ML17229A674
| ML17229A674 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 03/30/1998 |
| From: | Stall J FLORIDA POWER & LIGHT CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| GL-97-06, GL-97-6, L-98-81, NUDOCS 9804070424 | |
| Download: ML17229A674 (22) | |
Text
CATEGORY 1 REGULA A
INFORMATION DISTRIBUTION SYSTEM (RIDS)
ACCESSION NBR:9804070424 DOC.DATE:.98/03/30 NOTARIZED: YES FACIL:50-335 St. Lucie Plant, Unit 1, Florida Power S Light Co.
50-389 St. Lucie Plant, Unit 2, Florida Power 5 Light Co.
AUTH".BAMh
'UTHOR AFFILIATION STALL,J.A.
Florida Power E Light Co.
RECIP.NAME RECIPIENT AFFILIATION Document Control Branch (Document Control Desk)
DOCKET 05000335 05000389
SUBJECT:
Forwards response to GL 97-06, "Degradation of SG Internals" for Units 1
& 2.
DISTRIBUTION CODE:
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TITLE: OR Submittal: General Distribution NOTES:
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E NOTE TO ALL "RIDS" RECZPZENTS:
PLEASE HELP US TO REDUCE WASTE. TO HAVE YOUR NAME OR ORGANIZATION REMOVED FROM DISTRIBUTION LISTS OR REDUCE THE NUMBER OF COPIES RECEIVED BY YOU OR YOUR ORGANIZATION, CONTACT THE DOCUMENT CONTROL DESK tDCD)
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MAR 30 1998 L-98-81 10 CFR 50.4 10 CFR 50. 54 (f)
U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555 RE:
St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 The Florida Power and Light Company (FPL) response to Generic Letter (GL) 97-06, Degradation ofSteam Generator Internals, for St. Lucie Units 1 and 2 is attached.
The GL has four purposes.
The first is to reemphasize previously communicated findings of damage to steam generator (SG) internals, namely, tube support plates and tube bundle wrappers, at foreign PWR facilities. The second is to alert addressees to recent findings of damage to steam generator tube support plates at a U.S. PWR facility. The third is to emphasize to addressees the importance of performing comprehensive examinations of steam generator internals to ensure steam generator tube structural integrity is maintained according to the requirements ofAppendix B to 10 CFR Part 50.
The last is to require all addressees to submit information that willenable the NRC staff to verify whether addressees'team generator internals comply with and conform to the current licensing basis for their respective facilities.
FPL used information &omthe Nuclear Energy Institute (NEI), the Electric Power Research Institute (EPRI), and the Combustion Engineering Owners Group (CEOG) to prepare the responses for St.
Lucie Unit 2 and for the St. Lucie Unit 1 original SGs.
The St. Lucie Unit 1 original SGs were replaced in December 1997 with Babcox and Wilcox International (BWI) units that are the same form, gt, and function as the originai units. Domestic operating experience of BWIrepiacement SGs is limited to three cycles, and no degradation of secondary side internals has been reported.
BWI replacement SGs have advanced materials including thermally treated Alloy690 tubing and stainless steel lattice type (eggcrate) tube supports that are less susceptible to degradation.
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As discussed in the attached, the St. Lucie response relies on information in CEOG reports CE NPSD-1103 and CE NPSD-1104 which are currently in final draft. The reports are expected to be completed and submitted to the NRC by NEI by June 1998. When these reports are finalized and submitted, FPL willconfirm in writing that their applicability and the conclusions do not impact the attached response.
The attached information is provided pursuant to the requirements of Section 182a of the Atomic Energy Actof 1954, as amended, and 10 CFR 50.54(f).
Please contact us ifyou have any questions about this submittal.
Very truly yours, J. A. Stall Vice President St. Lucie Plant JAS/GRM Attachment cc:
Regional Administrator, Region II,USNRC Senior Resident Inspector, USNRC, St. Lucie Plant
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STATE OF FLORIDA COUNTY OF MIAMI-DADE ss.
J. A. Stall being first duly sworn, deposes and says:
That he is Vice President, St. Lucie Plant, for the Nuclear Division of Florida Power 8c Light Company, the Licensee herein; That he has executed the foregoing document; that the statements made in this document are true and correct to the best ofhis knowledge, information and belief, and that he is authorized to execute the document on behalf of said Licensee.
J. A. Stall STATE OF FLORIDA COUNTYOF Sworn to and subscribed before me this~ dsy of
, 19~8 by J. A. Stall, who is personally known to me.
Name ofNotary blic - State ofFlorida OLGA HANEK ff
~sb, MYCOMMISSICM8 00562742
@i EXPIRES: Jtfllo 18, 2000
">,d:" BtwdttflllnfNotay Pubic UfKIteNrlittf3 (Print, type or stamp Commissioned Name ofNotary Public)
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St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 L-98-81 Attachment Page
1 Background
This response provides the results of evaluations and inspections, and identifies programs and plans for monitoring ofpotential degradation of steam generator (SG) secondary side internal components that may pose a risk to the structural integrity of the SG tubing.
In response to the proposed GL on degradation of SG internals, the Nuclear Energy Institute (NEI) formed the SG Internals Task Force in January 1997. The purpose of the task force was to develop a coordinated industry-wide response to the proposed GL. Participation on the task force included the Electric Power Research Institute (EPRI), licensees, and representatives of the owners groups for each domestic SG design.
Each owners group initiated programs to help their respective owners in assessing the susceptibility of tube damage or loss of decay heat removal capability due to secondary side degradation.
An integral component in this assessment was an understanding of the applicability of the degradation found in the French units to domestic SGs.
EPRI, with the cooperation of Electricite de France (EdF), developed the report, GC-109558, Steam Generator Internals Degradation:
Modes of Degradation Detected in EdF Units. The EPRI report provides evaluations of the causal factors involved in the modes ofdegradation experienced in the French units. The owners groups used this report to gain insights into the applicability of the French experience to their SG designs and operating history. This report was transmitted to the NRC via an NEI letter, dated December 19, 1997.
In developing the susceptibility assessment, other attributes considered were design factors, fabrication and manufacturing techniques, and plant operating history, including chemistry and related degradation, such as denting. Additionally, the owners groups compiled and assessed information on their respective visual, video, and pertinent nondestructive examination (NDE) inspection experience to enhance their evaluations regarding the susceptibility to internals degradation. This inspection experience is summarized in the table provided in this response.
Furthermore, the NEI task force met with the NRC in May 1997 to gain a better understanding of the safety concerns discussed in the generic letter. From these efforts, the owners groups developed preliminary safety and susceptibility assessments on the design and operating history of their fieet.
These assessments provide reasonable assurance that SG tube integrity and decay heat removal capability are not compromised by internals degradation. It is the intention of the NEI SG Task Force to provide the respective owners groups reports via NEI for NRC information. Confirmation and a
. schedule forproviding the reports willbe provided by NEI. The industry, through the focused efforts ofthe NEI task force, provided the guidance and information necessary for licensees to address the potential issues regarding SG internals degradation.
St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 L-98-81 Attachment Page 2 Complete NRC Information Request:
Within 90 days of the date of this generic letter, each addressee is required to provide a written report that includes the followinginformation for its facility:
(1)
Discussion ofany program in place to detect degradation of steam generator internals and a description of the inspection plans, including the inspection scope, frequency, methods, and equipment.
The discussion should include the followinginformation:
(a)
Whether inspection records at the facilityhave been reviewed for indications oftube support plate signal anomalies Rom eddy-current testing (ECT) of the steam generator tubes that may suggest support plate damage or ligament cracking. Ifthe addressee has performed such a review, include a discussion of the findings.
(b)
Whether visual or video camera inspections on the secondary side of the steam generators have been performed at the facility to gain information on the condition of steam generator internals (e.g., support plates, tube bundle wrappers, or other components).
If the addressee has performed such inspections, include a discussion of the findings.
(c)
Whether degradation of steam generator internals has been detected at the facilityand how the degradation was assessed and dispositioned.
(2)
Ifthe addressee currently has no program in place to detect degradation of steam generator internals, include a discussion and justification of the plans and schedule for establishing such a program, or why no program is needed.
NRC Request 1:
Discussion ofany program in place to detect degradation ofsteam generator internals and a description ofthe inspection plans, including the inspection scope, frequency, methods, and equipment.
FPL Response 1:
This response initiallydiscusses the St. Lucie Unit 1 original SGs and the Unit 2 SGs. Information for the Unit 1 original SGs is provided for industry experience value only, since these SGs have been
St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 L-98-81 Attachment Page 3 replaced.
The Babcox &Wilcox International (BWI)replacement SGs at St. Lucie Unit 1 willbe discussed later in this response.
The St. Lucie Plant has participated in industry and Combustion Engineering Owners Group (CEOG) activities to evaluate the potential for degradation ofSG internals experienced in EdF and domestic designed units for St. Lucie Unit 1 original SGs and the Unit 2 SGs.
The CEOG, through its SG Task Force (SGTF), reviews SG inspections, evaluations, and issues in regularly scheduled meetings.
Combustion Engineering (CE) designed SGs can be divided into three different groups based on tube support design.
Group 1.
Group 2.
Group 3.
Units with carbon steel eggcrates and drilled plates at upper elevations Units with carbon steel eggcrates only Units with stainless steel eggcrates only The original SGs at St. Lucie Unit 1 are in Group 1, and the existing SGs at St. Lucie Unit 2 are in Group 2.
The CEOG program includes development of three reports. The objectives and conclusions of the reports are summarized below. Upon completion or revision, these reports willbe provided to the NRC under NEI cover letter to give the staff additional details.
SG internals inspections encompassing the three different CE SG tube support designs identified above have been conducted.
A summary table of the inspections is provided as part of this response.
The EdF SG internals degradation experience was evaluated in CEOG Report, CE NPSD-1092, Rev.
0, Evaluation of Degraded Secondary Internals
This evaluation concludes that the specific causal factors identified by EdF were not applicable to the CE designs. CE NPSD-1092 includes a broader evaluation of CE SG internals degradation based on review of experience, and reviews the potential degradation mechanisms based on design, manufacturing, and operational practice.
CE NPSD-1092 objectives and conclusions, which are applicable to the St.
Lucie Plant, are summarized below.
Assess the applicability ofEdF damage mechanisms to the CE design.
Assess the applicability of tube support erosion/corrosion experience at Maine Yankee and San Onofre Nuclear Generating Station Unit 3 (SONGS 3) to other CE designed units. Assess the impact ofapplicable mechanisms on tube integrity and decay heat removal capability.
CEOG Report, CE NPSD-1092, Rev. 0, Evaluation of Degraded Secondary Internals - Operability Assessment
St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 L-98-81 Attachment Page 4 The primary damage mechanisms related to the wrapper support failures in the French units are not directly applicable to the CE designed SGs.
2.
Support plate cracking is a residual effect oftube denting, but is not detrimental to the safe operation of the SG.
Adequate margins against failure have been shown for the flow-accelerated-corrosion (FAC) damage observed in the SONGS 3 eggcrates.
4.
There are no reported tube wear indications directly related to tube support degradation.
Plants with degradation of tube supports, such as that observed at SONGS 3, can continue to operate safely because adequate margins against failure exist and possible tube damage can be detected in routine ECT examinations.
6.
Corrosion degradation, as manifested by denting, such as detected in the lower eggcrates of the Millstone Point 2 (MP2) original SGs, has been determined to be acceptable by model boiler testing and analysis.
Current chemistry practices can mitigate existing denting and preclude further degradation due to this phenomenon.
7.
None ofthe degradation mechanisms reviewed posed a threat to the reactor coolant system (RCS) pressure boundary integrity or the heat removal function of the SG.
The CEOG/NEI industry program also addressed susceptibility of CE designed units to the types of degradation mechanisms identified based on review ofexperience with the CE designed units. CEOG Report, CE NPSD-1103, Evaluation ofSusceptibility ofInternals Degradation in CE Designed Steam Generators, which is scheduled for completion in May 1998, concludes that FAC is the only credible damage mechanism to the internals ofCE designed SGs which could potentially compromise SG tube integrity. The objectives and conclusions of CE NPSD-1103, which are applicable to the St. Lucie Plant, are reviewed below.
- Report, CE NPSD-1103, Evaluation of Susceptibility of Internals Degradation in CE Designed Steam Generators, (Draft - February 1998)
St. Lucie Units 1 and 2 I0ocket Nos. 50-335 and 50-389 L-98-81 Attachment Page 5 Review the history ofSG internals degradation in CE designed units and examine their susceptibility to internals degradation mechanisms that have occurred in CE and EdF designed SGs.
1.
CE designed SGs have not encountered a significant amount of internals degradation.
Ofthe degradation that has occurred, appropriate mitigating action has been taken to reduce the effect ofthis degradation.
2.
The most common forms of SG internals degradation have been from waterhammer events or erosion of components within the feedwater system.
However, these degradation mechanisms are not considered safety significant.
3.
The SG internals degradation mechanisms described in GL 97-06 are generally not applicable to CE designed SGs. The only degradation mechanism applicable to the CE fleet that could have safety significance is FAC of peripheral eggcrates.
4.
FAC of peripheral eggcrates is primarily the result of secondary fluid flow redistribution caused by severe tube bundle fouling. Use of alternate amines in heavily fouled SGs is expected to decrease the susceptibility to FAC.
5.
Of the CE designed SGs with carbon steel tube supports, only those units with severe tube bundle fouling, as indicated by significant SG secondary pressure loss, may be susceptible to FAC ofperipheral eggcrates.
6.
No CEOG member plants have detected, by NDE or visual inspections, any FAC ofdrilled tube support plates.
A bounding analysis ofapplicable degradation mechanisms is being completed to provide reasonable assurance that SG tube integrity and decay heat removal capability are not compromised by internals degradation.
CEOG Report, CE NPSD-1104, Evaluation of Degraded Secondary Internals-Bounding Analysis', which is scheduled for completion in May 1998, willprovide this assessment.
The objectives and preliminary conclusions, which are applicable to the St. Lucie Plant, are discussed below.
CEOG Report, CE NPSD-1104, Evaluation ofDegraded Secondary Internals-Bounding Analysis, (Draft - February 1998)
St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 L-98-81 Attachment Page 6 Assess the impact ofdegradation issues applicable to CE designed SGs and determine the bounding cases for degradation issues affecting safety.
Report CE NPSD-1104 is not yet completed.
Preliminary conclusions are provided below, but will not be final until the end ofMay 1998.
1.
No CE designed plants are at risk for loss of tube integrity or decay heat removal function because of SG secondary side internals degradation, including FAC degradation for the limitingcase.
2.
For plants with carbon steel eggcrates only (i.e., St. Lucie Unit 2), CE NPSD-1104 provides assurance that the only credible SG internals components damage mechanism of potential safety significance is FAC of eggcrate type tube supports. A potential susceptibility to FAC has been identified for CE designed plants with carbon steel eggcrate supports with heavily fouled tube bundles.
For plants with carbon steel eggcrates and carbon steel drilled tube supports at upper elevations (i.e., St. Lucie Unit 1 original SGs), CE NPSD-1104 provides assurance that the only credible SG internals components damage mechanism ofpotential safety significance is FAC ofeggcrate type tube supports. Apotential susceptibility to FAC has been identified for CE designed plants with carbon steel tube supports with heavily fouled tube bundles.
Some
,EdF units have experienced tube support plate degradation due to FAC. Drilled support plates were present in the St. Lucie Unit 1 original SGs at the uppermost support elevations.
Evaluation of the degradation and inspection experience in CE designed plants for drilled support plates found no reports of missing plates, plate ligaments, or progressive cracking (CEOG Report CE NPSD-1092).
The St. Lucie Unit 1 SGs were replaced in December 1997.
FAC of eggcrates,has been detected in one CE designed unit as reported in,GL 97-06.
Usually, FAC is possible in units with carbon steel supports iftube bundle fouling causes redistribution of flow such that FAC threshold velocities are exceeded.
The CEOG evaluations suggest that FAC, without substantial fouling, is unlikely. Experience has shown that the onset ofsubstantial fouling is evidenced by a reduction in the normal plant operating steam pressure.
Experience has also shown that plants can experience steam pressure reduction and not experience the onset of FAC in the tube supports.
CE NPSD-1103 recommends that, ifa substantial reduction in steam pressure is experienced, remote visual
St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 L-98-81 Attachment Page 7 inspection of the uppermost eggcrates be conducted at the next scheduled refueling outage to detect whether FAC has occurred. FAC occurs preferentially toward the periphery of the hot leg side of the tube bundle at the upper supports.
It should be noted that the St. Lucie Unit 2 SGs are not severely fouled, and no loss of steam pressure has been experienced.
The BWIreplacement SGs installed in St. Lucie Unit 1 in December 1997 have advanced materials and design, including stainless steel tube supports and Alloy690 tubing. These materials and designs make BWI replacement SGs much less susceptible to the types of secondary side internals degradation discussed in GL 97-06.
Domestic operating experience of BWI replacement SGs is limited to three cycles at other sites. No degradation of secondary side internals has been reported.
Recent discussion with BWIrepresentatives suggest that from their assessment ofBWI SG designs for susceptibility to the types ofinternals degradation discussed in GL 97-06, there are no issues for the St. Lucie Unit 1 replacement SGs.
The St. Lucie Plant plans to followindustry developments with BWIreplacement SGs and conduct inspections, as appropriate, to provide reasonable assurance that SG tube integrity and decay heat removal capability is not compromised by internals degradation.
The St. Lucie Plant program has typically included routine secondary side inspections at each refueling outage since 1984.
The scope of these inspections has included steam separation and feedring equipment, and foreign object search and retrieval (FOSAR) followingsludge lancing of the tubesheet.
Methods and equipment include direct visual and remote video using Welch Allynprobes and video cameras mounted on inspection carts and telescoping devices.
NRC Request 1 (a):
8'hetherinspection records at thefacilityhave been reviewed forindications oftube support plate signal anomalies from ECT ofthe steam generator tubes that may be indicative of support plate damage or ligament cracking. Ifthe addressee has performed such a revie~,
include a discussion ofthe findings.
FPL Response I (a):
Aqualified ECT technique for detection ofligament cracking does not exist for eggcrate design tube supports in the St. Lucie Unit 1 and 2 SGs.
Further, ligament cracking has not been reported in eggcrate design tube supports.
For the St. Lucie Unit 1 original SGs, the upper most drilled tube supports were staked and cut Bee of their attachment lugs in 1979 to alleviate stress build up due to denting. Inspections at that time, and later in 1985, did not detect any ligament cracking. Based on ECT data, denting levels remained dormant after that.
St. Lucie Unit 1 original SGs were replaced in December 1997.
St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 L-98-81 Attachment Page 8 ECT has included 100% ofactive tubes since 1986 at St. Lucie Units 1 and 2. Since tube degradation typically initiates at tube support plates, they are included in the review of inspection data.
The absence of a tube support plate signal in the expected location would be evident during review of ECT data. No missing tube supports have been reported at St. Lucie Units 1 and 2 or in other CE SGs.
Any identified abnormal or distorted support plate signals are expected to be reported for further evaluation by lead analysis personnel.
These evaluations have included historical data reviews and rotary probe inspections.
No degradation ofthe tube support plates has been confirmed by these evaluations.
NRC Request 1 (b):
WhetJier visual or video camera inspections on the secondary side ofthe steam generators have been performed at thefacilityto gain information on the condition ofsteam generator internals (e.g., support plates, tube bundle wrappers, or other components). Ifthe addressee has performed such inspections, include a discussion ofthe findings.
FPL Response to Item 1 (b):
No degradation of the tube bundle supports or bundle wrapper has been detected in the St. Lucie Plant SGs.
At St. Lucie Units 1 and 2, visual inspections of the tubesheet regions have typically been completed following sludge lancing at each refueling outage since 1984.
These inspections are completed through openings in the shell. The bottom of the bundle wrapper is immediately above the shell openings, and any downward movement of the wrapper would be evident. No such movement has been noted. During these inspections, small objects (e.g., wire segments or small screws), which are not indicative ofinternals degradation, have been detected and removed.
Tubes near the objects are inspected by ECT and removed &omservice ifdefective. When such objects cannot be removed after reasonable effort, they are evaluated for potential effects on tube integrity during subsequent operation. Ifit can be determined that tube damage which may exceed the allowable limits of the technical specifications willnot occur, the object may be left in place, and the tubes checked at subsequent inspections to assess their condition.
At St. Lucie, inspections ofthe steam separation and feedring equipment have been conducted since October 1978. A summary ofthe inspection dates is provided below for each unit. Inspection results that are relevant to degradation of internals components are discussed in the response to item 1 (c) below.
St. Lucie Units 1 and 2 I3ocket Nos. 50-335 and 50-389 L-98-81 Attachment Page 9 October 1978 June 1979 November 1985 November 1991 April1993 November 1994 October 1984 April 1986 October 1987 February 1989 October 1990 May 1992 February 1994 October 1995 For the St. Lucie Unit 1 original SGs, the uppermost drilled tube supports were staked and cut free of their attachment lugs in 1979 to alleviate stress build up due to denting. Inspections conducted in 1978, and later in 1985, did not detect any ligament cracking. Based on ECT data, denting levels remained dormant after that. The St. Lucie Unit 1 original SGs were replaced in December 1997.
At St. Lucie Unit 2 in October 1990, ultra-sound testing (UT) thickness measurements were completed for the feedring, distribution box, and feedwater nozzle thermal liner. The UT thickness measurements were repeated in October 1995. No evidence of erosion/corrosion was noted in either of these inspections.
AtSt. Lucie Unit 2 in October 1995, remote video inspections were completed for the upper three eggcrate tube'supports to assess fouling. While the extent of the periphery examined was limited, fouling was not severe and no degradation of the tube supports was evident. Also, in 1995 a sample offeedring j-nozzle boreholes was inspected using Welch Allyncameras.
No evidence of degradation was noted.
NRC Request 1 (c):
Whether degradation ofsteam generator internals has been detected at the facility, and how the degradation was assessed and dispositioned.
St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 L-98-81 Attachment Page 10 FPL Response to Item 1 (c):
A broken gusset weld was reported in a feedwater pipe support assembly above the distribution box in the St. Lucie Unit 1 original SGs in November 1994, and in the existing SGs at Unit 2 in February 1994. This condition was evaluated by the original equipment manufacturer, who concluded that the gusset/weld failure was due to secondary stresses (thermal fatigue). The evaluation was completed assuming that the failed gusset weld was not present in the feedwater pipe support, and it was concluded that the condition was acceptable for the lifeof the vessel. FPL continues to monitor this condition for further change during secondary side inspections.
No change has been noted in subsequentinspections.
In November 1985 at St. Lucie Unit 1, the steam deflector plates in each SG were found to be loose and missing some attachment bolting. Afterretrieval ofloose parts, the deflector plates were restored to their original configuration using replacement hardware supplied by the manufacturer.
During sludge lancing of the 1B SG, three nuts and a bolt head were removed from the blowdown lane. It was determined that the material was from the feedring restraint bolting, and that the ring had, most likely, experienced a slight waterhammer during the previous cycle. An inspection of the feedring confirmed that the bolting material was Rom the feedring, and showed that the remaining attachment bolting was intact and no other damage was evident. The feedwater restraint bolting was replaced using hardware supplied by the manufacturer.
ECT was conducted for 100% of active tubes during this inspection, and a total of 19 tubes were plugged in SG 1B. None of the tubes plugged appear to be a result of damage from the objects removed from the SG.
In 1991 at St. Lucie Unit 1, inspections of SG 1B revealed that feedwater pipe support u-bolts were broken due to a waterhammer event. Allloose parts were found on the wrapper attachment lugs and retrieved.
None of the parts migrated to the tubesheet region and, therefore, there was no tube damage. The supports were upgraded to the St. Lucie Unit 2 restraint design (double u-bolt rather than single). No degradation of the wrapper supports was evident. The Unit 1 SGs were replaced in December 1997.
In October 1984 at St. Lucie Unit 2, the steam deflector plates were found securely attached, but several locking tabs and one bolt were apparently not installed during manufacturing.
No loose parts were found. The condition was corrected by site personnel.
Shroud plugs were also found loose, two were missing in SG 2B and one was missing in SG 2A. One missing plug was retrieved from the SG 2B blowdown lane, but the others could not be found. The shroud plugs were tightened and the missing plugs were replaced.
ECT was conducted for 10% of the active tubing during this outage.
No tubes were found defective.
In April 1986 at St. Lucie Unit 2, a shroud plug and a spacer for a feedring u-bolt were retrieved from the blowdown lane of SG 2B during sludge lancing. It was concluded that the plug was one that
St. Lucie Units 1 and 2 Socket Nos. 50-335 and 50-389 L-98-81 Attachment Page 11 could not be found during the October 1984 inspection. The spacer was also, apparently, a result of the same waterhammer event. ECT was conducted for 100% of active tubes in this outage. Twelve tubes were plugged in SG 2B, none ofwhich are a result of damage from the objects removed from the SG.
In October 1987 at St. Lucie Unit 2, a minor defect was reported in SG 2A in a seal plate located between the pressure boundary and the dryer support deck. The seal plate is not a structural member, but merely seals a small gap to prevent the steam mixture from bypassing the dryer system.
The defect was sealed by weld repair. Inspection during the subsequent outage showed that the repair was in good condition.
In February 1989 at St. Lucie Unit 2, one u-bolt had failed in SG 2B, apparently, due to a waterhammer event, The Unit 2 design consists of a double u-bolt at each restraint location. All loose parts, except a small spacer, were retrieved fiomthe tubesheet.
The spacer could not be found, and a justification for continued operation was completed.
Inspection of the remaining restraints did not identify additional degradation.
The feedring restraint was restored to the original condition.
ECT was conducted for 100% ofactive tubes in this outage. Fifty-fivetubes were plugged in SG 2B, none ofwhich was a result of damage from the objects removed from the SG.
Unanticipated transient events, such as waterhammers, are evaluated according to site engineering standards to determine the effects of the event on piping systems and associated components.
NRC Request 2:
Ifthe addressee currently has no program inplace to detect degradation ofsteam generator internals, include a discussion andjustification ofthe plans and schedule for establishing such a program or why no program is needed.
FPL Response to Item 2:
Item 2 is not applicable to the St. Lucie Plant. As discussed above, St. Lucie has conducted routine inspections ofSG internals since 1984, and plans to followthe industry program to provide reasonable assurance that SG tube integrity and decay heat removal capability are not compromised by internals degradation.
Inservice Inspection Plans Based on current CEOG recommendations and inspection experience at St. Lucie and similar units, inservice inspection plans for secondary side internals components are discussed below. Inspection
St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 L-98-81 Attachment Page 12 scope and frequency may be adjusted as necessary based on a site specific experience and evaluation of the results from other industry inspections.
No change in the St. Lucie Plant program is considered necessary for inspections of tube supports to assess their condition for ligament erosion/corrosion and cracking. No ligament cracking has been reported for eggcrate design tube supports.
The extent of bundle fouling is not severe at St. Lucie Unit 2, and no steam pressure loss has been noted.
Sample inspections for the upper three eggcrates in 1995 were conducted and no degradation was noted.
Therefore, ligament cracking and erosion/corrosion of the tube supports are considered a low probability events at St. Lucie Unit 2.
St. Lucie Unit 1 replacement SGs were installed in December 1997. No degradation of SG internals has been reported for BWIreplacement SG designs.
No issues were identified for St. Lucie Unit 1 by BWI from their review of GL 97-06 with respect to the types of degradation discussed.
ECT for ligament cracking is not applicable for the eggcrate design.
However, distorted tube support signals willcontinue to be reported for further evaluation during routine ECT. Future inspections of the tube support plates willbe based on a site specific inspection experience and the industry program recommendations.
No change in the St. Lucie Plant program is considered necessary for inspections to assess the condition ofthe tube bundle wrapper. Awrapper drop or cracking has not been reported in any SG designed by CE or BWI, and is a low susceptibility event because of design differences.
Proper alignment of the wrapper is necessary for insertion of sludge lancing equipment.
Sludge lancing at the St. Lucie Plant is typically conducted at each refueling outage.
Routine ECT are expected to detect potential tube deformation resulting from wrapper misalignment. Ifinterference with the sludge lance equipment or deformation of periphery tubes is detected, the lower wrapper support blocks willbe visually inspected.
No change in the current St. Lucie Plant program is considered necessary.
FPL plans to inspect according to ASME Section XIInservice Inspection Program requirements for the SG shell.
St. Lucie Units 1 and 2 Bocket Nos. 50-335 and 50-389 L-98-81 Attachment Page 13 No change in the current St. Lucie Plant program is considered necessary.
FPL plans to inspect according to ASME Section XIInservice Inspection Program requirements.
Loose parts monitoring is expected to help detect potential degradation of the feed water nozzle.
No change in the current St. Lucie Plant program is considered necessary for inspection of steam separation and feedring equipment. Inspections of steam separation and feedring equipment have typically been conducted in one or more SGs at each outage since 1978.
CEOG member utilities have compiled and assessed information on their respective visual, video, and pertinent nondestructive examination (NDE) inspection experience to enhance their evaluations regarding the susceptibility to internals degradation.
This inspection experience is summarized in the table on the followingpage and willbe considered in future inspections conducted under the St. Lucie Plant program. Inspection experience for SGs that have been replaced is not reflected in the table (i.e., St. Lucie Unit 1, MP2, and Palisades).
CONCLUSIONS This evaluation provides the information requested by the NRC for the 90-day response to GL 97-06.
Industry experience has been reviewed for SG internals degradation and it is concluded that, for the St. Lucie Plant, there is a low susceptibility to the types of degradation discussed in the generic letter. Routine secondary side internals inspections have typically been conducted at St. Lucie since 1984 for the tubesheet region, and steam separation and feedring equipment.
Recent inspections of the upper supports have also been completed at St. Lucie Unit 2.
These inspections show that the types of secondary side internals degradations that could potentially threaten SG tube integrity or decay heat removal capability are not present in the St. Lucie Plant SGs.
Further, the St. Lucie Unit 1 SGs were replaced with BWIreplacement SGs in December 1997. There has not been any degradation ofBWIreplacement SGs reported.
Discussion with BWIrepresentatives show that there are no issues for St. Lucie Unit 1 replacement SGs from their review ofGL 97-06.
It is expected that potential internals degradation would be limited in extent such that the tubes can sustain the conditions of normal operation, including operational transients, design basis accidents, external events, and natural phenomena, permitting the affected SG to perform its intended safety function.
St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 L-98-81 Attachment Page 14 Frequent inspections have been conducted at St. Lucie to assess the condition of SG internals.
The St. Lucie Plant program, and the assessments reviewed as part of this evaluation provide reasonable assurance that SG tube integrity and decay heat removal capability are not compromised by internals degradation, and that steam generator internals comply with and conform to the current licensing basis.
St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 L-98-81 Attachment Page 15 Table CEOG Member Plants SG Internals Inspection Data UNIT SG MODEL LATESP INSPECTION DATE IiNSPECfIoiNTYPE tnspcescd Ycs/ssio Desrada sion Note 1 UPPER EGGCRATES tnspcescd Ycs/silo Dcsrada non Note 1 LOWER EGGCRATES Inspoescd Y~io Dcsradarion Note 1 TUBESUPPORT PLATES Inspecscd Y~io Desrada sion Note 2 SHROUD SUPPORTS ANO-2 Cci%'-I FCS 67 Earl Ma -96 Fall 96 70w/fSP MAY-97 Wdch All,NDE Welch All Ranote Visual None None NA N
None NA N
Note 3 NA Note 4 N
NA NA None MY Palisades St. Lucie 2 PV2 PV3 SONGS 2 SONGS3 Waterford 3 Earl RSG 67 SYS 80 SYS 80 70 70 70 A r-97 Nov-96 Oa-95 A r-96 Oct-97 Mar-97 Dcc-96 Ma -97 Apr-94 84 Apr-97 Fiber
'c Visual Wdch All Visual Visual Visual Ranote Visual Ranote Visual Ranotc Visual Note 8 N
N YNoes to Yt outs Note 5 None Note 9 NA None None None Y Yeas lt None N
N N
N N
Yzion 14 Note 6 None NA NA NA NA NA NA None NA NA NA NA NA NA NA NA Note 7 NA NA NA NA NA NA NA N
N N
N N
NA NA NA None None None NA NA Note 1:
Note 3:
Note 5:
Note 7:
Note 9:
Note 11:
Note 13:
Note 10 Examples ofdegradation: Cracking, EC Snip'Ihinning, Wear, TSP/Shroud Contact.
Note 2:
TSP outcr Pcriphay cracks.
Highest EC. localized area damage inactive.
Outer periphery rows - aacking.
Minorfouling; no degradation observed.
inning, pitting, wash boarding.
Remote visual Apr-94 ofSGg2hot leg EC 10,5 tubes in from periphay - no degradation.
Examples ofdegradation: Shroud Tearin/cracking, displacement, shroud/supp.separation.
Note 4:
ggTSP outcr periphay: I post rim cut crack found in each SG.
Note 6:
Bottom-side in outer periphery roundcsk Note 8:
nspected upper 3 EC's periphay.
Visual inspeaion ofEC 6-10.
Note 12:
lhinning on EC 4 and 5.
Note 14:
Visual inspection ofEC. 1 supports-no degradation.