IR 05000361/1983013
| ML20023C544 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 04/13/1983 |
| From: | Canter H, Chaffee A, Irsch D, Kirsch D, Miller L, Sternberg D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML20023C541 | List: |
| References | |
| 50-361-83-13, 50-362-83-12, IEB-79-09, IEB-79-9, IEB-83-01, IEB-83-1, NUDOCS 8305170421 | |
| Download: ML20023C544 (28) | |
Text
{{#Wiki_filter:e- . U. S. NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos. 50-361/83-13 50-362/83-12 Docket Nos. 50-361, 50-362 License Nos. NPF-10 and NPF-15 Licensee: Southern California Edison Company P. O. Box 800 2244 Walnut Grove Avenue Rosemead, California 91770 Facility Name: San Onofre Units 2 and 3 Inspection at: San Onofre Site, San Clemente, California and Region V Office Inspection conducted: March 12-25,e1983 , n 'l f Inspectors: i . Q Ifate $igned D. M. Sternberg, Chief Reactor Projects Branch No. 1 % 150/* ) 4 ll 3 W D. F. KiYsch, Chief, Reactor Projects Da'te Signed Section No. 3 hi
All/ZIf> gA. E.Cffaf fee, Senior Resident Inspector Dite Signed A // > O / L. F. Miller, Senior Resident Inspector Da'te Signed 0- ////G $ I @ H. L. Canter, Senior Resident Inspector Date Signed Approved by: .\\7 ~ h6 ,e/// [3'/ D. F. Kirsch, Chief, Reactor Projects Dite Signed Section No. 3 Summary: Special Inspection on March 12-25, 1983 (Feport Nos. 50-361/83-13 and 50-362/83-12) Areas Inspected: Special unannounced inspection of the circumstances surrounding the failure the undervoltage trip device to open certain Units 2 and 3 reactor trip breakers. Areas examined included 8305170421 830414 PDR ADOCK 05000361 O PDR _.. _ __ _ _. _ _. - _ _ _
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. surveillance program and history; maintenance program and history; Technical Specification reportability; emergency ATWS procedures; control of vendor representatives; configuration control; control of vendor supplied information; follow-up on IE Bulletin 79-09; and reactor trip breaker troubleshooting activities. The inspection involved 186 inspector-hours by three NRC Senior Resident Inspectors and two regional office supervisors.
Results: Of the nine areas examined, two violations were identified (Failure to report reactor trip breaker inoperability as required by Technical Specifications, Severity Level IV, paragraph 5; and failure to implement vendor service bulletin information as required by procedures, Severity Level IV, paragraph 10).
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. DETAILS 1.
Individuals Contacted a Southern California Edison Company
- R. Dietch, Vice President, Nuclear Engineering and Operations
- H. B. Ray, Station Manager
- J. M. Curran, Manager, Quality Assurance
- W. C. Moody, Deputy Station Manager
- P. A. Croy, Manager, Configuration Control and Compliance
- B. Katz, Manager, Station Technical
- D. Schone, Manager, Site Quality Assurance
- J. J. Wambold, Manager, Station Maintenance
- H. E. Morgan, Manager, Station Operations
- D. E. Nunn, Project Manager
- J. S. Iyer, Lead Compliance Engineer
- E. E. Gulbrand, Assistant Manager, Station Maintenance
- C. A. Kergis, Lead Quality Assurance Engireer
- S. W. Stilwagen, Maintenance Supervisor The inspectors interviewed several other licensee personnel in Station Engineering, Maintenance and Quality Assurance.
b.
Combustion Engineering, Inc.
- P. M. Newton, Resident Manager
- A. Spine 11, Assistant Resident Manager c.
General Electric Company M. Fornwalt, Engineering Representative G. Gorro, Technical Representative B. J. Behroon, Technical Representative d.
Other Personnel H. Rood, Licensing Project Manager, NRR J. T. Beard, Reactor Systems Engineer, NRR P. Shemanski, Electrical Engineer, NRR
- Denotes March 16, 1983 exit interview attendee.
Background This report deals with the circumstances surrounding Licensee Event Reports (LERs) 50-361/83-19 and 50-362/83-23. Specifically, these LERs reported the failure, during testing, of four out of 18 GE type AK 2-25 Reactor Trip Breakers to trip, as required, when the undervoltage (UV) device was deenergized. The information included in this report was obtained by a team of inspectors and supervisors, dispatched to the site on March 11, 1983, augmenting the assigned resident inspectors, and a team of technical experts from NRC Headquarters and their consultants, a?so dispatched to the San Onofre Site on March 11, 1983. This team examined not just the event itself but the overall situation that culminated in the breaker trip failures. The remainder of this report provides the results of a detailed examination of the various aspects of the facility design and operation that contributed to this occurrence.
a.
Reactor Trip Breaker Surveillance Tests on March 1 and 8,1983 Surveillance Procedure S023-II-11.161 (Reactor Breakers Undervoltage and Shunt Trip Device Circuit Test) was issued as a new test for Unit 2 on January 13, 1982. On May 13, 1982, the procedure was revised to change the surveillance interval from 31 days to 18 months, because of a lack of problems disclosed during monthly surveillances. Finally, Revision 2 was issued on February 10, 1983, which incorporated the Unit 2 procedure into the Unit 3 system.
Since the issuance of this procedure in January 1982, a records review indicates that the test had been performed 13 times, including the March 1, 1983 test performed on Unit 3 and the March 8,1983 test performed on Unit 2.
Three of the 13 tests have been performed on Unit 3.
The licensee stated that the tests run on March 1 and 8, 1983, were performed to verify proper breaker operation after the issuance of IEB 83-01 (February 25, 1983). This IEB applied only to the Unit 1, Westinghouse DB-50 Reactor Trip Breakers, but a licensee engineer took the initiative to examine the Unit 2/3 GE AK-2 breakers.
On March 1, 1983, in response to the engineer's request, the surveillance test was completed on Unit 3 breakers. One problem was identified, a failure of TCB 4 to trip on deenergization of the UV device. NCR 3-243 was written on March 3, 1983 to document this problem.
On March 8, 1983, the surveillances performed on Unit 2 reactor trip breakers identified the failure of TCBs 1, 4, and 6 to trip on de-energization of the UV devices. NCR 2-163 was written at this time documenting that condition. These events were reported to the NRC on March 10, 1983, and LERs 83-19 and 83-23 for Units 2 and 3, respectively, were issue _.
. ~3 . . b.
NRC Response Two actions were taken by the NRC prior to the NRC response team's site visit on March 12, 1983. First, a Confirmatory Action Letter was sent to Southern California Edison on March 11, 1983. This letter confirmed the NRC's understanding that the licensee would take no action to close the reactor trip breakers except for testing with the rods deenergized, or add positive reactivity on Units 2 and 3 until the matter was resolved to the satisfaction of the NRC.
Second, also on March 11, 1983, the NRC issued IEB 83-04 on the subject of failure of the undervoltage trip function of GE AK 2 reactor trip breakers. This bulletin requested that all operating reactor facilities (except those with Westinghouse DB-50 breakers) perform tests on undervoltage devices, review the maintenance program on the breakers, notify all licensed operators of the failure-to-trip event at Salem and the testing failures at San Onofre, and finally, to report to the NRC the various results of the program described. The responses to IEB 83-04 were due by the end of March 1983.
On March 12, 1983, a team of six NRC personnel and two NRC contract - personnel joined the Unit 2 and 3 Senior Resident Inspectors onsite to examine in detail the breaker failures at Units 2 and 3.
The following is an outline of the actions taken by this team and discussions held with the licensee: (1) Discussion of the Objectives of the Site Visit.
(2) Facilities Requirements for the Visit (Security, etc.). (3) Paper / Hardware Needed.
(4) SCE Briefing - Description of Reactor Protection System and Breakers.
(5) SCE Summary Discussion of Recent Events.
(6) Plant Tours (Photographs taken) and Test Witnessing.
(7) Detailed Discussions of the Events with Various Plant Personnel.
(8) SCE Definition of Issues.
l (9) SCE Recovery Program (Preliminary).
l The last members of the team to leave the site exited on March 16, 1983, except for the Senior Resident Inspectors who continued l follow-up actions.
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, c.
-Licensee's Investigative Program
- With the arrival onsite of an NRC team of inspectors on March 12, 1983,: the licensee assembled a large team of engineers, technicians, and managerial personnel. That day, a draft procedure was developed which defined'the steps necessary to determine the cause of the breaker failures. Concurrent with this effort, the site document control center began massive file searches to recover all documents relevant to these breakers.
The NRC requested copies of applicable procedures, manuals, and drawings, plus a complete maintenance and surveillance history of the breakers. This history was to include the design basis and criteria that was used for purchase and installation, procurement documents, acceptance testing documents, surveillance test history, a record of maintenance and modifications, and copies of responses to related IE Bulletins and Circulars.
The licensee performed detailed static and dynamic tests on reactor trip breaker TCB 2, a Unit 2 breaker which had performed satisfactorily, with a General Electric technician and a General Electric engineer in attendance. This provided base line data that was used on TCB 1, a failed Unit 2 breaker.
With the results and experience gained on those two breakers, the licensee began work on the next failed breaker, TCB 6.
TCB 4 in both units were left undisturbed because of the request by the NRC to have a failed breaker sent to the Franklin Research Institute (FRI) in Philadelphia. The FRI personnel will perform independent tests on a breaker to verify the licensee's findings. The licensee was evaluating sending the other' breaker to GE for a similar analysis.
3.
Surveillance Program The inspectors examined the surveillance program associated with the reactor trip breakers for Units 2 and 3 and reviewed the program with plant management, plant engineers, and technicians. The following documents were examined: Technical Specification 3/4.3.1, Reactor Protective Instrumentation
S023-II-11.161, Revision 2, Reactor Breakers Undervoltage and Shunt Trip Device Circuit Surveillance Test Numerous Letters listed in a March 14, 1983 Memorandum to A. E. Chaffee from H. B. Ray on the Subject of UV Device Surveillance Testing Numerous Surveillance Test results listed in a March 13, 1983 memorandum to A. E. Chaffee from H. B. Ray on the subject of Surveillance Histor. f - '
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QA/QC Requirements There are no specific requirements that either the QA or QC organizations become involved in the surveillance testing of the reactor trip breakers. Either organization may get involved if their management desires involvement. The QA organization, for example, may review the reactor trip breaker surveillance records as part of their Plant Operations surveillance activity, which is an ongoing, year-round, sampling type of a program.
No items of noncompliance or deviations were identified in this area.
b.
Procedure Review The Surveillance Procedure, S023-II-11.161, Revision 2, was reviewed in depth. While the procedure appeared to comply with Technical Specification requirements, the following comments summarize the results of this review: (1) Prerequisite Verifications Verification signatures were not required for: (a) Paragraph 3.3 - Check of Radiation and Contamination Surveys (ALARA).
(b) Paragraph 3.9 - Removal of Scram Signal by I&C (i.e., I&C was not required to detail actions taken to remove the Scram Signal and verify the removal of those actions, thus returning the Plant Protection System (PPS) to normal).
(2) Instructions (a) Paragraph 6.2 - More detail appears advisable regarding what constitutes " Normal plant status and CEDM lineup."
(b) Paragraph 6.3 - Verification of indicator status at PPS mimic bus was not included.
(c) Paragraph 6.3.2 - Acceptance criteria did not include requirements to measure the time from UV deenergization to breaker opening (i.e., response time testing of the component), however, the Technical Specifications do not require response time testing of the reactor trip breakers.
Monitoring of response time may be valuable in detection of early signs of deterioration in the mechanical / lubrication conditions.
Based upon the results observed during troubleshooting activities, this criteria should address repeatability by, for example, a series of tests. Test data generated
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during this inspection indicates that a large data span is indicative of and a precusor to failure.
(d) Paragraph 6.4 - Verifications did not include indicator status on the PPS mimic bus.
' (3) Restoration Paragraph 6.6 - This paragraph did not include appropriate verifications, by I&C, regarding the return of the PPS to normal.(See paragraph 3.b(1)(b), above) (4) Acceptance Criteria - The brief statement contained in the procedure does not appear adequate in the light of recent events. Consideration should be given to a more detailed specification of acceptance criteria. The statement of procedure paragraph 7.1 merely states that "All TCBs function per the applicable drawings and meet the procedure sections requirements."
' (5) General , Frequency of Surveillance In light of recent events, the 18-month interval specified for this surveillance does not appear appropriate.
Consideration needs to be given to: , The judicious establishment of a more frequent surveillance interval with appropriate consideration given to a more frequent interval of preventive maintenance (PM).
Care should be exercised in determining reduction in the
surveillance and PM interval. Also, care should be exercised in modifying the intervals - the history of PM and surveillance findings must be sufficient and adequate to justify interval revision.
While the procedure appears to implement the Technical Specification requirements, the licensee agreed to review the procedure again for adequacy.
No items of noncompliance or deviations were identified.
c.
Surveillance History and Records The Unit 2 operating license was issued on February 16, 1982. The surveillance testing using Procedure S023-II-11.161 commenced on February 25, 1982. The following list details the history of surveillances on Units 2 and 3 from that date. This list was supplied in a large part via a memorandum to A. E. Chaffee from i H. B. Ray, dated March 13, 1983.
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- Februa ry 25, 1982 - Unit 2 surveillance completed satisfactorily.
- March 25, 1982 - Four nonconforming Unit 2 circuit breakers were identified due to UV device failure. Disposition is discussed in review of maintenance history based on NCR S023-P-152. Unit 2 was in Mode 5 at this time. The NCR was not evaluated for reportability.
April 4, 1982 - Unit 2 surveillance was conducted satisfactorily following the disposition of NCR S023-P-152. All , work on the breakers in March was done per the direction of the GE vendor representative.
' May 4,' 1982 - Unit 2 surveillance completed satisfactorily.
June 4, 1982 - Unit 2 surveillance completed satisfactorily.
NOTE: At this time, since no problems had been identified by three months of independent UV and shunt testing, the licensee decided (based partly on vendor (CE) recommendations) to increase the surveillance interval to 18 months.
July 6, 1982 - Unit 2 surveillance was performed on TCB 5, only, due to replacement pursuant to NCR S023-P-431. The replacement was done because of an open UV coil observed during maintenance. Unit 2 was in Mode 5 at this time.
- July 12, 1982 - Unit 2 surveillance of TCB 1, 2, 3, 5, 8, and 9 following Work Order 10245. The reason for this work is discussed in maintenance history (See paragraph 4).
NCR S023-P-511 was written on TCB 4 and 7 reflecting failure of UV trip function. The GE vendor representative assisted, on site, in the resolution of the observed trip function failure.
July 13, 1982 - Unit 2 surveillance of TCB 4 and 7 following Work Order 10305 which resulted from NCR 5023-P-511.
See maintenance history (paragraph 4) for reason for this work.
July 21, 1982 - Unit 2 surveillance of TCB 1 through 8, again pursuant to Work Order 10245.
The UV device was tested three times. The maintenance history (paragraph 4) discusses the reason for this retest.
August 23, 1982 - Unit 3 surveillance identified no problems.
- October 30, 1982 - Unit 3 surveillance identified no problems.
March 1, 1983 - Unit 3 surveillance identified a failure of the TCB 4 UV trip device.
This surveillance was accomplished in response to the Westinghouse DB-50 breaker problems identified by IE Bulletin 83-0 * g .
March 8, 1983 - Unit 2 surveillance identified failure of the UV trip device on TCBs 1, 4, and 6.
NCR 2-163 and LERs 83-19 and 83-23 for Units 2 and 3, respectively, were issued.
NOTE: Again, until the March 8,1983 test, there did not appear to be an evaluation of reportability by licensee personnel. This is addressed in another section of this report (paragraph 5).
d.
Adequacy of Technical Specification Requirements A review of the technical specifications for Unit 2 indicates a shortcoming in one area. There is no specification which addresses the breaker response time.
In other words, the time from removal of dc power to the UV device until the primary contacts open is not defined. This appears to be a problem, especially in light of the test results seen on Unit 2 breaker TCB 1.
Prior to lubrication and cleaning of the trip shaft bearings and latch roller, respectively, the licensee used a Visicorder to record the time from UV deenergization to breaker opening. Out of eight tests, the recorded times varied from 85 milliseconds to 2.26 seconds to minutes before the primary contacts opened. Af ter lubrication and cleaning, a repeatable time of between 64 and 67 milliseconds was observed.
No items of noncompliance or deviations were identified.
4.
Maintenance Program a.
Procedures and QA/QC Requirements The licensee's maintenance program, as defined by the following procedures, was reviewed: (1) Station Order S0123-M-5, " General Maintenance Order," Revisions 1 and 2.
(2) Station Order S0123-M-4, " Preventive Maintenance Program," Revision 0.
(3) Station Order S0123-M-1, " Organization and Responsibilities of ' the Maintenance Section," Revision 0.
(4) Station Order S0123-M-7, " Requirements for Maintenance Order Use and Control," Revisions 0 and 1.
(5) Maintenance Procedure S023-I-1.1, " Scheduling of Preventive Maintenance," Revisions 0 and 6.
, (6) SCE-1-A, " Quality Assurance Program," Chapter 5-C, " Maintenance Program."
This program was compared with the requirements of Section 5.2.7 of ANSI N18.7-1976, " Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants," and with 10 CFR 50, . ! l .- -- . -. - - - -. - . - - . . - -. . - -. - _ - - - _ _ -, ., .
- . Appendix B, " Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants." Specifically, the program was reviewed to determine whether: . (1) All maintenance was required to be preplanned and performed in , accordance with written procedures or documented instructions.
(2) Inspection and test of maintenance activities to assure quality was required.
(3) Preventive maintenance schedules were required to be revised and updated as experience was gained with the equipment.
(4) Causes of malfunctions were required to be promptly determined, evaluated and recorded.
. The program generally implemented and amplified these objectives.
It did not require the prompt evaluation of any malfunctions identified during maintenance (an evaluation was required, however).
Also, the program did not contain detailed assignments or instructions for implementing the program's objectives.
Instead, once,the objectives were established, overall responsibility for implementation of the program was assigned to the Supervisor of Plant Maintenance and his subordinates, but specific task assignments were n't'made by the program. For example, S0123-M-4, o " Preventive Maintenance Program" requires that the preventive maintenance program be updated to conform to current industry standards, i.e.
Bulletins, vendor technical information, ANSI and IEEE standards. However, the procedure which assigns specific task responsibility to specific personnel at Units 2 and 3, S023-I-1.1, " Scheduling of Preventive Maintenance," contains no reference to this requirement.
The inspector concluded that the licensee's maintenance program was deficient in that it did not require prompt evaluation of malfunctions identified as a result of maintenance, and that the program lacked formality with respect to the specific assignment of some maintenance program responsibilities. Both deficiencies contributed to the maintenance history concerns discussed below.
b.
Maintenance History and Records / Vendor Maintenance Activities , The maintenance history for the reactor trip breakers at San Onofre ' Units 2 and 3 was reviewed. The licensee provided an overview of this history by letter dated March 18, 1983. This information and supporting documentation was subsequently analyzed by the inspector.
The significant maintenance events in this chronology were: June, 1980 Licensee issued Maintenance Procedure MPES 008, "Undervoltage Tripping Device of GE AK-2-25 Circuit Breakers in the Reactor Trip Switchgear," in response to IE Bulletin 79-09 maintenance requirements.
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i January, 1981 Reactor Trip Circuit Breakers (TCBs) installed and energized at Unit 2.
January 2,1981 Performance of MPES 008 Revision 0 on Unit 2 TCBs commenced.
March 9, 1981 MPES 008 Revision 1 issued to correct difficulties encountered performing Revision 0 on Unit 2 TCBs.
April-May, 1981 MPES 008 Revision I completed on Unit 2 TCBs.
June, 1981 MPES 008 repeated on San Onofre Unit 2 TCB No. 2.
This was the last formal preventive maintenance performed on Unit 2 TCBs until March, 1983.
February 16, 1982 Unit 2 receives low power operating license.
March 25, 1982 Monthly surveillance procedure, S023-II-11.161, " Reactor Breakers Undervoltage and Shunt Trip Device Circuit Test" performed on Unit 2 TCBs.
TCB's 4,6,7 and 8 failed this test.
(They had passed this test on February 25, 1982.) Work Order 4832 was written to correct the failure of the TCBs to trip. The instructions on the work ' order were to adjust TCBs "per direction of vendor representative." No documentation of the
' specific maintenance tasks authorized or performed was made, other than for the transfer of a Unit 3 TCB to replace TCB 8.
These
activities were not conducted in accordance with Station Order S0123-M-5, " General Maintenance Order." Paragraph 6.16, "Outside Organization" and 6.4, " Maintenance Procedures", of this procedure required that maintenance procedures with documented acceptance criteria be used for i all safety-related maintenance work (including those perfo_rmed by the vendor representative).
The vendor technical manual and MPES 008 were available but apparently not used for this maintenance.
May, 1982 Unit 3 TCB's installed and energized. Required frequency for surveillance procedure S023-II-11.161 changed to 18 months.
July 8-10, 1982 Unit 2 TCB's No. 4,6 and 7 would not shut on the first attempt. Work Order 10145 was written to correct this deficiency. This work order detailing the work authorized did not specify or reference the method of repair required, as required by S0123-M-5.
Retest requirements were not specified as required. The following . _ _ _ _ _. _.. _ _ _,.. _, _ _ _. _,. _ _, _. _ - _ _ _, _ _ _ _ _ _ _ _ _ -
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- description of the work performed by Station Maintenance personnel was made on the Work Order.
" Adjusted relays to trip and reset at factory rec'd voltages" and " Operations functioned from control room."
'the factory recommended voltages were unspecified. The approved surveillance procedure for retest of these TCBs, S023-II-11.161, was not performed until July 12, 1982, two days after the return to service of these TCBs. On July 12, 1982, TCB's 4 and 7 failed to trip on undervoltage.
On March 30, 1983, the licensee reported this event as a violation of Technical Specifications 3.3.1 and 3.0.3 On July 13, 1982, TCB's 4 and 7
- vere replaced with Unit 3 TCB's.
The maintenance activities conducted on TCBs 4,6, and 7 was not in accordance with S0123-M-5, paragraphs 6.12, " Post-Maintenance Testing," and 6.4, as discussed above under the March 25, 1982 discussion.
During the same period, Work Order 10245 was written to adjust TCB's 1,2,3,5,8 and 9 using an unspecified section of General Electric Technical Manual 50 299B. The "as left" undervoltage coil drop out and pickup voltages were documented, with the pickup voltages ranging from 103.4 to106.5 volts. These values were near the 106 volts required by IE Bulletin 79-09 and MPES-008 for a 125 vdc system.
July 14-21, 1982 Work Order 10451 was written to check the undervoltage coil adjustments for all Unit 2 TCBs.
Informal data sheets and a licensee interview of the foreman indicated that an extensive inspection of the breakers was performed. No method of repair was specified.
The tasks which were performed were documented from memory in March, 1983, eight months later.
This work was performed with the assistance of a General Electric vendor representative.
Undervoltage coil pickup voltages were identified as nonconforming with approved procedure criteria (MPES 008) by Non Conformance Report P-563.
The as left values of 90-119 volts were accepted by the licensee on July 23, 1982 based on verbal authorization of the vendor representative. These values deviated substantially from the criteria of IE B'illetin 79-09 and MPES-008. The approved prceedural criteria of MPES 008 were not modified. This was the last maintenance performed on the undervaltage devices of the Unit 2 TCBs prior to March, 1983 when three TCB's failed to trip on . - , . _.
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i . unde rvoltage. Following this maintenance, surveillance procedure S023-II-11.161 was performed for the last time until March,1983, when it was performed in response to IE Bulletin 83-01.
August 10-21, 1982 Four Unit 3 TCBs were identified as nonconforming during a receiving inspection due to defective undervoltage trip devices.
Maintenance personnel and a vendor representative replaced the defective parts and adjusted the new devices. The as left settings were documented in Work Order 12278, but again the work was not clearly planned as required by Station Order S0123-M-5, " General Maintenance Order."
The inspector concluded that several deficiencies existed in the-licensee's implementation of their maintenance program, in this > case: (1) Corrective maintenance performed was not adequately described ~ in writing prior to performing the work, or after completing
it; an apparent deviation from the maintenance program requirements. Of particular significance, acceptance criteria for undervoltage device settings and the methods used for cleaning and lubrication were not specified. Approved-preventive maintenance procedure MPES 008 was not used even though it was an available and appropriate method to begin troubleshooting during the maintenance, described above, performed during March, July and August, 1982.
, (2) ~ Preventive maintenance frequencies were not adjusted as required by the program to reflect service experience. The responsibility for such adjustments was not specifically delegated.
(3) The vendor representatives who assisted in the performance of maintenance in March, July and August, 1982 were unfamiliar ' with the vendor's recommendations promulgated by IE '. Bulletin 79-09 and with the licensee's formal procedural requirements. Nevertheless, licensee personnel apparently ceded control of maintenance activities to these representatives. This is not in accordance with program requirements.
(4) The licensee personnel who performed the maintenance in March, July and August, 1982 apparently were unfamiliar with, or neglected the requirements of, the approved maintenance program requirements for planning, performance and documentation of maintenance.
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. While the above appear to be violations of programmatic requirements, a Notice of Violation is not issued for these discrepancies based upon the facts that:
the licensee identified the failure to control vendor activities as required by administrative procedures (see paragraph 7),
a significant contributory cause was the failure to adjust the preventive maintenance schedules based upon manufacturer's recommendations and equipment history, for which a Notice of Violation is seing issued (see paragraph 10), and
the licensee identified that documentation of maintenance did not conform to programmatic requirements.
' This area will be examined further during a future inspection.
(50-361/83-13-01) , 5.
Reports'to the NRC The licensee's Technical Specifications, Section 6, paragraphs 6.9.1.12 ' and 13 list the types of events which shall be reported to the NRC Regional Office Administrator.
The licensee implements'the reporting requirements in Section 4D of the i QA topical by requirir.g that nonconformances be reviewed for reportability. Nonconformances are identified by either the traditional Nonconformance Report or a Limiting Condition for Operation Action Requirement (LC0AR) Report.
The LC0ARs are generated by the plant operators when a Technical . Specification Action statement is entered during plant operations. These ' are reviewed for reportability by the Shift Technical Assistant staff and may be the source of a Station Incident Report. The LC0ARs are forwarded to the Confirguration Control and Compliance (CC&C) staff for the final , determination of reportability.
In mid-1982, the licensee observed that
several LC0ARs had not been reviewed for reportability.
Subsequent reviews identified several reportable events, at which time LERs were issued.
Corrective actions taken by the licensee appear to have been effective in assuring that reportability reviews are accomplished, on the LC0ARs and station incident reports, in a timely manner.
! Nonconformance reports (NCRs) are used to identify, and document resolution of, nonconforming conditions.
The QA topical report was revised, in November 1982, to require reportability reviews of NCRs. On June 24, 1982, the licensee's Technical Manager assigned a group cf engineers the responsibility of reviewing NCRs for reportability.
The NCR form was revised to include a signature block for a positive or , j negative reportability determination. The licensee has also implemented measures to assure that NCRs are promptly routed to the Quality
Assurance, Station Technical and Configuration Control and Compliance (CC&C) staffs for validation and reportability review.
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- i Discussions with station technical and CC&C personnel identified two concerns.
a.
Familiarity with Technical s'recification Reporting Criteria.
Personnel in the CC&C staff, responsible for the final determination of reportability, were fully knowledgeable of the Technical Specification reperting criteria. However, discussions with station technical persennel Indicat,d that these persons had only a general familiarity Eith the reporti.1g criteria used in the conduct of their reviews.
Furthermore, the a tation technical persons indicated that they had not received any srmal training, in the form of lectures or required reading, on reporting criteria. The licensee stated that action we.id be tak to assure that appropriate personnel were trained and L.owledgeable of the Technical Specification reporting criteria.
(50-361/83-13-02) b.
Assurance That All NCRs Have Been Evaluated for Reportability.
On about July 1,1982, the licensee began annotating the NCR forms with a section for determining reportability.
Before that time, it is apparent that the NCRs were not formally evaluated for ' reportability. The licensee agreed to review for reportability all NCRs issued, up to the time the form was revised.
(50-361/83-13-03) On March 25, 1982, the licensee performed a surveillance of the Unit 2 Reactor Breaker Undervoltage and Shunt Trip devices and documented that TCBs 4, 6, 7, and 8 were nonconforming. Nonconformance Report S023 P-152 was written on March 25, 1982, documenting the nonconforming condition.
Discussions with the Station Technical Reviewing Engineer established that this NCR was not reviewed for reportability. This event was not reported to the NRC.
On July 12, 1982, the licensee performed a surveillance of the Unit 2 Reactor Breaker Undervoltage and Shunt Trip devices and documented that TCBs 4 and 7 would not trip when their undervoltage devices were deenergized. This condition was documented by NCR No. S023 P-511, written on July 12, 1982. A block for reportability determination was annotated on the NCR, however, cpparently a reportability determination was not performed since the block was not checked. Discussions with the reviewing engineer indicated that the NCR was not reviewed for reportability. This event was not reported to the NRC.
This failure to report the failure of certain Reactor Trip Breakers to open upon deenergizing the undervoltage devices, observed on March 25 and July 12, 1982, is an apparent violation of the reporting criteria of Technical Specification paragraph 6.9.1.12.i.
(50-361/83-13-04) 6.
Emergency Procedures The inspector reviewed Operating Instruction S023-3-5.1 (Emergency Plant Shutdown) to determine whether the procedure adequately addressed Anticipated Transient Without Scram (ATWS) conditions.
. . . -,. -. - - - -. . - _ - - -,,, --- ,, -
,__ .. _ .. _.. . --. -
- . .. The procedure details the following steps: a.
Paragraph 1.2.1 (Indications): " Reactor Trip Breakers Open" 'Th'is condition' is observed by operators in the control room or at the Plant Protection System cabinets where both open and closed indication for all Reactor Trip Breakers exists. A reactor trip signal from the Plant Protection System causes both the undervoltage coil to deenergize and the shunt trip coil to energize, each of which independently actuates the trip bar and tripping mechanism.
b.
Paragraph 3.1.1 (Immediate Operator Action): "If the reactor is not tripped, then push all four manual reactor trip pushbuttons."
This step performs the same actions as the Plant Protection System trip signal, described above.
c.
Paragraph 3.1.2.1 (Immediate Operator Action on ATWS): "Deenergize Load Centers BIS and B16."
This step is performed from the control room and deenergizes power to the Control Element Drive Motor Generator sets.
If all RTBs had not previously opened, thus deenergizing the CEDMs, removing power from the MG set would deenergize the rod mechanisms and allow the rods to fall into the core.
The ATWS section of the procedure, therefore, postulates two failures.
- Failure of the undervoltage device to open the reactor trip breakers.
Failure of the shunt trip coil to open the reactor trip breakers.
A loss of station power would cause a loss of power to the MG sets and result in the rods dropping into the core.
Power to the undervoltage and , shunt trip devices is supplied by Class 1E 125 VDC power the loss of l which, while credible, is highly unlikely.
7.
Control of Vendor Representative Activities l l The licensee's system for controlling vendor activities is prescribed by l Test Instruction (TI) 16 (Vendor Monitoring), Revision 3, dated l August 13, 1982. The purpose of the procedure is to establish a uniform method for procuring and monitoring vendor aervices requested by startup personnel and applies to vendor personnel who perform or direct the performance of work during the startup and test programs.
Examination of reactor trip breaker (RTB) maintenance history indicates that: , l l On about March 25, 1982, in response to the failure of four Unit 2 RTBs to trip when the UV coil was deenergized, the licensee's ...- ._ -. . _ _,. - - - .-. - .. .. .. -.. - . _ - -, - - -
- _.
- - . .. - _-__ ~. - . . - . '
- maintenance organization and a vendor representative adjusted all UV coils.
- During the period of July 14-21, 1982, a vendor representative performed work on all Unit 2 RTBs. The overhaul purportedly included lubrication.
- During the period-of August 10-21, 1982, the licensee's maintenance organization replaced the UV trip devices on four Unit 3 RTBs and, with a vendor representative, adjusted all Unit 3 UV coil settings.
The inspector examined the maintenance documentation (Work Orders and Nonconformance Reports) utilized to effect the above sctivities and observed that the activities of the vendor rep,resentative(s) were not controlled as required by TI-16 in that approved procedures did not appear to be utilized which specified the work performed by the vendor representative. Work performed by the maintenance organization was, however, documented and'specified by procedures with quality control inspections required at various hold points.
The inspectors discussed, with a vendor representative who had performed work on the RTBs, the extent of adjustments made and the criteria used by the vendor representative. These discussions indicated that the vendor representative was not specifically familiar with the Technical Manual , . criteria of certain adjustments and that some adjustments may have been ! made which appear to 5e reserved for factory setting.
The licensee's procedure TI-16 does not appear to contain any criteria or provision for the assessment of vendor representative capability, training, or qualificatioh.
In summary, it appears that vendor representative (s) perfonned work on the breakers and, further, that the licensee exercised inadequate control over vendor representative activities in that:
The capabilities, training, and qualification of vendor representatives were not assessed prior to the start of work.
- Detailed work plans or procedures were not prepared to control the
, work activities.
- Documentation of work activities conducted was insufficient.
, These deviations from program requirements were identified by the licensee to the NRC on March 14, 1983.
8.
Configuration Control
The reactor trip switchgear cabinet assembly, including the reactor trip breakers, are specified as Quality Class 1, Seismic Category 1, Electrical Class 1E in the FSAR, Table 3.2-1, and were eupplied by Combustion Engineering as part of the NSSS contract. The licensee's Equipment List (Drawing No. 90009), Revision 55, page 61 of 70, , classifies the reactor trip breakers as Quality Class 1, Seismic Class 1.
' i [ _ - - -. - _ _ - . _. - - __ _ _ .. . ._.
. ..
.. .. -. .. .-
- Therefore, the licensee's Equipment List agrees with the classification assigned the quality class and seismic category by the FSAR.
The licensee has determined that General Electric type AK 2-25 circuit breakers are not used in any other safety-related application, other than in the reactor trip switchgear, at San Onofre Units 2 and 3.
The licensee further stated that Westinghouse type DB-50 breakers are not used in safety-related applications at San Onofre Units 2 and 3.
During inspections of the reactor trip breakers and undervoltage coils, the inspectors observed the following: Trip Circuit Breakers (TCBs) 5, 6, 7, and 8 in Unit 3 switchgear
were type AK 2-25, whereas all other Unit 2 and 3 TCBs were type AK 2-25-2.
Two different part numbers for the undervoltage trip devices were
observed. Part No. 269C282-G2 was stamped on the undervoltage (UV) device name plate for Unit 2 TCBs 6, 7, and 9, while Part No. 269C282-G5 was stampe3 on all other UV devices. All UV devices were labeled as 125 vdc.
Further examination identified that the parts list in the type AK circuit breaker technical manual identifies Part No. 269C282-G2 as an AC Instantaneous Undervoltage Device and Part No. 269C282-G5 as a DC Instantaneous Undervoltage Device. The UV device is supplied with 125 vde Class 1E power in the San Onofre Unit 2 and 3 applications.
Based upon these observations, the inspectors requested that the licensee identify the proper breaker and UV device configurations necessary to be utilized in the peactor trip breaker switchgear. On March 24, 1983, the inspector received information from the licensee indicating that: The AK 2-25 and AK 2-25-2 breakers are functionally identical and
interchangeable.
The AK 2-25-2 was supplied as original equipment and the AK 2-25 was
supplied as spares.
All UV relays are of the type utilized in DC applications.
- As a result of the difficulties encountered in obtaining information on breaker and UV device design configurations, the inspector concluded that the licensee either has not established or effectively implemented a program to effect controls over the specification and maintenance of the design configuration of safety-related equipment extending to the component level.
9.
Control of Vendor Supplied Information During an inspection, conducted between October 26 and December 4,1981, the inspector identified a weakness in the control of vendor information.
This finding was documented in NRC Inspection Report No. 50-361/81-28 and is still carried as a follow-up item. The finding, at that time, was
-_ _.
- - - - . __ _. _ _ _ _ , '
- - ,. that the licensee had not established a system to assure that vendor information was captured, coordioated, controlled, and evaluated for potential effects on maintenance or surveillance procedures.
Based upon findings of this inspection, it appears that the licensee has not yet established such a system. For example, difficulties were encountered in determining if the Reactor Trip Breaker Technical Manual onsite was the correct revision. A technical manual for the undervoltage devices vas never located onsite.
Discussions with licensee personnel indicate that procedures describing such a system have been written and are in the review process. As such, a program has not yet been fully established and implemented.
10.
Follow-up on IE Bulletin 79-09 The inspector reviewed the licensee's actions in response to Bulletin 79-09.
The inspector determined that, in response to the Bulletin, the licensee had stated that a preventive maintenance program would be developed in accordance with the Bulletin's requirements prior to plant operation. NRC Inspection Report No. 50-361/81-07 noted that a preventive maintenance procedure, MPES008, "Undervoltage Tripping Device
of GE AK 2-25 Circuit Breakers in the Reactor Trip Switchgear," was i developed to meet the inspection requirements of the Bulletin.
The procedure was not reviewed in detail at that time.
The inspector reviewed Revision 1 of MPES008 and discussed its implementation with cognizant licensee personnel. The inspector determined that this revision of the procedure implemented many of the recommendations of General Electric Service Letter No. 175 (CPPD)9.3.
(This letter was referenced in a requirement of paragraph 3.c of IE Bulletin 79-09.) However, the procedure was deficient in that it did not require checking for excessive clearance between the undervoltage trip device armature and " rivet."
Licensee personnel were unable to explain
this omission.
Also, the Bulletin required that the frequency of inspection of the breakers be increased until the service experience with the breakers demonstrated that the normal (annual) maintenance interval was adequate.
Similarly, the licensee's vendor, Combustion Engineering, recommended on May 27, 1981, that preventive maintenance in accordance with the manufacturer's recommendations should be performed once every refueling interval unless periodic testing indicates that a more frequent interval is required (emphasis added). The inspector determined that the licensee had established a refueling interval frequency for trip breaker maintenance, and had performed Maintenance Procedure MPES008, Revision 1, in March-May 1981. The inspector discussed with maintenance department representatives the licensee's method for incorporating service experience, testing experience, and IE Bulletin requirements into preventive maintenance schedules. These representatives stated that at Units 2 and 3, key maintenance planners were expected to revise maintenance schedules on the basis of their knowledge and experience with the equipment, however, no formal system exists to capture and document maintenance (equipment) history. The inspector reviewed Maintenance Procedure S023-I-1.1, " Scheduling of Preventive Maintenance," and , < z . __ .. - _ -,,, _..,__..m . - _ _. - - __.,n._, . .. m , ,m._ _, _ _ _,., _, _, _. -,. - _ _ -. _. _,
. _ . . _ _ _ __ _.- '
- , concluded that this expectation was not formally assigned to key naintenance planners. The inspector concluded that, in this case, the licensee's procedures for revising preventive maintenance schedules had been inadequate.
Consequently, the development of a trip breaker preventive maintenance program, as required by IE Bulletin 79-09, was incomplete.
10 CFR 50.34 and the licensee's approved Quality Assurance Program, Chapter 5-C, paragraphs 2.0 and 3.0, require that the preventive maintenance frequency be adjusted to reflect the equipment supplier's suggested schedules and the maintenance history of the equipment. The licensee's Maintenance Program Procedures S0123-M-5, Revision 2, " General Maintenance Order," paragraph 6.3.2, and S0123-M-4, " Preventive Maintenance Program," paragraph 6.2, reiterate this policy. The licensee's failure to revise the preventive maintenance program to reflect testing experience and the equipment supplier's suggested schedules, as well as IE Bulletin 79-09 requirements, is an apparent violation of NRC requirements. (50-361/83-13-05) ' 11. Reactor Trip Breaker Troubleshooting a.
Theory of Operation
The inspectors witnessed the troubleshooting effort on TCB 2, an operable Unit 2 reactor trip breaker, and TCB 1, and inoperable Unit 2 reactor trip breaker.
Both are GE AK 2-25-2 electrically operated breakers which are closed by a solenoid coil. The armature of the solenoid is linked to the breaker mechanism and the amature movement, operating through the mechanism, closes the breaker.
The breaker is tripped open by the displacement of a mechanism latch, which allows a toggle linkage, supporting the movable contacts in the closed position, to collapse. This trip latch is rigidly fastened to a trip shaft which runs horizontally across the breaker. All of the features provided for tripping the breaker operate through striker arms, which displace the mechanism trip latch by moving against trip paddles fastened on the trip shaft.
The manual trip button, overload devices, shunt trip, and undervoltage (UV) tripping device all operate on the trip shaft to trip (open) the breaker. There are eight breakers (see Figure 1) which must operate in a one-out-of-two-twice logic in order to scram the plant (i.e., release all control rods into the core).
The reactor trip breaker UV device and shunt trip device each receive plant protective system signals to trip (Figure 2).
There are manual pushbuttons which repeat the protective system signals to the devices simultaneously. The shunt trip device must receive I power to trip the breaker.
In other words, it is normally deenergized when the reactor trip breaker is closed. The undervoltage device coil, however, is normally continually energized and deenergizes to trip.
When the control voltage is low or non-existent, as when the breaker has been pulled out for inspection or maintenance or has received a . _ , , _ _, _ _ _ ___ __ _ _ _, _, _ _ - - - - -,._.
--. - . . .
. - . - . . 20 protection system trip signal, the breaker is tripped open by the UV ' device. When this occurs, the breaker mechanism is tripped by displacement of the trip latch off the latch roller. The remaining force in the operating spring causes the mechanism toggle to collapse, resulting in the opening of the breaker contacts. The trip latch, latch roller, and other components can be seen in ' Figure 3.
Item 7 in this figure is the trip latch. The latch roller is hidden under the component touching the left end of the trip latch.
< Finally, Figure 4 shows the major components of the UV trip device, b.
Observation As mentioned above, the inspectors witnessed the troubleshooting efforts performed by the licensee and vendor representatives on one operable reactor trip breaker (TCB 2) and one inoperable breaker (TCB 1) on Unit 2.
The operable breaker was carefully inspected visually and tested first in order to establish the initial conditions that one might expect in comparing results of the inspection on TCB 1.
The work on TCB 2 was completed on March 13, 1983. The major finding at this time was the fact that the torque required to trip the breaker was on the order of 1.75 pound-inches. This is 0.25 pound-inch more than the requirements provided in the vendor's service advice letter. The breaker did, however, function properly.
On March 14, 1983, the first of four failed breakers was tested under SCE Work Order 24389.
GE Company service and engineering representatives were actively involved in this testing, along with maintenance, operations, quality assurance, quality control, and Combustion Engineering personnel. During this testing period, witnessed by an NRC inspector, the breaker failed to trip once, and exhibited sluggish operation numerous times. Also, there were indications that factory settings on the UV device may have been changed.
The measured trip bar torque required to trip ranged between 1.5 and 2 pound-inches. The time to trip from loss of DC ranged between 85 milli-seconds and 2.26 seconds. The pickup voltage for the UV device was just under 100 VDC and dropout voltage varied between 32.9 and 41.9 VDC. The licensee recorded the dropout voltage at which the breaker tripped. A vendor representative stated that the dropout voltage reading should be taken at the moment the UV armature begins to move. The licensee will attempt to be consistent in the future in taking these readings. This situation was not significant in the results of the inspection.
After all necessary static and dynamic tests were completed on March 14, the licensee and vendor representative lubricated and . cleaned the two trip shaft bearings and the latch roller. This was considered prudent because the bearings appeared dry and the latch roller was gummy.
IE Bulletin 79-09 states in the attached GE . . service letter that WD-40 can be used to perform these actions.
Since WD-40 is conductive and corrosive to certain materials, the
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- i licensee decided to use the other solvent / lubricant (CRC 5-56) mentioned in the GE service letter.
It should be noted that even if CRC-5-56 was used, evidence of lubrication may not be visible after a period of time since the lubricant is clear and of a low vis'cosity, and the bearings may still appear to be day.
After lubrication, the important measurements were repeated. The breakers furetioned properly. The torque values dropped to slightly over one pound-inch; the pickup voltage was about 98 VDC; the drop out voltage was about 37 VDC; and the trip time dropped to about 64 milliseconds. At this time, the licensee stopped testing, and returned TCB 1 to its cubicle.
On March 15, 1983, the licensee made the decision to return to TCB 1
and measure the latch roller engagement, the UV coil air gap and then to operate the breakers in place by pulling the fuse to the UV '. control power circuit to test the breaker's UV function.
In addition, the licensee decided to: lower the pickup voltage slowly on TCB 2, to see if they could determine a hesitation voltage; and clean and lubricate the two bearings and the latch roller sequentially, to determine the sensitivity towards operation that lubrication affords. The licensee performed a complete inspection and testing on TCB 6, the second failed breaker, on March 16, 1983, , using techniques and information gained from the work on TCB 1 and TCB 2.
The results of these inspections and tests confirmed the results observed on TCB 1 and TCB 2.
c.
Concerns Based on the observations of the troubleshooting activity the following concerns were identified: (1) The licensee was asked to provide a technical justification for setting the pickup voltage on the UV devices.
IE Bulletin 79-09 states that the pickup setting should be 106 vde for a nominal voltage of 125 VDC. Nominal voltage at Unit 2 appears to be about 133 VDC. The advisability of raising the pickup voltage to a value of 80-85 percent of the 133 VDC will be examined during a future inspection.
(50-361/83-13-06) (2) The GE AK 2-25 Installation Manual (GEK-7302) states that periodic inspection of the circuit breaker is recommended at least once a year.
It also states that bearing points and sliding surfaces should be lubricated at regular intervals after the removal of hardened grease and dirt from these surfaces. The licensee was asked to assess the type of lubricant and lubrication frequency for optimum safe operation of the GE AK 2-25-2 breakers.
(50-361/33-13-07) (3) The licensee was asked to respond to the environmental qualification of the breakers, including radiation and aging effects on the lubricant used for the trip shaft bearings and other important components. This request is significant, in , .- . .. -. - _ - - . - - - - - ... - -. - --
_ ' '
- - - . ,
, part, due to~the fact that the reactor trip breakers are , located in a radiologically controlled area. The Unit 2 - reactor trip breakers, for example, are near the Deborating Ion ' Exchangers.
(50-361/83-13-08) d.
Conclusions s
Licensee representatives observed that, without adjustment of failed breaker TCB 1 on Unit 2, the unacceptable operation was corrected by lubrication and cleaning of the trip bar bearings (2) and the latch roller. The lack of lubrication appeared to be a major contributor to failure. The licensee felt that the UV device pickup voltage on TCB 1 should be raised from about 97 VDC to 106 VDC, per the IE Bulletin-79-09 recommendations. The hesitation in the UV device operation may have been lessened if the higher voltage was available.
It was the opinion of the licensee that the high torque figure necessary to trip the trip bar was balanced by a 108 VDC pickup voltage.
Finally, there were other anomolies associated with various adjustments on TCB 1 which could have contributed to the failure to operate. The inspector considers that without a proper maintenance program using the technical manual techniques and recommendations, in~ combination with properly trained personnel, these breakers are subject to repeat failures.
(50-361/83-13-09) No items of noncompliance or deviations were identified in the troubleshooting techniques witnessed by the inspector.
- 12.
Exit Interview The inspectors met with licensee representatives (denoted in paragraph 1) at the conclusion of the special inspection on March 16, 1983, and summarized the scope and findings of the inspection. The licensee acknowledged the apparent violations of Technical Specification reporting requirements and the failure to adequately _ implement the recommendations of a GE service alert letter, provided by IE Bulletin 79-09, as required by preventive maintenance programLprocedures.
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.- .. sc . . ~ ' SAN ONOFRE NUCLEAR GENERATING SL ..dTRUMENT AND TEST PROCEDURE S023-11-11.161 . UNITS 2 AND 3 REVISION 2 PAGE 1 0F 1 ATTACHMENT 9.3 TCB BUS ARRANGEMENT .... G SET #1 , MG SET #2 - NOT GEN GEN M0T
O MCB-1 MCB-2 I O/ SYNCH (o CIRCUIT m , , G-TRIP - -E - -- TRIP y TCB-9 A O C ,, TCB-2 TCB-6 TCB-3 TCB-7 g g g g __q_ __ _ _ __ y r _. _ _ _ _r__ (O LO o/ O/ . TCB-1 TCB-5 TCB-9 TCB-8 (U (U USy_____S U __ q_ _ __ _. _ y-s-- Y Y N O NO O O ,,
CEDM POWER SUPPLY CEDM POWER SUPPLY FIGlRE 1 . . . . _.. . . -
, _ _ _ _ _ _ _ _ - _ - _ _ __ . SAN ONOFRE NUCLEAR CENERATING STATION
UNITS 2 AND 3 INSTRUMENT AND TEST PROCEDURE S023-11-11.161 , ' REVIS?ON 2 PAGE 1 0F 1 .i.
ATTACHMENT 9.1 - .
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4 FU C - s/ TC DEVICE ' ! TUK-I E I ! !
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. _ - - ge- - l Power Circuit Breakers Types AK-2-15 and AK-2/3-25 GEI-50299B , ' . the breaker.willnot close. Use the maintenance where the latchandlatch roller begin to engage, closing handle whenever closing or attempting In some cases, it may be necessary to turn to close the breaker during this entire opera-the adjusting screw less than 1/4 turn to
(. before tripping occurs. When this position is j tion.
establish the position where the contacts move 3.
Withdraw the adjusting screw from thelocknut established, note the position of the slot in 1/4 turn at a time, attempting to close the the head of the adjusting screw.
l
breaker after each 1/4 turn, and observing whether the contacts move toward closing 4.
Withdraw the adjusting screw three and one-before tripping occurs. If the contacts move half turns from the position noted in step 3.
i toward closing before tripping occurs, you hav e This sets the proper amount of latch engage-established the position of the adjusting screw ment.
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Figure 5. (8024457) Cut Away Model of Electrically Gperated AK-2 Breaker 1.
Arc Quencher Retainer 8.
Trip Shaft 12. Lower Stud 2.
Cutoff Switch 8A. Front Escutcheon 13. Socket Head Screws 3.
Cutoff Switch Actuator 9.
Closing Solenoid 14. Upper Stud -{' 4.
Spring Carrier 9A. Location of Slots for 15. Stationary Contacts 5.
Shoulder Pin Maintenance Handle and Springs - 6.
Connecting Link 10. Closing Solenoid Armature 16. Arc Runner 7.
Trip Latch Roller 11. Cover Retainer of Overload Device FIGlRE 3 33 ,. _ ... ._ -. - - ._ , - .
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, . ' GEI-50299] Pow;r Circuit Br;akirs Type 3 AK-2-15 and AK-2/3-25 (p .
m /^ g 1. Mounting Screw a (, 2. Frame , (h
3. Armature r (-f, 4. Spring I . 5. Shading Ring '7 6. Adjusting Screw ([i
'~.Y 7. Locking Nut ' y I 8. Bushing s / I '6 . N S CP J 9. Clamp s M ." u , 10. Magnet MS
{ Q 11. Screws '
) R vet "' N 14. Adjusting Screw
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x 16. Mounting Nut
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17. Mechanism Frame - j - 18. Trip Paddle Clamps u
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{ (:, Figure 28. (0152C9206) Undervoltage Tripping Device ening of the bend in clamp (9) will separate the coil from the magnet. The coilleads, of course, p ,(T7..____ -% must be disconnected.
, , _, _ _ l ~p. t, _ _ INSTANTANEOUS UNDERVOLTAGE ' , d i \\ . TRIPPING DEVICE ' l ? ',,' -
- 7V-l N, l
i/ l 1! l The instantaneous undervoltage device is ' C3G.__ L i l y l mounted in the same location and manner as the i ^ 2 _ _ A _ _ s _ _ _1, static time-delay device and its constniction is
s, similar.
i ,a % i ' The adjustments and replacement of t is J l ' device are the same as those described above for , the static time-delay undervoltage device.
, , l l UNDERVOLTAGE LOCKOUT DEVICE ! / (Figure 29) { l_. _,.. The undervoltage lockout device holds an , , open breaker trip-free when the coil of the device , is deenergized. When the breaker is in the closed position, linkage operated by the breaker mech-Figura 29. (0101C7842) Undervoltage Lockout Device anism cam positions itself to mechanically hold the undervoltage device armature in the closed air gap position to prevent tripping the breaker ) - 1.
Cross Bar 2.
Left Side Frame in the event the undervoltage device coil is de- " 3.
Trip Paddle energized. This feature when used in conjunction 4.
Undervoltage Armature with normally-closed auxiliary contacts of an
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