ML20058J620
| ML20058J620 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 08/06/1982 |
| From: | Crouse R TOLEDO EDISON CO. |
| To: | Novak T Office of Nuclear Reactor Regulation |
| References | |
| 845, TAC-48349, NUDOCS 8208110131 | |
| Download: ML20058J620 (53) | |
Text
!
o .1 Docket No. 50-346 TOLEDO License No. NPF-3 EDISON Rcsue P Caoua Serial No. 845 V ce Pr ese"t
%hr August 6, 1982 a u m sm Director of Nuclear Reactor Regulation Attention: Mr. Thomas Novak, Assistant Director Division of Operating Reactors United States Nuclear Regulatory Commission Washington, D.C. 20555
Dear Mr. Novak:
This letter is being transmitted to update our July 15, 1982 submittal (Serial No. 839) and provide information requested in your letter dated July 30, 1982 (Log No. 1043).
The current refueling outage for the Davis-Besse Nuclear Power Station Unit No. 1 (DB-1) had been extended due to discovered damage of the auxiliary feedwater headers located in each steam generator. Repair activities are expected to be complete shortly which will allow the unit to return to electric generation service.
This letter also formalizes the information exchanged at our June 24, and July 29, 1982 meetings. The meeting between your staff, Toledo Edison, Duke Power Company, Sacramento Municipal Utility District and Babcock and Wilcox (B&W) discussed the inspection efforts, retiring of the internal headers and addition of external headers which are operating effectively on all older B&W plants. The information contained here is specifically related to Davis-Besse, its conditions, its systems, and its renair.
Included is:
- 1. Attachment A - A descriptive document, giving a summary from a history of the actions taken as well as the plans for future activities related to the repair effort. Modified portions from the previous submittal are indicated by vertical lines in the right margin.
- 2. Attachment B - The current status of the parts recovery program. j 0 D!
- 3. Attachment D 1982 letter C - A No.
cross-reference 1019) to the to the questions of your June 23,I 4.
(Log information in Attachment A.
Attachment D - A cross-reference to the questions of your July 30, j&eD I('
1982 letter (Log No. 1043) to the information in Attachment A.
The repair activity required re-routing of some of the auxiliary feedwater systen piping. Although this altered several pipe support schemes, no active components were added to or deleted from the process THE TOLEDO EDISON COMPANY EDISON PL AZA 300 MADISON AVENUE TOLEDO, OH!O 43652 8208110131 820806 PDR ADOCK 05000346 P PDR
a 1 Docket No. 50-346 License No. NPF-3 Serial No. 845 August 6, 1982 Page 2 system. This re-routing complied with all of the original design i criteria for the safety grade system. No instrumentation, control or l monitoring schemes were altered. As a result of the lack of any l functional change in the system portion of the auxiliary feedwater system i upstream of the new header, very little is discussed in the attachments.
The current schedule identifies the earliest possible transition into Mode 2 operation on August 11, 1982. We will keep you apprised of any schedule change.
Very truly yours, RPC:LDY: lab Attachments A, B & C Enclosures - Drawing No. M203B Rev. 15 Drawing No. 151902E, Rev. 7 cc: DB-1 NRC Resident Inspector NRC Region III Administrative Director
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SUBMITTAL IN RESPONSE FOR DAVIS-BESSE NUCLEAR POWER STATION UNIT NO. !
FACILITY OPERATING LICENSE NO. NPF-3 This letter is submitted in conformance with 10 CFR 50.54(f) in response to Mr. T. M. Novak's letter of June 23, 1982 (Log No. 1019). This deals with Auxiliary Feedwater Header Repair - Request for Additional Information.
By ((
Vice President, Nuclear 7-- _ -
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Sworn to and subscribed before me this 6th day of August, 1982.
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- W Notary Public I
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Docket No. 50-346 License No. NPF-3 Serial No. 845 l August 6, 1982 Attachment A EVALUATION, REPAIR AND REPLACEMENT OF DAMAGED INTERNAL AUXILIARY FEEDWATER HEADER AT DAVIS BESSE 1 (Revision 1) l
, i TABLE OF C0!; TENTS PAGE l 1.0 Introduction 1-1 1.1 Internal AFW Header Design 1-1 1.2 Internal AFW Header Functional Requirements 1-2 1.3 History of the Problem 1-2 2.0 Site Inspections and Results 2-1 2.1 Davis Besse 1 Inspections 2-1 2.2 Rancho Seco Inspections 2-4 2.3 Oconee 3 Inspections 2-5 3.0 Most Logical Cause 3-1 3.1 Mechanisms Examined 3-1 3.2 Most Logical Cause 3-1 4.0 Description of Repair 4-1 4.1 Internal Header Design Requirements 4-1 4.2 Internal Header Repair 4-3 4.3 External Header 4-4 4.3.1 Description 4-4 4.3.2 Functional Design Requirements 4-4 4.3.3 Comparison to Existing Designs 4-4 4.4 Loose Parts 4-5 4.5 Eddy Current Inspection and Tube Plugging 4-6 5.0 Pre-Operational Tests 5-1 6.0 Post-Operational Inspections 6-1 7.0 Safety Assessment and Summary 7-1 l
8.0 References 8-1 l
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, LlST OF FlGURES
. Figure No. Title 1-1 177FA Once Through Steam Generator with Internal AFW Header 1-2 Longitudinal Section of Internal AFW Header at Dowel Pin 1-3 AFW Thermal Sleeve / Internal Header Interf ace 1-4 Plan View of Internal AFW Header 1-5 Location of Internal AFW Header Flow Holes l 2-1 Typical Damage Found During Initial Visual Inspections 4-1 Securing Internal AFW Header 4-2 Arrangement of Replacement External AFW Header - Vertical Cross-section 4-3A Arrangement of Replacement 8 Nozzle External AFW Header - Plan View 4-38 Arrangement of Replacement 6 Nozzle External AFW Header - Plan View 4-4 Arrangement of Existing External AFW Header - Vertical Cross-section I
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1.0 Introduction I There are two configurations of auxiliary feedwater (AFW) header assemblies which are used on the steam generators for Babcock &
Wilcox's 177 Fuel Assembly Plants. The first type uses an external distribution header mounted outside the once through steam generator (OTSG) with nozzles penetrating the shell and shroud. The second type uses an internal distribution header mounted inside the OTSG. Recent inspections showed damage in the internal AFW headers at three plants: Duke Power Co., Oconee 3, Sacramento Municipal Utility District, Rancho Seco, and Toledo Edison Co., Davis Besse 1. Internal AFW header designs also exist at General Public Utilities, Three Mile Ialand (TMI-2), and Consumr rs Power Co. Midland I and 2 Units. TMI-2 has not been inspected, and Midland I and 2 are still under construction and have not begun commerical operation. The external AFW headers have operated for more than 22 reactor years with no evidence of damage. They are used at: Duke Power Co., Oconee 1 & 2, Arkansas Power & Light Co., ANO-1, Florida Power Corp. Crystal River 3 and General Public Utilities, Three Mile Island-1.
The purpose of this report is to describe the inspection, evaluation and repair activities related to resolving the damaged internal header problems which have occurred at the plants using that header configuration. It will also be used as a failure analysis report under the requirements of ASME Boiler and Pressure Vessel Code,Section XI, Article IWA 7000.
In the following sections of this report, facts will be presented to show that a logical cause has been established and that the modified design prevents recurrence of that problem in both the non-functional internal header and the new external header. In addition, the report will show that the modified design provides all functional requirements previously provided by the internal header design. Based on these facts, the report will demonstrate that start-up and continued operation of the affected plants is justified. ,
1.1 Internal AFW lleader Design The internal AFW header is a rectangularly shaped torus fabricated of welded plate segments. The header is positioned on the upper end of the upper vertical cylindrical baffle (upper shroud) (see Fig. 1-1). The header also serves as a continuation of the upper shroud to separate the tube bundle from the steam annulus. The header is positioned and retained by eight sets of inner and outer brackets welded to the bottom of the header and match drilled through the shroud. A dowel passes through each set of brackets and is welded to the inner bracket (See Fig. 1-2).
A single 3 1/2 inch diameter AFW nozzle delivers water to the header via a thermal sleeve which slip fits into the header (cee Fig. 1-3). Water leaves the header through 60 - 1 1/2 inch diameter flow holes near the top of the inner header wall. The flow holes are equally spaced around the circumference. There are 1-1
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8 - 1/4 inch diameter drain holes near the bottom of the inner i vertical vall (See Figures 1-4 and 1-5).
The auxiliary feedwater system piping connects to the AFW nozzle l
outside each steam generator. During power operation the internal ;
AFW header, thermal sleeve, and a portion of the horizontal piping are filled with dry superheated steam. '
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The bracket and donal arrangem:nt permits differcntial thermal movement of the internal AFW header in a radial direction during operation.
'l . 2 Internal AFW Header Functional Requirements The internal auxiliary feedwater header provides three functions. The header distributes auxiliary feedwater whenever required over the steam
, generator tube bundle at a point just below the upper tubesheet. It also acts as an extension of the upper shroud which separates the tube bundle f rom the steam outlet annelus.
The third function is served while the plant is shutdown. When a plant is in wet lay up the header distributes water and chemicals, during fill and recirculation, to the top of the steam generator secondary side to insure a well mixed solution.
1.3 History of the Problem In April,1981 tube leakage was experienced at the Davis-Besse 1 station.
An eddy current (EC) inspection determined that two adjacent peripheral tubes were leaking. The elevation and circumferential location of the tube leaks were aligned with the location of a header bracket pin. An expanded eddy current inspection carried out in this generator in the areas near the other dowel pins identified one additional tube indication (ding) which could be correlated to a dowel pin " location.
In May,1981 tube leakage at Rancho Seco was identified. Although the leaking tube was adjacent to the inspection lane and not related to the header, an eddy current inspection was performed at all dowel pin locations.
The inspection recorded dings in tubes at five of the eight dowel pin locations.
In February,1982 a leaking tube at the bundle periphery was identified at Oconee 3. An eddy current inspection performed at four of the eight dowel pin locations recorded no tube indications.
As a result of these indications more EC inspections of the perhipheral tubes in the OTSG at Davis Besse 1 were planned for their 1982 refueling outage. As a result of these inspections visual examinations of the internal headers were made to check for loose dowel pins in the brackets attaching the internal header to the steam generator shroud. It was during this inspection that the header and bracket damage was first detected. The results of this inspection led to the inspections at Rancho Seco and at Oconee 3 which also enploy the internal hedder design.
Following the preliminary inspections during April of this year at Davis-Besse and Rancho-Seco a meeting was held April 23, 1982, to provide the NRC staff with information then available on this problem. Since that time, there have been several plant specific meetings with the staff to review additional inspection ir.f:rmation and the repair plan. The three operating plants with the internal header design have also filed Licensee Event Reports with their regional NRC Inspection and Enforcement Offices and Consumer Power Company has' filed a 10CFR50.55e Report with their NRC I&E regional office.
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Figure 1-1 l ONCE-THROUGH STEAM GENERATOR WITH INTERNAL AUX. FEEDWATER HEADER l
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2.0 Site Inspections and Results As a result of the 1981 eddy current inspections, additional inspections were initiated at Davis Besse 1 in March of this year during their planned refueling outage. The damage noted during that inspection and the absence of any plant specific cause suggested the need for inspection of Rancho Seco and Oconec 3 internal headers.
The site inspection techniques used for these inspections include direct visual inspection, dimensional measurement, fiber optics and remote TV camera viewing. In addition, eddy current testing (ECT) is being used to determine tube wall thinning. Debris analysis of the ECT data is.used to indicate clearances between peripheral tubes and the inner most parts of the internal headers.
Visual examinations along with ultrasonic (UT) and penetrant tests (PT) are also being performed to establish the mechanical integrity of the feedwater header plates and welds and the steam generator shell in the vicinity of the new AFW nozzle penetrations. These results and the status of inspections at the three plants are described in Sections 2.1 through 2.3.
With one exception, the inspection results from all three plants were generally similar. The outer vertical wall of the header was distorted inward toward the center of the generator, the support brackets were bent or damaged and the dowel pins were either out of position or missing. The exception was the presence of holes in the parent metal at the top and bottom plates of the headers at Oconee 3. Investigation of the holes in the Oconce 3 headers is continuing.
Clearances between the inner wall and inner brackets and peripheral tubes have been inferred at Davis Besse and Rancho Seco to be minimal. It is postulated that the distortion of the outer vertical wall of the header has led to some inward bowing of the inner vertical wall and novement of the top and bottom corners of the inside of the header closer to the pheripheral tubes. This bowing was checked by feeling the inner wall at Davis Besse 1 and SMUD after machining the access holes. This movement along with distortion of the inner brackets could also account for the apparent reduction of inner bracket to perhipheral tube cicarance.
The distortion of the header inner wall is indicated in Figure 2-1, 4-1, and 4-2.
UT of the shell and internal header nozzle region was performed prior to machining. These examinations showed those areas to be free of unusual or unacceptable indications.
At all three plants, some gaps were noted between the top of the shroud and the bottom of the header. These gaps varied from 0 to about k".
2.1 Davis Besse 1 Inspection (Final)
During the 1982 refueling outage at DB-1, eddy current inspection identified a number of new indications in tubes corresponding to 2-1
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. i the dowel pin locations. In addition, a significant number of indications were recorded on peripheral tubes between the dowel pin locations. The indications correlated with the top and bottom i edge of the internal AFW header.
2
! An expanded inspection program was initiated on both of the DB-1
! OTSGs to characterize further the initial findings. This
! included:
- 100% peripheral tube eddy current inspection.
Selected profilometry inspection of peripheral tubes with eddy current indications in the header region, i
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Secondary side visual inspection of the internal AFW header.
Eddy current inspection showed 24 peripheral tubes in the two j generators had indications which were interpreted to show contact with the internal header assembly at some point in time. Of these i 24 tubes, seven tubes had outside diameter (OD) indications, and 17 tubes had tube diameter reduction (ding) indications. Three of
- the OD indications exceeded the technical specification plugging
! limits of 40% through wall.
Eddy current debris analysis of the peripheral tubes indicated that the header was very near tubes around one axis and showed that there is only slightly more cicarance at all other locations.
Profilometry indicated that the direction of the tube diameter
- reduction for tubes apparently in contact with the header was i
oriented toward the AFW header. The amount of tube diameter reduction is less than 20 mils.
! A visual inspection of the internal headers, followed by a 360*
remote video inspection, showed that the outer wall (shellside) of the header is distorted inward (concave) as much as 4 1/2". In addition, the inner vertical wall was noted to be bent inward in some locations. 'In one generator, the thermal sleeve was disengaged from the inlet hole of the header and was offset from ', 1 the center of that opening. It was also noted that certain header support brackets were bent, the bottom ligament torn out, or were broken off and that there was evidence of wear and/or distress on dowel pins and brackets. Dowel pins were found to be not in place at the majority of the eight bracket locations in each of the $
steam generators (See Fig. 2-1). All brackets and all but one dowel pin have been located and retrieved. The missing dowl pin is not in the tube bundle or on the 15th tube support plate.
The internal AFW headers have been thoroughly inspected to assure "
that their structural integrity is adequate. Several inspection ,
- techniques were used depending on accessibility and the objective of the examination. These techniques included
2-2
- 1) Direct visual examination
- 2) Visual via remote TV camera 5x magnification
- 3) Visual via fiber optics 5x magnification
- 4) Ultrasonic testing (UT)
- 5) Dye penetrant testing (PT)
Figures 2-2 A, B, and C shows the areas of the header that were examined to assure header stabilitiy.
The initial inspections of the DB-1 internal AFW headers were performed using a remote TV camera mounted on a track supported from the shroud alignment pins. The track and camera were rotated around the generator to provide a full 360* view of the header.
Several passes were made with the camera at different elevations and orientations to provide a view of the accessible portions of i the lower header plate, the outer vertical plate and the top header plate and their connecting welds. While some header blemishes were detected (subsequently reexamined and found inconsequential) in these examinations, no indications of cracks on other deformities which would detract from the structural integrity of the header were identified. Figure 2-2A shows the '
area encompassed by these inspections.
To provide some basis for the adequacy of the remote TV inspections, additional UT and PT examinations were performed.on selected portions of the SG 2 header. The worst deformation of all the internal headers at DB-1, Oconee-3 and Rancho Seco occurred on SG 2 at DB-1 near the manway opening. Consequently, the vertical outer header plate was ultrasonic 1y tested in this area and a portion of the vertical plate, the lower plate, and the connecting weld was dye penetrant tested. These tests showed that no cracks or other detrimental indications exist in the most
/ severely deformed portion of the header. An additional dye i
penetrant test was performed on the back wall of the header through the AFW inlet nozzle. The PT showed no unusual indications.
See Figure 2-2B for specific details of these inspections. i Af tetg3hc cight AFW injection holes were drilled in the shell and shroud of each Davis Besse steam generator, additional inspections i of the internal header were performed at each of the hole locations to ensure header integrity. The bottom plate of the header was ultrasonic 1y tested for approximately one foot on either side of each hole to assure that the material was sound in the area of the tie-down welds (see Section 4.0 Description of Repair). These tests showed the metal to be of full. thickness'and free of cracks.
Following the discovery of weld cracks at Oconee-3 and Rancho Seco, additional inspections were performed at each hole location.
These inspections were very similar in method and quality to those r done at Oconce-3 and would have detected cracks similat to those
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1 observed at Oconee. Using a fiber optics device through the shell and shroud holes, an examination of the welds connecting the inner j vertical plate to the top and bottom plates was performed.
1 Approximately 6 to 8 inches of the lower weld on either sidaiof i the hole, and about 6 inches of the upper veld at each hole <were f l. ,
examined. These inspections showed the weldss to be'f ree of cracks '"
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or other significant defects. Figure 2-2C illustrates the areas -
inspected at each injection hole location. f, Although a complete inspection of all header plate material and' welds was not possible, the extent, diversity, and quality of the' examinations performed provides complete confidence that no .
undetected, gross, cracking phenomenon exists andLthat the headers j are structurally sound. '
Eddy current inspection will be performed af ter secu' ring the header to the shroud to locate any wall thinned tubes that need;to be stabilized and plugged and to verify that'l/8" clearance still!
exists between the header and brackets and the peripheral tubes,
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l 2.2 Rancho Seco Inspections (as of July 13, 1982) "
t Examination of the internal headers at Rancho Seco 'showed similar.. ^
results. A 360* visual and video inspection of the two headers ,
indicates that there is inward distortion of the'outcr;vertic'al "
l plate of the header. The concavity approached what was not'ed at l Davis Besse 1. No misalignment of inlet thermal sleeves with the 1 header inlet holes was noted although one sleeve was disengaged ,,
it' l from the inlet hole in the header. .t Visual inspection of the A steam generator indicated the inner '
wall of the header at top and bottom'to have greater than 1/8" clearance between the header and perhipheral tubes. However, four inner brackets appear to be less than 1/8" away from at least one ;
i tube. One dowel pin is not in place and the other seven are I
loose. The missing dowel pin has not been located or retrieved.
One inner bracket has a crack in the weld attaching it to the header bottom but all the other 15 bracketc are in place and apppear to have sound welds.
- In the B generator, clearance between the header and peripheral tubes is greater than 1/8". Five inner brackets are in contact with at least one tube, while three have at least 1/B" clearance.
The outer brackets are in place with sound welds. Four dowel pins are not in place and four are loose. Lll missing dowel pins have been located and retrieved.
UT indicated no flaws or plate thinninr, In( f theilower plate or i either header.
l l Eddy current inspection will be performed af ter securing the .
l header to the shroud to locate any wall thinned tubes that'need to.
! be stabilized and plugged and to verify that 1/8" clearance still -
exists between the header and brackets and the pe ' ripheral tubes.
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I 2.3 Osonee3 inspections (fsofJuly 13, 1982)
Visual and video inspection of the header is complece at Oconee 3.
. Machining of the.new header inlet holes is also complete. Visual a '
inspection indicates distortion of the outer-vertical wall of the
, header and distortion of most of the fastener brackets on both I headers. All brackets are in place and only one dowel' pin is not j' in. place in the A generator. A hole approximately 4" long and i 1/4" wide oriented circumferential1y, was noted in the bottom of tle header of the A generator and one hole 2" - 3" long and 1/8"
-to 1/4" wide was found in the top of that header. This hole was Joriented radially. UT examination of the wrappers-in the' A SG Lshowed them to be sound with no loss of thickness. One crack about 1/16" wide by about 18" long was noted visually in the bottom inside corner weld. Fiber optic inspection through the feed water inlet showed the inside of the header to be free from j.
corrosion or chemical attack, In the B generator none of the dowel pins were in place. All brackets are in place but show some* distortion or damage. There is one 1/4" hole in the top of this, header.
Locationandretrievalofmissing.howelpinsisinprogress.
Visual examinations of both generators have shown that'none of the missing pins fare located inside the shroud on the 15th tube support. plate., , ,
i Inspection of the header inithe 3 gerierator will be completed i af ter machining of the holes in the shells. Ultrasonic inspections of the bottoa plates through the new holes will be performed after machining to assure the soundness of the points l for tie-down. E.C. inspect'ioC to determine wall thinning and verify header clearances will be performed in both generators after the header is welded to the shroud as described in Section
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, 3*0 Most Logical Caus@
3.1 Mechanisms Examined l
A number of mechanisms were evaluated as possible causes of the internal header deformations. Both stress and thermal hydraulic calculations were performed to analyze these mechanisms. Early in the evaluation, phenomena f rom normal operating conditions were ruled out as candidate mechanisms.
Mechanisms examined were:
o Impingement velocity and turbulent flow conditions due to high AFW flows o High pressure drop due to high steam flow through header holes at the beginning of AFW flow o Thermal stresses due to cold AFW flow into a header preheated by steam to about 550-590*F It was concluded from these evaluations that some other deformation mechanism must be present to cause partial collapse of the internal AFW header. Stress calculations indicated that a pressure differential above about 200 PSI would be required for this to occur.
3.2 Most Logical Cause Condensation-induced high differential pressure has been postulated to be the deformation mechanism which could create large enough pressure differentials to partially collapse the internal AFW header. Vertical walls have less rigidity and tend to buckle inward. This inward distortion could bow the lower plate upward binding the bracket and dowel pins. This could defeat the dowel pin slip mechanism and ratcheting of the brackets and pins could occur. Forces aay be sufficient to break bracket ligaments, bend pins, break bracket or dowel pin welds and deform inner brackets. Repeated application of such forces could increase the severity of the damage.
According to the Creare Report, NUREG 0291(1) condensation-induced high difference pressure can be anticipated under the following conditions:
- 1. Trapped steam
- 2. Sufficient flow of subcooled water
- 3. Sufficient subcooling Resulting in:
Rapid condensation of steam l -
Sudden depressurization of steam void NUREG 0291 describes condensation-induced pressure surge phenomena which can occur in a flowing system. These phenomena can be separated into three distinct stages. Stage #1 is the process of void formation, assumed to occur mainly by fluid mechanical interaction, possibly aided by countercurrent steam flow. Stage #2 is the condensation and heat transfer driven void collapse, resulting in potentially very large localized pressure decreases in the header. Stage #3 is the water slug impact with the upstream water, creating the large amplitude shock waves.
3-1
The AFW header internal damage mainly shows evidence of an inward collapse of the outer (shellside) wall. The " ballooning" ef fects which are typical of feedwater line water hammer (Stage 3) were not evident.
The observed damage to the AFW headers points to a conclusion that the most Ic3i cal deformation mechanism is condensation-induced high differential pressure. The first phase of the pressure transient appeared to create a condensation induced high pressure difference across the AFW header wall when trapped steam pockets collapsed, resulting in header deformation. The effects of a resulting shock wave were not evident due to the attentuation by both the wall deformation and by the flow holes in the header which provided a fluid " escape route".
l l
3-2
. t 4.0 Description of Repair The repair of the units involved meeting three objectives in an optimum combined manner:
Retain all AFW functional requirements
- - Complete the inspections of the damaged header Perform the required repairs The most logical choice from a functional standpoint was to use a configuration as similar as possible to that used on other operating OTSGs, i.e., the external AFW header. Because it was considered desirable to retain the internal header as an extension of the shroud to serve as a steam flow baffle, it was necessary to have sufficient access to inspect fully the damaged header. It was also necessary to locate the inspection holes so that they could serve both as repair access openings and subsequently as AFW injection points.
The following general considerations will be applied to the inspection and repair program:
All work will be conducted to minimize radiation exposure of personnel.
Secondary side lay-up conditions will be monitored and
! kept within established water chemistry limits.
Machining techniques used and materials control exercised will be designed to maintain systems' and components' cleanliness, protect the steam generator tubes and prevent the creation of loose parts.
4.1 Internal Header Design Requirements The evaluation of these considerations led to the establishment of a set of design requirements for securing the internal header.
These requirements met by the repair described in Section 4.2 include the following:
The header must be maintained in a fixed position relative to the tube bundle. The minimum clearance between unplugged (functional) steam generator tubes and
! the header / restraint is 1/8". The minimum required clearance between the tubes and the stabilized header was determined by accounting for thermal motions and 1 Flow Induced Vibration (FIV). The worst case relative motion, .026", occurs during heatup when the shroud is restricted by the shell. The header motion due to FIV is very small, less than .001" because the FIV loads are small and the header and shroud are relatively stif f.
The maximum tube motion due to FlV is .015" for a lane tube. This total of .042" is less than one-half the established criteria of .125".
It should be noted that although Figure 1-2 indicates a possible nominal clearance of 9/16" to 2" in the original header design, there was no minimum clearance criteria defined. No minimum dimension was specified.
4-1 1
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. 8 The secured header must serve as an extension of the shroud to channel steam flow through a similar flow area as it did in the original design.
Based on analysis performed, the AFW inlet opening in the internal header will not be closed.
The secured header must withstand the expected static and dynamic loads resulting from:
- 1) normal and upset operating transients
- 2) seismic conditions (OBE)
- 3) flow-induced vibration Restrained header must not cause leakage of steam generator tubes when subjected to faulted conditions from the most severe accident (steam line break) and seismic (SSE) conditions.
The header restraint design must meet ASME,Section III Class 1 allowables.
The design must minimize the risk of creating loose parts in the steam generator. Any existing brackets and pins which could potentially become loose parts shall either be removed or fastened in such a manner to prevent them from becoming loose during operation.
The design must be compatible with the carbon steel materials of the header, upper cylindrical baffle, and steam generator shell, and it must be compatible with the feedwater chemistry requirements.
The process of securing the header must be accomplished l via the existing secondary manway and/or the auxiliary feedwater nozzle openings, old and new.
The process of securing the header must not damage the j tubes, create loose parts inside the steam generator, or introduce contaminants which cannot be removed from the steam generator.
1 1
The process of securing the header may use but should not necessarily be limited to existing brackets and dowel dins at locations that are verified by inspection to be sound. Appropriate capture of the dowel pins and brackets must be achieved.
The design must be licensable without violating any of
, the plant's design bases.
A volumetric examinatien of the lower plate in the areas of attachment of the header is required.
4-2
a 4.2 Internal Header Repair The bottom of the internal header will be secured to the shroud in eight locations around the circumference. These will be oriented above and adjacent to the circumferential location of the shell to shroud alignment pins. At each location, a 7 inch long continuous fillet veld will be used to attach the outside of the shroud to the bottom of the header. In areas where there is significant separation between the shroud and the header, a shim will be used and will become part of the fillet weld. In the same locations 1/2 inch thick by 5 inch long by 3 inch wide gusset plates will be fillet welded to the bottom of the header and the outer face of the shroud. The fillet welds and 5" ausset plates acting together or separately are designed to take the forces and moments generated by normal operating or accident conditions. The required examinations of welds consists of visual examination of the root pass and final surface per ASME Boiler and Pressure Vessel Code,Section III Division 1, 1977 Edition Appendix XVI-3700 with the acceptance standards of NG-5360. Figure 4-1 illustrates the intended repair. All three affected units will employ this concept. However, there will be minor differences due to utility preference in regard to use of the existing brackets and dowels. At Davis Besse and Oconee 3 the remaining brackets and dowel pins will be removed prior to securing the header.
Rancho Seco has decided to exercise the option permitted by the design requirements of leaving the brackets and dowel pins in place with appropriate capture to preclude loose parts.
At all three plants the thermal sleeves used to direct AFW to the internal header will be removed. A flange will be welded to the existing nozzle and a blind flange will be used to seal the opening.
It is presently anticipated that the repair as described will be used at Oconee 3. Additional inspections are being performed to establish the mechanical ire'grity of the headers. Repairs to the header will be performed, .f needed, to meet the established requirements for soundness of the secured header. Analysis to determine the probable cause of the holes noted in the top and l bottom plates is in progress.
As mentioned at the beginning of this section a major consider-ation in the repair approach was to provide access to the damaged internal header with a minimum of machining on the shell. An engineering evaluation indicated that 5" diameter holes would provide sufficient access for securing the header while still complying with the code requirements for the mechanical strength l of the steam generator shell. A demonstration of the ability to l
secure an internal header to the shroud by the described method was performed on a full scale steam generator mock-up May 21,
! 1982.
It is important to note that the probable cause of deformation to l the internal header, identified in Section 3.2, describes a condition that only exists when that header is used for auxiliary feedwater additions. Steam will still exist in the internal g
4-3
i ,
i . .
header because the AFW injection hole, 60 flow distribution holes and eight drain holes are not plugged. However, no practical means of introducing significant volumes of cold water in this area exist; consequently, further damaging loads will not be produced by steam pocket collapse. It is, therefore, considered
. reasonable to leave the internal header in place, once it is properly secured, since it will no longer be exposed to conditions which produced the deformation.
4.3 External Header 4.3.1 Description The new external header will be connected to the existing plant auxiliary feedwater line by 6" diameter piping. The header will be about a 300* circumferential ring made from 6 inch schedule 80 pipe capped at each end. Each of the plants will employ either six or eight 3 inch schedule 80 pipe risers 1
spaced around the ring to feed auxiliary feedwater through the steam generator shell and shroud to the secondary side of the tubes. Flanges will be located in the vertical riser just above the ring and at the point of entry into the steam i generator shell.
i The centerline of the riser inlet to the steam generator will be -
located about 14 inches above the top (15th) tube support plate.
A tapered thermal sleeve will direct the flow from the shell opening through the shroud to the steam generator secondary side.
The risers will contain variable size orifices at the flange in the vertical run to help equalize distribution of flow. Figures 4-2, 4-3A, and 4-3B show the arrangement of the replacement external AFW header.
4.3.2 Functional Design Requirements Specifications have been issued to insure the header design meets j its two basic functional requirements, i.e. supplying and l distributing auxiliary feedwater to the steam generator tube bundleandprovidingdistribygjonofrecirculatingwaterand chemicals during wet lay-up.
The effects of flow-induced vibration have been examined (5)(6) g i insure that the retrofit design is at least equal to the existing external header design in this area.
1 The applicable ASME codes will be those which are consistant with the licensing basis of the individual plants. Design, fabrication and analysis of the B&W supplied components will meet the requirements of Section III of the ASM j
headerring,risersandshellflanges.{4gode, Class 2forthe
- 4.3.3 Comparison to Existing Designs As pointed out in Section 1.0 of this document the retrofit of the auxiliary feedwater external header has the advantage of applying i a decign proven in more than 22 reactor years of operation at five i
4-4
- 9 operating plants. No evidence of water hammer or other condensation-induced pressure surges have been noted. The thermal sleeves have been inspected at all operating plants that use the external header design and have been found to be free of damage due to thermal shock or condensate-induced pressure surge.
There are two additional features in the external header design i which tend to minimize the possibility of any damage by condensation-induced pressure surges. These are:
l 1) Top discharge nozzles to preclude header ring draining and suppress slug information, and
- 2) Short horizontal runs to limit void formation and slug acceleration.
These facts have led to the conclusion that no water hammer tests prior to operation are required.
There are a few minor differences between the existing design and the retrofit design. Figure 4-4 shows the existing external AFW header arrangement. The injection point for AFW in the retrofit is about three inches higher than in existing designs to allow
- access for securing the internal header. This could result in an increase in flow induced vibration loads. This increase however is more than offset by a reduction in these flow loads due to a more gradual taper in the thermal sleeve resulting in a lower discharge velocity.
Two features of the retrofit design should provide more equal distribution of AFW flow. These are:
- 1) the use of variable size orifice plates in the flanges of the vertical riser
- 2) feed to the risers at circumferential locations nearer the midpoint of the header ring rather than from one end as is the case for existing designs Lastly the thermal sleeve was redesigned and will be constructed partially of inconel, rather than carbon steel providing improved fatigue properties.
I 4.4 Loose Parts It is the intent, as part of this repair, to locate and remove all loose parts. Should it be impossible to account for all parts, the location of such parts would be either at the 15th tube support plate or in the steam annulus. All missing brackets have been located and retrieved. Missing dowel pins have not been found on the 15th support at any of the three plants and are judged not to be within the tube bundle. This judgment ie reached on the basis that the diameter of the dowel pin, 3/4", is greater than the 1/4" space between tubes; and, since no gross damage or spreading of tubes in the areas concerned have been noted, the 4 pins could not have entered the tube bundle. It is concluded that they are outside the shroud and tube bundle; therefore, there 4-5 i
should be no concern that they would endanger steam generator tube integrity. Teledo Edison inspected 100% of the 15th support.
Blankets to catch particles from the boring operations on the shell and shroud followed by a vacuuming to remove residual chips and dust will be used to preclude the machining operations producing contamination or loose parts. A careful inventory of all tools and parts that enter and leave the steam generator will also be kept.
The Vibration and Loose Parts Monitoring System at Davis Besse has sensors located at the top of each steam generator outside the shell near the top of the tubesheet. This sensor location provides good indicatior of a loose part on the primary side of the steam generator but is not considered reliable as an indication of loose parts on the secondary side.
4.5 Eddy Current Inspection and Tube Plugging After the internal header has been secured to the shroud an eddy current inspection and debris analysis vill be performed on peripheral tubes. Any tubes with gre- .r than 40% wall thinning or in a location where the secured li.ernal header and bracket clearance is less than 1/8" will be stabilized and removed from service by plugging.
Tube stabilization is done by inserting into the tube to be plugged 1/2" diameter inconel rods of whatever length is necessary. Varying lengths are obtained by coupling standard rod lengths. Each rod has a male and female thread at opposite ends to permit coupling. After coupling, the female thread is crimped to prevent decoupling. The rods are screwed into the plug prior to welding.
This stabilization technique is used as a capture mechanism to prevent instabilities due to potential flow-induced vibration and is not intended as a structural device.
1 The stabilizers are only used in conjunction with plugs in the upper tube sheet. More than 100 of these have been installed in OTSGs since inception of their use in 1976.
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ARRANGEMENT OF REPLACEMENT EXTERNAL AFYi HEACER-VERTICAL CROSS-SECTICN
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- 0 5.0 Pre-Operational Tests A field hydrostatic test will be performed on the new auxiliary feedwater piping, ring header and risers and on the internal AFW header inlet nozzle and blind flange. These tests will be in accordance with the ASME Section XI code requirements except where relief from these requirements as outlined in Toledo Edison letter Serial No. 830 has been granted by the NRC.
A cold flow demonstration test will be run to verify that all lines are clear and free from obstructions.
A hot flow demonstration test will also be performed by simulating an AFW injection actuation with the steam generator pressure and temperature slightly above normal, hot, no-load conditions. These conditions will be established as required for operational hydrostatic testing. The purpose of the test is to verify that no feedwater hammer problems exist. An individual will be standing near each of the new AFW header and risers during initiation.
This test will also ensure that minimum AFW flow to the steam generators is provided.
5-1
- O 6.0 Post Operation Inspections The following post operation inspections are planned:
Selected special interest peripheral tubes will be EC inspected in conjunction with other EC tube inspections as required by technical specifications but will not be considered as a part of those required inspections.
Visual inspections will be made of the secured internal header, attachment welds and external header thermal sleeves through selected opening (s) during the next two refuelings and at the 10 year ISI.
The AEW external header inspection will be included in the ISl program.
I l
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7.0 Safety Assessment and Summary B&W and the affected Licensees recognize that this repair has safety significance. The retrofitted external header is a component of a safety system w mitigatethefollowingevents:ggyefunctionisdesignedto
- 2) Loss of offsite AC Power
- 3) Main Steam Line Break (SLB)
- 4) Smg11 Break Loss of Coolant Accident (LOCA) - less than 0.5 ft break Furthermore, the repair has considered the need to secure the internal header to assure no dansge to steam generator tubes while retaining the shroud extension function.
The first of these two safety functions, the ability of the steam generators to provide decay heat removal for the above events, has been demonstrated at five different plants during more than 22 reactor years of operation.
There are only two differences between these existing AFW external headers and the retrofit external header design that impact this l cooling function. Neither have any significant effect on the SG decay heat removal capability.
One is a possible loss of needed flow due to increased pressure drop in the retrofit design the other is a lowered effective cooling due to less wetting of the SG tubes by the injection of cooling water at six or eight 3" nozzle locations (external header) rather than at 60 1 1/2" holes (internal headers).
, The small increase in pressure drop for the retrofit design is due to a 3" higher AFW injection point and an increase of 3 psi due to
, use of orifices to improve-flow distribution. Even taken I
together, this increased AP will not have any significant effect on flow capacity and is partially offset by the slightly more open throat diameters in the external sleeves of the retrofit design.
The second concern with distribution and penetration of cooling water to the SG tubes for the external header vs. the internal header design, a B&W study indicated that there is almost no difference in tube wetted surface area (about 1% less for the external header) between the two designs. This is attributed to i the greater penetration of the external header design which all but completely offsets the effect of the wider peripheral distribution of cooling water by the internal header.
Careful thought and analysis ( have been put into the repair of the internal header to assure it is securely fastened in place.
7-1
This stabilization analysis included the following loading conditions:
Normal and Upset Conditions (Now called Service Levels A and B).
Dead Weight, Flow Induced Vibration, Operating Basis Earthquake, and Thermal Transients were considered. This includes a fatigue analysis to demonstrate structural integrity for the plant life.
Emergency Condition (Now called Service Level C).
Dead Weight, Flow Induced Vibration, Safe Shutdown Earthquate, and Thermal Transients were considered.
Faulted Condition (Now called Service Level D).
Two load combinations were considered: (1) Dead Weight, LOCA, and Safe Shutdown Earthquake; (2) Dead Weight, Main Steam Line Break, and Safe Shutdown, Earthquake.
This analysis considered the box header corner welds which have been shown to be adequate. Complete corner weld integrity was assumed; however, considerable margin exists such that some degree of weld cracking is acceptable. The safety factor for a Main Steam Line Break is 2.3, indicating that at the limiting location the applied stresses could be doubled without exceeding the ASME Code allowable stress. The analysis was performed assuming a full penetration weld with a weld quality factor of 1.
The fatigue analysis shows that even if a stress concentration factor of 4 is used, which is the factor appropriate for cracks being present, the header can be shown adequate for the design transients including heatup and cooldown and 29,000 cycles of AFW initiation. Accordingly, 43.5% of the Corner weld integrity is required to meet ASME Code faulted limits for the limiting case.
In order to assess the acceptability of cracks, it can be inferred from the above analysis that cracks are acceptable as long as the cracks or degraded condition are intermittantly distributed around the header. It is expected that up to 25% of any weld could be fully degraded or cracked if the condition was intermittantly distributed.
As discussed in Section 2.1, the inspections at Davis Besse have produced no evidence of weld cracks such as those observed at Oconee-3 and Rancho Seco.
We are very confident that there are no significant cracks in the headers at Davis Besse and certainly none of the welds are j approaching the 25% degradation discussed above.
The proposed post-operational inspection program is sufficient to detect the development of any significant weld cracking problems, however, we do not anticipate that operation with the stabilized j header will result in the development of additional cracks.
t 7-2 l
- D With the internal header no longer utilized as an AFW flow distributor, the rapid collapse of steam in the header will no longer occur. Consequently, the headers will no longer be subjected to the large loads they previously experienced during feedwater actuation and which may have been responsible for the cracks observed at Oconee-3. In order to induce the distortion observed in the header, it would be necessary to apply a load sufficient to produce stresses in the header in excess of 1.5 times the yield stress. For the material in question, it can be inferred that stresses in excess of 36 ksi have been experienced.
The calculated maximum operational stress in the corner weld of the stabilizer header is 2 ksi or about 5% of the stress which the corner welds experienced without catastrophic failure during an AFW actuation.
Based on our inspections and the analyses discussed above, we believe the structural integrity of the stabilized headers at Davis Besse is sufficient to permit continued operation of the unit.
The minimum 1/8" clearance between the header and the tubes will be verified after tie down. As an added precaution any tubes closer to the header than 1/8" will be stabilized and removed from se rvice.
In 1981, a thermal sleeve was removed at Oconee to examine peripheral tubes at an AFW external header injection point. Not only was the sleeve in good condition, but also no damage from jet impingement or flow induced vibration was noted on peripheral tubes. This adds assurance to the validity of B&W analyses that show these two headerdesign.(gggggnismsnottobeaconcernfortheexternal The Stress Report issued when the steam generators were fabricated constitutes the ASME Section III required Design Reports. A revision to this report to incorporate the changes to the header is currently being prepared by Babcock and Wilcox.
Both the retrofitted external header and the secured internal header have had independent evaluations at B&W by in-house Design Review Boards and the affected Licensee's Safety Review Boards have examined the repair program.
In summary, the Licensees working closely with B&W believe they have established a logical cause for the original problem, and have a repair program that fully considers that cause and will preclude its recurrence. In addition the replacement external header is a proven design that has carefully been analyzed and will be tested. As an added precaution, although the redesign considers the full life time of the plant, the repaired units will be inspected at the end of the next fuel cycle to assure no degradation of the units. These facts justify start-up and continued operation of the affected plants.
7-3
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8.0 References ;
- 1. NUREG-0291, NRC-1, An Evaluation of PWR Steam Generator Waterhammer, Final Technical Report, June 1, 1976 - December 31, 1976, by Creare, Inc., Hanover, NH.
- 3. Functional Specification for Steam Generator Emergency Feedwater Header B&W Doc. No. 18-1134783-00.
- 4. Equipment Specification for Steam Generator Auxiliary Feedwater Header B&W Do, No. 08-1134172-01.
32-1134668-00.
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t 8-1
Docket No. 50-346 License No. NPF-3 Serial No. 845 August 6, 1982 Attachment B Davis Besse Parts Recovery Program The current status of all the internal header parts is provided below:
Recovered from Number Per SG #1 SG #2 Steam Generator (OTSG B) (OTSG A)
Internal Brackets 8 8 8 External Brackets 8 8 8 Dowel Pins 8 8 7 All brackets and dowel pins have been recovered from Steam Generator No.
1, and all brackets and seven of the eight dowel pins have been recovered from Steam Generator No. 2. The eighth pin is 3/4 inches in diameter and 2 11/16 inches long. Figure 1-2 of Attachment A provides a graphical description of its location.
All the interp31 brackets were examined and show indications that a dowel pin was originally installed.
Although efforts are continuing to locate the remaining dowel pin, an evaluation is being made to identify any potential safety concerns associated with a loose pin and its possible locations.
Due to its size, the pin could not have entered the tube bundle area without severe tube damage. No such damage has been discovered in the detailed inspection which included the eddy current inspections of all peripheral tubes above the 15th tube support plate. Video inspections were conducted inside the shroud after the eight access holes were made.
The video inspection showed no significant drilling debris or any evidence of the eighth dowel pin on the 15th tube support plate.
The remaining potential locations are all limited to areas separated from the tube bundle by the steam generator shroud without any steam flow path that could return the pin to that area. Therefore, as stated in Section 4.4 of Attachment A, there is no concern as to steam generator tube integrity.
This means the pin would have fallen toward the steam annulus. There are no other portions of the steam generator on the outside of the shroud that could have been adversely affected by the dowel pin. The closed Drawing No. 151902E, Revision 7, shows the location of the steam outlets and the steam annulus separation plate 3 feet below. All of the other pins and brackets that had come off of the header support scheme during operation were recovered from this area. A video inspection was also completed
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af ter the eight access holes were made for the external header. The eighth pin was not located.
The only areas remaining that are open to the steam annulus are the steam lines. These lines themselves contain no components that could be affected by a loose dowel pin within the shield building. Enclosed is a piping isometric Drawing No. M-203B, Revision 15, showing the specific routing for the No. 2 steam generator steam line. The migration path '
required to leave the containment area requires passage. through at least four ninety degree piping bends and a vertical elevation lift of at least 34 feet. The only potential concern would involve the dowel pin interfering with active components downstream in the main steam system.
To provide reasonable assurance that no dowel pin interaction will cause a future problem, Toledo Edison is now planning to extend its video inspection to portions of the steam line. A fiberscope check is planned for each of the initial horizontal to verticle elbows out of steam generator #2. Also, there will be a check in the horizontal piping upstream of the main steam isolation valve.
Barring discovery of the pin in this area it la considered that the pin is captured in the annulus or is no longer in the portion of the main steam system which could cause interference with an active component of safety concern. Since initial operation, there has been no problem with any active components in the main steam system that indicates migration of a dowel pin through the steam line, lab b/6 i
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Docket No. 50-346
, 4 , Lidinse Fo. NPF-3 ,
Serial No. 845 t August 6, 1982 /
Attachment C RESPONSETONRCbETTERDATEDJUNE 23, 1982
,'. i t
,' AUXILIARY ;
FEEDWATER HEADER REPAIR - REQUEST FOR ADDITIONAL INFORMATION 3 % \
- 1. Provide a detailed description of the repairs and modificecions to the auxiliary feedwater system. Describe how the as modfiled system compares to the auxiliary feedwater design used previously in,other operating B&W plants. Compare the expected performance of the moddfied design to that of the original design and of earlier B&W units.
I RES, PONS : For the description of the repairs and modifications see Section 4 of Attachment A. Identification of the differences are in Sections 4.3.3 and 7.0 of the same attachment.,
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- 2. Describe the program tof i'dertify and recover loose parts resulting s f rom previous dattage ' and > hat may be produced durnng repair. . i Describe your loose parts .ing system (s) and discuss detection g / , ;,
capability particularly wit.u reference to any known or potentialf f 8 loose parts. If loose parts will exist after operation, evluate the
,enfety consequences.
56SPONS2: Section 4, specifically 4.4, of Attachment A discuss the l parts recovery program at Davis Besse and the currently installed monitoring systems. Attachment B identifies the current status of the program and its potential safety Concerns.,
h
/ 3. Describe the' ypes of pre-repair inspections performed on the steam
)\< , generator shell, shroud and header and discuss the results.' Supply yN #
, ' a drawing or drawings which show the limits of each inspection performed. Identify the' criteria used to evaluate theizsandness of f
the header and' discuss, where applicable, the ability of the remote
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visual inspection to detect flaws with respect to the acceptance t'
, criteria.
RESPONSE: Section 2 of Attachment A discuss the inspections and ['
3 results at Davis Besse. /,
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- 4. Describe ther'oyiginal criteria for minimum acceptable clearancis betwe.:n the AFW header dad supports and the neripheral tubes,/ and
, relate this to the clearance ~s that will exisc after repairs are completed. If clearances ef ter repair are lets than the minimum accceptyble for the original design, provide the nesessary dialyses to fu.scify operation under normal, transient, and accident conditions.
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RESPONSE: The acceptability of tube to internal header cicarances is discussed in Section 4.1 of Attachment A. Following the internal header reattachment, neither header was less than the minimum clearance from any unplugged steam generator tubes.
- 5. Discuss your criteria and i,rocedures for plugging and stabilizing of '
peripheral tubes. ,
RESPONSE: Tube plugging is discussed in Section 4.5 of Attachment A.
- 6. Provide an analysis which demonstrates acceptable results when maximum expected forces are applied to the stabilized header ,
considering normal, transient, and accident conditions.
RESPONSE: Section 7 of Attachment A discussed the post-stabilized header forces.
- 7. Describe your acceptance criteria for all welds used to stabilize or reinforce the header. Describe in detail the inspection program to be followed.
RESPONSE: Sections 4.1 and 4.2 discusses the reattachment process criteria and inspections.
- 8. What inspections will be performed following the stabilization of the header te ensure that distortion from welding does not reduce claarances between tubes and the header below the minimum acceptable?
RESPONSE: After the header reattachment process, the inspections discussed in Section 4.5 of Attachment A verified all clearances between tubes and header were acceptable.
RESPONSE: Attachment A, Sections 4.3.2 and 7 discuss the issue of flow induced tube vibration as it relates to the modified auxiliary feedwater design.
- 10. Describe your plans for revision of the ISI/IST program to include steam generator internals on the steam side.
RESPONSE: Post-operation inspections are discussed in Section 6.0 of Attachment A.
d f' Docket No. 50-346 J License No. NPF-3 Serial No. 845 August 6, 1982 Attachment D RESPONSE TO NRC LETTER DATED JULY 30 3 1982 AUXILI'C.t FEEDWATER HEADER REPAIR - REQUEST FOR ADDITIONAL INFORMATION (4 ITEMS)
- 1. The responses to Items 6 and 9 in Attachment C of your July 15, 1982 letter are not complete. With respect to the stabilized internal header, we require the following information as a minimum:
- a. Provide a summary of the analyses performed to assure that the structural integrity of the stabilized internal header will be maintained for the remaining life of the plant. Include a description of all forcing functions associated with ASME Level A, B, C and D loads, a brief description of the analyses performed and a summary of the results of the analyses.
RESPONSE: For a summary of the analyis performed and results, see Section 7.0 of Attachment A Revision 1.
- b. Provide a more detailed description of the analyses performed to assure that the new location of the stabilized internal header, including the 1/8" minimum clearance between the unplugged steam generator tubes and the header / restraint, has been accounted for with respect to the design requireemnts in Section 4.1 of Attachment A of your July 15, 1982 letter, i.e.,
maximum differential thermal motion, maximum movement due to flow induced vibration and maximum thermal induced movement during heatup and cooldown.
RESPONSE: Section 4.1 of Attachment A has been expanded in Revision 1 to include a description of the mimimum clearance considerations,
- c. Since the inlet opening to the internal header will not be closed, provide assurance that steam pockets cannot still be trupped in the header and cause additional damage in the event of their collapse.
RESPONSE: For a description of the evaluation to ensure internal header steam pocket collapse loadings are acceptable, see Section 4.2 of Attachment A Revision 1.
- 2. It is our understanding that some of the internal header welds in the Oconee 3 plant were found to be cracked. These cracks were discovered as a result of special examinations to reveal the cause of holes formed in one of the Oconee 3 headers. These cracks were not detected by the initial examinations to establish the soundness of the header. Subsequent re-examination of the already stabilized l
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l header in the second steam generator at Oconee 3 revealed similar l cracking. Discuss the structural integrity of the as-stabilized headers at Davis-Besse with respect to the potential for similar cracks in header welds.
l RESPONSE: For an evaluation of the structural integrity of the i as-stabilized header based on examinations and analysis of l acceptable flaws, see Sections 2.1 and 7 of Attachment A Revision 1.
i
- 3. Provide a commitment to prepare the ASME Section III required Design ,
j Reports for the modified steam generator and auxiliary feedwater piping systems.
l RESPONSE: The commitment to modify the ASME Section III Design Report is included in Section 7 of Attachment A Revision 1.
- 4. Provide a commitment to conduct the following tests prior to j resumpticu of power operation:
I
- a. A cold AFW flow test to verify that the minicum flow l requirements specified for the design basis accidents (FSAR
,l Chapter 15) will be met.
- b. A water hammer test in accordance with the requirements of NUREG-0800, Standard Review Plan, Section 10.4.7 and Branch l Technical Position PSB 10-2. Describe your proposed test
( program.
, RESPONSE: For the details of flow and water hammer testing commitments, see Section 5 of Attachment A Revision 1.
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- 11. Describe the post-repair startup test and insepetion program, including water hammer tests, to be conducted prior to the resumption of power operations.
RESPONSE: The pre-operational tests are described in Section 5 of Attachment A. Section 4.3.3 of the same attachment discusses the water hammer resistance of the external design that have been effective on the earlier plants.
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