due to the decreasing' density of the RCS water and increasing pressurizer level.

RCS pressure increased to the Power Operated Relief Valve (PORV) setpoint (2425 psig). The PORV cycled a total of three (3) times, relieving pressurizer pressure to - the Quench Tank.

Following the third opening, the PORV failed to reclose properly. The control room operator observed primary conditions and closed the block valve on the PORV. RCS pressure fell to 2075 psig before the block valve closed or the PORV reseated.

During this time period, operators were attempting to restart the auxiliary feedwater pumps locally. Some problems were encountered with local control of the AFP turbines. The turbine trip throttle valves at the turbine

)

inlet were difficult to reset and the effort was I

complicated by comuunications problems with the I

l control room.

During the same time period..an operator locally assisted the opening of both steam generator isolation valves AF599 and AF608. After he partially opened the valves, the motor operator l

stroked the valves open.

i 1

l

[

1 S; quince of Evints Summary - 6/9/85 Page 4 01:51 Operators placed the Startup Feedpump (SUFP) in operation to supply the steam generators. SG 1 pressure had reached a minimum of approximately 750 psig. SG 1 repressurized to approximately 900 psig from the startup feedpump. The #2 SG has reached a minimum of 920 psig.

~01:52 AFP 2 was returned to operation by operators to supply SG 2 and SG level began increasing.

Maximum RCS temperature had reached approximately 592*F. When AFP 2 was returned to service, the control room operator controlled the pump in manual rather than returning it to the Auto Essential mode of operation.

~01:55 AFP 1 was returned to operation by operators to supply the SG 1 and the SG level began increasing. Operation of AFP 1 turbine could not be regained by the control room operator in either the Auto Essential or the manual mode of operation.

Control of the turbine was maintained locally by an operator at the turbine steam inlet valve.

~01:58 Tave restored to normal post trip temperature.

The cooldown lowered RCS pressure. Operators manually started the HPI pump #1 in the piggyback mode (D.H. pump 1 supplying the suction to the HPI pump 1).

A slight amount of water (5~50 gallons) wac injected.

Additional Notes:

Adequate subcooled margin was available throughout the transient.

The Reactor Coolant Pumps remained in operation. The Quench Tank

' contained the discharges from the PORV. Makeup /High Pressure Injection cooling of the RCS was available as a method of core cooiing at all times.

This data is preliminary and additional clarifications or correc-tions may be necessary after a detailed analysis of the event.

JRL:SNB:bec i

SNB/009

~.

2

+

SEQUENCE OF EVENTS JUNE 9, 1985 TRIP Updated 1200 Hours June 18, 1985 1

.The following is a summary of the Sequence of Events that occurred at Davis-Besse on June 9, 1985. The plant was originally at approximately 90% of full power. No surveillance testing related to the event was in progress. The plant was in full automatic control except for the #2 Main Feedpump which was in manual.

Time Event 01:35:00 The #1 Main Feedwater Pump (MTP) tripped on overspeed due to a control failure. An automatic plant runback was automatically initiated. Due to the reduced feedwater flow available, Reactor Coolant System (RCS) temperature and pressure-began increasing.

The plant ran back to approximately 80% of full power prior to the reactor trip.

01:35:29 The reactor tripped on high RCS pressure (2300 Psig).

The turbine tripped from reactor trip.

01:35:31 The Steam & Feedwater Rupture Control System l

(SFRCS), Channel 2, spuriously half tripped on low SG level and cleared four seconds later.

A sequence of events monitor SFRCS full trip alarm was also received and cleared.

01:35:36 Main Steam Isolation Valve (NSIV) #2 closed.

1

-01:35:37 MSIV #1 closed.

01:35 to Normal post trip equipment operation, such as 01:40 the auto transfer of housepc.:: to the startup transformers, etc.

The #2 NFP continued to supply normal feedwater until approximately 0140 4

hours, when there was not adequate steam to operate the MFP turbine due to the closure of the MSIV's.

01:41:04 Steam generator water levels decreased to the SFRCS low level trip setpoint. A full trip on low level occurred on SFRCS actuation Channel 1.

Actuation of SFRCS actuation Channel 1 related components was initiated including alignment of Auxiliary Feed Pump (AFP) I to feed Steam Generator (SG) 1.

4 4

-a r

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w

---v e----

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- - --*-+--

s

p__

Ssqucaca cf Evento Susanary - 6/9/85 Page 2 01:41:08 The control room operator attempted to manually initiated FFRCS to start auxiliary feedpumps, however, he incorrectly actuated the SFRCS on low steam pressure instead of the desired low steam generator level. He performed the manual actuation.by depressing the top switch 4

in both strings of manual actuation switches for the respective SFRCS actuation channels. This generated a low pressure trip on SG 1 in SFRCS actuation Channel 1 and a low pressure trip in SG

(

2 on SFRCS actuation Channel 2.

Therefore, each SFRCS actuation channel sensed that its respective steam generator was inoperable while the opposite steam generator was still intact.

SFRCS actuation Channel 1 then attempted to align AFP 1 to feed steam generator 2 and SFRCS actuation channel 2 attempted to align AFP 2 to feed SG 1.

Both actuation channels, however, closed their respective steam generator isolation valves (AF599, AF608) which prevented any auxiliary feed flow from reaching the steam i

generators.

Per the SFRCS design, some valves positioned by the low level trip on SFRCS Channel I were repositioned by the low pressure trip. The AFP 1 steam supply valve from SG 1, MS 106, started open in response to the SFRCS actuation Channel 1 low level trip. Following the manual initiation of the low pressure trip, the valve should have continued opening to its full open position before it cycled closed.

The entire open/close stroke time should have been about 50-60 seconds.

j The valve returned to its closed position in about 18 seconds, however. This indicates that the open command to the valve did not seal in as designed.

01:41:13 SFRCS actuation Channel 2 tripped on low steam generator level.

Since the low pressure trip already present had priority, no change in component actuation occurred.

l 4

/

I Sagaenca of Evznto Summary - 6/9/85 Pega 3 01:41:31 AFP 1 tripped on overspeed.

01:41:44 AFP 2 tripped on overspeed.

01:42:00 The Operator's error was corrected by clearing the manual SFRCS actuation on low steam pressure.

Since both SFRCS actuation channels were already tripped on low steam generator level, the SFRCS attempted to realign valves in the normal configuration with AFP 1 feeding SG 1 and AFP 2 feeding SG 2.

The SFRCS attempted to open steam generator isolation valves AF599 and AF608, but o

the valves did not open. With these valves closed and the AFPs tripped, no feedwater was being supplied to the steam generators.

01:45 Both Steam Generators had steamed down to approximately 12-13 inches of indicated level.

RCS Tave at this time was approximately 562*F.

01:45 - 01:51 RCS Tave was increasing due to the lack of primary to secondary heat transfer. RCS pressure was increasing due to the decreasing density of the RCS water and increasing pressurizer level.

RCS pressure increased to the Power Operated Relief Valve (PORV) setpoint (2425 psig). The i

PORV cycled a total of three (3) times, relieving pressurizer pressure to the Quench Tank.

Following the third opening, the PORV failed to reclose properly. The control room operator observed primary conditions and closed the block valve on the PORV. RCS pressure fell to 2075 psig before the block valve closed or the PORV rescated.

During this time period, operators were I

attempting to restart the auxiliary feedwater pumps locally.

Some problems were encountered with local control of the AFP turbines. The t

turbine trip throttle valves at the turbine inlet were difficult to reset and the effort was i

complicated by communications problems with the control room.

During the same time period, an operator locally assisted the opening of both steam generator isolation valves AF599 and AF608. After he partially opened the valves, the motor operator stroked the valves open.

l l

l-

f:

^

Sequ:nce of Evrnta Summary - 6/9/85 Paga 4 01:51 Operators placed the Startup Feedpump (SUFP) in operation to supply the steam generators. SG 1 pressure had reached a minimum of approximately l

750 psig.

SG 1 repressurized to approximately 900 psig from the startup feedpump. The #2 SG has reached a minimum of 920 psig.

~01:52 AFP 2 was returned to operation by operators to supply SG 2 and SG level began increasing.

Maximus RCS temperature had reached approximately 592*F. When AFP 2 was returned to service, the control room' operator controlled the pump in manual rather than returning it to the Auto Essential mode of operation.

~01:55 AFP 1 was returned to operation by operators to supply the SG 1 and the SG level began increasing. Operation of AFP 1 turbine could not be regained by the control room operator in either the Auto Essential or the manual mode of

' operation.

Control of the turbine was maintained locally by an operator at the turbine steam inlet valve.

~01:58 Tave restored to normal post trip temperature.

The cooldown lowered RCS pressure.

Operators manually started the HPI pump #1 in the piggyback mode (D.H. pump 1 supplying the suction to the HPI pump 1).

A slight amount of water ($~50 gallons) was injected.

Additional Notes:

Adequate subcooled margin was available throughout the transient.

4 The Reactor Coolant Pumps remained in operation. The Quench Tank l

contained the discharges from the PORV. Makeup /High Pressure Injection cooling of the RCS was available as a method of core l

cooling at all times.

This data is preliminary and additional clarifications or correc-i tions may be necessary af ter a detailed analysis of the event.

i JRL:SNB:bec l

1 1

I SNB/009

g0 rn api 3

SEOUENCE OF EVENTS Davis-Besse Complete Loss of Feedwater Event

,1 June 9, 1985 8*38A M E M Or#Y NRC Fact Finding Team

.f.

M Status: Preliminary (Rev.

)'

T.0? ^W_ June 18, 1985 b.

I

  • Unexpected or of_f-normal response Initial Conditions

- Unit operating at 90%

- Number One Main Feedpump (MFP) in automatic control

- Number Two Main Feedpump in manual

- One Source Range Nuclear Instrumentation Channel inoperable

- Safety Parameter Display System (SPDS) inoperable a

Transient Initiator

~

  • 01:35:00 #1 MFP Trips

.L._ J -

MFP flow increases; MFP turbine trips on overspeed.

m.-

2s k

..-_I -

Systems Response / Operator Actions to Partial Loss of Main Feedwater.

I l ~~:. } ;; m. ::. y y. p _..,...

3... -,

.. y... n.;. y,, -

01:35:01 Unit runback toward 55% at 50%/ min initiated.

01:35:21 Operator increases the speed of #2 MFP turbine. Pressurizer spray valve manually opened to 100%.

01:35:30 Reactor Trip + Turbine Trip - RCS High Pressure (2300 psig) from 80% power._

4 L'ontPuTGR Mconbib

  • 01:35:31 Steam & Feedwater Rupture Control System (SFRCS), trip on i

A l

S/Glowlevel,actuationChannel2MothMSIVsstartto}

l

& lose.

.)t or:fs';s tr 01:35:34 SFRCS actuation signal clears.

  • 01:35:37 MSIV #1 has closed.

With both MSIVs closed, the source of steam for #2 MFP turbine is isolated. Steam from main steam piping and moisture separator reheators continued to drive #2 MFP for a while.

01:35:45 Pressurizer spray valve closed.

x :n _

4 SEOUENCE OF EVENTS 5%

01:35:M once Through Steam Generator (OTSG) levels at normal post-trip level (35 inches).

  • 01:40:00 OTSG 1evels begin to fall from the normal post-trip level.

System Response / Operator Actions to Complete Loss of Main Feedwater 01:41:04 SFRCS low OTSG 1evel (26.5 in.)'hetuationChannel1 actuates; this actuation causes Auxiliary Feedwater Pump (AFP) #1 to be aligned to feed OTSG fl.

  • 01:41:08 The control room operator attempted to manually initiate SFRCS; however, he incorrectly actuated the SFRCS on low steam pressure instead of the desired low stcan generator level. He performed the manual actuation by depressing the top switch in both strings of manual actuation switches

+

for the respective SFRCS actuation channels. Therefore, each SFRCS actuation' channel sensed that its respective steam generator was inoperable. SFRCS actuation Channel 1

~

then attempted to align AFP 1 to feed steam generator 2

~

and SFRCS actuation Channel 2 attempted to align AFP 2 to feed SG 1; both actuation channels,.however, closed their respective steam generator containment isolation valves (AF-599 AF-608), which prevented,any auxiliary feed flov

. g,_. J M,. $.. n.

'. from reaching the steam generators'.'8,4tWs'g'fFf irf5C/

, l:

.v.,.,.1..su. p g g g m-e...ps.g.y

..m Per.the SFRCS design, valves positioned by the low level trip on SFRCS Channel 1 were repositioned by the higher priority pressure trip. The AFP 1 steam supply valve from SG 1, MS 106 had started open in response to the SFRCS i

actuation Channel 1 low level trip. Following the manual initiation of the low pressure trip, the valve shculd have continued opening to its full open position before it cycled closed. The entire open/close stroke time should have been about 50-60 seconds. WThe valve however returned to its closed position in about 18 seconds.

l This indicates that the open command to the valve did not seal in as designed.

(

01:41:13 SFRCS actuation Channel 2 tripped on low steam generator i.

level. Since the low pressure trip already present had i

priority, no change in component actuation occurred.

l

  • 01:41:31 AFP 1 tripped on oversp'eed.

l

  • 01:41:44 AFP 2 tripped on overspered.

t O

g-

~. - -

.c. s:

SEOUENCE OF EVENTS

.o Art System Resoonse/Onerator Actions to Co=olete Loss of Feedwater 01:42:00 Manual reset of SFRCS low OTSG pressure actuation.

  • AF-599, AF-608 should re-open automatically, but did not.

4

  • An attempt was made to re-open AF-599 and AF-608 from the main control panel, but the valves did not respond.

01:43:55 Assistant Shift Supervisor went to SFRCS cabinets (behind the control room area), opened the doors, and operated the SFRCS " Initial Reset and Bypass" function in an attempt to reset any automatic safety signals to AF-599 and AF-608.

  • The valves remained closed.
  • 01:44 - 01:52 The Shift Supervisor dispatched Equipment Operators into the plant to operate the following equipnent:

(1) Two Equipment Operators were sent to the Auxiliary, Feedwater Pump turbines to manually restore the A W pumps to service.

No. 2 A W turbine overspeed trip was reset at 01:45:50. Manual control of the N

~

' turbine trip throttle valve was required to bring the turbine up to speed.

No. 1 AFP turbine was reset D,.

7.1.w.

and speed was controlled locally throughout the.

. " ?".!q=.;>;' ~~::::,n - recovery.:. 3:: G. y-Jik'hE....,:,..m.:.vpis:n.a M ;.i.. h?: ~.

../

W

v..,

m -(e v - ;.

.e-r (2) The Assistant Shift Supervisor left the control room i

to place the startup feed pump in service. This

  • evolution required opening the pump suction valve, the pump discharge valve, and two cooling water valves.

l In addition, the control fuses for the pump circuit breaker were required to be installed. The startup feed pump was started at 01:51:23.

i s

l l

(3) Two equipment operators were sent to open OTSG Auxiliary Feed Isolation Valves AF-599 and AF-608.

These valves are the containment isolations for the A M wystem. The operators moved the valves from the closed position, and the motor operators opened the valves. Computer printouts indicate that tha #2 OTSG l

Valve AF-599 was open at 01:47:48, and the il OTSG Valve i

AF-608 was open at 01:49:28.

t t

01:47:33 OTSG #1 below 960 psig and decreasing.

01:48:49 Pzr. PORY opens first time at 2433 psig (2425 setpoint).

  • 01:48:51 OTSG #2 below 960 psig and decreasing.
  • Q',-4..*.],

., j

" '

  • lX~._

=

=-

SEOUENCE OF EVENTS 01:43:52 Pzr. PORV has closed at 2377 psig (2375 setpoint).

01:50:09 ?$r. PORV opens second time at 2434 psig.

01:50:12 Pzr. PORV has closed at 2369 psig.

5 01:51:17 OTSG SG #1 level falls below eight inches.

  • 01:51:18 Pzr. PORV opens third time at 2435 psig; did not close.

01:51:23 Startup feed pump motor on.

krm4. MA-01:51:42 Pzk.PORVblockvalveclosedbyoperatorat2140psig.

01:51:42 RCS Loop #1 reaches a minimum pressure of 2081 psig.

Loop #1 T-hot = 588.6 F; Tave = 587.5 F.

01:51:49 Accoustic monitor indicates no flow thru PORV/ block valve.

01:53:00 RCS loop #1 T-hot reaches peak value of 59'3.5 F.

AW #2 has significant flow, hECA. & ~3 b 01:53:22

~-e-..

4 nm.

,n._...

-*(WhenAFP2wasreturnedtoservice,thecontrolroom

.y.

I. "f g,o,N ~,EZiel --? (returning it to 4he. Automatic. P4 M Operator controlled the pump in manual rather than n

,j

,~

1, -

.,.Q.. ' ' Cp.

+ -,.

g A

01:53:25 RCS Tave reaches peak value of 592.3 F.

01:53:35 SG #2 returns to above 960 psig.

01:53:56 PORV Block Valve reopened by operator.

01:54:45 SG #1 return to above 960 psig.

01:54:46 AW #1 has significant flow hEER. CM d**

1

  • L h y

{Q:p.: u %.

. h ::;;in:d 53 th; C

'- cf ^!? ? :: 512: :: "

ci:h: p.-:

h: /.. _ a. : :h:-

r::: ;rr ::: i

...n:

_d -:d ef :; :::i:::.

Control of the turbine was

~

maintained locally by an operator via the turbine steam trip valve.

01:56:58 SG #2 below 960 psig and decreasing due to return of feedwater.

01:57:05 SG #1 below 960 psig and decreasing.

f

SEOUENCE OF EVENTS 1

I 01:53 Tave restored to normal post-trip temperature. The cooldown had lowered RCS pressure to about 1720 psig.

Operators manually started the HPI pump #1 in the piggy-back mode (LPI pump 1 supplying the suction to the HPI pump 1). A slight amount of water (about 50 gallons) was injected.

RCS loop #1 reaches a minimum pressure of 1716 psig.

01:58:08 Loop #1 T-hot = 546.6 F; Tave =,546.2 F.

e' 01:58:33 AFW #1 flow reduced to control OTSC level.

02:01:13 AFW #2 flow reduced.

02:02:27 SG #1 returns to above 960 psig.

02:02:30 SG #2 returns to above 960 psig.

02:04 P* ant conditions essentially stable.

i 4

,i Additional Complications 9 '-:'

  • When the only operable source range nuclear instrumentatic.n channel 4

1 was energized, it failed to as offscale low value'.;, This left no...y.

nuclear instrumentation on scale?i All control rods were re-verified '

' ",.E;}.

to be fully inserted. The operator initiated emergency boration.

  • AFP #1 suction automatically transferred from the condensate storage tank (CST) to the service water system. The operator realigned-6e--

to CST.

l f

Jd The desuperheating spray.see".? r for the auxiliary steam system.hed.

allowed water into the t---

.w.

-4.

-t'-

3.-

rg --;.

.m i

main steam piping. When vacuum was restored and the MSIVs opened, l

the water slug damaged one of the main turbine bypass valves.

l I

Notes 1.

Adequate subcooled margin was available throughout the transient.

The Reactor Coolant Pumps remained in operation. 'The Quench Tank contained ths discharges from the PORV. "? 7 /"i;h Prc:::::

tj ;;; b; ;;;! B; ' "'"' - - -

^

~

---15; :: :!! tir:;.

g, fyrA*( r.5" 4 Quf57"tod ed *rr/

0 /%CK A 8 /l.1 T Y 0 5' TlW y

krout.b 8f Off f0 Coo /fAot. VALVC

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SEQUENCE OF EVENTS JUNE 9, 1985 TRIP Updated 1400 Hrs. June 14, 1985 The following is a summary of the Sequence of Events that occurred at Davis-Besse on June 9, 1985. The plant was originally at approximately 90% of full power. No surveillance testing related to the event was in progress. The plant was in full automatic contro: except for the #2 Main Feedpump which was in manual.

Time Event I

01:35:00 The #1 Main Feedwater Pump (MFP) tripped on overspeed due to a control failure. An automatic plant runback was automatically initiated. Due i

to the reduced feedwater flow available, Reactor Coolant System (RCS) temperature and pressure a

began increasing. The plant ran back to approximately 80% of full power prior to the

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reactor trip.

01:35:29 The reactor tripped on high RCS pressure (2300 psig).

The turbine tripped from reactor trip.

01:35 The Steam & Feedwater Rupture Control System (SFRCS), Channel 2, spuriously half tripped on low SG 1evel and cleared four seconds later.

A sequence of events monitor SFRCS full trip alarm was also received and cleared.

01:35:36 Main Steam Isolation Valve (MSIV) #1 closed.

01:35:37 MSIV #2 closed.

01:35 to Normal post trip equipment operation, such as 01:40 the auto transfer of housepower to the startup transformers, etc. The #2 NFP continued to supply normal feedwater until approximately 0140 hours0.00162 days <br />0.0389 hours <br />2.314815e-4 weeks <br />5.327e-5 months <br />, when there was not adequate steam to operate the NFP turbine due to the closure of the MSIV's.

01:41:04 Steam generator water levels decreased to the SFRCS low level trip setpoint. A full trip on i

low level occurred on SFRCS actuation Channel 1.

l Actuation of SFRCS actuation Channel 1 related components was' initiated including alignment of Auxiliary Feed Pump (AFP) I to feed Steam Generator (SG) 1.

1 i

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Sequeles of Ev:nte Summary - 6/9/85

'Page 2 01:41:08 The control room operator attempted to manually initiated SFRCS to start auxiliary feedpumps, however, he incorrectly actuated the SFRCS on low steam pressure instead of the desired low steam generator level. He performed the manual actuation by depressing the top switch in both strings of manual actuation switches for i

the respective SFRCS actuation channels. This j

generated a low pressure trip on SG 1 in SFRCS actuation Channel 1 and a low pressure trip in SG 2 on SFRCS actuation Channel 2.

Therefore, each SFRCS actuation channel sensed that its respective steam generator was inoperable while the opposite steam generator was still intact.

SFRCS actuation Channel 1 then attempted to align AFP 1 to feed steam generator 2 and SFRCS actuation channel 2 attempted to align AFP 2 to feed SG 1.

Both actuation channels, however, closed their respective steam generator isolation valves (AF599, AF608) which prevented any auxiliary feed flow from reaching the steam generators.

Per the SFRCS design, some valves positicned by the low level trip on SFRCS Channel I were repositioned by the low pressure trip. The AFP 1 steam supply valve from SG 1, MS 106, started open in response to the SFRCS actuation Channel 1 low level trip. Following the manual initiatica of the low pressure trip, the valve should ha>e continued opening to its full open position before it cycled closed.

The entire open/close stroke time should have been about 50-60 seconds.

The valve returned to its closed position in about 18 seconds, however. This indicates that the open command to the valve did not seal in as designed.

01:41:13 SFRCS actuation Chanael 2 tripped on low steam generator level. Since the-low pressure trip already present had priority, no change in component actuation occurred.

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p Ssquenca cf Evants Summary - 6/9/85 Page 3 01:41:31 AFP 1 tripped on overspeed.

01:41:44 AFP 2 tripped on overspeed.

01:42:00 The Operator's error was corrected by clearing the manual SFRCS actuation on low steam pressure.

Since both SFRCS actuation channels were already tripped on low steam generator level, the SFRCS attempted to realign valves in the normal configuration with AFP 1 feeding SG 1 and AFP 2 feeding SG 2.

The SFRCS attempted to open steam generator isolation valves AF599 and AF608, but the valves did not open. With these valves closed and the AFPs tripped, no feedwater was being supplied to the steam generators.

01:45 Both Steam. Generators had steamed down to approximately 12-13 inches of indicated level.

RCS Tave at this time was approximately 562*F.

01:45 - 01:51 RCS Tave was increasing due to the lack of primary to secondary heat transfer. RCS pressure was increasing due to the decreasing density of the RCS water and increasing pressurizer level.

RCS pressure increased to the Power Operated Relief Valve (PORV) setpoint (2425 psig). The PORV cycled a total of three (3) times, relieving pressurizer pressure to the Quench Tank.

Following the third opening, the PORY failed to reclose properly. The control room operator observed primary conditions and closed the block valve on the PORV. RCS pressure fell to 2075 psig before the block valve closed or the PORV rescated.

During this time period, operators were attempting to restart the auxiliary feedwater pumps locally. Some problems were encountered with local control of the AFP turbines. The turbine trip throttle valves at the turbine inlet were difficult to reset and the effort was complicated by communications problems with the control room.

During the same time period, an operator locally assisted the opening of both steam generator l

isolation valves AF599 and AF608. After he partially opened the valves, the motor operator stroked the valves'open.

d'?

c-SequInce of Ev2nto Summary - 6/9/85 Page 4 01:51 Operators placed the Startup Feedpump (SUFP) in operation to supply the steam generators. SG 1 pressure had reached a minimum of approximately 750 psig. SG 1 repressurized to approximately 900 psig from the startup feedpump. The #2 SG has reached a minimum of 920 psig.

~01:52 AFP 2 was returned to operation by operators to supply SG 2 and SG level began increasing.

Maximum RCS temperature had reached approximately 592'F. When AFP 2 was returned to service, the control room operator controlled the pump in manual rather than returning it to the Auto Essential mode of operation.

~01:55 AFP 1 was returned to operation by operators to supply the SG 1 and the SG level began increasing. Operation of AFP 1 turbine could not be regained by the control room operator in either the Auto Essential or the manual mode of operation. Control of the turbine was maintained locally by an operator at the turbine steam inlet valve.

~01:58 Tave restored to normal post trip temperature.

The cooldown lowered RCS pressure. Operators manually started the HPI pump #1 in the piggyback mode (D.H. pump 1 supplying the suction to the HPI pump 1).

A slight amount of water (5~50 gallons) was injected.

Additional Notes:

Adequate subcooled margin was available threughout the transient.

The Reactor Coolant Pumps remained in operation. The Quench Tank contained the discharges from the PORV. Makeup /High Pressure Injection cooling of the RCS was available as a method of core cooling at all times.

This data is preliminary and additional clarifications or correc-tions may be necessary after a detailed analysis of the event.

JRL:SNB:bec

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SEQUENCE OF EVENTS

SUMMARY

June 9, 1985 The following is a summary of the Sequence of Events that occurred at Davis-Besse on June 9, 1985. The plant was originally at approximately 90% of full power. No surveillance testing was in progress. The plant was in full automatic control except for the #2 Main Feedpump which was in manual.

Time Event 01:35:00 The il Main Feedwater Pump (MFP) tripped on overspeed due to a control failure. Automatic plant runback initiated. Due to the reduced feedwater flow available, Reactor Coolant System (RCS) temperature and pressure increasing.

Plant ran back to approximately 80% of full power.

01:35:29 Reactor tripped on high RCS pressure (2300 psig).

Turbine trip from reactor trip.

01:35:31 The Steam & Feedwater Rupture Control System (SFRCS), Channel 2, spuriously half tripped.

01:35:36 Main Steam Isolation Valve (MSIV) #1 closed.

01:35:37 MSIV #2 closed.

01:35 to Normal post trip equipment operation, such as

~

01:40 the auto transfer of housepower to the startup transformers, etc.

The #2 MFP continued to supply normal feedwater until approximately 0140 hours0.00162 days <br />0.0389 hours <br />2.314815e-4 weeks <br />5.327e-5 months <br />, when there was not adequate steam to operate the MFP turbine due to the closure of the MSIV's.

Approx. 01:41 Steam Generator water levels decreased to the SFRCS low level trip setpoint. The SFRCS actu-ated. The Control Room Operator at this time also actuated the SFRCS manually, however, he incorrectly actuated the SFRCS on low steam pressure instead of the desired low steam generator level.

l

Sequence of Events Summary - 6/9/85 Page 2 01:41:31 The #1 Auxiliary Feedpump (AFP) tripped on overspeed.

01:41:44 The #2 AFP tripped on overspeed.

01:42 The Operator corrected his error by c1 caring the manual SFRCS actuation on low steam pressure.

However, since the AFP's were tripped, no feed-water was supplied by the AFP's.

01:45 Both Steam Generators had steamed down to approximately 12-13 inches of indicated level.

RCS Tave approximately 562*F.

01:45 - 01:51 RCS Tave increasing due to lack of primary to secondary heat transfer. RCS pressure increasing due to decreasing density in RCS water and in-creasing pressurizer level. RCS pressure in-creased to the Power Operated Relief Valve (PORV) setpoint (2425 psig). PORV cycled a total of three (3) times, relieving pressurizer pres-sure to the Quench Tank, j;f,j gg, c /gegi, 01:51 Operators placed the Startup Feedpump (SUFP) in operation to supply the #1 Steam Generator. The

  1. 1 Steam Generator pressure had reached a minimum of approximately 750 psig. The #1 Steam Generator repressurized to approximately 900 psig from the startup feedpump.

01:52

  1. 2 AFP returned to operation by operators to supply the #2 Steam Generator. Maximum RCS temperature had reached approximately 592*F.

Steam Generater #2 level restored. The #2 Steam Generator had reached a minimum of 920 psig.

01:55

  1. 1 AFP returned to operation by operators to supply the #1 Steam Generator. Steam Generator
  1. 1 level restored.

01:58 Tave restored to normal post trip temperature.

( __

.. =v4

' Sequence of Events Summary - 6/9/85 Page 3 Additional Notes:

Adequate subcooled margin was available throughout the transient.

The Reactor. Coolant Pumps remained in operation. The Quench Tank contained the discharges from the PORV. Makeup /High Pressure Injection cooling of the RCS was available as a method of core

~

cooling at all times.

This data is preliminary and additional clarifications or correc-tions may be necessary af ter a detailed analysis of the event.

SNB:nif 6/10/85 f

/6 SEQUENCE OF EVENTS JUNE 9, 1985 TRIP Updated 10:00 AM June 13, 1985 The following is a summary of the Sequence of Events that occurred at Davis-Besse on June 9, 1985. The plant was originally at approximately 90% of full power.

No surveillance testing was in progress. The plant was in full automatic control except for the #2 Main Feedpump which was in manual.

Time Event 01:35:00 The #1 Main Feedwater Pump (MFP) tripped on overspeed due to a control failure. An automatic plant runback was automatically initiated. Due to the reduced feedwater flow available, Reactor Coolant System (RCS) temperature and pressure began increasing. The plant ran back to approximately 80% of full power prior to the reactor trip.

01:35:29 The reactor tripped on high RCS pressure (2300 psig).

The turbine tripped from reactor trip.

01:35:31 The Steam & Feedwater Rupture Control System (SERCS), Channel 2, spuriously half tripped on low SG level and cleared four seconds later.

A sequence of events monitor SFRCS full trip alana was also received and cleared.

01:35:36 Main Steam Isolation Valve (MSIV) #1 closed.

01:35:37 MSIV #2 closed.

01:35 to Normal post trip equipment operation, such as 01:40 the auto transfer of housepower to the startup transformers, etc.

The #2 MFP continued to supply normal feedwater until approximately 0140 hours0.00162 days <br />0.0389 hours <br />2.314815e-4 weeks <br />5.327e-5 months <br />, when there was not adequate steam to operate the MFP turbine due to the closure of the MSIV's.

c S:quenc2 cf Ev;nta Summary - 6/9/85

~

Pag 2 2 01:41:04 Steam generator water levels decreased to the SFRCS low level trip setpoint. A full trip on low level occurred on SFRCS actuation Channel 1.

Actuation of SFRCS actuation Channel I related components was initiated including alignment of Auxiliary Feed Pump (AFP) I to feed Steam Generator (SG) 1.

01:41:08 The control room operator attempted to manually initiate SFRCS, however, he incorrectly actuated the SFRCS on low steam pressure instead of the desired low steam generator level. He performed the manual actuation by depressing the top switch in both strings of manes 1 actuation switches for the respective SFRCS actuation channels. This generated a low pressure trip on SG 1 in SFRCS actuation Channel 1 and a low pressure trip in SG 2 on SFRCS actuation Channel 2.

Therefore, each SFRCS actuation channel sensed that its respective steam generator was inoperable while the opposite steam generator was still intact.

SFRCS actuation Channel 1 then attempted to align AFP 1 to feed steam generator 2 and SFRCS actuation channel 2 attempted to align AFP 2 to feed SG 1.

Both actuation channels, however, closed their respective steam generator isolation valves (AF599, AF608) which prevented any auxiliary feed flow from reaching the steam generators.

Per the SFRCS design, some valves positioned by the low level trip on SFRCS Channel I were repositioned by the low pressure trip.

01:41:13 SFRCS actuation Channel 2 tripped on low steam generator level.

Since the low pressure trip already present had priority, no change in component actuation occurred.

01:41:31 AFP 1 tripped on overspeed.

01:41:44 AFP 2 tripped on overspeed.

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S:quence of Evsnts Summary - 6/9/85 Pega 3

)

i 01:42:00 The Operator corrected his error by clearing the manual SFRCS actuation on low steam pressure.

I Since both SFRCS actuation channels were already tripped on low steam generator level, the SFRCS attempted to realign valves in the normal configuration with AFP 1 feeding SG 1 and AFP 2 feeding SG 2.

The SFRCS attempted to open steam generator isolation valves AF599 and AF608, but the valves did not open. With these valves closed and the AFPs tripped, no feedwater was being supplied to the steam generators.

01:45 Both Steam Generators had steamed down to approximately 12-13 inches of indicated level.

RCS Tave at this time was approximately 562*F.

01:45 - 01:51 RCS Tave was increasing due to the lack of primary to secondary heat transfer. RCS pressure was increasing due to the decreasing density of the ECS water and increasing pressurizer level.

RCS pressure increased to the Power Operated Relief Valve (PORV) setpoint (2425 psig). The PORV cycled a total of three (3) times, relieving pressurizer pressure to the Quench Tank Following the third opening, the PORV failed to reclose properly.

The control room ' operator observed ' primary conditions and closed the block valve on the PORV.

RCS pressure fell to 2075 psig before the block valve closed or the PORV rescated.

During this time period, operators were attempting to restart the auxiliary feedwater pumps locally. Some problems were encountered with local control of the AFP turbines.

During the r.sme time period, an operator locally assisted the cpening of both steam generator isolation valves AF599 and AF608. After he partially opened the valves, the motor operator stroked the valves open.

01:51 Operators placed.the Startup Feedpump (SUFP) in operation to supply the steam generators. SG 1 pressure had reached a minimum of approximately 750 psig.

SG 1 repressurized to approximately 900 psig from the startup feedpump. The #2 SG has reached a minimum of 920 psig.

~.

~ *+..4-S:qu;nce'of Ev:nts Summary - 6/9/85 Paga. 4

~01:52-AFP 2 was returned to operation by operators to supply SG 2 and SG level began increasing. Maximum RCS temperature had reached approximately 592'F.

When AFP 2 was returned to service, the control room operator controlled the pump in manual rather than returning it to the Auto Essential mode of operation.

~01:55 AFP 1 was returned to operation by operators to supply the SG 1 and the SG 1evel began increasing.

Operation of AFP 1 turbine could not be regained by the control room operator in either the Auto Essential or the manual mode of operation.

Control of the turbine was maintained locally by an operator at the turbine steam inlet valve.

~01:58 Tave restored to normal post trip temperature.

The cooldown lowered RCS pressure. Operators manually started the HPI pump #1 in the piggyback mode (D.H. pump 1 supplying the suction to the HPI pump 1).

A slight amount of water (5~50 gallons) was injected.

Additional Notes:

Adequate subcooled margin was available throughout the transient.

The Reactor Coolant Pumps remained in operation. The Quench Tank contained-the discharges from the PORV. Makeup /High Pressure Injection cooling of the RCS was available as a method of core cooling at all times.

This data is preliminary and additional clarifications or correc-tions may be necessary after a detailed analysis of the event.

JRL:SNB:bec

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SEQUENCE OF EVENTS SIM1ARY June 2, 1985 ThefollowingisasummaryoftheSequenceofEventsthatoccurredat Davis-Besse on June 2,-1985.

The plant was originally at approximately 85% of full power. The main turbine governor valve testing was in progress. The No. 4 high pressure turbine governor valve was success-fully tested.

This report may require clarification or corrections after the detailed analysis and Tap report is prepared.

Time Event 06:03:35 High pressure turbine governor valve #3 was closed as part of the governor valve testing.

06:03:40 High pressure governor valve #3 began to open as part of the governor valve testing.

06:03:41 The main turbine tripped on a high vibra-tion. With the turbine tripped, the ARTS system tripped the reactor.

06:03:42 Main feed pump 1 tripped.

06:03:43 Steam and Feedwater Rupture Control System channel 2 spuriously half tripped.

06:03:44 Main Feed Pump #2 tripped.

06:03 - 06:05 Normal post trip equipment operation such as the auto transfer of house power to the startup transformers, etc.

Steam generator water levels decreased due to the loss of the main feed pumps.

06:05 Steam generator levels decreased down to the SFRCS low steam generator level trip set point. Both auxiliary feed pumps actuated correctly and supplied their respective steam generator with proper auxiliary feedwater.

Steam generator levels were adequately maintained by the auxiliary feedpumps.

07:00 - 09:10 startup feedpump was started and used to supply the steam generator feedwater. As the decay heat load decreased, the startup feedpump was used as the main source of feedvater to the steam generators.

r L

a Sequence of Events Summary - 6/2/85 Page 2 Time Event 0900 JP '

The il auxiliary feedpump was experi-encing some speed control problems s

while being removed from service. This did not affect the plant transient.

Operators continued with the normal trip recovery actions.

The transient was initiated by high Main Turbine vibration during governor valve testing. The loss of the main feed pumps resulted in an SFRCS actua-tion on low S.G. level. The Auxiliary Feed pumps operated to properly sup-ply auxiliary feedwater for the transient.

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.TE:Er:~+5 i~: ;- 2 PE.,CTOR C O O J,' F E i ll E: HIGH F EEEUF.C TCI 1: 7:~ :;45 F El _ TOF TRIF CONFIRMED 1:35:T::31n M /,1 N TUREINE TRIF 1:35:31 STEAM RJD FEEDWATER RUPTL'RE COtJTROL SYSTEM (SFRCS>

STEAM GENERATOR (SG) LOW LEVEL HALF TRIP (SOE RECORDER SHOWS THIS AS A FULL TRIP AT 1:35:30:935) 1:35 "

cFRCS SG LOW LEVEL HALF TRIF CLEARS (SOE SHOWS THIS f,5 AN SFRCS FULL TRIP CLEARING AT 1:35:34:70) 1:35:36 MAIN STEAM ISOLATION VALVE ( f1E I V ) 112 CLOSES 1:35:37 t"SIY #1 CLOSES 1:40:20 LOW FW FLOW ALARM 1:41:03 SFRCS SG LOW LEVEL TRIP. CHAtJNEL 1 (SEE 1:41:04:345) 1: 41:04:345 SFPCS FULL TRIP (SAME AS 1:41:03) 1: 41:08 MANUAL SFRCS TRIP, LOW STEAf1 PRESSURE. DOTH CHANNELS 1: 41:10 AFW TO SG IEOLATION VALVES START TO CLOSE 1:41:13 SFRCS SG LOW LEVEL TRIP. CHANNEL 2 1: 41:31 AUXILIARY FW (AFW) PUMP TURDINE ti l OVERSFEED TRIP 1: 41: 44 AFW PUMP TURDIf4E ti2 OVERSPEED TRIP 1:42:00 MANUAL SFRCS TRIP. LOW STEAM PRESSURE. RESET 1:45:50 AFW PUt1P TURDINE tt2 OVERSPEED TRIF RESET 1:4L:32 tt i AFW PUMP STARTS 1:47: 43 AFW TO tt2 SG ISOLATION NALVE OPElJ 1:40:49 PORV OPEN (2432.8 FEl ACTUAL. 2425 PSI SETPOINT) 1: 48:52 PORV CLOSED (2376.7 PSI ACT U(iL. 2375 PSI SETPOINT) 1:49:28 AFW TO tti SG ISOLATION VALVE OPEN 1:50:09 PORV OPEfJ (2434.1 PSI ACTUAL) 1:50:12 PORV CLOSED (2369.4 PSI ACTUAL) 1:51:18 PORY OPEN (2435.3 PSI ACTUAL) 1:51:21 tt i SG LEVEL DROPS DELOW B" 1:51: 23 S T AT.T UF FW PUMP OlJ TO FEET 11 1 55 FROM I F ARATOR 1:51: 42 FORV ISOLATION VALVE CLOCED FY OPEF. AT Or (.T 2141.0 fLI 1:51:43 ft2 SG LEVEL STOPS DROPFING AT C.G" 1:51:44 ti l SO LEVEL STOPS DROF T'IlJG AT 7. !'

1:51:49 FORV CLOEED (2112,9 PSI ACTU/L) 1:51:54 81 EG FRESSUPE ETOPS DROPPING AT 749.6 PSI 1:51:57 tt i SG LEVEL STARTG INCREASING 1:52:03 42 SC PFESSURE STOPS DFiOPPING AT 910.2 PSI 1:52:06 M2 SG LEVEL STARTS If JCRE ASIf1G 1:52:21 ft2 AFW PU'1P PUMP STARTS 1:52:25 ti l SG LEVEL RAISED ADOVE 0" 1:53:20 MA X IMUf1 INCORE TEMF ERTURE RE ACHED. 601.5 F 1:53:25 AFW FLOW ST(.RTS TO tt: SG 1:53:31 MAXIMUM T3vg REACilED, 592.3 F 1:53:35 MAX It1Uf1 Th REACHED, 59?.5 F

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til 4FW PUMP SUCTION TRANEFERS TO SERVICE WATER 1 : 5C: Os HPI FLOW STOPE 2:r :27

  1. 1 AFW PUMO SUCTION TRANIFEFED BACI TO CD:JDENSATE ST 2 : c. : : ~ 1 HPI PUMP e1 OFF 2: 'r:24 LPI PU:F #1 OFF

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