ML20149L322
| ML20149L322 | |
| Person / Time | |
|---|---|
| Issue date: | 02/29/1988 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| References | |
| NUREG-0040, NUREG-0040-V11-N04, NUREG-40, NUREG-40-V11-N4, NUDOCS 8802240187 | |
| Download: ML20149L322 (185) | |
Text
. - _ __ -- - _
~
l NUREG 0040 l
Vol.11, No. 4 i
LICENSEE CONTRACTOR
- AND VENDOR INSPECTION
- STATUS REPORT l i
QUARTERLY REPORT l'
! OCTOBER 1987 DECEMBER 1987 UNITED STATES NUCLEAR REGULATORY COMMISSION i l ... ,
1 i}g/p/
s.....
l wun -
0040 R PDR j
~- ,
~
_[A
~ ., . . ..
%' A
/,f- ,
, f
,.A
. s' 4
4 ...
s
,,wZ '
i Available from -
= 4 Superintendent of Documents -
a U.S. Government Printing Office Post Office Box 37082 Washington, D.C. 2001}7082 '
s A year's subscription consists of 4 issues for e- s this publication.
% 4 Single copies of this publication are available from National Technical 9
information Service, Springfield VA 22161 I
MN .A l fs i s"
-P
% i N I
~s l 1
i* .
h h
, r%l .
% 4 1
= '
4: W ,
i I
Id a
~. s s
- ' \
,,,e f
- \ \ \ j I
'~ Q ; \. 4 l
~. .v t- .
- h 1
NUREG 0040 Vol.11, No. 4 LICENSEE CONTRACTOR AND VENDOR INSPECTION STATUS REPORT QUARTERLY REPORT OCTOBER 1987 DECEMBER 1987 oa[e Posh d fe vary 1988 Division of Reactor inspection and S:feguards Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 20555
, f"..%,,
/
i i
l
1 l
CONTENTS Page
- 1. Preface ............................................................. iii
- 2. Reporting Format .................................................... V
- 3. Inspectors Reports .................................................. 1
- 4. Selected Information Notices ........................................ 151
- 5. Index ............................................................... 177
- 6. Table of Vendor Inspection Reports Related to Reactor Plants ......................................... 179 I
l i
l I
l 1
l r
l I
i I i 1
t L
PREFACE A fundamental premise of the Nuclear Regulatory Commission's (NRC) nuclear facility licensing and inspection program is that licensees are responsible for the proper construction and safe operation of their nuclear power plants.
The total government-industry system for the inspection of nuclear facilities has been designed to provide for multiple levels of inspection and verification.
Licensees, contractors, and vendors each participate in a quality verification process in accordance with requirements prescribed by, or consistent with, NRC rules and regulations. The NRC inspects to determine whether its requirements are being met by a licensee and his contractors, while the great bulk of the inspection activity is performed by the industry within the framework of ongoing quality verification programs.
In implementing this multilayered approach, a licensee is responsible for developing a detailed quality assurance (QA) plan. This plan includes the QA programs of the licensee's contractors and vendors. The NRC reviews the licensee's and contractor's QA plans to determine that implementation of the l proposed QA program would be satisfactory and responsive to NRC regulations.
In the case of the principal licensee contractors, such as nuclear steam supply system designers and architect engineering firms, the NRC encourages submittal of a description of corporate-wide QA programs for review and acceptance by the NRC. Once accepted by NRC, a corporate QA program of a licensee's contractor will be acceptable for all license applications that incorporate the program by reference in a Safety Analysis Report (SAR). In such cases, a contractors's QA program will not be reviewed by the NRC as part of the licensing review process, provided that the incorporation in the SAR is without change or modification. However, new or revised regulations, Regulatory I Guides, or Standard Review Plans affecting QA program controls may be applied l by the NRC to previously accepted QA programs.
When design and construction activities were high, fims designing nuclear I steam supply systems, architect engineering firms designing nuclear power plants, and certain selected major equipment vendors were inspected on a regular basis by NRC to ascertain through direct observation of selected activities whether these design firms and vendors were saHsfactorily implementing the accepted QA program. However, with the substantial decline of new plant design activities, the inspection of QA program implementation has been deemphasized. Instead, the NRC vendor inspection focus has been shifted to vendor activities associced with nuclear plant operation, maintenance, and modifications. Inspection emphasis in now placed on the quality of the vendor products including hardware fabrication, licensee-111
vendor interfaces, environmental qualification of equipment, and equipment problems found during operation and corrective action. If nonconfonnances with NRC requirements and regulations are found, the inspected organization is requested to take appropriate corrective action and to institute preventive measures to preclude recurrence. If generic implications are identified, NRC assures that affected licensees are expeditiously informed.
In addition to the above, the Vendor Program Branch has begun inspections at licensee facilities covering the areas of procurement of replacement parts for use in safety-related systems and licensee / vendor interface programs as requested in Generic Letter 83-28. This edition of the White Book contains copies of the inspection reports of inspections completed to date. Subsequent issues will contain those reports that are issued in the quarterly report period covered by that White Book.
In the past, NRC issued confirming letters to the principal contractors to indicate that NRC inspections have confirmed satisfactory implementation of the accepted QA programs. Licensees and applicants could, at their option, use the letters to fulfill their obligation under 10 CFR 50 Appendix B, Criterion VII, that requires them to perform initial source evaluation audits and subsequent periodic audits to verify QA program implementation. However, based on the above described change in nuclear plant design and construction activities, NRC will no longer issue confirming letters to principal contractors since futura NRC vendor program inspections will focus on selected areas rather than addressing the implementation of their respective QA programs. Therefore, confirming letters that have already exceeded their three year effective period will not be renewed. Confirming letters issued less than three years ago will remain in effect until the stated effective period expires. Therefore, as the confirming letters expire, licensees and applicants will no longer be allowed to take credit for the NRC acceptance of the implementation of a principal contractor's QA program. Licensees continue to be responsible for the conduct of initial source evaluation audits and subsequent periodic audits to verify QA program implerrentation.
The White Book will continue to be published and will contain copies of all vendor inspections issued during the calendar quarter specified. The vendor inspection reports list the nuclear facilities to which the results are applicable thereby informing licensees and vendors of potential problems. In !'
addition, the af fected NRC Regional Offices are notified of any significant problem areas that may require special attention. The White Book also con-tains copies of IAE Information Notices, concerning vendor issues released during the calendar quarter.
The White Book contains information normally used to establish a "qualified l suppliers" list; however, the information contained in this document is not j adequate nor is it intended to stand by itself as a basis for qualification of suppliers. l Correspondence with contractors and vendors relative to the inspection data contained in the White Book is placed in the USNRC Public Document Room, located in Washington, D.C.
iv
ORGANIZATION: COMPANY, DIVISION l CITY, STATE REPORT INSPECTION INSPECTION NO.: Docket / Year / Sequence DATE: ON-SITE HOURS: l l
CORRESPONDENCE ADDRESS: Corporate Name Division ATTN: Name/ Title ;
Address l City, State Zip Code l ORGANIZATIONAL CONTACT: Name/ Title TELEPHONE NUMBER: Telephone Number NUCLEAR INDUSTRY ACTIVITY: Description of type of components, equipment, or services supplied.
ASSIGNED INSPECTOR:
Name/ Vendor Program Branch Section Date OTHERINSPECTOR(S): Name/ Vendor Program Branch Section APPROVED BY:
Name/ Chief - Section/ Vendor Program Branch Date l
1 INSPECTION BASES AND SCOPE:
A. BASES: Pertain to the inspection criteria that are applicable to the activity being inspected; i.e., 10 CFR Part 21, Appendix B to 10 CFR Part 50 and Safety Analysis Report or Topical Report comitments.
B. SCOPE: Suninarizes the specific areas that were reviewed, and/or identi-fies plant systems, equipment or specific components that were inspected.
For reactive (identified problem) inspections, the scope summarizes the problem that caused the inspection to be performed.
PLANT SITE APPLICABILITY: List plant name and docket numbers of licensed facilities for which equipment, services, or records were examined during l the inspection.
Y
I ORGANIZATION: ORGANIZATION CITY, STATE REPORT INSPECTION l NO.: RESULTS: PAGE 2 of 2 '
A. VIOLATIONS: Shown here are any inspection results determined to be-in violation of Federal Regulations (such as 10 CFR Part 21) that are applicable to the organization being inspected.
B. NONCONFORMANCES: Shown here are any inspection results determined to be in nonconformance with applicable commitments to NRC requirements.
In addition to identifying the applicable NRC requirements, the specific industry codes and standards, company QA manual sections, or operating procedures which are used to implement these commitments may be referenced.
C. UNRESOLVED ITEMS: Shown here are inspection results about which more information is required in order to determine whether they are acceptable items or whether a violation or nonconfomance may exist. Such items will be resolved during subsequent inspections.
D. STATUS OF PREVIOUS INSPECTION FINDINGS: This section is used to identify the status of previously identified violations, items of nonconfomance, and/or unresolved items until they are closed by appropriate action.
For all such items, and if closed, include a brief statement concerning action which closed the item. If this section is omitted, all previous inspection findings have been closed.
E. INSPECTION FINDINGS AND OTHER COMMENTS: This section is used to provide significant information concerning the inspection areas identified under "Inspection Scope." Included are such items as mitigating circumstances concerning a violation or nonconformance, or statements concerning the limitations or depth of inspection (sample size, type of review performed and special circumstances or concerns identified for possible followup).
For reactive inspections, this section will be used to summarize the disposition or status of the condition of event which caused the i inspection to be performed. 1 F. PERSONS CONTACTED: Typed, Name, Title l
- present during exit meeting SAMPLE PAGE (EXPLANATIONOFFORMATANDTERMIN0 LOGY) i l
l vi i
<, m --n,s-- ---+0 m .A-w..-L--' s a A- -u-a2 m J w 4 i
i i
I l
j
/
INSPECIORS g g l
i I
l l
1 i
l ORGANIZATION: BABC0CK & WILC0X LYNCHBURG, VIRGINIA REPORT INSPECTION INSPECTION NO.: 99900400/87-01 DATE- 09/28-10/01/A7 nN RTTF MntlDR. 1R7 CORRESPONDENCE ADDRESS: Babcock & Wilcox Company Post Office Box 10935 Lynchburg, Virginia 24506-0935 NUCLEAR INDUSTRY ACTIVITY: Design and engineering services for Babcock and Wilcox designed Nuclear Steam Supply System.
ASSIGNED INSPECTOR:
"SEE NEXT PAGE" Date OTHERINSPECTOR(S): E. Hagen, ORNL, Consultant APPROVED BY:
/0!$0 7 F.Stolz,NRR/pl4 Date i
INSPECTION BASES AND SCOPE:
A. BASES: Special inspection of the B&W Owners Group Safety and Performance Improvement Program, report BAW-1919, Rev. 5, dated July 1987.
B. SCOPE: The purpose of this inspection was to determine if the recom-nendations developed under the Safety and Performance Improvement Program were being adequately tracked and accounted for during the review and dis-position process.
l PLANT SITE APPLICABILITY: AN0-1 (50-313); Bellefonte 1/2 (50-438/439);
Crystal River 3 (50-302); Davis-Besse (50-346); Oconee 1/2/3 (50-269/270/287);
Rancho Seco (50-312); TM1-1 (50-289).
I 1
l
ORGANIZATION: BABC0CK & WILC0X LYNCHBURG,-VIRGINIA REPORT INSPECTION NO.: 99900400/87-01 RESULTS: PAGE .' of 23 ASSIGNED INSPECTORS: M /er /v/ c.,,
/o/28/S7 R. LV Ferguson, NRR/PD14 Dhte QB. Si $
el, NRR/PD32 Der 4 / cu ' /0/28/$
Da~te '
(
E. Tg#flinson, NRR/PO4
,y) fo/2p/97 Date 9% d. M&c J.C/ Stone, Team Leader, NRR/VIB ted7 Dhte l
1 l
l l
2
ORGANIZATION: BABC0CK & WILC0X LYNCHBURG, VIRGINIA REPORT INSPECTION NO.: 99900400/87-01 RESULTS: PAGE 3 of 23 I.
SUMMARY
A. Results During the period of September 28 through October 10,1987, a team of five NRC inspectors and one consultant conducted an inspection of the Safety and Performance Improvement Program (SPIP) developed by the B&W Owners Group (B&WOG). The scope of the inspection was limited to the disposition of recommendations developed by the various comittees and task groups that participated in SPIP. The inspection did not include the recommendation development process within the various comittees and task groups. Also, the implementation of the recomendations issued by the B&WOG to the utilities will be included in a future inspection.
The inspection team reviewed the disposition of all recomendations contained in 13 out of 19 reports that are included as appendices to BAW-1919, "B&W Owners Group Safety and Performance Improvement Program, Revision 5, dated July 1987. The total' number of recommendations generated by the committees as of September 30, 1987 was 375. Of these, 207 were accepted, entered into the Reconvendation Tracking System (RTS) and issued for implementation by the utilities; 39 were returned for rework and entered into the Action Item Tracking i (AIT) system; 76 were found to be duplicates of other recomendations; 32 are still awaiting Steering Comittee action; and 21 were rejected. During this inspection the disposition of 290 recommenda-tions was reviewed. For each of the rejected recommendations, the documented basis for rejection was reviewed. In each instance there was a documented basis but in two cases the basis did not adequately support the rejection. Discussions with representatives of the appropriate committee provided additional information. Based on the verbal information the inspection team concluded that there existed a reasonable basis for rejection, but it had not been adequately documented.
The system used to track and maintain the status of the recomenda-tions was reviewed. The system did not have a single location that provided the status of each recommendation. In order to determine i
the status it was necessary to review all the elements of the j recomendation disposition path: (1) the task comittees reports; l (2) letters from the SPIP Chairman to the Steering Comittee; (3) the Steering Comittee minutes that directed recomendations to the l 1
RTS for implementation, returned recommendations to the SPIP committees for rework as documented in the AIT system, and rejected recommendations; and (4) letters back to the individual comittees.
3
ORGANIZATION: BABC0CK & WILC0X LYNCHBURG, VIRGINIA REPORT INSPECTION NO.: 99900400/87-01 RESULTS: PAGE 4 of 23 An informal compilation from Steering Comittee minutes of Steering Comittee actions on the recommendations provided a "road map" to direct the inspectors to the applicable documentation to determine the disposition. Without that listing the task would have been more difficult. Although the team was able to track all recomendations that were incluoed in the reports that were reviewed to current disposition, the formal documentation process required considerable support from SPIP informal documentation and SPIP personnel.
In addition tc the documentation audit, eight SPIP personnel who had active roles in the development of SPIP recommendations were inter-viewed, three by telephone. None of those interviewed expressed any concerns about the processing of recommendations from the comittees through final disposition.
On September 10, 1987, the SPIP Management Team was dissolved.
Those functions will now be handled by the Transient Response, Trip Reduction Comittee (TR Trip).
B. Areas Inspected The following reports were reviewed during the inspection. The Appendix listing refers to the appendix in BAW-1919, Revision 5:
- 1. Main Feedwater Pump Trip Reduction Program - Final Report, B&W Document 47-1159449-00. (Appendix B-4) 1
- 2. Final Report on Re-Evaluation of ICS Design Features, B&W I Document 47-1163861-00. (Appendix C) l 1
- 4. Charters Of The Independent Advisory Board And The SPIP Management Team. (Appendix F)
- 5. Results Of Operator Support Comittee's Review Of Procedures Related to Loss Of ICS/NNI, B&W Document 47-1164196-00.
(Appendix G)
- 6. 1154 Task Force Report-B&WOG Review Of The June 9, 1985 Davis-Besse Loss Of Feedwater Transient. (Appendix H) 4
l l
l ORGANIZATION: BABC0CK & WILC0X LYNCHBURG, VIRGINIA REPORT INSPECTION N0.: 99900400/87-01 RESULTS: PAGE 5 of 23
- 7. Review Of Category "B" And "C" Events At The B&WOG Plants 1980-1985, B&W Document 47-1165733-00. (Appendix I)
- 8. Recommendation Tracking System Report - SPIP-Related Recomendations. (Appendix J)
- 9. Safety And Performance Improvement Program Operator /Maintenace Personnel Interview Project Recomendations and Action Items, B&W Document 47-1165970-00. (Appendix K)
- 10. Instrument Air System Review Report, B&W Document 47-1165965-00.
(Appendix M) j
- 11. Main Steam Pressure Control Review Final Report, B&W Document 47-1167122-00. (Appendix N)
- 12. B&W Owners Group Safety Performance Improvement Program Prioriti- I zation Process. (Appendix 0)
- 13. A Comparative Study Of The Sensitivity Of B&W Reactor Plants; Volumes I & II. (Appendix P)
- 14. Auxiliary / Emergency Feedwater System Review Final Report, B&W Document 47-1168159-00. (Appendix Q)
- 15. ICS/NNI Evaluation Report. (Appendix R)
- 16. Operator Burden Project, B&W Document 47-1168190-00.
(Appendix S)
- 17. Safety And Performance Recommendation Integration Group (SPRIG),
B&W Document 47-1168543-00. (Appendix T)
- Did not generate recommendations.
l l II. DETAILS A. Background Early in 1986, the B&W Owners Group (B&WOG), as a result of NRC initiatives began a major effort in reassessing the design of 8&W plants focusing on reducing the complexity of transients and l
l l 5 1
ORGANIZATION: BABC0CK & WILC0X LYNCHBURG, VIRGINIA REPORT INSPECTION N0.: 99900400/87-01 RESULTS: PAGE 6 of 23 frequency of reactor trips on B&WOG member's plants. Although some work was already in progress on trip reduction, a new program was established within the existing framework of the B&WOG to emphasize improvements in safety associated with transient complexity and trip reduction. The program was named the Safety and Performance Improvement Program (SPIP). Figure 1 shows the relationship of the SPIP to the other B&WOG Committee and Task Forces. Using resources from the B&WOG the SPIP conducted various studies and evaluations that resulted in recommendations being made to reduce the trip frequency and transient complexity. The results of those studies are documented in "B&W Owners Group Safety and Performance Improve-ment Program," BAW-1919, Revision 05, July 1987. All recommenda-tions that were made by the various committees and task forces are contained in Appendicies B through T of BAW-1919.
B. Disposition Process for Recomendations Used by B&WOG Fourteen diverse projects that generated 19 reports were used to review or study specific areas and develop recomendations for safety and performance improvements. A'1 the recommendations developed by the individual committees or groups overseeing the various projects are included in the reports issued by the individual committee or groups.
After the recommendations were developed, they were sent to the SPIP Chairman for review and comment. The SPIP Chairman sent all recom-mendations to the B&WOG Steering Comittee for final disposition.
The SPIP Chairman included in the transmittal to the Steering Committee comments and recommended disposition for each recommen-dation. The Steering Committee had five options it could take:
accept and place it in the Recommendation Tracking System (RTS);
combine with other similar recomendation(s) and place it in RTS; !
return it to the originatin !
Action Item Tracking (AIT) system; g group return for rework it to aand place group it inthan other the j the originating group for rework and place it in the AIT system; or i reject and document the reasons for the rejection in the Steering Committee minutes. Once a recommendation was accepted and placed in the RTS it was sent to the B&WOG member utilities for evaluation I for possible implementation. Figure 2 shows the path taken for the dispositioning of recomendations. ;
1 Since the October 28-29, 1986 Steering Comittee meeting, a letter has been sent to the originating group's chairman providing the I disposition of each recommendation by the Steering Comittee. This provided the originating group an opportunity to appeal the decision by the Steering Committee. Before that time the originating group's 6
)
ORGANIZATION: BABC0CK & WILC0X LYNCHBURG, VIRGINIA REPORT INSPECTION N0.: 99900400/87-01 RESULTS: PAGE 7 of 23 chairman was not notified by separate letter. However, copies of the Steering Committee minutes and copies of the periodic updates of the AIT and RTS were provided, and are still being provided, to the chairmen of the various groups.
This procedure was used for all recommendations except those developed by the ad hoc committees on Instrument Air and Emergency Feedwater. These recommendations were submitted by the ad hoc committe'e chairman directly to the Steering Committee for disposition because these functions had not been included in the B&WOG standing committees. Following submission of the recommendations the ad hoc committees were dissolved.
Two other groups were formed by the B&WOG Executive Committee to round out the review and disposition process, the Independent Advisory Board (IAB) and the Safety anq Performance Recommendation Integration Group (SPRIG). The IAB was established in June, 1986 to overview the reassessment effort from an objective perspective. The IAB members were: Mr. W. H. Layman, EPRI, Chairman; Professor N. E. Todreas, MIT; Mr. R. S. Brodsky, BETA Corp. ; and Mr. S. Levy, Levy Associates.
Seven meetings during a period of one year were held, by the IAB to review the SPIP. Among other things, their assessment concluded that the SPIP had been effective in identifying areas that needed improve-ment and they generally concurred with the process and basis employed in prioritizing recommendations. In June, 1987, following the presentation of their final assessment to the B&WOG Executive Committee, the IAB was dissolved.
SPRIG was formed in March,1987 for the purpose of integrating and prioritizing the recommendations generated by the various committees and groups. The SPRIG met three times over a period of two months and produced a report containing 20 recommendations on prioritizing of the recommendations developed by the SPIP. Following issuance of the report, SPRIG was dissolved.
In addition to the documentation, the inspection team interviewed eight SPIP personnel who had active roles in the development of the SPIP recommendations. The purpose of the interviews was to 1 determine if any of the SPIP participants had any concerns over the management of recommendations generated in the committee reports through final disposition by the Steering Committee. The inspection team discussed the following subjects in its interviews with the listed representatives of the selected committees:
I I 1
7 l
l
ORGANIZATION: BABC0CK & WILC0X l LYNCHBURG, VIRGINIA l
REPORT INSPECTION N0.: 99900400/87-01 RESULTS: PAGE 8 of 23
- 1. Feedback process.
- 2. Appeal of rejected recommendations.
- 3. General satisfaction / dissatisfaction of the disposition process (i.e., recomendations being "watered down" or rejected without basis).
The following individuals were interviewed:
Bob Williamson, John Concklin, and Eric Swanson from the Availability Comittee (Main Steam Pressure Control).
~
Eric Swanson from the ad hoc committee on Instrument Air.
Stuart Rose of Duke Power (by telephone) from the task group that oversaw the comparative study of the sensitivity of B&W Reactor Plants.
Larry Reed of Duke Power (by telephone) from the ad hoc comittee on Emergency Feedwater.
Ron Dorman from the Instrument and Control comittee (ICS/NNI recom- l mendations). i R. Skillman of GPU Nuclear (by telephone), Chairman of the SPIP.
Feedback to the standing comittees has taken place since October, 1986. This mechanism appears to be satisfactory for informing them of the actions taken on their recommendations. In the case of ad hoc committees, these comittees were not formally notified of the Steering Committee actions. However, they knew what actions had been taken and were able to provide additional details of the rationale for rejection, except for the Instrument Air. In the case of the Instrument Air report, the chaiman could not provide any additional detail. This lack of providing feedback to the ad hoc comittees is viewed as a weakness by the inspection team.
All persons contacted felt that if they disagreed with the action taken by the Steering Comittee they could appeal the decision. The Chairman of the I&C comittee stated that they had successfully appealed a Steering Comittee decision. The Chairman of the SPIP also stated that if committee chairmen disagreed with the coments made in the transmittal letter to the Steering Comittee they would contact him and he would convey their concern to the Steering Comittee.
8
1 ORGANIZATION: BABC0CK & WILCOX LYNCHBURG, VIRGINIA 1
REPORT INSPECTION N0.: 99900400/87-01 RESULTS: PAGE 9 of 23 All contacted persons stated that they were satisfied with the process used for the disposition of the recommendations. Further, they knew of no one on the committees who were dissatisfied with the dispositions of the recommendations.
The inspection team feels the process used for dispositioning the recommendations was appropriate with adequate feedback to the originators of the action taken by the Steering Committee, with the exception of the weakness in not formally providing the ad hoc committees the results of the Steering Committee actions.
C. Areas Reviewed
- 1. Main Feedwater System - MFW The recommendations for the main feedwater system as set forth in "Main Feedwater Pump Trip Reduction Program Final Report,"
B&W Document No. 47-1159449-00, undated, and included as Appendix B-4, BAW-1919, were reviewed to determine their disposition. This report contained five recommendations. All five were accepted by the Steering Committee and placed in the RTS.
Thirty recommendations came from the report "B&W Owners Group Review of the June 9, 1985 Davis Besse Loss of Feedwater Transient," B&W Owners Group 1154 Task Force, August 1986.
These are reviewed in Section II.C.2 of this report.
Five reconmendations came from operating experience reports.
Two recommendations were redundant to existing recommendations in the RTS. The other three were placed in the RTS by the !
Steering Committee. !
i Based on this review, the inspection team has concluded that the recommendations concerning main feedwater are accurately I
reflected as final recommendations in the RTS and that the process by which this was done is adequately documented.
- 2. Review of June 9,1985, Davis Besse Loss of Feedwater Event (1154 Task Force).
The recommendations resulting from the B&W Owners Group 1154 Task Force review of the June 9, 1985 Davis Besse loss of 9
1 ORG ANIZATION: BABC0CK & WILC0X LYNCHBURG, VIRGINIA 1
REPORT INSPECTION NO.: 99900400/87-01 RESULTS: PAGE 10 of 23 feedwater event as set forth in Appendix H of BAW-1919, Safety and Performance Improvement Program, Revision 5 dated July, 1987, have been reviewed to determine their disposition.
The 1154 Task Force documented 64 recommendations. Of these, 56 were accepted by the Steering Committee and entered unchanged into the RTS. Five of the recommendations were considered by the Steering Committee to be duplicates of recommendations already in the RTS. The inspector agrees with this disposition cf these five recommendations. Three additional recommendations were retained for further review, one by the Steering Committee and two by the I&C Committee.
No recommendations were rejected.
The documents used in this review included: BAW-1919, Appendix H. Minutes of Steering Committee Meeting - 9/3-4/86, BAW-1919, Appendix J, and Action Item Tracking Report.
Based on the above review, the inspection team has concluded that the recommendations of the 1154 Task Force are accurately reflected as final recommendations in the RTS and that the process by which this was done is adequately documented.
- 3. Review of Category "B" and Category "C" Events at B&WOG Plants (1980-1984)
The reconctadations resulting from the B&W Owners Group Transient Assessment Connittee study of Category "B" and "C" events that occurred at B&WOG plants between 1980 and 1985 as set forth in Appendix I of BAW-1919, Safety and Performance Program, Revision 5, dated July 1,1987 have been reviewed to determine their disposition.
I The documents used in this review included: BAW-1919, Appendix I, Action Item Tracking system report, July 1987, Recommendation Tracking System, July 1987, Informal Listing of Steering )
Committee actions on recommendations, and Letter from i R. W. Ganthner to B&WOG Steering Committee, October 15, 1987. j The Transient Assessment (TA) Committee documented 31 recommen- ;
dations. Four of the recommendations were identified by the l TA Committee as duplicates leaving 27 recommendations to be !
dispositioned by the Steering Committee. Of these 10 were accepted by the Steering Committee and entered into the RTS.
Nine recommendations were sent back to the committee for further l
l 10
1 I
l ORGANIZATION: BABC0CK & WILC0X
- LYNCHBURG, VIRGINIA REPORT INSPECTION N0.
- 99900400/87-01 RESULTS: PAGE 11 of 23 l l
action and entered into the AIT system. The Steering Comittee I identified three recomendations that were duplicates of l recommendations already in RTS, One recomendation was combined I with another recomendatinn and entered into the RTS. One I recommendation was addressed by the 1154 Task Force. Three i recomendations were rejected.
The NRC inspection team concludes that all the recomendations contained in the review of Category "B" and Category "C" event report have been accounted for and that no substantive I differences exist between the recomendations contained in the report and those that have been approved by the Steering j Comittee and incorporated into the Recommendation Tracking '
System or those that are in the Action Tracking System. For ;
the recommendations rejected an adequate bases for rejection I has been provided and for those recommendations that were identified as duplicates or combined with other recomendations no substantive change in scope or content of the recomendations was observed.
- 4. Operator / Maintenance Personnel Interviews The recommendations resulting from the B&W Owners Group, Operator Support Comittee interview of operator / maintenance personnel as set forth in Appendix K of BAW-1919, Safety and Performance Improvement Program, Revision 5, dated July,1987, have been reviewed to determine their disposition.
The Operator Support Committee documented 11 recommendations.
Of these, 9 were accepted by the Steering Conmittee and entered unchanged into the RTS. The remaining 2 recomendations were retained for further review by the Operator Support Comittee.
No recomendations were rejected.
The documents used in this review included: BAW-1919, Appendix K, Minutes of Steering Comittee meeting 1/14-15/87,BAW-1919 Appendix J, & Action Item Tracking Report.
Based on the above review, the inspection team has concluded that the recomendations of the Operator Support Comittee are accurately reflected as final recomendations in the RTS and that the process by which this is done is adequately documented.
11
ORGANIZATION: BABC0CK & WILCOX LYNCHBURG, VIRGINIA REPORT INSPECTION N0.: 99900400/87-01 RESULTS: PAGE 12 of 23 l
- 5. Instrument Air System Review Report The recommendations resulting from the ad hoc group review of instrument air systems as set forth in Appendix M af BAW-1919, Safety and Performance Improvement Program, Revision 5, dated July, 1987, have been reviewed to determine their disposition.
The ad hoc group documented 60 recommendations. The Steering Committee determined that there was redundancy in 30 of the 60 recommendations such that these 30 could be placed in 8 groups of 2 to 6 recommendations in each group. The recomendations in each group were summarized, and the summary entered into the RTS.
The inspection teant has reviewed the process of consolidating recomendations and have concluded that the subje:t of each individual recommendation in the 8 groups is accurately reflected in the single RTS entry for each group respectively. Of the remaining 30 recommendations, 27 were entered into the RTS. The Steering Comittee determine.d that one recommendation was a duplicate of a recomendation already in the RTS. The inspection team agrees with the disposition of this one recommendation.
The documents used in this review included: BAW-1919, Appendix M, minutes of Steering Comittee meeting January 14-15, 1987, BAW-1919, Appendix J, SPIP recomendations rejected by the Steering Comittee, & Action Item Tracking Report.
The Steering Committee rejected recommendations 5.2.7 and 5.2.9.
The inspector determined that the basis for rejection has not been adequately documented by the Steering Committee. During verbal discussions with B&W Owners Group representatives, a valid basis was presented for rejection of these recommendations, but that basis was not included in the documentation reviewed by '
the inspector. The Steering Committee should reconsider these rejected recommendations with a view towards providing better documentation of the rationale for the rejection. The ad hoc l group should consider reviewing the basis for rejection.
Based on the above review, the inspection team has concluded that with the exception of 2.5.7 and 2.5.9, all of the ad hoc group recommendations in Appendix M of BAW-1919, are accurately l reflected in the RTS. The inspection team further concludes '
that the process for recomendation disposition is adequately !
documented except for the basis for the rejected recommendations 1 noted above.
1 1
12
i ORGANIZATION: BABC0CK & WILC0X LYNCHBURG, VIRGINIA l l
REPORT INSPECTION N0.: 99900400/87-01 RESULTS: PAGE 13 of 23 j
- 6. Main Steam Pressure Control Review The recommendations resulting from the B&W Owners Group !
Availability Committee review of main steam pressure control !
as set forth in Appendix N of BAW-1919, Safety and Performance Improvement Program, Revision 5, dated July, 1987, have been reviewed to determine their disposition.
The Availability Committee documented nine recommendations, two of which have a total of five sub-parts. The Steering Comittee determined that four complete recommendations and one recommenda-tion sub-part were duplicates of recomendations already in the RTS. The inspection team agrees with the disposition of these recommendations. Three complete recommendations and one recomendation sub-part were entered unchanged into the RTS.
One complete recommendation (consisting of three sub-parts) was rejected by the Steering Committee. The inspection team agrees with the rationale presented for this rejection.
The documents used in this review included: BAW-1919, Appendix N, minutes of Steering Committee meeting 1/14-15/87, BAW-1919 Appendix J Ltr. - R. F. Wichert to G. R. Skillman dated November 25, 1986 (w/ attachments). Ltr. - G. R. Skillman to Steering Committee dated December 18, 1986, & SPIP recommenda-tions rejected by the Steering Comittee.
Based on the above review, the inspection team has concluded that the recommendations of the Availability Comittee are accurately reflected as final recomendations in Appendix J of BAW-1919, or that an adequate basis for not including recommendations has been provided.
The process by which the recomendations of the Availability Committee became final recommendations is not, however, well documented. The recommendations set forth in Appendix N do not
- correspond directly to the recommendations forwarded from the l Availability Comittee to the Steering Committee (Ltr. - Wichert to Skillman November 25,1966). Therefore, in order to track the Appendix N recommendations, a reviewer must review the subject matter in the disposition of Availability Committee recommendations by the Steering Comittee to determine if the Appendix N recommendations are covered. At best, this is a
, subjective review. The inspection team has conducted such a l review and concluded, to the extent possible, that Appendix N recommendations are covered by final recomendations in the RTS.
1 13
ORGANIZATION: BABC0CK & WILC0X LYNCHBURG, VIRGINIA REPORT INSPECTION NO.: 99900400/87-01 RESULTS: PAGE 14 of 23 The transition from Appendix N wording of recommendations to what was finally submitted to the Steering Committee via the SPIP Committee Chairman is not documented. Handling of recommenda-tions from the SPIP Committee Chairman through the Steering Committee and into the RTS is however adequately documented.
- 7. Audit of Independent Sensitivity Study Recommendations These recommendations were prepared by MPR Associates Inc.,
Washington, D.C. under contract to the B&WOG with oversight management conducted by peer review personnel assigned from the B&WOG. The results of the study are contained in Appendix P l to BAW-1919, Revision 5 - Volume II, Conclusions Recommendations and Discussion of Results (Section B: Recommendations).
Five recommendation areas noted herein, containing specific reconcendations within each area, were sent without comment to the Steering Committee by the SPIP Chairman.
Recommendation 1 - Modifications to the Integrated Control System (105) to reduce the probability of the complex transients generated by failures in the ICS and particularly to reduce the probability of feedwater upsets generated by such failures.
There are 12 specific recommendations within this area plus an endorsement of four other measures already recommended by the ;
B&WOG Instrument and Control (IC) Committee for utility action at the time the sensitivity study was in progress. {
l The Steering Committee referred Reconmendation No. I area to ;
the I&C Committee as an action item described in AIT No. T-039. i The I&C Conmittee's ICS/NNI Evaluation Final Report Recommendations in Section VII of Appendix R to BAW-1919 Revision 5, incorporated the Sensitivity Study recommendations along with those derived from three other distinct sources -
the ICS/NNI Evaluation Matrix / Problems List; Failure Modes and Effects Analyses; and studies performed by other committees.
The I&C Committee report however did not separately identify the sources of the listed recommendations. Therefore, there
{
was no way to readily verify the disposition of the Sensitivity !
Study recommendations except by sifting through the I&C report and comparing the recommendations listed to those from the Sensitivity Study. Based on this type of screening six 14 k
l I l
l ORGANIZATION: BABC0CK & WILC0X
! LYNCHBURG, VIRGINIA REPORT INSPECTION NO.: 99900400/87-01 RESULTS: PAGE 15 of 23 Sensitivity Study recomendations were not listed in Appendix R.
(e(1), e(2), and f(1) through f(4)). The I&C Comittee currently has a draft report under review which will address its specific responses to the Sensitivity Study recomendations.
An audit of the draft report indicates that the six missing recomendations noted will be addressed.
Although the B&WOG indicates that recomendations e(1) and e(2) are included in the RTS as items TR-104-ICS and TR-153-IAS respectively, it is not clear that the details described in these recomendations are included within the broad scope of TR-104 and TR-153. The recomendations f(1) through f(4) recommend that any reconfiguration of ICS retain some of the key features described in f(1) through f(4), which are already in the existing ICS for B&W plants. This point needs to be documented to close out the issues. In any event, the burden of e(2)clearly and f(documenting
- 1) through f(4)the willdisposition be placedof onrecommendations the forthcoming e(1),
I&C report on the independent Sensitivity Study.
The six remaining recommendations from the Sensitivity Study (listed within Ib, Ic and Id) were included in Appendix R.
These are categorized as Level II recommendations in Appendix R, a classification which means that major modifications are needed to existing equipment or extensive evaluation is required. The merits of implementing the Level 11 recomendations are still under consideration by the I&C committee as discussed in Section VII C of Appendix R. i l
Recomendation 2 - Enhancement of Main Feedwater (MFW) relia- i bility so that, if two feed pumps are in operation, the single l failure of an active element will not lead to a total loss of l feedwater. l 1
l There are 16 specific recomendations made for this area listed '
l within 2a through 2d described in Section B of Appendix P. l
- This recomendation area was referred by the Steering Comittee l to the SPIP Management Team as an action item in AIT No. T-040.
The action was completed by SPIP. All recomendations were i
found to be duplicates of other recommendations entered into i
the RTS, except two, 2b(7) and 2c(1) (Letters SPIP Chairman to Steering Comittee dated 5/27/87 and 6/17/87). The two recommen-dations were subsequently combined and entered into the RTS as l
l 15 l
ORGANIZATION: BABC0CK & WILC0X LYNCHBURG, VIRGINIA REPORT INSPECTION N0.: 99900400/87-01 RESULTS: PAGE 16 of 23 TR-179. At the time of this inspection, the AIT report had not been updated to reflect the TR-179 entry into the RTS. TR-179 covers MFW and condensate reliability improvements and preventing single failures which is sufficiently broad to cover the issues raised in 2b(7) and 2c(1).
Recommendation 3 - Reducing susceptability to overcooling by emergency feedwater.
There are specific flow control alternatives described: specific flow control changes listed in recomendation 3a; or recommenda-tion 3b which proposed an analysis in lieu of the 3a recomen-dation.
Recomendation 3a was entered into the RTS as TR-155; and recomendation 3b was not justified since 3a was adopted.
Recommendation 4 - Elimination of the anticipatory reactor trip (ART) on turbine trip to reduce the possibility of overcooling.
Subsets of this recomendation deal with considerations of enhancement of capability to withstand turbine trips and load rejections, i.e., 2e 4c(1), increasing high reactor pressure trip setting to 2400 psi; and 4c(2), increasing flow capacity and. swiftness of control valve response for pressurizer spray.
This recommendation was considered by the Steering Committee to be a duplicate of RTS item TR-030 which recommended raising the ,
ART or turbine trip arming point from its current rating of 20 !
percent power to a higher level (Section 5 of BAW-1893). How- !
ever, TR-030 does not address disposition of the considerations i raised in 4c(1) and 4c(2). This issue is to be addressed in the i forthcoming Transient Assessment Committee report per discussions j with B&WOG representatives, i Recomendation 5 - Enhancement of steam flow control following reactor trips (optional recommendation) is offered primarily as l a means to reduce challenges to and hence maintenance of, steam safety valves. l There are three specific recommendations described in Sa, and 5b.
l The Steering Comittee referred this recommendation to the Valve Task Force as action item T-041. The action is still pending.
i 16 l 1
1 I
ORGANIZATION: BABC0CK & WILC0X LYNCHBURG, VIRGINIA REPORT INSPECTION N0.: 99900400/87-01 RESULTS: PAGE 17 of 23 1
- 8. Emergency Feedwater System l The recommendations for the emergency feedwater (EFW) system as set forth in "Auxiliary / Emergency Feedwater System Review Final Report", B&W Document Number 47-1168159-00, May 1987, and included as Appendix 0 of BAW-1919 were reviewed to determine their disposition. This report contains fifteen recommendations:
ten of these were accepted; two were rejected ; one was revised by the Steering Comittee and two require further action by the Steering Comittee.
Recommendation 2.1.7 concerned an R&D program to determine if more reliable controls are available and an information exchange program to provide each owner with the results of future changes.
The recomendation regarding the R&D program was rejected by the Steering Comittee as not necessary because the operating history of present controls has Seen good and considering the work done previously by the 1154 lask Force, Arkansas Pcwer & Light and Toledo Edison. The recommeadation regarding information exchange was rejected as unnecessary, because of the ongoing information exchange program that currently exists within the B&WOG.
Recommendation 2.2.5 concerned training of plant personnel specifically in areas where repetitive problems have occurred.
This recommendation was rejected by the Steering Comittee, because other training initiatives had already addressed this Concern.
l'.vomendation 2.1.6 concerned modification to the EFW Control System to provide continuous smooth flow control. The Steering Comittee revised the recomendation in an attempt to clarify that the EFW Control System should control the flow such that it is always appropriat.e for existing conditions and that on-off or single valve continuous flows are not acceptable.
The revised recomendation (TR-162-EFW) requires additional clarification to clearly state the desired objective.
Recomendation 2.1.1 and 2.2.1, are still under review by the i Steering Committee: T-046 and T-047 are related to how exchange ;
of information should be made for these recommendation.
- 9. ICS/hNI Evaluation The B&W Owners Group I&C Comittee has completed an investi-gation into the design and operation of the ICS/iiNI at B&WOG l
l l 17 l ,
ORGANIZATION: BABC0CK & WILC0X LYNCHBURG, VIRGINIA REPORT INSPECTION N0.: 99900400/87-01 RESULTS: PAGE 18 of 23 plants. This investigation was intended to identify problems and indicate solutions and improvements which which may reduce plants trips and/or reduce the severity of plant transients associated with the ICS/NNI. Appendix R of BAW-1919 Rev.5 is the repository for all recommendations formalized to date that pertain to ICS/NNI. As such it also includes these recommen-dations developed in Appendices C,D, and G to BAW-1919.
Recomendations in Appendices C,D, and G are covered before those in Appendix R.
Appendix C, "Final Report on Re-Evaluation of ICS Design i Features", B&WOG Transiant Assessmant Comittee, B&W Report 47-1163861, June 1968 was a pre-SPIP project. However, the .
results of the study were reviewed by the SPIP. This task l evaluated certain design features of the ICS design via plant operating experience. From this study changes were developed to those features which could reduce certain reactor trips.
There were four specific and six ancillary concerns identified.
These ten concerns were consolidated into four general recommend-ations. The Steering Comittee appraved and entered the four general recommendations into the RTS.
Appendix 0, "Improvement of ICS Response to Input Failures,"
B&WOG Transient Assessment Comittee, B&W Report 47-1164108, June 1986 was a pre-SPIP project. However the results of the study was reviewed by the SPIP. This document describes and sumarizes the engineering analysis performed in the evalu-ations of selected ICS inputs and presents the conclusions l drawn from this analysis. Seven recommendations were developed and later approved by the Steering Comittee. Two recomend-ations have since been superseded. The disposition of these recomendations was found to be adequate. 1 Appendix G," Results of Operator Support Comittee's Review of Procedures Related to Loss of ICS/NNI," B&WOG Operator Support ,
Comittee, B&W Report 47-1164196-00, May 1986 documents the results of a review of plant specific emergency operating procedures, B&WOG emergency operating procedures, technical bases document and operator training. Its purpost was to 4 evaluate the adequacy of those documents for handling a transient involving a loss ICS and/or NNI power. The five recomendations made were to strengthen weak areas in the existing procedures reviewed. These recommendations did not l go through the Steering Comittee because they were developed before the formation of the SPIP team. The inspection team i
! l l 18 i
l
ORGANIZATION: BABC0CK & WILC0X LYNCHBURG, VIRGINIA 4
REPORT INSPECTION NO.: 99900400/87-01 RESULTS: PAGE 19 of 23 was able to identify that the intent of the recommendations was included in recommendations that are in the RTS. However Appendix G was not referenced as a source document.
Consideration should be given to including Appendix G as a source document in the appropriate RTS recommendation.
Appendix R, "ICS/NNI Evaluation Final Report" contains the recommendations developed by the I&C Committee for improvement in the ICS/NNI system. The recommendations are categorized as Level I, Level II or Level III.
Level I recommendations were those that were deemed to provide immediate improvements to the operation, availability and reliability of the ICS/NNI. The I&C Committee submitted 59 Level I recommendation to the Steering Committee. 28 were approved by the Steering Committee and placed in the RTS for implementation. The other 31 are awaiting Steering Connittee action.
Level II recommendations potentially involved major modific-ations to the existing equipment. Their disposition is to be decided following evaluation of their operational benefits and practicality with respect to both economics and implementation.
Ten recommend 6tions are categorized as Level II, including the recommendation from the Sensitivity Study (Appendix P) that pertain to the ICS/NNI system. These have been entered in the AIT system and returned to the I&C Committee for further consideration. A report is in preparation by the I&C Connittee that will elaborate on these Level Il recommendations.
Level III consists of those recommendations concerned with replacement of the existing ICS/NNI system with a new system based on modern digital control technology. There are six recommendations listed. The B&WOG plan to pursue, as a follow-on activity to the ICS/NNI evaluation, the development of an Advanced Control System concept that will incorporate these six recommendations. Implementation will be in keeping with the state-of-the-art technology.
The NRC inspection team concludes that there is suitable accountability and traceability for all ICS/NNI recommendations submitted by the I&C Comnittee to the Steering Committee and from the Steering Committee through to the final disposition of the recommendations for system improvements. However, a majority of the ICS/NNI recommendations are still in a 19
ORGANIU.UON: BABC0CK & WILCOX LYNCHBURG, VIRGINIA REPORT INSPECTION N0.: 99900400/87-01 RESULTS: PAGE 20 of 23 processing stage within the I&C Comittee. Of those sent to the Steering Comittee only 47% of them have been approved and placed into the Recomendation Tracking System. The reminder are awaiting Steering Comittee action. The Steering Comittee has not. rejected any ICS/NNI recommendations. The issue of categorizing recomendations as Level I, II, or III will be included in the technical review of the ICS/NNI report.
- 10. Operator Burden Review I
The recommendations resulting from the B&W Owner Group Operator Support Comittee study of operator burden as set forth in Appendix S of BAW-1919, Safety and Performance Improvement Program, Rev. 5, dated July 1,1987, have been reviewed to determine their disposition. The document used in this review included: BAW-1919, Appendix S, Action Item Tracking Report, July 1987, Recomendation Tracking System Report, July,1987, Informal listing of Steering Comittee actions on recommendation '
and letter from R.W. Ganthner to B&WOG Steering Comittee.
April 23, 1987.
The Operator Support Comittee documented 13 recommendations.
Of these six were accepted by the Steering Comittee and entered into the\RTS. Five recomendations were sent back to the comittee for further action and entered into the AIT system.
Two recomendations were not sent to the Steering Comittee.
One recomendation related to managing of backlog work and its impact on operator burden was not released because the Operator Support Comittee made a longer term comitment to address this issue and develop specific recomendations. The other recommendation is related to the implementation of routine forums for information exchanges such as Owners Group meetings.
Because this recomendation is redundant to the charter of the B&WOG, the committee decided not to release it to the SPIP Chairman.
Included in Appendix S, the Operator Burden Report, are the results of the review of the eight SPIP project reports, contained in the Appendices to BAW-1919, prepared from an operator burden perspective. Section 2.2.4 contains general coments developed during the review of these reports and Tables 1, 2 and 3 list the recomendations from the eight reports to which the general coments apply. In addition Appendix B of Operator Burden Project Report provides specific coments to specific recomendations made in each of the eight 20
4 sN',
ORGANIZATIONi BABC0CK & WILC0X l ,c LYNCH 8URG, VIRGINIA REPORT , INSPECTION N0.: 99900400/M-01 . RESULTS: PAGE 21 of 23
'k a k y
1 SPIP-pFoject reports. These have been classified as comments 3 by the Operator Support Corrmittee, because they were deemed not significant enough to be considered recomendations.
Section 4.5.3 of the Safety and Performance Recomendation N -
Intergration Group (SPRIG) report (Appendix T of BAW-1919, Rev'. 5) on operator burden states that the Operator Burden "Report should be reviewed by each utility prior to implementing
. the identified SPIP recommendations and that SPRIG considers
\ ,
this report very useful from the stand point of reducing s -
operator action and burden. However, the recomendations
- ~
cont'ained in the RTS and identified in the Operator Burden report as important from an operator standpoint do not reference the Operator Burden report for review before implementation by s - the utilities.
The NE inspection team concludes that all the recomendations contained in the Operator Burden Project Report have been
- accounted for and that there are no substantive differences between the recommendations contained in the report and those that have been approved by the Steering Comittee and incorporated into the Recommendation Tracking System or those 3,- that are in the Action Item Tracking System. It is the opinion
' 1' of the 1rdpection team that the general and specific coments related to operator burden for the applicable recomendations identified in the Operator Burden report are not adequately referepod by the applicable recommendations so there is no reasonable assurance that operator burden will be addressed
_- at the appropriate time during implementation of the recommen-dations by the utilities. During the inspection the B&WOG represrdtstives acknowledged this as a potential problem and l
- stated th.t corrective action is under consideration.
- 11. Owner Grcup Program There are four programs under the B&WOG (see Figure 1), the l
Economic Benefit Program, the Regulatory Commitment Program, i' t*a Avai ubility Improvement Program and the SPIP. Generally l
_ the progruin under which a recommendation is placed is determined
< ' by the Steering Comittee at the time the recommenoation is s N, submitted to the Steering Committee for approval by the committees had task forces. Although the purpose of this i inspection was to review the SPIP recomendations, the inspection ;
team also revieried the other three programs to determine if any l of the recor.mndations evolving from these programs had trip i .
- l
~ .
~ j l
l \
ORGANIZATION: BABC0CK & WILC0X LYNCHBURG, VIRGINIA REPORT INSPECTION i N0 : 99900400/87-01 RESULTS: PAGE 22 of 23 {
l reduction benefits that should be included in the SPIP. The Recommendation Tracking System Report (July,1987) and Action Item Tracking System Report (July,1987) were utilized in this review,
- a. Availability Improvement Program There were 31 valid recommendations approved under this program and four potential recommendations in the Action item Tracking System. Of the 35 recomendations and potential recommendations only two were detennined to have direct trip reduction benefits. Recomendation AV-019-ADM, which is in the area of plant administration, recommended factoring the following into current procedures and practices, personnel training and administrative controls:
the review of existing equipment and panel labels for consistency with procedures, providing additional labeling of critical switches and valves on panels and equipment, applying enhancement principles used in control room design reviews, and providing warning signs in area containing equipment sensitive to nonnal operation.
Recommendation AV-020-ADM which is also in the area of plant administration recomends factoring the following into current procedures and practices, personnel training and administrative controls: the establishment of a feed back mechanism similar to that required for reviewing plant operating events to identify training and procedural deficiences, recomend changes and then provide actual training.
These two recomendations were approved in May 1986, at a time when the SPIP was in its initial stages of development.
At that time it was decided to retain these recomendations within the Availability Program where they had originated.
The B&WOG has stated that the recomendations from all programs are approved by the Steering Comittee, entered into the RTS and receive the same attention from the utilities with regard to evaluation and implementation.
This was verified by the inspection team review of the implementation status for all the recomendations contained in the RTS.
It is the inspection team's opinion that retaining these two trip reduction recomendations under the Availability Program is acceptable.
I 22
ORGANIZATION: BABC0CK & WILC0X LYNCHBURG, VIRGINIA REPORT INSPECTION l N0 : 99900400/87-01 RESULTS: PAGE 23 of 23 l
l
- b. Economic Benefits Program There has been one Economic Benefit recommendation approved unaer this program and four potential recommendations in the Action Item Tracking system currently under consider-ation. Neither this recommendation nor the potential recommendations appear to have trip reduction benefits,
- c. Safety and Regulatory Commitment Program There has been one Safety and Regulatory Commitment recom-mendation approved under this program and four potential recommendations in the Action Item Tracking System currently under consideration. None of these recommendations or potential recommendations appear to have trip reduction benefits.
In conclusion, the inspection team has determined that only two of the recommendations under these programs have any trip reduction benefits and it is acceptable for these two recommendations to remain under the existing program.
- 12. Personnel Contacted
- R. Black B&W *R. Rogers Duke Power Co.
J. Bohart B&W E. Swanson B&W B. Brooks B&W *J. Taylor B&W J. Concklin B&W R. Dorman B&W D. Downtain B&W
- D. Mars B&W
- A. Mercado B&W
- Attended exit meeting .
f i
l 23
s e
c T O I
N 5e T E Y e A DRD 0 1 R
$ g i .
eO A Y8T E
~ sS EI A R A P T O P VO S lt O
- _I cA EDD UePs l
8 t
eP s
e g _ 0AE8 0 0
_ 8C 5
_ R s 0
- _ s e _
O I 0
" 83 t
PO _ A m'
_ Fs 8
U At _
i L
s
_ Tce A Ss _
e e
A _
u p I" V E
s A E _
a T t
A T
_ s _
I 'l 8 e A P N _ A _ L 5 0
Pa t I E 8 aR AE e t
P a C _ CC ISC S ?. II C O" R
A I NUE SR I E
f 5
C A P eOD V 0 N " l CSA I
S
- 9 A A
W 6
" EEE P 4 TDL 3
g n
A I C R - s G 8 O
R P
- YT TN T
N - g t
eMtN E
T Y
E g gE AA A tA I 5 G TS S N aV L 0 0 OCR T E I g0a a 8 O W EE D N V g 9 Gl gP OA T U
S I
S OG A 1
O R E E E E y8A R H I Y
A mA T L
gIPC I L P AN I P vE T GEN GE E L E U N TA TM Nvr A wM f
M T T E 5 E I I $ l I a e c
R E UM RIR MI S O U C C m E R N. C G N E h MO EMA TOM E.
E TO I A E C SCC SC F M Y T A
0 aN 0 E f M R 3M A T MA AS E I A P E UN eCB AS D CiOA N EGEH t
A 8CPC f
f E
F A
S C
e t M t A mTAA A 5
^
I oI NECB FR S O8eOA CES ESPC M
l S
l Oe t
ns5mK AOA VCT l
"g .
F'SURE 2 ItJPUT FR0f1 I tJFORt1AT I 0t1 GATHERItJG PHASE i i f SPIP RECOMMENDAT. ION PROCESS - FLOW PATH DRIGINillING COMllI((
ORSPIP . - _.--__ - - - - - _ - - INDEPENDENT ADVISORY
' ROARD - TAR
- PROJ((l/IllSUl[M ' ,TO EXECUTIVE
, . - commEE
, Fm /
CGTD4TS '
/ U -
A' SAFETY f. PERFr.Rf1ANCE RECOMt1ENDATIOM INTEGRATION
[
- h 4.----*
TTEES / " ~
l / //
//
\ \ ) /
/
- /
w I Fm ' ,
J ,f w
&.* poppon, f
/
~ ~ ~
.f,J
\ \ --*~ ~ ~ ;
p g Wj g_/__. .
g E* j ej STEERING - - _ . . _ RESTER 11 T : .
.. _.._ .._.._ .._.._ ._..-- - --+
E l f ~' COMITTEE i 0T E connIITEB ---i :
ll .' ~., Ile i ll Es N, no j
lCLOSE-!
MT l
ilg s ~.,'~..s y 4 :
!I RECOnnENDRTION js 'a ACTION ITEt1 TRACKING i
l
,i TRACKING
,_, NOTINTORTS
"'" "' ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
AiT Bs SYSTEM i gg; ggg)
IAB 3 RTS l
1 l
r i U FEEDBACK l
EXECUTIVE ~ LUILITY C0ft1ITTEE a - -
- 0lNITim i 1
L______' *Interin function l
i
ORGANIZATION: CIMCORP ST. PAUL, MINNES0TA
{ REPORT INSPECTION ] NSPECTION NO.: 99901095/87-01 DATES: 09/28-10/02/F7 ( N-SITF HnllPR- 17 CORRESPONDENCE ADDRESS: CIMCORP ATTN: Mr. H. Wals President 615 North Enterprise Aurora, Illinois 60507 ORGANIZATIONAL CONTACT: Mr. John Manship TELEPHONE NUMBER: (612) 484-7261 NUCLEAR INDUSTRY ACTIVITY: Fabricator of spent fuel storage racks.
I ASSIGNED INSPECTOR: sf
'R. L~ Cihmberg, Pro m Development and Reactive
"/ f7 Date Inspection Section PDRIS)
OTHERINSPECTOR(S): D. J. Lynn, Consultant APPROVED BY:
E.T. Baker,ActingChief,PDRIS,VendorInspectionBranch05te[ [
1 INSPECTION BASES AND SCOPE-A. BASES: 10 CFR Part 50, Appendix B, 10 CFR Part 21.
B. SCOPE: Follow-up an allegation concerning welder qualification and QA program implementation related to fabrication of spent fuel storage racks.
PLANT SITE APPLICABILITY: VermontYankee(50-271).
! 27 l
ORGANIZATION: CIMCORP ST. PAUL, MINNES0TA REPORT INSPECTION NO . QQQn1nOR/R7 01 RFRill TR
- DACF ? mf A A. VIOLATIONS:
Contrar: to Section 21.31 of 10 CFR Part 21 a review of documentation packacas for spent fuel storage racks (SFSRs) fabricated urader Yankee Atonr.c Electric Company (YAEC) specification YA-F17 "Specification for Design and Fabrication of Spent Fuel Racks for BWR plants, "Revision D, dated February 11, 1977, revealed that while 10 CFR Part 21 was imposed on CIMCORP by Vermont Yankee Nuclear Power Corporation (VYNPC), CIMCORP did not specify that 10 CFR Part 21 requirements would apply on purchase orders (P0s) 1577, 70484, 70598 to Industrial Stainless Supply; 70574, 70840 to Aluminum Fasteners; 1646 to C&M Incorporated; and 1663 to Temroc Metals. (87-01-01)
This is a Severity Level V violation (Supplement VII).
B. ,NONCONFORMANCES:
- 1. Contrary to Criterion VII of Appendix B to 10 CFR 50 and Section 5.3 of YA-F17. Revision D, material test reports were not supplied for material ordered on CIMCORP P0s 1577, 70484, 70598, 70574, 70840, 1646, and 1663. (87-01-01)
- 2. Contrary to Criterion XII of Appendix B to 10 CFR 50 and Section 6-2.0 of QCP-100-6, "Identification, Inspection, and Control of Product Items," Revision 8, dated February 5,1985, thermometer SN-2319 which is used to verify the temperature of the weld rod oven has notcalibration last recorded been calibrated every two date of August years(87-01-02 4,1983. as indicated by)the
- 3. Contrary to Criterion V of Appendix B to 10 CFR 50 and Section 3 of QCP 42, "Control of Welder Qualification Procedure," Revision 12 dated January 9, 1980, two forms entitled "Record of Welder or Welding Operator Qualification Tests" and "Welder or Welding Operator Test" are being used to record qualification results but the fonns have not been approved nor referenced in QCP-42. Revision 12. ,
(87-01-03)
C. UNRESOLVED ITEMS:
None.
D. STATUS OF PREVIOUS INSPECTION FINDINGS:
Not applicable, i
28
ORGANIZATION: CINCORP ST. PAUL, MINNES0TA REPORT INSPECTION wn . oooninoc/azs11 pretit Ts. our 7 a g E. INSPECTION FINDINGS AND OTHER COMMENTS:
- 1. Entrance and Exit Meetings l
[ The NRC staff informed CIMCORP management representatives of the scope of the inspection during the entrance meeting on September 28, 1987, and summarized the inapection findings and observations during the exit meeting on October 2, 1987.
- 2. Allegation An allegation was received by NRC which alleged that welder #1 welded a test coupon for the alleger (ALGR) and the coupon was submitted for bend testing as having been welded by the ALGR. The ALGR Yankee subsequently performed Nuclear Power Station (VYNPSwelding)on
. two SFSRs for the Vermont The inspectors reviewed the qualification documents of all welders who performed production welding on the SFSRs. This review which covered qualification of welders since 1975 did not reveal any infor-mation which would substantiate the allegation. The welding of test coupons by the ALGR wLs witnessed by the welding foreman as recorded on qualification forms datid May 1, 1987, and June 2, 1987, for WP-30 and WP-21 weldirg procedures. Both forms contained signature approval by the welding engineer.
Discussion with CIMCORP Dersonnel determined that the ALGR was more skilled in operating the seam welder than welder #1 and documenta-tion indicated that the ALGR ve =lifiW cn the seam welder one month before welder *L The CtMCORP welding engineer stated that the ALGR was assigned to the welding of SFSRs in part to train ,
welder #1 in the use of the seam welder. The historical information indicates that the ALGR was well qualified in the processes which he used to weld the SFSRs for the VYNPS. The allegation could not be substantiated.
- 3. Spent Fuel Racks l
The SFSRs currently installed at the VYNPS were manufactured by the Progrened and Remote Systems Corporation (PAR) which is now a part of CIMCO?P. VYNPC issued P0 30516 dated March 17, 1987, to CIMCORP for the fabrication of two SFSR 10 x 10 modules for the VYNPS, P0 30516 imposed VYNPC QA requirements dated March 10, 1987, and YAEC l specification YA-F17, Revision D on CIMCORP. The requirements of 1
29 l
ORGANIZATION: CIMCORP ST. PAUL, MINNES0TA REPORT INSPECTION Nn
10 CFR Part 50, Appendix B were referenced in YA-F17 and 10 CFR j Part 21 was referenced in the VYNPC QA requirements dated March 10, i 1987. The two SFSR 10 x 10 modules are currently located at the VYNPS. CIMCORP was not fabricating any SFSRs during the inspection.
- 4. Welding Records The NRC inspectors reviewed 530 fabrication and inspection records which documented the welding and inspection for the two SFSRs during June, 1987. This review' determined that four welders perfonred all of the welding on the SRSRs and the welder and procedure identifica-tion was used to support the qualification review in Section 5 below.
The 530 records were documented in accordance with QCP-04-9018, Revision 1, with the exception of one typographical error which listed a welder identification number which did not exist. The error was corrected and documented by the CIMCORP QA manager before the end of the inspection.
- 5. Welder Qualification The welder qualifications to applicable Welding Procedure Specifica-tions(WPS),ProcedureQualificationRecords(PQR)anddesign specification requirements were reviewed. Each welder record included his identification number, the WPS to which he was qualified and the supporting PQRs. Documentation for the four welders who performed welding on the SFSRs for the VYNPS was reviewed. The documentation covered qualification of the four welders for the last seven years.
Two forms were used to document and control qualification of welders which are not described in QCP-42, Revision 12 which is the QA procedure for welder qualification. "Record of helder or Welding Operator Qualification Tests" is required by Section IX of the ASME Boiler and Pressure Vessel Code and is one of the fonns being used by CIMCORP which is not described in QCP 42, Revision 12. "Welder or Welding Operator Test" is a fann which is used to verify that the welder taking a test is supervised during the test, and this form is 1 also being used by CIMCORP without being described in QCP 42 Revision 12.
The records of four welders qualified to the applicable WPSs were in I compliance with design requirements but two of the forms lack signature approval and are not referenced in QCP 42, Revision 12. ,
(See nonconformance 87-01-03) i 30 I i
ORGANIZATION: CIMCORP ST. PAUL, MINNESOTA i
l REPORT INSPECTION Mn - QQQn100R/A7.n1 RFRHfTR. Pant R nf A
- 6. Weld Filler Material Control The inspectors review of weld material purchase, receipt inspection, storage, and issuance of weld filler materials was determined to be in accordance with QCP-36, "Control of Weld Filler Materials,"
Revision 9, dated February 1, 1983.
- 7. Material Test Reports The inspectors reviewed documentation packages to determine if material test reports contained the chemical and mechanical properties of the aluminum alloys used in the fabrication of the SFSRs for the VYNPS. This review revealed that the test reports required by YA-F17, Revision D were missing for material supplied to seven P0s as described in Section B. above. (See nonconformance 87-01-01)
- 8. Control of Measuring and Test Equipment The NRC inspectors reviewed calibration stickers on neasuring and test equipment to detennine if calibration intervals met the require-ments of QCP-100-6, Revision 8. A thermometer identified by serial number SN-2319 is used to measure the temperature of the weld rod oven. This thermometer was last calibrated on August 3, 1983, while Section 6-2.0 of QCP-100-6 requires that temperature measuring devices be calibrated every two years. (See nonconformance 87-01-02) 9, 10 CFR Part 21 CIMCORP procedure AP-1, "Reporting of Defects and Noncompliance to the Nuclear Regulatory Commission," Revision 3, dated August 14, 1984, implements 10 CFR Part 21 at CIMCORP. Section 206 of the Reorganization Act of 1974 and a copy of 10 CFR Part 21 are attach-ments to AP-1. AP-1 with attachments is posted on the CIMCORP bulletin board in the production area.
The inspectors determined by documentation package review that P0s issued to suppliers of aluminum alloys used in the SFSRs for VYNPS did not s 87-01-01)pecify the requirements of 10 CFR Part 21. (See violation 31
ORGAN 1ZAT10h. 114 CORP Ayt, MINNES0TA REPORT INSPECTION Nn . QQQninO4/A7.01 R frill T9 DanF A af K l 1
- 10. Internal Audits The inspectors reviewed 15 internal audit reports which addressed different areas in accordance with written procedures, plans, and checklists. The reports were determined to be in compliance with Section 19 of the CIMCORP QA Manual Revision 6, dated February 26, 1987.
F. PERSONS CONTACTED:
M. Benoit R. Berry
- W. Calin
- J. Cunov
- J. Manship
- G.' Rose W. Skiba
- A. Sturm
- N. Tucker
- Attended exit meeting, i
32 1
ORGANIZATION: COMBUST 10N ENGINEERING, INCORPORATED WINDS 0R, CONNECTICUT REPORT INSPECTION INSPECTION N0.: 99900002/87-01 DATES: 08/24-28/87 ON-SITE HOURS: 32 CORRESPONDENCE ADDRESS: Combustion Engineering, Incorporated i ATTN: Dr. P. L. McGill i Vice President, Nuclear Fuel 1000 Prospect Hill Road Windsor, Connecticut 06095 ORGANIZATIONAL CONTACT: Mr. M. Glotzer TELEPHONE NUMBER- 203-PRG-RO?4 NUCLEAR INDUSTRY ACTIVITY: Nuclear fuel assembly supplier for Combustion Engineering (CE) and Westinghouse designed reactors, b i ,
ASSIGNED INSPECTOR: /t.mu% st rr f7 R. L. Cilimbsrg, Program /)fevelopment and Reactive Date Inspection Section (PDRIS)
OTHERINSPECTOR(S): D. J. Lynn, Consultant APPROVED BY: @g /d 4 7 J.gC.' Stone, Chief,PDRIS,VendorInspectionBranch at INSPECTION BASES AND SCOPE:
A. BASES: 10 CFR 21 and 10 CFR 50, Appendix B.
B. SCOPE: Review tubing fabrication and testing, fuel pellet manufacturing and testing, follow-up corrective action on previous inspection findings, and evaluations by CE of the leaking fuel at various facilities.
PLANT SITE APPLICABILITY: San Onofre 2/3 (50-361/362), Calvert Cliffs 1/2 (50-317/318), Palo Verde 1/2/3(50-528/529/530), Waterford (50-382), St.
Lucie 2 (50-389), Maine Yankee (50-309), Yankee Rowe (50-029), Arkansas 2 (50-368), Fort Calhoun (50-285).
33
ORGANIZATION: COMBUSTION ENGINEERING. INCORPORATED WINDSOR, CONNECTICUT REPORT INSPECTION NO.: 99900002/87-01 RESULTS: PAGE 2 of 8 A. VIOLATIONS:
None. I l
B. NONCONFORMANCES: j
- 1. Contrary to Criterion VIII of Appendix B to 10 CFR 50 and Section 8.4.1.7 of the CE Quality Assurance Manual (QAM), Revision dated ,
May 4,1987, implies that traceability shall be maintained only i when required by contract. (87-01-01)
- 2. Contrary to Criterion V of Appendix B to 10 CFR 50, the CE QAM references Temporary Shop Instructions (TSIs) and there are no documents available, to describe how to use TSIs relative to the CE QA program. (87-01-02)
- 3. Contrary to Criterion V of Appendix B to 10 CFR 50, and Sections 3.2.2 and 4.0 of QC-15-14. "Procedure for Special Process Qualifica-tion," Revision 1, dated March 18, 1987, MFG-15-05, "Process Specification for Grinding Pellets," Revision 0, dated November 23, 1971, does not contain the required parameters or procedures.
(87-01-03)
- 4. Contrary to Criterion V of Appendix B to 10 CFR 50, and Step 4 ,
of OS 419, "Machine First End," Revision 2, dated September 16, l 1974, end cap protection was not installed on the machined end i i
of guide tubes although the sequence had been signed off as I complete on traveller ES 120-B. (87-01-04) j
- 5. Contrary to Criterion V of Appendix B to 10 CFR 50, and Section 3.11 of 05 510. "Load Fuel," Revision dated May 4, 1987, one door to the stacking and loading room was propped open for 30 minutes. (87-01-05)
C. UNRESOLVED ITEMS: !
(0 pen) Unresolved During the inspection, a CE employee alleged to the NRC inspectors that he had observed other CE employees putting oversized fuel pellets in '
trays containing acceptable fuel pellets. This was alleged to have occurred occasionally on the second and third shifts during 1985 and 1986.
On August 23, 1987, a Southern California Edison (SCE) auditor observed an oversize fuel pellet that prevented CE personnel from loading a stack 34 i
+
t
ORGANIZATION: COMBUSTION ENGINEERING, INCORPORATED WINDSOR, CONNECTICUT REPORT INSPECTION N0.: 99900002/87-01 RESULTS: PAGE 3 of 8 of fuel pellets in zircaloy tubing to be used for fuel rods in the batch F reload for the San Onofre (SONGS) Unit 2 reactor. CE increased their surveillance of pellet production and discovered a large number of oversize pellets. CE is investigating the allegation, and evaluating pellet deviations in addition to obtaining other information concerning safety implications of pellet dimensional problems. This item will remain open until CE provides NRC with an answer to the allegation and resolution of the fuel pellet dimensional problems.
D. STATUS OF PREVIOUS INSPECTION FINDINGS:
- 1. (Closed) Nonconformance (86-01-01):
Contrary to Section 6.6.2 of the CE QAM, Revision 1, dated January 22, 1986, ink chan of Operation Sheet (0.S.) ges were 925, Number made"Leak to Sections B.4.0 and Test," Revision 32,B.5.0 dated June 1984, without the proper approvais.
The NRC inspectors determined that the proper approvals were obtained on July 24, 1986, and review of other documents has not revealed any additional ink changes.
- 2. (Closed) Nonconformance (86-01-02):
Contrary to Section B.7.0 of 0.S. Number 945, "Leak Test,"
Revision 32, dated June 1, 1984, the helium leak test was not being conducted for a minimum of 30 seconds as required.
1 The NRC inspectors determined that the equipment used to perform the helium leak test has been replaced with a new leak detector with an electronic test circuit that automatically achieves the times required for leak testing fuel rods.
i E. INSPECTION FINDINGS AND OTHER COMMENTS:
1
- 1. Entrance and Exit Meetings !
- The NRC staff informed CE management representatives of the scope of the inspection during the entrance meeting and summarized the inspection findings and observations during the exit meeting on August 28, 1987.
l
, l l
35
ORGANIZATION: COMBUSTION ENGINEERING, INCORPORATED WINDSOR, CONNECTICUT REPORT INSPECTION N0 : 99900002/87-01 RESULTS: PAGE 4 of 8
- 2. Fuel Pellet Manufacturing CE informed the NRC inspectors that fuel pellet dimensional l problems were slowing production of the Batch F reload for the SONGS Unit 2 reactor. SCE has been auditing CE manufacturing of fuel bundles for the SONGS Units 2 and 3 reactors on all shifts since June 1987. On August 23, 1987, a SCE auditor observed i an oversize pellet that prevented CE personnel from loading a j stack of fuel pellets in zircaloy tubing to be used in the Batch '
F reload. CE initiated a number of TSIs to provide extensive manual measurement on a large sample of fuel pellets prior to loading stacks of pellets in tubing. This was the situation that existed when the NRC inspectors entered the fuel pellet area on August 25, 1987.
- 3. Fuel Pellet Grinding The NRC inspectors reviewed CE procedures OS 517, "Operating Instructions Grinder Area," Revision 17, dated June 29, 1987; MFG-15-05, "Process Specification for Grinding Pellets," Revision 0; QC 1514 "Procedure for Special Qualification," Revision 1; 05 1477, "Pellet Shop In-Process Checks," Revision 39, dated August 10, 1987, and the CE QAM, Revision dated May 4, 1987. During this review the inspectors determined that MFG 15-05 does not contain j the parameters or procedures required by QC 15-14, Revision 1. ;
(See Nonconformance 87-01-03.) l The inspectors observed the grinding of pellets in accordance with OS 517, Revision 17, and finished pellet surveillance in accordance with OS 1477. Revision 39. The inspectors noted that the roller-micrometers were designed to separate undersize pellets into tray j one, acceptable pellets into tray 2, and oversize pellets into tray 3. '
During the inspectors observation of these processes on August 26, 1987, a CE employee alleged that he had occasionally seen three operators putting oversize pellets in tne acceptable tray during 1985 and 1986. (See Section C of this report.)
- 4. Fuel Pellet Stacking The NRC inspectors reviewed OS 510. "Load Fuel," Revision 55, dated June 30, 1987, and observed that operators were following the steps of this procedure for stacking, inspection, and rotation of troughs.
However, the inspectors observed that one of the doors to the 36
ORGANIZATION: COMBUSTION ENGINEERING, INCORPORATED WINDS 0R, CONNECTICUT REPORT INSPECTION NO.: 99900002/87-01 RESULTS: PAGE 5 of C stacking and loading room was propped open for 30 minutes. The l inspectors told the CE supervisor who immediately closed the door.
l (See Nonconfonnance 87-01-05.)
i l S. Fuel Pellet Inspection On August 25, 1987, the inspectors observed CE inspectors selecting pellets from troughs and measuring the diameter of the pellets in accordance with TSI 107, dated August 24, 1987. The dimensions of the pellets measured were oversize and did not meet specifications so the pellets in the stacking room could not be released for loading into tubing for fuel rods. The inspectors determined that the TSI is not referenced in the QAM, Revision dated May 4, 1987, and a document is not available in the CE QA system which prescribes the proper use of a TSI. (See Nonconformance 87-01-02.)
- 6. Stop Work On August 27, 1987, the NRC inspectors were advised by the CE QA Manager that he had issued a stop work order on fuel rod loading, upper end cap welding, fuel rod processing and inspection, and fuel bundle assembly, containerization and shipment. The inspectors were provided with a copy of the written "Stop Work," dated August 27, 1987, which also identifies the requirements for lifting the "Stop Work."
- 7. Guide Tube Processing The inspectors reviewed OS 419, "Machine First End," Revision 2, and observed the processing of guide tubes according to 05 419 and traveller ES 120-B. Guide tubes were observed in a carrying box with machined ends that were not protected with plastic caps as required by Step 4 of OS 419. The protector cap installation had been signed off as complete on traveller ES 120-B. (See Noncon-fonnance 87-01-04.)
- 8. Document Review l The NRC inspectors reviewed shop travellers for outer guide tube assembly (Lot A-69), tube cleaning (Lot 201), flange part E 6111-B !
(Lots 189 and 190) and grid cage assembly part EV-100A (Lot Cl-22) ;
and procedures OS 2159, Revision 4 and OS 2402, Revision 9. Obser- ;
vations determined that operations complied with the proper i sequencing and sign-off of travellers in conformance with approved procedures.
4 37
ORGAN!ZATf0N: COMBUSTION ENGINEERfNG, INCORPORATED WINDS 0R, CONNECTICUT REPORT INSPECTION i NO : 99900002/87-01 RESULTS: PAGE 6 of 8 ;
- 9. Internal Audits i The inspectors reviewed internal audit reports on material identifica-tion and traceability and determined these reports to be in compliance with Section 18 of the QAM, Revision dated May 4, 1987.
- 10. Equipment Calibration The inspectors determined that the micrometer with serial number 13-04-16 and roller micrometer standards set number 7 were calibrated in accordance with Section 12 of the QAM, Revision +
dated May 4, 1987,
- 11. Helium Leak Testing The inspectors reviewed OS 945, "Operation of Varian Leak Detector,"
Revision 36, dated July 15, 1987, which details the steps required to calibrate and operate the Varian Leak Detector (VLD).
The VLD equipment replaces the helium leak tester used to perform leak tests which resulted in nonconformance 86-01-02. The VLD equipment automatically achieves the times required for leak testing fuel rods which replaces this function being performed manually by an operator. Document review did not reveal any ink changes being made since the last inspection.
Nonconformances 86-01-01 and 86-01-02 were closed out as a result of the inspection in this area.
- 12. Fuel Performance CE currently manufactures fuel bundles / assemblies for (13) pressurized water reactors (PWRs). The PWRs that use CE fuel are San Onofre Units 2 and 3; Calvert Cliffs 1 and 2; Palo Verde 1, 2, and 3; St. Lucie 2, Waterford, Maine Yankee, Yankee Rowe, Arkansas 2, and Fort Calhoun. The CE Nuclear Fuel Projects group estimated that 127 fuel rods have leaked as a result of hydride failures initiated by inadequate drying of tubing used for fuel cladding. Arkansas '
Unit 2 contained 8 leaking fuel rods that were fabricated in 1977 i
to 1978 and 6 leaking fuel rods that were fabricated in 1983. St.
Lucie 1 contained 8 leaking fuel rods that were fabricated in 1981.
SONGS Unit 3 contained 105 leaking fuel rods fabricated in 1981. CE estimates that all fuel rods fabricated in a time period which I
l 38
ORGANIZATION: COM8USTION ENGINEERING, INCORPORATED WINDSOR, CONNECTICUT REPORT INSPECTION NO.: 99900002/87-01 RESULTS: PAGE 7 of 8 would make them susceptible to hydride failure will be out of operating reactors in 1988.
CE has used ultrasonic fuel inspection systems to nondestructively test fuel rods at reactor sites. The inspection systems detect the presence or absence of moisture on the inside of the fuel rods. If water is detected in a fuel rod, that rod has experienced a breach in the cladding. The results of these inspections are as follows:
(1) Arkansas Unit 2 - June 1986 Inspection of 177 assemblies identified 6 leaking rods by primary hydriding, 4 leaking rods by debris in the core, and 3 leaking rods by spacer grid fretting.
(2) Calvert Cliffs Unit 1 - October 1986 Inspection identified I leaking rod by debris fretting, 1 leaking rod by fretting at an inco.iel grid arch, and the cause of I leaking rod was unknown.
(3) Calvert Cliffs Unit 2 - March 1987 Inspection identified 5 leaking rods by debris fretting and i leaking rod was by an unknown cause.
(4) Maine Yankee - March 1987 I
Inspection identified 2 leaking rods by debris fretting and 2 leaking rods was by unknown causes.
(5) Yankee Rowe - May 1987 Inspection identified 14 leaking rods which were probably caused by baffle - jetting.
F. PERSONS CONTACTED:
G. Buddenhagen D. Byerly
- G. Chalder E. Chan C. Collins 39
ORGANIZAT!0N: COMBUSTION ENGlNEERING, INCORPORATED WINDSOR, CONNECTICUT REPORT INSPECTION N0.: 99900002/87-01 RESULTS: PAGE 8 of 8 W. Coppersmith i I. Courser l M. Czupryna l M. Defranzo l G. Dube l M. Duval F. Enos R. Freeman
- M. Glotzer M. Guagengi J. Lema
- P. McGill J. Presbie
- F. Stern R. Tergliafera T. Vallon
- Attended exit meeting.
i J
l l
l ;
40 l l
ORGANIZATION: COOPER INDUSTRIES GR0VE CITY, PENNSYLVANIA REPORT INSPECTION INSPECTION NO.: 99900317/87-02 DATES: 10/05-10/09/87 ON-SITE HOURS: 102 CORRESPONDENCE ADDRESS: Cooper Industries Cooper Energy Services ATTN: Mr. F. Bruce Stolba, Vice President and General Manager l 150 Lincoln Avenue Grove City, Pennsylvania 16127 ORGANIZATIONAL CONTACT: W. H. Allen Lambert, Manager of Quality Assurance TELEPHONE NUMBER: (412)458-8000 NUCLEAR INDUSTRY ACTIVITY: Original equipment manufacturer of standby diesel generators for nuclear service. Current sales are in parts, repair, and service only. There are no current orders for standby diesel generators at conroercial nuclear facilities.
ASSIGNED INSPECTOR: M(u )
I-87 (4 Ft. g. Prescott, ram Development and Reactive Date 1 \laspection Sect (PDRIS)
OTHERINSPECTOR(S): J. T. Conway, (NRR)
E. Tomlinson ,(NRR)
Q / *. , //
,'#/F/
APPROVED BY: / / b; <F 7/
E. T. Baker, Acting Chief, PDRIS, Vendor Inspection 'M Branch INSPECTION BASES AND SCOPE:
A. BASES: 10 CFR 21 and 10 CFR 50, Appendix B.
B. SCOPE: This inspection was performed in response to several recent TOTfR Part 21 and 10 CFR 50.55(e) reports involving Cooper standby diesel generators. In addition, the purpose of this inspection was to review several issues concerning the Palo Verde Unit III 3B emergency dieselgenerator(EDG).
PLANT SITE APPLICABILITY: Byron 1 and 2. (50-454, 455); Braidwood 1 and 2, (50-456,457); Palo Verde 1, 2, and 3, (50-528, 529, 530); South Texas 1 and 2, (50-498,499).
l I
41 1 i
ORGANIZATION: COOPER INDUSTRIES GR0VE CITY, PENNSYLVANIA REPORT INSPECTION NO.: 99900317/87-02 RESULTS: PAGE 2 of 13 A. VIOLATIONS:
Contrary to Section 21.31 of 10 CFR Part 21, a review of purchase orders (P0) to service vendors revealed that while 10 CFR 21 was imposed upon the Energy Services Group (ESG), ESG did not impose 10 CFR Part 21 require-ments on P0s 392188193 to Dresser Industries, 3421B5592 to E. J. Daiber, 3921B5288 to Huygen Corporation. 392186126 to Starrett, 3421B5845 to Page-Wilson, and 342186047 to Automation /Sperry. (87-02-01)
B. NONCONFORMANCES:
- 1. Contrary to the QA Program Statement of Authority in QAM-1000-1.
Criterion VII of Appendix B to 10 CFR Part 50, and Section 8 o' ANSI N45.2, there was no documented evidence that a survey or audit had been undertaken on eight vendors who performed services for ESG.
The vendors include Dresser Industries, E. J. Daiber, Magnaflux Corporation, Huygen Corporation, Starrett, Edmunds Manufacturing, Page-Wilson, and Automation /Sperry. (87-02-02)
- 2. Contrary to the QA Program Statement of Authority in QAM-1000-1, Criterion IV of Appendix B to 10 CFR Part 50, ano Section 5 of ANSI N45.2, the requirerrent to have an acceptable QA program was not included or referenced in P0s to Dresser Industries (3921B8153),
E. J. Daiber (342185592), Huygen Corporation (392185288), Starrett (392166126), Page-Wilton(342185045), and Automation /Sperry (342186047),(87-07-03)
- 3. Contrary to Criterion 1 of Appendix B to 10 CFR Part 50, Section 2 of ANSI N45.2, and Section 2.1.1 and 2.2 of the Ouality Assurance Manual (QAM), the responsibilities and authority of the Field Services Manager and the Site Representatives were not documented in the ESG Nuclear QA Program or identified in Exhibit 2-1. (87-02-04)
C. UNRESOLVED ITEMS The root cause of the cracking of the cylinder head on the #8-R cylinder on Palo Verde's 32-ELG is not known and is considered an unresolved issue (87-02-05). ;
D. OTHER FINDINGS AND COMMENTS:
- 1. Organization The Reciprocating Division and Rotating Division of ESG are located in Grove City, Pennsylvania and Mt. Vernon, Ohio, respectively. The QAN indicates that the ESG QA Program is designed to provide control :
l 42 i
ORGANf2AT10N: COOPER INDUSTRIES GROVE CITY, PENNSYLVANIA REPORT INSPECTION N0.: 99900317/87-02 RESULTS: PAGE 3 of 13 in all phases of company performance at the Mt. Vernon and Grove City facilities. In conversations with the Quality Control (QC) Manager end the QC Supervisor, both from the Reciprocating Division, the l inspectors were told that the ESG site representatives report to the i Manager of Field Services who in turn reports to the Manager of Marketing and Distribution located in Mt. Vernon. It was also noted that the site representatives do not receive any orientation or training in the QA Program.
The four organizational cnarts in Section 2, "Quality Program Manage-ment " of the QAM did not identify the department of Field Services as being covered by the ESG QA program. In addition, the responsi-bilities and authority of the Manager for Field Services and the site representatives were not documented in the ESG QAM. (See Nonconformance 87-02-04)
- 2. Palo Verde Unit III, 3B EDG Cylinder Head
- a. Background In late May 1987, reassembly of the 3B Emergency Diesel Generator (EDG), following extensive repairs, was completed.
On June 2,1987, 3B EDG was operated for about 15 minutes with apparent success. Following this operation, the EDG was shut l down for approximately 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, at which time an attempt was 1 made to restart the EDG, which was unsuccessful. It was l subsequently detenained that 3B EDG had experienced a l "hydraulic lock" on the #8-R cylinder which prevented the -
engine from rotating. The cause of the hydraulic lock was coolant water entering and filling the #8-R cylinder via a ,
through crack between the cooling water passages and the fire '
face of the #8-R cylinder head. As a consequence of excessive i forces developed during the hydraulic lock, the #8-R cylinder !
liner also cracked.
l To date, all involved parties agree that there is/us a crack i in the #8-R cylinder head, that the water in the #8-R cylinder l was the cause of the EDG failure to start, and that the 18-R cracked cylinder liner was a direct result of trying to start
.l 3B EDG with water in the #8-R cylinder head. The vendor.
Cooper Industries (Cl), is of the opinion that the crack initiated on the fire face side and propagated through to the cooling water passages. CI also believes that the crack was a direct result of the conditions that existed immediately 43
ORGANIZAT10N: COOPER INDUSTRIES GROVE CITY, PEhNSYLVANIA REPORT INSPECTION NO.: 99900317/87-02 RESULTS: PAGE 4 of 13 following the December 23, 1987 failure of the #9 master connecting rod. The licensee, Arizona Public Service (APS),
contracted with Scanning Electron Analysis Laboratories, Inc.
(SEAL) to analyze the cylinder head to determine the cause of the crack. SEAL has stated that the cylinder head crack was caused by fatigue of the metal which originated at the cooling water passages, and propagated through to the fire face. A third possibility is that the crack was in the #8-R cylinder head when the vendor assembled the 3B EDG at the factory.
All of the above opinions / possibilities are discussed further !
in the following paragraphs,
- b. Manufacturing Defect (Discussion) !
l During the week of October 5,1987, members of the NRC Vendor i Inspection Branch (VIB) ccnducted en audit of the tranufacturing l records for the 3B EDG at CI's facility in Grove City, PA. As a result of this audit, it was determined that all cylinder heads are subjected to a series of inspections, starting at the foundary where the cylinder heads are cast, and ending with the final inspection of the finished cylinder head. In the process, 1 the cylinder heads are subjected to ncn-destructive examination l (NDE) specifically for the purpose identifying cracks. The '
records reviewed by the NRC inspectors indicated that the (8-R cylinder head received the appropriate NDE. Based on the above audit, it appears that there was no apparent Quality Assurance breakdown associated with the manufacturing process of the head and that the crack in the #8-R cylinder head was caused by something other than a manufacturing defect.
c, Cooper Industry's Position j l
In an interview with CI personnel, they stated that the crack in the #8-R cylinder head originated at the fire face and propagated through to the cooling water passage, and that the cause of the crack is directly related to the December 23, 1986 )
failure of the #9 master rod. CI's rational is that following the #9 master rod failure in December 1986, the 3B EDG continued to operate at reduced speed for approximately 45 minutes. It i is theorized that the engine operated on lube oil vapors, and that the #8-R cylinder did most, if not all, the work since it was immediately adjacent to the damaged areas which could have allowed vapors and air to be ingested by the #8-R cylinder.
During this it is also probable that there was no cooling water l
44 l l
ORGANIZATION: COOPER INDUSTRIES GROVE CITY, PENNSYLVANIA REPORT INSPECTION NO : 99900317/67-02 RESULTS: PAGE 5 of 13 in the #8-R cylinder head since the cooling water pressure boundary had been broken and the cooling water draired. As a consequence of no cooling water, the cylinder head temperature could have been raised substantially above normal, causing a crack which originated at the fire face and continued into the cooling water passages.
CI cites the following as additional support for the above scenario:
- The section of the cylinder head containing the crack, which was cut out for detailed analysis, was held together at the cooling water side by segments of uncracked cast iron, or "hinges." The section had to be broken apart at the hinges in order to expose both crack surfaces. These hinges were located on the cooling water side, apparently opposite the crack origin.
- There are secondary cracks showing propagation from the fire face to the cooling water passages.
- There are carbon deposits on the crack surface to a depth which appeared to be the depth of the initial crack.
These deposits would have formed during engine operation on June 2, 1987, prior to through cracking between the '
exhaust valves on #8-R cylinder head.
- d. SEAL Position In their report, SEAL concludes that the through crack in the
- 8-R cylinder head initiated at an inclusion in a radius in the coolir.g water passages and progressed as a function of fatigue to the fire side of the cylinder head. Most of the SEAL report consists of descriptions of the events surrounding the cylinder head crack and what was found using the Scanning Electron Microscope (SEM). There is no discussion of what SEAL i considers to be the failure mechanism, i.e., what caused the i cylinder head to fail in fatigue. In addition, the report l contains a number of modifying or qualifying statements, such l as "analysis very difficult " "finding fatigue failure in gray i cast iron is particularly difficult " "appeared to be fatigue !
striations,' and "definite evidence of fatigue was not obtained."
l l
i I
45 l
+ TZATION: COOPER INDUSTRIES GROVE CITY, PENNSYLVANIA t P' ,, INSPECTION 9900317/87-02 RESblTS: PAGE 6 of 13 l
l SEAL also acknowledges the existence of secondary cracks, but I draws a conclusion opposite from the vendor's.
l l e. Conclusion At the present time, the NRC inspectors have not reached any conclusion. Based on the CI's position, there is reeson to believe that the crack in the 18-R cylinder head occurred as a consequence of the December 23, 1986 master rod failare and was not detected during inspection of engine components following teardown and prior to reassembly. However, the SEAL position can not be summarily dismissed. Therefore, some resolution between CI's and SEAL's position must be obtained before the NRC inspectors can reach a final conclusion. This is considered anunresolveditem(87-02-95) and will be reviewed during a future inspection.
- 3. Palo Verde Unit I!! 3B EDG Piston Pin
- a. Background On June 30, 1987, during testing, the 3B EDG experienced a crank-case overpressurization. The cause of the overpressuriza-tion was ignition of combustible products in the crankcase l which were ignited by excessive temperatures in the #9-L cylinder. Following the overpressurization, the #9-L cylinder l
was disassembled to determine the cause of the excessive i temperatures. Upon inspection, it was determine that the piston pin had overheated and expanded, causing the piston to expand and scuff the cylinder liner. The piston scuffing caused the cylinder liner to score and overheat, thereby
! providing the ignition scurce.
1 The piston pin overheated initially due to inadequate lubrica- !
l tion between the pin and its mating surfaces in the piston. l The root cause of the lock of lubrication to the piston pin has been attributed to inadequate clearances between the pin and the I piston, improper surface finish on the pin, or a combination of the two. It is possible that either or both of the contributing factors were manufacturing defects. This is discussed further i i
in the following pdrdgraphs. I
- b. Discussion !
During the week of October 5, 1987, the NRC inspectors conducted on audit of the manufacturing records of the 3B EDG at CI's ,
4 46 i i
0RGARIZATION: COOPER INDUSTRIES GROVE CITY, PEhNSYLVANIA REPORT INSPECTION f NO.: 99900317/67-02 RESULTS: PAGE 7 of 13 !
facility in Grove City, PA. The audit included a tour of CI's manufacturing facility with special emphasis on the processing '
of piston pins from their machining and finishing through final inspection. Piston pins are inspected for conformance to both dimensional and finish specifications. The finish on the piston t
pins for KSV engines (the 3B EDG is a model KSV 20T) is inspected ,
electronically and visually. As a result of the tour, it '
appeared that all piston pins receive careful handling, and are coated following machining and inspection to protect the i finish from physical damage and/or corrosion. At the conclusion '
of the audit, the ARC inspectors had not found any evidence that the piston pin that failed in the #9-L cylinder was not subject to the same handling and inspection as all other piston pins, nor could the NRC inspectors determine whether a defective piston pin was shipped from CI to Palo Verde. A more logical explana-tion to the problem is that the piston pin was improperly inserted into the piston during redssembly of the 3B EDG at -
Palo Verde. There appears to be a lack of verification by CI that proper assembly procedures were followed on the #9-L piston pin. This could have resulted in improper piston pin to piston clearances. A second possibility is that the piston pin finish was altered sometime between being shipped from the f actory and being installed in the 3B EDG. One of the hRC audit team members inspected the failed piston pin after it was '
removed from the #9-L piston. At that time, it was noted that the finish on the pin appeared to be markedly different from the factory finish, both in terms of appearance and surface quality. The failed pin had a "cross-hatched" appearance indicative of manual finishing with an abrasive cloth, and the
, surface quality appeared to be under the recuired specifications.
Since the surface quality of piston pins is extremely important, .
the relatively "rough" surface of the failed pin could have been the cause of feilure by itself or in combination with an improper fit.
- 4. Byron /Braidwood/Palo Verde - Rocker Anns
- a. Background To date, there have been a number of rocker arm failures at Byron /Braidwood, and one instance of rocker arm failure at Palo Verde. The rocker arm appears to fail in tension as if they had been overloaded. The licensee for Byron /Briadwood has taken the position that the failures are due to defective 4
i f
l 47 l l
. 1
ORGANIZATION: COOPER INDUSTRIES GR0VE CITY, PENNSYLVANIA REPORT INSPECTION NO.: 99900317/87-02 RESULTS: PA*E 8 of 13 material in the rocker arm castings. Cl has taken the position that although the rocker arm castings do not conform to specifi-cation, the failures are a result of improper operation and/or maintenance. Both the licensee's and CI's positions are discussed further in the following paragraphs,
- b. Discussion During the week cf October 5,1987, the NRC inspectors discussed the problem of rocker arm ~ failures with CI's metallurgical personnel. The emphasis of these discussions was to determine if def ective castings (material) were the primary cause, or if there was some other mechanism which caused the failures.
CI personnel stated that all failed rocker arms returned by the i licensee for analysis were tested and found to have at least a
- tensile strength of 17,000 psi. CI did acknowledge that at 17,000 psi, the niaterial was under the specification requirement of 40,000 psi. However, the nonnal tensile loading of the rocker arms is on the order of 3,500 psi, which still allows a nfety factor in excess of 4. Cl further stated that some of the samples returned fcr analysis showed definite signs of impact loading.
This type of loading occurs when valve clearances are excessive which, in turn, is a result of improper adjustnent. During the i inspection, the NRC inspectors also examined a rocker arm returned from Zion for anal bushings had been removed (ysis and from which the bronzeby the licen with a hacksaw. As a consequence, the rocker arm casting had been undercut to a depth of about 1/8 of an inch. Such action 2
1 is not a good practice, and indicates a lack of proper training
! of the licensee's maintenance personnel.
Based on the above discussions, the NRC inspectors are of the opinion that the rocker am failures are not due soley to defec- ;
- tive material. Rather, it appears that improper adjustments and -
maintenance, resulting in improper clearances and impact loadir.g of the rocker anns, are more likely the root cause. However, I because a sample of the rocker am material was found to be cet of specification and there is no certainty as to the root cause in other instances. Cl stated that they would issue a 10 CFR i Part 21 report in the near future, i
l i
I 48 I
ORGANIZATION: COOPER INDUSTRIES GROVE CITY, PENNSYLVANIA REPORT INSPECTION NO.: 99900317/87-02 RESULTS: PAGE 9 of 13 1
1 5. Palo Verde - Agastat Relan I
- a. Bac kgroun_d During required surwaillance testing of the Unit 11. "A" emergency diesel generator (EDG) it was noted that the EDG did not reach full rated speed of 600 rpm (equal to 60 Hz) when operated with the governor in isochronous mode. As a result, the licensee issued a 10 CFR Part 21 report on July 17, 1987. <
The report stated that the actual frequency was about 59.5 Hz, or approximately 595 rpm. The cause of the problem was determined to be an oxide buildup on the contacts of an Agastat relay which is used to energize the EDG governor isochronous circuit under emergency conditions. Under errergency conditions, the Agastat relay is energized and a contact is closed to place a fixed resistance in the governor control circuit. This fixed resistance circuitry provides a reference signal against which the engine speed signal is compared.
When the two signals (reference and engine speed) are mismatched, the engine speed will increase (or decrease) until the signals are equal. The oxidation on the relay contacts represents additional resistance in the circuit. This additional resistance causes the fixed reference signal to be reduced with the result that the engine speed necessary to generate a ,
matching signal is less than the design speed of 600 rpm. Conse-quently, the steady state engine speed and associated frequency is lowered (595 RFM and 59.5 Hz).
After some initial miscomunication, the vendor (CI) i acknowledges the prcbltm arid corrective measures have been ,
implemented. CI stated that a service bulletin will be issued !
to advise affected utilities of the problem and provide t instructions on how to clean the relay contacts to remove oxides. This is an interim measure. Cl is also working on a redesign of the affected circuits which will include a relay that is not susceptible to oxidation of the contacts. Under consideration are relays with mercury wetted contacts, hermitically sealed relays, arid relays with non-oxidizing, i precious metal plated contacts. )
)
l l
l i j
i {
l 49 l l
]
~ -
/ %
OR@.NIZATION:
' COOPER 1NDUSTRIES GR0VE CITY, PENNSYLVANIA p._. ._._ _
REPCRT INSPECTION NO.: 99900317/87-02 RESULTS: PAGE 10 of 13
- 6. South Texas - Cracked Injector Nozzles
- a. Background and Discussion On August 26, 1987, Houston Light & Power Co. issued a 10 CFR 50.55(e) report concerning the standby diesel generator fuel injection nozzles at the South Texas Project (STP). To date, there have been two failures of fuel injection nozzles at South Texas. In both cases, the nozzles failed in a manner that allowed significant amounts of diesel fuel to leak from the nozzles into the EDG lube oil surrp where it raised the sump level, diluted the lube oil, and eventually caused a drop in lube oil pressure. Both injection nozzle failures had the potential for causing EDG failure due to inadequate lubrication as a consequence of lube oil dilution.
The licensee for South Texas sent both failed injection nozzles I to Southwest Research Institute (SWRI) for detailed analysis.
A final report on the analysis results was submitted on September 23, 1987. Hcwever, the report from SWRI does not contain any definite root cause(s) for the injection nozzle failure. In the report, SWRI identifies cracks in the spray head as the leakage point for fuel oil and concludes that the cracks were propagated as a function of high-cycle fatigue. In the report, the point of crack initiation and the direction of propagation are also identified. However, the cause of crack initiation and hence, the root cause of the failure, are not identified in the SWRI report. Consequently, it is not known whether there is a generic problem with injection nozzles on KSV engines, or the problem is isolated to a few nozzles or single lot of injection nozzles. At present, SWRI is analyzing two additional nozzle spray heads in an effort to determine a root cause of failure. These analyses and subsequent report are not yet available. At present, there is only speculation as to the root cause of the failure. It is possible that the spray heads were not properly machined initially, which 1,
resulted in some sections being toe thin and cracking under stress. There is also the possibility that the spray heads were initially cracked during heat treating (nitrating) following machining. Finally, there is the possibility that the root cause is a combination of improper A chining and heat treating.
50 w m
ORGANfZATION: COOPER 1NDUSTRIES GROVE CITY, PENNSYLVANIA REPORT INSPECTION N0.: 99900317/67-02 RESULTS: PAGE 11 of 13 CI acknowledges there is a problem with injection nczzles cracking. However, this equipment is manufactured by the Scintilia Division of the Bendix Corporation. CI has contacted Bendix and requested they provide their own evaluation with respect to the root cause of the failures, as well as an evalu-I ation concerning the extent of the problem. As of the week of l October 5,1987, the Bendix evaluation was not completed.
- 7. Palo Verdo Unit #3 - EDG 3B Main Bearing (#2)
- a. During qualification testing of the 3B EDG following repair of damage from the December 23, 1986 master rod failure, there were several incidents where the EDG tripped because of high temperature at the #2 main bearing. Following corrective action, the #2 main bearing was operated successfully at a somewhat higher temperature than that of an adjacent main bearing.
Successful operation was demonstrated by 1) operation in excess of 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> without tripping, and 2) a temperature profile of the bearing during operation which showed stable temperatures.
In order to obtain the temperature profile, a thermal trip device (one of two) in the #2 main bearing was removed and replaced with a thermocouple. In a meeting on July 10, 1987, -
between the licensee, CI, and NRC it was determined that it was necessary to continue monitoring the #2 main bearing temperature in order to establish a trend and thereby be better able to assess the potenti&l for long term reliability of the #2 main bearing. CI, however, favors removing the thermocouple and replacing it with the trip device.
During the week of October 5, 1987, while conducting an audit of the 3B EDG manufacturing records at CI's facility, the subject of utilizing a theromcouple as opposed to a thermal trip device was discussed. As a result of these discussions, it was concluded that CI would accept a thermocouple in place of a trip device provided the thermocouple was connected to an engine trip device and the response time of the thermocouple to ,
temperature change was equivalent to trip device.
- 8. Training / Qualification The inspector reviewed Section 1.3 of the QAM and Procedure No.
QCP-10-12, "Gualification and Certification of NDE Personnel."
The QC Managers in the Mount Vernon and Grove City plants are 51
ORGANIZATION: COOPER INDUSTRIES GROVE CITY, PENNSYLVANIA 1
REPORT INSPECTION N0.: 99900317/87-02 RESULTS: PAGE 12 of 13 responsible for indoctrinating the managers of affected depart-ments as to any changes that occur in the QA Program. The department manager in turn is responsible for indoctrinating the personnel in their respective departments.
The training records of 25 inspectors and eight QC personnel were reviewed. The certifications for the 25 inspectors were signed by the QC supervisor in June 1987. All the inspectors were certified to Level I and the effective period of certifica-ation was for two years. The certifications for four QC tech-nicians, two QC supervisors, the QC Manager, and the Super-visor Quality Engineering were signed by the QC Manager or Director of Manufacturing.
The qualification records for three lead auditors were reviewed.
The file contained a Record of Lead Auditor Qualifications (similar to ANSI N45.2.23), QA Personnel Resume, and a Nuclear QA Proficiency Examination.
The requirements Gr qualification and cert.fication of NDE personnel are in compliance with SNT-TC-1A. The qualification records of six NDE personnel included training / experience records; certification; recertification; general, specific, and practical examinations; and annual eye examinations. The personnel included one Level III in the disciplines of UT, !T, and MT and five Level IIs in PT and/or MT.
- 9. 10 CFR Part 21 ESG Procedure No. QCP-10-14, "Reporting of Deficiencies as Required by 10 CFR 21," dated August 25, 1987, was reviewed and found to meet the requirements of 10 CFR Part 21. During an inspection of the facilities, it was noted that Section 206 of the Energy Reorgaaiza-tion Act of 1974 and a notice describing the regulations and proce-dures were posted on several bulletin boards. The Vice President /
General Manager is responsible for notifying the NRC of 10 CFR 21 items.
- 10. Audits The ir.spector reviewed Section 2.6 and 5.1 of the QAM, Procedure No.
QCP-10-5, "Internal Audits," and QCP-10-9, "Vendor Qualification."
Eighteen areas of the QA Program are audited on an annual, biannual, or quarterly frequency. Internal audits from 1985 to the present were reviewed. The audits were conducted by personnel who did not 52
ORGANIZAT10N: COOPER INDUSTRIES GROVE CITY, PENNSYLVANIA REPORT INSPECTION NO.: 99900317/87-02 RESULTS: PAGE 13 of 13 have direct responsibility for the activities being audited. Auditor training records were established for 12 individuals who performed the internal audits. It was noted that the check lists contained only a few line items for each of the activities that were audited.
It was noted that ESG did not perform external audits / surveys on eignt calibration service vendors (See Nonconformance 87-02-02).
l The vendors included Dresser Industries (deadweight tester),
l E. J. Daiber (torque testers), Magnaflux (3 MT units), Huygen (Weston light meter), Starret (gage block set), Edmund Manufacturing (gage block set), Page-Wilson (six Rockwell and one Brinnel hardness tester), and Automation /Sperry (UT unit).
- 11. Control of Measuring and Test Eauipment (M&TE)
The inspector reviewed Section 4 of the QAM and Procedure No.
QCP-10-15, "Periodic Calibration of Measuring Equipment." The calibration of M&TE is maintained through a computerized recall and inventory system. Current certification for reference standards calibrated by eight vendors indicated that the standards were calibrated with instruments traceable to the National Bureau of Standards. A Certification of Accuracy from Dresser Industries l indicated that the deadweight tester was calibrated in February 1984. The three torque testers (S/Ns S1496, S3599, and S3600) were calibrated by E. J. Doiber in January 1987. An equipment Certifica-tion Certificate noted that the three MT units (S/Ns 851580, 53845, and 85681) were calibrated in December 1986 by Manaflux. The Weston light meter (S/N 66632) was calibrated by Huygen Corporation in February 1987. Master gage block set S/Ns 2109-B and 1088-H were calibrated in May 1987 and September 1984 by Starrett and Edmunds Manufacturing, respectively. The model VM-715 UT unit (S/N 1956-6) was calibrated in June 1986 by Automation /Sperry. Seven Certiff-cates of Calibration from Page-Wilson indicated that six Rockwell (
hardness tester (S/Ns 983-1678, 6078, 6067, 1900, 8996-983, 6122, i and 518) and one Wilson Brinell hardness tester (S/N 89197) were calibrated in February 1987. A review of purchase orders to the eight vendors indicated that ESG failed to pass on the requirements of 10 CFR Part 21 and to have a QA Program in these orders (See Violation 87-02-01 and Nonconformance 87-02-03).
l 53
ORGANIZATION: C&S VALVE COMPANY WESTMONT, ILLIN0IS REPORT INSPECTION 1 NSPECTION NO.- 99901099/87-01 DATES: 07/21-24/87 ( N RTTF HntlDR. dQ CORRESPONDENCE ADDRESS: C&S Valve Company 40 East Chestnut Street Westmont, Illinois 60559 ORGANIZATIONAL CONTACT: M. L. Seshagiri, QA Manager TELEPHONE NUMBER: 317-789-R900 NUCLEAR INDUSTRY ACTIVITY: Valve manufacture.
ASSIGNED INSPECTOR: Mi % MC J. Cl Nhrper, Prografn Development and Reactive
// 07 D' ate Inspection Section (PDRIS)
OTHER INSPECTOR (S): Michael Villaran APPROVED BY: ( d E. T. Baker, Acting Chief, PDRIS, Vendor Inspection Branch Date P[
I INSPECTION BASES AND SCOPE:
A. BASES: 10 CFR Part 21 and 10 CFR Part 50, Appendix B.
B. SCOPE:
The inspection at C&S Valve was to determine the merits of i allegations that there has been inadequate transferring of material l heat codes and improper selection and use of materials of construc-tion for valve parts.
PLANT SITE APPLICABILITY: LimerickI/2(50-352,50-353), Peach Bottom 2/3 (50-277,50-278), Arkansas 1/2 (50-313, 50-368), Nine Mile Point 2(50-418).
55
ORGANIZATION: C&S VALVE COMPANY WESTMONT, ILLIN0IS REPORT INSPECTION nn . oconinoo/A7 n1 RFSULTS: 07/21-24/87 )AGF 2 of 11 A. INSPECTION FINDINGS:
- 1. Violations None.
- 2. Nonconformances
- a. Contrary to Criterion XVII of Appendix B to 10 CFR 50, and the C&S Valve QAM, Revision A, Section 6.4.2, the material release and verification, material cutting, heat code transfer /verifica-tion activities were not documented and signed-off as a separate step for various nuclear travelers in the sequence that these activities were being performed (87-01-01).
- b. Contrary to Criterion XIV of Appendix B to 10 CFR Part 50, and the C&S Valve QAM, Revision A, Section 12.5, QA Deficiency Reports numbers 2738, 2746, and 2743 were not properly admini-stratively dispositioned. (87-01-02)
- c. Contrary to Criterion VIII of Appendix B to 10 CFR 50, and the C&S Valve QAM, Revision A, Section 6.7.3, one bar of 5" dia. x 14'10", heat M0723B material, was incorrectly marked as heat code QSB instead of the correct heat code GSB (87-01-03).
B. UNRESOLVED ITEMS:
None.
C. OTHER FINDINGS AND COMMENTS:
- 1.
Background:
4 l
The inspection was conducted as a result of an allegation pertaining ;
to inadequate transferring of material heat codes and improper )
selection and use of material of construction for valve parts, j On July 31, 1985, the C&S Valve Company was formed by purchasing the assets of Clow Valve Company. In a relative size comparison, Clow Valve operated an average of $190 million in annual sales as compared i to $5-6 million in annual sales by the C&S Valve Company. C&S Valve i Company retained the Clow technical procedures, occupies thE former Clow facilities, and much of the staff is from the original company. Records and documentation for Clow supplied components are l
56 l 1
ORGANIZAT10N: C&S VALVE COMPANY WESTMONT, ILLIN0IS REPORT INSPECTION Nn . oooninoo/A7 01 RESULTS: 07/21-24/87 > AGE 3 of 13 _
still maintained by C&S, and the operating, manufacturing and quality procedures have been carried over by C&S.
The C&S QA group consists of a QA Manager, a QA Assistant, and two QA Inspectors, one of whom is in training (at the time of the inspec-tion) and has not yet assumed full responsibilities. At the time of the inspection, a third QA Inspector had been terminated two to three weeks prior to the inspection.
In the transition from Clow Valve Company, C&S was forced to reduce their work force by 60-70%. Apparently, the reduced workforce, management / personnel relations and cash flow problems contributed to a large percentage of disgruntled employees. An interview with one of the QA Inspectors (a Clow and C&S employee for 10 years) was conducted in order to gain insight into the basis for the allegations and the reasons for the relatively large employee turnover. During the interview the QA inspector informed the inspection team that some employees, particularly machinists, used the experience cjained at C&S Valve to step up to better jobs outside of the company.
Several people listed on the company roster are part-timers who are brought on and let go, based on workload. Morale was a problem after the C&S take over. Streamlining of the size of the company led to personnel cut backs and cash flow problems. Morale improved somewhat after 1987 salary raises were issued. During an informal interview with the shop superintendent, he spoke of ore instance where an employee was laid off from C&S during personnel cutbacks and then he later contacted C&S threatening to report them to the NRC.
The Clow ASME N-stamp Certificate of Authorization expired on July 1, 1985. No nuclear orders were taken until April 8, 1986 when the N-stamp was reinstated for C&S.
On June 12, 1987 allegations were made against C&S Valve Company by a former employee to Region III of the NRC. The following allegations were made to Region III:
Allegation Item #1 The alleger was told to sign a "nuclear traveler" for a valve manu-factured at least two years prior to the beginning of his employment.
He could not recall any of the details regarding the matter but he remembered that it pertained to "attesting to heat code transfers."
57
ORGANIZAT10N: C&S VALVE COMPANY WESTMONT, ILLIN0IS REPORT INSPECTION Nn - coon 1noo/n7 01 RESULTS- 07/21-24/87 FAGF 4 of 13 Allegation Item #2 C&S was "pinching pennies" and using low grade materials. In the sawroom, heat codes were not always being transferred between materials and travelers.
The alleger was telephoned by the lead inspector on July 22, 1987 at his home in order to obtain details about the allegations. The alleger could not recall details, however, he provided further information regarding his original statements.
According to the alleger, under instruction from the C&S Valve manage- l ment he provided signature approval on a nuclear traveler for a l sawcut step for one valve manufactured two years prior to his l employment. He stressed that the traveler was a C&S traveler. l During a training session held on the subject of 10 CFR Part 21, he '
brought the incident to the attention of the C&S management ano management explained that the incident was not a problem.
The alleger went on to say prior to the saw cutting operation that he would notify the QC department to transfer heat codes, however, at times they would not respond. Therefore, manufacturing personnel were transferring heat codes on these materials or the heat codes s were not being transferred. He could not recall any other details. l The Heat Code is defined by C&S Valve as "C&S's unique identification l number (represented by 2, 3, or 4 digits) and is assigned for mill {
heat / lot numbers except for weld material where the manufacturer's i heat / lot / batch numbers are used." !
The alleger was asked for details about his statement regarding C&S l using low grade materials in the valves. He responded by saying I that C&S used foreign steel producers to make valve bodies. In one case a valve body contained "holes and rocks within the holes,"
therefore, they could not be cut by the machinist because the machine tools would break. C&S would subsequently "weld over the holes and send the valve to the nuclear plant" without any mention of the problem. He could not recall any other details.
The alleger claimed that he knew of both present and former employees willing to attest to the problems with C&S Valve Company that he mentioned. At that point, he was given the lead inspector's hotel telephone number so that the people mentioned could make statements. No additional people contacted the lead inspector during this inspection.
58
ORGANIZATION: C&S VALVE COMPANY WESTMONT, ILLIN0IS REPORT INSPECTION wn - ooon10Q4/n7 n1 RESULTS: 07/21-24/87 ) AGE 5 of 13
- 2. Discussion Allegation Item #1 could not be substantiated.
The alleger claims that he signed one C&S nuclear traveler for a valve manufactured two years prior to his employment date. His employment start date was August 1986. The typical CSS traveler is light green and contains information regarding traveler number, tab number, QA approval, ANI acceptance, heat code, P0 number, material description, part number, drawing number, part description, number of pieces. In addition, each job function during the manufacture and a hold point were delineated on the traveler (See nonconformance 87-01-01). According to the C&S QA manual paragraph 6.3.2, "The traveler is the primary construction control document for a part or an item...The traveler is identified with the job number, drawing number, and so marked with Nuclear or Q as applicable." Also, naragraph 6.8.1, "QC shall witness and sign-off all traveler sequences identified as QC hold points. In addition QC may determine to witness any other operation when a problem is detected or suspected. QC inspection shall include verification of material prior to release and documents the Heat Code on the traveler...."
In this case, the traveler indicated a sign-off step for saw cutting, and for material release and verification (see Nonconformance 87-01-01). It should be noted that each traveler contains a dark bold job number. The first two digits of this number are the year that the valve job was quoted to the customer by CaS. It is common practice that a quote would be placed one or two years before the commencement of actual valve manufacturing.
According to the C&S QA manual the job number is the governing identification number for all documents throughout design, construction and archiving.
According to the alleger's statements, the valve that he signed-off had to have been manufactured in the 1984 time frame and was a C&S nuclear traveler. C&S Valve Company did not exist in 1984. Prior to July 1985, Clow Valve Company was in existance. Due to the color difference bewteen the Clow and C&S travelers, they are easily distinguishable. Nevertheless, the inspection team examined approximately 600-700 Clow and C&S shop travelers from the years 1984-87. The number of travelers reviewed represents approximately 70% of the total travelers written during that period. Nuclear travelers from 1984-85 were reviewed for evidence of the alleger signing-off on the saw cut step and on the QC verification release 59
ORGANIZATION: C&S VALVE COMPANY WESTMONT, ILLIN0IS REPORT INSPECTION NO - 444n1n04/R7-01 RESULTS: 07/21-24/87 ) AGE 6 of 13 block. Travelers from August 21, 1986 - February 11, 1987 were examined and evaluated for missing heat code verification / material release sign-off on jobs worked by the alleger, and personnel sign-offs inconsistent with their employment dates. Only one case was j noted: a date on a saw cutting sequence step was apparently i improperly signed-off with a signature dated one year earlier than the other sign-offs on traveler 004 for job 86-4774-01Q (see nonconformance 87-01-01). This sign-off was noted and corrected by C&S at the time that traveler 004 was being executed. The inspec-tion team reviewed and evaluated 129 nuclear document packages which contained the various nuclear travelers.
According to the C&S training records the alleger was qualified as a machinist / welder. The extent of his sign-off responsibilities were to document the physical act of saw cutting naterial. According to the C&S QA manual paragraph 6.7.2, "When material is to be divided into sections during manufacturing, the manufacturing personnel shall notify QC to transfer heat codes prior to cutting." Materials for nuclear jobs are all stored in a locked and controlled area.
According to the C&S Assembly and Weld Shop Foreman, the QC Inspectors have sole possession of the keys to the controlled area.
Therefore, prior to any material being delivered to the saw, the QC inspector had to physically release the material from the controlled area. Once the material was divided into sections, the operator signs-off on the traveler's cutting operation block. The QC inspector was to transfer the heat code and subsequently sign-off the traveler's verification / material release opeation block. There was no objective evidence to support that heat codes were not being transferred properly. It was noted that there was no specific procedure to cover the process. However, QA manual paragraph 6.7.2 does give instructions covering the cutting and transferring of heat code process which should suffice as a procedure. Furthermore, the traveler for this process does not describe the flow of the operation in exact terms. The traveler usually itemizes the material release and and subsequently the verification saw cutting step step (as the first traveler typesign-off 1). Onlystep on occasion will there be a transfer heat code and verification ste on the traveler following the saw cutting step (traveler type 2)p .
If "verification" is meant to describe verification that the proper material has been released from the storage area, then there is no distinct heat code transfer verification step in traveler type 1.
If "verification" is intended to mean both verification that the correct material has been released from the storage area and that 60
l 1
ORGANIZATION: C&S VALVE COMPANY {
WESTMONT, ILLIN0IS REPORT INSPECTION wn . oooninoo/R7 01 RFSulTSt 07/21-24/87 >AGF 7 of 13 heat code markings have been properly transferred after saw cutting, then the construction sequence listed on traveler type 1 does not conform to the coniitments of Section 6.4.2 of the Nuclear Quality Assurance Manual. Section 6.4.2 states, in part, "... construction activity shall be in accordance with the sequence provided in the Travelers and Manufacturing personnel shall perform those specifie_d activities to the documents referenced on the Travelers." According t'o C&S "verification that heat codes were transferred was made by a verification step block on the traveler regardless of its physical location on the traveler." Therefore, construction activities in the case of traveler type 1 were not performed in accordance with the sequence provided in the travelers. (See nonconformance 87-01-01.)
In some cases, there were steps on the nuclear traveler involving a saw cutting operation that did not require a heat code documenta-tion, for example cutting parallel key actuators (traveler 00c6 &
0138) and gland tubes (traveler 0116 & 0139).
The NRC inspector toured the Nuclear controlled area in order to verify that it was controlled and that heat codes were correctly affixed to the materials. The storage area was clearly designated as a nuclear material hold area and was locked. Seven randomly picked heat codes were checked against the master file. Materials were marked with heat codes QSB, HC-LBE, HC-VLB, HC-208, BQB, MH, 140 BN. All materials checked in the storage room had proper heat codes with the exception of QSB. It appeared that QSB was written in white marker on 1 bar, 5" dia. x 14' 10", Heat M07238. However, after further checking of the heat code master file it was evident that it should have been marked GSB. Upon careful examination of the stenciled marking on the material the G in GSB was superimposed by a stamped number which made it appear as a Q. The person writing the heat code on the material in white marker (for easy identifica-tion) misread the G for a Q and subsequently marked it as such.
(See nonconformance 87-01-03.)
Allegation Item #2 could not be substantiated.
An attempt was made to detennine whether C&S Valve was "pinching pennies" and using low grade materials or foreign supplied material in their valve components as stated by the alleger. Deficiency Reports (DR) from 1983 - 1985 were reviewed and all of the Engineering Change Notices (ECR) for the years 1984 - 1987 were reviewed. In no case was there any evidence that materials of construction were used without the approval of the C&S customer or of the material being in compliance with applicable codes and standards. DR 2029, 61
ORGANIZATION: C&S VALVE COMPANY WESTMONT, ILLIN0IS REPORT INSPECTION
>>n . coon 1noo/97 n1 RFSill TS- 07/21-24/87 l' AGE 8 of 13 describes valve body OD undersized at 7 5/16", the drawing called for 7 3/4 OD. The corrective action sent the bodies out for repair by weld buildup. DR 2074 involved 14" aluminum bodies. The bodies failed the liquid penetrant test because of porosity and linear indications in the ID bore and flange faces. The bleedout exceeded the.3/16" maximum diameter bleedout for 5/8" and greater wall l thickness. The corrective action was to return the material to the supplier to repair the porosity and linear indication by welding.
DR 2033 and DR 2032 involved a 6" and a 3" dual check valve, respectively, which failed hydrostatic testing. The corrective action was to bond new seat material to the valve bodies, reassemble and test. DR 2001 involved a casting that failed a liquid penetrant test on the machined surface of the flange face. The corrective action was to scrap the body casting and procure a new casting and remachine. ECRs were required for new travelers.
DR1952 involved valve bearing material. The bearing material specified on the traveler did not match the material on the drawing.
The order was for P0 #NMP2-P302X, Nine Mile Point Nuclear Station Unit 2, Niagara Mohawk Power Corporation, Jobs #83-2221-04, 05, 07, 09, 10, 12, 14, 16, 18, 19, 20, 27, 28, 29, 31, 32, 33. The traveler material was 8505 and Metcar M10 (for 83-2221-28, 29, 31, 32, 33).
The material on the print (design condition) was Teflon and Carbon /
Antimony, Metcar MID (83-2221-28, 29, 31, 32, 33). The alternate material was acceptable per TWX from Stone & Webster Engineering Corporation for Nine Mile Point, "The alternate materials per your ref TWX are acceptable in accordance with the requirements of the subject specification." DR 1950 involved the same situation and was dispositioned the same as DR 1952. DR 1947 involved 6" cast dual plate check valve bodies with shrinkage cavaties found at the junction of the machined ID wall and seat surface. The casting was returned to the vendcr. DR 1858 and 1954, involved 30" valve body (Job #83-2063-02
- 82-2739-01-N-02)(N) -02, 03 (N) respectively. The-01) and valve problem in bothbody casesmachining was (Job excessive porosity. The corrective action was to drill out the porosity and plug weld.
ECR #1968 was of interest since it involved a major repair of a valve body. The alleger claimed that on occasion C&S Valve would try to process valve bodies with porosity (holes) that contained rocks. Machining these valve bodies could not be done as a result of numerous machine tool failures. And the porosity would be weld ,
repaired, then subsequently sent to the nuclear plants. ECR #1968 '
involved DR #2654 from Job Order #83-2462-01 (N) -03, a 12" wafer body valve for IL Power (Baldwin). The body material was purchased 4
62
ORGANIZATION: CSS VALVE COMPANY WESTMONT, ILLIN0IS REPORT INSPECTION wn . oooni ncio /97_ n1 RFSUITS- 07/21-24/87 PAGF 9 of 13 by C&S from a domestic manufacturer, Jorgensen Steel Company. C&S obtained approval from IL Power for the weld repair procedure on the subject valve on June 24, 1985. The DR stated that the material was found unsatisfactory since it failed the radiographic examination due to porosity and slag inclusions. The corrective action recomended by C&S was to reissue a supplement to the original traveler to perform the repairs as required and re-exami.ne by radiography.
Applicable approved procedures were EPS 30-69-825, Revision A; EPS 30-20-103, Revision 0; and EPS 30-49-70, Revision B. The' weld repair report stated the repair description as drill oversize holes and plug weld. The parent metal was SA516 grade 70, the weld metal and heat number was E7018-3/16, 431C3231. The cavity size was 5/8" radius in four places. The customer approved weld procedures used in the repair were EPS-30-49-825, Revision A and EPS-30-20-103, Revision 0. The customer approved radiographic procedure was EPS 30-49-702, Revision B. The report of radiographic examination was reviewed by the NRC inspector and all four repairs were found acceptable.
The report of ultrasonic testing (UT) of the plug welds stated that the areas were machined smooth and an Aerotech 1/2", 2.25 MHZ, 0 transducer was used to scan the repairs. No defects were found.
The test was performed by a certified Level II UT inspector on June 21, 1985.
ECR #1942 for Job 84-2993-01 (N) Arkansas Power & Light involved an alternate material, SA240-T3166, substituted by C&S for a clamp ring. The normal clamp ring material was T316 or T304 stainless steel (SS). C&S used 316L since it was available. This was acceptable by the customer since 316L in most cases offers better corrosion resistant properties with an ultimate tensile strength (UTS) of onl 5000 psi less than 316 or 304 ECR #1911 for Job 84-2948-01 (y) N -02 (N), Arkansas Power & Light involved DR 2610 for a 8" lugged wafer stop valve clamp ring. Again, the same situation i occurred and disposition was reached as in ECR #1942. l As a result of two Clow Corporation butterfly valve failures at Peach Bottom Atomic Power Station (PBAPS), the Philadelphia Electric l Company submitted a Part 21 report to the NRC in 1986. The problem involved seizing of the valves' shafts and bearings which rendered the valves inoperable after approximately one year of service. The subject valves with carbon bearings were in service at Limerick and PBAPS. The M-57 valves were containment isolation valves. If an accident occurred during purging (when the valves are open), they may not close within the required time period (5, 6, 9 seconds per 63
ORGANIZATION: C&S VALVE COMPANY WESTMONT, ILLIN0IS REPORT INSPECTION en - coon 1044 /n7_ n1 RESULTS: 07/21-24/87 >AGF 10 of 13 Tech. Spec. Table 3/4.6.3) upon receipt of a containment isolation signal. From review of the Philadelphia Electric Company's (PEC)
Metallurgical report, it was concluded that the shaft and bearing seized due to improper material selection which caused pitting strictly from galvanic corrosion and a subsequent build up of corrosion products between the valve shaft and bearing material.
C&S valve had two independent laboratories evaluate the problem.
Packer Engineering Associates performed a metallurgical analysis and determined that seizing was due to pitting whi' ch was chloride induced crevice corrosion. The crevice was created by the stainless steel shaft in the carbon bearing. The Packer Engineering report states, in part:
"It should also be noted that graphite is more noble I than stainless steel. Thus, some galvanic acceleration of any corrosion processes is expected." " ...The subject carbon bearing was found to contain significant amounts of chloride, using two separate test methods (leaching and spectrographic). Neither of the new bearings were found to contain significant quantities of chloride. This indicates that the chloride was probably picked up from service exposure.
Corrosion testing has shown that chloride containing water can pit 17-4 PH stainless steel in a manner similar to that observed on the subject. Further, that crevices composed of subject metal and chloride, containing carbon bearing material, produce corrosion pits in six days when exposed to pure (deionized) water.
Patel Engineers (PEA) performed a literature search and reconnend a material change of the bearing to "bronze, babbit, etc." or change the shaft material to "316SS."
It appears from review of the evidence submitted in the PEC and the PEA metallurgical reports that the chloride level in the environ-ment experience by the failed valves was the cause of the seizing, since similar valves have been in service at other facilities for several years without reported failure. Yet, C&S decided to change the bearing material to 8505 Alloy 932 (bronze) in lieu of Mercar M-10 or PTFE or Duralon. Approval for the material selection was granted by the customer. The original M-10 material was specified since it was accepted as an industry standard for bearing material.
The material selection was based on technical merits as well as the financial advantages of material.
64
ORGANIZATION: C&S VALVE COMPANY WESTMONT, ILLIN0IS REPORT INSPECTION wn . cooninoo/A7.n1 RF9til TS- 07/21-74/87 >AGF 11 nf 11 An attempt was made to establish whether C&S Valve used foreign materials to manufacture valves. All purchase orders (P0) from job orders reviewed were evaluated for foreign manufacturers or material certification from foreign manufacturers. None were found. In addition, the ANI who has been auditing Clow and C&S for at least 11 years was interviewed. He stated that at no time has he ever had any knowledge of C&S using any foreign supplied materials / metals for valves manufactured for nuclear plants.
In sum. nary, there is no objective evidence to prove that C&S Valve has hedged on quality by inadequate material selection due to financial incentives.
Training and QA Deficiency reports were reviewed in order to deter-mine if those people named in the allegations were adequately performing their job functions. The 1987 training schedules for personnel in the engineering, receiving, painting and crating, quality control, welding, machining, assembly and testing areas were reviewed. The lists of personnel requiring training and their schedule for training were maintained by the QA Manager in accor-dance with the C&S Valve Company Nuclear Quality Assurance Manual (Revision A), Section 15.4. The areas reviewed were found to be adequate. The training files covered were found to be satisfactory.
A review of all completed QA Deficiency Reports (Exhibit 9, C&S Valve Co. Nuclear Quality Assurance Manual) during the time period from June 1,1986 to present was performed to verify the effective-ness of this aspect of the C&S QA program. A total of forty-six Deficiency Reports were examined. Three of these, each in a different area of the QA function, were investigated in greater detail:
- a. DR 2769, dated June 29, 1987. The QA inspector noted that thread gauges being used on Job 87-5149(N), the manufacture of stop and hinge pin retainers, were past their calibration due dates. The finding was substantiated and all gauges were sent for calibration. All items in the job were checked by the alternate wire gauge method as given in ANSI B2.1 and conformance was verified. The cause of the deficiency was attributed to a QC oversight in the scheduling and update of calibration lists. Calibration schedules were to be maintained monthly as a corrective action. The auditor reviewed the C&S 65
ORGANIZATION: C&S VALVE COMPANY WESTMONT, ILLIN0IS REPORT INSPECTION wn - oooninoo/n7 n1 RFSUITS- 07/21-24/87 ? AGE 12 of 11 M&TE Control program to verify the corrective action and the effectiveness of the M&TE program in general. The areas reviewed were found to be adequate.
- b. DR 2766, dated June 12, 1987. While verifying dimensions of work performed on an 8" valve body under Job 87-5032-01 Q01, ;
traveler 002-1, the QA inspector noted improperly located i holes. The finding was justified, holes were weld repaired, )
re-drilled, and surface penetrant tested per C&S procedure 30-49-700, Revision E. Cause was attributed to machinist not verifying the drawing required dimensions and QA hold points not properly identified on the traveler. Nachinists were notified of the error and travelers on a generic basis were corrected to prevent recurrence,
- c. DR 2749, dated February 20, 1987. QA inspector noted that an incorrect alloy was used in a shipment of plates and bodies for Job 86-4665 unoer Purchase Order No. TDN-00078. Finding was justified. Alloy 952 was supplied instead of Alloy 954, as stated in the Purchase Order, as a result of an error by the vendor's order correspondent. A Corrective Action Requestion 001-87 was issued to the vendor in accordance with C&S procedure 30-49-676 Revision A, to identify the cause and implement appropriate corrective actions.
Measuring and Test Equipment Control. As part of the review of QA Deficiency Report 2769 (Section E.3.2), the C&S Valve Company measuring and test equipment controls were investigated.
- a. Calibration Cards. Calibration cards for equipment with calibration frequencies of from one month to two years were reviewed. The records reviewed were found to be in order,
- b. Calibration Stickers. A sample of two tools was selected from the calibration lists to verify the effectiveness of the program. Tool number S0179, an NGK 7"-8" 0.D. micrometer, and tool number DC06, a Mitutoyo 0"-6" Dial Caliper, were chosen at random from the calibration list and then located in the plant. Both measuring tools were properly marked with their current calibration stickers.
- c. Daily Equipment Log. A daily equipment log is maintained in i accordance with Section 10.3 of the C&S Nuclear Quality Assurance Manual, Revision A, dated April 9, 1986, to provide control and traceability of individual tools and the jobs they e
66
l l ORGANIZATf0N: C&S VALVE COMPANY WESTMONT, ILLIN0IS REPORT INSPECTION Nn . ooontoco/97 n1 R F9til TS- 07/21-24/87 l'AGF 13 of 11 were used on. The log in use on July 23, 1983, was reviewed, and found to be in order. Two items were selected from the current log and validity of their calibration was verified by the inspectors.
- d. M&TE Procedure. The M&TE controls at C&S Valve Company are regulated by the Nuclear Quality Assurance Manual, Revision A, Section 10.3 and procedure 30-49-675, Revision Q dated February 6,1985, "QC Procedure for Tool and Gage Calibration."
These documents were reviewed and found to be adequate.
- 3. Part 21 The C&S Valve Part 21 procedure was reviewed and found adequate. All necessary documents were posted in clear view for all C&S employees.
- 4. Plant Tour As part of the plant tour, the inspection team verified adequate nuclear weld rod storage. The nuclear weld rod holding oven temperature was being maintained at 275 F. The temperature readings were logged daily and maintained at 250 - 300*F in accordance with procedures.
D. PERSONS CONTACTED
- M. Seshagiri
- Mary Ann Pankov
- Tom Casale
- Greg LaFrance
- Leon Fordhem Scotty MacGregor Habib Jubran '
- Attended the exit meeting.
67
ORGAN 1ZATION: GENERAL ELECTRIC COMPANY SAN JOSE, CALIFORNIA REPORT INSPECTION INSPECTION NO.: 99900403/87-02 DATE: July 20-31. 1987 ON-SITE HOURS- 14A CORRESPONDENCE ADDRESS: General Electric Company Nuclear Energy Business Operations Attn: Mr. N. L. Felmus, Vice President and General Manager 175 Curtner Avenue San Jose, California 95125 ORGANIZATIONAL CONTACT: Mr. J. J. Fox TELEPHONE NUMBER: 408-925-6195 NUCLEAR INDUSTRY ACTIVITY: General Electric (GE) is currently providing engineering design and service activities for many domestic nuclear plant utilities.
ASSIGNED INSPECTOR: k[ M# , 9 M ate R. P. McIntyre, ~Special Projectj Inspection Section (SPIS)
OTHER INSPECTOR (S): J. J. Petrosino, Program Development and Reactive Inspection Jection APPROVED BY: [t [ (.- oo- /n>
/
Uldis Potapovs, ' Chief, SPIS, VenpVInspection Branch f27Date
/
INSPECTION BASES AND SCOPE:
A. BASES: 10 CFR Part 21 and Appendix B to 10 CFR Part 50.
B. SCOPE: This inspection was performed to determine if the GE procurement and control of industrial grade components for the Nine Mile Point-2 control room safety-related panels was accomplished in accordance with a l GE white paper submitted to the NRC on July 2,1987. l PLANT SITE APPLICABILITY: All BWR Facilities.
69
ORGANIZATION: GENERAL ELECTRIC COMPANY SAN JOSE, CALIFORNIA REPORT INSPECTION nn - ooonnan1/R7_n? RFSULTS- PAGE P of R A. VIOLATIONS:
None.
B. NONCONFORMANCES:
None.
C. UNRESOLVED ITEMS:
- 1. UnresolvedItem(87-02-01).
Due to the fact that the majority of the NMP-2 PGCC procurement packages reviewed did not include all the necessary paperwork to ,
substantiate the implementation of steps 1-4 in the GE white paper, '
and that only a limited number of complete procurement packages were reviewed, the inspectors could not reach a conclusion as to whether the control of the dedication process for comercial grade component parts used in the Nine Mile Point 2 (NMP-2) power generation control complex (PGCC) safety-related panels and assemblies was accomplished as described in the GE white paper submitted to the NRC on July 2, 1987. It appears that some of the statements in the white paper may be overly optimistic and that the QA program implementation for these activities was not as rigorous as stated.
Other factors also contributed to the unresolved status of the inspection. One major factor is th'at of the approximately 50 safety-related PGCC panels for NMP-2, only 3 were manufactured at the Nuclear Energy Business Operations (NEB 0) facility in Sar. Jose, California. The remaining safety-related panels were fabricated at the GE Ground Systems Department (GSD) in Daytona Beach, Florida. A cursory review of the GSD purchase order, dated in 1978, indicated that GSD would be performing its own procurements, material control, fabrication process controls, testing activities and other control activities. A second factor was that due to time limitations, the inspectors were only able to perform a cursory review of the process which implements steps 5-8, including functional and qualification testing during and subsequent to fabrication.
Follow-up inspections are anticipated at GE NEB 0 and GE GSD in the !
near future and will require a review of records to detennine if the facilities adequately implemented their QA program comitments 2 as outlined in the white paper. I 70
l ORGANIZATION: GENERAL ELECTRIC COMPANY SAN JOSE, CALIFORNIA REPORT INSPECTION Hn . oconnan?/n7_n? RF9til T9- PAGF 1 nf A D. STATUS OF PREVIOUS INSPECTION FINDINGS:
No previous inspection findings were reviewed within the scope of this inspection.
E. OTHER FINDINGS AND COMMENTS:
- 1. Background - The NRC staff identified concerns with the hMP-2 design relative to IEEE-279 (1971), "Criteria for Protection Systems for Nuclear Power Generating Stations." Specifically, it appeared that numerous non-safety-related systems electrical circuits were connected to Class 1E reactor protection system (RPS) power supply buses on RPS Class 1E circuits. These concerns were identified during a staff review of a GE failure modes and effects analysis (FEMA) submitted by Niagra Mohawk Pcwer Corporation (NMPC) on May 18, 1987.
Subsequent to this review, technical meetings were held between the NRC, NMPC and GE to discuss this issue concerning NMP-2. In a meeting held on June 19, 1907 to discuss possible generic implica-tions of the RPS non-1E component issue, GE stated that these isolation componer,ts were infact Class IE. The NRC requested GE to document their position on the quality of parts contained in safety-related assemblies.
On July 2,1987 GE submitted a white paper to the NRC and to all domestic BWR utilities. This white paper describes the process at GE for the upgrading of industrial grade items (or dedication of comercial grade items) to safety-related assemblies.
The Vendor Inspection Branch (V18) was requested to conduct an inspection at GE to verify the implementation of the white paper for procurement and control of industrial grade components used in the NMP-2 PGCC. The intent of the VIB inspection was to review the documentation for a representative sample of comercial grade components used in the NMP-2 PGCC and verify that the GE QA program was implemented as stated to assure that parts and assemblies supplied by GE meet all applicable requirements for safety-related equipment.
- 2. Review of Dedication of NMP-2 PGCC Components The inspectors chose several components that would have been procured commercial grade and been put through the dedication process using the eight steps described in the white paper for use 71
ORGANIZAT10N: GENERAL ELECTRIC COMPANY SAN JOSE, CALIFORNIA REPORT INSPECTION Mn - QQQnnan9/R7 n? RFRt!I TS- par,F a nf A in safety-related assemblies. GE put together procurement packages for these components including all the necessary paperwork verifying the process described in the white paper.
The white paper can be summarized as stating that GE controlled all of the individual components within its PGCC system panels by:
a) Establishing an Appendix B structured system of "quality activity" implementing procedures and instructions; and b) Rigorously implementing the applicable portions of its program to provide a reasonable level of confidence to assure that the quality and required performance for the parts is adequate.
The eight steps in the white paper were categorized into three general areas for inspection purposes. The first area relates to step 1 of the GE white paper for establishing a QA program and implementation procedures at the "quality activity" working level.
The second area contains GE white paper step numbers 2, 3, and 4, which include:
a) Development and documentation of the requirements for individual parts (design);
b) Independent verification of the design requirements; c) Delineation of specific requirements / controls on purchase orders; and d) A receipt inspection that verifies the parts conform to the engineering requirements.
The second area is important because it determines the operating range and characteristics of a particular part to perform its function, and ensures that the correct parts are ordered and received.
The third area contains GE white paper step numbers 5, 6, 7. and 8, which iaclude: ,
a) Installation of parts into assemblies / panels with QA docu-mentation to verify the same; 72
l l
ORGANIZATION: GENERAL ELECTRIC COMPANY SAN JOSE, CALIFORNIA 1
REPORT INSPECTION l Jg goonnana/R7_n? RF9lff TS; PArJ R nf A I
b) Performance of functionability testing; c) Engineering performed qualification tests, either by test or combined test and analyses; and d) Records, inspection reports, nonconformance reports (NCRs) and other documents that verify the applicable steps were taken.
The NMP-2 components chosen were from the High Pressure Core Spray (HPCS), Reactor Core Isolation Cooling (RCIC) and the Nuclear Steam Shutoff System (NSSS), and consisted of fuses, relays, switches, meters, diodes, resistors, controllers, and a signal resistor unit.
For each component, GE put together a package which was to include <
information such as the Purchase Part Drawing (PPD, which incicdes the requirements for purchase of parts), the original Engineering Review Memorandum (ERM, which documents the independent design verification and approvals), the Purchase Order, the Quality Control Inspection Card (QCIC, which specifies any Test Instructions and receipt inspection requirements), t!)e receiving inspection history log, the Approved Suppliers List, and other background information.
Component parts to be used in PGCC panels are specified on Master Parts List (MPL). Elementary Diagram Device Lists (EDDL) and Electrical Device Lists (EDL).
The above documents should verify that steps 1-4 as described in the white paper (or the first two inspection areas) were accomplished.
When reviewing the packages, it became obvious that in several cases certain paperwork, such as the original ERM, the QCIC, and the original purchase order were not included. GE stated that since this information was extremely old, in some cases pre 1978, it could not be located.
The current process used by GE for the dedication of commercial grade j items is different than the process which was in place when the NMP-2 !
PGCC panels were originally manufactured. As GE has stated, the PGCC i was originally fabricated using commercial grade components that were dedicated for use in safety-related applications through the process described in steps 1-8 of the white paper. During the inspection, GE stated that the current system for replacement components uses dedicated PPDs and therefore does not fall under the process described in the white paper.
Dedicated PPDs are basically the original PPDs which are revised to include qualification requirements such as seismic conditions, 73 l
ORGANIZAT10N: GENERAL ELECTRIC COMPANY SAN JOSE, CALIFORNIA 1
REPORT INSPECTION kn - 0000na01/A7.07 DFRlfl TR
- DAAC K nf D environmental conditions, applicable industry standards, and any special dedication tests.
The inspectors reviewed a total of 10 NMP-2 procurement packages with PPDs and associated documentation. Of these 10 packages, 8 were for original PGCC equipment and 2 were for replacement
, equipment and included the current GE system using dedicated PPDs.
The packages for the current system were reviewed to establish a basis for the difference between dedication performed on PGCC components during initial fabrication and dedication of replacement PGCC components today.
The replacement component packages reviewed using dedicted PPDs contained all the documentation required to substantiate items 1 to 4 in the white paper. The 8 packages for the original NMP-2 PGCC components, however did not contain all of the documentation necessary to establish full compliance with the white paper. The missing documentation includes 7 PPDs without original ERMs, 2 packages without QCICs, 2 other packages without the original P0s, 2 cases where the receiving history Icg shows none of the parts received during the appropriate time frame and 3 instances where GE was unable to demonstrate that the vendor was on the approved suppliers list.
These examples tend to demonstrate that all of the records to support steps 1-4 in the white paper may not be available and the statements in the white paper may be overly optimistic. During the exit meeting, GE stated that they were going to review the white paper and discuss the possibility of revising it.
Below is a listing of the NMP-2 components reviewed with the applicable system, PPD number and panel number.
Component System PPD # Panel f Switch HPCS 249A1471 H13-P852 Diode NSSS 176A1572 H13-P609/611 Meter RCIC 159C4540 H13-P601 Relay HPCS 163C1170 H22-P028 Switch HPCS 214A1471 H13-P652 Meter RCIC 157C4570 H13-P601 Controller RCIC 163C1392 H13-P014 Fuse HPCS 145C3039 H22-P028 Fuse HPCS DA317A6159 H22-P028 Diode NSSS DA317A7898 H13-P609 74
l l
1 ORGANIZAT10N: GENERAL ELECTRIC COMPANY SAN JOSE, CALIFORNIA REPORT INSPECTION Nn . QQQOndn1/A7-n7 RFS!Il TS- PArJ 7 nf A 1 1
The inspectors began a review of the activities conducted by GE as described in items 5 to 8 in the white paper. The inspectus reviewed documentation pertaining to inspection and functional testing of I&C subassemblies, assemblies, panel inserts, and complete panels (not including interconnected panel system testing) and determined that the procedures and methods appeared adequate for their intended purposes and that the docurnented results indicated proper operation as l certified by the various technicians and QA personnel.
It was noted that the method of documentation normally does not involve recording observations and raw data, but rather only the technician's and/or QA inspector's certification that a particular step of the procedure was corepleted with satisfactory results.
The intended purpose of this functional testing would be adequate in many cases to detect malfunctioning or failed components, and in some cases to detect degraded performance. However, there are sone design attributes of components of these assemblies that are impor-tant to durability which cannot be evaluated solely by functional testing of unaged components under shop ambient conditions. These attributes require individual component inspection, material verification, etc., to verify that all design specifications are met.
The installation, testing and qualification of components at the subassembly, assembly, panel insert, and panel level will be reviewed in more detail to verify that GE accomplished this process as described in steps 5 to 8 of the white paper. This is considered unresolved item (87-02-01) and a further review will be con (ucted 1 during a future inspection.
F. PERSONNEL CONTACTED:
- Don H. Ferguson, Manager, QAES, GE-NSQA !
- James J. Fox, Senior Program Manager, GE-QA !
- Roger K. Waldman, Principal Engineer
- George B. Stramback, Safety Evaluation Program Manager, GE-Licensing and Control Services
- Louis D. Test, Consulting Engineer, GE-QA
- Joseph M. Case, QA System, Manager, GE-QA
- Norman E. Barclay, Principal Engineer , GE-NSQA E. Wester, Principal Project Engineer
- H. R. Peffer, Project Manager, Nine Mile Point i
1 75 I
i i
l
ORGANIZAT10N: GENERAL ELECTRIC COMPANY SAN JOSE, CALIFORNIA l
REPORT INSPECTION R F9lll TR- parF A nf A NO
- QQQnnan9/A7 n?
- R. Artigas, Manager, L&CS
- Noel Shirley, Sr. Licensing Engineer
- L. S. Bohl, Manager, QA/NSTO
- B. A. Smith, Counsel
- R. L. Fisher, Principal Engineer, Material Services
- Harry L. Shannon, Manager, Test Engineering
- H. C. Pfefferlen, HGR BWR Licensing Issues l
- Attended exit meeting.
I 4
4 76 l i
-e._ _ . . _ . . _ . - .__m _ _ _ _, __. _. _ _ .__m _ _ . _
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS SAN JOSE, CALIFORNIA REPORT INSPECTION INSPECTION NO.: 99900403/87-03 DATES: 6/15-18 & 7/27-8/6/87 ON-SITE HOURS: 264 CORRESP0hDENCE ADDRESS: General Electric Company Nuclear Energy Business Operations ATTN: Mr. N. L. Felmus, Vice President and General Manager 175 Curtner Avenue San Jose, California 95125 ORGANIZATIONAL CONTACT: Mr. J. J. Fox, Senior Program Manager TELEPHONE NUMBER: (408) 925 6105 NUCLEAR INDUSTRY ACTIVITY: General Electric Company's Nuclear Energy Business Operations (GE NEB 0) is engaged in furnishing engineering services for domestic and foreign nuclear power plants.
ASSIGNED INSPECTOR: .<pb _ /J/ h /dIh R. IK Ptttis, Specia VProjects spection Section Date (CPIS)
OTHER INSPECTOR (S): R. P. McIntyre, SPIS S. Alexander, SPIS P o ,r Consultant P. Eshleman, Consultant APPROVED BY: 9W -
(0-13-I7 U.Potapovs, Chief,(PIS,VendorInspectionBranch Date INSPECTION BASES AND SCOPE:
A. BASES: 10 CFR Part 21 and 10 CFR Part 50.
B. SCOPE:
The purpose of this follow-up inspection was to review allegations involving potential deficiencies in design control activities within the Quality Assurance program at GE San Jose, during the period March 1978 to April 1982. In addition, the status of previous inspection findings was also reviewed. I PLANT SITE APPLICABILITY: Potentially multiple plant sites, including River Bend, TVA Units 17-22 (identified by GE as cancelled), Perry 1/2, Nine Mile Point 2, Hope Creek 1/2, Grand Gulf 1/2, Limerick, Clinton, and Susquehanna 1/2.
l 77
ORGANIZAT10N: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS 9AN JOSE. CALIFORNIA REPORT INSPECTION N0.: 99900403/87-03 RESULTS: > AGE 2 of 27 A. VIOLATIONS:
None.
B. NONCONFORMANCES:
Contrary to GE Engineering Operating Procedure 42-6.00, "Independent Design Verification," dated April 30, 1981, GE did not perform a seismic analysis, as required by the GE Problem Review Board in a letter dated November 17, 1980, extending the original seismic qualification data, performed in 1978, to a 1980 revised design configuration of the reactor mode switch and its interface with the isolation casing (87-03-01).
C. UNRESOLVED ITEMS:
None.
D. STATUS OF PREVIOUS IHSPECTION FINDINGS:
- 1. (Closed) Nonconformance (87-01-01)
GE issued Engineering Change Notice (ECN) NJ-17436, dated June 2, 1980, without a tecinical justification to delete the requirement for glyptal coating of GE Electrical Metallic Tubing (EMT) because of unavailability.
GE's response to this item of nonconformance indicated that GE decided to use Purchase Part Drawing 175A9666 to improve the identification and control of various sizes of EMT as part of a company decision to identify commercially available materials on Purchased Part Drawings. GE stated that the statement "BAKED ON CLEAR GLYPTAL" was simply copied from a GE commercial catalog and wa not a necessary design requirement for any EMT used in nuclear control and instrumentation panel assemblies manufactured by GE. In May 1980, GE (San Jose) learned that EMT with baked on glyptal was no longer commercially available and therefore deleted the statement i from the drawing via ECN NJ17435. As a result, this item is closed.
- 2. (0 pen) Unresolved Item (86-01-07)
GE Engineering Practices and Procedures (EP&P) 5.38 Addendum 4, {
dated December 1975, required that a tracking system and status I log of deferred verifications be maintained. The inspectors l 78 q
- - ~ - ,
f -
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS SAN JOSE. CALIFORNIA REPORT INSPECTION NO.: 99900403/87-03 RESULTS: ) AGE 3 of 27 verified during NRC Inspection 86-01 that the first entry was made in the status log for deferred verifications in May 1977. At that time, it could not be determined whether verifications had been deferred before May 1977 since the status log did not contain entries of any deferred verifications prior to that date.
During the 86-01 inspection, GE committed to perform an extensive review of deferred verifications from inception through May 1977 to positively demonstrate closure of deferred design verifications.
During an NRC review of this effort during the June 15-18, 1987, inspection, GE reviewed all 15,322 Engineering Review Memorandums (ERMs) generated from inception to May 1977 to identify ERMs containing a deferred verification statement. As a result, 962 ERMs were identified which affected 3423 design documents. A computer search of these documents, performed on GE's Engineering Information System (EIS), was then used to identify the current deferred verifica-tion status of the affected documents which resulted in only three documents identified as "u" (unverified). At the end of the inspection, GE committed to researching further the status of these three documents to verify closure. A DBASE III computer program was used by GE to produce a list of deferred verifications based on criteria previously established by the NRC inspector. The criteria established was based on safety-related shippable components produced by GE NEB 0, San Jose, for use on domestic nuclear power plants.
This search produced approximatley 130 design documents of which the NRC inspector selected six for further review t'y GE. GE's review consisted of a manual search of documentation (ERMs, ECNs, etc.)
necessary to demonstrate positive opening and closing of each deferred verification throughout the history of ear.h document. This review also verified the current status as now reported in the EIS.
In a few instances, the six documents selected for resiew by the NRC related directly to items referenced in Mr. Stokes' summary of Mr. Milam's work record and are associated with Limerick, Susquehanna, and the Shoreham nuclear plants. These six items are:
Item Document No. ERM System / Component 1 283X569 BMA 0743 Reactor Vessel Top Guide 2 851E378 CHA 111 Reactor Protection System Elementary Diagram 79
ORGAN 11AT10N: .GEfMRAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS 9A N OSF, CALIFORNIA REPOR1 INSPECTION NO.: 999r10403/ 87-03 RESULTS: ' AGE 4 of 27
- 1. tem Docuntent No. ERM System / Component 3 828E375TF AMC 0057 RWC and Recirculation Bench Board 4 8650152 AMC 0871 RHR/HPCI I Relay Vertical Board 5 237X574TN AMC 0600 HPCI RLY Yertical Board 6 13309538 AMC 0568 RCIC RLY Vertical Board Durins the 87-03 inspection, GE informed the inspectors that it had completed this review. This unresolved item will remain open pending NRC's review of GE's actions during the next inspection.
'3 . 1 Closed)UnresolvedItem(87-01-09)
GE's Problem Review Board (PRB) stated in a letter dated June 13, 1980, that a stadified reactor mode switch should replace those previously shipped and that the design changes required were to be documated via a Field Disposition Instruction (FDI) document. The FD1 referenced by the PRB was not available for review during the previous NRC inspection.
GE's re'ponse s to this unresolved item stated that the correct reactor mode switch is now installed in all boiling water reactor (BWR) plants. This installation was initiated as a replacement in BWRs in late 1943 and 1984, based on a GE product improvement redesign and i the issuance of NRC Information Notice 83-42. Because the GE J response did not fully address the concerns of unresolved item 86-01-09, this item remains open pending a further review of the 155v upgra6 data and the 1983 product improvement redesign including all affected FDl's.
Insxction Findings - The inspectors reviewed documentation contained
~
in ?ctential Reportable Condition (PRC) files 80-57 and 83-22. PRC 80-57 dealt with the 1980 modification and improvement to the hcus vg asse e ly. After engineering evaluations were performed b GE, which included two meetings of the Problem Review Board (PRB)y ,
reconnendations were made to improve the mode switch housing 6s Nably. These reconnendations (identified as Product Improvements by GE) were made via Engineering Change Notices, not FDIs, at applicable plants, The 1983 redesign of the reactor mode switch I
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS SAN JOSE. CALIFORNIA REPORT INSPECTION NO.: 99900403/87-03 RESULTS: PAGE 5 of 27 came as a direct result of problems experienced at Susquehanna Unit 1 concerning loss of certain scram signals during switching of the reactor mode switch. Subsequent to Susquehanna's notification of this problem to the NRC, IE Information Notice 83-43 was issued which initiated action to correct these problems. The inspectors verified that a replacement mode switch was sent to all affected l
utilities via a Field Disposition Instruction (FDI) or a Field l Deviation Dispositon Request (FDDR).
Based on this review, this unresolved item is considered closed.
Additional information concerning the reactor mode switch is presented in Section E.6 of this report.
- 4. (0 pen) Stokes Report Section 1.6 Engineering Review Memorandums (ERMs)
"In the first week of November 1978, the following line was part of an entry: Bill Millard said either he would sign the ERMs or I (Sam) could forge his signature to them." (Clarification added by Mr. Stokes.)
Inspection Findings - During the 87-01 inspection, discussions were held with Mr. Millard at which time he denied any such statements concerning "forging" of his signature. Because specific details were not available as to the ERM referenced by Mr. Milam's work record entry in November 1978, the inspector was unable to verify whether Mr. Milam signed his own name or whether Mr. Milam "signed 'or" Mr. Millard. This item will remain open.
- 5. (0 pen) Stokes Report Section 1.7 Elementary Diagram Drafting Effort ,
"Continuing with a problem of similar nature on November 14, 1978, a letter to C.W. Hart on the subject of the CNV connection has an interesting paragraph. It seems that the CNV elementary diagram drafting effort was subcontracted to an outside firm, the Power i Division of C.F. Braun & Company, in Alhambra, California. When completed, the diagrams were provided to the General Electric System i Engineers for signature. The system Engineers felt that they were not being given sufficient time for review and refused to sign the ,
documents. The documents were later signed by the C&EE CNV Engineer, without review." l l
l 81 l l
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS RAN JOSE. CALIFORNIA REPORT INSPECTION NO.: 99900403/87-03 RESULTS: PAGE 6 of 27 Inspection Findings - During the 87-01 inspection discussions were held with Mr. C.W. Hart, Mr. Milam's supervisor during this period, who stated he had never received the November 14, 1978 letter. In addition, specific examples of insufficient review times could not be identified from the connents contained in the ERMs or the discussion with Mr. Hart. This item will remain open.
- 6. (0 pen) Stokes Report Section 6.2 Unauthorized Signature Changes "Mr. Milam wrote a letter to W.M. Barrentine on April 14, 1982 about unauthorized, post signature changes. In this letter, Mr. Milam states that R.L. Reghitto made an authorized change to ERM AML-2997 without Mr. Milam's knowledge and in direct conflict with specific instructions."
Inspection Findings - A discussion during the 87-01 inspection with Mr. Barrentine, in the presence of Mr. Barton Smith, GE counsel, inquired as to what actions were taken concerning this subject.
! Mr. Barrentine stated he had not received Mr. Milam's letter of April 14, 1982. He also stated that he was not aware of anyone else who might have known about the letter and also might have acted on l it in his (Mr. Barrentine's) place while he was on business travel. l This item will remain open, i i
- 7. (0 pen) Stokes Report Section 6.3 i Letter to Management "On May 22, 1982, Mr. Milam wrote Mr. Barrentine a letter and included a copy of his work record while working for Mr. C.L. Cobler.
In this letter, Mr. Milam requested Mr. Barrentine to read about the on-going underworld of C&ID and says he tried to communicate some of these things to Mr. Barrentine on several occasions but was discouraged by Mr. Barrentine's managers and attitude. Mr. Milam says:
Since you no longer hold my form 38 (a standard threat), I have nothing further to fear from either you or your conspiratorial managers. I hope, by sending you this Record, to give you a glimpse into that hidden world of ,
uncontrolled bootleg activity we all know so well. l l l l
l 82 1
ORGANIZAT10N: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS SAN JOSE. CALIFORNIA REPORT INSPECTION NO.: 99900403/87-03 RESULTS: > AGE 7 of 27 Mr. Stokes also stated that Mr. Barrentine was the manager of the Nuclear Control & Instrumentation Product Design Operation (NC&lD) of (C&ID). He was Mr. Hart's, Mr. Cobler's, Mr. Reghitto's, Mr. Strambach's, Mr. Koslow's, and Mr. Wortham's supervisor.
Mr. Milam had been notified of his layoff when this last letter was l written and his reference to fonn 38 had to do with the constant l
threat of layoff if you did not go along with the system. He did I not."
Inspection findings - In a discussion during the 87-01 inspection with Mr. Barrentine stated he never received the letter in question nor the portion of Mr. Milam's work record. This item will remain open.
- 8. (0 pen) Stokes Report Section 5.13 River Bend Excluded Equipment List "Mr. Milam's work record included a nonapproved form titled PWA No.
1229LD, Revision IJ for River Bend. This document, which is dated February 5, 1982, was caused by an excluded equipment list which was sent to the utility, Gulf States Utilities Company, by the NRC. The second page of this document states that there is no controlled tracking system for vendor identification of these devices and that a complete item by item search of the entire River Bend database would be necessary. GE felt that the scope of such a search was prohibitive and furthermore was not considered to be necessary.
Excluded equipment as referred to in this list is equipment which has been found at other facilities to be so deficient.that plant safety is seriously in question. GE neither admitted nor denied that this equipment was installed at River Bend."
Inspection Findings - The objectives during this portion of the inspection were to determine, to the extent possible, the following:
(1) What items on the Excluded Equipment List (EEL), which was prepared and submitted to GE by Stone and Webster Engineering Corporation,are used by GE NEB 0 in what plants and applications.
(2) Whether the use of those items is appropriate for the particular application in light of the problems or deficiencies with the ]
items that caused them to be listed.
1 (3) How nonnal GE controls identified the problems associated with i listed items. i 1
83 l
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUS 8 NESS OPERATIONS SAN JOSE. CALIFORNIA REPORT INSPECTION NO.: 99900403/87-03 RESULTS: ' AGE 8 of 27 (4) The effectiveness of GE NEB 0 and product department systems for disseminating information on problems with equipment in preventing inappropriate use.
(5) How and to what extent, if any, GE was negligent in not responding to the request from Stone & Webster to confirm that listed items were not used at the River Bend Plant.
To make these determinations, the inspectors reviewed the following documentat1on:
(1) A GE computer generated listing of all purchase part drawings (PPDs), called"CATNIP."
(2) The file of GE Service Information Letters (SIls).
(3) The Index of Field Deviation Disposition Requests (FDDRs),
Field Disposition Instructions (FDIs), Potentially Reportable Conditions (PRCs) (under 10 CFR 21), and the Index of "Germane-to-Safety" (GTS) Notifications (Considered by GE to be non-reportable under 10 CFR 21, but still a safety concern to GE customers).
(4) A listing from the GE Service Representative in Philadelphia of Service Advice Letters (SALs) issued by GE Power Systems Management Business Division (PSMBD) for components for which there was a PPD annotated to reflect which were on file with the NEB 0 electrical and instrumentation and control (I&C) engineering department.
Although additional information must be reviewed before conclusive findings can be reached with respect to the stated objectives, the following points were evident from the information reviewed during the inspection:
(1) Review of the CATNIP revealed that there were PPDs for components of the same manufacturer and with the same model number as many of the EEL items. (Note that in some cases, the EEL lists only manufacturer and model and in others, particular lots or manufacturing periods are specified, requiring review of other documentation to determine if the components in question were purchased and/or used.)
84
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS '
RAN JOSE. CALIFORNIA REPORT INSPECTION N0.: 99900403/87-03 RESULTS: PAGE 9 of 27 (2) A review of the SILs by the inspector indicated that, in many cases, NEB 0 had advised customers of problems associated with EEL items and had provided recomendations for corrective measures.
(3) The NRC inspector noted that although NEB 0 procedures call for issues that are to be the subjects of SILs to be screened for safety ramifications and if any, forwarded to the PRC Coordinator for 10 CFR 21 screening, many SILs were issued in addition to 10 CFR 21 reports on the same issue.
(4) Not all SALs pertaining to EEL components were on file with GE NEB 0 Electrical Engineering although it was learned that NEB 0 was taking actions to be placed on the distribution list for all SALs.
(5) The inspector observed no evidence of a formal system to ensure that SALs received by NEB 0 would be screened by other than QA for applicability to particular plants or generic applicability, in addition, no evidence of a formal distribution and/or action tracking plan for QA to use for SALs was observed.
Additional documentation was requested and intended to be reviewed along with the above to aid in the objective detennination.
Some information was made available and was requested from product departments; however, none of the following was reviewed during the inspection.
(1) Complete listings from the three GE product departments that supplied EEL components, for which there was a PPD, of all SALs issued by them on those components.
(2) A listing (for comparison with the lists of SALs issued) of which SALs are held by GE Electrical Engineering, QA, or elsewhere particularly as relating to EEL components.
(3) The file of customer correspondence held by the GE project engineer for River Bend and Nine Mile Point-2, individual FDDRs selected from the FDDR Index pertaining to EEL components, and the file of individual FDIs selected from the FDI Index pertaining to EEL components.
(4) Individual PRC and GTS evaluations / dispositions selected from the PRC/GTS Logs and SALs pertaining to EEL components.
85
I ORGANIZATION: GENERAL ELECTRIC COMPANY l
NUCLEAR ENERGY BUSINESS OPERATIONS l RAN JOSE. CALIFORNIA REPORT INSPECTION NO.: 99900403/87-03 RESULTS: > AGE 10 of 27 (5) A complete "Where Used" printout from the GE Engineering Informa-tion (EIS) data base for PPDs of EEL components.
l (6) Procurement documents for components with EEL model numbers to determine if the let numbers or particular manufacturing period of concern were included.
(7) QA documents, such as receipt inspection records for components with EEL model numbers to determine if the lot numbers or particular manufacturing periods of concern were included.
As discussed above, the NRC inspector drew sone interim conclusions on the basis of the information reviewed during this inspection as discussed previously. However, determining conclusive findings with respect to the stated objectives will require a further review of the documentation listed above. As a result, this item will remain open.
E. OTHER FINDINGS AND OBSERVATIONS:
Background Information As stated previously NRC Inspection Report Nos. 99900403/86-01 and 87-01 did not attempt to address all of the allegations raised by Mr. Milam and Mr. Stokes, but rather, a representative sample of potentially more significant allegations was selected for review. However, all allega-tions received by the NRC are being addressed and will be documented in future inspection reports. Previously, the area of deferred design verification was addressed which represented the alleger's major concerns (as noted during an NRC interview with the alleger in April 1986). As stated in Section D.2 of this report, tnis item is open and will be reviewed during the next inspectiun.
This inspection report primarily focuses on the follow-up of items of nonconformance and unresolved items identified in NRC Inspection Report No. 99900403/87-01. This was accomplished in part by a review of GE's responses to such items (GE's letters to the NRC dated February 5 and March 5,1987) in addition to a formal review of all documentation supportive of GE's response. In addition, several new issues in the areas of fire protection and the use of unverified documents used in preparing GE licensing documents, including the FSAR, were introduced during this inspection as a result of Congressman Edward Markey's April 10, 1987 letter to NRC Chairman Lando Zech. It should be noted that issues involving fire protection were not contained in Mr. Stokes' report, but have been extracted directly from Mr. Milam's work record.
86
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS SAN JOSE. CAllFORNIA REPORT INSPECTION N0.: 99900403/87-03 RESULTS: 3 AGE 11 of 27 The representative sample of allegations inspected is summarized below, along with the results of the NRC review of each item. The inspection was composed of personnel interviews, examination of applicable files, records and procedures.
- 1. Halon-Based Fire Protection Systems During the inspection, the inspectors reviewed GE's response to Grand Gulf licensing question 013.22, (April 1981) relating to Halon-based fire systems. Halon-based fire system are important safety features in control rooms since they suppress flames without destroying the operator's ability to breathe. One such question posed by the licensee required GE to verify that the Halon system installed at Grand Gulf to protect the Power Generation Control Console (PGCC) floor sections is designed to provide a 30 percent concentration. GE's response stated that the floor section fire suppression system is designed to provide an initial concentration of 6 percent to 7 percent, by volume of Halon within 10 seconds of initiation and sustain a 20 percent concentration for 20 minutes.
GE's response to the licensee raised questions from Congressinan Markey as to the minimum concentration standard in addition to the fire systems furnishing only two-thirds coverage and the possible effect this may have on the operators ability to control the plant in the event of a severe fire.
Inspection Findings - The NRC does not have a requirement of 30 parcent halon coverage for control room:,. NFPA 12-A, Standard on Halon 1301 Extinguishing Systems,1985 Edition, published by the National Fire Protection Association, specifies minimum design concentrations (given as percent by volume) for Halon 1301 ranging from 5.0 percent to 8.2 percent depending on the type of fire (fuel) involved. The 1973 Edition of NFPA 12A specified two larger concentrations - 12 percent for carbon disulfide and 20.0 percent for hydrogen - but the rest of the concentrations given are similar to those listed in the 1985 Edition. The Standard also states: "In addition to the
, concentration requirements, additional quantities of agent may be required to compensate for any special conditions which would affect the extinguishing efficiency." Carbon disulfide and hydrogen ignite easily and are difficult to extinguish. They have been dropped by specific reference from the standard and are covered by paragraph 2-3.2.2(d), which gives minimum design concentrations required to extinguish nonnal fires involving several flammable liquids and gases. Design flame extinguishment concentrations not listed shall be obtained by test plus a 20 percent safety factor, and minimum design concentrations shall be 5 percent.
1 87
ORGAN!ZAT!0N: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS RAN JOSE. CALIFORNIA REPORT INSPECTION NO.: 99900403/87-03 RESULTS: PAGE 12 of 27 The GE PGCC control room is constructed of prefabricated and prewired modular units consisting of control cabinets and consoles mounted on steel floor panels with cables and cable harnesses located in under-t the-floor steel cable troughs. The total flooding Halon 1301 fire l suppression systems that are the subject of this question are for the protection of these under floor cable troughs. The Halon requirements address concentrations (percent volume of these under-the-floor cable troughs). There are no nuclear power plants with total flooding Halon 1301 suppression for the entire control room volume.
The concept of Defense-in-Depth as applied to nuclear power plant fire protection involves several different levels of activity and concern. The first step in the program is fire prevention. The second step is to provide fire detection and fire suppression capabililty in the event a fire should occur despite fire prevention activities. The third step is to ensure by means of separation and passive fire protection that even if a fire should occur and be promptly extinguished, it will not prevent safe shutdown of the plant because of fire damage to safe shutdown cables and components.
The defense-in-depth theory also affects the second step with respect to minimum design concentration for Halon 1301. After the Browns Ferry fire in March 1975, the NRC staff devoted considerable time to development of a broad spectrum of fire protection guidelines for nuclear power plants. During this time GE was developing and NRC was reviewing and approving, minimum design concentrations for Halon 1301 protection in under-the-floor cable trough fur PGCC installations. For some of these installations design concentrations as high as 30 percent were agreed upon. These higher concentrations were stipulated to give a greater margin of safety because of any
) unknown factors that could not be easily quantified, in addition, it was reasoned, the volumes to be protected and resultant increased installation costs would be small, and the increased hazard to personnel from Halon 1301 leaking out of the cable trough into the control room volume would be negligible.
In n. ore recent installations the need for such conservatism in specifying minimum design concentrations three to five times higher than those specified by NFPA 12A has been reevaluated. With installations using improved cable constructions that meet the fire-retardant criteria of IEEE Standard 383, the NRC staff found no technical justification to continue with the earlier conservative approach calling for substantially higher Halon 1301 concentration.
In addition, the staff found that the original rationale was not based 88 1
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS SAN JOSE. CALIFORNIA REPORT INSPECTION RESULTS: ' AGE 13 of 27 N0.: 99900403/87-03 upon arguments that can now be justified as technically compelling.
The NRC staff therefore, concluded that use of the higher concentra-tions of Halon 1301 in the newer plants would not result in a corresponding increase in plant safety.
On this basis, the NRC staff concluded that reducing the concentra-tion of Halon 1301 in the PGCC under-the-floor cable troughs to those l
l generally accepted concentrations contained in NFPA 12A would not adversely affect fire protection nor would it affect the operattr's ability to control or shutdown the reactor in the event of a severe fire in the control room. The Halon 1301 protection for the PGCC cable trough is only one of the components of the defense-in-depth approach to the provision of fire protection for these control rooms. '
It constitutes protection above that nonnally provided for control rooms and more than satisfies those minimum design concentrations stipulated in NFPA 12A. Therefore, reducing the design concentra-tion from those earlier specified levels, which are now understood to have been unnecessarily conservative, does not constitute any reduction of protectinn, i
Discussions with the GE staff and a review of GE's design files revealed that Halon concentrations were changed because cable material insulation with lower concentrations and longer soak times providing the required fire suppression was in compliance with NFPA 12A recommendations. Included in this review were descriptions of site-specific test procedures to verify thc adequacy of the suppression material as applied at each plant installation. No relaxation of the fire protection design standards was noted in this review. As a result, this item is considered closed.
- 2. Kaowool vs. Sand Another area potentially affecting the protection of control room instrumentation in the event of a fire was covered in an internal GE memorandum dated May 23, 1980 with regard to the fire stop design requirenents for Grand Gulf 1/2 and Clinton 1. The memorandum stated that a combination of metal barriers and Kaowool, both covered with RTV Rubber would constitute the fire break design in the control room under-the-floor cable troughs. This memorandum also indicated concern about the inability of Kaowool to fill the cable interstices and that Kaowool may be too easily removed. The memorandum also stated that unless specific NRC approval is obtained, this design approach may be unsatisfactory.
)
89
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS SAN JOSE. CALIFORNIA REPORT INSPECTION NO.: 99900403/87-03 RESULTS: PAGE 14 of 27 During early discussions between GE and NRC concerning fire protection for the under floor cable troughs in the PGCC, one design concept that was considered involved filling the cable trough with sand.
After considerable discussion of the idea in 1976-1978, all parties agreed that the potential disadvantage outweighed the benefits of using sand as a fire stop, especially considering the low risk of fire occurrence and associated damage to control room cables.
Therefore, the concept of filling the cable troughs with sand was not adopted by GE and was never required by NRC. GE's current design of the fire stops is based upon test data obtained by GE during tests conducted at the University of California at Berkley.
The design concepts are presented in design concept document NE00-10466A titled "Power Generation Control Complex Design Criteria and Safety Evaluation." This document and amendments are referenced in the FSAR's of the GE plants utilizing PGCC equipment. The criteria for the fire stop material is referenced as 3 inch minimum of a refractory material. The tests at the University of California are included as a reference in this document. The refractory material used in these tests was No. 20 sand. A refractory blanket material is currently utilized as a fire stop material in openings which '
do not have cables passing thru the opening. However, in the areas where cables are present an RTV foam material is applied as the fire >
stop material and sealant between the cable trough and is utilized throughout current plants as a fire stop. GE stated the existence of an analysis documenting the acceptability of the RTV foam material in lieu of using No. 20 sand, as utilized in the original test program. However, NED0-10466A does not reference this alterna-tive material. Because GE considers NEDO documents to be licensing documents only (not design documents), GE does not intend to revise NED0-10466A to reflect the substitution of RTV foam material for No. 20 sand.
Where Kaowool had been installed, the design cetails were reviewed and found acceptable by the NRC. Fires that are caused by earth-quakes generally involve rupture of flanrnable liquid and gas storage tanks and piping distribution systems. Since these hazards are not present in nuclear power plant control rooms and since these facilities are designed and constructed to resist and prevent unacceptable damage from earthquakes, earthquake-induced fires are not anticipated and are not included in the design criteria for control rooms.
90
ORGANIZATZON: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS SAN JOSE. CALIFORNIA REPORT INSPECTION L NO.: 99900403/87-03 RESULTS: PAGE 15 of 27 The inspectors recommended that NED0-10466A be revised to reflect the RTV foam material as an acceptable alternative to using sand for
- applicable plant installations. GE stated their position regarding the revision of technical licensing topical reports is
- (1) as a rule, technical topical reports are not revised after they have been approved by the NRC, (2) the topical reports are not intended to provide design requirements to any design groups within GE, and (3) the topical reports provide an acceptable method for addressing a generic issue or a way of meeting an NRC staff requirement based on best available information at the time. GE stated that these
': licensing topicals can be referenced in specific plant FSARs as a preapproved licensing document.
The utilization of the RTV foam material, used at Grand Gulf and Clinton 1 (and possibly other plants), remains an open item and will be reviewed further during the next inspection.
- 3. ,Unvarified Documents Stokes Report Section 3.9 "Mr. Milam had a disagreement with George Stramback on 3-3-81 over the use of unverified documents to verify FSARs. Mr. Milam felt that they should note the use of unverified documents to verify FSARs and fonnally notify the responsible engineer that his unverified documents were used to support an FSAR quality review.
Mr. Stramback felt that the verification status of the documents that were used was not important. Mr. Reghitto was in agreement !
with Mr. Stramback."
Stokes Coment: Unverified documents should not be used to verify any other design documents. This includes the FSAR, which is used by the NRC Comissioners to grant the license. 10 CFR 50 Appendix B, Section I, "Or are those of (ganization," saysanthat a) assuring that the quality appropriate assurance quality functions assurance program is established and effectively executed and (b) verifying, such as by checking, auditing, and inspecting activities affecting safety-related functions, to ensure that those activities have been correctly perfonned.
Inspection findings - The NRC inspector verified that part of Mr. Milam's job at the time was to perform quality reviews of the FSAR sections assigned to him during which he was to-identify the l
l J
l 91 l
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS SAN JOSE. CALIFORNIA REPORT INSPECTION NO.: 99900403/87-03 RESULTS: PAGE 16 of 27 design documents used to support the descriptive text and document that correlation, during which time Mr. Milam identified design documents which may not have been in a verified status at the time of his review. GE stated that they were not aware of any FSAR updating caused as a result of an unverified document change.
The FSAR text is a description of the plant as depicted in other GE, Architect-Engineer, and Utility documents. It provides a narrative explanation which is reviewed by the NRC in addition to the other documents which are either required to be supplied to the NRC or are available upon request. It represents a functional level explanation of the drawings, symbols, and other documents which are the basis for the design and demonstration of plant adequacy and is the responsi- .
bility of the utility to maintain. If the utility maintains the i total responsibility, GE sends updated documents to keep the FSAR !
current. These updates may be used for clearing of design verifica-tion or other reasons. It should be noted that the FSAR is a constantly changing document up to plant licensing and undergoes many an4ndments. The GE design document process (in compliance with the Quality Requirements of 10 CFR S0 Appendix B) controls the genera-tion of documents for first time use and any necessary later changing of information contained in those documents. If a document was issued for use without verification being complete (deferred verification), it is scheduled and tracked until the verification process was completed. In most cases the document when finally verified, required no change from the already issued document.
However, if a change is necessary, as a result of completion of verification after the docunent was first issued, the Change Control process outlined in GE E0P 55-2.00 would be initiated.
This E0P process authorizes and initiates the modification to the FSAR document, as well as, the design document itself. The Engineering Change Authorization (ECA) process and its related documents include a Change Impact Check Sheet which requires identification in the Change Impact Effects section of FSAR type changes. Once the need for the FSAR change is identified, the affected FSARs are put on the ECA and scheduled for completion. The task for completion is then scheduled and tracked in GE's Work PlanningandScheduleSystem(WPSS). l In an attempt to ver',fy this system the NRC inspectors selected I eight ECAs for review, generated by GE for Grand Gulf, during the !
1981 period as covered by the work record with a total of four ECAs noted as potentially affecting the Grand Gulf FSAR (ECAs 801203-1A, 92 t
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS RAN JOSF. CALIFORNIA REPORT INSPECTION N0.: 99900403/67-03 RESULTS: PAGE 17 of 27 810609-1A,810430-2A,and810615-1). ECA 810615-1 issued August 19, 1981 was selected by the inspectors for review in order to verify the documentation path necessary to cause the FSAR to be updated.
i I This particular ECA was generated as part of the Boiling Water Reactor Owners Group response to the NRC action plan developed for Three Mile Island as documented in NUREG-0660 and NUREG-0737. The change in question described a logic modification proposed by GE which would have improved the High Pressure Core Spray system automatic response after manual termination of the system.
The inspectors verified that the package initiating such proposed change was complete and contained the required documentation as described in GE E0P 55-2.00, issued March 31, 1977. The Change Impact Check Sheet, dated June 15, 1981, was reviewed and contained a checkmark next to the column "Licensing SAR's or Topical Report Changes Required" which indicated the potential for such document to be affected by the proposed change. As a result, GE Safety and Licensing Department proposed to the utility (Mississippi Power &
Light and Middle South Energy, Inc.) a change to the Updated FSAR (UFSAR),Section 7.3.1.1.1.3.4. "Logic and Sequencing." This change proposed adding the following section which stated, "The HPCS system can be reset if reactor water level has been restored even if '
the high drywell pressure ccndition persists. The HPCS pump can then be stopped and the injection valves closed. Automatic restart will occur if the low water level condition returns." A review of Volume 13 of the UFSAR by the inspectors was found to incorporate GE's proposed change and demonstrated satisfactory compliance to GE E0P 55-2.00. The UFSAR is the reference document for purposes of i communicating with the NRC such as reporting of deviations from conditions stated in the FSAR and for 10 CFR 50.59 evaluations. The original FSAR, as amended, is considered to be the licensing basis i for the plant. l As a result of this review, the inspectors were unable to verify the concerns expressed by Mr. Milam. It was noted, however, that the NEDO documents are used as a reference for FSAR design descriptions, but these same documents are not considered as a design reference for the plant designs as developed by the GE responsible engineers.
It was also noted from the discussions held with the GE staff that NEDO type documents are not controlled under 10 CFR 50 Appendix B design control and project application is difficult to established since they are not tracked by project. The HE00 documents are reviewed and approved by management, however the plant designs are I
< 1 93
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS SAN JOSE. CALIFORNIA REPORT INSPECTION NO.: 99900403/87-03 RESULTS: PAGE 18 of 27 based upon design specifications and referenced to a NED0 document.
From this discussion it was apparent that confusion as to the purpose l and use of these documents in the FSAR reviews (where particular designs are presented for NRC approval) may have existed during Mr. Milam's employment while in the Technical Licensing Unit of the Control and Instrumentation Department. As a result of the above, the allegation was not substantiated and is considered closed.
- 4. FSAR Verification Stokes Report Section 3.10 - During FW8112 (the third week of March),
Mr. Milam discovered that they routinely use NED0-10466-A to support FSAR's. He feels that since the purpose of the FSAR review is to l
show that the FSAR in question is supported by the design, the use of NED0 documents is not appropriate. The NEDO documents do not provide formal support because they are not controlling design documents and therefore do not formally define the design. Further l items that bothered Mr. Milam were:
- 1. NE00's are not issued through the formal engineering review cycle.
- 2. NED0's are not covered by change control.
- 3. Because of 1 and 2 above, NED0's do not satisfy document requirements for design control and change control of 10 CFR 50 Appendix B.
- 4. Except for very rare exceptions, NED0's do not appear in the GE Engineering Information System (EIS). Thus, the revision status is difficult to establish.
- 5. NED0's do not appear on the project Master Parts List (MPL's).
Thus, project application is difficult to establish.
Conment: The least the NED0's should do is reflect the design.
Inspection Findings - GE stated that NED0 documents describing designs and systems conform to a proceduralized issue and change control system, as outlined in NED0-22000, and are approved by GE management, and as in the case of NED0-10466-A, have been accepted by the NRC as a Licensing Topical Report (LTR). The FSAR reviews are instituted to ensure that the FSAR properly reflects plant design. In appropriate cases, NEDO documents are used as an 94
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS SAN JOSE. CALIFORNIA REPORT INSPECTION N0.: 99900403/87-03 RESULTS: PAGE 19 of 27 approved source. The reviewing engineer assures the factual accuracy of the FSAR statement, and determines the appropriateness of using a NEDO document as a source. NED0 accuracy has been appropriately maintained by controlled document revisions initiated by the responsible author and approved by management. NED0 documents describing designs and systems are based on documents produced, issued and revised under the controlled GE QA system (E0Ps). The NEDO documents undergo extensive review with acceptance and signoff by management prior to issue. It is preferred to use design documents in the review of FSARs when an NRC accepted LTR does not exist and when changes to design documents have not yet been reflected in an NRC accepted LTR, as was indicated by Mr. Reghitto's note (attached to Mr. Milam's concern) which was circulated to the responsible GE organization on March 23, 1981.
The following represent NRC inspection findings to Mr. Milam's issues raised under items 1-5 above.
Issue 1 NE00s are not issued through the formal engineering review cycle.
Inspection Findings NE00s are issued and revised through a formal GE document control system. They are not processed through the " m al engineering review cycle" because they are not formal design documents which conform to 10 CFR 50. GE design requirements and NRC connitments which may appear in NED0s are incorporated by the responsible design engineer into GE design documents which are controlled by the design document control system (E0Ps).
Issue 2
, NED0s are not covered by change control.
Inspection Findings ;
1 As discussed previously in Stokes Item 3.9 (Section E.3 of this j report) and in response to issue 1 above, GE does not require NEDO j documents to be included in a formal design change system. l l
95
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS j RAN JOSE. CALIFORNI A 1 REPORT INSPECTION NO.: 99900403/87-03 RESULTS: PAGE 20 of 27 Issue 3 Because of issues 1 and 2 above, NEDO documents do not satisfy docu-ment requirements for design control and change control of 10 CFR 50 Appendix B.
Inspection Findings Mr. Milam's statement was correct. GE classifies NEDO type docunents as licensing related only and are not used for design purposes.
As discussed in the response to Issue 1 above, the design requirements I requiring design and change control under 10 CFR 50 Appendix B are included in design documents that are issued and revised in full compliance with criterion III of Appendix B.
Issue 4 Except for very rare instances, NED0 documents do not appear in the EIS. Thus, the revision status is difficult to establish.
Inspection Findings Since NED0s are not formal design documents, they need not appear in EIS. The revision status of NE00s is available through either the NEDO library or the engineer responsible for a given NEDO.
Issue 5 NEDO documents do nc; appear on project MPLs. Thus, it is difficult to establish project application.
Inspection Findings Since NED0 documents are not formal design documents, inclusion in the projecc MPL is not necessary or appropriate. If project applica-tion is of interest, each FSAR includes a listing of all NED0s referenced.
With regard to Items 4 and 5 above, it should be noted that the FSAR is included in both the MPL and EIS and therefore hE00s referenced in the FSAR are tied to both systems. Considering this explanation, Mr. Milam's concerns about the appropriate use of NEDO documents was not substantiated, and this issue is considered closed.
96
ORGANIZAVION: GENERAL ELECTRIC COMPANY hUCLEAR ENERGY BUSINESS OPERATIONS RAN JOSE. CALIFORNIA REPORT INSPECTION NO.: 99900403/87-03 RESULTS: PAGE 21 of 27
- 5. Subcontractor Performance Stokes Report Section 4.27 - On October 26, 1981, Mr. hi nam received work packages for 821 FCD update for Grand Gulf, Perry and River Bend. Two Grand Gulf device lists were unverified and not so noted on OMTEC Documentation.
Inspection findings - GE stated that part of Mr. Milam's job when interfacing with subcontractor personnel was to review inputs received from the subcontractor to confirm their accuracy and acceptability.
It appears Mr. Milam, in identifying certain inaccuracies in the subcontractors input, was properly performing his assigned work task. In order to verify that no unverified documents exist today for Grand Gulf, Perry and River Bend, the NRC inspectors reviewed several B21 series Functional Control Diagrams (FCDs) to verify their completion status. During the period in question, the following FCDs and associated Device Lists (DLs) were reviewed.
Project FCD # DL #
River Bend B2T-7570 82ET4TSAA B21-3050 828E443AA B21-3060 851E225AA Perry No Information available Grand Gulf B21-3090 828E445BA B21-3060 828E444BA A review of all affected Deferred Verification Status Change Notices (DVSCNs) associated with the opening and closing of each deferred verification was performed by the inspectors and observed to be complete. One example reviewed ECN NJ14507, dated September 12, 1980, for Document DL 828E444BA)(, prepared by OMTEC (Formerly Jet Consultants Inc.) demonstrated independent review and approval by GE staff personnel including the notation Deferred Design Verification" in the verification statee nt block of the ECN. A further review indicated OMTEC as being an approved vendor and so noted on the GE Approved Vendor List. It was also verified that OMTEC had a GE apprcved QA program as early 1979, with regular GE audits conducted as part of GE's Vendor Surveillance Program. The NRC inspectors verified that all deferred verifications reviewed for this ECN were subsequently cleared prior to plant start up as required by GE procedures. As a result, this allegation was not substantiated and is considered closed.
97
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS RAN 110SE. CALIFORNI A REPORT INSPECTION N0.: 99900403/87-03 RESVLTS: PAGE 22 of 27
- 6. Reactor Mode Switch h2 During this inspection Potentially Reportable Condition (PRC) files 1
80-57 and 83-22, as well as related concerns involving the Rundel-Gould reactor mode switch were reviewed. PRC 80-57 included a June 13, 1980 letter documenting the concerns of the Problem Review Board (PRB) and solutions to identified problems as well as a November 17, 1980 letter which documented the follow-up meeting of the PRB and its coments concerning the reactor mode switch. The alleger, Mr. Sam Milam, was a member of both PRB meetings. PRC 80-57 dealt primarily with potential deficiencies caused during the panel mounting of the reactor mode switch which has previously been discussed as part of NRC Inspection Report Nos. 99900403/86-01,and 87-01.
PRC 80-57 The concerns raised in PRC 80-57 were dispositioned by GE as not affecting the safe operation of the switch, but did result in product improvements for panel mounting. The most significant concern involved disassembly and subsequent reassembly of the ,
reactor mode switch neck for attachment to the switch isolation '
housing. This operation had the potential for positioning the switch out of phase. However, because this could only be caused by a deliberate act, it would be easily recognized prior to and during testing following panel assembly and field installation. This potential problem would still not disable the function of the switch or actual reactor scrams. GE modified the node switch to isolation housing attachments to prevent assembly errors and by doing so affected the seismic response characteristic of the switch. There- ,
fore, at a minimum, a documented analysis should have been performed to extend the original seismic testing (performea in 1980) to the current design as earlier stipulated in the November 17, 1980 letter documenting the follow-up meeting of the PRB, Since GE could not produce the seismic analysis during the inspection, the inspectors concluded that the switches provided by GE did not have full seismic qualification covering the modifications made. During the inspection, the NRC inspectors brought this to the attention of GE, and '
subsequently GE provided the inspectors a Memo of Record dated I August 4, 1987 which addressed the seismic capability of the changes '
made to the mode switch. This memo concluded that the reactor mode !
switch assembly in the control room bench board is seismically l qualified as documented in the original seismic qualification 1
1 l
98
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS RAN .109F. CAI IFORNI A REPORT INSPECTION NO.: 99900403/87-03 RESULTS: PAGE 23 of 27 reports for the switch assembly and the prototype bench board. As a result, honconformance (87-03-01) was identified during this part of the inspection for GE's failure to perform this analysis, per GE E0P 42-6.00, as reconnended in 1980 by the GE Problem Review Board.
The most significant inconsistencies noted by the inspectors concerned a December 5, 1900 letter from Hendrix/ Grim /Reigel (GE) to W. Barrentine (GE) which stated that, "none of the problems are of a safety concern and our evaluation is that this is not a reportable condition." It was also noted that the letter did not reference the November 17, 1980, PRB letter and also did not address any of the recommendations made during that meeting. A May 27, 1981, letter from G. Sherwood (GE) to D. Ferguson (GE) requested documentation for the seismic analysis which was required per the November 17, 1980 PRB letter. In a letter dated July 20, 1981 W. Barrentine and D. Ferguson answered the Sherwood request by stating that the December 5,1980 letter documents the engineering conclusion of the mode switch concerns that no safety hazard exists and that existing reactor mode switch assemblies do not have to be replaced. In addition, no additional seismic test data is required. This statement was in direct contradiction to the November 17, 1980 PRB letter which never was addressed or referred to in the December 5, 1980 letter.
The final disposition of PRC 80-57 was made in an October 16, 1981 letter written by G. Sherwood of GE Safety and Licensing which concluded that the condition described did not constitute a reportable condition to the NRC under the provisicns of 10 CFR '
Part 21. The product modifications and irnprovements as specified by the PRB on November 17, 1980 were irnplemented per ECNs NJ 21792 and NJ 21793, both dated December 15, 1980, for Susquehanna 1/2 Hope Creek 1/2, Nine Mile Point 2, Perry 1/2, Grand Gulf 1/2, Clinton 1, Liebstadt, Kuosheng 1/2, and Cofrentes.
l The chronology of documentation contained in PRC 80-57, as reviewed l by the inspector, is as follows:
)
- 1. May 28, 1980 - memorandum from D. Taylor (GE) and S. Milam (GE) l identifying potential reactor mode switch problems.
- 2. May 29, 1980 - mcmorandum to W. Barrentine (GE Product Design Engireering) from Quality Systems elevating concerns identified in Taylor /Milam letter.
)
99
OROANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS RAN JOSE. CALIFORNIA REPORT INSPECTION RESULTS: PAGE 24 of 27 N0.: 99900403/87-03
- 3. June 2,1980 - memorandum from W. Barrentine/D. Ferguson (QA NC &
ID Manager) to G. Sherwood, Safety and Licensing requesting their evaluation of reactor mode switch problems.
- 4. June 13, 1980 - PRB meets to discuss problems and develop solutions for the reactor mode switch. Additionally, GE stated that replacement of previously shipped switches should be considered.
- 5. November 17, 1980 - PRB meets again to discuss reactor mode switch modifications and additional actions including recommenda-tion for seismic analysis to determine effects of change. No reconwendation for replacement of previously shipped switches. ,
- 6. Decen.ber 5,1980 - memorandum from Hendrix/ Grim /Reigel (GE Engineering) to W. Barrentine documenting PRB evaluation input.
Memo states that none of the problems from the June 10, 1980 PRB are of a safety concern and all of the proposed solutions '
are being completed except #1.
- 7. May 27, 1981 - memorandum from G. Sherwood to D. Ferguscn requesting infortnation on mode switch replacements and documenta-tion of the seismic analysis by engineering, i
- 8. July 20, 1981 - memorandum to G. Sherwood from D. Ferguson l stating that no change-outs are needed and neither is a seismic analysis because the deficiencies and changes were insignificant.
- 9. September 4, 1981 - memorandum to G. Sherwood stating that potential problems with the reactor mode switch do not affect the safety functions and Product Design Engineering's opinien !
is that this condition is not reportable under 10 CFR 21. !
- 10. October 16, 1981 - memorandum from G. Sherwood closes out PRC i i 80-57 stating that the condition is not reportable under l 10 CFR 21, 1
PRC 83-22 PRC 83-22 addressed the reportability and significance of the
' reactor mode switch design and manufacturing deficiencies identified at Susquehanna Unit 1 before initial startup. While engaging the reactor mode switch, certain scram signals were disabled in positions in which the scrats were required to be operable. As a l
i 100 l
l
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS SAM JOSF. CALIFORNIA REPORT INSPECTION NO.: 99900403/67-03 RESULTS: PAGE 25 of 27 result, GE initiated action imediately to correct the deficiencies with notification made of the problem to the NRC by Susquehanna.
This action initiated NRC IE Information Notice 83-42.
The NRC inspectors verified the issuance of Field Disposition Instructions (FDI) and Field Deviation Disposition Request (FDDR) notifying affected licensee's to replace the original mode switch with the new design. The plants notified were. River Bend 1. Clinton 1 Susquehanna 1/2, Grand Gulf 1, Perry 1, and Hope Creek 1.
I Additional Questions Concerning the Reactor Mode Switch included in Congressman Markey's April 10, 1987 letter to NRC Chairman Lando Zech, were questions concerning aspects of the GE reactor mode switch. These questions are presented along with the NRC findings.
Question 1 Did the redesign of the mode switch include seismic testing and actual field installation testing?
Inspection Findings - The mode switch mounting arrangement modifica-tions and product improvements did not include any new documented seismic testing outside of what was performed for the original design. Field testing verifying continuity and contact pickup for each mode was performed by both GE and the licensees.
Question 2 Were the original causes of the misalignment deficiencies identified?
What were they? .
Inspection Findings - The alleged misalignments identified in PRC-80-57 involved the disassembly and improper reassembly of the early Rundel-Gould switch neck for attachment to the isolation housing. The inspectors observed that any incorrect disassembly would be irrrnediately identified during initial panel assembly and testing and therefore any rrode switch misalignrrents would be imediately detected.
t 101 l
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS SAN JOSE. CALI 0RNIA _ _ _ _
REPORT INSPECTION NO.: 99900403/87-03 RESULTS: PAGE 26 of 27 Question 3 What reinstallation procedures were prepared to assure that the initial misalignment problems do not occur when the switches are replaced? How frequently are reactor mode switches replaced?
Inspection Findings - Any misalignment would be imediately determined in the GE checkout and the licensee preoperational tests prior to fuel load. The misalignment is not a credible problem for any near term or currently operating BWR plant because these plants contain the 1983 installed code switch with the improved mounting arrangements which prevent this from occurring. All mode switches in-place today are expected to operate for the 40 year plant life.
Question 4 Were plant owners who may have to engage in corrective action on-site made aware that during replacement of mode switches problem could occur with the switch contacts that cause them again to be misaligned unless specific corrective action procedures were followed? If yes, please provide documentation of which plant owners were identified and when. If no, why not?
Inspection Findings - For current operating plants this is not an occurrence that is likely to happen based on the response to Item 3 above.
Question 5 Was the mounting for each new switch installed by GE properly qualified for compatibility with the new switch? What is the basis for this conclusion?
Inspection Findings - The actual panel mounting of the mode switch has not changed. The mounting improvements concern only the switch connection to the isolation can assembly which is performed by GE prior to shipment to the site.
Question 6 What other isolation systems exist as backup to the mode switch?
102 L
ORGAN 1ZATION: GENERAL ELECTRfC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS SAN JOSF. CALI 0RNIA _
REPORT INSPECTION NO.: 99900403/87-03 RESULTS:
lPAGE27of27 l Inspection Findings - The inspectors interpreted "isolation systems" to mean "scram signals." Typically the following scram signals are not affected by the mode switch operation, and therefore can be considered as a backup. In addition, these signals would not become disabled should problems develop during operation of the switch,
- a. Turbine stop valve closure
- b. Control valve fast closure
- c. Scram discharge volume high level
- d. Containment high pressure
- e. Vessel high pressure l f. Vessel low level
- g. Main steam line high radiation Question 7 Pending completion of necessary corrective action on the mode switches, what additional tests or inspections has the NRC conducted to assure the backup will provide accurate infonnation to operators?
Inspection Findings - No corrective action on the reactor mode switch is required by the NRC. The current surveillances, annunciators, and instrumentation available to plant operators would detect any reactor mode switch malfunctions.
As a result of this review of the reactor mode switch concerns, this item is considered closed.
- 7. Subcontractor Signature Concerns Congressman Edward Markey indicated concerns over possible improprieties of permitting subcontractor personnel to sign GE drawings produced by the subcontracter. During the inspection the inspectors reviewed several ECNs and connection diagrams produced by OMTEC (formerly JET Consultants, Inc.), a GE subcontractor during the 1978 period, to determine if OMTEC personnel had signed for GE entployees. ECNs NJ04925 NJ04926, and NJ09992 were examined in addition to connection diagrams 807E480AD, and 807E371AB. These documents were noted as being originated by an OMTEC employee, and in all cases the review and approvals eere performed by GE staff personnel.
As a result of this review, no exan.ple could be found to support the Mr. Markey's concerns. This item is considered closed.
. 103
ORGANIZATZON: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS SAN JOSE, CALIFORNIA 95125 REPORT INSPECTION INSPECTION NO.: 99900403/87-04 DATE: 9/15-16/87 ON-SITE HOURS: 36 CORRESPONDENCE ADDRESS: General Electric Company Nuclear Energy Business Operations ATTN: Mr. N. L. Felmus. Vice President ,
and General Manager 175 Curtner Avenue San Jose, California 95125 ORGANIZATIONAL CONTACT: Mr. James Fox, Senior Program Manager, QA TELEPHONE NUMBER: 408-925-6195 NUCLEAR INDUSTRY ACTIVITY: Design and manufacture of BWR-NSSSs and related systems, components and services. Primary current activity is supply of spare and replacement parts and services.
l 1
ASSIGNED INSPECTOR: !) .m bh #'
.-r_ r. -. - /' >N?
Walter P. Haass, Special Projects Inspection Date Section (SPIS)
OTHERINSPECTOR(S): Robert L. Pettis, Jr. (SPIS)
APPROVED BY: s-fo fl-17 -y/ l Uldis Potapovs, Chief. SPIS, Vendor Inspection Branch Date INSPECTION BASES AND SCOPE:
A. BASES: 10 CFR Part 50 Appendix B, and 10 CFR Part 21 B. SCOPE: This inspection was performed to determine General Electric's ciinTdrmance to the requirements of 10CFR50, Appendix B, and 10CFR Part 21 in the performance of contractual work involving training of nuclear plant personnel (other than reactor operators). The inspection was prompted in part by an allegation by a former en:ployee regarding deficiencies in the training services areas.
1 PLANT SITE APPLICABILITY: All BWR-type nuclear plants for which General Electric provides training of plant personnel.
105
l ORGANIZATION: GENERAL ELECTRIC COMPANY !
NUCLEAR ENERGY BUSINESS OPERATIONS 9AN 110SF. CAI 1 :0RNI A I
REPORT INSPECTION NO.: 99900403/87-04 RESULTS: PAGE 2 of 8 A. VIOLATIONS:
} There were no violations identified as a result of this inspection.
B. NONCONFORMANCE:
There were no nonconformances identified as a result of this inspection.
C. UNRESOLVED ITEMS:
There were no unresolved items identified as a result of this inspection.
D. STATU.c, OF PREVIOUS INSPECTION FINDINGS:
This is the first NRC inspection of the vendor's training activity.
E. OTHER FINDINGS AND COMMENTS:
- 1. Training Services Offered at San Jose General Electric's Maintenance and Technical Training Services organization in San Jose offers training courses in maintenance, angineer ng, instrumentation and control, and refueling floor i
ectivitiec with a total instructor staffing level of 16. The training cour.es address system and components supplied to utilities by General E10ctric as an NSSS vendor. The courses are offered to utdities c;,erating BWRs for training of their nuclear plant personnel (other than reactor operators) either at the plant site or in San Jose. Appropriate hardware training aids and facilities are provided at either location.
General Electric also offers other courses at training centers located at Shorewood, Illinois; Vallecitos Nuclear Center; and Morris, Illinois as well as at customer sites.
The inspectors toured the training facilities at San Jose. The facilities included classrooms; a simulated refueling floor including a reactor vessel, cranes, BWR internals, and refueling platform; maintenance areas for jet pumps, stud tensioner, control rod drives, main steam isolation valves, standby liquid control system explosive valves, safety / relief valves, recirculation pump seals, and reactor water cleanup pumps; I&C equipment including a neutron rnonitoring system; and 1&C maintenance areas including source range monitoring /
intermediate range monitoring detector drive, and traversing incore probe system.
106
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS l RAN JORF. CALI:0RNIA l
REPORT INSPECTION NO.: 99900403/87-04 RESULTS: PAGE 3 of 8
- 2. Quality Assurance General Electric indicated that appropriate QA controls from their NRC approved topical report, NE00-11209 (QA program description),
have been applied to the training services activity even though no aspects of this activity were considered to be safety-related up until mid-to-late 1986. In mid-1986, a purchase order was received from utility licensee (LILCO) for safety-related training. This prompted action to consider and develop more specific requirements and safety-related QA for training activities.
By December 1986, General Electric had established some safety-
, related requirements for training services and had developed initial I
procedures and pertinent forms for the implementation of QA controls.
The controls established requirements for proposal authorizations, software files, instructor qualifications, and the anticipated need for purchaser audits. Sign-off forms were made available for course ',
materials. '
In January 1987, General Electric initiated the categorization of training courses into safety-related and non-safety-related groups.
The basis for this categurization was the Master Parts List (MPL); <
if the training course addressed a safety-related item from the MPL, then it in turn was categorized as safety-related. '
General Electric classifies all hardware training aids (i.e.,
simulators) as non-safety-related because such items do not directly I perform a safety function. A procedure to control the quality of such training aids was issued in January 1987.
In March 1987, a set of forms to document the quhlity of the various training course materials and a more comprehensive list of sefety-l related courses were issued. The forms attest to the quality of text training material, lesson plans, test material, course reference material, and instructor qualifications.
In September 1987, Nuclear Training Services (NTS) management issued a memorandum that announced the initiation of development of a quality assurance program for the NTS business area. This resulted apparently from a recent internal audit. The memorandum continued the implementation of certain QA requirements previously promulgated and instituted other new guidelines for immediate implementation.
The memorandum directed that the new NTS QA program be in place by December 31, 1987 for implementation.
107
ORGANIZAT10N: GENERAL ELECTRIC C0MPANY l l
NUCLEAR ENERGY BUSINESS OPERATIONS RAN J0 W. Cati 70RNTA REPORT INSPECTION N0.: 93900403/87-04 RESULTS: PAGE 4 of 8 Based on the above, it is concluded that General Electric is actively pursuing the development of a formalized QA program for the San Jose training services activity that is intended to satisfy NRC require-ments for safety-related training. The inspectors found the approach to safety-related QA and the schedule objective for develop-ment of the program to be acceptable subject to later confirma 4 ry review.
- 3. 10CFR Part 21 With the NRC's issuance of Information Notice 85-101, "Applicability of 10CFR21 to Consulting Firms Providing Training", dated December 31, 1985, Gener.11 Electric NTS recognized the need to implement the requirements of Part 21 in their training services business area.
In December 1986, a memorandum was issued to NTS personnel directing the implementation of Part 21 for identified nonconformances, errors, and defects in training course text material, proposalt and instructor qualifications. It invoked NEB 0 Policy and Procedures 70-42, previously available for the manufacturing of basic components including related design, procurement and test activities, for the training services activity. While the policy was applied to training, it did not result in any potentially reportable conditions.
It was noted that General Electric issues annual reminders to their personnel regarding the need for renewed familiarity with Part 21 requirements and for reporting of identified defects and non-compliances in training software.
The inspectors concluded that General Electric had adequately comitted to the implementation of Part 21 in the training services a rea .
- 4. Purchase Orders The inspectors reviewed ten purchase orders (P0s) from utilities for procurement of training services. These P0s were accepted by General Electric during the period of April 21, 1986 to August 17, 1987. The earlier P0s included no requirements for the implementation of safety-related QA or 10CFR Part 21 while the later ones tended to include both. This is consistent with General Electric's, and the utility licensees', increasing comitment to safety-related QA and compliance to 10 CFR Part 21 for the training service area.
108
ORGANIZAT10N: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS 1 SAN JOSE. CALIFORNIA l REPORT INSPECTION NO.:- 99900403/87-04 RESULTS: PAGE 5 of 8
- 5. Tra hing Cocuments Several folders of training documents for courses delivered to utilitfes were reviewed to determine the degree of conformance to management directives on safety-related QA. It was observed that in several folders, the required forms were not always present or comrneted as directed. The inspectors also noted course critiques
! offered by students that identified incorrect instructions, and a lack of consistency between the training aid and the actual plant hardware. General Electric stated that many of the training courses present the general concepts of operation of a component or system rather than the specifics of the plant equipment, and therefore might even employ equipment from another plant or BWR series. The i inspectors suggested that this is an area that needs to be clarified and that, if a concepts course is presented, a portion of the class time should be devoted to explaining the relationship between the concepts and the plant specific hardware. The need for concepts or plant-specific information should be clarified in the P0.
The inspectors found the training documents to be in a state of transition regarding the implementation of safety-related QA.
6 Instructor Training / Certification The inspectors reviewed several General Electric programs for the training of instructors. These included a workshop for classroom instructor techniques, principles for development of training systems, and a program for the qualification of instructors. Instructor certification records were reviewed; these records include educa-tional background, identification of courses qualified to teach, instructional capability certification, and the means by which the qualification requirements are satisfied (i.e. , job performance reviews, NTS basic instructor course, or other formal courses).
It was concluded that the program for training and certification of
, inst,ructors was adequate.
- 7. Audits !
l General Electric had performed annual internal audits of its training I 4
services area beginning in 1980 relative to commitments contained !
in the NRC accepted QA topical report. However, only three, in 1981, 1983, rnd 1987, addressed the San Jose training services activity.
No significant deficiencies were identified in the 1987 audit report. l 109 yy ,-
~W
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS 9AN ,109F. CAIIFORNIA REPORT INSPECTION NO.: 99900403/87-04 RESULTS: PAGE 6 of 8 No audits of the GE/NTS activities were performed by utility customers. However, initiation of outside auditing is anticipated to occur in the near future as more utilities include requirements for safety-related QA and 10CFR Part 21 in their P0s.
The inspectors concluded that internal auditing of the General Electric's training services activities is expected to increase as the new safety-related QA program is developed and implemented.
Auditing by utility customers is also anticipated to increase.
- 8. INP0 Guidelines The Institute of Nuclear Power Operations (INP0) has established ,
procedures, objectives, and criteria for the production of well- !
qualified and competent personnel to operate nuclear power plants.
INP0 is in the process of accrediting the nuclear utilities' plant personnel under this program which is described in INP0 85-002, Rev 1, "The Accreditation of Training on the Nuclear Power Industry" dated September 1985. Areas of training accreditation also offered by GE/NTS-San Jose include instrumentation and control, electrical maintenance, mechanical maintenance, radiation protection, and chemistry. In reviewing utility P0s and General Electric's training documentation, the inspectors noted some recognition of the need to specify and satisfy the INP0 objectives and criteria. General Electric indicated that progransnatic changes are planned for incor-portation into the developing training program controls that will ultimately assure conformance of General Electric's offerings to the INP0 objectives and criteria. The inspectors concluded that this approach is satisfactory subject to further review in subsequent inspections.
- 9. _I_n_terview of Instructor The inspectors briefly interviewed one of the NTS instructors who wasinvoivingwithNuclearMeasurementsAnalysisandControls(NUMAC) tra i ni r.g . The instructor indicated the following:
the training courses offered are generally conceptual I or generic in nature rather than plant specific. The inspectors believe this needs to be recognized and emphasized by the instructor. i l
1 i
110
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS RAN .1n9F_ CAII 0RNIA REPORT INSPECTION N0.: 99900403/87-04 RESULTS: PAGE 7 of 8 the instructors generally have an adequate amount of time to prepare for up~ coming courses.
the additional paperwork to satisfy safety-related QA requirements can be prepared in 1 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
hardware training aids are generally functional, and it is useful if the instructor can correct problems as they arise.
1 there was a lack of familiarity by the instructor inter-viewed with the provisions for implementation of 10CFR Part 21.
- 10. Conclusions As a result of this inspection, it was concluded that General Electric's program for providing training services to utility-licensees is currently in a state of transition in which the quality assurance controls are being formalized and revised to conform better to safety-related requirements. This action was prompted by the NRC's issuance of Information Notice 85-101 (dated December 31, 1985) and the receipt of a utility purchase order for safety-related training in mid-1986. Until that time frame, General Electric, and their utility customers, did not consider training services to be safety-related although it was stated by General Electric that the appropriate provisions of their QA topical report, NED0-11209, "Quality Assurance Program," were always applied. In December 1986.
General Electric issued directions to its employees for implementa-tion of 10 CFR Part 21 in the training services area. The inspec-tion substantiated that the allegation regarding deficiencies in the training services area were in part valid. General Electric has comitted to the establishment of more formalized safety-related quality assurance programatic controls for the training services area by the end of 1987.
F. PERSONS CONTACTED:
- # James Fox, Senior Program Manager, QA
- # Ted Krishisky, Senior Program Manager, NTS
- # John A. Berry, Senior Program Manager, NTS
- # Barton A. Smith, Counsel, Legal
- # Charles Lanham, Acting Manager, M&T Training William Chittenden, Program Manager, M&T Training 111
ORGANIZATION: GENERAL ELECTRIC COMPANY NUCLEAR ENERGY BUSINESS OPERATIONS SAN JOSE. Call:0RNIA REPORT INSPECTION NO.: 99900403/87-04 RESULTS: PAGE 8 of 8
- Caroline Smith, Senior Instructor, Eng'g Training
- # Joe M. Case, System Manager, QA
- # Ivan F. Stuart, Manager, QA
- # George Stramback, Safety Evaluations Program Manager, Licensing
- James C. Larrew, Nuclear Services QA Manager
- Entrance meeting # Exit meeting I
l l
1 112
ORGANIZATION: GENERAL ELECTRIC COMPANY SAN JOSE, CALIFORNIA REPORT INSPECTION .
NSPECTION NO.: 99900403/87-05 DATES: 10/20-21/87 UN-SITE HOURS: 56 CORRESPONDENCE ADDRESS: General Electric Company Nuclear Energy Business Operations ATTN: Mr. N. L. Felmus, Vice President and General Manager 175 Curtner Avenue San Jose, California 95125 ORGANIZATIONAL CONTACT: Mr. James Fox, Senior Program Manager, QA TELEPHONE NUMBER: 408-925-6195 l NUCLEAR INDUSTRY ACTIVITY: Design and manufacture of BWR-NSSSs and related i systems, components and services. Primary current activity is supply of spare and replacement parts and services.
ASSIGNED INSPECTOR: ! c .-
. u .s . C' *#7 Falter P. Haass, Special Projects Inspection Date Section (SPIS)
OTHER INSPECTOR (S): P. T. Kuo, Chief, SCIS, EMEB P. Y. Chen, SCIS, EMEB V. P. rini, Consultant, Engineering Analysis Services APPROVED BY: 21tM l 2-2A D Uldis Potapovs, Chief, BPIS, Vendor Inspection Branch Dati INSPECTION PASES AND SCOPE:
A. BASES: 10 CFR Part 50, Appendix B, and 10 LFR Part 21.
B. SCOPE: This inspection was performed primarily to review and gather seismic qualification data for safety-related parts and components supplied by General Electric, to review the method for similarity analysis, and to review the process whereby purchase orders for such items are fulfilled.
PLANT SITE APPLICABILITY: All nuclear power plants for which General Electric provides replacement parts and components.
113
ORGANIZATION: GENERAL ELECTRIC COMPANY SAN JOSE, CALIFORNIA REPORT INSPECTION N0.: 99900403/87-05 RESULTS: PAGE 2 of 4 A. VIOLATIONS:
There were no violations identified as a result of this inspection.
B. NONCONFORMANCES:
There were no nonconformances identified as a result of this inspection.
C. UNRESOLVED ITEMS:
There were no unresolved items identified as a result of this inspection.
D. STATUS OF PREVIOUS INSPECTION FINDINGS:
There were no previous inspection findings in the area of seismic qualifi-cation of equipment.
E. OTHER FIhDINGS AND COMMENTS:
- 1. Seismic Gualification Data The inspectors reviewed and obtained seismic qualification data on several components manufactured and/or supplied by General Electric for nuclear power plants including racks, local panels, transmitters, pumps, metal clad switchgear and relays. The ir/ormation could be useful in the staff's resolution of unresolved safety issue A-46.
The purpose for gathering the seismic qualification data is to review the adequacy of the method of seismically qualifying parts and components by similiarity analysis and to compare the seismic capa-bility of these items to the seismic requirements for particular nuclear plant sites. Only very preliminary assessments could be made during the inspection. More detailed analyses and evaluations will be performed later at the NRC staff offices. Therefore, no conclusions have as yet been drawn.
It was noted that General Electric by test and/or analysis has esta- :
blished a minimum seismic capability for components it supplies. I Preliminary assessment indicates that the method of qualification by similarity requires detailed justification. We have found, for l instance, that relays and transmitters having the same model type but with different serial numbers or different casings exhibit different levels of seismic capability.
114
ORGANIZATION: GENERAL ELECTRIC COMPANY SAN JOSE, CALIFORNZA REPORT INSPECTION N0.: 99900403/87-05 RESULTS: PAGE 3 of 4
- 2. Guidelines for Supplying Qualified Components General Electric has established guidelines for completing purchase orders for components relative to seismic qualification requirements.
It was indicated that utilities generally do not specify the seismic requirements for components in their purchase orders.
These guidelines include the following:
For safety-related components no longer available to the original design, General Electric reevaluates the replacement component to determine the effect of modifications on the seismic capability relative to the original design. The inspectors reviewed records of several similarity analyses.
For components that are safety-related and the purchase order does not specify seismic qualification requirements, General Electric supplies a product sunnary sheet that identifies the seismic capability. It is then the utility purchaser's respon-sibility to assure proper use of the component.
For replacement of components that were originally provided by General Electric, General Electric can identify the component's seismic qualifications by locating the item on the Master Parts List (MPL) which in turn is tied to design documents including seismic requirements. This information is provided to the purchaser.
For comconents not originally provided by General Electric (e.g., for a PWR-type NSSS), General Electric provides an l equivalent component and sp3cifies the seismic capability, j lt is the utility's responsibility to assure proper application l of the component.
NEB 0-San Jose is the source for all General Electric products supplied to utilities with the exception of GE-Malvern which supplies safety-related relays and switches. I F. PERSONS CONTACTED: l
- Noel Shirley, Sr. Licensing Engineer
- James Fox, Sr. Program Manager, QA
- George Stramback, Program Manager, Licensing
- Robert W. Clemens, Sr. Program Manager 115
ORGANIZATION: GENERAL ELECTRIC COMPANY SAN JOSE, CALIFORNIA REPORT INSPECTION N0.: 99900403/87-05 RESULTS: PAGE 4 of 4
- Roger L. Fisher, Principal Engineer fJay L. Murray, QA Auditing Manager
- Entrance Meeting
- Exit Meeting 116
ORGAN 1ZATION: HUB INCORPORATED TUCKER, GEORGIA REPORT INSPECTION LNSPECTION N0.: 99900866/87-01 DATE: 11/16-20/87 )N-SITE HOURS: 31 CORRESPONDENCE ADDRESS: HUB Incorporated l
, ATTN: Mr. B. H. Camp l Chairman of the Board
, c146 Flintstone Drive Tucker, Georgia 30084 ORGANIZATIONAL CONTACT: Mr. E. Thornton, Manager, Quality Assurance TELEPHONE NUMBER: (404)934-3101 NUCLEAR INDUSTRY ACTIVITY: Approximately 85 percent of the Energy and Process Division of HUB Incorporated sales of pipe, valves, fittings, structural steel and fasteners are made to the commercial nuclear industry.
- n _ g ASSIGNED INSPECTOR: -
4 W)7 [
R. L. Cilimberg,'Prg ram Development and Reactive Date Inspection SecticV. (PDRIS)
OTHER INSPECTOR (S): None APPROVED BY: .
Md( / U -E
, kar, Acting b[ PDRIS, Vendor Inspection Date l
INSPECTION BASES AND SCOPE:
A. BASES: 10 CFR 21 and 10 CFR 50, Appendix B.
B. S_ COPE: This inspection was made to follow-up an allegation pertaining to marking pipe with incorrect heat numbers and to review corrective action on previous inspection findings.
PLANT SITE APPLICABILITY: Vogtle 1/2 (50-424/425).
117
-. . - _ ~ . - . -- , -
HUB INCORPORATED i ORGANIZATION:
TUCKER, GEORGIA I REPORT INSPECTION N0.: 99900866/87-01 RESULTS: PAGE 2 of 8 A. VIOLATIONS:
None B. NONCONFORPANCES:
Contrary to Criterion VIII of Appendix B to 10 CFR 50, heat number 60744 and heat number 62879 were marked on the same pipe which results in loss of traceability if the incorrect heat number, 62879, is used to locate records. (87-01-01)
C. UNRESOLVED ITEMS:
(0 pen) Unresolved An allegation was received by the NRC which alleged that the alleger saw f a warehouseman write a false heat number on a pipe without a heat number, i
The false or incorrect heat number was alleged to have been selected at random from a test report and written on the pipe with a Dalo. The NRC inspector partly substantiated the allegation in that an incorrect / false heat number, 62879, had been marked on a pipe as determined during the inspection. Although HUB took corrective action on the pipe containing the incorrect heat number the allegation will remain unresolved until HUB has responded tn Nenconformance 87-01-01 and tne possibility that incorrect heat numbers , marked on other material in storage et HUB.
Specificalb ,will not be closed until HUB has implemented appro-priate corr . ion.
D. STATUS OF PREVIOUS INSPECTION FINDINGS:
- 1. (Closed) Violation (84-01-01)
Contrary to Section 21.21 of 10 CFR Part 21, HUB procedures did not include an evaluation process. The procedures only covered the particular customer purchase order on which the deficiency was found.
There were no provisions to review material in stock or perform a file search for other customers who might have received the same material.
A review of QCP 16. "Reporting of Defects and Noncompliarice (10 CFR Part 21)," Revision 0, dated April 9, 1986 determined that this HUB procedure contains an evaluation process which includes provisions to review material in stock and notification of customers who might have received defective material.
118
ORGANIZATION: HUB INCORPORATED TUCKER, GEORGIA REPORT INSPECTION N0.: 99900866/87-01 RESULTS: PAGE 3 of 8
- 2. (Closed) Violation (84-01-02)
Contrary to Section 21.31 of 10 CFR Part 21, material was furnished by HUB on some purchase orders for which the applicability of 10 CFR Part 21 was a specific requirement, without similarly specifying its l
applicability in the HUB procurement documents for these items. In l addition, neither the Quality Systems Manual (QSM) nor any other l
procedures require that the Part 21 applicability statement be applied to purchase orders or that anyone review the purchase orders to assure that it is there.
The inspector determined that stamps are being used on nuclear purchase orders (P0) which contain the word "NUCLEAR" and "10 CFR 21 APPLIES."Section IV of the QSM, Revision 9, dated February 13, 1987, requires that P0s be stamped by the QA Manager.
- 3. (Closed) Nonconformance (84-01-03)
Contrary to Criterion IV Appendix B to 10 CFR 50, NCA-1140(b),
NCA-3867.4.b, and paragraph 5.3.2 of the Quality Systems Manual (QSM),
HUB is not imposing on their suppliers the requirements imposed on HUB by their customers.
This nonconformance is withdrawn based on discussion with ASME and the change to NCA-3867.6 clarifying the code requirements. HUB is imposing on their suppliers the requirements imposed on HUB by their l customers. The date of the Manufacturer's program stated on the ,
Certified Material Test Report (CMTR) together with the Supplier's !
audit of the Manufacturer's Program is the documentation that the l program meets the requirements of NCA-3800 provided the Supplier has i performed an adequate audit.
- 4. (Closed) Nonconformance (84-01-04)
Contrary to Criterion VII of Appendix B to 10 CFR 50 and Baltimore Gas and Electric (BG&E) purchase specification SP-242, HUB is not assuring that all purchased material meets the procurement requirements.
HUB assures that purchased material meets the procurement requirements through Section 4.0 of the QSM, Revision 9, that requires that the P0 be issued to an ASME or HUB qualified source. A HUB document certifies that the material supplied was produced under the applicable Quality System Program, date and revision, which was surveyed and qualified by HUB or includes the supplier's Quality System Certificate Number and expiration date.
J 119 l
ORGANIZATION: HUB INCORPORATED TUCKER, GEORGIA REPORT INSPECTION N0.: 99900866/87-01 RESULTS: PAGE 4 of 8
- 5. (Closed) Nonconformance (84-01-05)
Contrary to Criterion X of Appendix B to 10 CFR 50, inspectors were '
required to inspect work which they had performed.
Review of Section 5.0 of the QSM, Revision 9, detemined that work is performed by operations warehouse personnel and inspected by QA inspection personnel.
- 6. (Closed) Nonconformance (84-01-06)
Contrary to Criterion XV of Appendix B to 10 CFR 50, HUB did not have a procedure or criteria for accepting material that was initially dispositioned as nonconforming due to loss of traceability.
In addition, HUB did not have a procedure for handling nonconformance reports (NCRs) received from customers.
Review of Section 9 of the QSM, Revision 9, determined that measures are provided to obtain documentary evidence from the vendor to alleviate questions of material integrity such as loss of traceability.
A procedure for handling NCRs from customers was transmitted by memos to the HUB staff dated August 24, 1984 and January 15, 1987, with an enclosed form AR Revision 1, "CUSTOMER REQUEST FOR ACTION."
- 7. (Closed) Nonconformance (84-01-07)
Contrary to Criterion XVI of Appendix B to 10 CFR 50, HUB procedures do not require corrective action for internal nonconformances, only for nonconformances found during audits of suppliers programs.
This nonconformance was withdrawn in response to HUB's comments on two forms approved by ASME which are used internally. Internal Discrepancy Report Form #111 has a section titled "Corrective Action Taken" and th( Nonconformance Report Fonn #104 has sections titled "Recommended Disposition" and "Final Disposition," where corrective action is entered.
- 8. (Closed) Nonconformance (84-01-08)
Contrary to Criterion XVII of Appendix B to 10 CFR 50 and paragraph D. of Quality Control Procedure (QCP) #6, HUB was not maintaining records as required.
120
ORGANIZATION: HUB INCORPORATED TUCKER, GEORGIA REPORT INSPECTION N0.: 99900866/87-01 RESULTS: PAGE 5 of 8 The NRC inspector determined by review of records that Hub's corrective action was appropriate for the four incidents of failure to maintain the required records.
- 9. (Closed) Unresolved items (84-01-01 Through 84-01-06)
A review of NCRs written by HUB on material supplied to them with I various marEing/ traceability problems resulted in the following unresolved items. In each of the NCRs listed below traceability had been lost by the time the material had reached HUB. HUB informed the supplier of the marking / traceability problem. In all cases, HUB accepted a letter from the suppliers authorizing HUB to re-mark the material as appropriate corrective action and re-marked the material.
No additional substantiating documentation or explanation of how traceability was re-established was requested or received. HUB has agreed to request additional substantiating documentation from their suppliers. A listing and brief description of the NCRs follows:
URI 84-01-01 NCR #42 25% of 3995' of 2" x H Seamless A106 GrB pipe was received with two different heat numbers stenciled on each piece.
URI 84-01-02 NCR #56 3" SA-106 GR. B pipe, Heat Number on pipe 366195, Heat Number on CMTR 366340.
URI 04-01-03 NCR#62 16 SA 193 GR 87 studs received without any markings or tags.
URI 84-01-04 NCR #94 168' of 3/8" rod and 420' of 1" rod were not marked as a bundle or as individual pieces.
URI 64-01-05 NCR 196 A quantity of nuts were received which were marked A4. The CMTR was for trace code Y13. The response from the supplier was a new CMTR for trace code A4Y13 and instructions to mark the nuts as such.
]
URI 84-01-06 NCR #98 One 4" standard 45' Elbow SA234WPB was received i with beat code JJ72 while the CMTR was for heat code LL72.
Copies of substantiating documentation and explanations were submitted i to the NRC inspector for each of the unresolved items. The inspector i reviewed the submitted information and determined that appropriate corrective action had been implemented. l l
l 121 l
_----.-________l
ORGANIZATION: HUB INCORPORATED i
TUCKER, GEORGIA REPORT INSPECTION N0.: 99900866/87-01 RESULTS: PAGE 6 of 8 E. INSPECTION FINDINGS AND OTHER COMMENTS:
- 1. Entrance and Exit Meetings The NRC staff informed HUB management representatives of the scope of the inspection during the entrance meeting on November 16, 1987, and summarized the inspection findings and observations during the exit meeting on November 20, 1987,
- 2. Allegation An allegation was received by the NRC which alleged that a ware-housenan had a pipe on a fork lift without a heat number. The alleger stated that he saw the warehouseman pull a test report for a 14 to 16 inch diameter pipe and the test report contained four heat numbers.
The warehouseman was alleged to have selected a heat number at random and wrote the heat number on his hand. The alleger stated that he watched the warehouseman jot the number on the pipe with a Dalo.
This marking of an incorrect heat number on a pipe was alleged to have occurred between April and June of 1987. Between October 1986 and January 1987 the alleger saw the warehouseman write a heat number on a six to eight inch diameter A 106 pipe. This heat number was also written on the hand of the warehouseman. The alleger stated that other warehousemen knew of similar allegations and that the Hub QA manager was told about one similar allegation which occurred in late 1986.
The alleger had contacted Georgia Power Corporation (GP) prior to reporting the allegation to the NRC and GP recommended that the alleger call the NRC about his concerns. GP discussed the allegation with HUB who employed a consultant to conduct an investigation of the allegation. This inspection consisted of a thorough review of the consultants interviews with 21 present and former employees of HUB, including the alleger, warehouseman in question, and the QA Manager.
HUB did not believe that the allegation occurred while GP assumed that the allegation did occur and requested that HUB provide GP with a list of recalls of nuclear materials from HUB by HUB's suppliers.
The recall list did not contain any pipe material so HUB and GP concluded that faulty marking would not have safety significance because HUB purchases all pipe material with the documentation required for nuclear application.
The NRC inspector reviewed HUB's documentation of the allegation including letters, sumary reports, and transcripts of the interviews 122 l .
ORGANIZATION: HUB INCORPORATED TUCKER, GEORGIA REPORT INSPECTION N0.: 99900866/87-01 RESULTS: PAGE 7 of 8 of 21 people. This review developed a question as to why HUB manage-rnent waited until August 1987 to act on the report to management from the QA Manager of the incident, which occurred in late 1986. The NRC inspector independently assessed whether the allegation was correct and conducted the inventory described in 3 below. The results of that inventory partly substantiated the allegation in that a pipe was incorrectly marked, but it is not known if the incorrect heat number was obtained from the QA files.
- 3. Pipe Inventory l
The NRC inspector randomly selected an area of outdoor pipe storage which contained large diameter pipe. HUB inventories outdoor storage every six months and creates a log which provides material location by area number on a diagram and lists the material located in each area. The inspector used the log to determine that area 6 was the randomly selected physical location containing the material to be checked. While checking the identification on each pipe with the information on the log, a 17 foot three inch length of 14 inch diameter, schedule 80, A106C alloy pipe was observed to exhibit two heat numbers 60744 and 62879. Heat number 60744 was stencilled on the pipe while heat number 62879 which was marked with a Dalo is considered to be incorrect because 60744 was on the inventory log and was found later to match the information on the CMTR. A red reject tag was placed on the pipe by the Assistant QA Manager and the pipe was taken to the Nonconfoming Material area in accordance with Section IX, "Nonconforming Material Control" of the HUB QAM, Revision 9, dated February 13, 1987. (See nonconformance 87-01-01)
- 4. Document Review CMTRs, P0s, and Inspection Reports were reviewed to detemine what information was contained in the QA files relative to information marked on pipes which was obtained during the pipe inventory discussed in 3 above. Appropriate information was contained on documents covering 18 pieces of pipe. Heat number 62879, which was incorrectly marked on a 14 inch diameter schedule 80 pipe fabricated from A106C alloy, was found on a CMTR for an 8 inch diameter schedule 80 pipe fabricated from A106B alloy. Heat number 60744 was found on a CMTR for 14 inch diameter, schedule 80 pipe fabricated from A106C alloy, which matches the information marked on the pipe with two heat numbers.
The inspector could not develope any rationale for the incorrect heat number 62879 being marked on the 14 inch dianeter pipe.
l 123
ORGANf2ATION: HUB INCORPORATED TUCKER, GEORGIA REPORT INSPECTION 11 0 . : 99900866/87-01 RESULTS: PAGE 8 of 8 F. PERSON" CONTACTED:
- C, Bell
- R. Berry
- R. Buffington
- B. Camp
- G. Chilson
- D. Cummings
- R. Dunster
- G. Finck
- Keith Kennedy
- Kathy Kennedy L. Page M. Smith
- G. Snyder
- E. Thornton !
- K. Thornton I
- Attended exit meeting.
j l
l 1
l l
124
1 l
ORGANIZATION: INGERSOLL-RAND ENGINEERED PUMP DIVlSION oup_i 7 ocogne qg ngy REPORT INSPECTION :NSPECTION NO.: 99900064/87-01 , DATES: 04/1a 1 A/A7 im tfTE ungoe. 37 CORRESPONDENCE ADDRESS: Ingersoll-Rand Engineered Pump Division ATTN: W. J. Schmidt, Vice President Pump Group World Wide Operations 942 Memorial Parkway Phillipsburg, New Jersey 08865 ORGANIZATIONAL CONTACT: M. F. Hagerstrom, Manager QA TELEPHONE NUMBER: 201-M4 7?d1 _
NUCLEAR INDUSTRY ACTIVITY: Since 1983, only component parts for nuclear pumps.
ASSIGNED INSPECTOR: (h\M(%
i.)T. Conway, Progra velopment and Reactive
/O- N-OI Date spection Section RIS)
OTHERINSPECTOR(S): T. Tinkle (consultant}
q APPROVED BY: .
z dw U. C: Stone, Chief, PDT S,
[ /# ON7 endor Inspection Branch Date INSPECTION BASES AND SCOPE:
A. BASES: 10 CFR Part 50, Appendix B and 10 CFR Part 21.
B. SCOPE: The inspection was conducted as a result of a notification of mechanical seal leakage on three low pressure safety injection (LPSI) pumps at the Palo Verde nuclear facility and to perform a programatic evaluation of the implementation of the QA program in the areas of training / qualifications, control of purchased material and services DrOCurement document control. ennten1 nf (enntinnAd nn novt nano)
PLANT SITE APPLICABILITY: Mechanical seal problem - Palo Verde 1/2/3 (50-528/529/530), St. Lucie 1/2(50-335/389), and WNP 3/5(50-508/509).
125
ORGANTZATION: INGERSOLL-RAND ENGINEERED PUMP DIVIS10N PHilIIPSRURG. VEW JERSEY REPORT INSPECTION NO.: 99900064/87-01 RESULTS: PAGE 2 of 16 B. SCOPE: (continued from previous page) measuring and test equipment, audits (internal / external), control of special processes, and reporting of defects.
A. VIOLATIONS:
- 1. Contrary to Section 21.21 of 10 CFR Part 21, Ingersoll-Rand's (IR) 10 CFR Part 21 procedures do not ensure that a responsible officer shall be notified in all cases when a defect is found in a safety-related basic component. (87-01-01)
- 2. Contrary to Section 21.31 of 10 CFR Part 21, a review of purchase orders (P0) to vendors revealed that while 10 CFR Part 21 was ;
imposed upon IR, IR did not impose 10 CFR Part 21 requirements on {
P0s 571639 (March 21, 1986) to Accutrex Products, 503428 (March 2, 1987) to Micro Speciality Systems, 546431 (March 18,_1983) to Page Wilson Corporation, 503413 (November 7, 1986) to Nutley Equipment Repair Company, 502326 (January 29,1986) to Grumman Aerospace Corporation, and 500051 (July 22, 1987) to Blanchette Tool and Gage Company. (87-01-02)
- 8. NONCONFORMANCES:
- 1. Contrary to Criterion VII of Appendix B to 10 CFR Part 50 and Subsection 5.4.3 of Section N-10 of the Quality Assurance Manual (QAM), P0s were placed with Accutrex Products (571639), Tinius Olsen (500052), and Nutley Equipment Repair Company (503413); but the three suppliers were not on the Approved Vendor List (AVL).
(87-01-03)
- 2. Contrary to Criterion XVII of Appendix B to 10 CFR Part 50, Subsection 4134.17 of Section III of the ASME Code, Subsection 5.5.3 '
of Section N-10 of the QAM, and Subsection 4.9 of Section N-24 of the QAM, a copy of the following P0s could not be retrieved by IR:
500052 (Tinius Olsen), 575638 (Vitco Nuclear Products). 579777 (Durametallic), 527545 (IR - Foundry Division)(, andCarpenter Technology), 570857 and 575426 548915 (Precision Heat Treatment).
(87-01-04)
- 3. Contrary to Criterion II of Appendix B to 10 CFR Part 50 Subsection l i
NCA-4134.2 of Section Ill of the ASME Code, and Subsection 3.0' of Section N-25 of the QAM, it was noted: (87-01-05) l 126
ORGANIZATION: INGERSOLL-RAND ENGINEERED PUMP DIVISION PMil l T P9 AIIPG . Ukl.1FR9FY REPORT INSPECTION NO.: 99900064/87-01 RESULTS: PAGE 3 of 16
- a. IR did not have records to show that welding personnel had been indoctrinated and trained regarding applicable code requirements, company policies, QA Program requirements and quality procedures.
- b. A review of records in the QC Inspection Department revealed that the formal training scheduled for this department for calendar year 1987 had not been accomplished as of the date of the inspection.
- 4. Contrary to Criterion XII of Appendix B to 10 CFR Part 50, Subsection NCA-4134.12 of Section III of the ASME Code, and Section 4.5.2.1 of Procedure No. GXQ-1, the QC Department did not have the listing of calibration standards. (87-01-06)
- 5. Contrary to Criterion XVIII of Appendix B to 10 CFR Part 50, Subsection NCA-4134.18 of Section III of the ASME Code, and Subsection 4.2.1 of Section N-10 of the QAM, external audits were overdue for John Crane-Hondaille and Durametallic who were both last audited in July 1986. (87-01-07)
- 6. Contrary to Criterion VII of Appendix B to 10 CFR Part 50, Subsection NCA-4134.7 of Section III of the ASME Code, Subsection 5.3 of Section N-12 of the QAM, and Vermont Yankee P0 25165, and although IR's Certificate of Conformance (C of C) dated April 10, 1986 stated that the items furnished on P0 25165 conformed to the contract requirements including ouality requirements, two items were purchased as stock material from Livingston Wilbar (P0 571538) and Accutrex Products (P0 571639), but there was no documented evidence that the items had been upgraded per the conditions noted in Section N-12 of the QAM. (87-01-08) 7.
Contrary to Criterion IV of Appendix B to 10 CFR Part 50, subsection NCA-413d.4 of and L.4.2 of S,6ection III of the ASME Code, and Subsections 5.3.1 ection N-10 of the QAM, the requirement for a vendor to have an approved QA prograin was not stated on P0s 502326 (January 29,1986) to Grumman Aerospace, 571639 (March 21, 1986) to Accutrex Products, 500051 (July 22,1987) to Blanchette Tool
& Gage. (87-01-09)
- 8. Contrary to Criterion IV of Appendix B to 10 CFR Part 50, Subsection NCA-4134.4 of Section III of the ASME Code, and Subsections 3.1.3, 5.3.1, 5.4.1, and 5.5.1.2 of Section N-10 of the QAM, it was noted that the Manager 0A and/or the QC department did not review and approve the following documents: prs and P0s to Accutrex Products 127
ORGANIZATION- INGERSOLL-RAND ENGINEERED PUMP DIVISION PHT!1 TP9Rl!RG. NFW .1FR9FY REPORT INSPECTION N0.: 99900064/87-01 RESULTS: PAGE 4 of 16 (571639), Grumman Aerospace (502326) and Blanchette Tool & Gage (500051); and P0s to Nutley Equipment Repair (503413), and Vitco Nuclear Products (575055, 575657, 575427, 575422, and 575420).
(87-01-10)
C. UNRESOLVED ITEMS:
None.
D. STATUS OF PREVIOUS INSPECTION FINDINGS:
None.
E. OTHER FINDINGS AND COMMENTS:
- 1. IR - Engineered Pump Division (EPD) !
IR - EPD manufacturers nuclear pumps, vessels and associated component supports, parts and appurtenances to the requirements of Section III, Division 1, Class 1, 2, and 3 of the ASME Code. IR -
EPD renewed in May 1987 their Certificates of Authorization for "N" and "NPT" stamps at their Phillipsburg, New Jersey facility.
IR - EPD also manufactures comercial pumps and components to their standard QA program and military pumps and components to l the requirements of Standard HIL-Q-9858.
The last order for a nuclear pump was from Baltimore Gas & Electric, l and two auxiliary feedwater pumps were delivered to Calvert Cliffs I nuclear facility in 1982. The current nuclear work is for component l parts which amounts to approximately 1.5 percent of the sales in i 1986, j
- 2. Palo Verde 1 Low Pressure Safety Injection (LPSI) Pump Mechanical l Seal Leakage l
The mechanical shaft seals on both 1A and 1B LPSI pumps at Palo Verde 1 experienced excessive leaking during pump operation on July 3-4, 1987. These pumps were manufactured by IR to Combustion Engineering (CE) specifications, The mechanical shaft seals used in these pumps were purchased from Durametallic by IR. Leakage rates of 1 gpm for the IB pump and 2-3 gpm for the 1A pump were reported, j 128
ORGANIZATION: INGERSOLL-RAND ENGINEERED PUMP DIVISION PHit ! IPRRilRG. 4FW ilFR9FY _ _ .
REPORT INSPECTION NO.: 99900064/87-01 RESULTS: PAGE 5 of 16 The Instruction Manual documents that the LPSI pumps are IR type 8X20 WDF which is a vertical, single stage centrifugal pump with a bottom suction, 8-inch discharge, and a 20-inch impeller. The 8X20 WDF pump was designed in accordance with ASME Section III, Class II, 74 Sumer Addenda for a temperature of 400*F and a pressure of 710 psig. The pump has a rated capacity of 4300 gpm for borated water ranging in temperature from 40-400'F. Six LPSI pumps were provided for the Palo Verde site and were identified as follows: Unit 1 -
pump S/N 0876-36 -37; Unit 2 - pump S/N 0876-40, -41; and Unit 3 -
pump S/N 0876-44. -45.
The LPSI pumps are equipped with a Durametallic mechanical seal (ref. Durametallic Drawing 2D-151340, Revision 2) to prevent shaft leakage. The sealing surface for this mechanical seal is formed by a tungsten carbide seal ring in contact with a carbon insert. The insert is stationary, and an 0-ring is used to prevent leakage between the insert and the adjacent stationary gland ring. The seal ring rotates with the shaft sleeve, and packing is used to prevent leakage between the ring and sleeve. The shaft packing and 0-ring are made from an EPT material. A spring assembly holds the seal ring against the insert. This arrangement maintains contact between the sliding seal surfaces and accommodates wear and pump shaft movement.
The instruction manual indicates seal leakage is not visible to the naked eye during pump standby or operation. The seal drawing states that the maximum normal :,eal leak rate is 50 cc/hr, and the maximum accident seal leak rate is 100 cc/hr for the LPSI pump.
The instruction manual indicates that some flow is required through the pump to prevent everheuting during low flow operation. The pump installation is to include a recirculation line to provida required minimum flow. A general drawing note in the manual states for start-up and in-service testing periods not exceeding one hour of pump operation, the minimum flow for safe operation is 100 gpm and the et.stomer should install a 2-inch by-pass line from the discharge to the source of suction to provide this flow.
In the maintenance section of the manual as well as on the seal ;
drawing a note states: "Caution - do not lubricate EPT 0-ring '
with petroleum base lubricants. Use glycerine, ethylene glycol, silicone oil, or silicone grease. This pertains to 0-ring (6), !
gasket (G), and shaft packing (P)."
129
ORGANIZATION: INGERSOLL-RAND ENGINEERED PUMP DIVISION Phil l iP9 Af f D A. yFW .1FR9FY REPORT INSPECTION NO.: 99900064/87-01 RESULTS: PAGE 6 of 16 Table 1 identifies IR 8X20 WDF and 8X23 WDF pumps supplied for conmercial nuclear service. The QA Mana recent listing (dated December 8, 1977) ger that stated had beenthiscompiled was the most by IR.
Table 1 Site Pump Type Service Beaver Valley 8X20WDF RHP, Braidwood 1 8X20WDF RHR Braidwood 1 8X23WDF CS Braidwood 2 8X23WDF CS Braidwood 2 8X20WDF RHR Byron 1 8X20WDF RHR Byron 1 8X23WDF CS Byron 2 8X23WDF CS Byron 2 8X20WDF RHR Callaway 1 8X23WDF CS Callaway 2 8X23WDF CS Catawba 1 8X20WDF RHR Catawba 2 8X20WDF RHR Cherokee 1 8X23WDF CS Cherokee 1 8X20WDF LPSI Comanche 1 8X20WDF RHR Comanche 2 8X20WDF RHR Forked River 1 8X23WDF CS Forked River 1 8X20WDF LPSI Harris 1 8X20WDF RHR Harris 1 8X23WDF CS Harris 2 8X23WDF CS Harris 2 8X20WOF RHR Harris 3 8X20WDF RHR Harris 3 8X23WDF CS Harris 4 8X23WDF CS Harris 4 8X20WDF RHR Jamesport 1 8X20WDF RHR Jamesport 2 8X20WDF RHR Marble Hill 1 8X20WDF RHR Marble Hill 2 8X20hDF RHR Nillstone 3 8X20WDF DHR North Anna 3 8X20WDF DHR North Anna 4 8X20WDF DHR 130
ORGANIZATION: INGERSOLL-RAND ENGINEERED PUMP DIVISION PHT!ITP9R!lRn. VFW .1FR9FY REPORT INSPECTION h0.: 99900064/87-01 RESULTS: PAGE 7 of 16 Palo Verde 1 8X20WDF LPSI Palo Verde 1 8X23WDF CS Palo Verde 2 8X23WDF CS Palo Verde 2 8X20WDF LPSI Palo Verde 3 8X20WDF LPSI Palo Verde 3 8X23WDF CS Perkins 1 8X23WDF CS Perkins 1 8X20WDF LPSI San Onofre 2 8X23WDF CS San Onofre 2 8X20WDF LPSI San Onofre 3 8X20WDF LPSI San Onofre 3 8X23WDF HPSI Seabrook 1 8X20WDF RHR Seabrook 2 8X20WDF RHR St. Lucie 1 8X20WDF LPSI St. Lucie 2 8X20WDF LPSI St. Lucie 2 8X23WDF CS Sterling 1 8X23WDF CS Summer 1 8X20WDF RHR Surry 3 8X20WDF DHR i
Surry 4 8X20WDF DHR Tyrone 1 8X23WDF CS Vogtle 1 8X20WDF RHR Vogtle 2 8X20WDF RHR Watts Bar 1 8X20WDF RHR Watts Bar 2 8X20WDF RHR :
Wolf Creek 8X23WDF CS WPPSS 3 8X20WDF LPSI WPPSS 5 8X20WDF LPSI For each line item, the quantity of pumps is two.
It was noted that most IR 8X20WDF and 8X23WDF pumps supplied for nuclear service were designed to operate with an external heat exchanger to provide seal cooling and flushing for the shaft j mechanical seal and gland area. The pumps supplied to Palo Verde :
as well as some other nuc; ear sites do not use an external heat exchanger for seal cooling (see Table 2).
For pumps designed to operate with an external heat exchanger, a small amount of water is diverted from the pump discharge to a heat exchanger cooled by external cooling water. After cooling, the water re-enters the pump through a pipe connection in the mechanical seal gland ring. The water cools and flushes the mechanical seal and other gland area parts as it flows to the i
131
ORGANIZATION: 1NGERSOLL-RAND ENGINEERED PUMP DIVISION DHf f l f pSRilRG. PIFW .1FR9FY REPORT INSPECTION NO.: 99900064/87-01 RESULTS: PAGE 8 of 16 low pressure region in the casing above the impeller. A character-istic of this design is that in the event of pump operation with a loss of heat exchanger external cooling water, the temperature of the mechanical seal and gland area parts can approach i.e water temperature at the pump discharge. The mechanical seal with seal water cooling is depicted in Durametallic Drawing 2D-134815.
For pumps designed to operate without an external heat exchanger, water is not bypassed from the pump discharge to the gland ring.
Instead, water in the internal gland area remains essentially stagnant and helps to maintain a barrier to reduce heat flow from the casing to the gland area. This design is not dependent on a l source of external cooling water to prevent gland area overheating.
l However, in the event that water in the gland area leaks from the pump for some reason (e.g., mechanical seal leakage), the temperature of the mechanical seal and gland area parts can approach the water l
temperature in the casing. The rate of temperature change depends upon the magnitude of the leakage rate (i.e., the higher the leak rate, the faster the gland area temperature will approach the casing watertemperature).
l Table 2 l Pumps Without Seal Cooling Heat Exchangers l
_ Site Pump Type St. Lucie 2 8X20WDF St. Lucie 2 8X23WDF ,
Palo Verde 1 8X20WDF Palo Verde 1 8X23WDF Palo Verde 2 8X20WDF Palo Verde 2 8X23WDF Palo Verde 3 8X20WDF Palo Verde 3 8X23WDF WPPS 3 8X20WDF 1 WPPS 3 8X23WDF WPPS 5 8X20WDF WPPS 5 8X23WDF Wolf Creek 8X23WDF Callaway 1 8X23WDF Callaway 2 8X23WDF Tyrone 1 8X23WDF Sterling 1 8X23WDF 1
133
ORGANIZATION: INGERSOLL-RAND ENGINEERED PUMP DIVISION PHilI TPRRIIRG. NFW MRSFY REPORT INSPECTION N0.: 99900064/87-01 RESULTS: PAGE 9 ef 16 Site Pump Type Byron 1 8X23WDF Byron 2 8X23WDF Braidwood 1 8X23WDF Braidwood 2 8X23WDF Harris 1 8X23WDF Harris 2 8X23WDF i For each item, the quantity of pumps is two, and the 8X20WDF and l 8X23WDF are LPSI and CS pumps, respectively.
Section 4.2.14 of CE's design specification SYS80-PE-410, Revision 3, states: "It shall be a design objective that a loss of externally supplied cooling water, for at least two (2) hours, shall not cause a loss of operability of the pump nor leakage of the seals in excess of 100 cc/hr per seal. Supplier shall state minimum time, if less than two (2) hours, pump assembly can withstand loss of cooling water."
This resulted in IR's decision to eliminate external gland cooling on the Palo Verde pumps.
Durametallic performed the technical evaluation to determine that the LPSI pump mechanical seal would operate satisfactorily without external seal cooling water. This evaluation was based on certain assumptions provided by CE about the time-temperature profile and transients of the water being pumped. At this time, capability of the mechanical seal to operate properly under more severe water temperature conditions is not known by IR. The IR representatives stated they did not have any available service life data for ,
mechanical seals in IR pumps installed in operating nuclear power l piants. The same mechanical seal is used for buth the IR 8X20WDF )
LPSI and OX23WDF CS pumps. In addition, the electric motors on tha l LPSI pumps had been changed during a modification, orid both the LPSI !
and CS pumps currently have the same size electric motors installed. !
The reported swelling of EPT parts in the Palo Verde 1A and IB LPSI pumps was briefly discussed. It was stated that this material ,
can swell if contaminated by oil based lubricants. The question I in the 1A unit was addressed related to the was whether failure swelling of the carbonofinsert the 0-ring (found in two pieces).
Based on a review of their notes.and recollections at the July 28, 1987 meeting at Palo Verde to discuss the mechanical seal problem, two IR representatives agreed on the following concerning the 1A LPSI pump: a) the 0-ring between the shaft and shaft sleeve (part not 133
ORGANIZATION: INGERSOLL-RAND ENGINEERED PUMP DIVISION '
PPil f T PRRIIPG yFW 1FDRFY REPORT INSPECTION N0.: 99900064/87-01 RESULTS: PAGE 10 of 16 shown on drawing) was reported to be heat set, b) the shaft packing between the sleeve and seal ring was swollen, c) there was no information on the condition of 0-ring between the carbon insert and l gland ring.
1
- 3. Control ?urchased Material and Services i
The inspector reviewed Section N-10 "Control of Procurement Documents l 8 Purchase Materials, Items and Services" of the QAM, procurement documents, and external audit reports to assure that items and services conform to the procurement documents and are purchased from approved vendors.
Procurement documents to six vendors of services were selected to determine if technical and quality requirements were included in prs and P0s. P0 503428 (March 2, 1987) to Micro Specialty Systems (MSS) covered semi-annual calibration services for four temperature records and one zone survey of the Sonder furnace. Page Wilson Corporation performed maintenance and calibration of two hardness testers under P0 546431 (March 18, 1983). The magnetic particle testing equipment was serviced and calibrated by Nutley Equipment Repair Company from Apr01 1986 thrcugh December 1987 under P0 503413 (November 7,1986).
P0s 500051 (July 22, 1987) to Blanchette Tool & Gage Company, 500052 to Tinius Olsen, and 502326 to Gruman Aerospace were for calibration services of other M&TE.
Approximately 20 P0s to nine vendorssfor material / items used on nuclear orders were also reviewed. The vendors included American Alloys, Vitco Nuclear Products, John Crane - Houidaille. Durametallic, Cann & Saul Steel, Livingston Wilbar, Accutrex Products, Carpenter /
Technology, ana IR-Foundry.
For nuclear material a PR had a "Controlled Pump Program" 6pproval stamp which was signed and dated by a representative from the QA department. Each P0 was signed and dated by a QA representative indicating that QA had compared the P0 with the PR. For five vendors, it was noted that prs and/or P0s were not signed by QA (See Nonconformance 87-01-10). Three P0s to Grumman Aerospace, Accutrex Products, and Blanchette Tool & Gage did not contain a requirement for the vendor to have a QA program which was approved by IR (See Nonconformance 87-01-09). Six P0s to one material vendor and five service vendors did not impose the requirerrents of 10 CFR Part 21 upon the vendor (See Violation 87-01-02).
134
ORGANIZATION: !NGERSOLL-RAND ENGINEERED PUMP DIVISION PHILLIPSBURG. NEW JERSEY REPORT INSPECTION N0.: 99900064/87-01 RESULTS: PAGE 11 of 10 Procurement documents for services performed by IR-Central Material Services Laboratory and weld material purchased from E. R. Joseph were requested, but copies of prs and/or P0s could not be retrieved by IR. In addition, a copy of IR's P0s which were referenced on certified material test reports or C of C's from Tinius Olsen, Vitco Nuclear Products, Durametallic, Carpenter / Technology, IR-Foundry Division, and Precision Heat Treatment could not be located. (See Nonconformance 87-01-04)
Five AVLs from April 1985 through April 1987 were reviewed. The AVL is updated semiannually by the QC Engineer. It was noted that orders were placed with Accutrex Products, Tinius Olsen, and Nutley Equipment Repair (NER) but the three suppliers were not on the AVL (See Nonconformance 87-01-03).
~
A Vermont Yankee P0 25165 dated August 30, 1985 was for an impeller nut modification for a reactor water cleanup pump. The licensee imposed nuclear and 10 CFR Part 21 requirements upon IR who assigned it order No. 001-41849. IR P0s 571638 (March 20, 1986) to Livingston Wilbar Corporation and 571639 (March 21, 1986) to Accutrex Products were for stock material. IR C of C (April 10, 1986) certified that the items furnished on P0 25165 conformed to the contract requirements including quality requirements. Documented evidence was not available to indicate that IR had upgraded the stock material per the requirements documented in Section N-12 of the QAM which are similar to those contained in Subsection NCA-3867.4(e) of Section III of the ASME Code. (See Nonconformance 87-01-08)
- 4. ControlofMeasuringandTestEquipment(M&TEJ The inspector reviewed Section N-16 "Control of Measuring and Test Equipment," of the QAM, Procedure GXQ-1 "Gage Control Program,"
and calibration records to assure that M&TE is properly controlled and calibrated.
It was noted that the QC Department did not have a listing of the !
calibration standards (See Nonconformance 87-01-06). A calibration l check of randomly selected instruments found in various departments in the manufacturing facility was made. The instruments included eight micrometers, four verniers, one protractor, two hardness testers, one magnaflux unit, and two U/V meters. The calibration sticker noted the calibration frequency and the calibration due date.
135
ORGANIZATION: INGERSOLL-RAND ENGINEERED PUMP DIVISION PHILLIPSBURG. 4Ek JERSEY REPORT INSPECTION N0.: 99900064/87-01 RESULTS: PAGE 12 of li A calibration check of randomly selected gauges found in the test area was also made. The four gauges were identified with control numbers 33-0042, -0065, -0029, and -0027; snd the gauges were last calibrated in July or August 1987 and were due for calibration in October 1987. During the calibration check of gauges and instruments, the following items were found with cal 1bration stickers from outside vendors. The items included a Rockwell hardness tester calibrated by Page-Wilson, two Magnaflux units, and two U/V Meters calibrated by NER, and one dead weight taster calibrated by Grumman Aerospace. MTE control cords in the Gage Rovin masterdeck for 14 items were also reviewed.
The certification standards for Starrett End Standards S/N 9196 to 9201 and S/N 9190 to 9195 were reviewed. The certification was issued by Blanchette on July 31, 1987, and the calibration service was requested on IR P0 M500051E. Tinius Olsen Field Service Report dated July 1,1987 indicated services were provided to repair and calibrate the Tinius Olsen Hardness tester. IR's P0 500052 dated June 25, 1987 was referenced on the report.
- 5. Control of Special Processes The inspector reviewed Section N-15 "Welding, Heat Treatment, NDE and Other Special Processes" of the QAM. The covered welding electrode holding ovens were inspected. Each oven was labelled for a particular type of covered welding electrode. A thermometer with a serial number was installed in each oven. Information obtained from the calibration stickers for a few randomly selected oven thermometers indicated that five thermometers (Nos. 39-0005, ;
-0006. -0020, -0021, and -0031) were on a 12 month frequency and ,
were due for calibration in December 1987. !
l The heat treat oven control panel was inspected. Calibration stickers on the temperature controller (No. 39-0027) and the temperature indicating recorder (No. 39-0052) indicated that both instruments were calibrated by MSS in May 1987 and were due for .
calibration in November 1987. 1 The Welding Foreman records for the welding machine voltmeter and ameter calibration checks were reviewed. The records that were inspected showed that calibration checks had been performed every six months as required. The calibration stickers on two randomly selected welding machines (Nos. 17 and 33) indicated that both were calibrated in May 1987 and were due for calibration in November 1987.
136
o ORGA!U7ATION: INGERSOLL-RAND FNGINEERED PUMP DIVISION PHil l IPSRUR$ NFW JFRSFY l REFORT INSPECTION NO.: 99900064/87-01 _
RESULTS: PAGE 13 of 10 The inspector reviewed the Welder Continuity - Monthly Weld Report for nine (urrent wcloers who were qualified to the requirements of Section I5 of the ASME Code. The report was signed by the weld foreman and QA Engineer and documented the wolder and the weld procedure specification (WPS) that was used on a monthly basis from January 1983 tv the present. The Section IX Welder Qualification Records for six welders (Nos. 343, 108, 14, 872, 63, and 210) were reviewed. It was noted that all six welders were qualified to a particular WP'i'which was used on a nuclear order. The records
- included the appitcable Procedure Qualification Record and Radiography Reporti for test coupons which were radiographed by a Level III examiner at the IR-Foundry Division.
The nondestructive examination (NDE) records were reviewed. IR's written practice for NDC is Procedure No. ESQ-3 "Certification of Nondestructive Ta t Pe-sonnel," Revision 3 dated May 21, 1986. The procedure prepared in accordance with SNT-TC-1A was written by IR's Level III and approved by the Chief Inspector and Manager QA.
The qualification records of four Level II and one Level III examiner were reviewed in detail. The records were consistent with the requirements of SNT-TC-1A.
- 6. Documentation Packeges,(DP)
The inspector reviewed 21 DPs (2-1984, 3-1985, 4-1986, and 12-1987) for nuclear spare part orders. A DP normally consisted of a Quality Control Inspection and Package Control Form (QCIPCF),
Factor Order Page (F0P), IR C of C, CMTRs/C of Cs from vendors, Hydrostatic Test Report, NPT Data Reports, Final Documentation Checklist, Receiving Inspection Record, Manufacturing & QC Plan (HQCP),andProductionRoutingSheets(i.e., travelers). The QCIPCF identities the item by S/N (vibratooled on item) and the shipping foreman :vho does the processing and packing, the QC representative =to reviews the software and order requirements, ano the ins' actor who checks the item before shipment. The F0P describes tie item and the vendor and IR shop requirements, and
'c is signed by i Contracts Administrator and a QA representative.
IR's C of C was signed by a QC technician and containco a statement that the item (s) conform to contract requirements,Section III of the ASME Code, and IR's "Nuclear Controlled Pump Program Quality Assurance Manual." The MQCP was generated by a Project Engineer and approved by a Product Engineer and a QA Representative.
137
ORGANIZAT10N: INGERSOLL-RAND ENGINEERED PUMP DIVISION PHil i IPRRilRG. NFht MR9FY REPORT INSPECTION N0.: 99900064/87-01 RESULTS: PAGE 14 of 10 The 1987 orders were from Alabama Power Company, Texas Utilities Generating Company (TUGCO), Arizori. W blic Service Company, Corrrronwealth Edison, Public Service T.lectric & Gas, Virginia Power, Florida Power & Light, anc Bechtel. Vermont Yankee and Commonwealth Edison ordered replacement parts for nuclear pumps in 1986. The three orders in 1985 were from Duke Power, Southern California Edison, and General Electric; and the 1984 orders were from Carolina Power & Light and TUGCO.
- 7. Indocorination and Training The inspector reviewed Section N-25, "Training and Indoctrination,"
of the QAM and indoctrination and training records for the QC Inspection Department. The 1987 training session schedule for the QC Inspection Department was approved by the QA Manager on March 8, 1987 and identified nine training sessions that were scheduled from April to November 1987.
Reports were not found for training during calendar year 1987 (See Nonconformance 87-01-05). This matter was brought to the attention of the QC Inspection Manager who stated formal training had not been conducted this calendar year. He indicated he is performing some indoctrination and on-the-job training and occasional posting of various items he wants to bring to the attention of department personnel.
Eight training files for QC inspection personnel were selected for review. Typical information found in the files included:
Certificate of Minimum Required Training, Inspection Qualification Resume and Progress Report, training session reports, Inspector Qualification Progress, and visicn test. Four training files were reviewed in detail and included three Level II Inspectors (Nos.
1014, 707, and 138), one Level II Hydrotester (No. 1172), and one Level III Inspector (7030).
The Welding Department Foreman did not have any records to show that Welding Department personnel had been indoctrinated and trained regarding applicable code requirements, company policies, quality assurance program requirements and quality procedures (See Nonconformance 87-01-05).
i 138
l I
ORGANIZATION: fNGERSOLL-RAND ENGINEERED PUMP DIVISION PHill IPRRllRG. MEW JERSEY REPORT INSPECTION NO.: 99900064/87-01 RESULTS: PAGE 15 of 10
- 8. _10 CFR Part 21 The inspector reviewed Section N-19 "Nonconfonnance Control" of the QAM. Subsection 7.2 addresses the reporting of defects and stated it is the responsibility of all employees to report to the Manager, Quality Assurance deviations which may result in substantial safety hazards (10 CFR Part 21).
Procedure No. NSQ-1 "Control of Nonconforming Material," Revision I was reviewed. The procedure states that it is the responsibility of all employees to report to the Manager, Quality Assurance deviations which may result in substantial ufety hazards. It was noted that neither procedure ensures that a responsible oficer higher on the organizational chart that the Manager Quality Assurance will be notified when a defect is id'.ntified. (See Violation 87-01-01.) Section 21.3(j) of 10 CFR Part 21 requires that a "Responsible Officer" be an individual who is vested with executive authority over activities subject to this part, and a QA Manager is not ordinarily vested with executive authority.
- 9. Audits The inspector reviewed Section N-23, "Audit of QA Prc. 'am," of the QAH and Procedure ASQ-1, "Internal Audits." The internal Audit Schedule, QCM-511, is completed and controlled by the QC Department.
The schedule of audits to be completed, revisions to the schedule, and individuals responsible for conducting the audits are approved by the Manager QA. The Quality Audit Report Log, QCM-158, is maintained by QC.
The Auditor or Lead Auditor prepares the Internal Audit Checklist, QCM-286, securing a Quality Audit Report Number from the Quality Audit Report Log Sneet, QCM-158, indicates the scope and purpose of the audit, and prepares a checklist from the manual sections, exhibits, procedures, and applicable documents to be covered by the audit. The checklist is approved by the Manager QA.
Internal Audit schedules for 1987 were reviewed. The schedules reviewed were distributed by four memos from the QC Engineer dated February, March, June and September 1987. The following audits had not been perfonned by the scheduled date: GXQ-36, PNM-3, and INQ-12.
The following internal audit reports were briefly reviewed. Check-lists signed by the Manager QA were used for the audits. Audit Report AR-879 was for Training and Indoctrination (N-25, S-22) and i
139
ORGANIZATION: INGERSOLL-RAND ENGINEERED PUMP DIVISION PHilITPSRURG. NFW JFRSFY ._
REPORT INSPECTION N0.: 99900064/87-01 RESULTS: PAGE 16 of 1h included three audit dates (November 1. December 6, and December 8, 1986). Audit Report AR-885 was for Document Control (N-9, S-8) and included two audit dates (March 5, and March 31,1987).
The QA record files fcr the external audits of 12 vendors were reviewed. The audits took place from November 1985 through May 1987 and were conducted by one of three auditors. For each audit, documentation in the file consisted of: a) memo from the lead auditor to the Manager QA summarizing the audit results with a recommendation regarding placement of the vendor on the AVL, b) letter to vendor signed by the auditor and Manager QA, c) Vendor Survey Report, and d) checklist signed by the auditor and Manager QA. It was noted that the audits for John Crane-Houdaille and Durametallic were last conducted in July 1986 and were overdue by two months (See Nonconformance 87-01-07).
A memo dated April 10, 1987 from the QC Engineer to the Manager QA documented a list of nine people (3 in training) who are currently qualified to perform internal and vendor audits / surveys in accordance with Section N-25 of the QAM. The records for the three individuals who performed the external audits were reviewed in detail. The records consisted of: a) certification as lead auditor signed by the Manager QA, b) Record of Lead Auditor Qualification per the re d)quirements of ANSI training classes, e) N45.2.23, resume, andc) auditor f) lead qualification record, auditor examination.
F. PERSONNEL CONTACTED:
- M. Hagerstrom, Manager QA K. Schumann, Manager Customer Service P. Nagengast, Manager Engineering Analysis
- G. Young, QC Engineer
- D. Jean, Manager Manufacturing H. Walters, QC Technician j
> l
- Attended exit meeting.
l i
140
ORGANIZATION: STATSC-0-RING OLATHE, KANSAS REPORT INSPECTION INSPECTION
_ N0.: 99900824/87-01 DATES: 08/05-07/A7 ON RTTF MnllDR. M CORRESPONDENCE ADDRESS: Static-0-Ring ATTN: Mr. J. Johnson Vice President 11705 Blackbob Road Olathe, Kansas 66061 GRGANIZATIONAL CONTACT: Harry Hartman TELEPHONE NUMBER- 913-764-2610 NUCLEAR INDUSTRY ACTIVITY: Pressure & difff.:rential pressure switches.
l ASSIGNED INSPECTOR: '.b .1- //< /
K. R. Naidu, Program Develpment and Reactive Date Inspection Section (PDRIS)
OTHER INSPECTOR (S): J. C. Stone APPROVED BY: A .
/0 J9 J. C/ Stone, Chief, PDRIS, Vendor Inspection Branch at INSPECTION BASES AND SCOPE:
A. BASES: 10 CFR Part 21, Appendix B to 10 CFR 50. l B. SCOPE: Review actions taken to correct setpoint drift in differential pressure switches; action taken to select diaphragm material in pressure switches and verify implementation of QA program in selected areas. i PLANT SITE APPLICABILITY: LaSalle Unit 1 and 2 (50-373, 50-376), Davis-Besse (50-346). ,
1 1
141 I
ORGANIZATION: STATIC-0-RING OLATHE, KANSAS REPORT INSPECTION Nn
- QQQnnn?d/n7-n1 R FSul TS ! PAGF ? nf 6 A. VIOLATIONS:
No violation was identified during this inspection.
B. NONCONFORMANCES:
Contrary to Criterion X of Appendix B to 10 CFR 50, and Section 10.6 of the SOR Quality Assurance Manual, 8303-100, the inspectors observed that the adjustment screw for manipulating the setpoint for 102/103 differential pressure switches, which was manufactured to Drawing 8305-034, Revision 2, dated November 13, 1986, was inspected by S0R QC and documented to be in accordance with Revision 1, dated June 22, 1984 of this drawing.
C. UNRESOLVED ITEMS:
l No unresolved items were identified during this inspection. I D. INSPECTION FINDINGS AND OTHER COMMENTS:
- 1. Background Information On June 1, 1986, LaSalle County Station (LSCS) Unit 2 was operating at 95 percent power level when a feedwater transient occurred which caused the water level in reactor vessel to drop to the level 3 trip setpoint. One of the four differential pressure switches (DPS) manufactured by SOR responded to the drop in level and actuated resulting in a half scram. The LSCS operator recovered water level and continued operation. Subsequent investigation determined that three DPSs failed to trip at their set level. The NRC issued Bulletin 86-02 and Information Notice 87-47 to alert other users of potential problems with SOR DPSs. LSCS took corrective actions to establish revised setpoints, modify the calibration methodology and instituted surveillance programs to verify the calibration of the DPSs at predetermined intervals depending on the function, location of the DPS, and procedures. Conservative action and rejection limits for the DPSs were established. If a DPS exceeded the action limit for two consecutive calibrations, it was scheduled to be replaced within 14 days. If any DPS exceeded its rejection limit, the switch was to be replaced and the rejected switch was to be '
disassembled, inspected, and the results of the inspection sent to ,
the NRC. The following are the typical action limit and rejection '
limit values for a switch.
142
ORGANIZATION: STATIC-0-RING OLATHE, KANSAS REPORT INSPECTION Mn - coonnA9a/97.n1 R F9lll TS
- PAGF 1 of 6 Inches of Water Column Nominal Level Setpoint translated to differential 23.00 During calibration, the DPS is set between 22.4 - 23.6" i
1 Action Limit 21.3"(23-1.7)
(the switch should actuate 24.7 (23+1.7) between these setpoints)
Tech Spec Limit of tolerance 1.78" Rejection Limit 17.7" (23-5.3)
(theswitchactuatesat 28.3"(23+5.3) these limits)
- 2. Corrective Action Taken by S0R SOR received eight switches consisting of five 103AS-8212 type and three 103AS-8203 type DPSs. SOR's findings and the corrective actions are discussed below,
- a. During receipt inspection of the switches, SOR determined that seven of the eight DPSs actuated within the specified action limits. SOR attributed the acceptable results to calibration under laboratory conditions,
- b. Burrs were observed on the adjusting screws in five DPSs. The burrs may cause problems in adjusting the setpoint during calibra-tion in the field; at the factory, however, the burrs did not affect calibration. SOR revised the design of the adjusting screw to eliminate the burr.
- c. Traces of brown deposit were observed inside several switches.
S0R was unable to determine the origin of the deposit. SOR plans to electro-chemically clean the switch bodies to improve cleanliness of the switch bodies.
In addition to the above, during calibration, setpoint instabilities were encountered on some switches. On disassembly, the diaphragm was observed to be perforated. Perforation of the diaphragm does 143
ORGANIZATION: STATIC-0-RING :
I OLATHE, KANSAS REPORT INSPECTION Mn - QQQnn9?a/n7 n1 RESULTS- PAGE 4 nf 6 not cause the switch to fail completely due to the large volume of water on either side of the DPS; however, it is difficult to adjust the setpoint. SOR examined the DPS bodies in which the diaphragms were perforated under a microscope and observed the presence of microscopic metal residues from machining process.
LSCS also initiated an investigation of the DPSs with perforated diaphragms. On May 6,1987, LSCS informed SOR that their investiga-tion indicated that the switches could have been contaminated with foreign material during assembly and testing. To reduce foreign debris and remove burrs from cut edges, CECO recommended changes in the manufacture and testing of the SOR switches. Specifically, CECO recomended that a) the machined switch body be electro-polished or electro-deburred, b) imediately prior to assembly, all switch body internal parts including the diaphragm be washed & cleaned, and c) deionized water used for testing and calibration be filtered through a 15 micron filter.
SOR opted to electro-deburr the DPS body blocks, and selected a contractor. Three procedures using solutions with three different chemical cleaning concentrations were developed. Two body blocks were deburred in each of the three processes. One set of the bodies were retained by SOR and one set was sent to LSCS for examination.
SOR intends to use the procedure which yields the best results. The inspectors examined the diaphragms of several 103 type DPS and concurred that the diaphragms had been damaged by contaminents of unknown origin.
- 3. Followup on 6TA Series Pressure Switches On January 11, 1987, Davis Besse nuclear power plant (DB) reported to the NRC that they were experiencing drift in setpoints in 6TA-B4-NX-C1A-JJTTX6 type pressure switches (PS), manufactured by S0R.
- a. Background Information The following two factors exposed the kapton diaphragms in SOR PSs to the adverse effects of hydrazine.
The first factor was that the application was changed from intermittent to continuous duty. Following the June 9, 1985 feedwater transient DB modified the steam inlet to the two i
144
I ORGANIZATION: STATIC-0-RING OLATHE, KANSAS REPORT INSPECTION un . coannn9a/n7_n1 RESULTS: 1 AGE 5 of 6 Auxiliary Feedwater Turbine Pumps (AFTP) to preclude condensed water impingement on the AFPT. After modifying the steam lines the pressure switches are now pressurized when the main steam line is pressurized instead of only being pressurized during operation of the Auxiliary Feedwater Pump. Secondly, the existing unqualified SOR PSs which contained pressure sensing diaphragms made of stainless steel (SS-316) were replaced with environmentally qualified PSs containing kapton diaphragms, i 4. Identification of the Problem The combination of the above two factors exposed the incompatability of kapton and hydrazine. Hydrazine, an additive in the secondary water system to control water chemistry in PWRs, reacts with oxygen to form ammonia. Arrrnonia permeates kapton. Dupont, the manufacturer of kapton, stated that certain concentrations of chemicals such as ammonium hydroxide, sodium hydroxide, and potassium hydroxide will cause kapton to degrade.
Based on the above information, SOR issued product information letter dated January 15, 1987 to all users. The letter advised them that gas bubble fonnation (due to hydrazine) between the diaphragm layers will cause the setpoints to drift.
On April 20, 1987 the NRC issued Information Notice 87-16. Three months later, SOR determined that hydrazine also permeated SS diaphragms. On April 27, 1987, SOR informed all users that the use of SS-316 diaphragms did not completely eliminate the problem. The letter stated that an indication of a bubble formation increases the deadband of the PS but also stated that the root cause had not been determined.
- 5. Corrective Action Taken by SOR SOR now believes that the gas was leaking by the "0" ring that seals the diaphragm. They are now testing a pressure switch that has the SS-316 diaphragm welded to the pressure port fitting. This PS is undergoing long term tests with helium as the process medium, because of its small molecule size. SOR considers this to be a worst caso scenerie which will give more rapid results and is safe for the personnel involved in the test. The inspectors reviewed the results of the tests conducted to date and determined it acceptable.
S0R is in the process of perfonning a supplemental Environmental i Qualification evaluation with the revised design. l 145
ORGANIZATION: STATIC-0-RING OLATHE, KANSAS REPORT INSPECTION un coonnooa/97_n1 QFRIll TR. PARF A nf 6
- 6. Observation of Tests in Progress The NRC personnel witnessed the periodic testing of switches. These switches are undergoing long term tests to determine any trends in setpoint drifts. Approved procedures were used to verify drifts in setpoint. Records on the data collection were legible and retrievable. The results indicate no adverse tread in setpoint drift.
- 7. Observation of Manufactured Parts in Storage During a tour of the storage area, where parts for assembly of switches to be used in nuclear applications are stored, it was noted that the adjustment screw for differential pressure switches 102/103AS (drawing number 8305-034 Revision 2 dated November 13,1986)wasof the latest design. The revised design changed the physical l 4
appearance of the part. However, the receipt inspection documenta-tion referenced drawing number 8305-034, Revision 1 dated June 22, 1984. The SOR QC inspector had verified that the part met the requirements of the earlier drawing. (Nonconformance 99900824/
87-01-01 wasidentified.) Eight additional parts stored in the nuclear storage area were compared to the receipt inspection documentation and no additional descrepancies were observed.
E. EXIT INTERVIEW:
The inspector met with SOR representatives mentioned in Section F at the conclusion of the inspection and discussed the scope of the inspection and findings.
F. PERSONS CONTACT _ED:
- R. C. Dunlop, President ,
J. Peternel, Manager, Nuclear Sales i L. Ganser, Project Engineer l W. A. Priest, Project Engineer l H. P. Hartman, Manager, Quality Assurance l R. C. Davidson, Production Engineer l R. C. Engel, Manager, Sales j S. Baras, Nuclear Coordinator !
i 146 l
ORGANIZATION: WYLE LABORATORIES HUNTSVILLE, ALABAMA REPORT INSPECTION INSPECTION NO.: 99900902/87-02 DATES: 09/28-29/87 ON RTTF NollDR. 11 CORRESPONDENCE ADDRESS: Wyle Laboratories Scientific Services and Systems Group ATTN: Mr. W. W. Holbrook, General Manager Eastern Test and Engineering Operations 7800 Governors Drive Huntsville, Alabama 35807 ORGANIZATIONAL CONTACT: Mr. E. W. Smith, Director, Contracts and Purchasing TELEPHONE NUMBER: 205-M7-4411 NUCLEAR INDUSTRY ACTIVITY: Wyle Laboratories; Huntsville, Alabama, provides a variety of nuclear services to the industry. These services include environmental and seismic qualification testing of safety-related equipment, refurbishment and recertification of valves, valve and component flow testing, mechanical and hydraulic snubber testing, decontamination, and repair.
ASSIGNED INSPECTOR: CM[MM 27,(( 8hf[P7 N. Moist, Special Projects Inspection Section Dath (SPIS)
OTHERINSPECTOR(S):
,3 APPROVED BY:
_U. Potapovs Chief SPIS, Vendor Inspection Branch l0-lb@
Date INSPECTION BASES AND SCOPE:
A. BASES: 10 CFR Part 21 and 10 CFR Part 50, Appendix B.
B. SCOPE: Review equipment qualification test results of electrical cable splices for use in the Farley huclear Plant.
PLANT SITE APPLICABILITY: Farley 1,2,(50-348,50-364).
't 147 1
ORGANIZATION: WYLE LABORATORIES HUNTSVILLE, ALABAMA REPORT INSPECTION Nn . QQQnnCn?/A7.07 RF9H1TS. PACF 7 nf a A. VIOLATIONS:
None.
B. S NONCONFORMANC_E_S:
None.
C. UNRESOLVED ITEMS _:
None.
D. OTHER FINDINGS OR COMMENTS: l
- 1. The NRC inspector reviewed test results of splices fabricated with 3M Scotch 33+ Vinyl plastic electrical tape and Okonite splicing ,
tapes numbers 35 and T-95. This test was performed under Qualifica- l tion Plan 17942-01 for Alabama Power Company for use in Farley Nuclear Plant.
Fifteen specimens were included in the qualification test program. '
The specimens represented splices installed on cables which supply fan motors and motor and solenoid operated valves. Configuration of each specimen differed based on cable size, or insulating tape, or jacketing tape or splice overlap. Testing voltage and current for the specimens also differed depending on the application of each splice. The fabrication of test specimens was performed by Wyle Laboratories, Huntsville, Alabama. All materials for fabrication of the splices were supplied to Wyle Laboratories by Alabama Power Company.
all specimens were subjected to the following qualification sequence:
receiving inspection, specimen preparation, baseline functional test, radiation exposure, functional test, themal aging, functional test, accident simulation and post-test inspection.
The test setup included a NEMA 1 enclosure with six specimens, three condulets with two specimens each and a Limitorque limit switch compartment cover with three specimens., The mounting of the six splices in the NEMA 1 enclosure was in a vertical direction where the "V" of each splice was oriented in the downward direction. The mounting of the splices in the condulet and the Limitorque limit switch compartment cover was oriented in a horizontal direction.
148
ORGANIZATION: WYLE LABORATORIES HUNTSVILLE, ALABAMA REPORT INSPECTION wn . ooonnan?/A7_n? RFRULTS! PAGE 3 of 4 The accident simulation test represented the main steam room (MSR) temperature and pressure profiles for a main steam line break and containment temperature and pressure profiles during a LOCA/HELB for Farley Nuclear Power Plant. All fifteen specimens were tested to the MSR and containment profiles. The MSR profile was conducted first followed immediately by the containment profile. Leakage current was monitored for all specimens in the condulets at the initiation of the MSR and continuously for specimens in one condulet for the duration of the MSR and containment profiles. Leakage current of 1 ma was measured for the specimens in one condulet.
Wyle personnel suspected that the leakage current was self induced by two cables tied with nylon tie wraps outside the test chamber.
, After the nylon tie wraps were cut and the cables separated, the l leakage current dropped to zero. Review of the test results t
indicated that the test specimens demonstrated the capability to conduct the specified currents at the specified voltages during the accident simulation. The specimens were artificially aged for fifteen years equivalent life prior to the accident simulation.
The NRC inspector examined the qualification plan (QP) and related engineering docurnentation to verify the following:
a) Adequate test instrumentation and their accuracies were described and used to meet the requirements of IEEE-STD-323/
1974, b) Equipment interfaces were addressed, c) Test acceptance criteria were established, d) Same equipment was used for all phases of testing and represen-ted a standard production item, e) Environmental conditions were established and described (e.g.,
pressure and temperature profiles.
f) Test results were adequately reduced and evaluated against established acceptance criteria described in QP.
g) All prerequisites for the given tests as outlined on the QP had been met.
h) Test equipment included a description of all materials, parts, and subcomponents.
149
ORGANIZATION: WYLE LABORATORIES HUNTSVILLE, ALABAMA REPORT INSPECTION Nn - coonnon?/A7.n? REStiLTS: PAGE 4 of 4 i) Notice of Anomaly reports were properly documented, j) Appropriate margins applied.
With respect to i) above:
An anomaly occurred during the accident simulation test program relating to the use of a high speed printer that was outside its calibration interval. The printer was subsequently calibrated and was found to be within manufacturer's prescribed tolerance.
No nonconformances were identified.
E. PERSONNEL CONTACTED:
J. Hazeltine, Wyle Project Engineer R. Woodfin, Alabama Power T. Hamilton, Acting QA Manager l
150
SE N INFORMATIm NOTICES I
t
IN 87-35, Supplement l' UNITED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION WASHINGTON, D.C. 20555 December 16, 1987 i
NRC INFORMATION NOTICE NO. 87-35, SUPPLEMENT 1: REACTOR TRIP BREAKER, WESTINGHOUSE MODEL DS-416, FAILED TO OPEN ON MANUAL INITIATION FROM THE CONTROL ROOM Addressees:
All holders of operatino licenses or construction permits for nuclear power '
reactors.
purpose:
This infomation notice is being provided to alert addressees to the detemi-nation of the cause nf the mechanical binding that resulted in the failed reactor trip breaker (RTB) described in Infomation Notice No. 87-35. The NRC is considering the need to request action by licensees using Westinghouse DS series breakers in Class IE applications. This supplemental notice also ,
discusses other concerns that arose during investigations of the RTB failure but that did not contribute to the binding of the RTB. It is expected that recipients will review the information for applicability to their facilities and consider actions, as appropriate, to avoid similar problems. However, suggestions contained in this information notice do not constitute NRC require-ments; therefore, no specific action or written response is required.
l
Background:
Infomation Notice 87-35, dated July 30, 1987, discussed the July 2, 1987, I event at McGuire 2 in which an RTB would not open upon receipt of an electrical l comand signal. The RTB had bound mechanically. The shunt trip coil burned 1 and shorted during the attempt to open the breaker. Operators in the control l room stated that they observed open indications for both redundant RTBs, but the event recorder showed that only one had opened. The licensee's investiga-tion, observed by an NRC Augmented Inspection Team, revealed abnomal wear of the pole shaft assembly and a broken weld joining the center pole lever and the pole shaft, but did not identify the specific cause of binding. Because the licensee's facilities for further investigation were limited, further investi- !
gation was to be conducted in a Westinghouse laboratory.
j l
1 0 l l
8712100417 l
151 I
? . ., . . - _ _ - - . _ - - - _
IN 87-35, Supplement 1 December 16, 1987 Page 2 of 4 1
Failure Mode:
The McGuire 2 RTB failed to open because the main roller was wedged between the raised edge of the close cam and the right-hard side frame plate (viewing the RTB from the rear). A labeled view of the RTB mechanism is shown in Figure 1.
When the RTB is closed, the position of the mechanism is as shown in Figure 2.
A conceptual sketch showing the main roller wedged between the right side frame plate and the left cam segment, as viewed from the rear of the RTB, is shown in Figure 3. Similar wedging could occur between the left side frame plate and the right cam segment.
In the Westinghouse DS series breakers, the close cam (item ? in Figure 1) is composed of four steel segments that are sandwiched together and held by three rivets. The two outer ser.n nts are heat-treated steel; the two inner segments are non-hardened steel, lhe surface of the segments is supposed to be of unifonn shape. However, on the McGuire RTB, the two outer seaments are slightly(item roller 15). larger Only than the inner a slightly raisedsegments, cam edgeproviding the edge is necessary to catch the main to allow binding. In addition, the distance between the inner surface of the close cam edge and the side frame plate (item 19) must be close to the width of the main roller.
The main roller can become wedged durino the closing action of the breaker. As the close cam rotates, the edge of the main roller is caught, as shown in Figure 4. Continued rotation of the close cam causes the main roller axis to straighten. This action causes the edges of the main roller to attempt to separate the close cam and the side frame plate. However, the close cam and side frame plate are not free to move and, therefore, they wedge the main roller in place. When an attempt is made to trip the breaker, the wedgirig of the main roller prevents the main roller from rolling down the close cam face to allow the circuit breaker to open. The wedging of the main roller also prevents full discharge of the closing springs (not shown in Figure 1), leaving the close cam 18 degrees from a fully rotated position.
Both lateral displacement of the main roller end of the main drive link (item 14) and a small rotation (3 to 5 degrees) of the main roller axis are necessary to allow wedging. If the weld joining the center pole lever (item 9) to the pole shaft (item P) is sound, the main roller end of the main drive link could still move laterally and even allow the main roller to strike the side plate. However, a sound weld would not allow sufficient rotation of the axis for wedging to occur. A large number of cycles of operation (3000 or more),
however, could cause wear that would allow the necessary rotation of the axis.
Additional details on the failure mode and the Westinghouse tests are contained in References 1, ?, and 3.
Other Concerns:
Stop Roller Binding. The inspection of the McGuire 2 RTB components at Westinghouse revealed that the close cam surface had been peened. The peening 152
IN 87-35, Supplement 1 December 16, 1987 ,
Page 3 of 4 flattened and laterally expanded the surface of the outer cam segments, creat- :
ing a mushroom shape. Of key concern was mushrooming in the area of the stop ,
roller (item 1), which holds the mechanism in readiness for release of the spring release latch (item 16). The extreme mushrooming impeded rotation of the stop roller. It is possible that sufficient mushrooming could totally ,
prevent operation of the stop roller, which could prevent closure of the circuit breaker upon demand. While not of safety concern for an RTB, this failure to close condition would be of concern for a breaker in a Class IE application requiring energization of the connected loads.
l RTB Position Indicating Light. At McGuire, red and green lights placed below '
each of the two RT5 spring-loaded manual control switches in the control room ,
serve to indicate whether the associated RTB is closed or open, respectively.
Operators are trained to operate both control switches simultaneously, one with each hand, and to interpret each set of lights as representing the actual status of each breaker. However, the red lights serve the additional purpose .
of indicating continuity of the shunt trip circuit for each breaker.
The design circuitry is such that the absence of the red light can mean either that the breaker has opened as intended or that the associated shunt trip circuit has been interrupted. Determining which is the case cannot be done from the red light behavior alone; rather, the red light behavior must be interpreted in combination with the green light behavior and other control room
. indications, such as rod position displays. Operators need to understand that
- a "malfunction" of the red light may in reality be a valid indication that the associated shunt trip circuit is inoperable. Additionally, it is important that operators understand that the combined absence of the red and green lights ,
after release of the spring-loaded manual control switch may mean that the associated breaker has failed to open in response to the electrical demand and i that imediate local verification or trip action is needed. At McGuire, pressing the manual trip plate at the RTE did not open the breaker, but manipu-lating the manual spring-charging handle did open it.
i
- Since the McGuire event, the licensee has modified the requalification training i program for operators to ensure that they understand the potential meaning of the various combinations of RTB indications and that they follow appropriate verification procedures for suspected "malfunctions" of these indications.
Trip Latch Pivot Pin. During an NRC inspection at Braidwood ? in late Septem-ber 1987, the licensee reported that a Westinghouse DS-416 PTB at Braidwood 1 i failed to close because im 4 to the trip latch (item 5) proper resulted braring of the pivot pin in disengagement (item of the 4 in two. Figure While not 1) of I
a safety concern for an RTB, this failure to close condition would be of concern !
l for a breaker in a Class IE application requiring energization of the connected i loads. '
< l 153
_ . _ _ . _ _ , - - - - - - . , ~ _ . . _ -
IN 87-35, Supplement 1 December 16, 1987 Page A of 4 No specific action or written response is required by this infonnation notice.
If you have any questions about this matter, please contact the technical :
contact listed below or the Regional Administrator of the appropriate regional office.
f %
Char es . Rossi Director Division of Operational Events Assessment Office of Nuclear Reactor Regulation Technical Contacts: Vern Hodge, NRR (301)492-8196 j Darl Hood, NRR l (301)492-8961 K. R. Naidu, NRR j (301) 492-9659
References:
- 1. "Interim Report on McGuire 2B Reactor Trip Breai,er Failure Evaluation and Recomended Corrective Actions from Westinghouse "
Franklin Research Center September 30, 1987, enclosure to letter from D S. Hood, NRC, to H. R. Tucker, Duke Power Company, October 16, 1987, NRC Docket No. 50-370
?. NRC Inspection Report Nos. 50-369/87-22 and 50-370/87-22, August 31, 1987
- 3. "Reactor Trip Breaker Failure Due to Mechanical Failure,"
Licensee Event Report 50-370/87-009, Duke Power Co. August 3, 1987 Attachments:
1, Figure 1. Linkages of DS-416 Breaker Mechanism
- 2. Figure 2. Position cf Mechanism with RTB Closed
- 3. Figure 3. Roller Wedged Between Left Cam Segment and Right Side Frame Plate
- 4. Figure 4 Binding of Roller 5 List of Recently Issued NRC Infonnation Notices 154 I
O At IN,t87-35.
a c hmSupp.
e .i t 11 December 16, 1987 Page 1 of 1
[
- 1. Stop Roller
- 2. Close Cam hhh h 12
- 3. Roller Constraining j Link 4 Pivot Pin
- 5. Trio Latch
- 6. Trip Shaft e i Latching Surface
?. Trip Shaft
- 8. Pole Shaft --- -
1
/
- 9. Center Pole Lever
- 10. Pole Lever Pin
- 11. Moving Contact Arm @ s
' ,' e lsy s
- h
- 12. Sta tionary Arcing 4 ,
=
j Contact '
/
- 13. Moving Contac 5 gl. , < ,
l Pivot Pin . ,
li: " u. Wi:,""' @ .r .%:<, 14@@ @ 4 j '
- 16. Spring Release J ,. .1 yg t -
- 17. n ulating Link I l
Adjusting Stud and Locknut
)
M
<O -
h
]
- 18. Insulating Link
- 19. Mechanism Side h ,6 1)
F-ame Front of Rear of Breaker Breaker Figure 1. Linkages of DS-416 Breaker Mechanism Shown i with CB Open and Springs Charged (Source:
) Instructions for Low-Voltage Power Circuit Breakers Types DS and DSL, Westinghouse Electric Corp., Instruction Bulletin 33-790-IE) i 155
Attcchment 2 IN 87-35. Supp. 1 December 16, 1987 Page 1 of 1
(
l l
~
e ~
\
l ~_d
'sk e " ~@ s , ,.<
, '(O,
9'
/
o#
^
Front of Rear of Breaker Breaker Figure 2. Position of Mechanism with RTE Closed (Source: Instructions for tow-Voltage Power Circuit Breakers, Types DS and DSL, Westinghouse Electric Corp. Instruction Bulletin 33-790-10 156
Attechment 3 IR 87-35, Supp. 1 !
December 16, 1987 l Page 1 of 1 Left Side Frame Plate (When Viewed from Rear of RTB)
Roller i
Right Side Frame Plate 1
/ (When Viewed from Rear of RTB) '
/ Roller Axis .,
/
A 1
\
/ -.
/ /
\ \
, / '
/ /
Point of Wedging Between Side Frame
/ j[ and Raised Edge of Close Cam i
/
f
/ '
/
/ l I
/ l
/ l l r -
Cam Segments 7 l
^
l l l 0
/ /
/ l
/ l
/ / Spacers
/
i
/ l /
/ Crankshaft
/
/ l 7b [g,, ,,,
l L __
. \ l Figure 3. Roller Wedged Between Left Cam Segment and Right Side Frame Plate (Conceptual Drawing. Not- Fully to Scale; Source: Franklin Research Center, Interim Report, September 30, 1987) 157
Attachment 4 IN 87-35, Supp. 1 December 16,1987 Page 1 of 1
/
/ \
/ \
(A) -
/
Edge of Roller / -
g Caught by /p \
Cam segment f W g y
f/ , % '
h Direction of Cam Surface Rotation Right Side Trame Plate
[ (Viewed from Rear of RTB)
/ N
/ N (a) f/ k N
Roller Axis Straightens, Causing Sideways Displacement of Cam
~f. N and Right Side Trame Plate.
j
/ k Displacement Results in Force That
/ \ Pinches and Retains Roller.
p s _ . = --
]N{
/
/
I N
$ h
/
/
/ \
/
/ l l
i
] Tigure 4. Binding of Roller (Source: Franklin Research Center Interim 1
Report September 30, 1987) i l
158 t
SSINS No.: 6835 i IN 87-48 UNITED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION WASHINGTON, D.C. 20555 ,
October 9, 1987 NRC INFORMA110N NOTICE NO. 87-48: INFORMATION CONCERNING THE USE OF ANAEROBIC ADHESIVE / SEALANTS ;
Addressees:
All nuclear power reactor facilities holding an operating license or a con-struction permit.
t
Purpose:
This information notice is provided to alert recipients to a potentially significant safety problem pertaining to the use of anaerobic adhesives and sealants. It is expected that recipients will review the information for applicability to their facilities and consider actions, if appropriate, to preclude a similar problem. However, suggestions contained in this notice do !
not constitute NRC requirements; therefore, no specific action or written '
response is required.
l Description of Circumstances:
On July 1, 1987, Carolina Power and Light Company reported that following a reactor trip / turbine trip at the Brunswick Steam Electric Plant, Unit 1 :
(Brunswick), one safety relief valve (SRV) failed to open when manually actu- '
ated for pressure control. The SRV is part of the automatic depressurization system (ADS) at that plant. Subsequent testing of other ADS valves on July 3 resulted in a second valve failing to open on manual actuation. During post-failure examination it was determined that Loctite RC 620 was used as a secondary lock between the stem and the plunger in the solenoid assembly when the valves l were rebuilt by Target Rock Corporation at Wyle Laboratory. This material then migrated to the clearance around the plunger before setting.
Discussion:
This event is similar to the one described in Information Notice 84-53, "Infor-mation Concerning the Use of Loctite 242 and Other Anaerobic Adhesive /
Sealants." In that event, Loctite 242 threadlocking adhesive / sealant was used in the assembly of scram pilot solenoid valves. An investigation into the
, failure of several scram solenoid valves revealed that maintenance technicians failed to wipe excess Loctite from the assembly, which resulted in the bonding of the solenoid core plunger to the core tube.
4 i 8710050169
)
1 i
159 l
IN 87-48 October 9, 1987 Page 2 of 2 The Brunswick SRVs also failed because the contractor technician did not clean the excess Loctite RC 620 from the plunger assembly. Because this substance is anaerobic (cures in the absence of air, e.g., the inerted containment atmo-sphere), the plunger did not become seized until after the valves with excess Loctite were placed in the inerted atmosphere that exists in the reactor containment when the reactor is brought to power conditions.
l No specific action or written response is required by this information notice.
If you have any questions about this matter, please contact the Regional l Administrator of the appropriate regional office or this office.
l 2 ss Division of Opera'tional Events Assessment Office of Nuclear Reactor Regulation Technical
Contact:
Ray Scholl, NRR (301) 492-8213
Attachment:
List of Recently Issued NRC Information Notices 160
SS8NS No.: 6835 TN 87-51 i UNITED STATES !
NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION WASHINGTON, D.C. 20555 October 13, 1987 NRC INFORMATION NOTICE NO. 87-51: FAILURE OF LOW PRESSURE SAFETY INJECTION PUMP DUE TO SEAL PROBLEMS Addressees:
All nuclear power reactor facilities holding an operating license or a con-struction permit.
I
Purpose:
This information notice is provided to alert addressees to potential failures of pumps as a result of problems with pump seals. Recipients are expected to ,
review the information for applicability to their facilities and consider actions, i if appropriate, to avoid similar problems. However, suggestions contained in this information notice do not constitute NRC requirements; therefore, no specific ;
action or written response is required. '
Description of Circumstances:
! On July 4, 1987, Palo Verde Unit I was at approximately 330*F with decay heat removal being provided by the Shutdown Cooling (SOC) system. The system uses either the low pressure safety injection (LPSI) pumps or the containment spray (CS) pumps to circulate reactor coolant through a heat exchanger. With the "A" LPSI pump in service, the unit experienced a sudden electrical trip of the pump, accompanied by the presence of a small amount of smoke in the pump room.
The unit was subsequently cooled down and an investigation into the pump l failure initiated. '
i The licensee found the "A" LPSI pump motor windings damaged and the pump shaft '
seized. Before the event, the licensee had observed that the pump shaft seal I leakage was greater than normally expected. After the event, foreign material was observed in the motor lower bearing oil sight glass. The licensee solic-ited the support of several vendors in conducting the investigation. The pump l is type 8x20 WOF, manufactured by Ingersoll Rand and supplied to the licensee by Combustion Engineering. The motor was manufactured by Westinghouse and the pump shaft seal was manufactured by the Durametalic Corporation of Kalamazoo, Michigan. There are no coolers for these seals at the three Palo Verde units, l
i 8710070045
! l 161 l
1 l
i l
IN 87-51 October 13, 1987
, Page 2 of 3 l
1 Discussion:
The licensee's investigation thus far has raised two concerns of a generic l nature. Both concerns focus on the pump seal and, more specifically, on the EPT "0" rings and carbon seal faces used in the seal. The seal designation is a type PTO.
The first concern is associated with the temperature to which the "0" rings and carbon seal faces are exposed. The 500 system is designed for 400'F and plant procedures allowed it to be placed in operation at temperatures up to 350*F.
The environmental qualification data for the pump indicate that the "0" ring's qualified life at a temperature of 300*F is 99 days. "0" ring life apparently decreases rapidly at temperatures greater than 300*F and the carbon seal faces suffer accelerated wear at temperatures greater than,300'F. The implication is that prolonged operation of the 50C system at temperatures above 300'F could result in rapid failure of the seal.
The second concern is associated with the application of a petroleum-based cleaning' solvent or lubricant to the seal. A representative of the seal manufacturer visually inspected the "A" LPSI pump seal and observed that the "0" rings had expanded beyond their normal size, apparently as a result of the application of an inappropriate cleaning solvent or~ lubricant. This expansion may have caused the cracking of a carbon bushing component of the seal, which also was identified during the seal inspection. Although the manufacturer's drawing associated with the seal indicates that petroleum-based lubricants are not to be used on the "0" rings, it does not address the use of cleaning solvents.
The licensee concluded that the failure of the seal on the "A" LPSI pump allowed water to spray up the pump shaft and enter the motor lower bearing, eventually leading to failure of the bearing. To preclude similar damage ts the Unit 1 and 2 pump motors, the licensee installed water slingers on the shafts between the pumps and the motors. The licensee is also considering the installation of bearing isolators to shield the motor lower bearings from leakage. Because of the affects of temperature on pump seal life, the licensee established an administrative restriction that reactor coolant temperature must be reduced to 300'F or less hafore LPSI pumps are put in service.
To prevent the misapplication of solvents or lubricants to the seals, the licensee modified the plant maintenance procedures to allow only the use of demineralized water.
162
~
IN 87-51 OctCber 13, 1987 Page 3 of 3 .
No specific action or written response is required by this information notice.
- If you have any questions about this matter, please contact the Regional '
Administrator of the appropriate regional office or this office.
Y s k. p $ '
kharTesE.Rossi, Director Division of Operational Events Assessment :
Office of Nuclear Reactor Regulation Technical Contacts: Stuart Richaras, RV I (415) 463-3853 Sam MacKay, NRR (301) 492-8394
Attachment:
List of Recently Issued NRC Information Notices a
I a
I 4
u 1
1 5
l, 163 J
l SSINS No.: 6835 IN 87-52 UNITED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION WASHINGTON, D.C. 20555 October 16, 1987 NRC INFORhATICN N011CE NO. 87-52: INSULATION BREAKDOWN OF SILICONE RUBBER-INSULATED SINGLE CONDUCTOR CABLES DURING HIGH POTENTIAL TESTING Addressees:
All holders of operating licenses or construction permits for nuclear power reactors.
Purpose:
This information notice is being provided to alert addressees to potential pr6blems resulting from insulation breakdown of various silicone rubber-insulated singit conductor cables discovered during special high potential tests. It is expected that recipients will review the information for appli-cability to their facilities and consider actions, as appropriate, to avoid similar problems. However, suggestions contained in this information notice do not constitute NRC requirements; therefore, no specific action or written response is required.
Description of Circumstances:
On September 4, 1987, the Tennessee Valley Authority (TVA) notified the Nuclear Regulatory Commission (NRC), pursuant to the requirements of 10 CFR Part 21, of several failures of silicone rubber-insulated cables during high potential testing. The insulation failures occurred on three different silicone rubber- l insulated single conductor No. 14 cables manufactured by the American Insulated Wire (AIW) Corporaticn and' installed at TVA's Sequoyah Nuclear Plant. Suose-quent testing by TVA found three add: ,nal insulation fai'ures in silicone rubber-insulated cables manufactureu oy AIW and three failures in cables manu-factured by the Rockbestos Company. To date, the licensee has found a total of 9 failures out of 91 tested conductors; however, the licensee has not deter- ,
l mined the cause cf tnese failures. TVA has concluded that the performance of I tne silicone rubber-in;ulated cables is significantly different from other cables at TV1 facilities. where 923 tests were recently completed with no failures.
Discussion:
, Additiai,al laboratory testing of the silicone rubber-insulated cables, author-J ired by TVA, indicated that significant decreases in insulation wall thickness could result from lower-than-expected impact forces. The licensee speculates )
1 6710140124 165
IN 87-52 October 16, 1987 Page 2 of 2 that such impact forces 2 which could affect the dielectric withstand charac-teristics of the cable, may occur during (1) handling by the manufacturer, (2) shipping, (3) receipt and storage by TVA, or (4) the installation process.
A failure of the cable at voltages below those accepted by the industry to demonstrate insulation integrity during equipment qualification testing may indicate the inability of the cable to perform its intended function under design basis accident conditions. For this reason, the licensee and the NRC are continuing to evaluate the silicone rubber-insulated cable failures. TVA is planning to perform additional high-voltage withstand tests on an expanded sample of the installed cables to provide a level of confidence in the integ-rity of the cable commensurate with that provided during the equipment qualifi-cation testing previously performed.
The results of the additional testing planned by TVA, as well as the results of those tests previously performed on installed cables and the NRC to determine the extent of the problam.', will be analyzed by TVA The NRC will take appropriate regulatory action, such as issue a bulletin, if !
it is determined that the inability of these cables to perform as designed !
could create a substantial safety hazard.
No specific action or written response is required by this information notice.
If you have any questions about this matter, please contact the technical contact listed below or the Regional Administrator of the appropriate regional offico.
o f ybM harles E. Rossi, Director Division of Operational Events Assessment Office of Nuclear Reactor Regulation Technical Contacts: Jim Knight, NRR (301) 492-7456 Angelo Marinos, OSP (301) 492-9041 Jaime Guillen, NRR '
(301) 492-8933 l l
Attachment:
List of Recently IssueJ NRC Information Notices 166
IN 87-61 UNITED STATES j NUCLEAR REGULATORY COMMISSION i 0FFICE OF NUCLEAR REACTOR REGULATION l WASHINGTON, D.C. 20555 December 7, 1987 NRC INFORMATION NOTICE NO. 87-61: FAILURE OF WESTINGHOUSE W-2-TYPE CIRCUIT BREAKER CELL SWITCHES Addressees:
All holders of operating licenses or construction permits for nuclear power reactors.
Purpose:
This information notice is being provided to alert addressees to potential problems resulting from the failure of Westinghouse W-2-type circuit breaker cell switches. It is expected that recipients will review the information for applicability to their facilities and consider actions, as appropriate, to avoid similar problems. However, suggestions contained in this information notice do not constitute NRC requirements; therefore, no specific action or written response is required.
Description of Circumstances:
On October 16, 1987, v. :nghouse Electric Corporation notified the Nuclear Regulatory Commission (hi,) staff, pursuant to the requirements of 10 CFR Part 21, of the failure of a modified Westinghouse W-2-type switch that was being utilized as a circuit breaker cell switch. The failure was identified at Indian Point Station, Unit 3, on May 15,1987, while the reactor was at cold shutdown for a scheduled refueling outage. Tne output breaker for emergency diesel generator (EDG) No. 31 was prevented from re-energizing the 480-volt bus 2A after plant personnel had inadvertently de-energized 480-volt buses 2A and 5A. Subsequent investigation by the licensee determined that an erroneous input to the EDG logic system had prevented the EDG output breaker from closing. The licensee identified deformation of the spring retainer in the spring-return mechanism of the cell switch in the 52/2A breaker cell as the root cause of the erroneous input.
The spring retainer is continuously under stress whenever the breaker is racked in (which it is, except when the breaker is racked out for testing or naintenance) and releases whenever the breaker is racked out. Its deformation allowed a loss of spring tension that rendered the cell switch unable to spring-return to the racked out position when normal supply breaker 52/2A was racked out for maintenance. Thus, the EDG logic system received an erroneous input indicating that breaker 52/2A was racked in and the main con-tacts were still closed. This erroneous input prevented the EDG No. 31 output breaker from closing automatically in response to a loss of power. During 8712010036 167
7 .-.
-December 7, 1987-Page 2 of 2 subsequent inspections by Indian Point personnel, 35 of'a total of 37 similar W-2-type switch spring retainers in the 480-volt system breakers exhibited some sign of deformation.
All the cell switches had been shipped to Indian Point in,1971-1972 and all had been in service for close to 15 years. The licensee reported the results of its investigation to the NRC in Licensee Event Report 87-009-00 on October 2,1987.
Discussion:
Westinghouse has determined (1) that the deformation of the spring retainer in the spring-return mechanism of the cell switches'was related to the aging ~of the cor,ponent and (2) that the failure mechanis;n was the continuous stress it
- experiences while the breaker is racked in. The W-2-type cell switches are available as optional equipment for all Westinghouse 05 switchgear cabinets.
Westinghouse has indicated that inspection or testing. performed when the breaker is racked out would determine if a failure has occurred. Where inspec-tions and/or testing have not been performed, the potential exists that if the breaker is not racked in, a cell switch malfunction may prevent the completion of safety-related functions dependent on cell switch indication of the breaker l being racked out or in the test positicn. J In the 10 CFR Part 21 notification submitted to the NRC, Westinghouse recommends that proper cell switch operation be verified through periodic inspections or testin0, or whenever the breaker is racked out. Proper operation of the spring j retainer is only verifiable when the breaker is moved from its racked in position.
Visible inspection may be used to verify cell switch operation. However, it will ,
be necessary to move the breaker out on the rails to observe whether the switch r operating lever is in its proper position (30 degrees off vertical for _the W-2 cell switch). Any uncertainty in this observation may be resolved by manually 1 ensuring that the switch has returned to the proper pcsition. Persons performing this inspection should use caution not to contact any energized terminals.
No specific action or written response is required by this information notice; If you have any questions about this matter, please contact the technical contact listed below or the Regional Administrator of the appropriate regional office. 4 .
I arles E.' Rossi, Director Division of Operational Events Assessment Office of Nuclear Reactor Regulation Technical Contacts: K. R. Naidu, NRR I
(301) 492-9656 i
Jaime Guillen, NRR (301) 492-8933
Attachment:
List of Recently Issued NRC Information Notices
. 168 .
I i
. . , - _ - m. , . _ . - . . . . _ . - _ _ _ . . . - ~ , . . . , . . _ . - . _ , . . ... ~ , , - _ _ . - ~ .
IN 87-62 UNITED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION WASHINGTON, D.C. 20555 Decerber 8, 1987 NRC INFORMATION NOTICE NO. 87-62: MECHANICAL FAILURE OF INDICATING-TYPE FUSES Addrossees:
All holders of operating licenses or construction permits for nuclear power reactors.
Purpose:
This information notice is being provided to alert addressees to potential i
I problems resulting from the mechanical failure of indicating-type fuses.
It is expected that recipients will review the information for applicability to their facilities and consider actions, as appropriate, t.o avoid similar problems. However, suggestions contained in this information notice do not constitute NRC requirements; therefore, no specific action or written response is required.
Description of Circumstances:
The Nuclear Regulatory Commission has been notified of four separate events in the past two years related to the mechanical failure of indicating-type fuses.
The events occurred at McGuire Nuclear Station, Unit 1; Catawba, Unit 2; and Sequoyah Nuclear Plant and are described herein.
On March 25, 1986, Duke Power Company's McGuire Nuclear Station, Unit 1, ex-perienced a reactor trip on a steam generator low-low level signal when the mechanical failure of a Bussman FNA-type fuse caused a main feedwater contain-ment isolation valve to close. McGuire personnel determined that the failure was the result of the fuse element having pulled loose from the solder joint inside the fuse. The solder joint was found unbroken; the element wire had pulled out of the solder joint. The licensee found that 8% of the spare fuses in stock also had failed mechalically. Previously, in December 1981 and December 1985, the licensee had reported to the NRC the mechanical failures of FNA-type fuses [ Licensee Event Reports (LERs) 369-81-179 and 369-85-036).
On July 3, 1986, the NRC issued a Confirmation of Action Letter (CAL) to Duke Power Company as a followup to an event at Catawba, Unit 2. In that event one of the auxiliary feedwater trains failed to start during testing because of a mechanically failed FNA-type fuse. On July 7, 1986, Duke Power notified the NRC of the preliminary results of a review of all safety-related circuits where FNA-type fuses were used. The review included the inspection of approximately 8712020019 169
IN 87-62 December 8, 1987 Page 2 of 3 2500 fuses. The inspection found 14 failed FNA-type fuses, 9 of which were determined to have failed mechanically. The inspection of the spare fuses in the warehouse stock found an additional 11 mechanically failed fuses.
On October 29, 1986, the Tennessee Valley Authority (TVA) submitted a notifica-tion on Bussman MIS-5-type fuses to the NRC pursuant to the requirements of 10 CFR Part 21. The Bussman MIS-5 actuating fuse consists of two very thin wires in a sand-like filler. One of the wires, which is approximately 96% silver, acts as a fuse link; the other, a nichrome alloy, acts as a retaining wire for a spring-loaded actuator / indicator rod that is located at one end of the fuse assembly. In the notification TVA indicated that fuses at the Sequoyah Nuclear Plant had exhibited partial actuation, not detectable in all cases by visual examination, that was the result of the elongation of very thin wires. The elongation of these wires could significantly change the characteristics of the fuse and its current-carrying characteristico. This is particularly true if the silver wire breaks but remains in contact with the elongated and unbroken nichrome wire. TVA contacted Bussman and establishkd the resistance and current values that could be used to conclusively test the operability of the remaining fuses.
On July 20, 1987, TVA submitted an LER on Littlefuse Incorporated FLAS-5 type fuses to the NRC (LER 327-87-030). The LER noted that there had been two separate Engineered Safety Feature actuations of the Sequoyah Nuclear Plant's onsite emergency diesel generators as a result of blown FLAS-5-type fuses in the emergency diesel generator start logic circuitry. The FLAS-5 fuse consists of a fuse wire in parallel with a 560-ohm resistor, a spring-loaded indicator nin, and sand-like filler. The indicator pin is mechanically attached to the spring. At the end of the spring, the resistor and the fuse wire are soldered together. The solder material used is a eutectic alloy that has a low melting point. During normal operating conditions, the fuse wire carries the operating current. During a fault condition the solder material rapidly melts. During overcurrent conditions, the resistor heats up with increasing current and serves as the heat source that melts the solder material. When the solder joint melts it interrupts the circuit and releases the indicator pin. The indicator pin itself causes annunciation only and does not trigger any safety features.
Because 69 out of 3200 installed FLAS-5-type fuses have failed to date, TVA perceives that a mechanical weakness, such as a defect in the solder joint, is the main cause of the blown fuses in at least two FLAS-5-type fuse lots. The vendor believes that the problem has been corrected by modification of the solder material and processes.
Discussion:
The fuses involved'in the events described above are of the pin indicating type. These fuses have an internal spring-loaded indicating pin that protrudes ,
from the end of the fuse when the fuse links separate. These fuse links are '
designed to melt when the current exceeds the design load; however, in the cases !
described above, the fuses apparently failed as a result of either a cold solder I joint, creep, or fatigue induced by the internal spring tension. Bussman and 1 Littlefuse supply other indicating-type fuses, and other fuse suppliers also l make indicating-type fuses. The fuses that have failed mechanically are of l the same type that have successfully undergone seismic testing.
170 t
{
l
IN 87-62 December 8, 1987 Page 3 of 3 The NRC staff reviewed 575 fuse-related LERs for the period 1981-1986. They showed no additional cases of specific mechanical failure; however, 183 reports indicated that the licensee had determined the failure to be from unknown causes, and many of the reports identified a blown fuse as the cause of the associated circuit failure. Fuse replacement was the usual corrective action taken. Because of the large number of fuses involvad, the total number of fuse failures may not be abnormal. However, the experience of Duke Power Company and TVA shows that the safety significance evaluation is dependent on an ac-curate root-cause determination. In the event of an indicating fuse failure, additional investigation, including internal examination of the fuse, may be warranted if an electrical fault cannot be found.
No specific action or written response is required by this information notice.
If you have any questions about this matter, please contact the technical contact listed below or the Regional Administrator of the appropriate regional office.
1 kharlesE.Rossi, Director l Division of Operational Events Assessment l Office of Nuclear Reactor Regulation 1
1 Technical Contacts: James C. Stewart, NRR I (301) 492-4644 !
Joseph J. Petrosino, NRR (301) 492-4316
Attachment:
List of Recently Issued NRC Information Notices 1
l l
171
IN 87-66 UNITED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION WASHINGTON, D.C. 20555 December 31, 1987 NRC INFORMATION NOTICE NO. 87-66: INAPPROPRIATE APPLICATION OF COMMERCIAL-GRADE COMPONENTS Addressees:
All holders of operating licenses or construction permits for nuclear power reactors.
l
Purpose:
This information notice is being provided to alert addressees to potential problems resulting from inappropriate application of commercial grade com-ponents within qualified Class 1E electrical panels and to identify the differences in the quality and qualified life expectancy between a particular manufacturer's nuclear grade and commercial grade relays.
It is expected that recipients will review this information for applicability to their facilities and consider actions, as appropriate, to avoid similar problems. However, suggestions contained in this information notice do not constitute NRC requirements; therefore, no specific action or written response !
is required. '
l Description of Circumstances: 1 During a September 16-October 3, 1986 NRC inspection at the Sequoyah Nuclear Plant, Units 1 and 2, it was revealed that the licensee had replaced previously qualified equipment with components and parts of commercial grade, without pro-viding adequate documentation of their qualifications and dedication. The items (
selected by the NRC inspectors included two Agastat time-delay relays from one l Class 1E panel. Both relays were Agastat model number 7012PD relays. The !
manufacturer's markings on these two relays indicate that they were neither manufactured nor controlled as qualified Class 1E components, because the model number is not preceded by an "E." The licensee was unable to identify or produce the procurement documents for these relays; consequently, the inspectors presumed that these components had not been supplied or dedicated as qualified devices. l Therefore, the qualification of the panel was deemed "indeterminate," since the l components may not have been capable of performing their intended function. l l
8712290155 173 m- ,
IN 87-66 December 31, 1987 Page 2 of 3 During an NRC inspection on May 11-22 and June 1-5, 1987 at the Joseph M. Farley Nuclear Plant, Units 1 and 2, it was revealed that the licensee had allowed commercial grade components to be purchased for Class 1E panels without adequate evidence of component qualification. As a result, hardware items were installed in safety-related applications where they may not have been capable of performing their intended function. One example at Farley was the installation of a commercial grade Agastat relay in a Class 1E panel. The Agastat model number on the relay was not prefixed by an "E"; hence, the relay was not considered Class 1E qualified by the manufacturer nor was it found to have been dedicated by the licensee for Class 1E application.
The NRC requested and received information from the Amerace Corporation of Union, New Jersey, concerning the projected qualified life of its nuclear grade (E series) Agastat and commercial grade electrical relays. Amerace indicated that its typical 7000 nuclear grade E series electrical pneumatic timing relays have a projected qualified life of 10 years from date of manu-facture or 25,000 operations, whichaver occurs first. Its commercial grade 7000 series relays have a 2 year projected qualified life.
Discussion: l The relays discussed above are all electrical pneumatic Amerace Agastat timing relays. These relays are being used here as an example of how degradation of a qualified component or system can occur if a licensee does not implement adequate controls in procuring replacement components. There are no apparent physical form, fit, or function differences between the commercial grade and nuclear grade Agastat relays. However, there are several very distinct dif-ferences in the design, manufacturing, testing, and modification controls that are imposed by Amerace for the two different relay series, as discussed below:
Commercial-Grade 7000 Series Relays
- 1. No design change or configuration controls are required.
- 2. Functionability product testing is neither as comprehensive nor as docu-mented as for the comparable E7000 series testing.
- 3. Internal component substitutions are not documented or controlled, and parts that can be rejected for the E7000 series can be utilized in the 7000 series.
- 4. Commercial grade relays are assembled and manufactured at facilities in Mexico, Canada, Belgium, and Union, New Jersey.
- 5. Undocumented field modification of the 7000 series relays is allowed by the distributors as they deem necessary.
- 6. Amerace does not project a qualified life expectancy longer than two years for these relays.
174
l IN 87-66 l December 31, 1987 Page 3 of 3 Nuclear-Grade E7000 Series Relays
- 1. The design, manufacture, modification, and testing are performed only at the Union, New Jersey facility under a 10 CFR Part 50 Appendix B and ANSI N-45.2 program.
- 2. Amerace imposes in process manufacturing inspections that are more stringent than for its commercial grade series.
- 3. Design and configuration traceability control is in place for each piece part.
- 4. The projected qualified life expectancy is 10 years or 25,000 operations.
- 5. Only the E7000 series relay is tested and analyzed to comply with the requirements of the applicable IEEE and ANSI standards.
- 6. Final functionability tests are performed to encompass all operational parameters for each E7000 series relay.
The NRC staff learned of these differences during a vendor inspection and sub-sequent discussions with Amerace personnel. These types of differences in a manufacturer's product should be readily discernible by a licensee's pre-award survey and procurement program actions, regardless of the type of replacement component purchased.
No specific action or written response is required by this information notice.
If you have any questions about this matter, please contact the technical contact listed below or the Regional Administrator of the appropriate Regional Office.
CharlesE.Ro[ssi,Directo Division of Operational Events Assessment Office of Nuclear Reactor Regulation Technical
Contact:
Joseph J. Petrosino, NRR (301) 492-4316
Attachment:
List of Recently Issued NRC Information Notices 175
INDEX FACILITY REPORT NUMBER PAGE Babcock & Wilcox Lynchburg, Virginia 99900400/87-01 1 CIM00RP St. Paul, Minnesota 99901095/87-01 27 Combustion Engineering, Inc.
Windsor, Connecticut 99900002/87-01 33 Cooper Industries Grove City, Pennsylvania 99900317/87-02 41 l C&S Valve Company Westncnt, Illinois 99901099/87-01 55 General Electric Company San Jose, California 99900403/87-02 69 General Electric Company San Jose, California 99900403/87-03 77 General Electric Company San Jose, California 99900403/87-04 105 General Electric Company San Jose, California 99900403/87-05 113 HUB Incorporated Tucker, Georgia 99900866/87-01 117 Ingersoll-Rand Phillipsburg, New Jersey 99900064/87-01 125 Static-O-Ring Olathe, Kansas 99900824/87-01 141 Wyle Laboratories Huntsville, Alabama 99900902/87-02 147 177
YENCOR IhSPECTICQ REPORTS RELATED TO REACTOR PLOTS
- 1 A 1 B l B l B B l B C t C l C l C i D l D i D i F 1 F i F l
- l R l E : R ! R l R l Y I A I L i 0 ! R l A l R l U ! A I E l 0 l
- l K i L l A I O l U ! R l L i ! l 0 i f i V 1 E i A I R 1 R 1 R l 4 FLANTS i N i L : 1 W l N i 0 1 Y I N 1 P l S l 1 l 5 ! N i L ! 11 1 1 1
- i S l E i 0 : N i S i N I E ! i l E l i l S l D i E I E i ! l t
- 1 A ! F ! W ! 5 l W ! ! R ! 0 ! R l A i ! E l ! Y l 1 C l
- l S : 0 1 0 l l 1 l 1 1 i l N ! I L l B l N l A i ! 2 l A !
- l l N l 0 : F : C 1 L l 1 l l l E : l R ! ! I ! L l
- i 1 ! T I D l E K i 2 l C I 1 l l R ( S ! ! I N i 6 l l H '
- l 6 l E l l R 1 l L l 6 l l 1 l S 1 2 l 0 2 l l 0 l
) : 2 1 l 1 l R l 1 1 l 1 l 2 1 l V I E l 6 ! L ! ! ! U !
- I 1 l L l Y i & ! l F l l l E ! ! 3 1 0 l i N i
- l l 6 l 2 121 ! F l ! l R l 1 l 1 l i ! t VEhDORS
- l l 2 ! 1 i ! ! ! i l I l l l l l 1 i
- l l 1 : 2 l l l 1 l l l 3 l l l l 1 l l
- l l l l k l l l 6 l l 1 l l l l l t l 4 l 1 i ! 3 l l l 2 l l 1 l l l t I
- ... : ... ; ... ; ... : ... : ... ... ... l ... : ... l ... ... l ... ... ; ... ...
BAMCCK L WILC01 CO. 1 313 i I i l l l ! ! ! I i I i 1 l l t !
l l l 1 ! l l l 1 i ! l l ! l l l l l
.........................:..........!-----l-----l-----l-----l-----l-----l-----I----l-----l-----l-----!-----l-----l-----l-CLS VALVE CCMPANY : I : : i i i ! ! l l l ! l l I I i i l l l 1 i l l l l l l l CIMCORP i l l ! l l l l l l 1 l l l l 1 l l l l l l l l l l ! ! ! ! l l l CC0FER IWCUSTRIES : I : i l 1 : i : i ; i i l 1 1 CC0FER ENERST EEFV!CES i l l ; l 1 l l 1 ; i l l l l l CORBUSTION EhS!hEERING 368 : i l l l l I I l l l l l l l l t l l l l l l l l l l t i i i i ! :
i 6ENERAL ELECTRIC C0 l l l ! 1 l 1 ; i l l I i : i I i 1 l l I i i NUC ENER BUS CFS 87-02 l l 1 : ! i l i : 1 i ! l l l t i 1
.........................:.....:.....:.....:.....:.....j.....:.....;.. .:..... ....;.....;.. ..:.....;..... .....;.....:.
GENERAL ELECTRIC CD i I l t : l I 1 ! I i i ! l 1 WUC EhER BLS CFS 87-03 l ! ! ! ! i i l l 1 i i : i
.........................:.....:.....:.....:.....l.....;.....;.....;.....:.....; ....;.....:.....:.....:.....:.....:.. .j.
6ENERAL ELECTRIC CO l ALL BWR-TVFE kUCLEAR FtANTS FOR M!CH SEhEFAL ELECTRIC -
1 NUC ENER BUS OFS 87-04 l PROVICES TRAlklh5 0F FtANT FERSC%EL SEhERAL ELECTRIC CO l ALL EkR-T)PE NUCLEAR FLA415 FCR E!CH BEhERAL ELECTRIC !
WUC EhER BUS CFS 87-05 : FROVICE FEFLACEPENT PARTS AhD COVCNEhTS HUB INC0lP0 FATED i l l l l l t : i : ; i l l l l i : 1 i i ! l t I i : i l l t )
.................... ...:.....:.....l.....:.....;.....:.....i.....i.....:.....: ....:.....;.....:.....:.....:.....:.....:. l IhBERSOLL-RAk3 l l l l l l t l 1 ! l ! : l l l l l Eh61NEEFED FL".P DIVISIC4 ! ! ! l l l l l l l l l l l l '
1
.. .. . . . . . . . . . . . . . . . . . . . . . l . . . . . : . . . . . : . . . . . : . . . . . : . . . . . : . . . . . : .. . . . ; . . .. . : . . . . . : ....:.....:.....:.....;.....;.....;.....:. !
STATIC-0-RIN3 ! l l l l l ! l l l l 1 l l l l ! !
l ; i ! l i ! l l l . i ; i ! !
.........................:.....;.....;.....:.....;.....;.....l.....;..u.;.....: ....:.....:.....:.....:.....:.....:.....;. l l
WYLE LABORATORIES i ! l 1 : l l l l t i i ! I : I l 1 ! l 1 l l l ! l l l l l i l
.........................l.....;.....;.....:.....:.....:.....:.....:.....;.....; ....:.....:.....:.....;......:.....:..... .
1*S I-APFLIES TO ALL FLANTS 00CrETWD.- AFFLIES CNLY TO THE ICENTIFIED Uhli
VENDOR INSFECTION REPORTS RELATED 70 REACTOR ltANTS l
3
- I 6: H I H ! J ! L 1 L 1 M l M ! N ! 0 ! O I P 1 P l P 1 P ! 0
- l R t A 0 1A 1 : A i 0 l I ! C 1 Y I A 1 E : E ! ! 1 U l
- lA1i!PlAiS1M!!INlNi0l5:LIA!RlL!A1
- FLANTS i N C l E l 1 A i E I N t i ! E ! N ! T l 0 l C l R I 6 1 0 1
- lD l' H l l F : L i R l E 1 1 I l E I E 1 l H ! Y l R I !
e t l ! C t I i L t I i ! C l M ! E I R i V I i i 1 i C 1
- ! 6 1 1 i R ! T ! E : C I Y t E I 1 1 I I E I B l 1 l M i i !
- l U l & I Ei ! ! 1 K l A i L I L ! ! I C l R ! 0 1 & ! I i !
- ! L i 2 : E ! P l C i i N 1 L t E : 2 i R ! D i l 2 1 1 1 1 1
- l F ! t t A t 0 I i ! K t 0 1 1 L t E l E l T l l & I E !
- I l l I I I N ! L l E i l P 1 3 ! E : : 0 l 12 51
- 1 1 l l 1 : R l N : 2 1 E l 1 i : i K I 1 l M l ! I i
- l t l l & l 1 : T ! 1 1 l l 1 ! 2 1 i l i i VDDDR5
- l 2 l 1 1 l C ! Y 1 1 1 1 l 1 l 6 i 2 : ! ! E i
- 1 : ! K I 1 i i i 161 ! l 3 1 & ! 1 I 2 l
- 1 1 l l l k I i 1 1 2 l ! ! ! 3 1 I l :
- l l l l t 2 ! ! l l t : i l ! l 1 !
........................ l ... ... : ... ! ... ... ... ... ... ; ... . .. t ... ; ... ; .. 1 --- l --- 1 --- 1 BAECOCK L WILC01 CO. l l l l l 1 l ! ! ! I I i 1 l 1 : I l l l l l l t i l I l t i l 1 i I
.......... ......- .g.....:.....:..... .....:.....:.....:.....:.....:.....;.....: ... .. .; ....:.....:.....; ...:.
CLS VALVE (CMFANY l ! ! 1 l l 1 i ! l 1 1 j l ! I I l 1 !
l l I i I l 1 l l 1 1 l l ! I i l CIRC 0CP l l l 1 i i l t : i l l 1 : I 1 i l l 1 l t t I ! l l l l 1 l 1 I
.....l.....: ...:.....:.....:..... .....: ...:.....:.....;..... ... ....; ...:.....:.....l-C0CFER ik'45TRIES 1 i l l l 1 i I ! ! 1 l l l ! !
C0CFER ENEE6V SERVICES : l t : i l 1 ! l l l l 1 1 l
.........................;.....;..... .....:..... .....:.....:.....:.....:.....:.....: ...;.....: ....;.....:.....:.....l.
CGKBJSilCNEN5thEEElkS : : I l l l 1 ! ! l t I i 1 : I l 1 ; I ! ! ! l 1 I l l t ! l l l l
.........................:.....:.....:.....:.....l.....:.....g.....:.. .:.....:......;.....;.....: .... .....:.....:.....:.
GENERAL ELECTRIC C0 I I I l 1 i I I l 1 : I l l 1 ! l I 1 I l 1 l 1 :
NUC EhER BUS OFS B7-02 l t ! l 1 i i ! ! ! l 1 : l l l
.......... ......,.......:.....:.....;.....:.....:..... .....:.....;.... 1-----I-----1-----I-----! ----1-----1-----l-----!-
GENEFAL ELECTRIC C0 ; I l l 1 l l 1 ! : ! I 1 1 l t I l 1 NUC ENER i4:S CFS 67-03 l l l l ! l 1 t l l 1 l 1 I l l t 6EkERAL ELECTRIC CO l ALL EsR-11FE kJCLEAR FLA%IS FOR WHICH GENERAL ELECTRIC !
WC ENER BUS Cf5 87-04 : FF0VIDES TF AlblN5 CF PLANT PER50hkEL 4
.........................;.....:.....:.....;.....:.....;.....:.....; ...;.....:.....:.....t.....; ....:.....:.....:.....;.
GEkEFAL ELECTRIC CD ; ALL EnR-TIFE h"JCLEAR PLANTS FOR WHICH GEhERAL ELECTRIC 1 KJC EhER BUS CFS 87-05 : FRCVIDE REFLACEMENT FARTS A V CCMPChENTS :
.........................;.....:.....:.....;.....:.....;.....:.....;.....;.....:.....;..... .....: ....:.....: ~...;.....;.
HUB 1 005PCM TED 1 i l l 1 : : l l 1 l l l 1
- ! ! i l l l 1 l 6 l 1 l i ! !
.........................:.....;.....:.....:.....:.....:.....l.....:.....:.. .:.....;.....:.....; ....:.....:.....:.....;.
IN5EF50LL-F40 i ! l ! ! ! ! l i 1 I : 1 i ! i Ek5thEEPED FUPF DIVISICM i i ! ! : : : l l l 1 i l l 1 !
STATIC-04lh5 1 l l l ! 1 ! : ! l l ! ! I I l 1 i : : i l ! ! : i i i l l l l l
.........................:.....:.....:.....:.....:.....:..... .....;.....;.....:.....;.....:.....l ....:.....l.....:.....:.
vfLE LABCRATORIES : : i ! i i l l l ! ! ! l l !
! ! l l l 1 ! ! 1 i i i l l 1
.........................:.....;.....:.....l.....:.....:..... .....;.....:.....l.....l.....:.....: ....:.....;.....:.....:.
M 14FFtIES TO ALL PLANT 5 DETC. A5 FLIES CWLJ 10 THE IDENTIFIED UNii
VENDOR INSPECfl0N REPORTS RELATES TO REAC70R PLMTS e i R 1 R I S ! S I Sl S I S ! 1 V I V l' N I N I Y l Z l e
A I I ! A I H I O I T I U l H I E ! O I A I N 1 A l 1 1
- I N I V l N l 0 ! ! I 5 i R ! R I B ! T I P 1 N I M i e PLANTS I C I E I I R ! T I L I 0 1~E ! M I T I E ! !K I M !
e
! H I R ! O I E I E1 U i U i E I O I L i R 1 N I E I E 1
- I O I I N I H l I I C I E I l N ! E I F i P 1 E I R I e I i B 1 01 A I A I I I H l' M i i l i O I P 1 1 I e i S i E I F 1 M i11 E I A I I I i 1 1 RI S F i 1
- I EI N I R I 1 I I N I L 1 Y I L i 0i S i 0 t I e ! C i D l E 1 1 P l 1 1 N ! E I A I 2 ! I I N I I e 101 I ! ! R I L 1 A I I N I i ! ! 1 1 E i 1 e I i 1 I i i 1 01 2 I I I I K 1 1 I 21 ! !
- 1 1 1 L I 2 1 ! J l I i 1 5 ! EI i ! t i I !
WGMS e ! I 2 1 & 1 I I I & I 1 E I I I 3 I I I
- I I i 3 I i ! I I 2 1 1 1 l 1 1 ! ! !
- 1 1 1 ! ! L I ! l & I I I I I I I
- ! ! ! ! 1 2 l l I 2 I I i i 1 1 1
. g. . g ... g . g ... ! . ! ... g ... g ... g . g . g . g ... g ... g BABCOCK L NILC01 CO. I I I I I I I i 1 I I i ! ! I 1 1 1 I I ! 1 I I 1 i l i l I ! !
==.p. . p.... p.... .....p. .p .. p.... p....p. .pt...p.... p.... p. .;.....g CLS VALVE COMP MY I I I I I i i ! I I i 1 I I I I I I I I I I i i 1 1 I I I I
..-..--- ...p....g- -
p.... p. p .. ; = p....p. . p.... p.. p....;- g p....
CIMCORP ! ! I I I I I i 1 I i ! ! ! ! 1 I i ! i l I i ! ! 1 1 I I I
..~.. .... .. .....g.....p.... p....;- .p....p ..p....p....p....;.. .p....p. .p. .p....
COOPER INDUSTRIES i ! ! I I I I I i ! ! 1 1 I I I COOPER ENER6Y SERVICES 1 1 I i 1 1 1 1 I I i ! I I I
.. ...- .. ...p....p. .g.....p. .p....p.... _ p.. p....g ... p .p. p....p....g COM8USTION ENGINEERINS I I I 361 1 1 1 369 I I i 1 1 I I I I I I I i I 362 1 1 I I I I I I i 1 1 I
..... ... .. .. . p. . p.... p. ... p.... p. ... p... . p. . p.... p.... p... . p. . g ...- p.... g ...- [
6ENERAL ELECTRIC C0 t i I I I i i ! I I I I i 1 1 I I I 1 NUC ENER BUS GPS 87 02 l I I i l i i ! ! I ' l t 1 i
....... p. . p . ... p. .g = p. ... p.... p. ... g . p.... p.... p . p. . p . . p. . g SENERAL ELECTRIC CD i i I I I ! i I I i i ! 1 1 1 1 I NUC ENER BUS OPS 87-03 I I I ! ! ! I I i 1 1 1 I I I
.... .. .. .. .p....p....p....p....p....p. .p. .p. .p....g ...p....p....p....p....g SENERAL ELECTRIC C0 i ALL BWR TYPE NUCLEAR FLMTS FOR NHICH BEhERAL ELECTRIC 1 NUC EhER BUS OPS 87-04 i PROVIDES TRAINING OF PLANT PERS0hMEL 1
.... ... .... . p. . p... . p .. p.... p.... p.... p.~. p.... p. . p ,. p . . g .. . p.... p. .!
BENERAL ELECTRIC C0 t ALL BNR-TYFE NUCLEAR PLMTS FOR NHICH 6ENERE ELECTRIC 1 WUC ENER BUS OPS 87-03 PROVIDE REPLACEMENT PARTS AND COMP 0NEhTS i 1
...~... ..
.....p....p....p....p....p....p....p....p....p....p....p....p....p....p....
HUB INCORPORATED l ! ! I I ! ! ! ! ! I I I i 1 1 1 ! ! I I I ! ! I I i 1 1 1 I
.. .. .......... ... p. . p.... p. ... p. . p. . p... . g .. . p. ... p.... p... . p... . p.... p .. p. .g IN6ERSOLL-RAND I ! i i I ! I i 1 1 1 1 15H I i i ENGINEERED PUMP DIVISION I I i ! I I I I I I I i 509 I I i
.... ... p.... p.... p.... p.... p.... p.... p.... p.... p.... p....g..... p....g ... p. .g STATIC-0-Rlh6 ! ! I I ! ! 1 1 I I I I I I I l l 1 ! ! ! ! ! I I I I ! I i
.. .. ...........p. p.. p....p. . p.... p. .p.... p....p....p....p....p....p.... p....g NYLELABORATORIES 1 1 1 1 I I I I I I I I I I I i 1 1 I I I I ! 1 1- 1 I I I I
....... . ........... p.... p. .p. .p....p....p....g..... p.... p.... p.... p.... p. . p....g.....;
1U51 I APPLIES 10 ALL PLANTS DOCrETWO.- APPLIES CWLY TO THE IDENTIFIED Unit
u s. .,ve6:1 6 vuto.T co==.ss,o= > ieoar=v s-<4.. .,reoc. v. -...,. ,,
as,c. eon = == [
Ifo*" 'E BIBLIOGRAPHIC DATA SHEET NUREG-0040 Vol. 11, No. 4 sei iraver o s oa r . .. e j 2 fif t A%QSv6fiThe *K 3 Lieve SLANE Licensee Contract *gr and Vendor Inspection Status Report Quarterly Reportk- October 1987-December 1987 e .cariai.o., cow. g o
- e-oaisi
'\) o r-December l
j 987 g ....
N e can an.srf .s.vio
) mo=r- g vaan t
4 February a[ 1988
- 7. Pte.oAWis Q oAGAsst2 ATIO.s Aus Ako esa.gi agoniS5IMch leC.ept 8 PAos CTIT ASE wo8L4 Umei =vwe e n Division of Reactor Ins ' tion and Safeguards /
OfficeofNuclearReactor}egulation * *ia oa Gaay1wweia U.S. Nuclear Regulatory Conunission a Washington, D.C.
, -,o. .,. o. ... . . .o 20555
... ..o .. L.
[
A oo. 3.-- . . , , ,.yi o. . .-,
W .
'ii ,. ( Quarterly Same as 7. above. f * " a co cov m o "~~ ~
/
l i n iv.,L .i=1.. =en
- t
[ October 1987 -- December 1987
,a i.sv..c1 <m ,
1,
/(*
}' e .
Thisperiodicalcoverstheresulth,ofingg>ectionsperformedbytheNRC's Vendor Inspection Branch that have'd>een cistributed to the inspected organizations during the period frcp ober 1987 thru December 1987. Also, included in this issue are the resuYP 'of certain inspections performed prior to October 1987 that were not L cluded in previous issues of NUREG-0040.
t F
N Tj,
..- y t.s.
- i. oocvvigta%aLv33.saivnonggegS 8 . Gas kt 4agg,g, S STATSWi%T vendor inspecti
?y Unlimited th h '6 8 Cbeit e CLASS .icaT'C%
%, u r.. n,
. ies=vi.,ian o.i= i eie n %
Unclassified
, r. . m, Unclassified
- i, w ....c...si.
....c.
s
UNITED STATES ,,,c,y ,ov cu,3 c,1, j NUCLEAR REGULATORY COMMISSION Pos'$cj,* 'p5 *o WASHINGTON, D.C. 20555 l OFFICIAL BUSINESS PENALTY 80R PRIVATE USE, $300 1
1 1ANINV 120555078877US U
T BR-PDRNRC-0 ARM-ADM NUREG 20555 ho W-53 [7 DC WASHINGTON i
_ _ _ _ _ _ _ _ _ - - _ _ - - _