ML19322C199

Forwards Info Re Chronology of in-plant Activities for 780208-1116;test Chronology Bar Chart;Power Made Histogram, 780201-1116;delays encountered,780201-1116;critical Path W/ Proper Main Stream Safety Valve Function,Best & Worst Cases

ML19322C199
Person / Time
Site:	Crane
Issue date:	01/23/1979
From:	Cutler R GENERAL PUBLIC UTILITIES CORP.
To:	Arnold R GENERAL PUBLIC UTILITIES CORP.
References
TASK-TF, TASK-TMR TMI-2-4022, NUDOCS 8001160571
Download: ML19322C199 (44)

Text

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Januarv. 23, 1979

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h ::e n Three Stile Island yuclear Station Unit 2-4,; >f 3-Startup Test Program History and Delay s2

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Enclosures:

i 1

(1)

Su==ary Chronology of ntI-2 In Plant Activities; 2/8/78 through 11/16/78 (2) ntI-2 Test Program Chronology Bar Chart (3)

Power /:!cde Histogram of ntI-2, 2/1/78 through 11/16/78 (4)

List of Delays to niI-2 Test Program Due to Problems Encountered (2/1/78 - 11/16/73)

(5)

Test Program Critical Path Assuming Main Steam Safety Valves Function Properly - Wors: Case (6)

Test Program Critical Path Assuming Main Steam Safety Valves (S

Function Properly - Most Optimistic

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,%J This is in response to your request for a detailed analysis cf the TL 2 Startup Test Program and delays thereto which have caused interruptions tc the schedule.

The CPUSC Startup and Test Scheduling Engineer, Tom Faulkner, and I reviewed

.e.iet-Ed DII-2 Shift Foreman's Log and the GPUSC Startup and Test Shift Test Engineer's Log for the period 2/S/73 through 11/16/73 and developed a summary chronology, Enclosure (1), which lists the major activities as they occurred. Frca this chronology, a n!I-2 Test Program Chronology Bar Chart, Enclocure (2), was developed. This chart graphically displays the Test Pro-

~

gram as it actually occurred along with proolems wnicn were encountered. _

"(Note that the original Test Frogram scnecule envisioned a 120 day program.

This was based on the DII-l Test Program experience and did provide some minimal amount of time for delays. Various conditions can be expected to cause delays during any startup program.

I have attenpted to select only those equipment problems which caused, or could have caused, delays in the 21I-2 Test Program.)

Enclosure (3) is a Power / Mode Histogram for your information.

On Enclosure (2) I have indicated in bold lines what I celieve to be i

the actual critical path between 2/1/78 and 11/16/79.

For clarity, I have l

f^1 chosen not to indicate on this critical path those problems which occurred C) during any test phase if they, by themselves, only amounted to a few days

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l delay at a time.

In these cases, the critical path is she'.,n to continue alcng the test phase path.

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i Mr. R. C. Arnold January 23, 1979 Enclosure (') is a listing of those problems shown on ~nclosure (2) along with ny evaluation of the period of time delay actually associated with each problem and the potential delay it, by itself, would have caused had it not been entirely or partially included under an umbrella of other problems at the same time.

Incl:sures (3) and (5) project critical path scenarios predicting what I believe would have been the course of events had we no: expeci+a:cd the Main Steam Safety Valve problem and subsequent retrofit modification.

In these cases, the inadequacy of the steam line steam hammer restraints, discovered in mid-1978, and the notification by B&W of potential loose parts (orifice rod assemblies and burnable poison rod assemblies) in the reactor internals and subsequent rectification, would have had a much more serious impact on our Test Program schedule. Enclosure (5) shows a " Worst Case" scenario and Enclosure (6) shows a "Most Optimistic" scenario. The results of these studies show that, because of problems encountered in the Test Progran other than the safety valve failure, the safety valve problem itself was solely responsible for a period of delay on the order of 20 to 39 days. An explanation of these hypothetical critical paths and the actual critical path is attached to the respective enclosures.

The followir.g persons have been consulted in performing this review:

-L3arton - GPUSC TMI-2 Proj ect Manager

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Fau1 % - GPUSC Startup and Test Scheduling Engineer A. S. Dam - 35R TM1-2 Proj ect Manager W. R. Cobean - 35R, Vice President R. W. Heward, Jr. - G?USC Manager of Nuclear Projects

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L-RCC/brh R. C. Cutler CC:J. J. Barton (w/encls.)

W. R. Cobean A. S. Dan R. W. "cuard W. H. IIirst R. J. Toola T.

Faulkner

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Enclosure (1) i f

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SC0fARY CHRONOLOGY OF TMI-2 IN PLANT ACTIVITIES j

2/3/73 THROUGH 11/16/73 I

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ACTIVITY FE3 sin". t Normal preparations for fueling - Reactor Vessel filled

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(Received NRC Operating License) t i

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>MEC sorking on fuel transfer carriages to su, port fuel load

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10

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6 1st Fuel asses, in core i

11 12 i

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Last Fuel assem. in core i

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Commence preparations for Rx head installation s

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Core barrel installation complete t

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4 16 Rx head installation begins i

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ACTIVITY

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-o Rx head installed, not torqued

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i I' 17 Rx head bolt torquing begins

[i 18 5

Rx head installation complete Coc=enced RCS fill & vent & CRDM coupling Started installing incore closures i

19 Completed coupling APSR's Co pleted torquing all incore closures i

20

• Energized pressurizers for loop fill I

RCS filled - to be vented (v

Ccemenced venting CRD's & RCS instrumentation t

I 21 ~

t i,I Completed venting CRD's at low RCS temp./ pressure i

"egin raising RCS te=p./ pressure 22 i i

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24 l

I!j'j 3egan running RCP's.

No ted noise on LP'."M.

30W advised secure pumps until analyzed. Pumps out of servica caused slower heatup rate 1/3 s

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2/3 25 ;

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,s Restarted RCP's and heated up to <200*F f

C ::enced CRD Functional testing

ACT 'lITY A.4

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' 3, 'T Completed venting CRD's at RCS temp. <200*F, >400 psig Commenced filling OTSG for secondary side hydro re-test le 2/3 t

Pressuri:cd ASB OTSC's to 900 psig - >!anways/Handholes sa tis f ac to ry, 1/3 other packing & seac leaks noted 27 Pressuri:ed ASB OTSG's to 950 psig, noted leaks, vented OTSG to fix I

leaks i

Continued CRD Functional Testing i

i 23 i

i 51\\R 1

RCP operational tests completed CRD Functional Testing Completed. Start CRD Trip Tests 2 '

t.

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I Completed CRD Trip Tests, Faising RCS pressure for hydro 1/3

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Com=caced RCS hydro, completed inspection, noted leaks, co=menced depres-j surization (Cooldown & drain to fix RCP Seal injection Grayloc flan;;e leaks) -

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j Grayloc flanges fixed, ccc ence RCS fill i

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Fill & vent in progress

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ACT!'lITY

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i Completed CRC:: Venting

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.l; Discovered gland steam leaks. Secured F.U. Heating, gland stea:

8-l RCS caintained <200% to fix (can' t heat up) t I

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Con =enced gland steam leak repair i

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Found caustic leaking fro = N, header in Aux. 31dg. & into bleed tanks Co::enced cleanup mode. Completed gland steam leak repair i

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2/3 10 f Completed cleanup of Caustic (NaCH) in RC Bleed Tanks i

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Co==ence heat up to Mode 4

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i 4i Reach Mode 4, first time s

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Rx 31dg. Personnel Access Hatch door seal failed.

(Can' t change code

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'till fixed) - Tested Sat. at 2230, recommenced heat up l l!

6 I

i Chemistry proble=s with RCS for high sodius - cleaning up two =ake-up l

de=inerali:ers 12.i I

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Co==enced heat up i 3 Reached Mode 3, first time 13.'

RC? 7; Clutch failure, all pu=ps secured, plant coasting down 1

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'I' beam on RCe' 2A t

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Lo s t_,a.u.x. b_o.i_le r,c a us i ng F. U. o u,,t o f s pe c.

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". Commence operating on RCP '.,.s',

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' Draining OTSG due to hign phosphates

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Coc=enced heat up l

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i 3i Noise noted in CTSC. Cooled down, depressurized, for instru=enta tion 1/3 a-r e_u_t_i_n c re ca i r s,,.-n,nrG\\0

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ACT!'lITY z

Plant cooldown continues MAR- *.

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CCMPLETED OTSC INSTRL,MENTATIC:T REPAIRS

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Co:cenced fill & vent I

18 l Completed venting C2D's i 1 si'.? doing RCP-2A pump shaf t runouts & cotor checks 5 seal replace =ent j

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19.,

ai 1 Completed work on 2A & blocked it.

Commenced heating & pressurizing RCS f

j Continued heat up i

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21 l CRD Rod tests perfor=ed

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Cooled slightly to fi c RCF-1.\\ seiscic restraint which bottomed out i

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, 2/3 f!,

Commenced Pressurince Spray tes: J 532*F, 1400 psi; l

(Cantinuin;; C:',D testing)

!ade other repa. irs f

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l Completed group rod drop testing i

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i RCP flow measurc=ents with 3 RCP's conducted, completed.

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Lepressurizin; 5 cooling do-n due to leaking Canax connectors t

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Comoleted Conax connector replacement, tightening CO: enced heat up 26 1

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Started pulling rods to criticallity 2,A" Initial Critica111ty-Actiieved,- first ' time ll C : enced preparations 'for zero po'.'er physics testing 28.-

e Start reactimeter checkout i

Complete reactimeter checkout I;

Ran all rods out critical boron concentration test 29 3'

5:EC Es testing-fuse blew on 2-1V inverter,'LRx trip; ES actuation, (Pressur-l 1:ce Electronstic Relief Valve Lifted) L Od' contaminated RCS Ccamenced cicanup of RCS 1/3 6

30 1!

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Disco'.ered Cl~ in RCS due to Na0H contamination, commence plant ceoidewn i

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Cooldown, cleanup continues I

4 APT 5 2reakdown vacuum to repair aus. steam leak in Unit 1 1

Satisfactorily tested repaired inverter 1

Torqued OTSC conax connectora

,m RCS cicanup continues

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' 2 3c:un heating up aux. steam line frce Unit 1 i

1 Cantinue flushin: :.a' f r ca M'1 i :i s ys t ces

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ACT!VITY s.

3 AP R ' 5 1

3 f.

Discoverec DM-V-lS63/RC-V-149 problems preventing proper pressurizer Spray operation, thus slowing down RCS cleanup progress Started venting CRD:!'s; RC-V-149 problems resolved i

un0li venting to clean CRC 11's of ::a continues 4

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Conolete CRDM venting I.

Condensate & Feedwater cleanup in process 1

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Lost one Aux. 3 oiler causing F.W. to cool down, delaying F.U. cleanup l

. i' progress l

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l Started F.U. heating again after Aux. Boiler was fixed Continuing F.U.' cleanup 7 l ! :!

i RCS heat-up in progress 1

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i 1/3 li Re-established prerequisites for :ero power physics testing 8; 2 Zero Power Physics Testing (ZPPT) in progress c i I

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3 Croup 3 Rod 1: orth ?!aasurements completed 2

Preparing for Stock Rod Worth !easurements 9

3 Questia::able Reactimeter results discovered 2

i Reciaccc card in reactimeter - neccare for checkout

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10,, j Reactimeter still uunsat.

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I-354 swapped on reactincter prepare for checkout j

3, I (Spare reactimeter rec'd on site)

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!;ew reactimeter demonstrates same unsat. characteristics I

e 11: r Continued :: PPT while attempting to resolve reactimeter problems l 2; 3

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AC'!*.'ITY Je..:.

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ZPPT continues 12. 3 i 2 i 3 l 3 ZPPT continues

~ 2 13 ; 3 2II 3,

2; ZPPT continues 3!

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} Ii j 3i Verified & rechecked reactimeter results from control room 15 ; 2f l

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l3l ZPPT centinues

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NI cable unction box discovered to have bad connector causing 2

some unsat. reactineter readings. Problem was corrected.

16.

9 3-l ZPPT continues i

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17 i 3-ZPPT continues l 2!

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Completed ZPPT I

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A j 3 Begin 0-15% power escalation / testing M._.Rx; Trip;w;2;57.!powerg'oni 1/3

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18 ' 1 7

Power /!= balance / Flow i

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15:

Pcwee escalation testing in progress g,2...l

[4trippedienhighpressure)RaiQl%n blowing down suction strainer on Conde

.' r j 3 1/3 19 ;

2-Improper sampling procedure caused delay in recovery 1,

10.

Power Escalation Testing in progress i 15:

Completed turbine data for '.{

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i 3 RPS Channel C =anuall'f tripped due to bad NI t

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Rn tripped on lii flun, Channel 0 (NI-8) s.) 20 j 3;

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1, 3 -

Delay in recovery due to NI-8 again 1/3 1

'5

?.e r Escalation in ar.e.:..r.a.s.s i

7 un~

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ACTI'.*ITY j'- t t.~.-:2

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APR 1 15

.urbine Generator synchroni:cd to grid for first time ( 105 :l',le) 21 l

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15% Power Testing continues

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Laakage noted at B OTSG Conax connectors y

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Performed Loss of Of f site Power Test 22 3

Delav in recoverv due I

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to NI 3?ain 2/3 2

1 15 T.G. back on line ( 100 MWe), Completed 0-13: Testing (W/3 RCP's) 20 3egin 15-40; eseslation/ testing i

30

Rx trip lon;NL powerispika,' rapid cooldown, M.S. relief valve excessive !

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I 3

'bibddosu;iES Tactuation#en low pressure, NaOH injection, bellows liners blown freq.)J S. relief valve discharge stacks.

1/3 4

Cooldown & investigation in progress f

Inspection found Conax connectors leaking - will depressurize to 1

24 t

repair. Also found tube leaks in 3A FW heater 5

RCS cleanup in progress t*

25 1

i.

26 i

Drained 3A FU heater for repair 1

RCS cleanup continuing 27 1

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I

?.CS depressurt:cd for Conax repair, discovered all leaks on RC?-23 "otor 23 Scgan working Conax connectors 1

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gj Continuing to investigate bellows liner problem l

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RCS cleanup in progress l

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ACTIVITY

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APR! i

~ Preparing for RCP-2A Clutch replacement I !

30 ;

Bellows liners evaluated-all hori:ontals & verticals to be replaced 1

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Replaced Conax connectors seals where needed

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>!oved RCP-2A clutch into R.B.

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, Torqued all Conax connectors 2

Continu ed to work M.S. relief valve disch..rge lines

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3 i Continued to work M.S. relief valve discharge lines 1

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.i O Ccamenced F.W.. heating i -

4,y Unit i Lost Aux. Boiler - couldn' t maintain temp. on 1 boiler, delayed 1

I i F.W. cleanup ii

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• Unit I now at 75*. - extraction steam available for F.W. heat-uo 5I.

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l Completed RCP-2A motor checks, ran water l.-

.l Completed RCP-2A motor / pump coupling 6; l RCS fill / vent valve lineup in progress 1

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l Started filling & ventin:; RCS

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Filled pressurizer, started drawing bubble k

Started venting C30's I

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. Completed initial CRD venting 8i ! !

Functionally tested RCP-2A sat.

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l!7 Found Canax connectors leaking, tor::ued to stop leaks

ACTIVITY L. u.

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MAY' 5 Started second vent & flush of CRD's 9;

Found Conax connectors leaking, commenced cooldo.m/depressurization to 1

t repair Removed nuts from c nax connectors. apol e& re to rcued o

Completeu ven:E fCRP s, commenced raising, p ssure i

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[ Continued to flush CRD's at pressure i i l.

Completed venting CBD's t

11 1

I I

Discovered Purge Valve AH-V-4A could not close i

i MEC working on repair to AH-V-4A i

Continuing F.'4. cleanup, checking out RCP operations, etc.

12 l ll 1

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i AH-V-4A repaired & tested t

13

• Mode 4 prerequisites completed 1

4 3

RCP-2A Ipper oil reservoir leaked empty. Splash shield drain lines clogged, i

4 oil spill to 2S0' el. in D-ring.

Started cocidown, depressuri:stion to :i:<.

14 5

1 8

Fixed RCP-2A backstop filter gasket, added new oil Oil cleanup in progress i

i I

15 011 cleanup in progress. Also fixing oil Icaks on RCP-23 motor &

1 flusning oil drain lines l

Oil leaks fixed, drain lines cleaned 16'

.ound leaka reversed on four RCP oil pumps caused' reverse. rotation I

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Fixed leads, commenced plant heat up 4 ;:

!3 tes,djyapjjy2J@,yprgg[tica{testingawl4 RCP*rnotrpreviously;performedl t

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ACTIVITY itAY 3

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l C:. ple:cd a pump testing (pre-eequisite to return to criticali:y) i

,i Co==enced !!.S. relief valve tes ting 2/3 18

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".S. relief valve tes:inz.encial if plant

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.sec c $ a...e::c incicatin.; 3.:Ra proble: pc is i

l run an less :han 3 RCP's.

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MAY 3 Continued testing M.S. relief valves 3

27 4

Discontinued valve testing and cooled down to work :1.S. valves 1

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(M.S.-R-4A is installed in M.S.-R-1A l'acation)

Co cenced heat up of RCS

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Started M.S. valve testing i

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Continued M.S. valve testing

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Discontinued :!.S. valve testing, concenced cooldown I*

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.%... r JU' D 3.:: ' Plant cooled down and holding pending resolu:: ion to M.S. relief valve

- il evalutation 5

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I 8 I i Commenced cooldown for Rx Head removal in anticipation of j

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resoving ORA's & installing BPRA Holddown devices j

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Vessel head bolts detensioned 1

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I Rx head removed O

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JU::E 6 Care plenum removed preparations for incore work 14 1

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j All 40 OR.\\'s recoved 15 1

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16 All 2P"A holddown devices installed, verification in progress 1

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l Con =ercial plenus installation

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(Firming up plans to modify L S. lines for new valves) 19 1

6

.I hn: ina::li;_, -.:: nrquad 20 1

.All LS. valves removed f rom steamlines 21 22 Rx vessel was overflowed withou head torqued, spilled boric acid over l

vessel flange & C-rings preparing to lift head & clean up t

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i 4 l Crouse 4,om=enced to =ake modifications to St.S. lines.

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.\\CTIVITY

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s.. r JULY e Continue ecdifiestions to !!.S. lines I

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1 26 M.S. relief valve gags re-ina:alled for hydro. Completed Sat.

I co==enced draining OTSG's & Steam lines.

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Cc: plated restoration of secondary after hydro 1

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Star:cd lifting M.S. safety with hydro set

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Comoleted safety valve testing & removed all gags l

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Performed full flow & coast down tests of RCS l

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Co:cenced cooldown for M.S. hanger installation (continuation) l l

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.Cormenced heat up, RCS filled & vented 1I

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14 4

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i.RC-V-3 tested OK et lFound steam leak on

'B' E.F. recirc line - cracked fitting not isolatible i 4

' Commence cooldown to fix.

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?eformed reactimeter testing Sat.

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15.T.C. on line (103 m.'e) 2/3

~L._T' 3egin 13% with 4 RCP's

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4. lI 'Perforced shutdown outside control room I

test i 3 t :

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!CS being tuned, 15" data reviewed prior to power escalation f

1.15 ~ Back on line (183 :!WE) 20.

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.30 Progressed thru startup range, settled out oscillations 3

4

! 34 Red.uc.i.ng po..w.e..r f or 30*.' Turbine trip test

! 30 30% Turoine trip test I.15.

,.,.._..y.,_.

Manually"trippedreactor.cocommencecooldown'forworkoutage{

22 2

i 3

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Exreriencing eroblems backflushing co-pump strainers 1/3 4:

Also fixing MSR crossover piping steam leaks (fermenite) and 5'

leaking conax connectors and bad RID in RCS hot leg.

23 1

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1 13 Discovered steam leaks in M.S. cross under piping due to vibration 3

,Rx trip on Mi pressure due to CO pump trip when reducing load to fix leak.

i I Steam leak rep _ aired 2

Recover from trip i 20:T.G. back on line 26 F'-P-18 has broken ICS controller, FW-P-1A, Hi vibration 1'

Can't escalate in power until resolved.

j j.15 F.?-P-la coupled, tested Sat.

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Ccamence power escalation to 40%

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' 407. Rx trip test pe r fo rmed 3

Commenced cocidown for work outage 4

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! 4 Carmenced cooldewn to fix.

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' Completed electrical repair of RC-V-1 3,-

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2 Found 5 fixed loose connec: ion on RC-V-1 1

1 20 Turbine on-line 1..,6 4

J-(RxLtrip.on icw pressure folicwing turbine trip 14 Recover from ::1p 1,

l 20.Turbino on line t -'.40 Operiencing F.'A.

p oscillations & Fe plugging Co pump strainers i

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Eese t:in:; M.S. sa fe ty valves t.

l Hea:er Drain systes being fine tuned

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3 15 1.epea: 30.1 turbine trip to collect =issing data due to ins:. probles

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1 40 'With last tes:

I 15 Carmence pcuer escaia:1 n :: 7 5.': power 40

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ACT t'.'!TY OCT. I Fower escalation t,,

progress 50 (Fc t i. system lis, ting escalation rate.)

1 52 '.':..wered leak in FU-V-17A Sody f/

'.D dr dn tank level controller problem has 1 HD pump out of service, further 3

03 delr. yin?, escalation rate 57 t/

19 53 HP level control valve fixed, both HD pumps back in service G

l, 31own packing on MU-V-17 (Switched to bypass valve)

! 63

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'75 Turbine trip due to phase comparison relay on generator output

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55' I6 63 Turbine trip-repeat of above 7

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75 Holding Stable for equlibrium zenon

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Received T'*G approval :o escalate to 1007, plateau with inter edia:e tes:ing i

at 9 0 ".

d 90 : oted vibra: ions on turbine generator exciter bearing :'o. 9, took curbine off line j

28 Co==enced work on exci:er bearing it (

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(Repair of RC-V-1 in progress - replaced operator gear box) j ;

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Replaced faulty relay on CRD's which had caused ratchet trip 4

i i; l Continue work en exciter bearing repair f 8 t

I SOV. 2 Completed repair of exciter bearing.

I 15 Replaced gaskets on exciter cooling lines.

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2 533 and recovered.)

i Commenced 90% power testin.;.

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'ly to conJEnsate polishing system trippini condsnsate booster and feedwater

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I 15. Returned to power operations, began escalation to 90%

1 5

. 90 *iatting for xenon equilibrium

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I 1 +,Rx; tripf on: variable l, low press.iaf ter heater drain pu=p tripped causing I

7 3 0,*eedwater pump trip, low press. caused NaOH injection.

3 RC-V-1 again needs repair - operator to be changed out.

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i 11]7 trip evaluation in progress 8

l Decision made to gin turbine screen outage on 11/11 in parallel with

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plant cleanup.

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- r "S-V-26A yoke found broken (probably caused excessively low pecss. and resultant : TACH injection on 11/7)

RCS cleanup in progress

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Connenced NCS cooldown 4'

Replaced gaskets on exciter cooling lines, j

10 5

l Turbine screen outage in progress I

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Attachment to Encl. (2) i Analysis of Actual Critical Path Shown on Enclosure (2) 1.

Completing NRC Operating License pre-requisites delayed issuance of the license by 8 days. The Operating License is required before fuel load can begin.

2.

Fuel transfer mechanism problems experienced at the onset of fuel load-in; is not shown on the critical path. Although it was a factor causing' the fuel loading activity to be extended longer than it might otherwise need to have been, fuel loading was, in fact, completed in the number of days allotted.

3.

The Reactor Coolant Pump 2A clutch failure which occurred on.3/13/73,

caused a delay of 6 days of pre-critical testing. After 3/19/78, the test program was resumed with only 3 of 4 Reactor Coolant Pu=ps in operation. This resulted in additional pre-critical testing on 5/15-16 to complete test requirements with four pumps in operation. Installa-tion of the repaired clutch in early May was accomplished in parallel with the repair of the bellow liners and therefore did not affect the critical path.

4 Steam Generator Instru=entation "Conax" fitting leaks have been a continuous problem throughou. the test program. Generally, the leak occurred due to pressure / temperature cycles of the system caused either

~'N purposely or inadvertently. Therefore, in many cases, this problem I

arose in parallel with another problem and I am considering, for the

• s purpose of this review, only 9 out of a possible 23 delay days attribut-

~-

able to these fittings.

5.

We have experienced three inadvertent ad_ igm _ hydroxide safety injec-tions into the Reactor Core. One on 3727/78 cadsid a delay of S days to the zero power physics testing. This first injection recovery delay was further compounded by chloride contamination of the Reactor Coolant System due to the use of impure Sodium Hydroxide chemicals. The second injection on 4/23/78 is not considered critical path because of the over-riding bellow liners recovery program which also resulted from the 4/23/73 transient. The third injection on 11/7/73 caused a direct critical path delay of 4 days to the power ++.:alation to 100" activity before it was decided to commence turbine een removal. On 11/11/73, therefore, the screen ou age became controlling.

6.

Nuclear Instrumentation /Reactimeter problems caused an approximate 8 day delay to :cro power physics tasting and 3 mora days during 15" power testing.

7.

Various Condensate System Strainer / Pump Suction Valve problems caused further delays to 15% power testing (2 days) and' power escalation

, testing (9 days) and was the prime reason for an eight day work outage performed in October. Problems in this area caused several plant trips.

v\\

s

3.

Although failure of the Main Steam Safety Valves to function properly en '/23/73 uas the root cause of safety injection, I am considering only that period of time from 3/13/73 through 9/1/73 (105 days) as be,ing critical path due to safet/ valves. The reason for this is be-cause, even if the valves had functioned properly on 4/23, the valve discharge line bellow liners would have failed and the cine it took to fix them, from 4/23 to 5/10 (17, days) was controlling at that point.

A subsequent problem with oil leaking from two Reactor Coolant Pump notors caused an additional 3 day delay befoce plant operations could resu=e to the point of discovering that the safcty valves could not be adjusted or modified to function properly.

9.

Removal of the Reactor Internals Orifice Rod Assemblies and Burnable Poison Rod Assemblies was not critical path since it was performed completely in parallel with the steam line modifications.

10.

In Sepe. ember 1977, it was discovered that Main Steamline snubbers were not.provided to accommodate steam hac=er vibrations. Apparently when Gilbert Assediates (GAI) perfor=ed a steam ha==er analysis for TMI-1, it was decided that GAI should also do a similar analysis for TMI-2 tecause, at that time, B5R did not have the in house capa-bility to do it themselves.

In that same year, Section 9.3 of the TMI-2 FSAR was written indicating that:

"In the Main Steam System, spec 1 attention was given to the dynamic effects or the fast closure of the turbine stop valves on the piping betueen the steam generators and the turbine steam chest. Hydraulic snubbers are provided to minimize steam ha==er while allowing nor=al system ther=al movement."

(Subsection 3.9.1.1, 2nd paragraph.)

These words were written prior to the analysis based on the assu=ption that due to the similarity of piping arrangements between Units 1 and 2,

.m h [, %, snubbers would be required on Unit 2, as on Unit 4Q 1, for the suppression 6cf steam ha=cer effects. The actr.1 steam hammer analysis was to be N g performed at some later date after 35R finalized the Main Steam piping N arrangement and the location and sizing of thermal and seismic pipe

/@gh supports and transmitted that information to GAI.

For reasons unknown, k 'y h'$@} hammer analysis or of B&R ever having trans

,there are no records of either the agreement to have GAI do the steam J M > f hanner snubbers were designed or provided for in the early days of the infor-ation to GAI.

As a result of this apparent oversight, no s: cam projcct. The lack of such snubbers was first noted by inspection during Hot Functional Testing in September 1977.

Since 1972, 35R has developed the in house capability of performing steam hancer analysis, so upon discovery of this omission 3&R was directed to proceed with the analysis and design of additional snubbers as required.

Because fuel loading and startup testing was echeduled for late 1977 and early 1973, B&R was also requested to calculs the maximum power level the Unit could safely be operated at without naving the new snubbers installed in the event lead time for =nterial procurement became critical.

B5R subsequently ectimated that power level to be abcut 30%.

(BLR letter 3934-GF, 9/13/77 and Project Change Notico 2457 refer.)

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35R performed the steam ha==er analysis using as the basis for the analy-sis a 150 milliseconds turbine stop valve closure time. That informa-4 tion was received verbally from Uestinghcuse on 9/6/77, with confirma-s tion from Westinghouse by memorandum of the same date. The =c=o also included a flow vs. closure time curve purported to be typical of these the use 'f 150 =illiseconds in that the valves which tended to support o

closure was fairly linear with respect to flow decrease. The results of this analysis showed the need for additional snubbers on steam line piping in the Turbine Building ares.

(Enisting restraints provided for dead weight, thermal and seismic loads were found to be capable of accc==odating the added steam ha==er loads in the steamlines routed through the Control Building Area, except for one seismic restraint with a PSA-35/35 kip snubber which was upgraded with a PSA-35/50 kip snubber.)

Material for these new snubbers was received on site and installation.

co==enced around 3/1/78. Installation was completed by 4/15/78, prior to reaching that point in the Test Program requiring power levels in excess of 307..

Therefore, these snubbers never became controlling on l

the critical path.

4

.. ~

In January 197, the General Office Review Board (GDR3) revieved the steam ha==er ana yris-snubber-probl am dascribed-+bdve and concluded that

_since the analysis, design and installation _xass la on an expedited Fasis at the end of construc_ tion, an indgoendent review of_3&R's ef? orts was warranted in_ view of the_importance of the snubbers. Met-Ed was requested to perform _chis review.

f-s i

Meanwhile, BLR had been attempting to justify the use of an increased

~

ss turbine stop valve closure ti=e of about 200-250 milliseconds (which B&R had seen for some other plants) in order to demonstrate additional conservatism in the snubber design because one of the snubbers in the Control Building Area was carginally capable of sustaining the calculated loads and increased power levels without snubbers installed were being sought. To do so, B&R requested Westinghouse to check the information previously provided (150 milliseconds) to see if actual test data was available. Westinghouse prepared a flow vs. closing time curve and tele-4 copied it to B&R on 4/25/78. This curve, based on test data, differed from the previously received " typical" curve in that it no longer showed a linear relationship between time and flow. Various interpretations of this curve demonstrated closure times anywhere between 50 to 150 milliseconds.

On 5/17/73, when Met-Ed firce met with 3&R to review the steam hammer ucek as requested by the GOR 2, this new curve was discussed. ::o agree-ment was reached as to the most appropriate closure time to use in the steam hammer analysis at that time.

During the next several weeks it was concluded that, based on the new curve, an, effective valve closure j

time to use fo-an appropriately conservative steam ha==er analysis of the main steamlines hould be 50 milliseconds vs. 150 milliseconds actual closure time used in the previous analysis. Met-Ed made this reco==enda-tion to CPU on 6/12/78-(CE:t 2544) and G?U forwarded the reco==endations

>s to SLR (TMI-II/7025, 6/2S/73)' requesting an evaluation of the effects of

\\

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the new closure ti=c.

On 7/18/73 B&R discussed with CPU the results of sc=e limited re-analysis usia; the 50 at111 seconds closure ti=c.

This re-analysis showed that the loads on the main steam seismic snubbers in the Control Buildin; Arca increase by about 50%, which was in execes of thair rated espacity in most cases.

BLR recommended that additional snubbors be purchased while they completed the analysis and design of new or upgraded ecstraints.

(The steam ha==er snubbers in the Turbine 3uilding previously installed were found to be acceptable without =odi-fication.) A; sin, 3&R reco==cnded limiting plant operations to no more than 30 pouer until the restrtints were modified.

(At this point in time, however, the plant was shut down for modifications to the steamlines for new safety valves.) These reco=mendations were forwarded to GPU by letter on 7/26/78 (4249-CP).

The new seismic snubbers wcre subsequently designed, fabricated and di Livered to the site by 8/14/78. Installation was not completed by,

the time the Main Steamline/ Safety Valve modifications uere completed on 9/1, so the balance of the installation became critical path and caused an additional 7 day delay to the Test Program.

(It should be noted that the snubber installation required the steamlines and surround-ing work areas to be cool, so no plant power operations could have taken place in parallel.)

The following Field Change Requests and Engineering Change memos des-cribe the modified or added steam ha=cer snubbers and seismic snubbers:

Turbine Building - FCR 2457.1

- ECM 5899, 5948 Control Building Area - FCR 2457.2 ECM 9047, 9052, 9053, 9062, 9071 11.

After completion of the Main Steam Line restraint installation, the plant was returning to power operations for resumption of the Test Program when the plant experienced problems with pressurizer spray valves and also discovered an unisolable crack in a fitting in an Emergency Feedwater line that serves to route water to a steam generator recirculatica line.

These two problems caused an additional critical path delay of 6 days.

12.

The failure of a Turbine Generator Exciter Bearing during power escala-tien testing on 10/27 caused another 4 day delay after completion of the 75 power plateau testing.

\\

Considerin; the aforc=entioned problems to be equipment probic=s causin,

or having the potential to cause, delays to a normal Test Program, it can be seen that these problems, taken in series, could have caused.a delay of about 355 days.

In the sequence of occurrence, however, the net del:v is about 201 days.

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Enclosure (a)

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V Delays to TMI-2 Test, Program Due to Problems Encountered (2/1/78 thru 11/16/78)

Delav Davs Actual Potential 1.

Oper$tingLicensePre-requisites 8

8 2.

Lack of Main Steam Line Restrairrs for Steam Ha=mer Forces (affected S-II portion of lines in Turbine Bldg.)

0 l'2(1) 3.

Inadequate Main Steam Line restraints for Steam Hammer Forces based on "new" criteria (affected S-I portion of lines in Control Bldg. Area) 7 71(2) 4.

Fuel Transfer Mechanism Proble=s 0

3 5.

Reactor Coolant Pu=p (2A) Clutch Failure 8

16( }

l 6.

Steam Generator Instrumentation Fitting Leaks 9

23 7.

Sodium Hydroxide Injection Transients 12 31-s

~

8.

Nuclear Instru=entation erable=s 11 11 9.

Condensate System Strainer Blowdown problems 11 13 10.

Main Steam Safety Valve Problems-105 120 11.

Safety Valve Discharge Bellow Liner Failures 17 17

~'

12.

Reactor Coolant Pump (2A/B) Motor 011 Leaks 3

3-13.

Reactor Internals potential loose parts 0

26 14.

Pressurizer Spray Valve ~ problems 3

4 15.

EFW Fitting failure in Steam Generator recirculation line 3

3 16.

Turbine Generator Exciter bearing failure 4

4 Totals 201 365

~

l Footnotes:

1.

Assu=es 30% power level exceeded by 4/3/73 based on original schedule.

[G 2.

Assumes po.er level was greater than 30% on 6/23/73 when concern was dis-

\\s, covered and plant operations were i= mediately terminated.

3.

Assu=es delay ti=e'for. clutch re=cval and reinstallation plus 2 extra test days after reinstallation.

?CC/brh - 12/5f71

. / *.

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Attachment to Encl. (5)

Analysis of Test Proers= Critical Path Assumine :tain Steam Safetv Valves Functicn Procerty - E'o rs t Case Referring to the attached Test Program Chronology Bar Chart, it can be seen that, making the abcve assumptions, events up to 5/13/73 would have re-l mained the same except that the Sodium Hydroxide Safety injection of 4/23/78 would not have occurred. Cleanup from that injection, however, was not critical path.

After 5/13/73, plant testing would have resumed with all four Reactor Coolant

, Pumps back in operation.

(Reinstallation of the clutch was done in parallel with bellow liner repairs.)

on 5/26/78 B&W notified GPU of potential loose parts in the core based on recently discovered failures at another plant. Based on the severity of the consequences of such an event, we would undoubtedly have decided not to continue plant operations until the problem was resolved. The Orifice Rods were subse'-

quently removed and hold down devices installed on Burnable Poison Red Assemblies in an expeditious manner, so it can be assumed that the least delay possible to t

the Test P cgras would have been 26 days as shown.

About a week later, on 6/28 as events actually occurred, GPU concluded that the steamlines were in jeopardy and again would have terminated operations (since lower than 30% power level testing had already been ec=pleted) until ade-quate supports were installed. This would have caused another direct delay to the program of 71 days.

('~~N All other proble=s actually encountered are considered to have happened

)

at one point or another during plant testing, possibly in the sequence shown on gs _/

the critical path.

The end result shows that, had events occurred as described above, we would have been 5 days into the Turbine Screen Removal Outage on 10/26/73 rather than 11/16/73. In other words, under this scenario, the Test Program would have been 20 days shorter.

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