IR 05000361/1998001
| ML20248E719 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 05/29/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20248E703 | List: |
| References | |
| 50-361-98-01, 50-361-98-1, 50-362-98-01, 50-362-98-1, NUDOCS 9806030424 | |
| Download: ML20248E719 (22) | |
Text
_ _ _ _ _ _ - _ _ _ - _ - _ - - - -
_ . - - -
-
.
.
DiCLOSURE U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
l l
Docket Nos.: 50-361;50-362 License Nos.: NPF-10; NPF-15 Report No.: 50-361/98-01; 50-362/98-01 Licensee: Southern California Edison C Facility: San Onofre Nuclear Generating Station, Units 2 and 3 Location: 5000 S. Pacific Coast Hw San Clemente, California Dates: February 2 through April 10,1998 Inspector (s): 1. Barnes, Technical Assistant Division of Reactor Safety S. M. Coffin, Materials Engineer Office of Nuclear Reactor Regulation Approved By: Arthur T. Howell 111, Director Division of Reactor Safety ATTACHMENT: Supplemental Information 9806030424 980529
~
. _ . _ _ _ _ _ _ _ _ _ . _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ ____
t . I
\ .
-2-l EXECUTIVE SUMMARY San Onofre Nuclear Generating Station, Units 2 and 3 -
NRC inspection Report 50-361/98-01; 50-362/98-01
Maintenance
. ' Unit 2 Outage MC9 eddy current examinations appeared effectively controlled, with good l overall contractor performance noted (Section M1.1).
Engineering
. Current steam gererator initiatives were considered comprehensive, with the planned actions to reduce operating temperatures to 596*F viewed as particularly noteworthy (Section E1.1).
. The licensee use of the plus point probe during Unit 2 Refueling Outage EOC8 and Outage MC9 was considered an indicator of management support for examination initiatives that would provide for early detection of degradation in steam generator tubing (Section E1.2).
. The number of tubes plugged in Unit 2 because of identified axial and circumferential flaws at the top-of-tube sheet location increased to 254 in Refueling Outage EOC8 from a total of 27 in the prior refueling outage. Axial flaw indications at eggerate supports (17 tubes) and freespan locations (29 tubes) were also identified for the first time in Refueling Outage EOC8, with the plugging totals for these categories of indications increasing to 68 tubes and 166 tubes in Outage MC9 (Section E1.2).
. Through Refueling Outage EOC8, the extent of Unit 3 steam generator tube degradation remained below that detected in the Unit 2 steam generators, despite very similar effective full power years of operation. The respective numbers of identified flaw indications at the top-of-tube shest location, eggerate supports, and in the tubing freespan were approximately an order of magnitude lower in Unit 3 than the corresponding Unit 2 totals (Section E1.3).
. The Unit 3 Outage MC9 eddy current examination and visual inspection data were considered supportive of the licensee's conclusion that chemical cleaning of the steam generators had restored the tube bundle thermal hydraulic conditions and flow characteristics, thus, stabilizing both the growth rate of existing wear indications and generation of new indications (Section E1.3).
l
= - _ _ - _ _ _ _ - _ _ _ _ - _ - - - - _ . -_ _ _ _ _ _ __ _ _ __ _ _ _ _ _ . _ - _ _ _ _ - -
.
l
!
l'
f-3-
. The scope of Unit 2 steam generator secondary side visual inspections was considered satisfactory, with the results indicating that the extent and magnitude of flow accelerated corrosion of the eggerate suprorts was approximately an order of magnitude less severe l- . than previously seen in the U:iit 3 steam generators (Section E1.4).
'
!
g . Review of a Unit 2 probabilistt' operational assessment for Cycle 9 was limited by l
much of the supporting data being offsite at the contractor's facility. The results from
! recent Unit 2 pulled tubes were found to be bounded by the burst pressure and leak
rate assumptions used in the Unit 2 assessment. The assessment and Refueling l Outage EOC8 eddy curreat results were verified to support the licensee's conclusion that j rotating probe examinations were not necessary at the top-of-tube sheet region during Unit 2 Outage MC9 to ensure steam generator tube integrity (Section E1.5).
Plant Suooort
. . Licensee efforts in the last 2 years, including adoption in 1997 of ethanolamines for pH control, have resulted in a significant reduction in iron transport to the Units 2 and 3 steam generators (Section R1.1).
l i
!
l l
l _ _ _ _ _ . _ _ _ _ . _ _ .. J
.
.
-4-Report Details Summarv of Plant Status Unit 2 was in a planned mid-cycle outage and Unit 3 was operating at 100 percent power during the onsite portion of the inspectio II. Maintenance M1 Conduct of Maintenance M1.1 Review of Unit 2 Tube Examination Data Insoection Scooe (50002)
The inspectors performed limited observations of tha acquisition, analysis, and resolution processes, including review of a sample of Unit 2 eddy current data from Outage MC9.'
included in the data review were defect " calls" by the primary and/or secondary eddy current data analyst, which were overruled by the resolution analysts; bobbin probe data exhibiting non-quantifiable indications, and subsequent plus point probe examination results for the indications; and defect " calls" that appeared to be potential candidates for in-situ pressure testin Observations and Findinos The inspectors found the eddy current contractor personnel to be knowledgeable and familiar with the program requirements in effect for Outage MC9. An ongoing contractor quality assurance surveillance was performed for the licensee in this outage, which appeared to the inspectors to be a contributor to the observed overall effective program implementation. No significant problems were noted with respect to the performance of eddy current data analysts. Calls that were overruled by the resolution analysts appeared, in general, to be related to "overcalls" by individual analysts rather than missed defect indications. The inspectors had no disagreement with or concerns in regard to any of the final disposition " calls" made by the resolution analyst ' Note: The licensee identifies a refueling outage by the number of the operating cycle which follows the refueling outage, rather than by the more usual number of the operating cycle that has just been completed. To avoid confusion, subsequent references in this inspection report to refueling outages utilize the acronym EOC (End-Of-Cycle) and the number of the operating cycle that has just been completed. For example, the Cycle 9 refueling outage is referred to as Refueling Outage EOC8. Similarly, the Units 2 and 3 mid-cycle outages that have been recently completed in Cycle 9 are referred to as Outage MC _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _
.
-5- Conclusions Outage MC9 eddy current examinations appeared effectively controlled, with good overall contractor performance note Ill. Engineering E1 Conduct of Engineering E1,1 Steam Generater Strateoic Plan Uodate Insoection Scooe (50002)
The inspectors reviewed the actions taken by the licensee to update its steam generator strategic plan since initial NRC review during a 1995 baseline steam generator tube integrity inspection (Inspection Report 50-361;-362/95-14). Observations and Findings Licensee staff informed the inspectors that the steam generator strategic plan had not been updated following the Cycle 9 (i.e., EOC8) refueling outages. Instead, the actions developed in response to the results of the outages were incorporated into the Nuclear Organization's Business Plan. Licensee personnel also stated that a steam generator program plan was being developed, which followed the guidance of NEl 97-06. This program, upon completion, would replace the steam generator strategic pla The inspectors reviewed the steam generator initiatives contained in the Nuclear Organization's Business Plan. The initiative subject areas included: (1) reduction of operating temperatures in the reactor coolant system; (2) development and implementation of improved eddy current examination techniques; (3) development and implementation of chemistry control and corrosion reduction strategies, including injection of boric acid and evaluation of primary and secondary side corrosion inhibitors; (4) development and implementation of repair methods for degraded tubing; and (5)
development and implementation of inspection, test, and analysis . methods to return Unit 2 to full cycle operations. The overall scope of steam generator initiatives was considered comprehensive by the inspectors, with the planned actions to reduce operating temperatures to 596*F (by return-to-service from Refueling Outage EOC9)
viewed as particularly noteworth Conclusions Current steam generator initiatives were considered comprehensive, with the planned actions to reduce operating temperatures to 596*F viewed as particularly noteworthy.
!
I L--_---_------------ - - ---------
- _ - _ _ - _ _ - _
.
-6-E1.2 Review of Unit 2 Steam Generator Tube Reoair History and Outage MC9 Examinatico Scooe and Results Insoection Scooe (50002)
The inspectors reviewed the tube examination scope and methods that were used in Unit 2 Outage MC9 with respect to Technical Specification requirements, industry guidance, and as a result of emerging degradation modes. A review was also performed of tube plugging history for the Unit 2 steam generators, including the specific plugging data for Refueling Outage EOC8 and Outage MC9, and the reasons for tube pluggin Observations and Findinas The licensee planned Unit 2 examination scope for Outage MC9 consisted of: (1) a full-length bobbin probe examination of all active tubes in both steam generators, with the exception of the U-bend region in Rows 1 and 2; (2) plus point probe examination of the U-bend region in all active Rows 1 and 2 tubes; (3) plus point probe examination of all hot-leg side dents and dings which produced bobbin probe amplitudes of 5 volts or greater; and (4) plus point probe examination of distorted and non-quantifiable bobbin probe indications. The licensee did not include plus point probe examinations at the top-of-tube sheet in its scope for the MC9 mid-cycle outage, other than its planned use at this location for evaluation of identified distorted and non-quantifiable bobbin probe indications. The inspectors considered the licensee's use of the plus point probe to be 4 an indicator of management support for examination initiatives that would provide for l early detection of degradation. As discussed in Section E1.5, the inspectors concluded
'
that the omission of plus point probe top-of-tube sheet examinations was technically justified for this outage. Following the identification of a circumferential indication in a Row 2 low radius U-bend in Unit 2 Steam Generator E-089, the licensee expanded the scope of plus point probe examinations of low radius U-bend locations to include all Row 3 tubes in both steam generator Table 1 lists the cumulative repair history for Unit 2 Steam Generators E088 and E08 As of the end of Outage MC9, a total of 625 tubes and 648 tubes, respectively, have been plugged in Steam Generators E088 and E089 during commercial service, which corresponded to respective inservice repair of 6.68 and 6.93 percent. Both steam generators remained below current approved repair limit Table 2 depicts a cumulative compilation for the Unit 2 steam generators of inservice tube degradation history by repair location and degradation mode. A previous review of tube degradation history through Refueling Outage EOC7 was documented in Inspection l Report 50-361; 362/ 95-14. The inspectors noted from the Refueling Outage EOC8 eddy current examination results that a marked increase had occurred from the prior outage in detected axial and circumferential flaw indications at the top-of-tube sheet location (i.e.,
254 tubes versus 27 tubes in Refueling Outage EOC7). The Refueling Outage EOC8 l
- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ .
'
7-Table 1
..-
,
IN NNYhkh h[h h MM e _. _ ._--5,,,j Time of Repair / Outage Effective SG ME088 SG ME089 Full Power Years of Tubes Plugged Tubes Plugged Operation O Cu O Cu IS%' IS%' ,
Preservice 0.00 11 N/A 10 N/A 6/1984' O.79 1 0.01 0 0.00 EOC'1 (1/1985) 1.00 146 2 1.57 184* 1.97 EOC'2 (5/1986) 1.73 5 1.62 12 2.10 i l
EOC53 (9/1987) 2.85 62 2.29 80 2.95 EOC'4 (11/1989) 4.31 31 2.62 31 3.28 EOC55 (9/1991) 5.72 10 2.73 31 3.61 EOC'6 (6/1993) 7.16 11 2.84 21 3.84 EOC57 (3/1995) 8.62 22 3.08 23 4.08 EOC'8 (12/1996) 10.10 178 4.98 154 5.73 l MC'9 (2/1998) 10.85 159 6.68 112 6.93 I
Total Repairs 636 658 1 - Cumulative inservice plugging percentage; 2 - Outage resulted from the identification of a primary-to-secondary tube leak in Steam Generator 2ME088; 3 - Plugging total included seven j tubes that were characterized as containing preservice type defects; 4 - Plugging total included five tubes that were characterized as containing preservice type defects; 5 - End of Cycle; i 6 - Mid Cycl l
i l
i l
t .
h i y t
e g O t
0 8
0 5 0 3 9 6
7 1 9 7 7 3 ca seC
- o u aai gd y s l ectu M d t nr e ob o -
b p l - psi 1 s2 e. pe a Uur ht ;
mnn 0 0 s soTe p iA 1 1
0 0 0 0 0 0 2 6 it uep lc d au0 y a r s1 C g r e wgon gd s o r
- f loe od
'do t i ein t Q R 0 0 0 0 8 5 1 1 6 0 2 at aEc d soi -
3_ ie nwt a ani n1 t
d 1 Tre s P 1 f l
ec;n sDci8 io w. ate 0tj r
_ d e oOd Rd a mE ac g
g
- r a n sl uM id lu e 0 7 7 4 3 0 0 2 ian eo2 n
3 1 9 i P W 5 1
4 2 1 2 1 5 s . tugt b vro l n D. f inar ioc s 2 e o1 b
u it aa l
od e n
[}_ T cigl n u ib
_ f ixnce b o dAinG n gi o gsm
.
o 5 l
i - b N S iax 0 0 0 0 0 0 0 0 9 6 5 w4 u n f FA o l
'_n it 2 6
9 1 lat;pos a e n
- _ _ U f ee ev aS t
o le lahi it sn t er in ita b n ee egnk ic a r b vi a f
T *
S la f e urege t gl is s
C ix E A 0 0 0 0 0 0 0 0 7
8
5
mf u o - pb u lcPue l a
c op7 r st y ict ;sor uyln
-
d et rea o e
.
nh ond d g- i C
r at pan f
d e
a oplu o ec u l
l
- 'S 8
- g T&
T ia l 0 0 0 0 0 0 2
7
4
2
'7 0
3 iys x ce Ai nei ss n t lc A
x icb M o- ep t i
2i; vt u - -y o
neta;a9 r c 2 . it oh r sm s 2d e r t an aeid r Rn r i eb pe
/e B C y RU&.xi 1 -
0 0 0 0 0 0 0 0 0 1 1 esWt pn oo - df u
a n eol a p n
g A f i6l oa;an t
si cseo e g 'Y s
9 0 3 5 1 2 6 2 0
5
r ad eit niacp nnib ona or t 0 7 8 3 7 6 g P F
0 1 1 2 4 5
7 8 0
0
ywa r clyi g i
f t
air nn yE ia s
r el oa f
wl inpd d eei nr oit a t y e ) ) )
)
)
p e
pi t nap e o r
) ) ) l h
g g 5
6 7 8 1 3 5 9 ) R lu repmt n a 8 8 9 9 9 9 9 y
- f t ou 9 9 9 1
/
9 9 9 1
9 l
a f
eesI mio eO
/ / /
5
9
1
/ / /
1
1
/
2 9 1 to ef vmre - roc t
1 1 1 / T f 8f e im/ r 8 ( ( ( ( ( ( ( (
2 it c c u lagde snp
~ T iap 2 3 4 5 ( ;
'4 1 6 7 8 8 " " " " " " " " 9 er i r e 9 C C C C C C C C 2 f
f E
ic x nt I R 1
/ O O O O O O O O E E E E E tC d Ailu t n s-6 E E E M -
n -
e 3 1 a5d r 1 e
! l
.
. examinations also detected, for the first time, axial flaw indications at eggerate supports and in the tubing freespan. The inspectors considered the inferred (or probable)
degradation mechanism for the axial and circumferential eddy current indications to be stress corrosion cracking. In Outage MC9, the plugging total for detected axial flaw indications at eggerate supports increased to 68 tubes (56 outside diameter indications, 12 inside diameter indications) versus 17 tubes in Refueling Outage EOC8. The plugging total for detected axial freespan indications increased to 166 tubes (all outside diameter indications) in Outage MC9 versus 29 tubes in Refueling Outage EOC8. Seven tubes were removed from service in Outage MC9 due to detection of axial indications in the vicinity of the top-of-tube sheet. This was a marked reduction from the 254 plugged in Refueling Outage EOC8 for defect indications at this location, but was considered by the inspectors to be related, in part, to the limited use of the plus point probe at this location in the mid-cycle outage. During Outage MC9, a circumferential flaw indication was detected in a low radius Row 2 U-bend in Unit 2 Steam Generator E089. As noted above, the licensee responded to this first-time detection in Unit 2 steam generators of a i Iow radius U-bend flaw indication by expanding the scope of plus point probe examinations to include all Row 3 U-bend sections. The inspectors considered the licensee response to appropriately bound the detected degradation. Tube plugging for detected tube wear at supports continued at a moderate rate in Refueling Outage EOC8 and Outage MC9 (i.e.,9 and 20 tubes, respectively). Conclusions The licensee's use of the plus point probe during Unit 2 Refueling Outage EOC8 and Outage MC9 was considered an indicator of management support for examination initiatives that would provide for early detection of degradation in steam generator tubin A marked increase in detected degradation at the top-of-tube sheet location was noted during Refueling Outage EOC8 (i.e.,254 tubes plugged versus 27 tubes plugged in Refueling Outage EOC7). Seventeen tubes and 29 tubes, respectively, were plugged during Refueling Outage EOC8 because of the first time detection of axial tube flaw indications at eggerate support and freespan locations. In Outage MC9, the plugging I totals for eggerate support and freespan axial indications increased, respectively, to j 68 and 166 tube E1.3 Review of Unit 3 Steam Generator Tube Reoair History and Outaae MC9 Eddy Current Examination Scoce and Results Insoection Scoog.(50002)
,
The inspectors reviewed the tube plugging history for the Unit 3 steam generators, including the specific plugging data for Refueling Outage EOC8 and Outage MC9. The primary purpose of Unit 3 Outage MC9 was to perform a reinspection of the steam generators to determine their condition, as a result of the identification in Refueling Outage EOC8 of flow accelerated corrosion induced degradation in the stay cylinder
- _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ __
. _ _ -__-_ _ _ _ ______ -
.
.
-10-region and at the periphery of eggerate supports. The eddy current examinations performed in the MC9 mid-cycle outage focused on obtaining growth information for previously identified wear indications and areas that were likely to exhibit wear, such as scallop bar intersections in the upper partial eggerates (i.e.,08,09, and 10).
b. Observations and Findinas Table 3 lists the cumulative repair history for Unit 3 Steam Generators E088 and E08 As of the end of Outage MC9, a total of 439 tubes and 432 tubes, respectively, have been plugged in Steam Generators E088 and E089 during commercial service, which corresponded to respective inservice repair of 4.70 and 4.62 percent. Both steam generators remained below current approved repair limit Table 4 shows a cumulative compilation for the Unit 3 steam generators of inservice tube degradation by repair location and degradation mode. A previous review of tube degradation history through Refueling Outage EOC7 was documented in Inspection Report 50-361;-362/95-15. The inspectors noted from review of the Unit 3 Refueling Outage EOC8 eddy current examination results that overall steam generator tube degradation continued to remain below that detected in the Unit 2 steam generators, despite very similar effective full power years of operation (i.e., Unit 2,10.1; Unit 3,10.0).
As in Unit 2, axial flaw indications were detected for the first time at eggcrate support and freespan locations during Refueling Outage EOC8. The number of indications found in the Unit 3 steam generators was, however, an order of magnitude lower than the corresponding Unit 2 totals (i.e., eggcrate support - 17 in Unit 2,1 in Unit 3; freespan -
29 in Unit 2,3 in Unit 3). The number of tubes plugged for top-of-tube sheet location axial and circumferential flaw indications increased from 2 in Refueling Outage EOC7 to 27 in Refueling Outage EOC8. The Unit 3 Refueling Outage EOC8 total was, however, approximately an order of magnitude lower than the 254 tubes that were plugged for this degradation mode and location in the corresponding Unit 2 outage. Forty-six tubes (versus 9 tubes in the corresponding Unit 2 outage) were plugged during Unit 3 Refueling Outage EOC8 because of wear at support locations. Data showing the specific locations of tube wear was not reviewed, thus, precluding determination of the extent that the tube wear was associated with peripheral regions of eggerates that had been subject to flow accelerated corrosion degradatio Inspection of previous wear indications (146 tubes) and scallop bar intersections (229 tubes) during Outage MC9 resulted in plugging an additional 22 tubes for wear, 9 tubes in Steam Generator ME088 and 13 tubes in Steam Generator ME089. The inspectors were informed by the licensee that the average change in through wall penetration for previous wear indications was 1.1 and 1.5 percent, respectively, for Steam Generators ME088 and ME089. The inspectors considered the data to be supportive of the licensee's conclusion that chemical cleaning of the steam generators had restored the tube bundle thermal hydraulic conditions and flow characteristics, thus, stabilizing both the growth rate of existing wear indications and generation of new indications. In addition to the 22 tubes removed from service because of eddy current
. _ _ _ _ . _ _ _ ._ _ _ _ _ - _ - _ _ _ _ - - - _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ .____ _ _
.
.
-11-Table 3 W$k:?hkd?N!?$$$h$&#&$dRh$$$$ hh hY Time of Repair / Outage Effective Full SG ME088 SG ME089 of" Tubes Plugged Tubes Plugged Operation Ot Cu Ot Cu IS%i IS%' l Preservice 0.00 24 N/A 11 N/A 7/19842 0.34 0 0 1 0.01 11/19842 0.55 0 0 1 0.02 2/19858 0.69 116 1.24 116 1.26
3EOC 1 (11/1985) 1.02 6* 1.30 20d 1.47 3EOC'2 (1/1987) 1.74 9 1.40 11' 1.59 3EOC'3 (5/1988) 2.81 77 2.22 100 2.66 3EOC'4 (5/1990) 4.33 11 2.34 23 2.91
3EOC 5 (2/1992) 5.74 18 2.53 11 3.03 3EOC'6 (11/1993) 7.13 42 2.98 17 3 21 3EOC'7 (8/1995) 8 49 23 3.23 8 3.29 3EOC58(4/1997) 10.00 106' 4.36 106' 4.43 3MC'9 (3/1998) 10.70 31 4.70 18 4.62 Total Repairs 463 4 Cumulative inservice plugging percentage; 2 - This outage resulted from the identification of ,
a primary-to-secondary tube leak in Steam Generator 3ME089; 3 -This outage resulted from the i previous identification in Unit 2 of batwing support location wear problems; 4 - This plugging total included one tube which was characterized as containing a preservice type defect.; 5 - End of Cycle; 6 - Mid Cycle; 7 - 49 tubes were removed from service because of eggerate support degradation; 8 - 64 tubes were removed from service because of eggerate support degradation
!
!
I
l l
___ _____ _ _ _ _ _ . ___. . _ _
.
e m m
_ h
_
t 0 0 0 2 1 0 1 3 9 0 3 7 9
_
_
_ N O 1 1 2 3 al e
_
Q ? t ebo
_
.
_
Sr p d n
.
.
r
_
A i a .
C l a ka es le wn
'p. e M n n 1 1 0 2 0 0 0 0 0 0 0 0 4 o
r n nit T t A 2 2 e oa bi t ic E
0 uad
4 t
yoi r
cn 4 l r
at a D 'do d r N n oe M
i R . 0 0 0 0 0 0 1 5 8 0 3 0 7
o pw cp D
O I
ie Tr ev e s su uso T P -
ogi v nG i t ien nd e ywpr r t i
V g sr aa d U lu g a e 0 0 2 2 9 7 2 1 2 9 6 2 2 imb n po a 3 7 r f 1 3 2 4 1 4 2 1 Y P W 2 1 6 s R s a2 n O e f it o T b S u on itc I T nU e H
'N f
o ion t i s
r an
.
O o 5 la "A e N Si t I
T F A x 0 0 0 0 0 0 0 0 0 0 3 /
N 3 ic f io n i A it n it r
n a t
D U c a A ei b 4 R idin f
p le G t b E D h ee l0 l
a E
- l t id a c
T B Sa i 0 0 0 0 0 0 0 "A ms s Cx 0 0 0 ou 1 / 1 U EA N T o o t
)
f rd iv d G
S ere e t ( lt p c
'R e
.
u e i r O ir s h s t T C " et r e A 'S
-
R T Tl
& 0 0 0 0 0 0 0 0 0 2 7
A
/
N
2 em go r
n 1 E ia o
-
N x t af r it E A ud c G oe t e
p M sl c
.
u s A 2 2d r ih s n E i Te r I T Rne C -
S /
& 0 0 0 0 0 0 0 0 0 0 6 "A 6 -
B /
e 4 3 1 - . N 0 g1 T RU x 1 a
I A ;t
e N eul U voc y o
S G 's biCs Y ah N 4 5 9 2 4 1 3 4 3 9 0 0 Tid O P 3 5 6 0 7 8 3 7 1 4 0 7 2 S F 0 O 0 2 4 5 7 8 0 0
-
M E
-
E 1 1 1 1 le 1 -
b1
'
s r a;3 ia p
T9 1 e
e8 ; e e ) )
R e0l g
a
8
)
7 8
)
)
) 3
)
5 7
)
) S Ec y f t 9 8 8 9 9 9 9 9 8 la M C ou 1 9 9 9 9 1 9 9 9 to 3 eO /
1
/ / / /
1 1 1
/ 1
/ /
1 9 T 9 r
f o
~
im/r T ia *
'
'4 "
(
(
5(
5(
(
(
(
(
/
h o gt d p
e
'4
8
5
2 1 2
3 2 2 4 2 5 6 2 2
2 8 (
9 u ran R 9 1 9 'C 'C 'C 'C 'C 'C iC 'C " or eE
/
/
1
/ O O O O O O O O C h ne -
.
7 1 2 E E E E E E E E M t
l 1 G1
- I l
_ _ _ _ _ _ - - - _ _ _ - _ - -
.
-13-examination identified wear indications, a further 27 non-degraded tubes were
.
preventively plugged because of both flow induced vibration criteria and by assuming I
that observed eggerate thinning was also present in adjacent areas that the inspection camera was obstructed in viewing. No wear was detected by eddy c,urrent examination of the 13 tubes that were plugged because of flow induced vibration criteri Conclusions Through Refueling Outage EOC8, the extent of Unit 3 steam generator tube degradation remained below that detected in the Unit 2 steam generators, despite very similar effective fu!! power years of operation. The respective numbers of identified flaw indications at the top-of-tube sheet location, eggerate . supports, and in the tubing freespan were approximately an order of magnitude lower in Unit 3 than the corresponding Unit 2 totals. The Outage MC9 eddy current examination and visual inspection data was considered supportive of the licensee's conclusion that chemical cleaning of the steam generators had restored the tube bundle thermal hydraulic conditions and flow characteristics, thus, stabilizing both the growth rate of existing wear indications and generation of new indications E1.4 Review of Unit 2 Steam Generator Secondary Side Internals inspections During Unit 3 Refueling Outage EOC8, secondary side visualinspections of the steam generators were performed in support of chemical cleaning. These inspections identified degradation of eggcrate supports in both steam generators. The licensee attributed the damage to erosion / corrosion caused by excessive deposit buildup in the steam generators. The damage was ascertained to be limited to the periphery of the tube bundle and to the untubed region of the stay cylinder. At the time, the licensee had limited visual evidence that similar degradation of the Unit 2 steam generator eggerate supports had not occurred. As a result of the Unit 3 findings, the licensee planned to perform more extensive Unit 2 steam generator secondary side visual inspections during Outage MC9 in order to assess the condition of the eggerate support Insoection Scoce (50002)
The inspectors reviewed Unit 2 steam generator secondary side visualinspection program requirements and results and compared the observed eggerate degradation against the Unit 3 secondary side visualinspection results that were obtained in the prior Unit 3 refueling outag Observations and Findinas Based on the Uni'. 3 inspection results, the licensee planned a Unit 2 inspection scope of 20 percent of the tubes and eggcrate supports (3H-10H) on the hot leg side of the steam generators at the periphery of the tube bundle. The actualinspection scope was somewhat larger, with inspections performed of 3H-10H eggerate supports and 75 and 92 peripheral tubes, respectively, in the two steam generators. This inspection scope
.
___
_ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _
.
.
-14-corresponded to 30 and 40 percent samples of peripheral tubes on the hot leg side of the steam generators. The licensee also performed secondary side visual inspections in the stay cylinder region of one steam generator. The licensee noted during these inspections that erosion / corrosion of the Unit 2 eggerate supports had occurred, but the extent and magnitude was approximately an order of magnitude less severe than previously seen in the Unit 3 steam generators. No preventive plugging of Unit 2 tubes was determined to be necessary as a result of eggerate degradation. Licensee staff informed the inspectors that future secondary side inspections of eggerate conditions were planned in order to establish a degradation rate, assuming some amount of erosion / corrosion continues to occur in the steam generators. The inspectors viewed several videotapes of the Units 2 and 3 visual inspections, with the content and quality of the videotapes noted to be supportive of the licensee's analyses. The inspectors considered the scope of the secondary side visualinspections to be satisfactory and the results supportive of the licensee's root cause evaluation and conclusions with respect to tube plugging criteri The inspectors reviewed the Units 2 and 3 secondary side visual inspection requirements contained in Procedures SO3-XVil-4.3, " Steam Generator Secondary Side Visual Inspection for SONGS Unit 3," Revision 0; SO23-XXVI-14.802, " Steam Generator Eggcrate inspection Assessment," Revision 0; and SO23-XXVI-14.801, " Steam Generator Secondary Side Visual inspection." Revision 0. During this review, the inspectors noted deficiencies in the documents, such as missing figures, attachments, step numbers, references, etc. The inspectors concluded, after evaluation of the deficiencies, that their significance was both minor and did not cause incomplete or inadequate secondary side inspections. The inspectors brought the deficiencies to the attention of licensee personnel, who responded by issuir.g change notices to correct the deficient procedures. The licensee also opened an " Action Request" that will require 1 some additional training on the preparation and execution of procedures, and will also revise the procedural requirements related to minor procedural deficienchs in order to clarify licensee expectation Conclusions The scope of Unit 2 steam generator secondary side visualinspections was considered satisfactory, with the results indicating that the extent and magnitude of flow accelerated corrosion of the eggcrate supports was approximately an order of magnitude less severe j than previously seen in the Unit 3 steam generator j i
E Unit 2. Cvele 9 Operational Assessment Insoection Scoce (50002)
The inspectors reviewed the bases fer the various inputs and assumptions used in the Aptech Engineering probabilistic assessment entitled, "A Probabilistic Operational Assessment of Steam Generator Tube Degradation at SONGS Units 2 for Cycle 9,"
l E_________________________..____ j
- - _- - ____-______ _- _ - .
.
.
-15-Revision 2, September 1997. The inspectors specifically addressed if the assessment used appropriately conservative values for: (1) bobbin coil probe probability of detection, (2) burst pressures and leak rates, and (3) crack growth rate b. Observations and Findinas The inspectors noted in regard to the bobbin coil probe probability of detection of axial cracking, that the probabilistic assessment relied, in part, on what appeared to be a comprehensive licensee qualification effort using pulled tube data from Unit 2. With respect to the assumed burst pressures and leak rates, the inspectors verified that the recent Unit 2 pulled tube results (contained in Report S-PENG-TR-009, " Examination of Steam Generator Tubes Removed from SONGS Unit 2 in 1997," dated January 1998)
were bounded by the assumptions used in the probabilistic assessment. With respect to the crack growth rates used in the analysis, the licensee contractor stated that use of San Onofre-specific data was inappropriate, based on a " benchmark" of the outage inspection results, and thus the contractor relied on crack growth rates from a similar plant that the contractor believed bounded several plants that were similar in design to Unit 2. The inspectors could neither directly verify the source of the crack growth rate data, nor evaluate the results of the various contractor benchmarking efforts, because the data was located at the contractor's facility. The inspectors noted that the licensee will be able to obtain a true benchmarking of the probabilistic analysis at the end of the Unit 2 Outage MC9, when the licensee can compare actual results with the predictions made in the operational assessment. The licensee committed (in its February 20,1998, special report to the NRC on Unit 2 Outage MC9 steam generator tube examination results) to provide an update within 90 days of the end of Outage MC9 of the run time analysis that was provided in a September 26,1997, submittal to the staf The inspectors noted that the probabilistic assessment supported the licensee's conclusion that rotating probe tube examinations were not necessary in the top-of-tubesheet region during Unit 2 Outage MC9 to ensure steam generator tube integrity. The inspectors additionally reviewed the top-of-tubesheet eddy current examination results that were obtained during the prior Refueling Outage EOC8. The inspectors concluded from this review that the licensee's position appeared to be technically justified, based on the relatively small size and number of top-of-tubesheet indications, the comprehensive inspection scope at this location (i.e.,100 percent of the I hot leg and a sampling of the cold leg in both steam generators), the use of a sensitive rotating probe (i.e., the plus point probe), and the acceptable in-situ pressure test results that were obtained from testing tubes, which contained some of the largest top-of-tubesheet circumferential and axial flaw c. Conclusions Review of a Unit 2 probabilistic operational assessment for Cycle 9 was limited by much of the supporting data being offsite at the contractor's facility. The results from recent Unit 2 pulled tubes were found to be bounded by the burst pressure and leak
. rate assumptions used in the Unit 2 assessment. The assessment and Refueling l
l l
L--------------_----.-----_ J
-_- _ _ - _ - - _ _ _ _ - _ _ . _ - _ _ - _ _ _ _ _ _ _ _ _ _ . _ _ _ . _ _ _ . _ . _ _ _ _ .
.
-16-Outage EOC8 eddy current results supported the licensee's conclusion that rotating probe examinations were not necessary at the top-of-tube sheet region during Unit 2 Outage MC9 to ensure steam generator tube integrit E8 Miscellaneous Engineering Issues (92903)
E (Closed) Insoection Followuo item 50-361: 362/9514-01: Conformance of eddy current examination procedures to Appendix H of Electric Power Research Institute Document EPRI NP-6201, "PWR Steam Generator Examination Guidelines," Revision The inspectors ascertained that the licensee was actively beginning implementation of Revision 5 of the Electric Power Research Institute "PWR Steam Generator Examination Guidelines." Under the criteria contained in NEl 97-06, utilities are expected to fully implement Revision 5 of the Electric Power Research Institute PWR Steam Generator Examination Guidelines," by the first outage following January 1,1999. The inspectors noted that Revision 5 specifically required utility cognizance of examination technique qualifications and applicability to site-specific conditions. Accordingly, the adoption of Revision 5 assures the use of essential variables that are consistent with the supporting technique qualification E8.2 (Closed) Unresolved item 50-361/9705-04: Incorrect steam generator primary manway gasket installe Backaround l
Violation A (50-361/9719-03) was identified in Inspection Report 50-361;-362/97-19 pertaining to the 1997 installation of an incorrect steam generator primary manway cover gasket in Unit 2 Steam Generator 2E089. The inspection, which identified this violation, was a follow up to Unresolved item 50-361/9705-04. The licensee responded by letter dated November 7,1997, with a denial of Violation A in Inspection Report 50-361;-362/97-19. The licensee was subsequently informed by letter dated January 26,- 1998, that Unresolved item 50-361/9705-04 was being reopened, and that the NRC would perform further inspection of the issue. The scope of inspection was indicated to include determining whether safety-related maintenance procedure requirements were complied with during installation of the (incorrect) gasket, determining what other quality barriers failed in allowing the incorrect gasket to be installed in the primary coolant system, and reviewing the basis for classification of the gasket as a nonsafety-related par Followuo insoection The inspectors reviewed the procurement history for the steam generator primary manway gaskets with licensee personnel and noted (from Purchase Order 65900551 dated September 1983 to Combustion Engineering) that early licensee procurement
- classified the gaskets as safety-related, The purchase order required that quality L assurance documentation be furnished in accordance with a master agreement for spare
! I
! I
_ - _ _ _ - _ - _ _ _ _ _ -
.
.
-17-and replacement parts, but did not specifically identify applicable technical and quality requirements in 1989, Combustion Engineering proposed (in a supplier deviation request) a change to a nonsafety-related classification for the gaskets. This proposed change was disapproved by the licensee. The inspectors were informed by licensee personnel that a change was subsequently made by the licensee to a nonsafety-related classification for primary and secondary manway gaskets. This change was accomplished by issue of Component Classification Evaluation Document 70074,
" Unit 2/3 Steam Generators," Revision 0, dated August 28,1990. The inspectors noted from review of Component Classification Evaluatic' Document 70074, Revision 0, that the nonsafety-related classification for the gaskets was based on the gaskets being considered: (1) not essential to maintain the system pressure boundary, (2) not essential for the component to perform its safety-related function, and (3) having no credible failure that would prevent the component from performing its safety-related functio '
The inspectors questioned licensee staff regarding the criteria that were used in the gasket evaluation process. Licensee staff informed the inspectors that Component {
Classification Evaluation Document 70074, Revision 0, was prepared in accordance with Nuclear Engineering, Safety & Licensing Department Procedure 37-7-11, " Quality Classification of Components and Piece Parts," Revision 0. This document was also issued as Site Procedure S0123-XXXll-2.11, Revision O. Licensee staff also informed the inspectors that the procedure, which was issued on June 20,1990, utilized the criteria and guidelines developed by the Electric Power Research Institute for parts re-classification. The primary Electric Power Research guidance document used was indicated to be NP-5652 (NCIG-07), " Guideline for the Utilization of Commercial Grade items in Nuclear Safety Related Applications," which was endorsed by the NRC in Generic Letter 89-02. Procedure 37-7-11, Revision 0, was also stated to have utilized additional guidance contained in NP-6406 (NClG-11), " Guidelines for the Technical l Evaluation of Replacement items in Nuclear Power Plants," pertaining to parts classification and failure modes and effects analysi The inspectors reviewed Procedure 37-7-11, Revision 0, and supplementary information provided by the licensee regarding the evaluation process that was
-)I used for determination of the safety classification for the steam generator primary and secondary manway gaskets. It was noted during this review that the licensee classification criteria (contained in Attachment 2 to Procedure 37-7-11, Revision 0)
encompassed the definition of safety-related structures, systems and components contained in 10 CFR 50.2 (i.e., that are relied upon to remain functional during and following design basis events to assure: the integrity of the reactor coolant pressure boundary, the capability to shut down the reactor and maintain it in a safe shut-down condition, or the capability to prevent or mitigate the consequences of accidents, which could result in potential offsite exposures comparable to 10 CFR Part 100 guidelines).
The inspectors concluded that the evaluation criteria developed by the licensee were
- appropriate for reaching a correct safety classification for replacement parts. The inspectors also concurred with the licensee analysis of each of the individual classification criteria. The failure modes analysis determined that joint leakage across or through the gasket represented a credible occurrence which warranted additional review l
l l
- - _ _ - _ _ - - - _ - _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ - _ _ _ _ - - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _
.
.
,
-18 .
i as to its consequence in the failure effects analysis for this condition, the licensee assumed a worst-case leak (i.e., where the gasket had split across its face and separated radially) and coincident common-mode failure of all four primary steam generator manway gaskets and one pressurizer manway gasket. These failures were calculated by the licensee to represent a cross-sectional leak area of 0.027 iri, which was fully bounded by the analysis for small break loss-of-coolant accident discussed in Sections 6.3.3.3 and 15.6 of the Updated Final Safety Analysis Report.
,
Independent analysis by ABB Combustion Enginee-ing of a worst-case leak area (if all l five installed steam generator primary manway and pressurizer gaskets failed) resulted in a value of 0.02626 irf which showed good agreement with the licensee analysis. ABB
,. Combustion Engineering calculated the maximum flow rate from this leakage area to be l 35.27 gallons per minute, with actual flow rate expected to be significantly lower due to~
- the restriction created by the metal-to-metal contact between the vessel shells and the manway covers. Leakage of 35.27 gallons per minute was also noted to be well within
- - the capacity of a single charging pump. As the result of this finding, ABB Combustion l Engineering concluded that the gasket failures did not qualify as a loss-of-coolant accident as defined in the Final Safety Analysis Repor The inspectors reviewed Procedures SO23-1-6.113, " Removal and installation of Steam Generator (Primary) and Pressunzer Manway Covers," Revision 6, and Temporary Change Notice 6-1, and Procedure SO123-1-1.3, " Work Activity Guidelines," Revision No deficiencies were noted with respect to maintenance personnel performance. The gaskets installed were of the correct material code and the inspectors did not see en apparent basis for an expectation that maintenance personnel could have identified the gaskets were incorrec As discussed in Inspection Report 50-361;-362/97-19, the licensee initiated i
! comprehensive reviews and corrective actions for tha noted procurement problem. The
- inspectors concluded during this inspection that the licensee's 1990 change to a l nonsafety-related classification for primary and secondary manway gaskets was technic 4lly appropriate. Accordingly, the inspectors considered that the licensee's denial of a violation against the requirements of 10 CFR Part 50, Appendix B, was justifie IV. Plant Suncort l
R1 Radiological Protection and Chemistry Controls j R Iron Transoort to Units 2 ano 3 Steam Generators (50002) Insoection Scooe The inspectors performed a review of trend data from January 1996 through January 1998 for iron transport to the Units 2 and 3 steam generator i
/
-_ _ - - _ _ - _ _ _ _ _ __ ._. -_
1 \
-
l l l ,
I-19-b. Observations and Findings The results of initial review of Units 2 and 3 iron transport to the steam generators through Cycle 7 were documented in inspection Report 50-361;-362/95-14. The inspectors concluded from the 1995 review that iron transport was the only secondary chemistry icsue warranting continued management attention. The respectivo Units 2 ,
and 3 average feedwater iron values for the final 3 months of Cycle 7 were 5.4 ppb and i 6.4 pp The inspectors noted during the current review that Unit 2 iron transport was somewhat higher in the first 3 months of 1996 than in the final 3 months of Cycle 7 in early 1995, with feedwater iron values ranging between 7 ppb and 8 ppb. Corresponding Unit 3 iron transport values were lower in the first 3 months of 1996 than in the final 3 months of Cycle 7 in mid-1995, with feedwater iron values ranging between 4 ppb and 5 ppb. The inspectors noted that, subsequent to the first quarter of 1996, the licensee was successful in significantly reducing iron transport to the Units 2 and 3 steam generators (by use initially of direct ammonia injection and then replacement of ammonia with ethanolamines for pH control). Review of the trend data indicated to the inspectors that j feedwater iron values in the range of 4 ppb to 5 ppb were attained in steady state i conditiens with direct ammonia injection. Conversion in 1997 to ethanolamines resulted in further improvement in iron transport, with current addition levels producing feedwater iron values in the range of 2 ppb to 2.5 ppb. The inspectors considered licensee efforts i in the last 2 years to significantly reduce iron transport to the steam generators, and thereby minimize fouling and deposit builduo, to be an indicator of both excellent
]
chemistry staff performance and management support for steam generator tube integrity initiative c. Conclusions Licensee efforts in the last 2 years, including adoption in 1997 of ethanolamines for pH control, have resulted in a significant reduction in iron transport to the Units 2 and 3 steam generator V. Manaaement Meetings X1 Exit Meeting Summary The inspectors presented the results of the initial onsite inspection to members of management on February 6,1998. The licensee acknowledged the findings presente Additional telephonic exit meetings were conducted on March 10 and April 10,199 l One ABB Combustion Engineering document was reviewed during the inspection which I
'
was considered to be proprietary. No information was included in the inspection report from this documen _ _ _ _ _ _ _ _ - _ _ _ _ . _ _ _ _ _ _ _ _ _
- _ _ _ - - - _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ - _ _ _ _ _ _
.
.
ATTACHMENT SUPPLEMENTAL INFORMATION PARTIAL LIST OF PERSONS CONTACTED Licensee i
D. Axline, Compliance Engineer, Nuclear Regulatory Affairs J. Clark, Manager, Chemistry ]
R. Clark, Manager, Quality Engineering, Nuclear Oversight Division G. Cook, Supervisor, Compliance, Nuclear Regulatory Affairs R. Coe, Engineer Ill, Site Technical Services G. Gibson, Manager, Compliance, Nuclear Regulatory Affairs T Herring, Manager, Procurement Engineering, Site Support Services R. Krieger, Vice President, Nuclear Generation T. Mackey, Supervisor, Procurement Engineering (Civil / Mechanical), Site Support Services A. Matheny, Steam Generator Engineer, Site Technical Services H. New'.on, Manager, Support Services D. Nunn, Vice President, Engineering and Technical Services M. Short, Manager, Site Technical Services Framatome-Rockridge J. Funanich, Lead Level lil Eddy Current Examiner R. Marlow, Vice President R. Penn, Site Manager NRC J. Sloan, Senior Resident inspector INSPECTION PROCEDURES USED 50002 Steam Generators 92903 Followup-Engineering ITEMS CLOSED Closed 50-361/9514-01 IFl Conformance of eddy current examination procedures to 50-362/9514-01 Appendix H of EPRI NP 6201, Revision 3 50-361/9705-04 URI Incorrect steam generator primary manway gasket installed
_ _ - _ _ _ - _ _ - _ _ - _ _ _ - - -
.. . . . . _ _ _ - _ _ _ - _ _ - _ - -- ._- . _ _ .
.
,
,
-2-DOCUMENTS REVIEWED
" Data Analysis Guideline-Sar: Onofre Nuclear Generating Station, Units 2 and 3," Revision 8 l Procedure SO23-XXVil-23.1 " Examination Technique Specification Sheet (ETSS) Bobbin
! Exam, Acquisition # 1," Revi . ion 6 Procedure SO23-XXVil-23.1, " Examination Technique Specification Sheet (ETSS) 0.115 Pancake & Plus-Point, Acquisition # 2," Revision 6
!
'
Procedure SO23-XXVil-23.1, " Examination Technique Specification Sheet (ETSS) 0.115 Pancake, Plus-Point & 0.080 High Frequency, Acquisition # 3," Revision 6 Procedure SO23-XXVil-23.1, " Examination Technique Specification Sheet (ETSS) Plus-Point'U-l Bend, Acquisition # 4 " Revision 6 t
l Procedure SO23-XXVil 23.1, * Examination Technique Specification Sheet (ETSS) Multi-Coil Profilometry, Acquisition # 5," Revision 6
Procedure SO23-XXVil-23.1, * Examination Technique Specification Sheet (ETSS) Plug MRPC,
~ Acquisition # 6," Revision 6 l Procedure SO23-XXVil-23.1, " Examination Technique Specification Sheet (ETSS) 3-Coil MRPC l (0.115" dia), Acquisition # 7 " Revision 6
' Procedure SO23-XXVil-23.1, " Examination Technique Specification Sheet (ETSS) 0.080 HF Shielded U-Bend, Acquisition # 8," Revision 6 Procedure SO23-XXVil-23.1, " Examination Technique Specification Sheet (ETSS) 0.115 i Pancake, Plus-Point & Mag Bias Plus-Point, Acquisition # 9," Revision 6 Procedure SO23-XXVil-23.1, " Examination Technique Specification Sheet (ETSS) Reduced Speed Plus-Point U-Bend, Acquisition # 10," Revision 6
.' Analysis Technique Specification Shaet ANTS # 1, * Bobbin Exam," Revision 4 Analysis Technique Specification Sheet ANTS # 2, "O.115 Pancake & Plus-Point," Revision 2
Analysis Technique Specification Sheet ANTS # 3, "0.115 Pancake, Plus-Point & 0.080 High Frequency," Revision 1 Analysis Technique Specification Sheet ANTS # 4, "Plus-Point U-Bend," Revision 1 Analysis Technique Specification Sheet ANTS # 8, "For PLPs in Bobbin Exam," Revision 0 l
_-_-___-__________-_-___a_______--_-_--____-
. - _ _ _ _ - _ _ _ _ - - _ _ - _ _ _ - _ _ _ - - -
_ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
.
.
-3-Analysis Technique Specification Sheet ANTS # 10, "0.115 Pancake, Plus Point & Mag Bias Plus Point," Revision 0 Procedure SO123-XXXII-2.11 " Quality Classification of Components and Piece Parts,"
Revision 0 Nuclear Engineering, Safety & Licensing Procedure 37-7-11, " Quality Classification of Components and Piece Parts," Revisions 0 and 1
'
Procedure SO123-X11-20.4, " Receiving Inspection," Revision 2 Procedure SO123-XI-3.6, " Receiving of Material and Equipment by SONGS Warehouse,"
Revision 3 Procedure SO123-1-1.3, " Work Activity Guidelines," Revision 5 Failure Analysis Report 97-014. " Failure Analysis of the Steam Generator Primary fAanway Gaskets," Revision 1
- Action Requests 970400152 and 970501180 Supplier Deviation Request 6D015901-N002, dated July 12,1989 Component Classification Evaluation Document 70074, Revision 0 Report " Steam Generator Primary Manway Gasket Evaluation," dated April 10,1997 .
l l
L_______________-___-____-_-______ _ . - - _ _.