ML19318C872

Forwards Response to IE Bulletin 80-13, Cracking in Core Spray Spargers. Rept Encl

ML19318C872
Person / Time
Site:	Oyster Creek
Issue date:	06/27/1980
From:	Finfrock I JERSEY CENTRAL POWER & LIGHT CO.
To:	Office of Nuclear Reactor Regulation
References
IEB-80-13, NUDOCS 8007020377
Download: ML19318C872 (17)

Text

_ _ _ _ _ _ _ ____ _____________________

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MBE Jersey Central Power & Ught Company m

EAF_E Madison Avenue at Punch Bowl Road Morristown, New Jersey 07960 (201)455-8200 June 27, 1980 Director of Nuclear Reactor Regulation Nuclear Regulatory Commission Washington, D. C.

20555

Subject:

Oyster Creek Nuclear Generating Station Docket No. 50-219 IE Bulletin No. 80-13 In accordance with requirements stipulated in IE Bulletin No. 80-13, " Cracking in Core Spray Spargers", Jersey Central Power 6 Light Company hereby submits an evaluation of possible cracks discovered on segments of core spray piping within the reactor vessel between the inlet nozzle and the vessel shroud. These possible cracks were not identified before Jersey Central Power 6 Light Company submitted to the Nuclear Regulatory Commission Technical Specification Change Request #83 dated March 31, 1980, which provided an evaluation and repair program for cracks found on the core spray spargers. The information provided in this letter and its attachment, together with Technical Specification Change Request #83, provides the complete information and evaluation package required by IE Bulletin No. 80-13.

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

Since the evaluation of all the cracks and possible cracks found on the Core Spray System within the reactor vessel and the repa'rs already performed on the core spray spargers shows that there is no significant change in safety margin from that of the original design, Jersey Central Power 6 Light Company requests approval for the return to operation of the Oyster Creek plant.

Very truly yours, j

GX,

Ivan R. Fin ek r.

Vice Presi nt la Enclosures 8007020 3 7 7-Jersey Central Power & Light Company i Member of the General Public Utilities Systern

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ersey tr wer & Light Company General Pubhc Ubiihes System OYSTER CREEK NUCLEAR GENERATING STATION INSPECTION AND EVALUATION OF CORE SARAY SPARGER PIPING INSIDE REACTOR VESSEL JUNE 1980 l

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4 TABLE OF CONTENTS I.

INTRODUCTION II.

SYSTEM DESCRIPTION

.III.

RESULTS OF 1980 INSPECTIONS IV.

EVALUATION OF INDICATIONS V.

SAFETY EVALUATION VI.

CONCLUSIONS i

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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, j

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O' 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 l

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-

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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 piping in the reactor vessel is shown in Figures 1, 2, and 3.

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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 l

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 experienced J

observers generally agree that this indication cannot be readily explained and therefore cannot be dismissed.

In an attempt to determine if these indications are new i

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 away from the welds and weld sensitized material.

Material Certifications for the reducer fittings indicate that the reducers were manufactured in accordance with ASTM A403, are in the solution annealed condition, and the material is Type 304L stainless steel with a reported carbon content less than 0.02%.

This material and pro-cessing should be resistant to stress corrosion attack. __

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 loads and frequencies due to vortex shedding at the maximum anticipated flow rates in the region.of_the core spray piping i

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-4, quency of 4 to 6 Hz (8 Hz maximum based on the most conser-vative assumptions).

This difference in the natural fre-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

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low to cause_high cycle fatigue failures (calculated alter-nating stresses in the reducers are less than about 2000 psi

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In addition, visual examinations have not revealed any evidence of vibration.

l-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 l

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.

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' B.

Significanbe of Indications On the basis of the visual inspections, it has been assumed for i

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

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postulated seismic event would add less than about 2000 psi cto this number.

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i 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.

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, 7-

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. (2). differential thermal expansions between the cold piping and 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*

i 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

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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 and that 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 core 4

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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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

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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

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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 be cracks, 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 are significant 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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