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E- _ I J MBE Jersey Central Power & Ught Companym EAF_E Madison Avenue at Punch Bowl Road-

Morristown, New Jersey 07960(201)455-8200

June 27, 1980

Director of Nuclear Reactor RegulationNuclear Regulatory CommissionWashington, D. C. 20555

Dear Sir:

Subject: Oyster Creek Nuclear Generating StationDocket No. 50-219IE Bulletin No. 80-13

In accordance with requirements stipulated in IE BulletinNo. 80-13, " Cracking in Core Spray Spargers", Jersey Central Power 6Light Company hereby submits an evaluation of possible cracks discoveredon segments of core spray piping within the reactor vessel between the'

inlet nozzle and the vessel shroud. These possible cracks were notidentified before Jersey Central Power 6 Light Company submitted tothe Nuclear Regulatory Commission Technical Specification ChangeRequest #83 dated March 31, 1980, which provided an evaluation andrepair program for cracks found on the core spray spargers. Theinformation provided in this letter and its attachment, together withTechnical Specification Change Request #83, provides the completeinformation and evaluation package required by IE Bulletin No. 80-13.

The attached evaluation has been reviewed and approved bythe required review groups in accordance with section 6.4 of the OysterCreek Techn'ical Specifications.

Since the evaluation of all the cracks and possible cracksfound on the Core Spray System within the reactor vessel and the repa'rsalready performed on the core spray spargers shows that there is nosignificant change in safety margin from that of the original design,Jersey Central Power 6 Light Company requests approval for the returnto operation of the Oyster Creek plant.

Very truly yours, j:

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;GX ,Ivan R. Fin ek r.

Vice Presi nt

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Enclosures

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8007020 3 7 7-Jersey Central Power & Light Company i Member of the General Public Utilities Systern 1

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General Pubhc Ubiihes System

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OYSTER CREEK

NUCLEAR GENERATING STATION

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INSPECTION AND EVALUATION

OF CORE SARAY SPARGER PIPING

INSIDE REACTOR VESSEL

JUNE 1980

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TABLE OF CONTENTS

I. INTRODUCTION

II. SYSTEM DESCRIPTION

.III. RESULTS OF 1980 INSPECTIONS

IV. EVALUATION OF INDICATIONS

V. SAFETY EVALUATION

VI. CONCLUSIONS

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I. INTRODUCTION,

Scheduled in-service inspection of the core spray spargers

in the reactor vessel during the 1980 outage disclosed the presence

of cracks in addition to those which were discovered in the fall

1978 refueling outage. These were reported to the Nuclear Regulatory

Commission in Technical Specification Change Request No. 83. During

the 1980 refueling outage, visual inspections wer, also performed

and video tapes made of the Core Spray piping in the reactor vessel

between the inlet nozzle and the vessel shroud. Subsequent review

of the video tapes resulted in the classification of two indications

as "possible" cracks. In order to conservatively assess the safety

significance of these indications, we have assumed that these are

cracks and have evaluated their impact on core spray effectiveness.

This report will summarize the results of that evaluation,

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II. SYSTEM DESCRIPTION

The Oyster Creeh reactor vessel contains two independent

core spray sparger assemblies which are fed by two separate core

spray systems. Each of these systems is provided with fully redun-

dant pumps, valves, power supplies, controls and instrumentation, so

that each system can perform the safety function in the presence of

a single active failure in that system. Only one system is required

to accomplish the safety objective. Within the reactor vessel, the |

1

core spray system piping for each system consists of 6 inch schedule

40 stainless steel piping from the reactor vessel nozzle to a 6 inch I

standard weight tee located next to the shroud and below the spargers.

On either side of the tee is a 6 x 5 inch eccentric reducer. Five

inch schedule 40 stainless steel piping is then routed around the

outside of the shroud for about 90' where it penetrates the shroud

connecting to the sparger assemblies. Each 90* segment of the 5 inch.

piping is supported at the midpoint by a bracket welded to the shroud.,

When the system is actuated, core spray water is directed through this

piping to both segments of the core spray sparger assembly, thus sup-~

plying water to the reactor core from all directions. The sparger

'nozzles are designed to provide a spray pattern that ensures each

fuel bundle receives adequate cooling flow at system flows from 3100

gpm to 4500 gpm. The configuration of the core spray system pipingin the reactor vessel is shown in Figures 1, 2, and 3.

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III. RESULTS OF 1980 INSPECTIONS

Visual examinations of the spargers using remote underwater

television were performed during the 1980 refueling outage. The

results of those examinations and the subsequent modifications to

the sparger assemblies were reported to the Nuclear Regulatory Com-

mission in Technical Specification Change Request No. 83 dated

March 31, 1980.

In addition, visual inspections were performed and video

tapes made of thn Core Spray piping within the reactor vessel between

the inlet nozzle and the vessel shroud. These tapes have been viewed

| by two qualified visual inspectors and two indications have been

; classified as possible cracks. Both of these indications are on the,

6 x 5 inch eccentric reducers of the system II piping. The larger.

of these two indications was classified by a third qualified inspector

as marks made during installation. Other nonqualified, but experiencedJ

observers generally agree that this indication cannot be readily

explained and therefore cannot be dismissed.

In an attempt to determine if these indications are newi

since 1978, reviews were made of the video tape inspection results

of the 1978 outage. The emphasis of the 1978 inspection was on the

|welds in the piping. Because these indications are not located

immediately adjacent to welds, this review did not provide conclu--

sive results.

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IV. EVALUATION OF INDICATIONS

A. Evaluation of Causes

Analyses have been made in an attempt to better characterize

the linear indications observed in the 6 x 5 reducers and to

determine their cause. The results of these analyses performed

by JCP&L, MPR Associates, Inc., and General Electric are summa-

rized bel'ow.

1. Stress Corrosion Cracking

The possibility that the observed indications are the result

of a stress corrosion mechanism similar to that which has

occurred in the core spray spargers has been evaluated. It

is concluded that stress corrosion is not a likely cause

for the following reasons:

* Appearance of Indications

The observed linear indications do not have the branching, ,

irregular appearance typical of stress corrosion cracks'

such as those observed in the spargers using the same |visual examination techniques. '-

* Location of Indications

The indications are located in forged material well awayfrom the welds and weld sensitized material.

* Material

Certifications for the reducer fittings indicate thatthe reducers were manufactured in accordance with ASTMA403, are in the solution annealed condition, and thematerial is Type 304L stainless steel with a reportedcarbon content less than 0.02%. This material and pro-cessing should be resistant to stress corrosion attack.

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2.- Stress Due to Normal OperaLing Conditions

-During normal operation, the core spray piping is subjected

to loads due to the vertical and. radial differential ther-mal expansion between the stainless steel shroud and the

carbon steel reactor vessel. Piping stress analyses indicate,

that the stresses in the reducers due tE~ heat-up to normal

operating conditions are approximately 17,000 psi. This

stress level is well within accepted allowables for thermal

expansion stress and would not result in crack initiation

due to low cycle fatigue. No other sources of thermal

fatigue loads have been identified.,

3. Flow Induced Vibration --

The possibility of high cycle fatigue cracking due to flow-,

induced vibration has been evaluated.''Possible excitation,

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loads and frequencies due to vortex shedding at the maximum

anticipated flow rates in the region.of_the core spray pipingi

were estimated and dynamic analyses of_the core spray piping ,

were performed. The results of these analyses indicate that '

the lowest natural frequency of the piping is approximately |

10 to 12 Hz as compared to an expected vortex shedding fre-,

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quency of 4 to 6 Hz (8 Hz maximum based on the most conser- ||

vative assumptions). This difference in the natural fre- |!

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quency and expected range of excitation frequencies is suffi-'

cient to preclude significant flow induced vibration. Fur-

ther,. stress analyses show that even if vortex shedding

were to excite the piping, the resulting stresses are too~

low to cause_high cycle fatigue failures (calculated alter-

nating stresses in the reducers are less than about 2000 psi(

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at' resonance' conditions). In addition, visual examinations,

have not revealed any evidence of vibration. '

|- 4. . Installation Marks

It is considered possible that the linear indications on the

reducers could be the result of tool or die marks from the

forging process or could be related to installation methods.-

The assumption that the indications are tool or die marks'

or surface scratches from other causes is not inconsistent

| with'their appearance.

; Based on the available data and analyses, it cannot be ascer-i-

' tained- whether the observed indications are relevant flaws

or surface marks and a definitive explanation for their,

presence has not been identified. Accordingly, the signifi- |

cance of the indications has been evaluated on the conserva-

tive assumption that they are through-wall cracks.

i ' B. Significanbe of Indications

; On the basis of the visual inspections, it has been assumed fori

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analysis purposes that a 4-1/2 inch long by 0.030 inch maximum-

width, through-wall crack exists in each of the 6 x 5 reducers.:

The effect of such a defect has been evaluated for normal and

accident loads. The results of these evaluations are as follows:

1.- Normal and Seismic Loads

As indicated above, stresses at the reducers due to worst-

-case normal operating conditions (specifically, heat-up/*

cool-down) are approximately 17000 psi. Stresses due to a~

postulated seismic event would add less than about 2000 psi

cto this number.1

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Crack propagation analyses performed by General Electric,

indicate that the propagation of a 4-1/2 inch crack due to

five heat-up/ cool-down cycles would be insignificant.

Therefore the growth of such a crack due to the possible

number of heat-up and cool-down cycles during a fuel cycle

is of n6 concern.

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Similar_ crack propagation analyses for an assumed alternating

stress of + 2000 psi due to either seismic or flow induced

vibration indicate that the resulting stress intensity mag-

nitude is within the threshold value for crack growth -

that is, no propagation of the assumed 4-1/2 inch crack would

occur for an unlimited number of cycles.

Since there are no primary loads on the core spray piping

during normal operation, and the results of crack propagation .

analyses predict no significant growth for a reasonably

expected number of heat-up/ cool-down cycles, it is concluded

that the presence of the indications on the reducers will .,

have little effect on the integrity of the system during

normal operation.

2. Core Sera.y Injection Loads

During a core spray injection event, the core sprny piping

would be subjected to relatively cool (e.g. 80*F) water.

This thermal transient subjects the initially 550*F piping

to:

(1) transient " skin" thermal stresses which are of no con-sequence for a single cycle and,

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. (2) . differential thermal expansions between the cold pipingand the 550*F shroud and reactor vessel.

Analyses of the thermal expansion stresses at the reducer*

- show that the thermal mis-match between the core spray

piping and its end points is less during an injection trans-

ient than during normal, steady-state operation. The maximum

.stress intensity in the reducer during the injection is cal-

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culated to be approximately 5000 psi. Average membrane

stresses in the axial direction (i.e., in a direction

tending to open the assumed cracks) are less than 10% of'

this combined stress.

The presence of an assumed 4-1/2 inch crack in each reducer'

has been evaluated by General Electric for all the design

loads associated with a core spray injection transient.

The results of these analyses indicate that an assumed

through-wall crack which. extends up to 260* around the cir-

cumference of the reducer would be acceptable. Since the

observed linear indications appear to extend about 90*,

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around the circumference, significant margin is available. ;e ,

The analyses summarized above demonstrate that the assumed|

defects in the core spray piping reducers will not reduce i

l? - structural margins to an unacceptable level during an injec-

tion transient.

C. . Core' Spray Hydraulic Analyses

Hydraulic analyses.have been performed by General Electric to

evaluate the effect of through-wall cracks on core spray

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system effectiveness. For the purpose of 'these analyses, it..

was assumed that a 4-1/2 inch crack exists in each reducer andthat these cracks are open at least 0.030 inch at the center

and. taper to the ends. The results of these analyses m...ow that

i, the minimum flow through any nozzle is maintained at tha minimum

required flow corresponding-to a system design flow of 1400 gpm

even if reducer leak areas are five times the assumed crack,

areas. These assumed leaks outside the shroud have no effect'

on core spray distribution. Accordingly, it is concluded that

the presence of significant through-wall cracks in the core4

spray piping in the vessel between the inlet nozzle and the

shroud will not degrade the effectiveness of Core Spray System

II below original design values.,

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V. SAFETY EVALUATION

The Oyster Creek Emergency Core Cooling System is made up

of two core spray systems each of which is single active failure

proof. Each core spray system is orovided with redundant emergency

power sources, valves, pumps, etc. so that no active single failure

can prevent it-from distributing, by itself, sufficient core spray~

flow to fully justify use of the spray cooling heat transfer coeffi-

cients assumed in LOCA analyses. Therefore only one of the two core

spray systems is necessary to meet the requirements of 10 CFR 50.46

with the exception of_a core spray line break in which case the

other core spray system is required to assure adequate core cooling.

Hydraulic and structural analyses have been performed

which take into account the existence of two linear indications

found on the Core Spray System II in-vessel piping. The results of~

these analyses indicate that even under the consee mtive assumption,

that these indications are through-wall cracks with significant flaw

area, the Core Spray System II piping inside the reactor vessel is

structually adequate for normal and core spray injection loads, and

there is no unacceptable effect on core spray system effectiveness.

.

Therefore, the conclusions reached previously in the NRC's

SER of May 15, 1980 that the present condition of the core spray

system does not reprasent a significant change in safety margin from

Lthat of the original design and that operation of the Oyster Creek

Plant is acceptable is still applicable..

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VI. CONCLUSIONS

The linear indications detected during remote TV inspec -

tion of the core spray piping inside the reactor vessel may becracks, tool or manufacturing marks or other surface irregularities.

A-definitive cause for the existence of cracks has not been identi-

fled. However, analyses indicate that the core spray piping inside

the vessel is structurally adequate for normal and core spray injec-

tion loads even *f it is assumed that the observed indications aresignificant through-wall cracks. Similarly, hydraulic analyses

indicate that the presence of such cracks would not have an unaccept-

able effect on core spray system effectiveness. Therefore there is

reasonable assurance that in the unlikely event that the core spray

system would be called upon to function during operation, the system

would perform its intended function in accordance with the original

design criteria.

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