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Forwards Reactor Pressure Vessel Internals Steam Dryer Rept Summarizing Indications Found During Unit 1 Refueling Outage,Per Request.Indications Will Not Impact Safe Operation of Facility.Related Info Encl
	ML18040B104
Person / Time
Site:	Susquehanna
Issue date:	05/14/1985
From:	Curtis N; PENNSYLVANIA POWER & LIGHT CO.
To:	Butler W; Office of Nuclear Reactor Regulation
References
	PLA-2471, NUDOCS 8505170393
	Download: ML18040B104 (157)
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REGULATOR INFORMATION DISTRIBUTION TEM (RIDS)

ACCESSION NBR:8505170393 DOC,DATE: 85/05/14 NOTARIZED: NO DOCKET Steam Electric Station~ Unit 1~ Pennsylva 05000387 FACIL:50 387 Susquehanna AUTH INANE AUTHOR AFFILIATION CURTIS' ~ N~ Pennsylvania Power L Light Coo RECIP ~ NAME RECIPIENT AFFILIATION BUTLERgl4 ~ Re Licensing Branch 2 S UBJECT: Forwards reactor pressure vessel internals steam dryer rept summarizing indications found during Unit 1 refueling outageiper request, Indications will not impact safe oper ation of facility.Related info OR CODE: A001D COPIES RECEIVEDILTR Submittal: General Distribution encl'ISTRIBUTION ENCL j SIZE'ITLE:

NOTES: 1cy NMSS/FCAF/PM, LPDR 2cys Transcripts. 05000387 OL o 07/17/82

'~IN k~p no RECIPIENT COPIES RECIPIENT COPIES ID LTTR ENCL ID CODE/NAME LTTR ENCL LB2'C CODE/NAME'RR 01 7 7 INTERNAL; ACRS 09 6 6 ADM/LFMB 1 0 ELD/HDS4 1 0 NRR/DE/MTEB 1 1 NRR/DL DIR 1 NRR/DL/ORAB 1 0 NRR/DL/TSRG 1 1 /METB 1 1 NRR/DSI/RA 8 1 1 REG 04 1 1 RGN1 1 1 EXTERNAL: EGLG BRUSKEgS 1 1 LPDR 03 2 2 NRC PDR 02 1 1 NSIC. 05 1 1 NOTES: 3 3 TOTAL NUMBER OF COPIES REQUIRED: LTTR 31 ENCL "28

Pennsylvania Power 8 Light Company Two North Ninth Street ~ Allentown, PA 18101 ~ 215 i 770-5151 Norman W. Curtis Vice President-Engineering tt Construction-Nuclear 21 5/770-7501 MAY 14 1985 Director of Nuclear Reactor Regulation Attention: Mr. W. R. Butler, Chief Licensing Branch No. 2 Division of Licensing U.S. Nuclear Regulatory Commission Washington, DC 20555 SUSQUEHANNA STEAM ELECTRIC STATION RPV INTERNALS/STEAM DRYER REPORT ER 100450 FILE 841-2 $ 203-11 $ 203-10 PLA-2471

Dear Mr. Butler:

In response to a request from Warren Hazelton, we submit the attached report summarizing the indications found during the Unit 1 First Refueling Outage and their dispositions. We have concluded that none of the indications impact safe operation of Susquehanna.

Also attached are copies of information requested by Mr. Hazelton in a site meeting on April 9, 1985. Please call if you have any questions on the attached.

For yout information, Unit 1 will restart in early to mid-June.

Very truly yours, N. W. Curtis Vice President-Engineering 8 Construction-Nuclear Enclosures (2) cc: M. J. Campagnone NRC R. H. Jacobs NRC esp Si 7P3~3-F$

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1. INTRODUCTION During inservice inspections (ISI) of internal components of the Susquehanna Unit No. 1 reactor vessel in Spring 1985, several visual indications were observed. The purpose of this report is to present results of the evaluation of indications observed in the steam dryer, steam dryer support bracket, core spray spargers, feedwater spargers, IRM/SRM instrument dry tubes, top guide, and in addition, get pumps set screw gap sizes.

2.

SUMMARY

2.1 STEAM DRYER SUPPORT BRACKET:

One of four dryer support brackets was found to be cracked during the Unit 1 first refueling outage. The bracket crack has been determined to be caused by fatigue. The bracket has been replaced with a similar component, however, the method of loading the bracket has been modified so as to significantly reduce the stresses.

Instrumentation consisting of strain gages, differential pressure transducers, and accelerometers will be installed for the purpose of investigating the causative load during the next operational cycle.

The observed defect represents no significant impact on plant safety.

2. 2 STEAM DRYER:

Three groups of indications were discovered on the Unit 1 steam dryer during the first refueling outage visual inspection. The first group included four crack-like indications on the dryer hoods which subsequent liquid penetrant testing proved to be not relevant/non-existent.

The second group included the vane bank tie rod washer-nuts. The tie rod washer nuts were covered by welded capture plates to prevent the generation of small loose parts.

The third group of indications is located on the dryer support ring.

They have been determined to be IGSCC cracks which have a maximum probable depth of 1/4.inch. ,Six 'of these cracks have been measured for depth by non-destructive techniques and will"be trended for 'crack growth rates during the next'operational cycle. Furthermore, analysis has been performed which, based on conservative crack depth growth assumptions, proves, that no adverse safety~,or operational consequences arise from operating;with" the observed cracks in the Unit 1 dryer.

-2.3 CORE SPRAY SPARGER Initial inservice inspections (ISI) of the core spray spargers revealed one indication in the C sparger and one indication in the D sparger. Because the weld area had been ground, it is not possible to tell whether the indications are in the weld, base metal, or heat affected zone (HAZ). As a result of subsequent ISI the indication in the C sparger was considered to be a non-relevant surface scratch or

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grind mark. The indication in the D sparger may also be a surface scratch or grind mark. However, because of the crack-like appearance of the lower 0.25" of the indication (the entire indication is about 0.75" long) and the fact that cracks have been observed in other BWR core spray spargers, the indication in the D sparger is conservatively assumed to be a crack herein. Cracking has not been confirmed by means other than visual examination. The most likely mechanism for the observed crack in the "D" sparger is IGSCC due to cold work from pipe bending and grinding. Possible additional contributors are weld HAZ sensitization and residual weld stresses.

Results of evaluations indicate that the observed crack in the D sparger will have no effect on the structural or hydraulic integrity of the sparger even during core spray injection. The observed crack would not be expected to produce loose parts or adversely affect the LOCA analysis. As a result, no corrective action is required at this time.

2.4 FEEDWATER SPARGER In service inspections (ISI) of the feedwater sparger revealed one axial indication in flow nozzle 14 of the A sparger. The indication starts in the flow nozzle elbow and extends through the adaptor and possibly into the header pipe.

A possible cause for initiation of the observed indication in flow nozzle 14A is high cycle fatigue due to thermal cycling in the sparger flow nozzles during low flow conditions. Indications have not been confirmed by means other than visual exam. It is conservatively assumed for analytical purposes to be a crack.

The results of the analyses indicate that a crack in a flow nozzle is not likely to propagate significantly into the sparger pipe.

Based on the evaluations presented in this report, it is concluded that no corrective action is required at this time.

2.5 TOP GUIDE Visual inspections revealed a crack-like indication at top guide grid location 36-41 and surface irregularities at several other grid locations. These indications were not confirmed by means other than visual inspection. The cause of this potential crack is not known.

An analysis was performed to determine the critical flaw sizes for the fast fracture of the beams under the worst postulated loading conditions.

Based upon the analysis, the critical crack size in the highest stressed region of the top guide is conservatively estimated to be in excess of 3". Even if total crack propagation throughout the ligament occurs, it does not pose any safety concerns.

In addition, a non-irradiated top guide at Hope Creek was video inspected by the ISI team and revealed indications similar to those observed at Susquehanna. These indications were dye-penetrant tested and found to be non-cracks.

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Based upon the fracture mechanics evaluation and Hope Creek information, it is concluded that no corrective action is required at this time.

2.6 SRM/IRM INSTRUMENT DRY TUBES Three of the twelve dry tubes were examined. All of the examined dry tubes are intact. There are no detectable bends or offsets in any of the examined tubes. The three dry tubes are at core locations 16-13, 16-21, and 24-37. All three dry tubes have several small faint indications. All of the indications are in the non- pressure boundary portion of the dry tubes similar to those at other reactors.

Only one dry tube (16-13) has a long indication and it is less severe than those observed at several other reactors.

Based upon analyses performed by GE, the SRMs and IRMs can continue to function even with a 360 0 through wall crack of the dry tubes, because the two pieces will be held in functional alignment by support from the adjacent fuel bundles. Also, the support provided by the fuel bundles will prevent adverse safety consequences from loose pieces in the unlikely event the dry tube becomes completely severed.

4 Based on this evaluation', Susquehanna Unit 1 can be operated for at least one, additional fuel cycle with the existing dry tubes with no adverse impact on safety.

2.7 JET PUMP GAPS The gaps between the restrainer bracket adjusting screws and the mixer on ten jet pumps were examined using a camera and video recording equipment.

The examination resulted in observable gaps at five of the twenty set screw positions (2 set screws per get pump). The largest gap was measured to be 0.026 inches wide. Four remaining gaps were obviously smaller and therefore were not measured.

An analysis performed by GE concludes that during normal balanced flow operation, unbalanced flow, and transient conditions, get pump vibration levels would be acceptable for gaps no larger than 0.030".

During single loop operation, jet pump vibration levels are acceptable if the gaps are no larger than 0.030 inches and the pump speed is limited to 80% of rated speed.

The observed gaps at Susquehanna Unit 1 are within the experience base of other reactors and do not pose any restrictions during normal two recirculation pump operation.

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2.8 REACTOR WATER CHEMISTRY:

It is known that the BWR water chemistry environment, even with good impurity control, is aggressive enough to produce IGSCC of stainless steels under suitable material conditions and stresses. However, impurity control can slow the initiation and propogation of cracking.

The control of impurities over the first cycle of SSES Unit 1 has been good. Average conductivities at power were reduced to levels consistent with BWROG guidelines during the first third of the cycle and have remained there. Chemistry should not have been an excessively aggravating contributor to IGSCC.

3. DISCUSSION 3.1 STEAM DRYER SUPPORT BRACKET:

3.1.1 Com onent Descri tion: The',support bracket is one of four short rectangular projections from the-interior of the RPV that support the steam dryer. They are 3x5xll inch forgings, full penetration welded to Inconel pads about 10 feet below the closure flange at azimuth 4', 94', 184', and 274'. (See Figure 3.A-1)

3.1.2 Indications

Remote underwater video viewing first revealed indications of cracking in the 184'racket. On the top of the block near the RPV wall, a single indication crossed the 3" width of the block following the contour of the weld prep.

On each side, the indication continued downward moving away from the RPV wall in a circular arc with center near the upper interior corner of the block. Fig. 3.A-2 shows the configuration of the indications. This indication was confirmed by local VT, PT, UT, and by physical separation of a portion during the bracket removal. The other three brackets were examined by remote VT, local VT, and PT with no indications.

3.1.3 Material

The brackets are constructed of forged blocks of Alloy 600 Inconel. Prior to welding, the blocks were mill annealed at 1700'F and machined. The pad on the RPV is an alloy 182 Inconel weld butter. The block is )oined to the pad by SMAW groove welding lg" deep from both sides. The root pass was by GTAW, back ground to sound metal. The bevel angle was 25'. No post weld heat treatment was applied.

3.1'.4 Causes of Indications:

The metallurgical analysis in the following section shows that the bracket failed by a fatigue mechanism. Since the initiation sites were found on the side surfaces of the bracket, the stresses had to be highest there. This implies that a flexural load was applied to the part in a horizontal direction. Vertical forces were also present, however a failure due to purely vertical forces, such as would be caused by lifting and dropping of the dryer on the bracket should

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have initiated cracks on the upper surface. No such initiation sites were found. Since no stress corrosion cracking was found, the mode of failure is fatigue.

Examination of the failed bracket on the upper surface showed that the support ring was in direct contact with the edge of the bracket farthest from the reactor wall. This was different from the other three brackets which showed contact with the seismic block attached to the support ring. The point of application of the load on the failed bracket was 80%

farther away from the crack initiation edge than was the load application point on the unbroken bracket diametrically opposed to it. This bracket, as well as the 94', and would most likely see the same forcing conditions as 274'rackets, the broken bracket, but because of the point of load application, the moment applied to the weld would be only 56%

of the moment at the same weld in the broken bracket and the stress would be significantly less than the failure stress.

An estimation of the expected life can be approximated by using the material fatigue curve and the estimated cycles to failure from the metallurgical analysis. The fatigue design curve from the BSPV code Sec. III Div. 1 Appendices, 1983 ed.

shows that in the lower stress regime, small stress reductions produce large increases in expected life (cycles to failure).

Thus, the new arrangement should provide a lifetime equal to the life of the plant with sufficient margin and certainly in excess of the duration of the next fuel cycle.

Evaluation of Indications:

Three different samples were removed from the support bracket which were sent subsequently to GE's Vallecitos Nuclear Facility for metallurgical examination.

Sample 'A'as taken from the center front left hand corner of the bracket at the termination point of the crack. The fracture surface was found to be typical transgranular fatigue with a small amount of plastic deformation at the termination point of the crack. No gross plastic deformation was observed in the area nor was there any branching or intergranular cracking evident.

Sample 'B'as taken from the center of the lower right surface crack. Again, transgranular fatigue was observed to be the mode of crack propagation with beach marking evident and proceeding from right to left across the surface of the fracture. This means that the initiation point was closer to the reactor wall than where the sample was taken.

Sample 'C'as taken from the top portion of the bracket including the point of closest approach of the cracks to the vessel wall overlay. This was a large sample extending the full 3 inch width of the bracket and including both weld metal and bracket base metal. The fracture surface showed evidence

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of 3 major cracking planes. Two planes originated at the right surface and one from the left surface of the bracket.

On the one crack plane from the upper right fracture it was evident that the crack origination point was in weld metal.

The characteristic thumbnail print of a fatigue initiation site was present and beach markings of slow irregular fatigue crack growth and river patterns of fast crack growth were also present. The fatigue crack initiation point was about 3/4 inch below the upper right corner of the bracket. Termination of the crack was in the center of the bracket at the point of closest approach to the vessel wall overlay.

The other two cracks were also characterized as fatigue as they showed the same fracture morphology as the fracture described above. It was not evident however exactly where the origination points of these cracks were located. The crack originating on the left surface of 'the bracket could have originated anywhere from the upper corner to below the lowest edge of the sample (about 1"). All three cracks terminated in the center of the bracket.

Evidence of stress corrosion cracking was pursued with both optical and scanning electron microscopy. All fracture planes were found to be transgranular in nature and no evidence of IGSCC was found. This was true of surfaces of the bracket in the areas of the base metal, the weld material and in the heat affected zone of the weld.

In summary, the metallurgical investigation gives evidence of fatigue failure being the ultimate cause of cracking in the steam dryer support bracket. Three independent cracks initiated in the weld material at the base of the fillet welds, and progressed inward towards the center of the bracket and down and away from the weld into the base metal of the bracket. The three cracks terminated at the center of the

, bracket at a closest approach to the vessel wall of 0.130 inches. This was determined by U.T. NDE techniques after the bracket and all evidence of cracks was removed.

Due to the extent of cracking, the safety analysis assumed complete failure of the support bracket. Two criteria were examined; loose parts and structural integrity. Dryer performance is considered a commercial issue only.

Structurally, the'unction of the support brackets would not be lost by a single bracket failure. The weight would be transferred to the two brackets on axis perpendicular to the failed bracket. Tipping would be limited by the hold-down brackets under the RPV head and, ultimately, by the skirt inside of the vessel below.

The dryer support bracket would most likely wedge into a stable position if it became completely severed. Assuming that all or parts of the bracket separate, a failure mode and v

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effect analysis was performed that showed potential for damage to feedwater spargers, core spray piping or get pumps. The damage would be detectable and in the absence of an independent failure, no safety function would be lost.

The actual failure of a bracket would quite likely be detected during power operations. Susquehanna has a loose parts detection system which would effectively detect the presence of migrating loose parts. In addition, the condenser hotwell is regularly sampled for Na-24 concentration which is indicative of moisture carryover.

3.1.6 Corrective Action:

The dryer support bracket at 184'racked due to caused by a horizontal reversing load. The other fatigue,'robably three brackets'atigue life were not significantly impacted because the load application point was closer to the RPV wall.

The dryer will be instrumented before it is placed back into service in order to aid in investigating the source of the loading. In order to preclude the recurrence of bracket cracking during the next fuel cycle, the point of load application at the'84'racket was moved by grinding out interference with the dryer support ring such that the seismic block bears the weight. The weld pad was carefully prepared for installation of the new bracket and the final surface was examined by VT, UT, PT, and etching for soundness of the material.- The final thickness of the inconel weld pad was

. 130 inches which precipitated the use of special welding techniques in the repair. The new support bracket is identical to the original in every way except the bevel angle on the weld prep was increased to 45'o facilitate rewelding.

3.2 STEAM DRYER:

3.2. 1 Com onent Descri tion:

The steam dryer is a non-code, non-safety-related reactor internal component. Its purpose is to improve outlet steam quality, especially when operating at less than full power.

See Pigure 3.B-1 for a general arrangement sketch of the dryer. The steam enters from below via the dryer skirt. The skirt is suspended from the dryer support ring, a heavy curved beam. The skirt has four drain ducts for returning water to the vicinity of the feedwater spargers. Attached to the top of the support ring are the vane banks. There are six vertical Chevron type dryer banks with perforated plate inlets and outlets and drain troughs below. The vanes have spacers strung over four tie rods whose ends pro)ect through the vane bank end plates. The tie rod ends are threaded into double eccentric washer/nut sets for alignment purposes. The steam flow is directed into the vane banks horizontally by the curved hoods. The outlet steam is directed upward by the back side of the inlet hood to the next vane bank except for the

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two central banks which face each other. Various deck plates fill the gaps between the circular support beam rectangular hoods. There are four lifting rods and the attached to the support ring with threaded eyes on top. These interface with the hold down lugs under the RPV head in an earthquake or a postulated mainsteam line break. The support ring is an assembly of two semicircular beams with a 3Q x 9Q inch cross-section joined into a circle by bolting to curved backing beams at azimuth 0'nd 180'. The ends of the half circles remain separated to provide a gap for the installation guide rods in the RPV. At azimuth 4', 94', 184', and 274',

seismic lugs are welded to the rings to support the weight of the dryer without rocking and to provide lateral restraint in an earthquake.

Indications:

Remote video examination was used to identify indications in the 1984 repair area of the hood at azimuth 40', the vane bank end plate at azimuth 0', the dryer support ring at many and the tie rod washer/nut sets. 'ocations, The indications on the hoods, both the 1984 repair area and the end plate at 0'zimuth were examined by PT. There were no relevant indications as a result of this examination.

The washer/nuts appeared to be damaged based on the remote video examination and have been repaired by welding capture plates over all washer/nut sets.

The indications in the support ring were confirmed by PT.

None of the indications progress into hood or deck plate attachment welds. Figures 3.B-2 show the approximate locations of a representative sample of relevant indications.

Material:

The entire dryer is constructed of Type 304 stainless steel sheets and plates. The dryer support ring is a 3Q x 9Q inch rectangular beam that is rolled into the semicircular shape and machined to square it. The heat treatment consisted of annealing of the bar prior to rolling. No heat treatment was applied post forming.

Causes of Indications:

Ten areas of the support ring and dryer hood welds were photographed at the time of the P.T. examinations to record the location of the indications. No cracking was revealed in any of the welded plates, but many cracks were found on the support ring itself. All of the photographed indications were within 3/4" of a weld and the one metallurgical sample tested, taken near the weld, showed mild sensitization (precipitation of carbides). Because of the close association of the cracks

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with welds, it is implied that both the residual stresses near the weld and the heat affected zone contributed to the cracking phenomena. Although 3/4" is farther from a weld than one normally considers a sensitized zone, it may have been close enough to be sensitized along with the fact that the material was in a cold worked state; i.e. it was formed into a ring after solution heat treatment.

3.2.5 Evaluation of indications:

The steam dryer support ring exhibited indications on the vertical surface, the corners and the upper (and lower) horizontal surfaces. A metallurgical boat sample was obtained from each of these three surfaces and analyzed by both light and scanning electron microscopy for fracture morphology and other characteristics.

Distance Crack

~Dam le Position from Corner ~De th Vertical II 0. 231" 6

225'urface Corner 0 0 II 0. 167" Surface 210'pper 47' 0 7II 0. 160" from weld)

'3/8" The depth of each crack was determined by grinding out the sample area until a dye penetrant exam did not reveal the presence of a crack. Metallographic evidence showed that each of the cracks was IGSCC in nature. Hardness tests were performed on the metallographic samples taken from the ring.

The samples showed surface hardening which is indicative of cold working during manufacture. There was no evidence of fatigue failure. There was some evidence of a very shallow layer of transgranular cracking on the surface.

Only the sample taken from the top surface of the ring showed evidence of sensitization. This was determined on revealing the carbide precipitates by an Oxalic acid etch. One of the remaining two samples was given an E.P.R. test to measure the sensitization and the results showed this material not to be sensitized. The ring was solution annealed and the carbon content is 0.056% so it is likely that the sensitization only appears in or near the heat affected zones of the welds and not in the bulk of the ring.

While the cracks near the surface showed oxidation, the IGSCC cracks deeper in the metal did not exhibit oxidation products and therefore they were considered to be fresh and actively growing. Edax analysis of the surface contaminants did not reveal any unusual elements; only those of the base metal and the P.T. examination materials.

In summary, the ring cracking is basically IGSCC in nature with a small amount of transgranular cracking which was very

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shallow. It is peculiar that only the ring itself is cracking and not any of the remaining 304 stainless steel plates welded

'o the ring or the rest of the dryer. This may indicate that the material is more susceptible to crack initiation by IGSCC due to high residual manufacturing stress and deformation than the remainder of the dryer.

The cracks in their existing state are not large enough to have any significant affect on structural integrity. Based on a conservative estimate of crack growth rate, the cracks will remain too small to affect integrity throughout the next fuel cycle. Therefore, there is no impact on safety.

3.2.6 Corrective Action:

We believe the stresses that contributed to the IGSCC cracks in the dryer support ring are due to manufacture and the operating stresses are very low. We expect to see very little crack growth during the coming fuel cycle, In order to prove this, six crack areas have been identified by punch marks and non-destructively tested for depth. The depth readings are all less than 1/4" which is consistent with the cracks in the boat samples. At the next refueling outage, these will be measured again and appropriate action taken.

3.3 CORE SPRAY SPARGERS 3.3.1 Com onent Descri tion:

I The Susquehanna Unit 1 co're spray'spargers are shown'n "

Figures 3 C-1 and 3 C-2. There are two independent core spray spargers; an upper sparger with bottom mounted nozzles and a lower sparger with top-mounted 0

nozzles. Each sparger consists of two approximately 180 sparger halves. Each sparger half (A, B, C, and D) consists of two 4" Schedule 40 header pipes (sparger arms) welded to a 6" schedule 40 inlet pipe (junction box). The junction box is welded to the upper shroud via the seal ring. The sparger arms are supported by brackets welded to the upper shroud at two locations in addition to the support at the inlet pipe.

3.3.2 Indications

A remote underwater TV examination of the accessible portions of the core spray spargers and corresponding internal piping was performed. Two indications were found. A 1/4"-3/8" indication was found in the "C" Sparger at 187 0 . (Figure 3 C-3) The location of the surface indication was possibly in the heat affected zone of the left sparger arm to junction box weld. Also, a 3/4" indication was found on the "D" Sparger at 172'. (Figure 3 C-4) The location of this indication was possibly in the heat affected zone of the right sparger arm to junction box weld. Cleaning of the affected areas was performed after which the "C" Sparger indication was 10-

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determined to be a non-relevant surface scratch or grind mark.

Only the "D" Sparger indication remained relevant after cleaning. The indication found on the "D" Core Spray Sparger was dispositioned to be a "crack" by the NDE Level III inspector. It was very tight with a width characterized as

'ess than 0.001 inch. This dimension was obtained by placing several wires next to the indication and making an optical comparison.

3.3.3 Material

The core spray spargers are as welded Type 304L stainless steel with a maximum carbon content of 0.019 percent. During fabrication and installation, it is noted that the 4" Schedule 40 sparger arms were cold bent to the required radius and that one or more of the sparger halves would have been cold sprung.

3.3.4 Causes of Indications:

The most likely mechanism for the initiation of the observed crack is intergranular stress corrosion cracking (IGSCC) due to cold work from pipe bending and grinding. Such cold work can significantly increase the susceptibility of Type 304L stainless steel to IGSCC. Possible additional contributors to IGSCC are weld HAZ sensitization and residual weld stresses.

In addition, previous observed cracking in BWR core spray spargers has been attributed to IGSCC.

3.3.5 Evaluation of Indications:

Evaluations of the core spray sparger crack have been performed by PPSL and our consultants. The analyses address structural and hydraulic integrity, loose parts, and the effect on LOCA analyses. The results of the analyses are presented below.

The analyses indicate that the observed crack in the "D" sparger will have no effect on the structural or hydraulic integrity of the sparger. The analyses addressed potential sources of stress resulting from fabrication, installation, normal operation, and operation during a postulated LOCA.

There are no significant primary loads on the core spray spargers during normal operation or core spray injection.

Secondary thermal stresses are not a concern for a few cycles.

Residual stresses from fabrication and installation vary from tension to compression. Thus, crack arrest would be expected as the crack propagates into the compression zone. An analysis which bounds the effects of core spray sparger cracks indicates that the effect on core cooling is negligible.

Because sparger structural integrity has been demonstrated, loose parts are unlikely. However, loose parts analysis has been performed. The conclusion is that the probability of unacceptable flow blockage of a fuel assembly or for unacceptable control rod interference is negligible. The lt I

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potential for corrosion or other chemical reaction with reactor materials is essentially zero since the sparger material is designed for in-vessel use. Loose parts are not expected to cause damage to the other RPV internals.

A bounding calculation of the limiting LOCA with approved Appendix K licensing model but with CCFL breakdown input based on large scale tests results in a maximum PCT of approximately 1400'F (800' margin to licensing limit of 2200'F). No credit for steam cooling or the improved decay heat correlation which would further reduce the PCT are included in this calculation.

3.3.6 Corrective Action:

F II It is concluded that Susquehanna Unit 1 can safety operate in the present condition and no'orrective actions. are warranted at this time.

3.4 FEEDWATER SPARGER INDICATIONS 3.4.1 Com onent Descri tions:

The SSES Feedwater Sparger design consists of six sparger headers each containing 18 top mounted welded nozzles. A nozzle consists of a 90'lbow welded to an adaptor (Figure 3 D-1). The spargers are supported at each end by end brackets that are pinned to support lugs welded to the inside diameter of the reactor vessel.

3.4.2 Indications

During inservice inspection of the spargers, an indication was seen in the area of nozzle 814 on "A" sparger (30'zimuth) using remote visual examination. The indication can be characterized as running axially to the two nozzle welds with its upper limit gust beyond the elbow to adaptor circumferential weld and lower limit on the sparger arm appearing to branch out in a faint starburst pattern between nozzles,,l3 and 14 (See Fig. 3 D-2). From the video tapes it is not possible to see the indication going through the elbow to adaptor weld but the indications in the elbow and adaptor appear to line up on opposite sides of the weld.

3.4.3 Material

The fabricated sparger assembly is type 304 stainless steel in the solution heat treated condition. The headers are 6" schedule 80S pipe.

3.4.4 Causes of Indications:

Cracks have been observed in a similar feedwater sparg'er at one other plant and the cause has been attributed to high 12-

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cycle fatigue due to thermal cycling during low flow conditions. However, the previous cracking has been oriented circumferentially with respect to the welds and in spargers that were not solution heat treated. If a crack exists, the cause of crack initiation is uncertain. The magnitude of thermal loads necessary to initiate a crack would likely have resulted in a more severe'crack. In addition', we would have expected to see indications on other nozzles. Therefore the possibility that the indication is the result of the growth of a pre-existing material defect in the base metal or a weld cannot be ruled out.

Evaluation of Indications:

As a conservative measure, the indication has been evaluated as if it were a crack.

Since there are no primary loads on the spargers, fatigue crack propagation can only occur due to a thermal gradient.

Such a thermal gradient is present only during low flow conditions. The thermal stresses in the sparger pipe would be expected to be much lower than in the flow nozzles. The result is that a crack in a flow nozzle is not likely to propagate significantly into the sparger pipe. The GE analysis has conservatively concluded that crack growth over the next ten month fuel cycle will not exceed 0.5 in. The critical crack size, calculated at 6 inches, will not be exceeded even if a conservative 2 inch crack is assumed to exist on the sparger.

Also, field operating experience with the older GE sparger design having flow holes rather than nozzles has shown that cracks in the sparger headers tend not to propagate around the pipe.

Because continued sparger structural integrity has been demonstrated, loose parts are not expected. However, GE has performed a loose parts safety evaluation and determined that there are no safety concerns with postulated loose parts.

Corrective Action:

The Level III inspector contracted by PP&L for in-vessel visual examinations has dispositioned the indication as non-relevant and PP&L concurs with this disposition.

No corrective actions are currently planned for the feedwater spargers.

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3.5 TOP GUIDE 3.5.1 Com onent Descri tions The top guide assembly consists of a network of interlocking beams which form a highly redundant gridlike structure (Figure 3 E). In the areas of interest, particularly the central high fluence regions, there are no welds present. The purpose of the top guide is to provide lateral support to the upper end of the fuel bundles.

3.5.2 Indications

During inservice inspection of reactor internals components, nineteen top guide grid locations were examined using remote video equipment. Several grid locations exhibited an irregularly contoured crud-like surface deposit. Particular attention was focused on grid location (X-36, Y-41) where a crack-like indication was seen in the central portion of the beam away from the ligaments. Surface conditioning was performed resulting in apparent removal of part of the indication and the remainder appeared faint.

3.5.3 Material

The top guide is made from type 304 stainless steel in the solution heat treated condition.

3.5.4 Causes of Indications:

The exact nature and cause of the indication at (X-36, Y-41) is unknown. The loading on the top guide during normal operation produces negligible stresses in the beams and therefore IGSCC is not expected to occur because of the negligible loading, the fact that the material is solution heat treated and that there are no welds present in the areas of interest.

3.5.5 Evaluation of Indications:

A fracture mechanics analysis of the top guide was performed assuming a through wall crack. The analysis is based on a fracture toughnes~ associated with a maximum accumulated fluence of 4.5X10 nvt at the lower edge of the beams which is essentially at the top of active fuel. Faulted event loading conditions were used since they represent the worst case loads. The analysis concludes that the critical crack size in the highest stressed location of the top guide, i.e.,

in the bottom beam cutout region of the ligaments is in excess of 3 inches. Furthermore, even if total crack propagation of an entire ligament occurs, it would not pose any safety concerns due to the highly redundant design of the top guide.

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In order to establish a baseline against which the various surface phenomena could be compared, a similar examination was performed on the unused Hope Creek 2 top guide. While the Hope Creek top guide is not structurally identical, it is of similar design using the same material and fabrication processes that were used for the SSES top guide. The Hope Creek top guide video examination revealed under magnification a large number of surface indications. The surface condition appeared to be similar to-that of the SSES top guide except for a shiny appearance rather than a dull crud-like appearance. The contracted Level III inspector acknowledged the similarity of the surfaces but noted that the relative severity of the indications on the two structures could not be compared due to illumination differences. Nine Hope Creek top guide areas exhibiting various indications were dye penetrant examined and no relevant indications were found.

3.5.6 Corrective Action:

Based on the fact that top guide loads are negligible during normal operation and based on the similarity between the observed indications in the SSES and Hope Creek top guides, PPGL does not consider it likely that the observed indication represents a crack. It is likely to be a non-relevant surface irregularity enhanced by the crud-like deposit. If a crack is present, it is less than the calculated critical crack size and does not constitute a safety concern. Therefore, no corrective action is planned.

3.6 SRM/IRM DRY TUBES 3.6. 1 Indications:

A remote underwater TV examination of three of the 12 dry tubes in Susquehanna Unit 1 was performed. The three dry tubes were at core locations 16-13, 16-21, and 24-37. All of the examined dry tubes were intact. The inspection revealed very fine circumferential indications in the non-pressure boundary portion of the'ry tubes. All of the observed indications are in the tube and the shaft (Figure 3 F-1). No indications were observed in the adapter, guide plug or primary pressure boundary. The indications were barely visible with the longest being approximately 75% of the circumference in length on the dry tube at location 16-13.

(Figure 3 F-2). The indications on the dry tubes were dispositioned as non-relevant by an NDE Level III examiner.

3.6.2 Material

The dry tubes are Type 304 stainless steel which has been solution annealed.

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The cause of the observed indications in the SRM/IRM dry tubes is most likely irradiation assisted stress corrosion cracking (IASCC). Cracking due to IASCC has been seen at several other plants resulting in dry tube replacement.

Evaluation of Indications:

Although the indications were non-relevant, a backup analysis was performed which conservatively assumed that a 360 0 through wall crack existed in the SRM/IRM dry tubes. The analysis addressed the following consequences of cracks in dry tubes:

loose parts, breach of pressure boundary, functional and structural performance. The results of the analysis are presented below.

The analysis showed that there is no possibility for the generation of undetected loose parts during fuel loading and there are no safety concerns for loose parts postulated to occur during operation. The support provided by the fuel bundles will prevent adverse safety consequences from loose parts.

In the unlikely event that a crack would initiate and propagate through the pressure boundary, a small leak would develop. The resulting leakage is not significant to safety.

It was shown through an Appendix K evaluation that leaks of this magnitude would result in a peak cladding temperature (PCT) of less than or equal to 1000 F, which is much less than our licensing basis.

The SRMs and IRMs can perform their intended function even with a maximum offset of the dry tubes due to a 360 0 through wall crack because the two parts will be held in functional alignment by support from the adjacent fuel bundles.

Therefore, there would be no effect on the insertion or removal of SRMs or IRMs.

There are two possible structural effects of cracked dry tubes; seismic performance and effect on flow induced vibration. A 360 through wall crack in a dry tube will not affect the ability of the fuel bundles to support the cracked dry tube during a seismic event.0 In addition, operation of a dry tube with a postulated 360 through wall crack will not cause any damage to the surrounding fuel channels nor further degrade the dry tube due to the fact that SRM/IRM dry tube vibration is primarily caused by small levels of fuel channel motion. The wear from this small movement is not a concern.

Corrective Action:

Based upon the above evaluation, Susquehanna Unit 1 can be operated for at least one additional fuel cycle with the existing dry tubes with no impact on safety.

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3.7 JET PUMP GAP:

3. 7. 1 Examination:

A remote underwater TV examination of the area between the jet pump wedge and restrainer screws and the jet pump mixing assembly on 10 jet pumps was performed. (Figure 3 G) This examination was performed to determine if gaps were present between the wedge or adjusting screws and the mixing assembly.

The results of the inspection revealed one readily visible gap between the vessel-side adjusting screw and the mixing assembly of Jet Pump /315. Using a taper gauge and a dial indicator, the gap was conservatively measured to be 0.026in.

3.7.2 Cause

The most probable cause for the gap found in Jet Pump gl5 was the implementation of an installation instruction to reduce the preload on the jet pump beam bolt assemblies. The inlet mixer had probably been slightly misaligned during the implementation of this instruction.

3.7.3 Evaluation

Analysis by GE has shown that a gap less than 0.030in. is acceptable. The analysis assumed normal operating conditions with balanced recirculation loop flow and a maximum gap of 0.030in. at the RPV side adjusting screw. Analysis has shown that jet pump vibration levels would be acceptable for gaps less than 0.030in. during unbalanced flow and transient conditions. In addition, during single loop operation, jet pump vibration levels are acceptable if the gaps are less than 0.030in. and the pump speed is limited to 80% of rated speed.

3.7.4 Corrective Action:

No corrective action is currently planned for the jet pump gap. Based on our analysis, Susquehanna Unit 1 can continue operation.

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CORE SPRAY SPARGER (ELEVATION)

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APPENDIX A APPENDIX A SUSQUKQLNNA I WATER CHEMISTRY DATA Susquehanna I water chemistry records were reviewed by GE for the period from first criticality on September 10, 1982 to January 1, 1985. An overall summary is that Susquehanna I had better than average reactor water conditions, as compared with most BWRs during the startup testing period and the remainder of the first fuel cycle.

From these data there appears to be no connection indicated between chemical impurity levels and the cracking of in-vessel components.

The daily plant data are well summarized by data submitted, as a partial fulfillment of fuel'arranty, requirements.'... These data are'hown in attached plots, I lk Figure 1 shows the, average weekly reactor conductivity on a time base. The weekly average value is derived as an arithmetic mean of 5 to 7 daily values in a one week period. Only two of the values are at or above 1 uS/cm. This same data is plotted on a log normal probability grid in Figure 2. A characteristic of this type plot is that the 50% probability point represents the geometric mean of the data set. Thus, for the startup period and the first fuel cycle to mid-1984, Unit 1 had a mean reactor water conductivity uS/cm. From experience, this is a better than average value for a BWR in of'.32 early life operation, and better than about 1/3 of the BWR fleet, each of which has a more mature data base.

The maximum weekly reactor water conductivity is plotted on a time base in Figure 3. These data are a sub-set of the weekly average data in that only the single maximum value for a one week period is plotted. Only two points are shown above 1 uS/cm. It should be noted that the values. in all of the figures do not consider reactor power level and, therefore, several of the less severe spikes are, in fact, associated with reactor shutdown conditions.

Average chloride concentrations in the reactor coolant are shown in Figure 4 with weekly maximum values in Figure 5. None of the values approach the specified maximum operating value of 200 ppb and both plots are dominated by values at the lower limit of detectability (20 ppb).

Overall, Susquehanna 1 reactor water conditions have been comparatively better than other early life BWRs, and there is no indicated causitive relationship between reactor water chemistry and reactor internals cracking.

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Enclosure 2

1. Complete CBSI welding history of welding and PWHT of-

a. shell course weld (SA533)

b. inconel weld pad

c. bracket attachment weld (See Attachment 1)

2. Detailed water chemistry history summary including highlights of unusual events. (See Attachment 2)

3. Tubing materials for-

a. condenser and FWH's: 304 Stainless

b. Noisture Separators: Carbon Steel Baffles (Chevrons)

4. Known occurrences of unusual air leakage and source of problem (See RPV Internals/Steam Dryer Report)

5. Preliminary and final failure analyses reports based on fracture study (See RPV Internals/Steam Dryer Report for Preliminary Failure Analysis)

II

6. Description of steam dryer instrumentation to be installed (See Attachment 6)

7. Chemistry data on sulphurous species in feedwater: Data not available.

Collection began in Harch, 1985.

8. Steam dryer skirt fabrication information: There were no indications on dryer skirt, therefore no information is supplied.

9. Restricted Access Welder gualification (See Attachment 9)

10. Bracket and seismic block loading patterns (See Attachment 10)

11. Results of NDE (VT) on seismic blocks (See Attachment ll)

12. Results of NDE (PT) on 94' 274'upport brackets (See Attachment 12)

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~~P t Wagging Pr 6'W4 ThLkness Describe iif pipe, A~ ~~r 'lier Metal WELDING PROCEDURE 4J Manual Machina g0 'RECORD OF WELDER PERFORMANCE TEST 8'iller /gg diameter and wall thickness) Welded ~ + RsngiQuallf'iameter Material SPacif ication Thickness to dd- Mmm>APE ~j~g Q / of P No. x f& Metal Group Zd" to P No. ~~ Range Qualified ~ Weld Metal Analysis N<<A. Single Pass 0 Single Arc gL Position of Groove If 3G 5G,6G Upward 0 Multiple Pass@ Multiple Arc 0 1G 0 2G 0 3G 0 4G)k 5G 0 6G 0 Downward 0 Preheat Temperaiure lnterpass Temperature Postwald Hast r tment Temp. Postweld Has~estment Time ATMOSPHER E AC4~2 FOR INFOR ATION ONLY spaz iW~ 4~ Trade Name ~<7"r"c~ Current/Polsri~~~ $ +r3 ~~ ~ Amps ~sg ~ P'Pe Volts gg 9-rc Inches per Minute ~gg Forehand Backhand g0 TEST RESULTS REDUCED SECTION TENSILE TEST Dimensions Ultimate Specimen No. Total Ultimate Unit Character of Failure and Location Width Thickness Area Stress IPSII Load ilbs.i GUIDED BEND TESTS Type and Figure No Result Type and F igure No. Result Test Conducted By Laboratory-Test No. RADIOGRAPHY TEST Radiographic Results. Test Conducted By Laboratory-Test No. of. 4S b~e~ d4'8> Welder's Nana Stamp No. Who by virtue of these tests meets wekfar perfonnance raqubements. Fr lr P- 8'<~2-Ne o'ortify that the statements in this record an cortact end that the test vsalds ware prapentL wafded and tasted in accordance with the , tssfuf~ents of Secdon IX of the ASbtE Code. / Mqwtr <<,Iv QU~ s ~ ~ ~ ~l<<7 ';;;i 'R".':,."(i'~",...R;,; -.,;::;;--,:,!g E II K IIII 1 K LE CT )I I C,;,;-,'~:.;:.'",'l-.'-R ') gg,'" ",'y R R Rll e Waging Pr Thickness Ilfpipe, diam>> M ual Machine g[ 0 Materhl Speclf ication /gg d wall thickness) Welded Isa~ + to~g+Q~H of Thickness Range Qualified ~ ~~ P No. gr + j to P No. i@meter Rss3ge Qualified dU Describe Filler Metal Fgler Metal Group Weld Metal Analysh WFg MI/ WELDING PROCEDU E Single Pass 0 Single Arc $ ?f Position of Groove lf 3G,SG,6G Upward $ k Multiple Pass$ K Multiple Arc 0 1GO 2GO 3G+ 4GC3 6GO EGO Downward 0 &c"+> 8Q ~ /gg Postweld Hea~atment Temp. Postweld H~reatment Time ATMOSPHERE Shia g Gas Composi Trade Name Torch Gas Flow Rate INFORMATION ONLY 'OR l8-25 N4 Joint Dimensggns per Welding Characteristics~~ Current/Polarity ~~+ ~Amps ~ ~~ Volts+/ Inches per Minute W" Forehand Backhand IC3 4a w TEST RESULTS REDUCED SECTION TENSILE TEST Dimensions Ultimate Ultimate Unit Specimen No. Area Total Character of Failure and I.ocation Width Thickness Load (lbs.) Stress (PS I) GUIDED BEND TESTS Type and Figure No. Result Type and Figure No. Result Test Conducted By Laboratory-Test No. RADIOGRAPHY TEST Test Conducted By Laboratory-Test No. Welder's Nane . ~lp Who by virtu>> of these tests meets welder performance requirements. We certify that the statements in this record ere correct and that the test welds were prepared, we)dcd cnd tested In acoordwaa svhh the .~ ~ settu)rements of Section IX of the ASME Code, r L t ".-.'.,:i:.i?j~Rj,"'R'.",:,", -', .'.,'. '"",":,"..'.",.;, . -" r '.l'-,""R i". ';i"'qj@,,:,"(li+~'/'j'i>:.;.'"GllfLsr"RI',c:f'rr.rstfr+fgj~+'"':j', r r r I RVi.R'g'- ~ r t ov e GENERAL O ELECTRIC ORIGIItIAL COPY O'HEN ~p rre '7HS IMPRINT lN RED SPECIAL PROCESS CONTROL SHEET projectWee~ec.prreGQ/d Project No. SPCS Page NO.~AS'6- / of / / Rev. ~ DemriPtion: ~~ ~ ~~retied ~M~i ~~wEcer ~y~T-References~~+ A~m&r~ ~ A ~~-M ~~A~ ~~, Oc d~< &,~oA Wd~ 4 Sr@~ Jr ZM C.E. gals. ~ C9S~u~ ~~9.~mace ep~gz io OD 5 I/ I '9 ghiGWAL.~ VrHEN ~Q IMPR!NT iN RED '5FEClAL PROCESS CONTROL SHEET Project SPCS NO~~" 'Z Rev. ~ Project No. Poge / of / D~rinrion:

~~References:~~
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procedture No. >VTE-R Rev. n Component Inspected/Location: Steam Dryer, VT-I Yisual Aids- Westinghouse ETV-1250 Underwater TV camera.
DEFICIENCIES NO N/A WELD FAILUIKS MELD CRACKS SEE 3 .
BROKEN PARTS LOOSE PARTS MISSING PARTS WORN PARTS SIGNS 0% }GVEMENT SURFACE CRACKS SE~ PTi Ao//-.JOEL Y i llA'OR i9.SÃbc I TC' I SURFACE PITTING TPN'lP Lt. Drj SEPVE QO A/7 I HIS
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i 3 i"pC'&S Examiners/Level:
Date Date Review Ec Accepted by: /
Date Yerified by: /
ASME ANII Date Form No.-NVTE-R-3
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Sb'S JUANA)flYA Q~/7 S7 EAf4 SR YE R
SvsguzHAAWA uwr red J S 7'7 DRYER
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0 t4. LL-SUSQUEHANNA h'INTER, 1985 OUTAGE NO. 1 'NIT VIDEO FILM CAT. NO.:
'STEAM DRYER .
REACXRF CXNPONBHT Inspect the Steam Dyer . VT-l, 1007. C x/=%7 Note that there are previously dis-covered indication and that repairs have been made. Refer to SES hork Authorization Package No. T33085.
20 Jan 84.
PREVIOUS INDICATIONS ON 'h~A-T33085 Location 813 225 lifting lu ." All 4 stabilizing straps removed. View removal areas.
Location Pi7 Vertical weld.
Unresolved indications in center area.
Location 85 Vertical weld.
Linear indication on 1/4" plate 1/2" up from hor'zontal weld.
Location f/8 Vertical weld.
Linear indication above the hori-zontal weld 1/8" plate 1" over from
.the vertital weld.
Page 4 of 6 Form No. -NVXE~R-1
~~
l Location 81 Verticpl weld Linear indication 60" in. length.
I MfL LD dg Welding repairs were performed. 45 hIz 8 r Sine.
. 7i C/CPtEPJ NORtfAL INSPECTION Gcs 7 ffA /9 Lifting lug assembly, including attachment welds=and surfaces 0
45 lifting lug welds and surfaces 35 lifting lug - welds and surfaces 25 lifting lug - welds and surfaces 0
15 lifting lug welds and surfaces 70 Hanway r
Vane Bank 81 Weeds and surfaces Vane Bank 82 Welds and surfaces Vane Bank P3 Welds and surfaces Vane Bank 84 --Welds and surfaces gcL PRCc g o~
RY7 .H. /PJD /
Vane Bank $/5 Welds and surfaces Vane Bank. 86 Welds and surfaces gee f'rate~- I oF'i x 9 Page 5 of 6 Form No. -NViK-R-I
L p REAC1UR OOM%NEMTS INSERVICE INSPECTION LIST REACIOR COhPOi&RZ ZNS OP'NaIC Upper suppor t ring - Note that there PipGa's v 3 may be 3 linear indications at 320 or ~n)sere.
Dr er Skirt welds and surfaces Lower Su ort Rin Upper Tie Bars Attachment welds.
4 Support Lug 94 Support Lug 184 Support Lug 274 Support Lug Comments Below InJ P7 v J/$ 7 ~ o b. "i5 I - I 3 A v'e ea f', ~ 8
.S'xaminers/Level: Tsge~of~
Date:~S Reviewed E: Accepted by:
Date Verified by: I AShK ANII Date Form-No.-NVTF~R-2
CTS POWER SERVICES, INC.
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pcoiect: PV'n ~
pro',ect p Procedure 0 $g 0 E. 0 Description of item: o RRCK~J ~
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Examination Results:
lte7 identification e.g. ~e a i denii f l cat ietta'ltc:t(
on component base n:aterial, part k) Accept Reiect Re. arks R Ek Su 7 5/ c$ Tydrf/s Sketch Atta hed: Contponent Temperature yes no be'.ween 6Q - 125'F Exan;incr: ~
I Level:
~l 2Z: Date: +'-D-S5 Reveii'ed by Pi Sb Level:~~& Accept ~Reject
I I~ 7 C " r H
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1/

ML18040B104

Contents

Text

Dear Mr. Butler:

SUMMARY

3.1.2 Indications

3.1.3 Material

3.3.2 Indications

3.3.3 Material

3.4.2 Indications

3.4.3 Material

3.5.2 Indications

3.5.3 Material

3.6.2 Material

3.7.2 Cause

3.7.3 Evaluation

References:

Navigation menu

ML18040B104

Text

Dear Mr. Butler:

SUMMARY

3.1.2 Indications

3.1.3 Material

3.3.2 Indications

3.3.3 Material

3.4.2 Indications

3.4.3 Material

3.5.2 Indications

3.5.3 Material

3.6.2 Material

3.7.2 Cause

3.7.3 Evaluation

References:

Navigation menu

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