IR 05000528/1995019
| ML17311B302 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 12/05/1995 |
| From: | Brockman K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17311B300 | List: |
| References | |
| 50-528-95-19, 50-529-95-19, 50-530-95-19, NUDOCS 9512120069 | |
| Download: ML17311B302 (44) | |
Text
ENCLOSURE U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-528/95-19 50-529/95-19 50-530/95-19 Licenses:
NPF-41 NPF-51 NPF-74 Licensee:
Arizona Public Service Company P.O.
Box 53999 Phoenix.
Arizona Facility Name:
Palo Verde Nuclear Generating Stations Units 1. 2.
and
Inspection At:
Palo Verde Nuclear Generating Station, Maricopa County, Arizona Inspection Conducted:
October 30 through November 3, 1995 Inspectors:
I. Barnes
~ Technical Assistants Division of Reactor Safety K.
D. Weaver.
Reactor Inspector, Maintenance Branch Division of Reactor Safety Approved: /.
net
.
r man~.
epu y erector ivision o~f eact Safety a
e Ins ection Summar Areas Ins ected Units
2 and 3:
Regional initiative and core, announced inspection of inservice inspection activities and followup to the 1994 steam generator tube integr ity review.
Results Units
2 and 3:
Steam Generator Tube De radation Status
~
The predominant steam generator tubing degradation modes in Unit 1 has continued to be circumferential primary water stress corrosion cracking, circumferential outside diameter stress corrosion cracking.
and axial 95aaca0OS9 95<a07 PDR ADQCK 05000528
I f
't
-2-outside diameter stress corrosion cracking at the top of the tube sheet.
The total number of tubes plugged during operational service through Refueling Outage 1R5 was. respectively.
161 in Steam Generator l-l and 276 in Steam Generator 1-2 (Section Z. 1).
~
The predominant steam generator tubing degradation mode in Unit 2 has continued to be upper bundle axial outside diameter stress corrosion cracking in both the mid span and at supports.
A limited incidence of axial and circumferential stress corrosion cracking has been found at the, top of the tube sheet in the last two outages.
The total number of tubes plugged during operational service through Refueling Outage 2R5 was, respectively, 405 in Steam Generator 2-1 and 1158 in Steam Generator 2-2 (Section 2.2).
The predominant steam generator tubing degradation mode in Unit 3
~
as for Unit 2.
has continued to be upper bundle axial outside diameter stress corrosion cracking in both the mid span and at supports.
In the last two outages.
limited incidence of axial and circumferential stress corrosion cracking has also been found in this unit at the top of the tube sheet.
The total number of tubes plugged during operational service through Refueling Outage 3R5 was, respectively, 97 in Steam Generator 3-1 and 110 in Steam Generator 3-2 (Section 2.3).
The overall steam generator plugging totals for identified stress corrosion cracking continued to vary significantly between units.
The current Unit 2 steam generator plugging total for identified stress corrosion cracking was, respectively, approximately 4.5 times and
times as high as the cor responding plugging total in Units 1 and
(Section 2.4).
Plant 0 erations
~
Not applicable during this inspection.
Maintenance Inservice inspection nondestructive examinations were observed to be performed in accordance with procedural requirements by appropriately certified personnel.
The examiners demonstrated appropriate rigor in the evaluation of questionable indications (Sections 6. 1 and 6.2).
Welding procedures were found to comply with ASHE Section IX Code-requi rements.
but were considered permissive with respect to allowable parameters.
Considerable latitude was noted to be given to first-line supervision in the approach used for the fabrication and installation of subassemblies (Section 6.3).
~
The licensee was appropriately monitoring and repairing steam generator nozzle leaKage (Section 7. 1 4).
f j
C
En ineerin-3-
The licensee has developed an excellent eddy current examination program following the March 1993 tube rupture in Steam Generator 2-2.
The licensee was considered proactive in its implementation of new.
more sensitive eddy current examination methods (Section 3. 1).
Plant Su ort
~
Not applicable during this inspection.
Mana ement Overview
~
The use of a dedicated multi-disciplinary steam generator staff was viewed as an indicator of management involvement and support for strong steam generator engineering programs (Section 3. 1).
Supervisory oversight of the inservice inspection personnel and activities was good (Section 6. 1).
Summar of Ins ection Findin s:
Licensee Event Report 530/94-004 was closed (Section 7. 1)
Inspection Follow-Up Item 528:529;530/9415-01 was closed (Sections 2.4 and 7.2.1).
Inspection Follow-Up Item 528:529/9415-02 was closed (Sections 3.1 and 7.2.2).
Inspection Follow-Up Item 529;530/9415-04 was closed (Sections 4 and 7.2.3).
Attachment; Attachment
- Persons Contacted and Exit Meeting
I l
J I
'1
-4 DETAILS
STEAH GENERATOR TUBE INTEGRITY REVIEW FOLLOW-UP (92903)
The objectives of this part of the inspection were:
(a) to ascertain the current degradation status of the Units 1, 2, and 3 steam generator tubing:
and (b) to review actions taken to further strengthen the effectiveness of licensee programs for the detection and analysis of degraded tubing. repai r of defects.
and correction of conditions contributing to tube degradation.
This part of.the inspection was performed by a single inspector during October 30 through November
~
1995. 'he inspection scope and findings are documented in Sections 2 through 5 below.
STEAH GENERATOR TUBE DEGRADATION HISTORY An initial review of Units 1, 2, and 3 steam generator tube degradation history was documented in Inspection Report 50-528; 529; 530/94-15.
This initial review encompassed Unit 1 tube examination results through Refueling Outage 1R4 (October 1993), Unit 2 tube examination results through Hid-Cycle Outage 2HC5-1 (Harch 1994).
and Unit 3 tube examination results through Refueling Outage 3R4 (April 1994).
Wear and stress corrosion cracking were noted to be the most prevalent degradation mechanisms in all three units.
Despite similar unit effective full power years of operation.
the incidence of tubing stress cor rosion cracking varied significantly between units (i.e.,
the number of tubes plugged in Unit 2 steam generators because of identified stress corrosion cracking was, respectively.
approximately 4 and 18 times higher than the corresponding plugging totals in Units 1 and 3).
The type and location of stress corrosion cracking also were not consistent between units.
In the Units 2 and 3 steam generators'he majority of tube stress corrosion'racking was axial, initiated on the outside diameter.
and was located in the upper tube bundle in the mid span of tubes and at supports.
The degradation was concentrated in an "arc" region of tubes near the periphery of the tube bundle.
Licensee thermal-hydraulic analysis confirmed that the location of degradation occur red in a dry-out region.
and which would result in concentration and deposition of impurities on the tube surfaces.
In the Unit 1 steam generators, however.
the stress corrosion cracking was located in the vicinity of the top of the tube sheet.
In addition to axial outside diameter stress corrosion cracking, circumferential primary water stress corrosion cracking and circumferential outside diameter stress corrosion were also detected at this location.
During the current inspection.
a review was performed of the Units 1. 2.
and
steam generator tube examination results that were obtained in outages that occurred subsequent to the initial review (i.e.. Unit 1, Refueling Outage 1R5; Unit 2. Hid-Cycle Outage 2HC5-2 and Refueling Outage 2R5: Unit 3. Hid-Cycle Outage 3HC5 and Refueling Outage 3R5).
l
-5-2.1 Unit 1 Refuelin Outa e
1R5 Tube examinations were performed during Refueling Outage 1R5 which occurred from April 1 through May 16, 1995.
Table 1 below provides the plugging history for the two steam generators through this outage as a function of effective full power years of operation at the time of repair.
Table
STEAN GENERATORS (SGs) l-l AND 1-2 TUBE REPAIR HISTORY Time of Repair Operational Time SG 1-1 SG 1-2 Unit 1 Refueling EFPYs"'uta e (1R)
Tubes Plugged Tubes Plugged Pre-Commercial Pre-1R1 (2/87)
1R1 (11/87)
1R2 (8/89)
1R3 (3/92)
1R4 (10/93)
1R5 (4/95)
NDA'~'.22 2.00 3.37 4.57 5.79 20<3)
23
39
14(
)
126 109 Total Re ai rs X Re airs ( Inservice, Total)
169 1.46.
1.53 302 2.51.
2.74 (1)
- Effective full power years:
(2)
-
No data available:
(3)
- The reasons for the plugging activity were not reviewed.
The Refueling Outage 1RS tube examinations resulted in the identification of further circumferential and axial stress corrosion cracking.
Nineteen tubes were plugged in Steam Generator 1-1 because of the detection on the hot-leg side of circumferential stress corrosion cracking at the top of the tube sheet (i.e...
6 tubes, primary water stress corrosion cracking; 13 tubes'utside diameter stress corrosion cracking).
Fifty-seven tubes were plugged in Steam Generator 1-2 because of the detection of circumferential stress corrosion cracking at this location (i.e..
15 tubes'rimary water stress corrosion cracking:
42 tubes, outside diameter stress corrosion cracking).
Thirteen tubes were plugged in Steam Generator 1-1 because of the detection on the hot-leg side of axial outside diameter stress corrosion cracking (i.e.,
cracking in 7 tubes at the top of the tube sheet.
3 tubes at mid span.
1 tube at a support.
and 2 tubes at mid span and a support).
'The corresponding plugging total in Steam Generator 1-2 for axial outside diameter stress
l
-6-corrosion cracking on the hot-leg side was 32 tubes (i.e.. cracking in 10 tubes at the top of the tube sheet.
1 tube at the flow distribution plate.
tubes at mid span.
6 tubes at tube supports.
and 4 tubes at mid span and tube supports).
Three tubes in Steam Generator 1-1 and 19 tubes in Steam Generator 1-2 were preventively plugged in Refueling Outage 1R5 because of the identification of incomplete tube-to-tube sheet expansion (i.e.. which creates a crevice condition that may act as an initiation site for stress corrosion cracking).
A total of four other tubes in Steam Generator l-l were plugged during this outage, three because of identified volumetric indications and one tube for what was listed in the licensee information reviewed as a defect category of
"other."
One tube was plugged in Steam Generator 1-2 because of wear at the batwing stay cylinder.
2.2 Unit 2 Unit 2 steam generator tube examinations were performed during Mid-Cycle Outage 2MC5-2 (September 17 through October 15, 1994)
and during Refueling Outage 2R5 (February 4 through April 1.
1995).
Table 2 below provides the plugging history for the two steam generators through Refueling Outage 2R5 as a function of effective full power years of operation at the time of repair.
2.2. 1 Mid-Cycle Outage 2MC5-2 Tube examinations performed during Mid-Cycle Outage 2MC5-2 resulted in the plugging of 63 tubes on the hot-leg side of Steam Generator 2-1 as a result of the identification of upper bundle "arc" region axial outside diameter stress corrosion cracking (i.e.
~ cracking in 54 tubes at mid spank'nd 9 tubes at supports).
The corresponding plugging total in Steam Generator 2-2 for upper bundle axial "arc" region outside diameter stress corrosion cracking on the hot-leg side was 144 tubes (i.e.
~ cracking in 130 tubes at mid span, 9 tubes at supports'nd 5 tubes at mid span and supports).
One tube was plugged in Steam Generator 2-1 and five tubes in,Steam Generator 2-2 because of identified axial hot-leg side outside diameter stress corrosion cracking at the top of the tube sheet.
Three tubes in Steam Generator 2-1 were plugged
"because of wear at upper bundle supports (i.e.,
one tube at a vertical support, two tubes at a batwing support).
The corresponding plugging total for wear in Steam Generator 2-2 was four tubes (i.e.,
one tube at a vertical support.
three tubes at a batwing support).
Three tubes and two tubes, respectively, were plugged in Steam Generators 2-1 and 2-2 because of identified volumetric indications.
2.2.2 Refueling Outage 2R5 Tube examinations performed during Refueling Outage 2R5 resulted in the plugging of 91 tubes in Steam Generator 2-1 because of identified upper bundle
"arc" region hot-leg side axial outside diameter stress corrosion cracking (i.e.. cracking in 59 tubes at mid span, 28 tubes at supports, and four tubes
-7-at mid span and supports).
The corresponding plugging total in Steam Generator 2-2 for upper bundle "arc" region axial outside diameter cracking stress corrosion cracking was 256 tubes (i.e., cracking in 172 tubes at mid span.
54 tubes at supports.
and 30 tubes at mid span and supports).
Two tubes in Steam Generator 2-1 and four tubes in Steam Generator 2-2 were plugged because of the identification of axial outside diameter stress corrosion cracking at the top of the tube sheet.
Two tubes were plugged in Steam Generator 2-1 because of the identification of circumferential primary water stress corrosion cracking at the top of the tube sheet.
An additional nine tubes were plugged in Steam Generator 2-1 because of the detection at the top of the tube sheet of mixed mode outside diameter stress corrosion cracking (i.e.. axial and circumferential cracks both present).
The corresponding plugging totals in Steam Generator 2-2 because of the identification of circumferential and mixed mode outside diameter stress corrosion cracking at the top of the tube sheet were 2 tubes and 15 tubes'espectively.
Table
STEAN GENERATORS (SGs)
2-1 AND 2-2 TUBE REPAIR HISTORY Time of Repair Unit 2 Refueling Outage (2R)
Pre-Commercial Pre-2R1 (2/87)
2R1 (4/88)
2R2 (4/90)
2R3 (11/91)
2R4 (3/93)
ZMC5-1"'3/94)
ZMC5-2"'9/94)
2R5 (2/95)
1.22 2.30 3.49 4.62 4.95 5.32 5.60 SG 2-1 Tubes Plugged
30
20
74
70 124 SG 2-2 Tubes Plugged
21
90
174 371 156 293 Total Re ai rs 420 1190 X Repairs ( Inservice, Total)
3.68.
3.81 10.51, 10.81 (1)
- Effective full power years; (2) -
No data available:
(3) - First Unit 2 mid-cycle examination in Cycle 5: (4)
- Second Unit 2 mid-cycle examination in Cycle l e
-8-Thirteen tubes were plugged in Steam Generator 2-1 because of identified wear at support and batwing stay cylinder locations (i.e.,
5 tubes at vertical supports.
1 tube at the batwing stay cylinder.
5 tubes at batwing supports, and 2 tubes at eggcrate supports).
The corresponding plugging total in Steam Generator 2-2 for wear was 12 tubes (i.e..
5 tubes at vertical supports.
tubes at the batwing stay cylinder.
2 tubes at batwing supports.
and 2 tubes at eggcr ate supports.
Five tubes were plugged in Steam Generator 2-1 because of degradation associated with loose parts.
Two tubes in Steam Generator 2-1 and four tubes in Steam Generator 2-2 were plugged because of identified volumetric indications.
2.3 Unit 3 Subsequent to Refueling Outage 3R4.
steam generator tube examinations were performed during a mid-cycle outage (i.e..
3MC5, November 26 through December 19.
1994)
and during Refueling Outage 3RS (October 14 through November 28, 1995).
Table 3 below provides the plugging history for the two steam generators through Refueling Outage 3R5 as a function of effective full power years of operation at the time of repair.
2.3. 1 Mid-Cycle Outage 3MC5 Tube examinations performed during Mid-Cycle Outage 3MC5 resulted in the identification of limited axial outside diameter stress corrosion cracking.
Eight tubes were plugged in Steam Generator 3-1 because of identified mid-span cracking.
Sixteen tubes were plugged in Steam Generator 3-2 because of identified axial outside diameter stress corrosion cracking (i.e., cracking in one tube at the top of the tube sheet.
nine tubes at mid span, and six tubes at mid span and supports).
Two tubes and three tubes. respectively'ere plugged in Steam Generators 3-1 and 3-2 because of identified volumetric indications.
An additional two tubes in Steam Generator 3-1 were plugged because of identified wear at supports (i.e..
one tube.
batwing:
one tube, eggcrate).
2.3.2 Refueling Outage 3R5 Tube examinations performed during Refueling Outage 3R5 resulted in the identification of both axial and circumferential stress corrosion cracking in the vicinity of the top of the tube sheet on the hot-leg side of the steam generators.
One tube was plugged at this location in Steam Generator 3-1 because of identified circumferential outside diameter stress corrosion cracking.
and three tubes because of identified axial primary water stress corrosion cracking.
The co~responding top of the tube sheet plugging totals in Steam Generator 3-2 were nine tubes because of identified circumferential stress corrosion cracking (i,e.. eight tubes, primary water stress corrosion cracking:
one tube. outside diameter stress corrosion cracking)
and five tubes because of identified axial primary water stress corrosion crackin e 0,
-9-Table 3 STEAM GENERATORS (SGs) 3-1 ANO 3-2 TUBE REPAIR HISTORY Time of Repair Operational Time SG 3-1 SG 3-2 Unit 3 Refueling EFPYs"'utage (3R)
Tubes Plugged Tubes Plugged Pre-Commercial 3R1 (5/89)
3R2 (4/91)
3R3 (10/92)
3MC4'
(12/93)
3R4 (4/94)
3MC5"'ll/94)
3R5 (10/95)
1.09 2.16 3.33 NDA'"
4.43 4.87 5. 69
23
12
83
20
36 Total Re airs 170 193 K Repairs ( Inservice, Total)
0.88.
1.54 1.00, 1.75 (1) - Effective full power years; (2)
- Unit 3 mid-cycle examination in Cycle 4; (3) -
No data available:
(4) - Unit 3 mid-cycle examination in Cycle 5.
Seventeen tubes in Steam Generator 3-1 were plugged because of identified upper bundle "arc" region axial outside diameter stress corrosion cracking (i.e.
~ cracking in 8 tubes at mid span, 6 tubes at supports, and 3 tubes at mid span and supports).
The corresponding plugging total in Steam Generator 3-2 for this type of degradation was also 17 tubes (i.e., cracking in 8 tubes at mid span.
5 tubes at supports, and 4 tubes at mid span and supports).
Additional causes for tube plugging in Steam Generator 3-1 were batwing wear (three tubes).
volumetric indications (three tubes).
and greater than 40 percent through-wall degradation (three tubes).
Additional causes for tube plugging in Steam Generator 3-2 were axial outside diameter stress corrosion cracking at the flow distribution plate (one tube). obstruction to passage of an eddy current probe (one tube).
and incomplete tube expansion (three tubes).
0
2 4 Com arison of De radation Betweer Units
!n Inspection Report 50-528:
529 530/94-15. Section 2.4 4. the inspectors noted tnat the incidence of stress cor ros on cracking in steam generator tubing appeared for Units 2 ana 3 to be an order of magnitude higher for the second steam generator when compared to the first. with Unit 1 steam generators exhibiting approximately nal that differential.
During the current review of plugging history.
documented in Sections 2. 1. 2.2.
and 2.3 above.
the inspector noted that the difference between unit steam aenerators
.n "ate of incidence of stress corrosion cracking appeared to be diminisning.
To illustrate this point.
and provide an overall comparison of degradation between the units. the inspector updated the information contained in the prior inspection report to reflect the current steam generator tube plugging status.
The updated information is listed below in Table 4.
able
DEGRADATION COMPARISON BY UNIT Tube Plugging-Inservice Total
Stress Corrosion Inservice Total Stress Corrosion Unit
EFPYs"'- 5.79 Unit 2 EFPYs"'- 5.60 Unit 3 EFPYs"'- 5.69 SG 1-1 SG 1-2 SG 2-1 SG 2-2 SG 3-1 SG 3-2 150 274 405 1157
110
181 207 847
71 (',)
- Effective full power years of operation at time of last tube examinations.
The data in Table 4 showed that the current plugging totals for identified stress corrosion cracking were. for the Units 1 and 2 steam generators.
approximately four times higher for the second unit steam generator than the first.
The current plugging total for identified stress corrosion cracking in the second Unit 3 steam generator was approximately twice that of the first steam generator.
The inspector noted that the accrued effective full power years of operation at the time of last examination remained.
as was true in the initial review of degradation history. very similar for each unit.
The inspector concluded from review of the data that.
although the incidence of identified stress corrosion cracking continued to be greater in the second steam generator than the first. the difference in rate between steam generators was diminishing.
The overall steam generator plugging t'otals for identified stress corrosion cracking continued to vary significantiv between units (i.e.. the current Jn.t 2 steam generator olugging 'otal for identified stress corrosion cracking was.
respec'.ive'.y.
approximately -'" times ana
'0 ".mes higher than the corresponding plugging totals ir Units
.
and 3;.
This status was similar to
i I
l
@I J
J
-11-that noted in Inspection Report 50-528:
529: 530/94-15 'ith the exception that the Unit 3 plugging total was somewhat less favorable (i.e.. the Unit 2 plugging total for identified stress corrosion cracking was previously
times higher than the corresponding Unit 3 plugging total).
Further review of the reasons for the apparent difference in unit steam generator tubing degradation rates was identified during the prior inspection as an inspection follow-up item (i.e.. 528;529:530/9415-01).
During the current inspection, the inspector reviewed the information in a document dated Apri 1 28.
1995. which was generated by licensee personnel in response to the inspection follow-up item.
Licensee personnel concluded in this document that the data collected and reviewed, to date (i.e.. the results obtained from 31 tube pulls. deposit and sludge analysis.
ATHOS thermal-hydraulic studies, blowdown studies.
wear studies.
secondary chemistry studies'nd fabrication review) did not provide an explanation for the plugging differences between the units.
The inspector concluded.
after review of the licensee document and discussions with licensee personnel.
that development of a detailed understanding of the reasons for apparent differences in unit steam generator degradation rates was unlikely.
A determination was accordingly made.
as noted in Section 7.2. 1. to close Inspection Follow-Up Item 528:529:530/9415-01.
REVIEW OF TUBE EXAMINATION PROGRAM REQUIREMENTS AND DATA 3. 1 Review of Examination Pro ram Re ui rements The inspector reviewed the examination scope for Refueling Outage 3R5 and the current eddy current examination program requirements contained in Procedure 73TI-9RC01
~
"Steam Generator Eddy Current Examinations."
The eddy current examination program requirements were found to be both comprehensive and
~ with the exception of an absence of quantitative criteria for noisy data, in full conformance with the recommendations contained in Electric Power Research Institute NP-6201.
"PWR Steam Generator Examination Guidelines,"
Revision 3.
During the review, the inspector performed a follow-up of Inspection Follow-Up Item 528:529/9415-02.
This item pertained to comparison of the location of identified foreign objects, that could not be removed, against eddy current examination results.
The inspector determined that the licensee:
had made appropriate provisions for inputting the results of foreign object search and retrieval activities into the eddy current examination program:
was monitoring tubes which were in contact with foreign objects for wear, in conjunction with the use of a conservative plugging policy: performed routine eddy current examination screening for loose parts; and had implemented effective overall controls.
Inspection Follow-Up Item 528:529/9415-02 was closed based on the results of the review.
The examination scope exceeded the guidance of Electric Power Research Institute NP-6201.
Revision 3.
and provided a high level of assurance that any.
significant degradation present in the Unit 3 steam generators would be ident~fied.
Overall. the inspector concluded that:
(a) the licensee had developed an excellent eddy current examination program following the March
I l
-12-1993 tube rupture in Steam Generator 2-2.
(b) the licensee was proactive in its implementation of new.
more sensitive eddy current examination methods.
and (c) the use of a dedicated multi-disciplinary steam generator staff was an indicator of management involvement and support for strong steam generator engineering programs.
3.2 Review of Tube Examination Data The inspector performed a limited review of eddy current examination data from Refueling Outage 3R5, with an emphasis placed on the relative detection capabilities of the Plus Point coil versus the standard motorized rotating pancake coi l.
The results of the review indicated that the Plus Point coil provided data that was less ambiguous and increased the level of assurance that the presence of circumferential stress corrosion cracking would be identified by eddy current data analysts.
No problems were noted with respect to resolution analyst performance.
LABORATORY EXAMINATIONOF DEFECTIVE TUBES During Refueling Outage 2R4 in the Spring 1993. portions of eight tubes were removed from the hot-leg side of Steam Generator 2-2 for laboratory examination.
A review was performed of the laboratory examination results which were documented in Inspection Report 50-528; 529: 530/95-14.
Inspection Follow-Up Item 529;530/9514-04 was also initiated during the inspection pertaining to the review of laboratory examination results from additional Unit 2 and Unit 3 tube samples that were removed.
respectively.
during Mid-Cycle Outage 2MC5-1 and Refueling Outage 3R4.
A review was performed subsequent to the on-site inspection period of the laboratory examination results that were obtained from the additional Unit 2 and Unit 3 tube samples.
4. 1 Mid-C cle Outa e 2MC5-1 Tube sections containing the hot-leg side bend were removed from 21 "arc" region U-tubes at the periphery of the Steam Generator 2-2 tube bundle following chemical cleaning of the steam generators in January 1994.
Thirteen of the 21 tube sections exhibited eddy current indications of various types.
The remaining eight sections showed no detectable defects on eddy current examination, and were removed to allow access to the tubes with indications.
The inspector reviewed the results of the laboratory examinations which were documented in ABB Combustion Engineering Report V-PENG-TR-005,
"Palo Verde-2 Steam Generator Tube Bend Region Examination and Metallurgical Examination,"
dated January 1995.
The findings from the examination process are summarized below.
~
The chemical cleaning process was found to have been effective in removing from the tube the majority of the deposits.
with the vertical sections of tubing found to be especially free of deposits.
It was also
-13-noted.
however, that the process had not been completely effective in removing deposits from batwing contact areas.
Some tenacious residual deposits were also observed on the upper surfaces of horizontal sections of the tubing.
Corrosion degradation modes were found to be outside-diameter initiated intergranular attack and intergranular stress corrosion cracking.
The most severe corrosion was observed to occur beneath residual ridge-like deposits.
Some degradation was also noted to be associated with scratches on the tube surfaces.
Sulfur species.
and in particular sulfides.
were viewed as probable contributors to the degradation.
Of the 20 tubes.examined'nly 2 were found to be free of both intergranular attack and intergranular stress corrosion cracking.
Four of the 20 tubes exhibited only minor intergranular attack.
Differing amounts of intergranular and intragranujar carbides were observed in the various tube samples.
No specific correlation was noted between depth of corrosion and microstructure.
with significant corrosion found in a variety of microstructures.
The extent of corrosion appeared to the investigators to be more a function of location in the tube bundle and the presence/absence of ridge deposits or scratches.
The inspector considered these observations to be somewhat surprising'ince they could be construed as indicating that the similar thermal-hydraulic characteristics of the Units l. 2.
and 3 steam generators should. if tubing microstructure was relatively unimportant. result in similar degradation rates in each steam generator (i.e., the deposit locations and characteristics would not be expected to vary much betwee'n tube bundles in different unit steam generators).
As discussed in Section 2 above.
actual steam generator tubing degradation rates have varied significantly between units.
Shallow wear (i.e..
up to 2 mi ls deep)
was present at most batwing contact locations and at some intrados/extrados locations.
The latter wear was attributed to periodic tube-to-tube contact during plant operation.
Room temperature burst test results from 13 of the tubes which contained eddy current indications ranged from 6020 psi to 9860 psi.
The lowest value in the range was equivalent to a 650 F burst strength value of 5159 ps'.
which significantly exceeded the Regulatory Guide 1. 121 structural limit (i.e.. three times the steam generator normal operating pressure differential) of 3600 psi for Unit 2.
Metallography indicated that the eddy current examinations performed before chemical cleaning were generally effective in identifying defects with average depths of 40 percent throughwall or greater.
The examinations were noted.
however. to be less effective in identifying the presence of defects when the average depth fell below 40 percent throughwall
0
-14-4.2 Refuelin Outa e 3R4 Hot-leg side bend sections were removed for laboratory examination from two
"arc" region U-tubes in Steam Generator 3-2.
One tube showed no detectable defects on eddy current examination.
and was removed to allow access to the second tube.
The tube of interest was indicated by eddy current examination to contain a volumetric indication on the intrados of the tube just above the batwing support contact arear'ut below the bend tangent point.
The inspector reviewed a summary of the examination results that was contained in a licensee document entitled "Unit 3 Steam Generator Evaluation." dated May 1995.
This document was transmitted to the NRC by Letter 102-03364 dated May 19 '995.
The findings noted are listed below:
Neither intergranular attack nor intergranular stress corrosion cracking were found in the tube containing the eddy current single volumetric indication.
The single volumetric indication was approximately 2 3/16-inches long.
1/4-inch wide.
and approximately 26 percent throughwall.
No evidence of active wear was noted and the degradation was considered by the investigators to have occurred by a general corrosion process under a
t ridge-like deposit.
~
The microstructure was not considered to be typical of Inconel 600 with good resistance to stress corrosion cracking.
The inspector considered that tube-to-tube fretting was a more probable cause for initiation of the volumetric indication. with subsequent corrosion eliminating evidence of the wear process (i.e.. cold worked grains) which initiated the degradation.
The inspector reached this conclusion as a result of it appearing improbable that a microstructure which was relatively susceptible to stress corrosion cracking would, in the presence of a ridge-like deposit.
be subject to general corrosion without at least accompanying intergranular attack or intergranular stress corrosion cracking.
Inspection Follow-Up Item 529:530/9415-04 was closed after completion of the review of the additional laboratory examination results.
REVIEW OF STEAM GENERATOR HODIFICATION PROBLEMS During Refueling Outage 3R5, two modifications were initiated in the Unit 3 steam generators.
The modifications consisted of:
(a) replacement of the existing feedwater ring. which provided 10 percent of the feedwater flow to the cold-leg side downcomer annulus.
with a new ring designed to deliver the downcomer feedwater flow to the hot-leg side downcomer annulus; and (b)
I
,l
-15-reduction of the hot-leg side flow resistance created by the flow distribution plate, by cutting holes in the downcomer shroud above the flow distribution plate to create a bypass.
Both modifications reduce maximum tube bundle exit steam quality.
and hence reduce the size of the dryout region.
While the contractor.
ABB Combustion Engineering, was performing the hole cutting operations in the downcomer shroud on the hot-leg side of the steam generators, various foreign objects entered the steam generators.
In Steam Generator 3-2. the foreign objects consisted of:
a clip-off magnet
~
a broken piece of cutter, a
X 32 3/16-inch long screw, an 18-inch long tie wrap.
and a broken cutter head inside the hot-leg side downcomer shroud.
In Steam Generator 3-1. the foreign. objects were a 3/4 inch X 3-inch long socket and a
diver's safety latch pin.
The inspector reviewed Procedure 30AC-9WP01,
"Foreign Material Exclusion and Zone III Controls." Revision 8, and the requirements of and conformance to Work Orders 715330 and 715332.
The inspector concluded from the review that the foreign material entry problems were related to the location of the cutting operations (i.e.. in the downcomer annulus which precluded sealing of the annulus)
~ rather than deviation from foreign material exclusion program requirements.
INSERVICE INSPECTION
- OBSERVATION OF WORK AND WORK ACTIVITIES (73753)
The objective of this inspection was to determine whether the performance of inservice inspection examinations.
and the repair and replacement of Class l.
2, and 3 pressure retaining components were performed in accordance with Technical Specifications.
the American Society of Mechanical Engineers (ASME)
Boiler and Pressure Vess~,
Code, requirements imposed by NRC and industry initiatives.
and correspondence between the Office of Nuclear Reactor Regulation and the licensee concerning relief requests.
This part of the inspection was performed by a single inspector October 30 through November 3.
1995.
6. 1 Observation of Inservice Ins ection Examinations During this inspection.
the inspector observed the following inservice inspection examinations performed by contractor nondestructive examination personnel:
~
Liquid penetrant examination
- Shutdown Cooling "B" Line, Weld ID 75-14;
~
Ultrasonic examination
- Shutdown Cooling "B" Line. Weld ID 75-14 The inspector observed that the examiners performed the proper surface preparation and verified component temperatures prior to performance of the examinations.
The examiners were ascertained by interview to be knowledgeable of examination procedures.
techniques'nd instrumentation.
The inspector also verified that the materials used during the observed examinations had
-16-been properly certified and accepted.
The examiners documented their calibration and examination results on the appropriate reports.
During the examinations.
the inspector observed that the examiners took extra precautions and performed additional examination efforts when questionable indications were identified.
The inspector also noted that the authorized nuclear inservice inspector was actively observing inservice inspection examinations, and that licensee supervisory oversight of the inservice inspection personnel and activities was good.
6.2 Personnel ualifications and Certifications The inspector was informed that the individuals performing the observed examinations were contractor personnel employed by Lambert-HacGi ll-Thomas.
Inc.
The inspectors reviewed the qualification files for the observed personnel and ascertained that the two examiners who performed the ultrasonic and liquid penetrant examinations were. respectively. certified as a Level II and a Level III examiner in accordance with the American Society of Nondestructive Testing Recommended Practice SNT-TC-lA.
Both individuals were verified by the inspector to have received annual near distance acuity and color vision examinations.
6.3 ASNE Section XI Code Re air and Re lacement 6.3. 1 Discussion The inspector was informed that the ASHE Section XI Code activity that was ongoing during the on-site inspection was a modification to the steam supply system for the auxiliary feedwater pump turbine.
The fabrication, installation and nondestructive examination activities associated with the modification were authorized by Work Order 00706767.
The inspector observed portions of the fabrication. installation and nondestructive examination activities associated with this modification.
the activities observed pertained to installation of Line SGEL389. which was part of the steam supply bypass warmup line for the auxiliary feedwater pump turbine.
During interviews with personnel performing the modification activities, the inspector noted that they were cognizant of their work scope and responsibilities.
The inspector also noted that good foreign material
.
exclusion controls were in place for pre-fabricated subassembly openings and open system piping.
During review of the field documentation to ascertain the status of the modification (i.e.. what work had been completed and what work still remained to be completed).
the 'inspector noted that steps in Work Order 0070676, which required signatures and dates of work completion.
appeared to be sporadically signed off.
The inspector also noted that steps in the work order were being worked out of sequence.
The inspectors also noted that Work Order 0070676 requi red a nuclear assurance hold point following fabrication to document verification of specified critical attributes on tne applicable "Critical
f 0't l
l
-17-Attribute Verification Sheet" and weld data sheets.
During review of the critical attribute verification sheet.
the inspectors noted that the sheet had not been completed or signed off.for Line SGEL389.
The inspector questioned licensee representatives at the work site and the foreman in charge of the modification activities concerning the status of Line SGEL389.
and to ascertain the reasons for:
fabrication steps and the critical attributes verification sheet not being signed off as completed; and steps in Work Order 0070676 being written and worked out of sequence.
Licensee representatives indicated that fabrication of Line SGEL389 had not yet been completed, although the subassembly observed by the inspector was being installed.
Licensee representatives also indicated that.
when all fabrication activities associated with Line SGEL389 were complete.
the steps in the work order package and the critical attribute sheet would be completed and signed off.
Licensee representatives further stated that steps in work orders were not required to be performed in sequence unless the work order instructions specifically stated to do so.
The inspector also questioned licensee representatives concerning what documents were used to track the status of completion of each individual weld activity and associated required nuclear assurance and nondestructive inspections and examinations.
since only multiple task work activities for completion of line fabrication and installation were required to be signed per the work order instructions.
Licensee representatives indicated that each individual weld status was tracked by the applicable weld, data sheet.
The inspector reviewed the following licensee procedures pertaining to work control to ascertain the procedural requirements for completion of step sequences:
~
Procedure 30DP-9NP01.
"Conduct of Haintenance."
Revision 15;
~
Procedure 63DP-OQQ06,
"Determination and Implementation of Plant Inspections,"
Revision 10;
~
Procedure 30DP-OAP01.
"Maintenance Instruction Writer's Guide."
Revision 12; and
~
Procedure 30DP-9WPOZ.
"Work Document Development and Control."
Revision 14.
Based on review of the program procedures, the inspector concluded that performing steps out of sequence was allowed by the licensee's procedures.
The inspector noted that the current work control measures gave great latitude to the first-line supervisor in the approach to be used for fabrication and installation of subassemblies.
No specific deficiencies were observed, however.
as a result of this latitude.
The inspector reviewed the weld data sheets associated with Line SGEL389 and noted that. in most cases, more than
e l
l l
-18-one welding procedure appendix was permitted to be used.
The inspector performed a limited review of the following welding procedures and their associated procedure qualification records to deterrqine if ASHE Section IX Code requirements were satisfied:
~
Procedure 73WP-OZZ04,
"Welding of Carbon and Low Alloy Steels to Stainless and Nickel Alloys," Revision 4:
Procedure 73QP-OZZ05,
"Welding of Ferritic and Martensitic Steels."
Revision 3; and Procedure 73WP-OZZ07.
"Welding of Stainless and Nickel Alloys.."
Revision 3.
Based on the review, the inspector concluded that the welding procedures appeared to satisfy minimum ASHE Section IX Code requirements.
but were considered permissive with respect to allowable welding parameters.
The inspector also reviewed the "Welder/Brazer Performance Qualification Summary."
which was effective October 20, 1995. to verify that the personnel who performed the welding activities f'r Line SGEL389 were appropriately qual~fied.
The summary indicated that the welders associated with the welding activities for Line SGEL389 had been appropriately qualified.
6.3.2 Nondestructive Examination Observations The inspector observed the authorized nuclear inservice inspector perform visual examinations and licensee nondestructive examination personnel perform requi red magnetic particle examinations on six new welds associated with Line SGEL389.
No indications were detected and all welds were accepted.
FOLLOW-UP (92700, 92903)
7.1 On-Site Review of Licensee Event Re orts 92700 7. 1. 1 (Closed)
Licensee Event Report 530/94-004:
TS LCO 3.03 Entry to Restore ASME Code Class 2 Structural Integrity 7. 1. 1. 1 Licensee Event Report Summary This event involved the discovery on two separate occasions that secondary pressure boundary leakage existed.
One occasion involved Steam Generator 3-2 instrument nozzle penetration leakage, and the other occasion involved a Steam Generator 3-2 sample nozzle penetration leakage.
7. 1. 1.2 Licensee Action in Response to the Licensee Event Report Based on investigations.
the licensee determined that the apparent cause of the nozzle penetration leakage was due to a defective weld. most likely from original fabrication.
In both cases the nozzles were replace ~,
-19-7. 1. 1.3 Inspector Action During the Present Inspection The inspector evaluated the adequacy of the licensee's corrective actions and the subsequent results.
The inspector reviewed Condition Report/Disposition Request 3-4-0343.
Work Order 00662966 which was written to authorize the repair of the instrument nozzle, and Work Order 00663842 which was written to authorize the repair of the sample nozzle.
Both the instrument nozzle and sample nozzle were cut, replaced with new nozzles.
and Inconel weld buildup pads were installed.
The inspector reviewed the subsequent visual inspection which was performed during the current Refueling Outage 3R5 and documented on Visual Examination Report 95-903.
No abnormalities were identified during this visual inspection.
During the current Refueling Outage 3R5. liquid penetrant examinations were also performed on accessible Steam Generator 3-1 nozzle welds.
The inspector reviewed the results of these examinations which were documented in Liquid Penetrant Report 95-960.
This ressort recorded that three rounded indications had been noted on Shell Cone Nozzle Y628, and were being evaluated by the licensee for possible repairs.
No other abnormalities were noted during the liquid penetrant examinations.
7.1.1. 4 Conclusi ons Based on the review of Work Order 00662966, Work Order 00663842, Visual Examination Report 95-903.
and Liquid Penetrant Report 95-960 'he inspector t
concluded that the licensee was appropriately monitoring and repairing steam generator nozzle leakage.
7.2 Ins ection Foliow-U Items 92903 I
7.2.1 (Closed)
Inspection Follow-Up Item 528: 529: 530/9415-01:
Review of reasons for apparent differences in unit steam generator tubing degradation rates.
A review was performed of available information pertaining to contributory reasons for apparent differences in unit steam generator tubing degradation rates.
The scope and results of the review are documented in Section 2.4 above.
Inspection Follow-Up Item 528;529;530/9415-01 was closed following a determination that development of a detailed understanding of the reasons for apparent differences in unit steam generator tubing degradation rates was unlikely.
7.2.2 (Closed)
Inspection Follow-Up Item 528; 529/9415-02:
Comparison of the location of identified foreign objects that could not be removed against eddy current examination program results.
Review of Inspection Follow-Up Item 528:529/9415-02 was performed in conjunction with a review of current eddy current examination program requi rements, The results of this review. which are documented in Section 3. 1
tf i
if
.i
1
-20-above.
indicated that the licensee had implemented effect;ve program requirements for identification of lodged foreign objects.
monitoring of abutting tubes for wear
~ and routine use of eddy current examination screening for loose parts.
7.2.3 (Closed)
Inspection Follow-Up Item 529; 530/9415-04:
Review of laboratory examination results for Units 2 and 3 steam generator tube samples which were removed during, respectively, Mid-Cycle Outage 2MC5-1 and Refueling Outage 3R4.
A review was performed of the laboratory examination results for the Mid-Cycle Outage 2MC5-1 and Refueling Outage 3R4 tube samples.
The results of the review are, documented in Section 4 abov )
I
ATTACHMENT
PERSONS CONTACTED 1. 1 Licensee Personnel
- J. Bailey. Vice Presidents Engineering C.
Brown
~ Inservice Inspection Engineer, Inservice Inspection
- B. Dayyo. Senior Representative.
Strategic Communications
- P. Guay, Directors'hemistry
- D. Hansen.
Nondestructive Examination Level III, Steam Generator Project Group
- D. Kanitz, Senior Engineer, Nuclear Regulatory Affairs
- A. Krainik. Department Leader, Nuclear Regulatory Affairs J. Levine. Vice President.
Nuclear Production
~A. Morrow, Section Leader, Inservice Inspection D. Oakes.
Section Leader
~ Inservice Testing
- G. Overbeck.
Vice President.
Nuclear Support gJ.
Provasoli
. Senior Engineer.
Nuclear Regulatory Affairs
- C. Russo.
Department Leader.
Nuclear Assurance****
- R. Schaller.
Manager
~ Steam Generator, Project Group G. Shanker, Engineering Assurance Department Leader.
Nuclear Assurance
- K. Sweeney.
Senior Project Manager.
Steam Generator Project Group 1.2 Other Personnel
- F. Gowers
. Site Representative, El Paso Electric
- R. Henry. Site Representative, Salt River Project 1.3 NRC Personnel
- D. Garcia, Resident Inspector In addition to the personnel listed above, the inspectors contacted other personnel during this inspection period.
- Denotes personnel that attended the November 3,
1995. exit meeting.
- Denotes personnel that attended the November 3.
1995'xit meeting and participated in the November 28:
1995. telephone review of Unit 3 steam generator degradation information.
/Denotes personnel that attended the November 3.
1995. exit meeting and participated in both the November 28 and 30.
1995. telephone calls.
EXIT MEETING An exit meeting was conducted on November 3.
1995.
During this meeting, the inspectors reviewed the scope and findings of the report.
The licensee did not express a position on the inspection findings documented in this report.
The licensee did not identify as proprietary any information provided to. or reviewed by. the inspectors.
Unit 3 steam generator eddy current examination results were provided by licensee personnel on a continuing basis following the on-site inspection until completion of all required examinations.
A final review with licensee personnel of Unit 3 steam generator degradation
I
-2-information was conducted by telephone on November 28.
1995.
Licensee personnel were additionally informed bp telephone on November 30, 1995. of the observations made during review of the laboratory examination results for the additional Unit 2 and Unit 3 samples that were removed during Mid-Cycle Outage 2MC5-1 and Refueling Outage 3R