ML20129H747
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{{#Wiki_filter:.___ i ~ j ? i ) J H MEMORANDUM FOR: James Y. Vorse, Director i Office of Investigations Field Office j Region II i FROM: -Stewart D. Ebneter l Regional Adiministrator L
SUBJECT:
REQUEST FOR ASSISTANCE I j This letter confirms our verbal request for assistance of May 4,1992. On that date, J. Milhoan, Deputy Regional Administrator, discussed with L. 2 Robinson of your staff, the need for assistance from your office in conducting 1 several-interviews related to a violation that occurred on January 28, 1992, at the Vogtle Electric Generatiag Plant. The violation involved two I&C technicians who performed a surveillance to verify instrument settings on the reactor trip system instrumentation. In this particular instance, the I&C L ' technicians performed the surveillance improperly and after realizing that they had done so, they created data on the calibration sheet to cover their failure to follow procedure. 1 This matter was previously reviewed by your office in order to determine if an i investigation was warranted. By memo dated April 28, 1992, you advised that ~ you had contacted the Assistant U.S. Attorney for the Southern District of Georgia and advised him of the merits of the above willful act by the I&C technicians. The Assistant U.S. Attorney declined any criminal prosecution based on the availability of other punitive actions by the NRC. You also advised that you planned no other activity regarding this matter. Based on the foregoing, the Region scheduled an enfor, -.p$c. dJ cement onference with the licensee to discuss this matter on May 13, 1992,'in the Region II office. In making arrangements with the licensee, they were advised to bring the two 1 I&C technicians to the enforcement conference which they agreed to do. Subsequently, during discussions with the Director, Office of Enforcement on May 4, 1992, regarding the enforcement conference and its expected results, it was concluded that additional information was required by the staff prior to the enforcement conference. Specifically, because the Region did not have information directly from the I&C technicians about their actions in either documented interviews or other written documents, it was determined that such i information was essential prior to conducting the enforcement conference. You are requested to conduct formal interviews with the two I&C technicians, as well as their immediate supervisor. In addition, a Quality Control technician was also involved in this matter when he signed off the work 4 purportedly done by the techncians without actually verifying that the surveillances had been performed. We understand that a reasonable effort will be made to complete these interviews prior _ to the scheduled enforcement conference scheduled for May 13, 1992. i We have also enclosed is a list of questions that should be addressed during ~ the interviews. P. Skinner, Division of Reactor Projects, has been designated i as the technical coordinator in this matter and will provide whatever additional information or assistance you require to expedite these interviews. It is also our understanding that the interviews will be transcribed. 1 i 1 9611040022 960827 kb 1 PDR
T Stewart D. Ebneter
Enclosures:
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T QUESTIONS FOR I&C FOREMAN 1. What information was given to you by the responsible I&C technicians during conduct of the surveillance on the RPS instrumentation on January 28, 19927 2. Did you review the procedure that had been accomplished in detail and direct the actions of the I&C technicians to correct the identified deficiencies? .3. Have you previously had any similar activities from the technicians concerned, i.e., have other procedures not been followed and the data sheets improperly completed. 4. Did you notify the operations personnel that the equipment did not meet the procedure requirements and would be aligned in accordance with the prescribed procedure? 5. What action' did you take-when you were notified (or identified) that the I&C technicians had not performed the procedure as required? 6. Did you go to the instrumentation area and personally observe the equipment or complete your review from your office? 7. How did you know these individuals have not previously performed all steps in this or other similar procedures. 8. Would you expect your review of this procedure after completion by the I&C technicians to identify this type of I
- problem, i.e.,
falsification of date? I e
-I O QUESTIONS FOR I&C TECHNICIANS 1-Explain in detail the sequence of events that occurred during the surveillance conducted by you on January 28, 1992. 2. What caused you to not follow the procedures as written? 3. How did you convince the QC inspector involved to sign the procedure without review of the completed document? Was the signature on the procedure adequate to assure the process was properly reviewed by QC7 4. Did the communications between you and your supervisor reflect the appropriate corrective actions you should have taken? i 5. Are other procedures you perform susceptible to being violated - in the same manner which you violated this particular Procedure? 6. Have you performed similar actions in the past on this procedure of other procedures? 7. Did both of you decide on the course of actions you took or did one of you initiate the actions and it was carried on by the other I&C technician? 8. Were the actions required by the procedure clear and precise? l 4 s W
l QUESTIONS FOR THE QC INDIVIDUAL 1. What is your responsibility with respect to review and sign-off on I&C instrument surveillance procedures? 2. Explain your involvement in the procedure in question on June 28 occurrence? 3. When you sign-off a statement, how do you assure that what you are signing for is accurate and correct? 4. Were you mislead by the I&C technicians during your review of this procedure? 5. Are you responsible to sign-off steps in a procedure that you do not actually witness? 6. Were you required to witness steps performed or was this particular action a review of data? 7. Were you aware that the procedure required an alignment of the l instrumentation when the initial data taken fell outside the required acceptance criteria? _-.________m_
I ] LIMITED DISTRIBUTION Not For Public Release DRAFT - PREDECISIGNh MEMORANDUM FOR: Luis A. Reyes, Director Division of Reactor Projects Region II FROM: Chris A. VanDenburgh, Chief Reactive Inspection Section - 2 Vendor Inspection Branch Division of Reactor Inspections and Safeguards
SUBJECT:
VOGTLE SPECIAL TEAM INSPECTION - ALLEGATION FOLLOWUP TEAM DRAFT INSPECTION REPORT (INSPECTION REPORT NOS. 1 50-424/90-xx AND 50-425/90-xx) 'This memoranium refers to the special inspection conducted on August 6 through 17, 1990, at the Vogtle Electric Generating Plant (VEGP). This inspection involved a review of several allegations regarding the safe operation of VEGP and the review of operational activities generally related to the allegations. As discussed in the inspection plan, the inspection was performed by two separate teams--an operational followup and an allegation followup team. At the conclusion of the inspection, all of the inspection team's conclusions with respect to the operations and allegation followup were discussed with the members VEGP's staf f identified in the enclosed draft inspection report. As decided in a meeting held in Nuclear Regulatory Commission (NRC) headquarters on September 26, 1990, the allegation followup team's findings and conclusions have not been included in Inspection Report 424/90-19; 50-425/90-19. This information har been withheld pending the completion of an Of* ice of Investigation review of the allegations and the inspection team's conclusions. This memorandum forwards a draf t inspection report (50-424/90-xx; 50-425/90-xx) which documents the inspection team's review and concluaions regarding the allegations as of the time of the inspection exit meeting on August 17, 1990. The areas examined during the inspection are identified in the inspection report. As discussed in Inspection Report 50-424/90-19; 50-425/90-19, the inspection team concluded that the facility was safely operated.
- However, the inspection identified several ir atances in which the VEGP was not operated in accordance with the intent of the Technical Specifications.
In
- addition, the inspection identified several potential weaknesses in the facilities' operational policies and practices.
IrIMI-TED DISMION - No lic Release v NhY
y- -LIMITED DISTRIS TION N poor Public eiease. d R M - PREDECI ONAL INFORMATION Luis A'. Reyes ! The inspection team's review.of the allegations identified several additional weaknesses in these operational. policies and practices. These are identified in the inspection summary of the enclosed draft-inspection report. Based on_ the results of.this inspection of the allegations, certain activities appeared to be.in violation of NRC requirements,~as specified in the' enclosed draft Notice of Violation (Notice). These violations are important because they indicate (1) a failure to implement the requirements of the Technical Specifications and ~ administrative procedures, and (2) the failure 'to provide accurate ,information to the NRC. JAs - part of the response to the violations identified in the cenclosed notice,'VEGP should also be requested to address'each of { the concerns listed in the inspection summary.
Enclosures:
j 1. Draf!:-Notice of Viulation 2.- Draft Inspection Report 50-424/90-xx; 50-425/90-soc j l, CC BKGrimes - EWBrach l E 1 i LIMITED DISTRIBUTION - Not For Public Releas n 's s m 1 Y f
%'~IMITED-DISTRIBUTION 90t For Pubpli L ease [ ~ DRAFT s PREDECISIONALJ NEORMATION \\ \\ 4 I NRR/DRIS RII/DRP RII/DRP RII/DRP JWilcox* RAiello* RStarkey* MBranch* 9/- /90-8/31/90 8/31/90 8/31/90 P RII/DRP RII/DRS NRR/DLPQ RII/DRS LGarner* MThomas* NHunemuller* PTaylor* 9/27/90 8/31/90 8/31/90 8/31/90 RII/DRP~ NRR/DRIS. RCarroll* CVanDenburgh 8/31/90 9/ /90
- See previous-concurrences-t IM Eo M 1
-? . LIMITED DISTRIBUTNO ot For Publi Rele ~ w ' DRAFT. '. PREDECISIONAL INFORMATION ENCLOSURE 1 NOTICE OF VIOLATION j . Georgia Power Company Docket'Nos. 50-424 and 50-425 Vogtle. Electric. Generating Plant License Nos. NPF-68 and NPF-81 i
- Units 1-and'2 During an~NRC inspection conducted on August 6 through 17, 1990,
) ' violations of NRC requirements were identified. In accordance with t { the " General Statement ~of Policy and Procedure for NRC Enforcement '3 - Actions, " 10 CFR Part-2, Appendix C (1990), the violations are . listed below.. i lA. '10 CFR Part 50.9, " Completeness and Accuracy of Information," requires-that information provided to the NRC by a licensee i shall be complete and accurate in all material respects. Contrary to the. above, the licensee provided inaccurate-information to the inspection team on three. separc e ] occasions. - Although the information was provided in unsworn, oral statements, the information provided was significant to the licensing process. The information was provided by licensed operators, supervisors and management concerning j information which was within their specific responsibilities. 2 ' The. five examples were. as follows. (50-424/90-xx-05; 50-j 425/90-xx-05) 1. Containment : Isolation Valves: During a Ur.it 2 i surveillance procedure, the unit shift supervisor (USS) stated,. and the operations manager later confirmed, that the containment isolation valves for the hydrogen monitor . system were allowed to be opened.without ' entering the limiting condition for operation (LCO) action i -requirements for-Technical Specification- (TS) 3.6.3 because the valves received' an automatic isolation signal. The inspection identified that these containment isolation valves were remotely-operated, - manual valves without automatic isolation signals. (Discussed in i Section12.2.1.1 of Inspection Report 50-424/90-19;;50-425/90-19). ~
- 2.-
Snubber Reduction: The. operations: manager stated that, after the 7 second Unit 1 refueling outage'- (1R2), the modifications'to the snubbers were done in conjunction -q LIMITED DISTRIBUTION; 'Not For 'Public Rel1PIsk ~ '1 \\j N %( i a-u J .r, = m . 44....
tLIMITED DISTRIBUTIOPNot For-PGb ase ~ DRAFT _ PREDECISIONAL INFORMATION with preplanned system outages which were required for other preventive or corrective maintenance or testing. The inspection identified that few of the snubber modifications were done jointly with pre-planned system outages. (Discussed in Section 2.1.1.4 of Inspection Report 50-424/90-19; 50-425/90-19) 3. Emergency Diesel Generator (EDG) Reliability: VEGP incorrectly counted the number of starts and failures of the EDGs and incorrectly represented the EDG reliability in a Region II presentation on April 9, 1990. Although the presentation was not intended to represent a specific number of successful valid tests as specified in Regulatory Guide (RG) 1.108 and TS 4.8.1.1.2a, but rather to describe the EDG maintenance test program and the EDG reliability status, the NRC was not informed of the incorrect information until the NRC asked for it during the inspection. The confirmation of action (CAL) response and Licensee Event Report (LER) 90-006 were also incorrect because they were based on the EDG start information that was compiled for the VEGP presentation in the Region II Office. (Discussed in Section 2.7 of this inspection report) This is a Severity Level IV violation (Supplement VII). B. Technical Specification 6.7.1.a requires that written procedures be established or implemented for those activities delineated in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Contrary to the above, two examples were identified in which the licensee failed to establish or implement the procedures for these required activities as follows: (50-424/90-xx-02; 50-425/90-xx-02) 1. Administrative Procedure 00150-C, " Deficiency Control," i states that a deficiency card must be written if the deficiency involves safety-related components which are to be dispositioned "use-as-is/ repair," or other conditions involving safety-related components which require engineering support or other technical assistance to determine if the component is deficient. On August 17, 1990, the NRC identified that a deficiency card was'not written on residual heat removal (RHR) pump
- 1B (a safety-related component) to document the pump's
\\ / y IB5fION,- Not For Public Release LIMITED D L
1 c4IMfTED DISTRIBbs-Not For-Public Release i D' RAFT - PREDECI'SIONAL INFORl4A g _ - L degraded conditions which were dispositioned "use-as-is". (Discussed in Section 2.2 of this inspection report) 2. Administrative Procedure 00100-C, " Quality Assurance Records Administration," Paragraph 4.1.1.8, specifies-i that quality assurance (QA) records-will exhibit j necessary and appropriate signatures or initials and dates. i On August 17, 1990, the NRC identified that the Unit Superintendent incorrectly initialed, dated, and signed ' a QA record which voided Temporary Change Procedure (TCP) j 1802-C-7-90-1 to Abnormal Operating Procedure 18028-C, " Loss of-Instrument Air, " with the date of June 12, 1990, t in lieu of the actual date (June 15, 1990) on which the document was-signed. (Discussed in Section 2.5 of this inspection report) ii This is a Severity Level IV violation (Supplement I). I I i C. '10 CFR Part-50, Appendix B, Criterion 'XVI, " Corrective -Action," requires measures to be established to ensure that conditions adverse to quality are promptly identified and corrected. In the case of significant conditions adverse to quality, the measures are required to ensure that the cause of the condition is determined and corrective action is taken to l preclude repetition. Contrary to the above, two examples were identified in which the ~ licensee failed to determine and implement adequate corrective actions to preclude repetition as follows: (50- '424/90-xx-03) 1. On August 17, 1990, the NRC determined that the licensee did not identify the format and normal use of the LCO status sheet as one of the causes of the event described in Licensee Event Report (LER) 90-004, " Failure To Comply With Technical Specification 3.0.4 Occurs on Entry Into Mode 6"; therefore,, corrective action was not taken to preclude repetition of the failure to review LCO-required n actions or remarks'which may be on the back side of the LCO status' sheet. (Discussed in Section 2.4 of this inspection report) ] 1 2.= Technical Specifications 4.8.1.1.3 and 6.8.2 require that all valid or non-valid EDG failures be reported'to the i NRC in a special report within 30 days. In addition, O IMITED U'PI Public Release g i t
'~ LIMITED DISTRIBUTION - Not For-Public Release DRAFT ~- PREDECISIONAL INFORM TION-Operations Procedure 55038-C, " Diesel Start Log," Section 7.0, requires that all EDG failures shall be reported to the NRC in a special report. On August 17,
- 1990, the NRC identified that the corrective actions taken in response to a previous notice of violation were inadequate.
Inspection Report 50-424/87-57 (dated November 5,1987) previously identified a violation of Technical Specification 4.8.1.1.3, in that, all EDG failures were not reported to the NRC in a special report. During a review of the start records for EDG #1B during the period of March 21 through June 14, 1990, the NRC identified that EDG failures had occurred which were not submitted to the NRC in a special report. In addition, the NRC identified that Operations Procedure 55038-C provided inadequate guidance to identify and ) - classify EDG failures. (Discussed in Section 2.7 of this j inspection report) i This is a Severity Level IV violation (Supplement I). Pursuant to the provisions of 10 CFR 2.201, Georgia Power Company is hereby required to submit a writt.en statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN: Document Control i
- Desk, Washington, DC
- 20555, with a copy to the Regional Administrator, Region II, and, if applicable, a copy to the NRC Resident Inspector within 30 days of the date of the letter transmitting this Notice of Violation (Notice).
This reply should be clearly marked as a " Reply to a Notice of Violation" and should include for each violation: (1) the reason for the violation, or, if contested, the basis for disputing the violation, (2) the corrective steps that have been taken and the results achieved, (3) the corrective steps that will be taken to avoid further violations, and (4) the date when full compliance will be achieved. If an adequate reply is not received within the time specified in this Notice, an order may be issued to show cause why the license IMIT5D'DI ON ase 1
_. ~ ' LIMITED DISTRIB.UTION M t-For Publi elease DRAFT ~r'PREDECISIONAL.INFORMATIO should not'be modified, suspended, or revoked, or why such other action as Inay be proper should not be taken. . here good cause is W shown, consideration will be given to extending the response time. FOR THE NUCLEAR REGULATORY COMMISSION 3 L Stuart D. Ebneter Regional Administrator 1 Region II Dated at Atlanta, Georgia .this day of 1990 ) l - r~. W_ m,_.. AtIMITED DISTRIBUTION - Not Tor'Public Release 5 ~ es
? [ IIMITED DISTRIBUTION - Not For-P5bTic Releas ~
- DRAFT - PREDECISIONAL'INFORMATION ENCLOSURE 2 Report No.:
50-424/90-xx and 50-425/90-xx - Licensee: Georgia Power Company P.O. Box 1295 i Birmingham,- AL' '35201 Docket'Nos.: 50-424 and 50-425 License Nos.: NPF-68 and NPF-81 Facility Name: Vogtle Electric Generating Plant, Units'1 and 2 Inspection-Conducted: August 6-17,-1990 Team Members: ~Ron'Aiello - Resident Inspector, Vogtle Morris Branch _-' Senior Resident Inspector, Watts'Barr Robert'E. Carroll, Jr. - Project Engineer, DRP, Region II ~ 1 Larry Garner - Senior Resident Inspector, Robinson Neal K. Hunemuller - Licensing Examiner, NRR Larry L.' Robinson - Investigator, OI, Region II Robert: D. Starkey - Resident Inspector, Vogtle Craig T. Tate - Investigator, OI, Region II ' Peter >A. Taylor - Reactor Inspector, DRS, Region II McKenzie Thomas - Reactor Inspector, DRS, Region II John D. Wilcox, Jr. . Operations Engineer, NRR Team Leader: Chris A. VanDenburgh, Section Chief Division of Reactor Inspections and Safeguards Office of Nuclear Reactor Regulation Approved by:- Luis A. Reyes, Director Division of_ Reactor Projects Region II IMITED,DISTRIBUTIO Jiot Release 6 -w -4 = r
4 LIMITED DISTRIBUTION ~..- Not For Public Release DRAFT - PREDECISIONAL INFORMATION TABLE OF CONTENTS INSPECTION
SUMMARY
1 1.0-INSPECTION OBJECTIVES................................ 7 2.0 ALLEGATION' FOLLOWUP.................................. 8 2.1 Improper Installation of FAVA System............ 9 2.2 Operability of Residual Heat Removal Pump....... 14 2.3 Missed Containment Isolation Valve Surveillance. 16 2.4 Mode Change With Inoperable Source Range Monitor Nuclear Instrument...................... 19 2.5 Backdating of Signatures........................ 21 2.6 Reportability of Previous Engineered Safety Features Actuation System Load Sequencer Outages......................................... 24 i 2.7 Reliability of Emergency Diesel Generators...... 27 2.8 Air Quality of Emergency Diesel-Generator Starting Air System............................. 31 2.9' Reportability of Previous System Outages........ 33 2.10 Intimidation of Plant Review Board Members...... 33 2.11 Personnel Accountability........................ 35 3.0 ' EXIT INTERVIEWS...................................... 36 APPENDIX 1
- LIST OF TRANSCRIBED INTERVIEWS...............
37 APPENDIX 2 - PERSONS CONTACTED............................ 38 ' APPENDIX 3 - LIST OF ACRONYMS............................. 40 ['N n., D LIMITED' DISTRIBUTION - Not For~Public Release v g
- L'IMITED DISTRIBUTION D ot For-Pu M c Release DRAFT 7" PREDECIS IONAITINFORMATI'ONy INSPECTION
SUMMARY
Recent activities which have occurred at the Vogtle Electric Generating Plant (VEGP) have raised concerns within the Nuclear Regulatory Commission (NRC) as to the ability and the determination of the licensea to operate the facility in a safe and conservative manner. To address this concern, the NRC performed a special team inspection to determine if the licensee operates the facility in accordance with approved procedures and within the requirements and intent of the facility's operating license. In addition to the occurrence of specific events, NRC concerns regarding the safe operation of the facility were heightened with the receipt of several allegations relating to operational activities at VEGP. .The aggregation of the facts and circumstances associated with the operational events and the allegations was viewed as a possible indicator of a non-conservative attitude on the part of the facility's operating staff which warranted the immediate initiation of special inspection activities. Specifically, the inspection objectives were to: 1) Assess the operational philosophy, policy, procedures and i practices of the facility's operating staff and management regarding operational safety. 2) Determine the technical validity and safety significance of each of the allegations and their impact on the safe and conservative operation of the facility. These inspection objectives were accomplished by the use of two inspection teams--an operations followup team and an allegations followup team. The efforts of these two inspection teams were closely coordinated;
- however, they independently pursued the objectives outlined above.
The operations followup team monitored control room activities on a 24-hour basis-in order to: (1) evaluate the operational philosophy, policies, procedures, and practices of the operating staff and management and (2) determine if the plant was being operated in a safe and conservative manner in accordance with the facilities' operating license. The allegations followup team verified the technical validity and safety significance of each of the allegations. In addition, with the assistance of the OI staff, this team interviewed members of the plant staff in order to determine '(1) their personal involvement and knowledge of the specific allegations and (2) their practice and understanding of the station operational policies. pMITEDDISTRIBUTION otTrNPyblic_. Reg
1,- 1 l LIMITED DISTRIBUTION - Not-For-Public Release ' DRAFT - PREDECISIONAL INFORMATION ' LThese) interviews were transcribed. Although an OI investigator was 1: assigned to:the: inspection team to assist during the' transcribed interviews, this inspection was not an investigation into. the ' intent.of-the alleged violations.- i The ' inspection substantiated the occurrence of the specific events described: in the allegations. These' events resulted in two [ examples of violations of regulatory requirements (50-424/90-soc-02; i 50-425/90-xx and 50-424/90-xx-03) and two of the events were 2 previously. identified as non-cited violations (50-424/90-10-03 and j 50-425/90-01-01).. However, the inspection did not substantiate l that-the y events and violations were performed with. the full-1 knowledge of VEGP' management.. This conclusion was. based upon'a _ review-;of'the licensee's records.and the sworn testimony of the j people. involved in the events. - The. inspection also identified that on several occasions responsible managers and supervisors. verbally' supplied inaccurate information to the. inspection team during the inspection. Although j the - inspection team ~ was concerned about the accuracy of the
- information provided, the team did not-have a basis to conclude or
. suspect that these examples.were the result of careless disregard for regulatory requirements or individual wrongdoing. 1 i The specific observations and conclusions of the inspection team are detailed in Inspection Report 50-424/90-19; 50-425/90-19. In i addition, the' bases for these previous conclusions are summarized below. f.! operational Policies and Practices NRC Inspection Report 50-424/90-19; 50-425/90-19 identified several examples in which the licensee's operational policies and practices had the ,etential to adversely affect the operation of the i i .fac l ty. The allegation followup team's review of the allegations . identified several additional examples in which the licensee's I; operational policies and practices had the potential to adversely affect the cc.fe' operation of the facility. For example: . 1)- The : licensee's method of conducting Pir.at Review Board (PRB) mee :ings had the potential for' advarsely_ affecting open discussions among the.PRB members. This concern was based on
- an. example in which a PRB-voting member felt intimidated and feared retribution during a PRB 7 meeting L because of - the
- presence of the general manager and the absence of dissenting ' ' opinions.. in ' the '.PRB meeting minutes. Continued licensee [ actionfis. necessary to. ensure' that.' PRB members freely and ~ u n n JIMITED -DISTRIBUTION - N,dPublic Release V O ^ J r i 22 - ,,a. L.
LIMITED DISTRIBUTION __llot For Public Release DRAFT - PREDECISIONAL INFORMATION _ openly express their technical opinions and safety concerns. (Section 2.10) 2) The licensee's practice of signing and dating quality assurance records was controlled by administrative procedures; however, there was a confirmed example in which a signature was backdated to reflect the actual date of performance. The backdating of TCP 1802-C-7-90-1 was verified and was identified as Violation 50-424/90-xx-02; 50-425/90-xx-02. (Section 2.5) 3) The licensee' practice of not initiating a deficiency card (DC) during troubleshooting activities involving the questioned operability of the residual heat removal (RHR) pump prevented a documented engineering evaluation for either the nuclear service cooling water (NSCW) outlet leak or the excessive vibration on the RHR motor. The failure to implement this administrative procedure was identified as Violation 50-424/90-xx-02. (Section 2.2) 4) The licensee's method of maintaining and controlling copies of completed surveillance procedures was not controlled by administrative procedures. Based on the confusion which resulted in the missed surveillance of the containment isolation valves and a review of this methodology additional attention is necessary to ensure that these procedures are appropriately controlled and used. (Section 2.3) 5) The licensee's method for identifying active and informational limiting condition for operations (LCOs) on LCO status sheets allowed continuation of the LCO required actions on the reverse side of the form. This method, in conjunction with the operator's confirmed practice of reviewing only the front side of the LCO status sheets, was one of the root causes.for a non-cited violation (50-424/90-10-03) concerning a mode change which occurred with inoperable source range nuclear instruments. The failure to identify this additional root cause was identified as Violation 50-424/90-xx-03. (Section 2.4) 6) The licensee's method of appraising the performance of the licensed operators resulted in a potential disincentive for identifying items which may result in LERs or violations. (Section 2.11)
t i ~ 6 _ LIMITED DISTRIBkJTkON Not Y Pub 3ic Release -DRAFT -z PREDECISIONAL INFORMATION Accuracy of'Information The inspection concluded that - during the inspection inaccurate i information 'was' received on several occasions, from responsible managers and operators.on. topics well within the scope of their specific responsibility. In five instances the initial information i supplied was clearly incorrect or inadequately researched. The inspection-team concluded that in each of.these examples, that i licensee officials,provided inaccurate, unsworn, oral statements
- concerning information which concerned topics well within their responsibilities.
.InL the= first 'three cases,- the inaccurate information was significant to the inspection process. Specifically, (1) if the ) ' containment isolation valves received an automatic closure signal, the' valves could remain open without a violation of TS 3.6.3; (2) Lif the snubber modifications had been performed in conjunction with other. preplanned preventive and corrective maintenance, then the voluntary _ entries into LCO 3.7.8 would not have been required, and (3).if the NRC.was. accurately informed of the number of problems and failures of the. Emergency Diesel ' Generator No. 1B which occurredLduring troubleshooting,-then. additional testing may have been required prior to the release of the confirmation of action letter. Thel inspection team concluded that the failure to provide ) accurate information was a violation of the requirements of 10 CFR J ~ 50.9 concerning accuracy and completeness of information. The inspection. identified Violation 50-424/90-xx-05; 50-425/90-xx-05 in this area.and noted the following examples: 1) Containment Isolation Valves: During a Unit 1 surveillance procedure, the unit shift supervisor (USS) stated, and the operations manager later confirmed, that the containment isolation valves for the hydrogen monitor system were allowed to be. opened without entering the LCO action requirements for TS 3.6.3 because the valves received an automatic isolation signal. The inspection identified that these containment isolation valves were remotely-operated, manual valves without automatic isolation signals. (Discussed in Section 2.2.1.1 of Inspection Report 50-424/90-19; 50-425/90-19) 2)- Snubber Reduction: The operations manager stated that, af ter Unit i refueling outage IR2, the modifications to the snubbers were done'in conjunction with preplanned system outages which 1 >were' required'for other preventive or corrective maintenance or testing. The inspection identified that few of the snubber modifications were done -jointly with pre-planned system-outages. (Discussed in Section 2.1.1.4 of' Inspection Report 50-424/90-19;-50-425/90-19) T ' +1IMITED DISTRIBUTION - Not70r-Publ@se 4
I i _ LIMITED DISTRIBUTION'- Not For Public Release DRAFT'- PREDECISIONAL INFORMATION i F i 3) Emeroency Diesel Generator Reliability: The licensee's method of. researching information for Region II presentation concerning the reliability.of the. emergency diesel generators l (EDGs) was inadequate in that there was a lack-of specific i guidance concerning the.EDG information desired coupled with ' inadequate research of the EDG starting history. This method resulted-in providing incomplete and, therefore, inaccurate j 'information to the NRC. In addition,.the licensee's response to the NRC's confirmation of action letter (CAL) was based on this same. inadequate research. In addition, the subsequent' Licensee Event Report (LER).' 90-006 was also inadequately researched. As a result of this method of investigation, the NRC was never informed of the correct operability status until this inspection. (Discussed in Section 2.7 of this inspection report) 4) Personnel Accountability: The operations manager stated that the shift superintendents (SSs) reported directly to the operations : manager and that he personally prepared their performance appraisals. The inspection identified that the SSs reported to the unit superintendent (US), and that the US personally prepared the perfomance appraisals of the SSs. (Discussed in Section 2.11 of this inspection report) 5) TS
- 3. 0. 3' Actions :
The unit superintendent indicated that there were no Operations Department actions which were anticipated or required within the first three hours of i entering -the action statement of TS 3.0.3. The inspection identified that the VEGP management policy and stated practice required preparations for a power reduction, including informing the-load dispatcher within the first hour. (Discussed in Section 2.1.1.3 of Inspection Report 50-424/90-p 19; 50-425/90-19) 3 In summary, t:he inspection identified three violations and two ~ inspector followup items. The. violations involved:-(1) a violation i ): - of 10 CFR ' 50.9. in that responsible licensee of ficials provided - inaccurate information' to the NRC during the inspection, (2) a i violationof TS 6.7.1.a in that, two examples were identified of ' the licensee failing. to implement actions in accordance with administrative procedures; ~. and (3) a. violation of 10 CFR 50, Appendix B,- Criterion XVI, in that, two examples were identified of . the licensee implementing inadequate corrective actions. -O n
- ~
( LIMITED DISTRIBUTION - Not 'Yor4blic Release- \\ 5. 4 e e.uP' d
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LIMITED DISTRIBUTION - Not Fcir'Public Release DRAFT - PREDECISIONAL INFORMATION 'dentified two inspector followup items The. inspection also i involving: (1) an unreviewed safety question concerning the use of the alternate radwaste building, and (2) the lack of operator guidance concerning the applicable limiting conditions of operation during' engineered safety features actuation system sequencer outages. t or I li'c Rel_e_as_e - MITED DISTRIBUTION N
LIMITED DISTRIBUTION - Not For Public' Release DRAFT - PREDECISIONAL INFORMATION ' INSPECTION DETAILS 1.O INSPECTION OBJECTIVES Recent activities which have occurred at the Vogtle Electric Generating Plant (VEGP) have raised concerns within the Nuclear Regulatory Commission (NRC) as to the ability and the determination of the licensee to operate the facility in a safe and conservative j manner. To address this concern, the NRC performed a special team inspection to determine if the licensee operates the facility in accordance with approved procedures and within the requirements and intent of the facility's operating license. In addition to the 1 occurrence of specific events, NRC concerns regarding the safe operation of the facility were heightened with the receipt of several allegations relating to operational activities at VEGP. The aggregation of the facts and circumstances associated with the operational events and the allegations was viewed as a possible indicator of a non-conservative ' attitude on the part of the facility's operating staff which warranted the immediate initiation of special inspection activities. Because a non-conservative attitude or operating philosophy may represent a hazard to the health and safety of the public, a special inspection team comprising staff from the Region II Office and the Office of Nuclear Reactor Regulation (NRR), assisted by staff from the Office of Investigations (OI), was formed to determine the individual validity and collective impact of these allegations on the safe operation of the facility. The purpose of the inspection was to determine if the licensee operates the facility in a conservative and safe manner in accordance with approved procedures, and the intent and requirements of the facility's operating license. Specifically, the inspection objectives were to: 1) Assess the operational philosophy, policy, procedures, and practices of the facility's operating staff and management regarding operational safety. 2) Determine the technical validity and safety significance of each of the allegations and their impact on the safe and conservative operation of the facility. These inspection objectives were accomplished by the use of two inspection teams--an operations followup team and an allegations followup team. The efforts of these two inspection teams were closely coordinated;
- however, they independently pursued the objectives outlined above.
( LI I ED DIS 10 N elease
. ~. _. -. _ _.. _- q -- LIM MED DISTRIBUTION - Not.hFor Public Release l ~ DRAFT - PREDECISIONAL INFORMATION N i (- u-LThe operations followup-team monitored control room activities on a 24-hour basis in order to: (1). evaluate the operational j.- . philosophy, policies, procedures, and practices of the operating l l staff f and management and' (2) determine if the plant was being j [ operated in a safe.and conservative manner in accordance with the j-facility's. operating license. The' specific inspection activities..of the operations team was described in Inspection Report 50-424/90-19 and 50-425/90-19. The efforts and conclusions of the_. allegations followup ~ teams. are described-in this inspection report. _In addition, this report identifies several ' violations.and potential weaknesses in the , licensee 's; operational policies, - programs, and procedures. The i specific details and' basis for the inspection team's concerns are ) 4 detailed in the. sections that follow and in the Inspection Summary. J 2.0 . ALLEGATION FOLLOWUP The inspection team reviewed several. allegations for their b technical validity and interviewed licensed and non-licensed . personnel to determine their personal knowledge and. experience i regarding ' these issues. This portion of the inspection was performed to determine the validity and significance of the 2-
- allegations.
Because -the allegations asserted that licensed operators had violated the Technical Specifications (TS) with the ' knowledge of. licensee management, the inspection team reviewed the circumstances and rationale for: individual actions. . The inspection of the allegations included technical reviews of the licensee's records, logs, and interviews of the personnel involved in the alleged violations. Although a transcribed record was not t required-for every discussion with the licensee's staff, the inspection team conducted-sworn, transcribed interviews with selected individuals in order to document (1) the individual's [ personal knowledge and involvement in the alleged violations and (2) the: circumstances and rationale for their individual actions. Although.an OI investigator was assigned to the inspection team to assist during-the transcribed interviews, this inspection was not i .an investigation.into the intent of the alleged violations. The interviews were transcribed af ter the technical evaluations of the Jallegations ; in1 order to -permit a focused interview and to !minimizeithe length and. scope of the transcribed proceedings. The transcribed interviews are listed in Appendix.1 in the order'they ~ were. conducted. The;swornitestimony~was the basis'on which the Tinspection team reached its conclusion on each of the allegations. LThesel: conclusions' are presented in the material that ' follows '(Sections 2.1:through 2.11). g IMITED DIST CUTION -Not'No_r Public Release 8-m i i q p C b e s-'s w-y -e. u tir ri-
4 ~, ~ -1IMITED DISTRIBUTION ~ Not For Public Release DRAFT - PREDECISIONAL INFORMATION 2.1 Imoroper Installation of FAVA System An allegation indicated that VEGP installed and operated a radwaste i microfiltration
- system, known as the FAVA
- system, without i
performing an adequate engineering and safety evaluation (i.e., 10 CFR 50.59). Furthermore, the material configuration, fabrication and quality of the system did not meet the guidance of Regulatory Guide (RG) 1.143 and the requirements of the American Society of Mechanical Engineer's (ASME) Code. l The FAVA system was temporarily installed for removing Niobium-95. The system was later determined to be better suited for as-low-as-reasonably-achievable considerations during refueling outage 1R2, particularly for removing Cobalt-59 and Cobalt-60. VEGP planned to replace this temporary modification with a permanent, high-quality, steel system in the future; however, the health and safety of the public may be jeopardized if a break in the system (resulting in a radioactive release to an unrestricted area) occurred in the interim. 1 Discussion In February 1988, the VEGP experienced difficulty in removing colloidal Niobium-95 following a reactor shutdown for maintenance work. FAVA Control Systems (FAVA) was hired to help rectify this problem. FAVA was selected because of its experience in filtration ) and demineralization. The situation was corrected by installing a 0.35-micron filter system downstream of the existing vendor-supplied pre-filters. However, a large volume of radwaste was generated as the 0.35-micron filters rapidly exhibited high differential pressure and were required to be changed frequently. ) The need to change filters frequently also resulted in additional j radiation exposure to Radwaste Department personnel. Upon evaluation of the performance of the 0.35 micron filter system, the Radwaste Department felt that the best approach to the problem was a back-flush, pre-coat filter system. However, no operational data was available for a system of this type in this specific application. FAVA supplied a proprietary Ultra Filtration System (Model No. 5FD/E) for testing purposes in order to evaluate whether or not this was a viable and economic solution to the problem. The FAVA system was installed before the Unit i refueling outage and was operated under Test Procedure T-OPER-8801. The test l system kept liquid effluent releases well below TS limits. On the basis cf an evaluation of test results by the Radwaste, Chemistry, l and Engineering Departments, a general work order was initiated to purchase a permanent system. ' LIMITED-DISTRIBUT5DNs-N,otAbr Publie-Release 9
LIMITED DISTRIBUTION - Not For~Public Release s DRAFT..--PREDECISIONAL INFORMATION In the early part of 1989, a Quality Assurance (QA) Department audit identified a significant audit finding involving a programmatic breakdown in the procurement of the FAVA system and the failure to meet commitments of the Final Safety Analysis Report (FSAR). Because of that finding, the FAVA system was removed from service. In late 1989, the licensee sought to reinstall the FAVA system under a temporary modification because colloidal Cobalt-59 and Cobalt-60 had to be removed. The Plant Review Board (PRB) reviewed this temporary modification and several members expressed strong objections to it based on the previous QA audit finding. Subsequently, a request for engineering assistance (REA) was submitted and a 10 CFR 50.59 safety evaluation was performed in late 1989. This safety evaluation did not properly address the guidance of Regulatory Guide (RG) 1.143 regarding the use of polyvinyl chloride (PVC) piping. Therefore, another safety evaluation was performed in February 1990 to address this issue-- particularly with respect to radiation degradation. The February 1990 safety evaluation specifically stated that the FAVA system did not conform to the criteria of RG 1.143. This deviation was found to be acceptable for the following reasons: 1) The design of the FAVA system had been previously evaluated and found to be adequate in the response to REA VG-9057 dated November 28, 1989 (log SG-8592). 2) The location of the FAVA microfiltration system inside a shielded, watertight vault provided adequate assurance that any system failures will be contained and would not create the potential for offsite releases of radioactivity. 3) The presence of PVC pipe in the FAVA system, although prohibited by RG 1.143, was acceptable because the radiation exposure to the plastic was within acceptable limits for up to 6 months based on the following: a) The amount of PVC piping used was not extensive and was contained c:1 the FAVA filter skid. b) There were no reported leaks or malfunctions during the approximately 6 months that the FAVA system filter was previously in use. c) Since the FAVA system filter skid was located within the demineralizer vault, it would be protected from being damaged. If1MITED DISylO ot-For_PMbl-it -Re-lease ~'
~ LIMITED DISTRIBUTION - Not For Pub Wc Release -DRAFT - PREDECISIONAL INFORMATION d) On the basis of the assumed length of time that the PVC piping would be used in a radioactive environment and the activity levels of the effluent at this stage in the liquid radwaste process, the integrated dose to the PVC piping would be well below the radiation damage threshold for PVC pipe as reported in Electric Power Research Institute (EPRI). Report NP-2129, dated November 1981 (i.e., 6.5 rad over a 6 month period versus the radiation 3 damage threshold of 5.0 x 10 rad). e) The PVC pipe would not be subjected to excessive pressure conditions since the maximum available inlet pressure to the filter was 80 to 100 pounds per square inch gauge (psig) which is well below the maximum allowable working pressure of 120 psig for the PVC pipe. f) The system could be operated at design-basis conditions for 182 days before it would exceed the radiation damage threshold. However, under conditions currently existing at the plant, the expected dose to the PVC piping will less than 0.1 percent of the design basis. Although the testimony of one of the PRB members indicated that the temperature effects on the use of PVC in the FAVA System were not adequately evaluated before the system was installed, the testimony of the corporate system engineer indicated that this was considered prior to installation, although not specifically documented in the safety evaluation. ~ The VEGP general manager subsequently consulted the NRC resident inspector to seek an NRC position with regard to placing this system back in service. This was supplemented by information documenting reasons why it should not be placed in service. This package was forwarded to ~ Region II and the Office of Nuclear Reactor Regulation (NRR) for review. In March 1990, following Region II and NRR concurrence via a telephone conference, the licensee placed the FAVA system in service with the following NRC stipulations: 1) Procedures for operating the FAVA system required an operator to be in attendance for the entire length of time the system would be in operation. 2) All hoses going to and coming from the FAVA system required verification that they met the requirements of RG 1.143. 3) The cover over the FAVA system was required to be securely fastened when the system was in operation to ensure that if a L'1MIT & DISTRIBUTION ot h 4
LIMITED DISTRIBUTION - Not For Public Release " N DRAFT - PREDECISIO_NAL INFORMATION spraying leak developed, it would be contained iri the concrete vault. 4) The design of the walls of the alternate radwaste building (ARB) was required to be evaluated to determine whether or not a design modification should be made to reduce the potential of wall leakage in the event'that a hose leak developed and sprayed its contents on the walls. In June 1990, in response to item 4 (above), the licensee revised Part G of the safety evaluation for the FAVA system. Part G of the safety evaluation addressed the effect that operation of the FAVA system would have on the probability of occurrence or consequences of accidents described in the FSAR. Although there was no comparable accident analysis in the FSAR that addressed the ARB accidents or the consequences of accidents in the ARB, the FSAR . accident analyses (Chapters 15.7.2 and 15.7.3) did describe worst-case releases of the contents of the recycle holdup tank (HUT). 2 The first bounding analysis in Chapter 15.7.2 addressed the release of the entire gaseous radioactive contents of the HUT to the environment at ground level and the second bounding analysis addressed the release of the entire liquid contents of the HUT through an assumed crack in the ARB floor directly into the ground water supply. In both cases, the 10 CFR Part 100 and 10 CFR Part 20 limits were not exceeded. These criteria were consistent with criteria provided in NRC Circular 80-18, "10 CFR 50.59 Safety Evaluations for Changes to Radioactive Waste Treatment System." However, neither of these analyses addressed the potential for wall spray down and leakage through the ARB walls and the subsequent release path to the environment. Therefore, the licensee revised the safety evaluation in June 1990 to address the consequences of a hose break on the FAVA system which would result in wall spray { down and potential leakage to the environment. The inspection-team's review of the revised Part G of the safety evaluation identified several erroneous assumptions with respect to the release path and the dilution volumes that could be used in the analysis of a hose break and resultant wall spray down.
- However, the inspection team also found that the design of the FAVA system (i.e., the use of a system cover) would prevent wall spray down and that the only potential source for wall spray down and subsequent leakage was from a hose break in another radwaste system in the ARB. Therefore, the inspection team concluded that the FAVA system safety. evaluation dated June
- 1990, adequately addressed the temporary modification for'the installation of the FAVA system; however, the inspection team's review identified an unreviewed
%I IMII5TiflBI PUbllc Release 4#
1 f y
- LIMITED DISTRIRUTION - Not For Public Release J DRAFT - PRE NAIrTN RMATION safety question ~concerning the release paths'ind consequences of a-l failure of the other radwaste systems in the ARB.
i In addition,_.the team noted that-in Supplement s 3 and 4 of thel . Safety Evaluation Report (SER), the NRC staf f reviewed and accepted the design ~o_f the ARB and specifically addressed the consequences of'a hose break on a radwaste system in the ARB. However, the SER supplements addressed the-effects of high airborne activities and puddling and did not address the potential for wall spray down.and leakage. The ARB was installed before the plant was licensed; theref ore,-- the NRC approved the design and use of the ARB in-Supplements 3 and 4.of the SER. Thus,_there was no requirement to perform another evaluation of the potential effects of. hose breaks on systems other than the system being installed by the temporary modification _(i.e., the FAVA system).. Because the design of the _ FAVA system effectively l prevented a wall spray down, this was not l ? a ' concern that was required to be addressed by the FAVA-system j ' safety evaluation. Nevertheless, now that it has been identified, 'the: consequences of a hose break and wall spray down in the other i ARB radwaste systems must be resolved. Therefore, this issue will be-followed as an inspector followup item pending further review and: evaluation' and is identified as: IFI 50-424/90-xx-01 and 50-425/90-xx-01, " Potential Unreviewed Safety Question Regarding Spray Down of the Alternate Radwaste Building." Conclusion i - Although. the FAVA system was originally installed without an adequate-safety evaluation and did not meet the regulatory guidance, the inspection team concluded that the subsequent safety evaluations were acceptable for the system's use. Therefore, the . inspection team concluded' that the allegation was not fully substantiated. As a result of QA Department's significant audit finding in early 1989 involving-a. breakdown in procurement and failure to meet FSAR - commitments, the system.was removed from service. Subsequently, the FAVA system was returned to service following two _ safety - evaluations.which adequately addressed'the use of PVC piping with -respect to ' radiation degradation. and _ pipe rupture. ' Therefore, these safety evaluations justified the use of the FAVA system, even ._though'the_ recommendations.of RG'1.143 and ASME Code requirements ) L were not met. Although the safety evaluations did not'specifically ~ address - high-temperature affects, the testimony indicated that j these effects had been considered before.the system was installed. A IMITED D IBUTION - Not For Public Release I \\ %s w
t l -LIMITED DISTRIBUTION - Not For.Public Release -DRA y REDECISIONAL INFORMATION ~. x Although..the safety evaluation performed in June 1990 at the t request of the'NRC Region II. Office did not adequately evaluate the 'effectsJof'a wall spray down and wall leakage to an unrestricted area, this evaluation was not required because the FAVA system has l l .a' protective cover.and the use-of hoses and effects of hose breaks (i.e., airborne activity and puddling) were addressed in SER j Supplements 3 and 4. j Regardless of'whether. the safety evaluation was required to address the effects..of a. break,in the hoses (which could. result in wall j ' spray down or. leakage), the inspection team identified a new 2~ ' concern involving the use of the ARB because the safety evaluation Linadequately addressed the. potential effects of wall spray ' down from.any other source in the'ARB owing to erroneous assumptions fconcerning the. release path and the: dilution volumes. This is a
- potentially unreviewed safety question concerning the use of the alternate radwaste building.
j 2.2 Ooerability-of the Residual Heat Removal Pumn An-allegation indicated that during Unit.1 refueling outage 1R2 with residual heat - removal (RHR) Train A out of service for [
- maintenance,' the Train B RHR pump experienced excessive vibration
- and a ' nuclear service cooling water (NSCW) motor cooler outlet leak. In addition, TS 3.9.8.1, "RHR and Coolant Circulation," was allegedly violated because the Operations Department chose not to declare RHR pump 1B inoperable in an effort to mitigate the impact on'the critical work path. i I Discussion TS 3.9.8.1 requires at least one RHR train to be operable and in operation during Mode 6 (refueling) when the water level above the top of the reactor vessel' flange is 23 feet or more. Otherwise, Suspend all operations involving an increase in the reactor decay heat load or a reduction in boron concentration of the ' reactor ' coolant system (RCS) and immediately initiate. corrective action to return the required RHR train to operable and operating status as soon as possible and close all containment ~ penetrations providing direct access from the containment atmosphere i to the outside atmosphere within 4 hours. The inspection-team. verified that during-Unit i refueling outage 1R2,with higherfthan normal vibration measurements on the RHR pump ~ 1B l and 'a ~ leak on ', the.. NSCW outlet of the - RHR. motor cooler, LOperations : Department'. personnel did not: declare the pump-Not' Tor Public Relgase' 1 ....J
LIMITED DISTRIBUTION ~ 'Not For Public Release DRAFT - PREDECISIONAL INFORMATION 1 inoperable. This determination was made after consulting with the on-shift duty engineer f rom the Engineering Department and was based on the determination that the pump would fulfill its intended i safety function in Mode 6. Specifically, the RHR pump was capable of removing decay heat from the partially defueled reactor core. The testimony of the individuals involved indicated that this operability determination was based on the fact that the vibration readings taken at the inservice test (IST) surveillance points did not reach the IST Alert levels and were therefore acceptable for continued service. Although the high vibration readings on the top end of the RHR pump were later determined by the vendor (Westinghouse) to be excessive, at the time of the operability evaluation, the licensee accepted these values, regardless of their magnitude, because the readings at IST test points were below the Alert levels. The testimony also indicated that, even with a leak on the NSCW outlet of the RHR motor cooler, the motor was receiving full cooling water flow and cooling would not have been immediately compromised following a complete NSCW discharge pipe break. j Furthermore, the testimony indicated that the Operations Department had implemented compensatory actions to monitor the vibration levels and NSCW leakage and ensure the continued operability of the pump by stationing an operator at the RHR purn to monitor the vibration levels and notify the control room if the vibration levels increased, thus allowing the-control room to implement the actions of the limiting condition for operations (LCO). The inspection t.eam also noted that in event of a catastrophic failure of the RHR pump, all the required actions of TS 3.9.8.1 (i.e., closing r.11 containment penetrations) could have been completed within the required 4 hour time period of the LCO because the LCO for TS 3.9.4, " Containment Building Penetrations," was in effect during this time period. This LCO was implemented due to the movement of irradiated fuel from the core to the spent fuel j pool. The LCO required that, The equipment door be closed and held in place by at least four bolts; at least one door in each airlock be closed; and each penetration providing direct access from the containment atmosphere to the outside atmosphere i shall be either closed by an isolation valve, blind flange, or manual valve, or be capable of being closed by an operable automatic containment ventilation isolation valve. As a' result of.the implementation of TS 3'.9.4, the only remaining action for the LCO of TS 3.9.8.1 would have been to close the en ,,LIMITE)VDISTRIBUTION'. Jot 7drM4c-Rel_ ease 15 4
4 LIMITED'~ DISTRIBUTION NbtJp' r - Pubildease DRAFT - PREDECISIONAL INFORMATION containment purge valve which receives an automatic closure signal - and could have been isolated within the LCO action times. - During the course of this review, the inspection team found that the licensee failed to initiate a deficiency card for either the NSCW 1eak or the excessive vibration as required by Operations Procedure 00150-C, " Deficiency Control." This procedure requires that a deficiency card be written if the deficiency involves - safety-related components which are to be dispositioned "use-as-is/ repair," or other conditions involving safety-related components which require engineering support or other technical assistance to determine if the component.is deficient. Failure to establish, implemer.t, and maintain adequate operating procedures represents a violation of TS 6.7.1.a. This item is identified as: VIO 50-424/90-xx-02 and 50-425/90-xx-02, " Failure To Establish or Implement Procedures for Required Activities." Conclusion The inspection team concluded that the allegation was not fully i substantiated because the Operations Department had an adequate engineering basis for accepting the operability of the RHR pump in spite of the pump's deficiencies. In addition, the team concluded that declaring the pump inoperable would not have impacted the critical work path: the LCO actions would not have been restrictive because containment (excluding ventilation) had been isolated as i required by TS 3.9.4. The LCO actions would not have prevented the continuation of refueling activities because the actions to close all containment penetrations providing direct access from the containment atmosphere to the outside atmosphere would only have required closing the containment purge valve which has an automatic closure signal. In addition, the inspection team identified that the licensee violated the station's administrative procedures by failing to initiate a deficiency card for either the NSCW outlet leak or the excessive vibration on the RHR motor as required by Operations Procedure 00150-C. 2.3 Missed Containment Isolation Valve Surveillance An allegation indicated that a unit shift supervisor (USS) concealed the correct entry time for a TS LCO to prevent a forced shutdown of the unit and to prevent a 10 CFR 50.72 notification to the NRC. Furthermore, containment isolation valves (CIVs) which were missed during a surveillance test should have been declared . inoperable and the immediate actions of the TS LCO should have been initiated at the time the missed surveillance was identified. In /'LIMITE ISTRIB QN_ -Aldt %or Public Release L s 16 v
j (LIMITED _DISTRIBbTION -No uhl-ic Release DRAFT - PREDECISIONAL INFORMATION addition, delaying the initiation of the deficiency card (DC) until j the surveillance had been re-performed allowed. the licensee to avoid-the.immediate actions-of the LCO and allowed the unit' to -remain in operation and avoid the immediate NRC notification. Discussion The inspection team reviewed the documentation of the missed surveillance on the containment isolation valves. described - in l Licensee Event Report (LER) 90 001 for which a non-cited violation -(50-425/90-01-01)- was issued. The LER~ identified that during the r l review ' of monthly Surveillance. Procedure 14475-2, " Containment Integrity Verification-Valves Outside Containment," the licensee discovered that 39 CIVs had been overlooked and had not been stested. In addition, the valves had not been tested during the previous _ two L monthly. surveillances. Upon-identification, the > operating. shift re-performed.the - complete surveillance and j ' initiated an investigation which resulted in a deficiency' card (DC) ffor the previously missed surveillances. The LER. indicated that; the root cause of the. violation was personnel' error in reviewing the completed surveillance task sheet. In addition, the computer sof tware which generated the surveillance task E sheets (STS) has been modified so that it is no longer possible to inadvertently get an incomplete listing of the . equipment. Even if an error similar to the one which resulted in only two valves being shown on the STS.were to recur, it could only result in either all or none of the equipment being listed. The inspection team. verified that TS 3.6.1.1, " Containment Integrity," LCO action statement required restoring containment integrity within.1 hour or commencing a unit shutdown to hot standby.within the next 6 hours. A shutdown required by Technical I Specifications would have required that the NRC be inmediately notified'in accordance with 10 CFR 50.72. The-inspection team found that the CIV surveillance requirement. of TS 4.6.1.1.a had been completed and approved. The surveillance procedure required verification every 31 days that all penetrations not capable _ of being closed: by operable containment automatic isolation valves and required to be closed during accident conditions b e.~ c l o s e d b y valves, blind flanges, or deactivated . automatic valves secured in their normal positions. During the j 2 next
- shift, the -oncoming shift supervisor noted that the surveillance procedure was only. partially performed and that 39 of the':CIVs L oni the' surveillance procedure had been marked as "not Japplicable".and had not been performed.
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- F r
w-+ + -- ~ + + -4 +mI
_ _.. _ _ _ _ _ _ _ ~. _ _ _ _ _. -. f;- i. LTMITED DISTRIBUTION - Not For Public-Release l' DRAFT 1PREDECISIONAL'INFORMATION i i TS 4.0.2.a requires that each surveillance requirement be performed. lwithin the specified time interval with a maximum allowable l extension not to exceed 25 percent of the surveillance interval. In. addition, TS 4.0.3 requires-that failure to perform -a surveillance requirement within the specified-time interval shall i-constitute a failure to meet the. operability requirements for an LCO. ? As. such,.the failure to perform Surveillance Requirement i ~ 4.6.1.1.a for all the CIVs within the surveillance period (i'.e., 31 q days plus the 25-percent extension) would have constituted an p inoperable-condition of the CIVs. j The oncoming USS testified that he lacked sufficient information to determine. if J the complete surveillance had not been performed F .within the surveillance frequency because he was not familiar with-1 the circumstances under ~ which the surveillance procedure was-uperformed. 'Furthermore,-.he lacked sufficient information in the t i < control room to-determine.if the complete surveillance procedure - i e had been: performed within the surveillance period. On the basis of -his experience,'.the CIV surveillance was normally performed in its entirety;. therefore, the potential existed that.another partial i surveillance procedure had verified the position of the missed .CIVs.: Although previously performed surveillances were filed-in the control room, these records were for information only and were 'neither controlled nor complete. l ..The USS indicated that'the previous'two monthly surveillances on the CIVs,obtained from this file were performed incompletely; however, he did not know whether surveillances on the missed CIVs had been performed completely under some other surveillance c procedure. This was confirmed when the team interviewed the surveillance coordinator. Who indicated that approximately once a month 'the Surveillance Tracking Group identified that suspected p - missed surveillances were performed under different tasks. Upon identification of the potential missed surveillances, the USS -initiated an investigation to determine whether the surveillances had-actually been missed and, concurrently, re-performed the surveillance within three hours.. The inspection team verified that .the discovery time'on the deficiency card correctly reflected the time at which.it was verified that the previous two surveillances had been performed incompletely. E Conclusion - On.the3 basis-of U the - testimony. of - the L USS, the inspection -team - l concluded that the allegation was not fully substantiated because. s m ' LIMITED DISJRIBUTION - ot-For PGblic Releas.e ~ 'W 18 V m -i- ~ .wd y 5-.e c 8 +W .w v 'te-w-w= w-<*d== w
- a'-r*'
- -* ~*-** * ' ' *
-LIMITED DISTRIBUTION - NoTFor_ EublMelease DRAFT - PREDECISIONAL INFORMATION the USS did not conceal the true discovery time of the missed CIV surveillances to avoid a unit shutdown. The USS indicated that he was not pressured to keep the plant in operation or to prevent NRC notification. He stated that he had never been given any indication or instruction to do "whatever it takes" to keep the unit on line or to avoid NRC notification of unusual events. The USS did not know and could not confirm if the previous CIV surveillances had been inadequately performed and believed that the surveillance could be re-performed within the allowable outage time; therefore, his actions to initiate an investigation into the adequacy of the previous surveillance and to concurrently re-perform the CIV surveillance procedure were appropriate. 2.4 Mode Chance With Inonerable Source Rance Monitor Nuclear Instrument An allegation indicated that the operations staff allegedly knowingly violated Technical Specifications (TS) when the unit was taken f rom Mode 5 (cold shutdown) to Mode 6 (refueling) with a source range monitor (SRM) nuclear instrument inoperable and that the prohibited operational mode change was made in order to reduce the critical path outage time. Discussion The inspection team reviewed the documentation of the mode change described in Licensee Event Report (LER) 90-004 for which non-cited Violation 50-424/90-10-03 was issued. The LER indicated that TS 3.0.4 was violated on March 1, 1990, when Unit 1 entered Mode 6 from Mode 5 with an LCO for Source Range Channel 1N31 in effect to allow performance of an 18-month channel calibration. The LER indicated that the root cause for the event was personnel error by the shift superintendent. The inspection team confirmed that TS 3.0.4 required that entry into an operational mode not be made unless the conditions for the LCO are met without reliance on the provisions of the action requirements. With one source range monitor inoperable, TS 3.9.2, " Instrumentation," could not be satisfied in Mode 6 without reliance on the action statement. Personnel were interviewed to (1) confirm the effect on the outage schedule directly attributed to this TS violation, (2) determine whether it was known at the time of the mode change that a mode-restraining LCO was in effect, and (3) determine the extent of emphasis on schedule. IMITED DISTRIBUTIDioLFor Pug _Eelease 19 L'
c
- LIMITED DISTRIBUTION Not For Public Release DRAFT - PREDEC SIONAL INFORMXTION The testimony and a review of the outage schedule confirmed that there was a reduction in critical path outage time which was directly attributed to proceeding to Mode 6 before restoring the SRM to an operable status.
The testimony also indicated that the shif t superintendent (SS) and the unit shift supervisor (USS) did not recognize that a mode-restraining LCO was in effect at the time of the mode change. Both the SS and USS were aware that there was an active LCO on the SRM, but neither of them had connected the LCO to the mode restriction. Contributing factors to the error were that both the SS and USS had directed their attention to a problem with the testing of the engineered safety features actuation system (ESFAS) sequencer and that the work which had been emphasized to be holding up the mode change was the decontamination of the reactor head. Upon notification that the Health Physics Department had cleared the reactor head for work, the SS granted permission to enter Mode 6. The testimony also indicated that there was no indication of an unreasonable emphasis on the critical path schedule. Both the SS and USS indicated that they had never been given any indication or instruction to do "whatever it takes" to stay on schedule. They also indicated that they did not feel undue pressure to stay on senedule and, particularly, not if it meant compromising safety. The SS admitted that he was initially commended for the schedule benefits; however, the violation of the Technical Specifications was not recognized at the time. The SS indicated that he had initially received some positive feedback during the morning management briefing for the shift's accomplishments and later in the briefing the TS violation was recognized and discussed. In the SS's opinion the recognition of the TS violation negated all positive feedback. The inspection team identified an additional concern during the inspection concerning the format and use of the LCO status sheets. On the basis of interviews with tne SS and USS and the review of the format of the LCO status sheets, the inspection team concluded that both the format and normal use of this form contributed to this TS violation. j The LCO status sheet, is a two-sided form; the section for required actions begins on the front and continues on the back, where the " remarks" section is located. During the testimony, both the SS and USS indicated that their usual practice, notwithstanding mode changes, was to review only the front of this form because only restorative actions were noted on the back. In this case, the mode LIMITED DIS IBUTION.p Not-For,Public Release x. 20 V I l
LIMkTEDDISTRIBUTION-~NotForPublic_ Release DRAFT - PREDECISIONALINFORMATION~ restraint was noted on the back of the form in the " remarks" section. LER 90-004 did not identify the format and use of the LCO status sheet, as a cause of the violation; therefore, corrective actions have not yet been taken in this regard. The failure to identify and implement adequate corrective actions to preclude repetition is a violation of 10 CFR 50, Appendix B, Criterion XVI, " Corrective Actions," and as such will be followed as: VIO 50-424/90-xx-03, " Failure To Determine and implement Adequate Corrective Actions." Conclusion On the basis of the transcribed interviews and from its review of the outage schedule, the inspection team concluded that the allegation was not fully substantiated. The testimony indicated that the mode change was a critical path item. However, the testimony of the shif t superintendent and the unit shif t supervisor involved indicated that at the time of the mode change they were not aware that an LCO was in effect on the SRM and that a mode change was prohibited. l The inspection team also concluded that the corrective actions for the LER failed to identify that the format and use of the LCO status sheets, was one of the causes of the event. Therefore, the failure to implement appropriate corrective actions was found to be a violation of 10 CFR 90, Appendix. B, Criterion 73I. 2.5 Backdatino of Sianatures An allegation indicated that a temporary change to Abnormal Operating Procedure (AOP) 18029-C, " Loss of Inst.ument Air," was not approved within the 14-d:1y requirement of TS 6.7.3.c; an6 that the unit superintendent intentionally incorrectly signed and dated the temporary change to indicate that the TS requirement was satisfied. Discussion TS 6.7.3. c requires that temporary changes to AOPs which do not involve changes to the intent of the original procedure be documented and reviewed in accordance with TS 6.7.2 and approved within 14 days of implementation. TS 6.7.2 requires that changes to AOPs be reviewed as stated in administrative procedures and approved by the Plant Review Board (PRB) and general manager. Administrative Procedure 00100-C, " Quality Assurance Records TiMITED-DISTRIBUTIdii > Not-For 4 b.lic Release ~
9 I o j , LIMITED DISTNIBUTION - Not For Public Release DRAFT - PREDECISIONAL INFORMATION Administration," Paragraphs 4.1.1.4 and 4.1.1.8, require that corrections to Quality Assurance records exhibit necessary and i appropriate signatures, initials, and dates. Operations Procedure 18028-C, Revision 7, provided operator actions in the event of a loss of the instrument air system. A temporary change to the procedure was initiated on May 29, 1990, to delete the references to the header isolation at 70 psig and the associated actions. This change was processed in accordance with Administrative Procedure 00052-C, " Temporary Changes to Procedures," which allowed the temporary implementation of minor changes to procedures as long as the change was approved by the PRB and signed by the general manager within 14 days of the temporary change. Therefore, Temporary Change Procedure (TCP) 1802-C-7-90-1 was required to be approved by the PRB and signed by the general manager by June 12, 1990. The PRB tabled thi> TCP on June 8, 1990, (PRB meeting 90-81) and assigned action to P.he Operation's Department to void the TCP cr revise the TCP to incorporate the PRB comments. Revision 8 to Operations Procedure 18028-C was developed to modify valve numbers and descriptions reflected in Temporary Modifications 1-90-006 and 2-90-002. This revision superseded the changes of the TCP. On June 12, 1990, the PRB approved Revision 8 (PRB meeting 90-82) and I the TCP was removed from the control room copies of the procedure. On June 15, 1990, the unit superintendent lined out the operations manager's previous approval of the TCP and marked the TCP form as disapproved by the Operations Department. The date entered on the form was June 12, 1990. i On June 22, 1990, the PRB secretary initiated Deficiency Card (DC) 1-90-282 which indicated that the unit superintendent incorrectly dated the TCP with the date of June 12, 1990, rather than actual date of June 15, 1990, and DC 1-90-283 which indicated that the TCP was not processed within the required 14 days (i.e., by June 12, 1990). The resolution of these DCs, the associated PRB meeting minutes, and discussions with the operations manager and Nuclear Safety and Compliance Department staff indicated that described deficiencies were acknowledged and confirmed by the Operations Department on July 3,1990, and attributed to personnel error. The TCP form was dated with the date on which the Operations Department decided to void the TCP and not the date on which the original 1as actually signed. As part of the corrective actions for DC 1-90-282, a TCP record correction notice was initiated to correctly indicate the date on which the TCP form was processed;
- however, the TCP record correction notice could not be produced--one was subsequently W
~ SL EILDISTRIBUTION - Not For PM1 ease
-LIMITED. DISTRIBUTION -Not For_ Public Release DRAFT - PREDECISIONAL INFORMATION ^ written on August 14, 1990. In addition,-the operations manager counselled the unit superintendent and assigned him to investigate both DCs because he was the most knowledgeable of the deficiencies and the assignment served to reinforce the reprimand. The subsequent PRB meeting of June 28,
- 1990, (PRB meeting 90-90) determined that the 14-day TS violation addressed in DC 1-90-283 was reportable to the VEGP vice president, but not to the NRC.
However, the inspection team found that the report to the VEGP vice president was not made. On August 9, 1990, the PRB (PRB meeting 90-104) confirmed that the report was required. As of August 17, 1990, the licensee had not issued the required report to the VEGP vice president; however, the licensee intended to issue the report. With respect to the rationale for the unit superintendent's actions, the inspection team learned (during discussions with the Technical Support Manager) that the PRB secretary told the unit superintendent on June 15, 1990, that the TCP needed to be voided and a DC written for violating the 14-day requirement of TS 6.7.3. As discussed in Section 2.11 of this inspection report, Operations Department personnel are held personally accountable for violations and LERs (i.e., there is a direct impact on their bonus pay); therefore, a reportable occurrence based on this event could have adversely impacted the unit superintendent's salary. The testimony of the unit superintendent indicated that he dated the TCP with the date (June 12, 1990) on which the PRB disapproved it and not the date on which it was actually signed (June 15, 1990). Additionally, the unit superintendent had no recollection of any discussions on June 15, 1990, regarding violation of the 14-day TS requirement. He indicated that he never considered the 14-day requirement despite his previous knowledge and training concerning this requirement and the June 12, 1990, expiration date indicated on the TCP form. The testimony of the PRB secretary indicted that during a discussion with the unit superintendent on June 15, 1990, she identified the need to void the TCP, as well as the need to write a DC for violating the 14 -day TS requirement. Therefore, the inspection team was concerned about whether the TCP was voided before or after the PRB secretary identified the need to void the TCP and initiate a DC. In order to resolve this discrepancy, the inspection team discussed the discrepancy with the PRB secretary on August 16, 1990. In addition to earlier testimony, the PRB secretary indicated that during her discussions concerning the TCP with the unit superintendent on June 15,
- 1990, the unit superintendent had indicated that the TCP had already been voided earlier in the day.
4IM jITEDISTRIB&ot For Public Rel19$se 23 W
I i ' $IMITED DISTRIBUTION - Not-For Public4elease t DRAFT - PREDECISIONAL INFORMATION * ~ Conclusion t On.the' basis of the testimony, the inspection _te'am concluded that backdating to avoid a violation of the 14-day TS requirement was t - not fully substantiated. In addition, the concern that this practice was - a ' plant-wide problem' was not fully _ substantiated. i 3-However, the' inspection team did confirm that TCP 1802-C-7-90-1 had been ' dated : incorrectly; ' this was a violation of ~ Administrative-1 Procedure 00100-C, " Quality Assurance Records Administration," i
- ParagraphsL4.1.1 4cand 4.1.1.8 and will be followed as:
VIO'50-424/90-xx-02-and'50-425/90-xx-02, " Failure to Establish or ~ 4: j Implement Procedures for Required Activities." I L2.6 Reoortability of Previous Enaineered Safetv Features Actuation I system-Load seauencer outaaes i LAn allegation indicated that the Operations Department incorrectly f used a _72-hour shutdown requirement when one of the two ESFAS load .sequencers was previously inoperable. It was also indicated that VEGP had.taken no action to: ensure that,the past occurrences were ' identified and reported to the NRC as required by 10 CFR 50.73, l despite newly acquired information that deenergizing an ESFAS i sequencer __ required entry into the 1 hour limiting condition for operation (LCO) action requirements of TS 3.0.3. In addition, the possibility existed that the LCO for TS 3.0.3 (i.e., 7 hours to hot standby) _ were -exceeded when the sequencers were previously deenergized for maintenance and testing. This concern was based on (1) the lack ~ of a specific TS for the sequencers, (2) the Operations Department historically linking the sequencer outages to ' the emergency diesel generator (EDG) LCO of TS 3.8.1.1.b (78 hours to hot'- standby), (3),a limited review of past maintenance work I orders (MWOs) -indicated _ possible sequencer deenergization; and i-(4)- comments by the engineering staff that the sequencers had been previously deenergized. Discussion ju There are;two ESFAS sequencers for each unit--one for each 4.16-kilovolt (kV) -emergency bus. Each sequencer is activated by one of .two-conditions, undervoltage;(UV) on the associated emergency bus - or.a respective train's safety injection (SI) signal. Upon receipt of'either;or;both of the initiating signals, each sequencer will perform'all;or partlof the following functions: Start the associated EDG. -Stop.any' test sequence in progress. TDTRUTION 4cdtelease/ ?} PD' 2 -. ~
LIMITED DISTRIBUTION - Not For Public Release DRAFT --~PREDECISIONAL INFORMATION Strip the associated emergency bus of all loads (W only). Close the associated EDG breaker (W only). Energize the associated train's engineered safety features (ESP) loads as determined by the initiating signal. 1 Each ESFAS sequencer contains three levels of W detection and system response, as well as the power supply for this W circuitry. Four potential transformers monitor the emergency bus voltage for these three levels of degraded bus voltage (Level 1, s 70 percent; Level 2, s 86 percent; and Level 3, s 88.5 percent) and furnish an analog signal to three sets of four bistables located in one of the five sequencer cabinets. Level 1 is the " loss of voltage" and Level 2 is the " degraded voltage" whicn is referred to in TS Table 3.3-2, Items 6.d, 8.a, and 8.b. As these TS items (applicable in Mcdes 1 through 4) do not address the loss of all four channels in Level 1 or in Level 2 (as would be the case when the sequencer is deenergized), TS 3.0.3 would apply if such a loss were to occur. It should be noted, however, that if the sequencer were deenergized, it could not respond to a safety injection signal either. Therefore, there would be only one automatic safety injection actuation channel (i.e., associated with the unit's unaffected sequencer) and Item 1.b of TS Table 3.3-2 (6 hours to hot standby) would be the most limiting LCO. Discussions with the operations manager, the assistant general manager-plant support, and system engineers for the ESFAS and sequencers confirmed that the Operations Department historically linked the sequencer outages to the emergency diesel generator (EDG) LCO of TS 3.8.1.1.b (78 hours to hot standby). Although the applicability of TS Table 3.3-2 and TS 3.0.3 to sequencer outages had been recently identified, past sequencer outages were not reviewed. Therefore, with the assistance of the licensee, the inspection team reviewed the completed MWOs which were performed on the sequencers on Units 1 and 2, as well as the related Instrumentation and Control (I&C), Engineering, and Operations Department surveillance tests. The review of completed MWOs did identify several instances where the work performed would moat likely require the sequencers to be deenergized; however, the associated unit was found to have not been in Modes 1, 2, 3, or 4 at the time the work was performed. Somewhat related to this concern, the review did identify two MITED_DIST3R0 TION' or-Public Rel b e~
4 -LIMITED.DISTRIBUTICN - Not For PubliFRhlease ~ DRAFT - PREDECISIONAL INFORMATION occurrences (March 4 snd June 17, 1987) where the Unit 1 Train B sequencer was inoperable during the change of sequencer controller card A (SLOT A4 - 3 ). Coecifically, when the controller card was removed, both the automatic SI function and UV function for the sequencer were rendered inoperable. Because the unit was in Mode 3 (hot standby) during these two occurrences, the sequencers and the ESFAS were required to be operable per TS 3.3.2. However, the associated LCO status sheets (1-87-356, dated March 4, 1987 and 1-87-566, dated June 17, 1987) only recognized TS LCO 3.8.1.1.b as ' being applicable to the outage. Despite the fact that LCOs associated with TS Table 3.3-2 (Item 1.b) and TS 3.0.3 were not recognized, these TS were not violated since the system was restored within 30 minutes and 10 minutes, respectively. In addition, as the unit remained in hot standby, reportability under 10 CFR 50.72 or 50.73 was not required (i.e., there was no power reduction while in a TS LCO (10 CFR 50.72) nor was the plant taken to hot standby as a result of a TS LCO (10 CFR 50.73)]. Similar to the MWO review, the inspection team's review of related I&C, Engineering, and Operations Department's surveillance tests ) did not find any examples of the sequencers or the ESFAS being deenergized in Modes 1 through 4. Completed 18-month ESFAS channel calibrations, EDG tests, and ESFAS tests were verified as having been done in Modes 5 and 6. Completed quarterly testing of the ESFAS Auto SI K610 slave relay, which removed the automatic SI signal to the sequencer, were verified to be performed within time limits allowed by TS 3.3.2. All other sequencer testing that used installed test circuitry is automatically bypassed on an SI or UV signal. In additio.n to the inspection team's review of MWOs and surveillance test procedures, the system engineers for the sequencers and ESFAS [as well as the nuclear steam supply system (NSSS) supervisor] were asked if they knew of any time in which the sequencers were deenergized in Modes 1 through 4. None of these engineers remembered any such occurrences. A review of applicable operator training material (System Description 8b for Engineered Safety Features System Sequencers) revealed that there was no reference to ESFAS TS 3.3.2, just those for the diesel and other power sources and distributions (i.e., TS 3.8.1.1, TS 3.8.3.2, TS 3.8.2.1, TS 3.8.3.1, and TS 3.8.3.2.). This finding, along with the March 4 and June 17, 1987, occurrences discussed
- above, indicates that the Operations Department historically has not linked sequencer outages to the LCOs of TS 3.3.2 or TS 3.0.3.
Nevertheless, discussions with the operations manager and the licenced operators on shif t indicated that although no written guidance or TS interpretation existed for the \\L DIST p UTJ 4.or-PubliA_ Release
' LIMITED DISTRIBUTION - Not For Publiclelease- -DRAFT - PREDECISIONAL INFORMATION sequencers, the Operations Department staff would currently consider all applicable TS requirements, including TS 3.3.2 and 3.0.3. Conclusion The LCO actions of TS Table 3.3-2, "ESFAS Instrumentation," are applicable for determining the operability of ESFAS components; however, if a load sequencer is not operable, the more restrictive requirement of TS Table 3.3-2, TS 3.0.3, or the affected system LCO should be considered. Although the EDG LCO of TS 3.8.1.1.b had 'been used for sequencer outages in the past, the allegation's concern of possibly exceeding the LCO for TS 3.0.3 when the sequencers were previously deenergized could not be fully substantiated. Because there is no specific TS for the sequencers and considering (1) their unique interaction with numerous other systems and equipment, and (2) the varying degrees in which related failures, i maintenance work, and surveillances can affect the sequencers' associated functions, the inspection team concluded that additional J guidance for the operators is warranted. Therefore, this issue will be followed as an inspector followup item pending further review and evaluation and is identified as: IFI 50-424/90-xx-04 and 50-425/90-xx-04, " Lack of Operator Guidance Concerning the LCO Actions Applicable During ESFAS Sequencer Outages." 2.7 Reliability of Emergency Diesel Generators An allegation indicated that VEGP counted the number of starts and failures of the EDGs incorrectly and misrepresented this information knowingly in (1) a verbal presentation to the NRC, (2) a formal response to the Region II confirmation of action letter (CAL), and (3) LER 90-006, Revision 0, issued following the March 20, 1990, event involving failures of the EDG #1A. In addition, it was alleged that VEGP attempted to confuse the EDG reliability issue with Revision 1, and delayed LER 90-006, Revision 1, in order to avoid drawing attention to these incorrect representations. Discussion The inspection team reviewed the following: r, ' -LIMITED-DIST,IBUTIONMoGrJublicJelease~ 27
a i i LIMITED DISTRIBUTION - Not ForPublic_ Release s DRAFT - PREDECISIONAL INFORMATION 1) VEGP presentation in the Region II Office on April 9,
- 1990,
.j concerning the site area emergency event of March 20, 1990. This presentation is identified.as Enclosure 2 to the Region II meeting summary letter of May 14, 1990. i 2) -t p ..VEGP letter dated April 9, 1990,-in response to the Region II j . confirmation of action letter (CAL) dated March 23, 1990. + [ 3) LER 90-006, issued April 19, 1990, to report the site area . emergency event of March 20, 1990. 4 These documents and the following procedures describe the EDG 4 l operability status and the licensee's program for recording EDG start information and the EDG surveillance test frequency i-requirements: Procedure 55038-C,'" Diesel Start Log" i i j. Procedure 13145-1, "EDG Operation for Maintenance Troubleshooting or Maintenance Testing" i Procedure 14980-1, "EDG Operability Test" The licensee indicated in a transparency used'during the Region II L presentation that there were 18 successful starts on EDG #1A and 19 successful starts on EDG #1B between the loss-of-offsite-power event (March 20, 1990) and the presentation 'to Region II of 2 April 9,1990.. The inspection team reviewed the EDG start logs and the detailed EDG start records completed during the performance of 1: . Surveillance Procedures 13145-1 and 14980-1. The inspection team's review of these records indicated that there were 31 EDG #1A and 29 4 .EDG #1B attempted starts. Two of the EDG #1A and eight of the EDG
- 1B starts involved problems or failures.
On EDG #1A there were a -total of 29 successful starts and on EDG #1B there were 21 successful starts.
- However, there were several intermittent problems or.' failures during the EDG #1B start attempts.
Although there were 29 successful, sequential starts on EDG #1A, the inspection team identified that there were only 12 successful, z. sequential starts of EDG.#1B during this time period. TS 4.8.1.1.2.a requires that each EDG be demonstrated operable in accordance with the periodicity specified in TS Table
- 4. 8-1 by
' verifying'. that the EDG. starts and. assumes rated frequency and
- voltage in accordance with the-EDG surveillance test.
This i surveillance test -required ' a minimum run time of 1 hour at a designated load. The inspection team found that at the time of the presentation to the NRC, the operability test of the EDGs had been successfully.-de:nonstrated two times. In addition, the EDGs.had ~ LIMITED DISTRIBUTION - EotJor 'Public Release '#' v ~ 28 N (:
t i ' V ,,4IMITED DISTRIBUTION ~ Not~For Public.R_elease 4.. k DRAFT,.sPRELECISIONAL INFORMATION successfully passed four-operability tests before. Unit 1. entered i ~ Mode'2.--Therefore, the EDGs were reliable and operable before the- -presentation. i .The! NRCf Region II-Office was.not. verbally informed of the i incomplete 'information regarding the number: of EDG starts. until " June,11, '1990 l (approximately. 2 ~ months af ter - the presentation). Although Revision 1 of LER 90-006,.. dated June 29, 1990, correctly j identified the number of sequential, successful EDG starts 'from the ' 1end-of the-maintenance test program (i.e., the first successful-operability test per TS 4.8.1.1.2a) until the issuance of LER 90- )i 006,o Revision: 0, dated April 19, 1990, this revision- (June 29, ~ t 1990) ~ did not address. the number 'of EDG starts that should have been cited inithe presentation, in the VEGP letter in response to' [
- the CAL, and inLLER 90-006,~ Revision O.
The correct numberLof. sequential,'..-successful starts for 'EDG #1B was 12 and not 19.as -) ' indicated in the presentation. Therefore, the NRC was not informed l 'of the correct information in a timely manner. .i i Therinformation' presented to.the NRC did not completely describe L the problems and failures that occurred with EDG #1B. However, the ~ ] testimony indicates that the' general-manager's intention was to l [ demonstrate that'the problems involving the immediate trip of EDGs j identified-during and following the - March 20, 1990 event were-corrected prior to Unit 1. startup.. Therefore, a compilation of 'the s total number of ~ successful starts (i.e., a start that did not j immediately trip) was an important factor in his presentation. b The'. terstimony also indicated that the unit superintendent. (US) researched the EDG starting history for the NRC presentation based ' on a request from the general manager. The ' general manager did not ask the.US to prepare a complete description of the EDG starting history. Specifically, the general manager requested a summary of only~ the successful starts--the information concerning the EDG probleras and failures was-not requested. In addition, the US used 4
- the unit reactor operator logs instead of the EDG operating logs to compile.the EDG starting history.
The reactor operator logs did ~not contain a detailed deceription of problems'or failures which p occurred during'the EDG starts. The US did not receive specific i guidance concerning the type of EDG starts that he was requested to n summarise. -In addition, the testimony indicated that the original . assumptions and EDG lilB start information used in the presentation
- were~also~used in the,VEGP response to the' CAL, and in LER 90-006
, > issued ~ April 19, 1990. 'The'.) inspection' team's' review of the. Unit 1 EDG's reliability and operability status-between March 21:and June 14, 1990, raised the .following' additional-concern. -The' review was~ performed to verify i kLIMITED DISTRIBUTION A t For Publ-ic Release ~ N C%- 29 N '- ~ \\ / s p y.{ ) ?' -.- b _'__,..'__E__.. .a .m
a "=s W-W O LIMITED DISTRIBUTION - Not For Public Release DRAFT --PREDECISIONAL INFORMATION that all EDG failures were identified and classified as either valid or-non-valid and were reported to the NRC as required by TS 4.8.1.1.3 and TS 6.8.2. The inspection team discovered that the following f ailures during starts of EDG #1B had not been classified as valid or non-valid and, consequently, had not been reported to the NRC pursuant to TS 4.8.1.1.3 and TS 6.8.2. EDG Start Date Remarks 1-90-132 3/22/90 EDG
- trip, high-temperature lube oil.
M a i n t ena n c e troubleshooting test. 1-90-134 3/23/90 EDG
- trip, low jacket water pressure.
M a i n t e na n ce troubleshooting test. 1-90-136 3/24/90 EDG intentionally stopped due to alarmed condition, high jacket water temperature. Maintenance troubleshooting test. 1-90-157 5/23/90 EDG
- trip, high jacket water temperature M a i n t e na nce troubleshooting test.
1-90-160 5/23/90 EDG
- trip, 1ow turbocharger
-161 oi1 pressure. Maintenance -162 troubleshooting test. 1-90-164 5/23/90 EDG
- trip, high jacket water
-165 temperature. Maintenance troubleshooting test. i: These inspection findings were discussed with the engineering support manager who agreed that these types of failures have not - been reported. .The licensee committed to have all EDG start records reviewed for any unreported failures.
- The inspection team also found that a violation was previously
, identified for the failure to report all EDG failures in Inspection w( LIMITED DISTRIBUTION - Not Fo N lic Release q 3y
$ LIMITED DISTRIBUTION M Not For_Public Release DRAFT' PREDECISIONAL' INFORMATION ~ Report 50-424/87-57 dated November 1987. Although the failure to report - all EDG failures is a violation of TS 3.8.1.1.3 and TS 6.8.2, the inspection team concluded that the failure was the result of inadequate implementation of corrective actions to prevent recurrence of a violation and, as such, is a violation of 10 CFR 50 Appendix B, Criterion XVI, " Corrective Actions," and will be'followed as: VIO 50-424/90-xx-03, " Failure to Determine and Implement Adequate Corrective Actions." Conclusion The allegation that VEGP incorrectly counted the number of starts and failures of the EDGs and knowingly misrepresented the EDG reliability in order to mislead the NRC was partially substantiated. On the basis of the sworn testimony and its review of EDG records, the inspection team concluded that the Region II presentation was not intended to represent a specific number of successful valid tests as specified in RG 1.108 and TS 4.8.1.1.2a, but rather to describe the EDG maintenance test program and the EDG reliability status. Nevertheless, the inspection team concluded that the NRC was not informed of the incorrect information until the NRC asked.for it during the inspection. The lack of specific guidance concerning the EDG information desired, coupled with inadequate 'research of the EDG starting history, resulted in providing incomplete and therefore inaccurate information to the NRC. The CAL response and LER 90-006 were also incorrect because they were based on the EDG start information that was compiled for - the VEGP presentation in the Region II Of fice. The inspection team concluded that the failure to provide accurate information to the NRC was a violation of 10 CFR 50.9 requirements and will be followed as: VIO 50-424/0-xx-05; 50-425/90-xx-05, " Failure to Provide Accurate Information to the NRC." 2.8 Air Ouality of Emeroency Diesel Generator Starting Air System 'An allegation indicated that VEGP had no basis for its conclusions regarding the air quality of the EDG starting air system and misrepresented the air quality in the licensee's written response to the CAL. Discussion The inspection team reviewed the maintenance records and deficiency cards associated with Unit 1 FDG starting air system. The team O IMITED. DISTRIBUTION _.-Not'For Public p ease, 31 1.
7_. bi L 6IMITED DISTRIBUTION --'Not For Public Release DRAFT - PREDECISIONAL;INFORMATION 1 .'notedithat: the maximum ' dewpoint reading of 50 degrees Fahrenheit i .was1 established when preoperational tests.were initially performed on Unit -1 in November 1986. Dewpoint measurements were taken af ter i.
- this'date,~but not.on a scheduled frequency.
During-the latter 3 j part of 1988,-a monthly preventative maintenance (PM) schedule was L established =to. measure the EDG starting air system dewpoint. The current-PM program required c;hecking the dewpoint monthly, cleaning i 1 1 the' air' dryer condensing units, and cleaning the fan motors. In { addition,' Operating. Procedure -11882-1, "Outside Area Rounds," i required that the EDG starting air-system air receivers and. air dryers be blown down on a daily basis until they. were free of moisture. The. inspection team verified that the plant equipment 4 operators blew down the air-systems on each shif t during the performance of their rounds. F .A1 review of'the Unit 1 EDG maintenance history records indicated 1 that-the majority of the dewpoint measurements taken were within 4 Sspecifications. There were instances, however, when the' dewpoint F measurements were above - specifications. These conditions were primarily attributed to problems with (1)- the dewpoint measuring ' instruments, -(2) system air dryers being out of service - for extended periods of time, and (3) repressurizing the EDG air start ' system following maintenance. t The inspection team reviewed maintenance records associated with an internal inspection of the'EDG air start system air receiver, 5-- g micron control' air system filter inspection and replacement,-and .the' replacement.of the dewpoint measuring instrument with an EG&G F analyzer..Fellowing the' loss of offsite power. event of March 20, l1 1990, the control air system instrument lines were disconnected for maintenance troubleshooting and functional tests of Calcon sensors. i: The system engineers associated with this work stated that no l< evidence of internal moisture or corrosion was noted during j' inspection and calibration of the Calcon sensors or the control air ~~ system' instrument: lines when this equipment was disconnected for maintenance troubleshooting and testing. Conclusion The inspection. team concluded ' that the licensee did have an 1 adequate basis to assess the quality of the EDG starting air system.. This was; based primarily upon the records of the visual inspection-of:EDG air start system components for degradation. In addition,- the. PM.: program dewpoint readings have shown more consistency ~since the' licensee changed over to an EG&G analyzer. .The~ allegation'that VEGP did not.have a basis for their statements ,concerning:, EDG. air start system quality was not fully t-substantiated. T LIMITED -DISTRIYb'-WtWPublic'REleasQ ^ ' M 324 p <n e c m
-~ IdMITED DISTRIBUTION - Not For Public Release t DRAFT -'PREDECISIONAL INFORMATION 2.9 Renortability of Previous System Outaces An allegation indicated that VEGP failed to immediately notify the NRC as required by 10 CFR 50.72 when VEGP identified that both trains'of the, containment fan coolers (CFCs) had been previously inoperable'at the same time on Unit 1. Discussion The inspection team's review of plant records indicated that this condition occurred when EDG #1A was declared inoperable when tape (used when the EDG was being painted) was found on the EDG fuel rack. The tape.kept the fuel injector piston from moving and injecting fuel into the EDG. With EDG #1A inoperable, the equipment associated with the Train A was also inoperable. In che - process of investigating the installation of the tape, VEGP identified that this condition existed during a period when the Train B containment fan coolers were also in a degraded condition for maintenance. During the performance of Surveillance Procedure 14623-1, Train B containment fan cooler (CFC) 1-1501-A7-003 failed to start in slow speed. LCO 1-90-560 was initiated at 0115 hours on June 19, 1990, j and maintenance on the CFC was initiated. The CFC was returned to operable-status on June 19, 1990, at 1415 hours. Approximately 9 hours later [on June 19,1990, at 2359 (LCO 1-90-562)], EDG #1A was j determined to be inoperable because the tape had been installed on the fuel rack. On July 17, 1990, VEGP issued LER 90-014 to identify the previously unrecognized violation of the LCO in accordance with 10 CFR 50.73. Conclusion Based upon the fact that VEGP did not become aware that both trains of CFCs were simultaneously inoperable until after the Train B CFC fan had been returned to service, the immediate notification requirements of 10 CFR 50.72 were not applicable. The allegation that VEGP failed to immediately notify the NRC upon discovery of the previously degraded condition of the CFCs was not fully substantiated. 2.10 Intimidation of Plant Review Board (PRB) Merabers An allegation indicated that Plant Review Board (PRB) members were - allegedly intimidated and pressured by the general manager in a PRB meeting. The meeting occurred in February 1990, to determine the LIMITED QISLRIBUTIONdat-~'7or Public Release f Nd 33' V'
1,- .i .l I 'l t. LIMITED DISTRIBUTION % Not For Public Release DRAFT - PREDECISIONAL INFORMATION 4 acceptability-of the. safety analysis.for the installation of the .' FAVA-microfiltration system. Discussion
- j.
- As ~ discussed in Section 2,2 of this inspection report, several Esafety evaluations were performed for the installation of.a 1
-temporary modification ' which installed the: FAVA microfiltration 1 system.. Discussions with ' PRB ' members indicated that during the. ~ 2 review of these -safety evaluations, _various 'PRB members had expressed reservations on several occasions concerning thez acceptability of.the installation of the FAVA system. 1 i j. ' Despite these reservations, the inspection team's review of the PRB Meeting minutes. associated' with this. temporary modification ' identified few instances of the PRB members documenting = their dissenting opinions.. Specifically, PRB meeting 90-15 (dated
- February 8, ' 1990) documented one PRB member's negative vote and l
dissenting opinions regarding the acceptability of exempting the temporary modification from regulatory requirements. and the 2 l -- adequacy of the system's safety evaluation. .PRB Meeting 90-28 ) (dated March 1, 1990) indicated that 'information and issues regarding the FAVA system's safety analysis were presented to the P PRB and that the ~ general manager solicited ' written cormnents and j questions - from-: other members for resolution. The only other . example. was in PRB meeting 90-32 (dated March 6, 1990) which identified a dissenting opinion related to the acceptability of j c . voting ' on the FAVA system.' installation when the PRB member who raised the initial questions and concerns on the operation of the i . FAVA l system was not present. t Discussions with the PRB members indicated that during.the various ' f PRB meetings concerning the installation.of the FAVA system, the PRB members felt intimidated and pressured by the presence of.the general manager.at the PRB meeting. The sworn testimony confirmed t that on one occasion an alternate voting member felt intimidated 4 and feared retribution'or retaliation because the general manager was present at 'the meeting and the PRB member knew the general manager wanted to have.the temporary modification. approved. However, the testimony also indicated that the PRB member did not alter his vote and felt comfortable with how-he had voted.- In- ^ addition, the.PRB member was not aware of any occasions on which he or:any;other PRB: member had succumbed to intimidation or feared 1 retribution. The inspection team. verified that the general manager was informed i ~ following this meeting that several PRB members viewed his presence as intimidating. As a result, on' March 1, 1990, the. general ~
- \\ LIMITED STpI t-for y -it'Yelease i
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- I/IMITED DISTRIBUTION -' Not For Public Release DRAFT - PREDECISIONAL INFORMATION i
manager. met with.all~'PRB members to' reiterate the member's' duties and responsibilities. He.specifically told the members that his i ' presence: at-PRB1 meetings must_ not-influence them and' that l calternates'should be selected who would feel comfortable with this l iresponsibility. He also~ addressed the difference. between professional differences of opinion and safety or quality concerns, j and their' respective methods for resolution. Conclusion e The inspection team concluded that in one case a PRB voting member felt intimidated ~and feared retribution because the general manager was present at the PRB meeting. However, this member did not change,his vote-in response to this pressure and the general ' manager met with the PRB;to allay fears. Based on the testimony, the inspection team' concluded ' that retribution did not occur. (Nevertheless, this confirmed event and the absence.of dissenting . opinions - in the PRB meeting. minutes indicate. that. there was a potential for an adverse affect on open discussions at the meeting. 3 The licensee needs to ensure that PRB members freely and openly express their technical opinions and safety' concerns. j 2.11' Personnel Accountability As a '~ result - of several. comments and. questions by the licenced operators.to the inspection team, the team reviewed the method'used to rate the performance of the shift superintendents and unit shif t supervisors. Discussion e The operationsL manager stated that the shif t superintendents (SSs) reported.directly to the operations manager and that he personally prepared their performance appraisals. The inspection identified that the -SSs reported to the unit superintendent (US), and that the ~ ,US' personally prepared the performance appraisals of the SSs. The. personnel accountability system, first used in 1989, was a pay- .for-performance methodology. Annual pay increases and a percentage oflthe Operations Department bonus were dependent on their ratings in accountability - categories. Each accountability category was subdivided into performance. categories. Most of the performance
- categories were based upon group performance.
Once these are i eliminated,.- any. differential in pay will result from eight performance categories. Implementation of-the plan in 1989 could
- result
- in up.to an $8,000-a-year dif ference in bonus pay to a shif t superintendent.
The performance categories and their relative
- weights are
TIMITED-DISTRIBUT o LPublic 4eleas p q t ? raa
4 IIMITED DISTRIBUTION - N For Public 4elease. DRAFT - PREDECISIONAL INFORMATION s e Personnel safety 4.1% e Regulatory compliance 10.2% e ESFAS actuation 12.2% e Reactor trips 10.2% e MWO _ perfonnance 4.1% e Special projects 8.2% o Personnel development 30.6% e Training 20.4% Therefore, 51 percent will be associated with personnel development and training and 32.6 percent will be associated with the number of LERs, and violations (i.e., regulatory compliance (10.2 percent), ESFAS actuation (12.2 percent) and reactor trips (10.2 percent)]. Conclusion The inspection team concluded that there was a potential disincentive for identifying items which may result in LERs or violations. In addition, the inspection team concluded that the operations manager provided incorrect or inadequately researched information to the inspection team. The inaccurate information concerned whether the operations manager personally performed the j performance appraisals of shift superintendents. The information was not very important because the inspection team did not use the information as the basis for a significant inspection finding. The inspection team concluded that this failure to provide accurate information was an example. of a violation of the 10CFR 50.9 requirements to provide accurate information to the NRC and will be followed as: 1 VIO 50-424/90-xx-05; 50-425/90-xx-05, " Failure to Provide Accurate Information to the NRC." 3.0 EXIT INTERVIEWS The inspection scope and findings were summarized on August 17, 1990, with those persons indicated in Appendix 2. The inspection team described the areas inspected and discussed in detail the inspection results. The licensee made numerous dissenting comments. The licensee did not identify as proprietary any of the materials provided to or reviewed by the inspector during this inspection. ^ LIMITED DISTRIBUTION - t For Public Release sy
fLIMITED DISTRIBUTION - Not For\\Public Release DRAFT - PREDECISIONAL INFORMATION ~N i APPENDIX 1 LIST OF TRANSCRIBED INTERVIEWS DATE TIME PERSON 8/14/90 904 hours George Bockhold 911 hours Jim Swartzwelder 1023 hours Harvey Handfinger 1026 hours Bill Diehl 1109 hours Mike Horton 1335 hours Mike Chance 1136 hours Jimmy Paul Cash 1338 hours Dudley Carter 1529 hours Bruce Kaplan 1625 hours Greg Lee 1800 hours Jeff Gasser l 8/15/90 906 hours Allen Mosbaugh 937 hours Ernie Thornton 1009 hours John Gwin 1048 hours Steve Waldrup 1335 hours Jerry Bowden 1452 hours John Williams 1637 hours Carolyn Tynan 1730 hours John Williams l l LIMITED-DISTRIBUTION-dot For Public1telease ,f - ~~- 37 U
m , LIMITED DISTRIBUTION - Not'For Public Release DRAFT - PREDECISIONAL INFORMATION ~ \\ APPENDIX 2 PERSONS CONTACTED Licensee Employees
- J. Aufdenkampe, Manager Technical Support
- G.
Bockhold, Jr., General Manager Nuclear Plant
- D.
Carter, Shift Superintendent J. Bowden, Work Planning J. Cash, Unit Superintendent M. Chance, Senior Engineer, Engineering Support
- S.
Chesnut, Technical Support C. Coursey, Maintenance Superintendent W. Diehl, Shift Supervisor, Operations
- G.
Frederick, Safety Audit and Engineering Group Supervisor J. Gasser, Shift Superintendent, Operations
- L. Glenn, Manager - Corporate Concerns
- D.
Gustafson, Maintenance Engineering Supervisor J. Gwin, Corporate System Engineer
- H.
Handfinger, Manager Maintenance
- K. Holmes, Manager Training and Emergency Preparedness
- M.
Horton, Manager Engineering Support B. Kaplan, Senior Engineer, Engineering Support G. Lee, Plant Engineering Supervisor, Operations
- R. LeGrand, Manager Health Physics and Chemistry W. Lyons, Quality Concerns Coordinator
- G. McCarley, Independent Safety Engineering Group Supervisor
- C. McCoy, Vice-President, Georgia Power Company
- R. Mcdonald, Executive Vice-President, Georgia Power Company
- D. Moncus, Outage and Planning
- A. Mosbaugh, VEGP Staff R. Odom, Nuclear Safety and Compliance Manager
- A. Rickman, Senior Engineer - Nuclear Safety and Compliance
- L. Russell, Independent Safety Engineering Group, SONOPCO
- M. Sheibani, Senior Engineer
- C. Stinespring, Manager Plant Administration
- S. Swanson, Outage and Planning Supervisor
- J.
Swartzwelder, Manager Operations E. Thorton, Shift Supervisor, Operations
- E. Toupin, Oglethorpe Power Corporation C. Tynan, PRB Secretary S. Waldrup, Planning and Scheduling Supervisor J. Williams, Shift Superintendent, Operations Attended exit interview, August 16, 1990.
LIMITED DISTRIBUTION..-Not-For Public Release k./ / 38 N Nj
I , LIMITED DISTRIBUTION,- Not For Public Release DRAFT - PREDECISIONAL'INFORMATION ' ' ~ " ~ ~ APPENDIX 2 PERSONS CONTACTED (continued) j NRC-Employees Who Attended Exit Interview R.'Aiello, Resident Inspector - Vogtle B.:Bonser, Senior Resident Inspector - Vogtle i M. Branch, Senior Resident Inspector - Watts.Bar K. Brockman, Chief, Reactor Projects Section 3B - RII R. Carroll, Project. Engineer - RII L. Garner, Senior Resident Inspector - Robinson N. Hunemuller, Reactor Engineer - NRR D. Matthews, Project Director - NRR J. Milhoan, Deputy Regional Administrator - RII L. Reyes, Director Division of Reactor Projects - RII i R. Starkey, Resident Inspector - Vogtle P. Taylor, Reactor Inspector - RII M. Thomas, Reactor Inspector - RII C. VanDenburgh, Section Chief - NRR J. Wilcox, Operation Engineer - NRR i i l' 1 \\- "^ y p . Q IMITED DISTRIBUTION - Not For-PublYc~ Release 39 }l
~ LIMITED DISTRIBUTIO -'Not ForJhtblic Release s DRAFT - PREDECISIONAL INFORMATION \\ 3 APPENDIX 3 \\_ LIST OF ACRONYMS AOP Abnormal Operating Procedure ARB Alternate radwaste building ASME American Society of Mechanical Engineers CAL Confirmation of action letter CFC Containment Fan Cooler CFR Code of Federal Regulations CIV Containment isolation valve DC Deficiency card DRP Division of Reactor Projects EDG Emergency diesel generator EPRI Electric Power Research Institute ESF Engineered safety features ESFAS Engineered safety features actuation system ] .FSAR Final Safety Analysis Report HUT Holdup tank I&C Instrumentation and controls IFI Inspector followup item IST Inservice test kV Kilovolt LCO Limiting condition for operation LER Licensee Event Report MWO Maintenance work order NRC Nuclear Regulatory Commission l NRR Nuclear Reactor Regulation i NSCW Nuclear service cooling water NSSS Nuclear steam supply system OI Office of Investigations PM Preventative maintenance PRB Plant Review Board psig Pounds per square inch gauge i PVC Polyvinyl chloride i QA Quality Assurance RII Region II Office RCS Reactor coolant system REA Request for engineering assistance RG Regulatory Guide RHR Residual heat removal SER Safety Evaluation Report SI Safety injection SONOPCO Southern Nuclear Operating Company SRM Source range monitor SS Shift superintendent. SSS Shift support supervisor LIMITED DISTRIBUTION' Notd or-Public._ Release L 40
pm 4-em M 4 4 Jw s-J 4 J JeMe-= >--u4A s ri-e 2 4 ,+-5v-4 e' i LIMITED DISTRIBUTION - Not For Public Release
- DRAFT - PREDECISIONAL INFOR jMA ION APPENDIX 3 LIST OF ACRONYMS - (continued) i i
STS Surveillance task sheet TCP- - Temporary change to procedure TS Technical Specification USS Unit shift superintendent UV. Undervoltage VEGP Vogtle Electric Generating Plant VIO Violation A r I l l l i - QIMfTEQ DISTRIBUTION __ -NdPilblic Jelease' 41
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....m., pom ing, no drugs"ung to e "no 5iE. cca 'kJl$N! Se*pt i theclub. sign posted cuiside 4 t i linked to a Virgin Islands drug 29. had been Another "no 1:ltering, ring. No cr in that caseeests have been made either. GA, Souennah no Riwr iPla t Vogtle n L . ater pump w 1 sh....w,htLdown ...v... ' ByJehn Wlaters 4 sesswneer. i.Q L. dieofNovember. r i the water within tSaturdarain 1 Improperty set a pump that reeltculates water toequipment i monitoring could low enoughso Plant Vogtle's Unit t remoter neltopbad on.put the reactor vene i ,geel dGring a refboling out. However instrum.ents that Agghl e* ! Jeg # gelapmonitor the,waterlevelin theTes-3 't ,shuhlew.,... r i , ahmt,a mimius ime s.tedens,.which lasted ly,Mr.parently weren't set proper, Mecoysaid. 4 In theremeter'sfuelgoing The waior dr i . l. fHm( levelofthepump'ained below the .gress, 1 ; W de t e >M.0filcials'y%grees to IM do. machint beganpum sintaka andthe ehich lth Geergle'P
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Tha pump was shut off, tip h and then the rectroulat. sto Taynesbors 3 there wasnedangeran[ i .Thewholeproce,sslookaboutp ' ',,30 ofradiatten. 3. E i Reactor fuel emits heat, / des 30 minutes.have si r. j of. coolant within the reestor vos/ Of5alais v-. i nel could cause the $4el.h . faulty water level monitoringnce fixed t i ..androlesegedioactivily,w. melt equ,igment.headded., ~ i grees. Kan McCoy, vlos presidentWater bissim en,. .'mu ustlan "s was not a threa...laningsW ' o m oous,c wsu; of Plant Vogtle, saidit would have real se,nsitive shout losing coo i -= taken.about two hours before the flow through the tsactor and as an heated enough to start belling. water within the re i industry, we are trying to prevent any kind of {'.ered by about five feet of waterAt the time, the fue i w. , v..
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The Nuclear Regu,latory Com. andMr i takense. M veral saW 18 wouW have, mission, which ovwsmes comsner,- i g-chl tar boiled dow. beibre the wa-W Wh i .r.p f.;..... o 1 ful. That's..n to the top of the Sundey morning a. wu 6 nd safety in4 . didn't do th C11anc,," Ms. lag,Unit 1is do.. ;1.g, gach, officials tthisweek Mr.McCoysaidare espect waterl.f a i _.
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an emergency or any special te r. wnfb .:,.,Z s boek, rm not ausrecommendations is espected to restart in th erefusDngand part," he and son, tha i e said-1 seriously,'? d. "But we take this. ?""tthefaq P;rfeet 4 e. ( e said, the d o .. v. FA" eparts ssor: A= y E i ucl.% e .cesv. q,ar pmanagw, ears UH OUR ed" I 4 i f, 1e Broad StreetByJohn Wittters alble - and that t seenweser 5 nuclear pew will M ons of the become the cornerst % ggg]gg,. 4me.... ,b
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i-NRC ENFORCEMENT CONFERENCE PIPING PENETRATION AREA FILTRATION AND EXHAUST SYSTEM INOPERABILITY i ~ i OPENING STATEMENT GPC / NRC DESCRIPTION OF SYSTEM BARNIE BEASLEY PURPOSE TECHNICAL SPECIFICATION CHRONOLOGY OF EVENT BARNIE BEASLEY CAUSES OF EVENT BARNIE BEASLEY SAFETY SIGNIFICANCE ANDY WEHRENBERG j CORRECTIVE ACT!ONS BARNIE BEASLEY l
SUMMARY
KEN McCOY l l i yi
i l PURPOSE OF PIPING PENETRATION FILTRATION SYSTEM l T Limit / Reduce releases due to ECCS recirculation and component leakage during a LOCA. 1 Maintain negative pressure in piping penetration areas. Additional filtration through charcoal filters. Sends exhaust to plant vent stack. Acceptance Criteria lodine leakage to both offsite and control room locations during post-LOCA will meet 10CFR 100 limit and GDC 19 acceptance criteria 1
PIPING PENETRATION AREA FILTRATION AND EXHAUST SYSTEM (SIMPLIFIED DIAGRAM) PLANT VENT STACK C EXHAUST f [ DAMPER 1PV-25518 J PRNG PENETATM)N d-ROOM FILTER & d hk j (# EXHAUST UNIT i TRAIN B y I l [ PIPING PENETRATION + COOLERS ? ROOMS & OTHER LOCATIONS Pb4NG PENETATION ROOM FILTER & j j r-EXHAUST UNIT p EXHAUST DAtrER j( 1PV-25508 PLANT VENT STACK C C i e
TECHNICAL SPECIFICATION i T.S. 3.7.7 Two independent Piping Penetration ' Area Filtration i and Exhaust Systems shall be OPERABLE. l APPLICABILITY: MODES.1,2,3, and 4 i ~ ACTION: i -With one Piping Penetration Area Filtration and Exhaust System inoperable, restore the inoperable system to OPERABLE status within 7 days or be in at least HOT STANDBY within the next l 6 hours and in COLD SHUTDOWN within the following 30 hours. l p f
I TECHNICAL SPECIFICATION SURVEILLANCE l REQUIREMENT u 1 TECHNICAL SPECIFICATION 4.7.7a SURVEILLANCE REQUIREMENT:
- Once per 31 days, initiate flow through the HEPA filters and charcoal adsorbers
- Verify that the system operates for at least 10 continuous hours with the heater control circuit energized PURPOSE:
4 i To verify the system operates for 10 continuous hours to reduce moisture buildup in the adsorber and HEPA filters 9 i 1 e-
EVENT CHRONOLOGY 1 2/1/94 Clearances prepared by work planner for use during electrical penetration filter units deletion. 2/23/94 Clearances reviewed by Support Shift Supervisor. 2/28/94 Train 'A' Clearance authorized and installed. 3/l/94 Train 'B' Clearance authorized and installed. 3/15/94 Train 'A' Piping Penetration Filter Unit surveillance test completed and documented as satisfactory. 3/28/94 Train 'B' Piping Penetration Filter Unit surveillance test completed i and documented as satisfactory with damper indication discrepancy observed 4/1I/94 Train 'A' Piping Penetration Filter Unit surveillance test performed. WRTs on damper indications written l 4/20/94 Electrician, during troubleshooting, discovered that the clearances removed r the power supply for the light indicators - USS notified, but he did not realize that the dampers were not operable 4/24/94 During Work Order closeout, Piping Penetration Filter Unit impact recognized, dampers energized and operability /reportability evaluation initiated. 4/25/94 Engineering review of configuration and impact on piping penetration filtration system functions begun. 4/26/94 Reportability/ operability determination completed; NRC notified. t - ~...
r CAUSES OF EVENT Inadequate Reviews of Circuit Breaker Clearances - Personnel errors due to inadequate reviews of Train 'B' drawings - Drawing Discrepancies - Exhaust damper not shown on Train 'A' drawing & load list Failure to Discover Event Earlier - Personnel Errors - Operators not resolving the position indication problem f Surveillance Guidance Unclear for Damper Position l 1 I . l
'I i PREVIOUS SIMILAR EVENTS No previous events were found with both trains of piping penetration. filtration system inoperable at the same time due to exhaust dampers being deenergized i One occurrence was found with one train of piping penetration filtration system inoperable for longer than the 7 days allowed out of service time due to an exhaust damper being deenergized. The train 'A' exhaust damper was deenergized from October 28 - November 9,1988, when an Electrical Penetration Filter System circuit breaker was opened. P i i e I i t i
k SAFETY SIGNIFICANCE i I System Acceptance criteria i i - Limit / reduce releases to both offsite and control room locations due to leakage from the piping penetration rooms and ECCS components during post-LOCA condition to meet: 10 CFR 100 Limit. . GDC 19 Criteria [ i I l I
i CORRECTIVE ACTIONS i l \\ Involved personnel have been counseled on significance of l plant configuration control Review event with work planners, system engineers & licensed operators, emphasizing configuration control Drawings and load lists corrected Tech. Spec. surveillance procedures being reviewed to l determine ifimprovement is needed i Sample of drawings revealed no similar drawing / load list problem The drawing review is continuing i
i l l
SUMMARY
1 i l l GPC considers this a significant event due to failure of administrative . controls. The piping penetration filtration system was degraded due to l -personnel errors and drawing error. I Problem discovered by licensee during performance of surveillance testing. Dampers restored to service as soon as system impact realized. i l Reportability determination made. l Minimal safety significance since the GDC 19 and 10 CFR 100 acceptance criteria were satisfied. i I
PIPE PENETRATION AREA LEAKAGE EVALL ATION MODEL ECCS ID0P OUTSIDE CONTAINMENT LEAKAGE (2 GPM) l 1 I ~ PIPING PENETRATION 2700 CFM UNFILTERED J L AREA LEAKAGE TO ATMOSPIIERE i FILTER EFFICIENCY + ELEMENTAL = 0.90 ORGANIC = 0.30 PARTICULATE = 0.90 o FILTERED RECIRCULATION FIDW = 14460 CFM
RESULTANT THYROID DOSES 'RE% CURRENT FSAR ANALYSIS EAU IFZ CONTROL ROOM CONTAINMENT MAKAGE 50.6 57.2 26.0 CONTAINMENT PURGE 0.3 0.1 0.0 FILTERED EXHAUST (2700CFM) ECCS EAKAGE 1.0 1.5-0.3 TOTAL 51.9 58.8 26.3 REVISED ANALYSIS UNFILTERED EAKAGE i (2700CFM) i 1 ECCS EAKAGE 1.4 ~ 'IUTAL 27.4 l
l C0;SSERVATIVE MODEL PARAMETERS ANALYZED EXPECTED SOURCE TERM - CORE FRACTION (%) 50 10 - IODINE FORM (%) 91-, 4, 5 NO ORGANIC (EEMENTAL ORGANIC, PARTICULATE) ECCS LEAKAGE (GPM) 2 < 0.1 PIPE PENETRATION. AREA 2700 1800-2600 i LEAKAGE (CFM) PPAFES FILTER EFFICENCY (%). 90, 30, 90 >= 98.8 PPAFES FILTER RH (%) 95 <= 74 CONTROL ROOM FILTER EFFICIENCY (%) 99, 99, 99 >= 99.8 CONTROL ROOM INTAKE (CFM) 1500 < 1000 RELEASE PATIIWAY DIRECT TO AUXIUARY ATMOSPIIERE BUILDING - PLATE 00T NONE YES - SETTUNG NONE YES -HOLDUP / DECAY NONE YES
SAFETY SIGNIFICANCE SBillARY a EAB LPZ CONTROL ROOM THYROID DOSE 300 300 30 i ACCEPTANCE CRITERIA (REM) t RE-ANALYSIS WELL WITHIN WELL WITHIN 27.4 RESULTS CONCLUSION: THE PPAFES REMAINED CAPABLE OF MEETING TIIE ACCEPTANCE CRITERIA DURING TIIIS EVENT. t 4 _.__..-.__-__ -.--_~----..-_-____.___ -_____--.__-_ - -_-.-_-- -.----- - _-- - - __.____- -.__- - - _- - _,___._ __, _____
PIPE PENETRATION ARBA LEAKAGE EVALUATION MODEL ECCS LOOP OUTSIDE CONTAINMENT LEAKAGE (2 GPM) 1 I C PIPING PENETRATION 2700- CFM UNFILTERED J L AREA LEAKAGE TO ATMOSPIIERE FILTER EFFICIENCY + ELEMENTAL = 0.90 ORGANIC = 0.30 PARTICULATE = 0.90 i FILTERED RECIRCULATION FLOW = 14460 CFM m a-- m- - H b m.- a s-+ m
~] o RESULTANT THYROID DOSES ' REM) CURRENT FSAR ANALYSIS EAB IPZ CONTROL ROOM CONTAINMENT EAKAGE 50.6 57.2 26.0 CONTAINMENT PURGE 0.3 0.1 0.0 FILTERED EXHAUST (2700CFM) ECCS EAKAGE 1.0 1.5 0.3 TOTAL 51.9 58.8 26.3 REVISED ANALYSIS UNFILTERED EAKAGE (2700CFM) ECCS EAKAGE 1.4 TOTAL 27.4
CONSERVATIVE MODEL PARAMETERS ANALYZED EXPECTED SOURCE TERM - CORE FRACTION (%) 50 10 - IODINE FORM (%) 91, 4, 5 NO ORGANIC (EEMENTAL ORGANIC, PARTICUIATE) ECCS LEAKAGE (GPM) 2 < 0.1 PIPE PENETRATION AREA 2700 1800-2600 LEAKAGE (CFM) l PPAFES FILTER EFFICENCY (%) 90, 30, 90 >= 98.8 PPAFES FILTER RH (%) 95 <= 74 CONTROL ROOM FILTER EFFICIENCY (%) 99, 99, 99 >= 99.8 CONTROL ROOM INTAKE (CFM) 1500 < 1000. RELEASE PATHWAY DIRECT TO AUXIUARY ATMOSPHERE BUILDING j - PLATE 0UT NONE YES - SETfLING .NONE YES - HOLDUP / DECAY NONE YES
SAFETY SIGNIFICASCE SLMMARY EAB LPZ CONTROL ROOM THYROID DOSE 300 300 30 ACCEPTANCE CRITERIA (REM) i RE-ANALYSIS WELL WITHIN WELL WITHIN 27.4 RESULTS CONCLUSION: THE PPAFES REMAINED CAPABLE OF MEETING THE ACCEPTANCE CRITERIA DURING THIS EVENT.
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[~ [. i o p (,%g/ The United Statesg Suelear Regulatory t s l ,( i .I l Nuclear Plant l Senior Reactor Operator License Certification d l granted to William F. Kitchens effective on the sixteenth day of September, Nineteen Hundred and Eighty-Six, for having met the provisions of - the U.S. Nuclear Regulatory Commission's regulations and l having demonstrated the knowledge, skills and ability to carry h out the responsibilities of the position of Senior Reactor Operator at the l Vogtle Electric Generating Plant, Unit No. I 1 l Facility Docket No. 50-424 Senior Operator License Number 20467 In accordance with the terms and conditions of ~ Operator Docket Number ~55 20117 6 A*. w. jed s. / t l. W w m _ _....- n m. g. )h % L. W,~- .t
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l mT; The United States '/ Nuclear Regulatory Commission 4..... Nuclear Plant l Senior Reactor Operator License Certification r granted to Jimmy P. Cash l effective on the thirty-first day of January, Nineteen l Hundred and Eighty-Nine, for having met the provisions of the U.S. Nuclear Regulatory Commission's regulations and i i having demonstrated the knowledge, skills and ability to carry i out the responsibilities of the position of Senior Reactor Operator at the Vogtle Electric Generating Plant, Unit Nos. I and 2 1 Facility Docket Nos 50424 and 50-425 in accordance with the terms and conditions of 1 i Senior Operator License Number 20461 Operator Docket Number 55-20551 i 1 J m _ a_ a _ pfV W a-. e ..n.,-..-, , - - -m c-
l ,e" "%,, r ',. . y 2 , n...<- g The United States b; i i '*4.. f.. # Nuclear Regulatory Commission Nuclear Plant Senior Reactor Operator i License Certification i l granted to l John E. Bowles effective on the twenty-fourth day of January, Nineteen Hundred and Eighty-Nine, for having met the provisions of i the U.S. Nuclear Regulatory Commission's regulations and having demonstrated the knowledge, skills and ability to carry out the responsibilities of the position of Senior Reactor i Operator at the Vogtle Electric Generating Plant, Unit Nos. I and 2 Facility Docket Nos. 50-424 and 50-425 i 4 In accordance with the terms and conditions of Senior Operator License Number 204.58 1 4 Operator Docket Number 55-20395 J e ~ -. i Schw f aesion II
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la addition, the VOTE's trace was revicwod for the test performed dur ,,i confirmed if the valve was or was not going fully into the seat. An impmv [ ' }, 4. i /@.switches on butterfly valves and is now used at Vogtle. His omsor ng.opll t' D. oflooking at the spring pack force and provides a much cicarse pi ts 1 c rconhowhardthediskisdrivenintotheseat. His$' f. sens:r us not com finallydt should be noted that the "dp;w, w P.%g.k oEp::u m QMJ... s u,; pm.mercially available when IEV 1979 w i; T ,.: mW d 4;. c .A Hl. g +- As Found"LLRTient j 1. demonstrated that there had bocn no valve degradation slace the previo : S ~. ' dy1 ' '? .,. 33, hn,. -y;.*;Q:.. m; a. f ;,a - , ',.,:n. : .i,()jgbyig.;',y.q;t.Tc'.6]fl-n g:
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\\ + Tu Rate ONLY those causes thatefcr to Figure 8 for addit , M '.*l. .,1aRoot (Direct) cause, b8econdary cause A 'i; ' ft ".. ~ 4(l. . I. 'L g 4 ses <, y. } .y . - {wayWAn uATEntAt usAoi!,ACAUSE? .......... r pu,,,,t.,,r, h;r..S.'c$g#cN$fdi%Ifo?titil sI pk..g..,h>gi. C:en>g, y_ a s 4., W ' k:' ] 3 @ % k.% " A d, M ~~,' $,y.Me Wrono mWedMs used. i A E 5 c' WHYhfkBTESTI'Nd C5hEdu..no d.v.as or m e .m.... ~.< - "i.e My..; g [ A lik eli$i N h'h' f*' I,"# h, c.. s { s.... S.{,'U --esruhMsMMd,hd@Mb k ~'k,s A. .. n.1 db'.:d, ~' bl. ' A. Required testino not performed C. Testino not performed as scheduled.8. Inadequate post ma 1 ..%'p 3, estino ?,; D. Testino not specmed _E. Improper test equipment .i F. Test results not reviewed for acceptability by approp i t .~ t e r a e personnel Recommendations (Describe corrective actions for causes ind Sd's R't.s.<4 cated above): p'e se,,.(O da ' 'Y " hE' {,: i g g s ' s l f l 3 ? T. ,,(;>4{< , h, ! *, ..f. , p[, ,.p,, 'a , f., .. l ',' ' s,} h.. '.. : ) j. ' & 'lf .,.he,. y, t ... >.y.n,, . f N , f.,p - r.
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4 F-f()$N k f 4 1.0 Introduction i The guidance and criteria contained in this document pertains to the pro-tection of Safeguards Information as defined in 10 CFR part 73. It is intended to assist licensees and other persons who possess Safeguards In-4 l formation in establishing an information protection systes that satisfies the i specific requirements of 573.21 of part 73. protection seasures and pro-cedures other than as set forth in this document may be used to satisfy the regulatory requirements if a cosparable level of protection is achieved. l There are no reporting, record keeping, or security plan developesent pro-f 4 l visions associated with this rule. i l 2.0 Scope of the Rule 2.1 Facilities and Material Type Covered Safeguards Information is limited to information regarding the physical pro-i tection of : - Operating power reactors. =l - $sent fuel shipments, and 1 - Activities involving formula quantities of strategic special nuclear material (for information J not otherwise classified as National Security Information j or Restricted Data under 10 CFR part 95) In regard to fact 11 ties that possess formula quantities, the rule applies to both fresh and irradiated material or combinations thereof and includes HEU { fuel fabricators, non-power reactors, away-fron-reactor spent fuel storage, I and laboratories. e l Information concerning the physical protection of special nuclear material of moderate and low strategic significance is not covered by the rule. j l 2.2 Types of Information included 3 l Safeguards Information is information that discloses equipment, procedures, conumanications, or response plans used by a licenses to protect certain I l l l special nuclear material or fact 11 ties. It includes: I I - The overall physical security and safeguards contingency f [ plan - Drawings, sketches and diagrams that show locations of site safeguards features l { I - Details of the intrusion alars system - Guard orders and procedures /~ /7 1 i . /(/
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--_w r w'. = m', [ n' i} q - Details of on-site and off-site response forces I - Drawings that explicitly identify certain areas or I j equipment at power reactors as being vital for pur-poses of physical protection. i j - Portions of guard training and qualification plans that disclose specific safeguards features or response procedures - Correspondence, inspection reports and audits that contain i t a#W of the above or that disclose weaknesses in the pro-t taction system. l Matter other than ecuments and draviags that contain Safeguards Infomation, j i e such as alarm system computer programs, data processing storage disks, afero-j films or photographs, should be afforded the same level of protection. (All ) 1 items described in 10 CFR 2.4(q) should be protected.) l j Certain types of information, even though possibly regarded as safeguards j i Information, do not fall within the scope of the rule. Most notably are ) generic studies, reports or analyses conducted by or on behalf of the NRC, Itcensees, or applicants which concern the safeguarding of nuclear materials or fact 11ttes. Additional types noi included in the rule are: - Documents, drawings, or reports submitted by appitcants or licensees, or produced by the staff, in response to the 4 environmental and safety requirements contained in parts 1 l l 50, 51,70, and 71. - Routes and quantities for spent fuel shipments. - Information concerning Itcensee control and accounting pro-cedures or inventory differences for special nuclear material, or source material and byproduct materia). e - Any information already in the public domain including com-mercial safeguards equipment specifications, catalogues and I 4 4 equipment buying data. i - Portions of guard qualification and training plans that do not disclose factitty safeguards features or resper.sc pro-cedures. Normally the composite (i.e. sum of all parts) physical security and safe-l guards contingency plans would be considered single entities for protection j purposes. However, licensees and applicants may find it more appropriate to segregate general or non-sensitive information into unprotected appendices or attachments. Also, guard orders and standard operating procedures may Il 1 -t-a I ed f
4 3 l l' [ 1 be segregated into protected and unprotected portions. (Note that the rule requires guard qualification,and training plans to be segregated) In regard to engineering or construction drawings, all the revisions that sestantially represent the final design features of the physical protection Initial re-4 system would be considered to contain safeguards Information. quests for bids or proposals and origin?1 design sketches, for example would probably not qualify as Safeguards Information. Specific items of design that should be protected faclude: J - Location and types of alars devices i - Alars system schematic and wiring diagrams (but not wiring I lists) - Defensive positions and guard posts I - Alars system emergency power location and capability I - Response and patrol routes i - Details of alars station and guard post bullet re-sistant contructfon features - Location of alais stations (when f t does not conflict with other submittal requirements) - Vehicle alars and immobilization features In addition to physical protection measures, the rule requires protection of documents or drawings that identify certain safety related equipment as being vital for the purpose of physical security. Normal engineering or construc-tion drawings that show the locations of safety-related equipment are not 1 safeguards Information. In order.to be Safeguards Information, the delETng must explicitly state that the equipment or area is vital from the standpoint of physical protection. (Unless a drawing is specifTcaTTy made, overlayed, i l or annotated for purpcse of the physical protection of the factitty, it cannot be considered Safeguards Information.) Arrangements made with State er local police forces for response to safe-guards emergencies are Safeguards Information. Specific information to be 8 protected include: - Size and armament of initial responding force - Response times - Primary and alternate routes - Identity (e.g., does the response force come from a road unit or Hq butiding) I 3 ( I N l \\ \\
b NUREG-1410 m Loss of Vital AC Power ~ and the Residual Heat Removal System During Mid-Loop Operations at Vogtle Unit 1 on March 20,1990 U.S. Nuclear Regulatory Commission l p- ~s. (g),, . _ - g 1
1 EXECUTIVE
SUMMARY
1.1 Introduction The Vogtle Electric Generating Plant, operated by Georgia Power Company, has two Westinghouse-designed units. Each unit has four reactor coolant loops and is rated at 3411 thermal MW. The site, shown in Figures 1.1 and 1.2, is located on the Savannah River in Burke County, Georgia, about 25 miles southeast of Augusta. Unit I received a full-power operating license in March 1987, and Unit 2, in March 1989. This incident occurred on March 20, 1990, with Unit I shut down and in a refueling outage and Unit 2 operating at full power. Unit I had been shut down for 25 days, refueling had been completed, and the water level in the reactor vessel had been lowered to mid-loop to perform various maintenance tasks. The head was on the reactor vessel, and the first pass to tension the head bolts had been completed. All steam generator manways were in place but not all were fully closed. The pressurizer manway was open. Both the personnel hatch and the equipment batch of the containment building were open. One 1 emergency diesel generator and one reserve auxiliary transformer had been removed from service for maintenance. The remaining reserve auxiliary transformer was supplying both i Unit I safety buses. At 9:20 a.m., a truck in the 230-kV switchyard backed into a support column for an offsite power feed to the reserve auxiliary transformer. A phase-to-ground fault occurred, and the feeder breakers for the safety buses opened. The operable emergency diesel generator staned automatically. The diesel generator energized its safety bus for about 1 minute and tripped. Eighteen minutes later, after the diesel generator load sequencer was reset, the diesel generator started a second time, operated for about 1 minute, and tripped again. These first two undervoltage starts placed the diesel generator in its " normal" mode where all trip functions are active. Thirty-six minutes after the loss of power, operations personnel manually restarted the diesel generator in the emergency mode. Many of the. diesel generator protective trip functions are bypassed in this mode. Following the third start, the diesel generator continued to operate and provide power to its safety bus. Had the diesel generator not started, non-routine actions would have been necessary to defeat interlocks so that a safety bus could be powered either from a Unit I nonsafety bus or from a Unit 2 bus. During the 36 minutes without all safety bus ac power, the temperature of the reactor coolant system increased from about 90 F to 136 F and water level remained at mid-loop. While attempting to restore power, the licensee initiated activities to close the contain-ment building and reactor coolant system. These activities were completed about 2 hours following the initial loss of power. '1wo hours and 20 minutes after the loss of power, the undamaged reserve auxiliary transformer, which had been out of service for maintenance, was returned to service an'd power was restored to its safety bus. NUREG-1410 1-1 Section 1 w
~. l t On March 23, 1990, and in' conformance with the Incident Investigation Program, the Executive Director for Operations-(EDO) of the U.S. Nuclear Regulatory Commission (NRC) sent an Incident Investigation Team to the site. (Appendix A contains the Team charter and the EDO memorandum dispatching the' Team.) The Team, which included - an industry representative accompanied by two industry consultants, was selected because of its broad experience in event analyses, with individual Team members having specific knowledge and experience in the fields of reactor systems, reactor operations, human factors, j and electrical and diesel generator systems, and emergency preparedness. The Team was j directed to determine what happened, identify the probable causes, and make appropriate i findings and conclusions. This report documents the results of the Team's efforts. Appendix B describes the Team's fact-finding activities. 1 i Section 2 presents a chronological narrative of the incident. l Section 3 describes the systems that played a role and their responses during the incident. j , The discussion focuses on the electrical systems and the reactor coolant system. An extensive j discussion of the diesel generator and its complex control and annunciator systems is included because of their importance during this incident. Section 4 discusses implementation of Vogtle's Emergency Plan. Of particular interest are the problems that were identified regarding the guidance and procedures for the emergency classification of events of this nature and the difficulty in accounting for large numbers of people who would be on site when an emergency occurs during an outage. Section 5 describes three problem areas identified during this incident in which human factors considerations played a significant role. These involved the complexity of the diesel generator control and annunciator systems, command and control actions during the transition from the outage orgamzation to the onsite emergency organization, and the lack of effective control of activities in the 230-kV switchyard. Section 6 presents a summary of the significant amount of operating experience that was available to the industry and that could have prevented this incident had the lessons learned been implemented. Section 7 discusses the impact of outage planning on the Vogtle incident, specifically on managing the risk rather than depending solely on restrictions in technical specifications. Section 8 discusses the various means that are available to cope with a complete loss of the residual heat removal system and the system responses that may hinder effective implementation of them. Section 9 discusses the adequacy of existing technical specifications relative to the risk that may exist during cold shutdown operations, particularly those with a reduced coolant inventory. Section 1 1-2 NUREG-1410 . d- .i_.
Finally, Section 10 presents the Team's findings and conclusions relative to this incident. The appendices provide a considerable amount of background information for the material presented in Sections 1 through 10. This information is provided for those readers who desire more details in a particular area. The Team has concluded this investigation and provided its findings and conclusions to the Nuclear Regulatory Commission and the industry for their consideration and for the possible development of follow-on actions. 1.2 Problem Areas Leading Up to the Vogtle Incident A combination of nonconservative initial conditions, combined with the failure to adequately control switchyard work activities, led to the Vogtle incident. Shutdown electrical redundancy was limited to only two of four safety bus power supplies. Following the loss of the one in service reserve auxiliary transformer, the one " operable" emergency diesel generator malfunctioned. Switchyard Controls The Vogtle staff had no effective control over a fuel and lubricants truck conducting routine operations in the switchyard. Moreover, because the truck carried fuel, there was the risk of a conflagration from ignition of fuel caused by electrical arcing. The damage to the switchyard equipment from such an event would have further limited the Vogtle staff' ability to recover electrical power. Guidance identifying the need for additional controls and precautions for work on electrical equipment, including work in the switchyard, ha been provided to the industry. Redundancy of Shutdown Electrical Supplies The Vogtle staff has tentatively concluded that maintenance on two of the four safety bus power supplies could have been scheduled outside the period of mid-loop operations. Diesel Generator Reliability The preliminary evaluation of the diesel generator trips indicates that the most probabl cause of the trips involved the failure of Calcon jacket water temperature trip sensors. The investigation of the root cause of the failures was incomplete as of the date ofissuance of this report. A significant number of Calcon sensor failures has occurred at Vogtle sinc 1985. ~ 1.3 The Vogtle Staff's Handling of the Incident The Vogtle staff generally handled the incident well, showing an effective response that compensated for weaknesses in their procedures. The Team identified some weaknesse Section 1 NUREG-1410 1-3
10 minutes after the initial loss of offsite power to the 4.16 kV ac safety-related buses). Emergency diesel generator IA was still providing power to the safety bus. The operators were concerned that continued operation of emergency diesel generator 1A with most of its protective trip functions removed might be causing engine damage. l Given that offsite power was now available to RHR system equipment, the decision was made to parallel the A and B safety buses and then to shut down the emergency diesel generator. The operators placed train B of RHR into service and placed the train A RHR pump on minimum flow recirculation. The emergency start signal was reset at the engine - control panel, which reinstated the bypassed protective trip functions. Control of emergency diesel generator IA was then transferred from the local panel back to the control room. Breakers were aligned to parallel the A and B safety buses approximately 1 hour and 19 minutes after restoring offsite power via reserve auxiliary transformer 1B. Subsequently, emergency diesel generator 1A was loaded to 6800 kW for 45 minutes to raise engine exhaust temperatures to burn off the unburned hydrocarbons that deposit on the turbocharger blades during low load operation. Emergency diesel generator 1A was subsequently shut down. Reserve auxiliary transformer 1B was supplying power to both 4.16-kV ac safety r-lated buses. RHR train A flow was increased to provide continued decay heat removal, the train B pump flow was throttled back, and the pump was secured. The RHR train A pump was preferred because of minor vibration problems with the train B pump. Emergency diesel generator 1A was operated for 4 hours and 31 minutes after the third - attempted start. It operated the first 3 hours with most of its protective trip functions bypassed and the last I hour and 31 minutes with all protective trip functions active. The diesel generator operated for 2 hours and 48 minutes after safety bus B was energized from reserve auxiliary transformer IB. There apparently were no emergency diesel generator operational problems subsequent to the emergency start; the monitored engine parameters remained within normal operating ranges. The diesel generator was later declared inoperable pending, the licensee's investigation for the cause of the two trips that occurred during the incident. 3.3.3 Cause of Malfunctions 1 Based on the results of testing performed after the incident, the licensee concluded that the primary cause for the unexpected emergency diesel generator trips was improper intermittent operation of the Calcon jacket water temperature sensors. The sensor malfunctions appear to have been caused by the presence of foreign material (i.e., pipe thread sealant and thread spalls) that affected sensor internal moving parts. It appears that premature venting of the sensor air supply lines caused the engine control logic to sense a false high temperature trip condition and to automa'ically trip the emergency diesel generator. Contributing causes appear to include the effects of multiple leaks in the pneumatic engine control system, and sensor calibration techniques that may have resulted in lower setpoint values. Prior to issuance of this report, the licensee modified the emergency diesel generator trip logic so that the jacket water high temperature trip function is bypassed on an emergency start signal. This modification was not reviewed by the Team. A detailed discussion of the post-incident troubleshooting effort is contained s 1 NUREG-1410 3-21 Section 3
i I in Appendix J. Appendix J also discusses factors that can affect proper calibration of bh temperature sensors based on the results of testing at an independent laboratory. After i the incident. the licensee experienced additional problems with pneumatic sensors used to trip emergency diesel generator IB. Not all sensor testing was completed in time to include the results in this report. The licensee's troubleshooting efforts are continuing. Subsequent to the Team's investigation, the licensee discovered a problem with a sticking diaphragm in a Calcon lube oil pressure sensor that was installed on emergency diesel generator ~ 1A during the incident. It is unclear whether the malfunctioning of this sensor was a ~~ contributing factor to the root cause for the unexpected diesel generator trips. The sticking problem appears to be the consequence of " tolerance stack-up" and possible aging and ~ stretching of the sensor diaphragm. The tolerance stack up problem is discussed in an addendum dated May 12,1988, to a 10 CFR Part 21 report from the diesel generator suppher (IMO Delaval Inc.) to NRC. This issue is discussed in greater detail in Appendix J. 3.3.4 The Importance of Understanding Emergency Diesel Generator Instrumentation and Control Systems ~ Electrical power is of paramount importance to a nuclear p!r at's safety. The emergency diesel generators rate among the most important of the safety systems at a nuclear power plant. For loss of offsite power events, the diesel generators are the last remaining source of power to equipment used to achieve and maintain the plant in a safe shutdown condition. The incident at Vogtle has demonstrated that their importance is not diminished because "l the plant is in a non-power operating mode. To ensure that the overall reliability of diesel generators is maintained requires that operations personnel responding to plant transient conditions have sufficient knowledge of the associated instrumentation and controls to correctly decide how to enhance or restore operability when problems occur. The diesel generator installations at nuclear plants are complex power plants in their own right. Many of their control and auxiliary systems must be redundant. They must start and be ready to carry full load in 10 or so seconds. They must be capable of starting motors whose rating is a major fraction of their own capacity. They must not shut down when needed, except for the most crucial of reasons. The diesel generator installations at nuclear power plants are a major part of the total plant. The diesel generator air start and load sequencer control systems are particularly complex and their need to interact only adds to the complexity. As a result of either a valid or spurious trip signal, a diesel generator may shut down at any time during or after the cycling of these control systems. In addition, the control systems can evolve into different modes of operation depending on the plant's status. For operations personnel to provide the most expeditious and proper response, they must be well trained and have all necessary information in a form that is tailored to ensure rapid recovery for the various modes of control system operation. Vogtle technical personnel generally understood the emergency diesel generator instrumentation and control systems. However, operating personnel needed more insight i 1 Section 3 3-22 NUREG-1410
( ~ APPENDIX I CONTENT 1 NUCLEAR PLANT RELIABILITY DATA SYSTEM............... 1 2 INDUSTRY EXPERIENCE WITH CALCON SENSORS IN DIESEL GENERATOR TRIP CIRCUITS............................. 3 5 2.1 Grand Gulf (3/24/84)............................ 5 2.2 Grand Gulf (5/5/84)............................. 5 2.3 Grand Gulf (4/27/85) 5 2.4 Catawba 1 (11/23/86)............................ 2.5 Catawba 2 (5/11/87)............................. 5 6 2.6 Catawba 2 (5/12/87)............................. 6 2.7 River Bend 1 ( 11/9/87)........................... 3 6 2.8 Catawba 1 (3/22/88)............................. 6 2.9 Catawba 1 (4/12/88)............................. 6 2.10 Catawba 2(4/12/88)............................. 6 2.11 Catawba 1 (4/19/88)............................. 6 2.12 Catawba 1 (4/25/88)............................. 6 2.13 Catawba 1 (5/5/88).............................. - 7 2.14 Catawba 2 (8/9/88).............................. 7 2.15 Catawba 1 (8/11/88)............................. 7 2.16 Catawba 1 (8/15/88)............................. 7 2.17 Catawba 1 (10/25/88)............................ 7 2.18 Catawba 1 (12/2/88)............................. 7 2.19 Catawba 1 (12/19/88)............................ 8 2.20 Grand Gulf (3/25/89)............................ 8 2.21 Shearon Harris (7/5/89)........................... 8 2.22 Catawba 1 (8/8/89).............................. 8 2.23 Shearon Harris (11/26/89)......................... 3 VOGTLE EXPERIENCE WITH CALCON SENSORS IN DIESEL GENERATORS TRIP CIRCUITS............................ 8 9 3.1 Vogtle 1(8/14/85)............................... 9 3.2 Vogtle 1(8/17/85)............................... 9 3.3 Vogtle 1(8/17/85)............................... 9 3.4 Vogtle 1(8/19/85)............................... 9 3.5 Vogtle 1 (8/19/85)............................... 9 3.6 Vogtle 1(8/20/85)............................... 9 3.7 Vogtle 1 (8/20/85)............................... 10 3.8 Vogtle 1 (8/24/85)............................... 10 3.9 Vogtle 1 (10/28/85).............................. 10 3.10 Vogtle 1(11/14/85).............................. NUREG-1410 I-i Appendix I
1 1 3.11 Vogtle 1 (12/10/85 ).............................. 10 3.12 Vogtle 1 (12/11/85).............................. 10 3.13 Vogtle 1 (2/11/86)............................... 10 3.14 Vogtle l (12/22/86).............................. 10 3.15-Vogtle 2 ( 1/24/88)............................... 10 3.16 Vogtle 2 (2/5/88) U 3.17 Vogtle 2 (2/26/88)............................... 11 3.18 Vogtle 2 (4/13/88)............................... 11 l 3.19 Vogtle 2 (04/21/88).............................. 11 3.20 Vogtle 2 (4/24/88)............................... 11 l 3.21 NVogtle 2 (7/22/88)............................... 11 3.22 Vogtle 1 (9/30/88)............................... 11 3.23 Vogtle 1 ( 10/10/88).............................. 1: 3.24 Vogtle 1 (10/18/88)............................... 12 3.25 Vogtle 1 (10/19/88).................... 12 3.26 Vogtle 1 (10/20/88).............................. 12 3.27 Vogtle 1 ( 10/20/88-).............................. 12 3.28 Vogtle 1 (10/21/88).............................. 12 3.29 Vogtle 1 (10/23/88).............................. 12 3.30 Vogtle 1 (10/26/88).............................. 12 3.31 Vogtle 1 (10/30/88).............................. 12 3.32 Vogtle 1 (10/31/88).............................. 13 3.33 vogtle 2 (12/9/88)............................... 13 3.34 Vogtle 1 (11/19/89).............................. 13 3.35 Vogtle 1 (12/5/89)................................ 13 3.36 Vogtle 1 (1/3/90)............................... 13 3.37 Vogtle 1 (1/25/90)............................... 13 3.38 Vogtle 1 ( 1/25/90)............................... 13 3.39 Vogtle 1 (3/3/90)............................... 13 3.40 Vogtle 1 (3/4/90) 14 3.41 Vogtle 1 (3/23/90)................................ 14 3.42 Vogtle 1 (3/25/90)............................... 14 3.43 Vogtle 1 (3/25/90)............................... 14 4 OPERATING EXPERIENCE REPORTS OF CALCON SENSOR PROBLEMS........................................... 14 Appendix I I-ii NUREG-1410 ___r______
T APPENDIX I CALCON SENSOR FAILURE DATA The inadvertent shutdown or trip of the emergmy diesel generator at Vogtle was caused by malfunctions of a number of Calcon sensors. In an effort to determine if.the expe with Calcon sensor problems is unique to Vogtle, failures of sensors at other plants were evaluated. The Nuclear Plant Reliability Data System (NPRDS) is a an electronic database designed to allow comparison of failure rates for similar equipment. 1-NUCLEAR PLANT RELIABILITY DATA SYSTEM The NPRDS database is an industry wide system for monitoring the performance of selected nuclear power plant components that are important to safe and reliable plant operation. NPRDS is managed by the Institute of Nuclear Power Operations (IN The performance information is obtained from reports submitted by participating for components that fail to perform their intended functions. These failure reports, alo with information about the component design characteristics and operating history, are use by utilities in many different applications. Among the applications are (1) early i of increasing failure trends or unusual failure patterns, (2) equipment reliability calculat and (3) location of equipment spare parts. The data contained in the NPRDS database is entered, as appropriate, in the following records: Unit Record: This record contains information about the nuclear power plant reporting to NPRDS, such as the name of the reactor supplier and the rea l power rating in thermal megawatts. l System Engineering Record: This record contains information about a reportable 1 system at a particular unit, such as an identification number of the system dra and the date the system was put into service. Component Engineering Record: This record contains information about a piece i a i of reportable equipment installed at a particular unit, such as the type of componen pump or valve, the date the component was placed in service, and the manufa of the component. Component Failure Reconi: This record contains information about a component failure at a particular unit, such as the date the failure occurred, the effect of the failure on the system and unit, and a description of the failure. ' Data about the emergency diesel generator and support systems are reportable to NP Once the plant starts reporting failure data to the database, the system and component e4=-deg records are submitted for all components. Engineering records are not s . I-1 Appendix I NUREG-1410
for individual parts," piece parts" of components. Component failure records are submitted when the component failure occurs. Piece pans that fail are not reported unless the failure causes the component to fail. The following is a summary of NPRDS reporting guidelines: Engineering data for instrumentation components that perform an automatic control or safety function in any reportable system rnust be reported. Function failures on' reportable components available for operation that occurred after January 1,1984, or after a plant's commercial service date for plants placed j in service after January 1,1984, are reportable. Function failures that occur on component:: not available for operation (e.g., failures during maintenance that are as a result of the maintenance and are repaired before the component is again made available for operation) are not reportable. Function failures that are discovered during maintenance and are not a result of j the maintenance are presumed to have occurred before the maintenan:e activity and are reportable. Function failures that are discovered when a component is available for operation or is being operated that are a result of previous maintenance activities are reportable. l 1 The key to proper reporting of components and failures is the classification of an item as either a component or a piece part of a component. A function failure is a failure of the reportable component to perform its function. For example, if a reportable system uses a two-out-of-four sensor trip logic to shut down the system, the following apply: each sensor is a reportable component a a sensor failure that does not cause a shutdown of the system is reportable as a sensor function failure two or more sensor failures that cause a shutdown of the system are each reportable as sensor function failures ' Appendix I I2 NUREG-1410
1 Information on reporting is found in the following INPO documents: INPO 83-020, "NPRDS Reportable System and Component Scope Manual." Revision 3 INPO 89-001, "NPRDS Reporting Guidance Manual" 2 INDUSTRY EXPERIENCE WITH CALCON SENSORS IN DIESEL GENERATOR TRIP CIRCUITS The Vogtle emergency diesel generators were manufactured by Transamerica Delaval currently know as Imo, Delaval Inc., Enterprise Engine Division. Eleven operating nuclear plants have Delaval diesel generators. All Delaval diesel generators use sensors manufactured by Calcon in the engine pneumatic control system to trip the engine when various parameters are outside of specific limits. The NPRDS reporting requirements for diesel generators are summarized in Table I.1. Some of the Calcon sensors are used in the diesel generator control logic to shut down the diesel generator when the various sensors actuate in any of the following operating i modes: loss of off-site power actuation safeguard actuation e normal actuation When sensors are used in the control logic that is active in any of these actuation modes, the sensors and failures are reportable to NPRDS as components of the diesel generator. Six of the eleven nuclear plants reported engineering records for the Calcon sensors thus indicating Calcon sensor failures at these plants would be reported independent of the faihires effect on the diesel generator. There were thirty-two reports involving Calcon sensor failures in NPRDS. Thirty of the failures were reported as component failures of the Calcon sensors. The remaining two failures were reported as engine failures because the sensors were considered piece parts. These reports included thirteen emergency diesel generator trips during testing. Two of the failures were not attributed to Calcon sensor problems, but, because of the intermittent problem noted, could have been caused by the Calcon sensors. Twenty-four of the failure reports were for pressure sensors and eight of the failure reports were for temperature sensors, railures have been reported by 5 of the 11 operating nuclear power plants which have emergency diesel generators with Calcon trip sensors. I Institute of Nuclear Power Operations (INPO) documents are referenced and summarized in this report with the permission of INPO. These INPO documents are classified under INPO copyTight as Limited Distribution and are only available to INPO members and participants. NUREG-1410 I-3 Appendix I
u3 %ble I.1 NPRDS Scope of Reporting for Emergency Diesel Generators 1x For a diesel generator-powered, emergency power system, components in the following subsystems are reportable: Emergency Power System Diesel Fuel Oil Subsystem day tank
- engine a
circuit breakers
- engine governor filters generator instruments that provide an automatic control or safety
- generator output breaker function 1
- motors Diesel Starting Air Subsystem pumps valves
- air start compressor valve operators g.
- air start compressor motor
- air start compressor motor circuit breaker Diesel Lube Oil Subsystem Diesel Cooling Water Subsystem circuit breakers a
filters
- surge tank heat exchangers
= circuit breakers in control circuits heaters
- heat exchangers instruments that provide an automatic control or safety
- heaters
- instruments that provide an automatic control or function motors safety function
- motors pumps valves
- pumps valve operators
- valves valve operators a
g ks
- All components that mntrol the normal, as well as emergency, starting and stopping of the diesel generator system; including all trips, even those l
bypassed during a loss of off-site power or a safeguard actuation, are reportable in this system.
Thiny-two failures of Calcon temperature and pressure sensors have been reported since January 1,1984. The following are summaries of the failure repon submitted by the plants to NPRDS:2 2.1 Grand Gulf (3/24/84) During engineered safeguard features testing, the diesel generator failed to stan. Cause of the failure to start is unknown. Subsequent attempts to duplicate the failure were unsuccessful. The diesel generator started and ran eleven subsequent times with no failures. The problem was reported as a diesel failure, but may have been caused by a sensor failure. 2.2 Grand Gulf (5/5/84) A diesel generator would not start during a surveillance test. The engine rolled one revolution and stopped, apparently from a trip signal. The problem could not be duplicated. The diesel generator started and ran ten subsequent times with no failures. The problem was reported as a diesel failure, but may have been caused by a sensor failure. 2.3 Grand Gulf (4/27/85) During a diesel generator maintenance retest, a pressure sensor was found to be leaking air. The leaking sensor could prevent the diesel engine from tripping on overspeed. The Calcon sensor (pan number F-573-156) was found to have a diny valve seat that allowed the valve to leak. 2.4 Catawba 1 (11/23/86) A diesel generator tripped during an operability test. The Calcon low lube oil pressure sensor (Model B4400) was out of calibration. 2.5 Catawba 2 (5/11/87) During a weekly operability test, the diesel generator tripped because of high cooling water temperature and high crankcase pressure sensor trip signals. Cause of the Calcon temperature sensor (part number F-573-330) being out of calibration was not determined. The Calcon crankcase pressure sensor (Model B4417) trip setpoint was out of calibration. Cause of the setpoint drift was not determined. 2 Nuclear Plant Reliability Data System (NPRDS) failure reports are referenced and summarized in this report with the permission of the Institute of Nuclear Power Operations (INPO). NPRDS failure repons are classified under INPO copyright as Limited Distribution and are only available to INPO members and participants. NUREG-1410 I-5 Appendix I
2.6 Catawba 2 (5/12/87) A diesel generator tripped because of a high crankcase pressure sensor trip signal. The Calcon crankcase pressure sensor (Model B4417) trip setpoint was found out of specification. Cause of the setpoint drift was not determined. The pressure sensor was replaced. 2.7 River Bend 1 (11/9/87) During a refueling outage, a high jacket water temperature diesel generator trip signal was received from a Calcon temperature sensor (Model A3500). As a result of normal wear and aging, the sensor's integrity was compromised. 218 Catawba 1 (3/22/88) i 1 A diesel generator tripped during an operability test. Failure could not be duplicated. The diesel engine started several times without failure. Cause later determined to be failure of a Calcon low lube oil pressure sensor (Model B4400). 2.9 Catawba 1 (4/12/88) A diesel generator tripped during an operability test. Failure could not be duplicated. i The diesel engine started several times without failure. Cause later determined to be failure of a Calcon low lube oil pressure sensor (Model B4400). j 2.10 Catawba 2 (4/12/88) A diesel generator tripped during surveillance testing. Two Calcon low lube oil pressure sensors (Model B4400) had failed. Both sensors were replaced. Evidence of corrosion was present on the sensors. Therefore, air compressor blowdown frequency was increased. 2.11 Catawba 1 (4/19/88) A diesel generator tripped during an operability test. A Calcon pressure sensor (Model B4400) in the diesel generator control panel failed. f 2.12 Catawba 1 (4/25/88) A diesel generator tripped during an operability test. A Calcon pressure sensor (Model B4400) in the diesel generator control panel failed. 2.13 Catawba 1 (5/5/88) A diesel generator tripped during an operability test. A Calcon pressure sensor (Model B4400) in the diesel generator control panel failed. Analysis of this sensor failure and Appendix I I-6 NUREG-1410
the previous sensor failures determined that a sensor design flaw existed. The design ~ flaw was related to loss of sensor movement as a result of mechanical interference caused by tolerance stack-up. The Calcon Model B4400 sensors were replaced with Model B4400B sensors. 2.14 Catawba 2 (8/9/88) Two Calcon low turbo lube oil pressure sensors (Model B4400B) were discovered with a trip setpoint out of specification. One Calcon low lube oil inlet pressure sensor (Model B4400B)was discovered out of specification. Cause of the setpoint drifts was not determined. 2.15 Catawba 1 (8/11/88) Three diesel generator Calcon low lube oil pressure sensors (Model B4400B) were discovered with trip setpoints out of specification. One Calcon crankcase high pressure sensor (Model B4417) was discovered with a trip setpoint out of specification. Cause of the setpoint drifts was not determined. 2.16 Catawba 1 (8/15/88) One diesel generator Calcon crankcase high pressure sensor (Model B4417) was discovered. with a trip setpoint out of specification. One Calcon low turbo lube oil pressure sensor (Model B4400B) was discovered with a trip setpoint out of specification. One Calcon jacket. cooling water temperature sensor (part number F-573-330) trip serpoint was found out of specification. Cause of the setpoint drifts was not determined. 2.17 Catawba 1 (10/25/88) i A diesel generator tripped during an operability test. A turbo lube oil Calcon pressure sensor was found to be venting continuously. Actual cause of sensor failure was not determined. The plant initiated a design modification request to replace all pneumatic devices in the diesel engine control system with electronic controls. 2.18 Catawba 1 (12/2/88) One Calcon crankcase high pressure sensor (Model B4417) was discovered with a trip setpoint out of specification. One Calcon jacket cooling water temperature sensor (part number F-573-330) trip setpoint was found out of specification. Cause of the setpoint drifts was not determined. 2.19 Catawba 1 (12/19/88) One diesel generator Calcon jacket cooling water temperature sensor (part number F-573-330) was discovered failed. Cause of the sensor failure was not determined. NUREG-1410 I-7 Appendix 1 m
l 2.20 Grand Gulf (3/25/89) During a refueling outage maintenance run, a diesel generator tripped because of a high crankcase pressure sensor trip signal. The indication for crankcase pressure was normal. The cause of the trip signal was a cracked orifice on the crankcase pressure sensor (Model H3337A). 2,21 Shearon Harris (7/5/89) A diesel generator tripped during the monthly surveillance test. A Calcon high temperature l sensor (Model A-3500-W3) for lube oil tripped. The normal trip setpoint is 195 plus or minus 5 E The indicated lube oil temperature was 177 E 2,22 Catawha 1 (8/8/89) A diesel generator tripped during functional testing following modification of the lube oil system. Two Calcon high temperature sensors (Model A3500.W3) for engine bearings tripped. The sensor failures were attributed to normal drift of the trip setpoint resulting from sensor age and constant vibration. The normal operating temperature is within 10 F of the trip setpoint. .2.23 Shearon Harris (11/26/89) A diesel generator low lube oil pressure sensor trip setpoint was found out of tolerance. The Calcon sensor (Model B4400) trip setpoint could not be adjusted in specification and 4 the sensor was replaced. Cause for the sensor failure could not be found. 3 VOGTLE EXPERIENCE WITH CALCON SENSORS IN DIESEL GENERATORS TRIP CIRCUITS Vogtle did not report the Calcon sensors as component engineering records to NPRDS. The NPRDS database also contained no diesel generator failure reports for Vogtle. The analysis of maintenance work orders indicated that Vogtle experiened 69 Calcon sensor failures and they should have submitted approximately 39 failure reports to NPRDS (since the date of commercial operation). For Calcon sensor failures from 1985-1990, 47 were for temperature sensors and 14 were for pressure sensors. In 17 cases, the temperature l sensor setpoints were discovered to be low during testing, the direction that can result in an unwarranted diesel generator trip. The Vogtle Calcon sensor failures as compared to 1 the industry failures reported in NPRDS are summarized on Thble I.2 for all Vogtle failures and 'Ihble I.3 for Vogtle failures reportable to NPRDS. 9 Appendix I I-8 NUREG-1410
1 The following are summaries of the failures that occurred at Vogtle: 3.1 Vogtle 1 (8/14/85) A Calcon lube oil pressure sensor (Model B4400) was discovered with a setpoint out of calibration low and was recalibrated. The cause of the setpoint drift was not determined. 3.2 Vogtle 1 (8/17/85) A Calcon jacket water high temperature sensor (Model A3500-W3) was discovered during construction acceptance testing with a setpoint out of calibration low and was recalibrated. The cause of the setpoint drift was not determined. 3.3 Vogtle 1 (8/17/85) A Calcon lube oil low pressure sensor (Model B4400) was discovered with a serpoint out of calibration high and was recalibrated. The cause of the setpoint drift was not determined. 3.4 Vogtle 1 (8/19/85) A Calcon lube oil low pressure sensor (Model B4400) was discovered with a setpoint out of calibration high and was recalibrated. The cause of the setpoint drift was not determined. 3.5 Vogtle 1 (8/19/85) A Calcon jacket water low pressure sensor-(Model B4400) was discovered with a setpoint out of calibration high and was recalibrated. The cause of the setpoint drift was not determined. f 3.6 Vogtle 1 (8/20/85) A Calcon jacket water high temperature sensor (Model A-3500-W3) during construction acceptance test was discovered with a setpoint out of calibration high and was recalibrated. The cause of the setpoint drift was not determined. 3.7 Vogtle 1 (8/20/85) A Calcon jacket water high temperature sensor (Model A-3500-W3) during construction acceptance testing was discovered with a setpoint out of calibration high and was recalibrated. The cause of the setpoint drift was not determined. NUREG-1410 I-9 Appendix I
3.8 Vogtle 1 (8/24/85) A Calcon low turbo oil pressure sensor (Model B4400) during construction acceptance testing was discovered with a setpoint out of calibration low and was reca'fbrated. The cause of the setpoint drift was not determined. 3.9 Vogtle 1 (10/28/85) Three Calcon jacket water high temperature sensors (Model A-3500-W3) were discovered with a setpoint out of calibration low and were recalibrated. The cause of the setpoint drift was not determined. 3.10 Vogtle 1 (11/14/85) j A Calcon jacket water high temperature sensor (Model A-3500-W3) failed and was replaced. The cause of the failure was not determined. 3.11 Vogtle 1 (12/10/85) A Calcon jacket water high temperature sensor (Model A-3500-W3) was discovered with a setpoint out of calibration low and was recalibrated. The cause of the setpoint drift was not determined. 3.12 Vogtle 1 (12/11/85) A Calcon jacket water high temperature sensor (Model A-3500-W3) was discovered with a setpoint out of calibration low and was recalibrated. The cause of the setpoint drift was l not determined. 3.13 Vogtle 1 (2/11/86) l A Calcon lube oil low pressure sensor (Model A-3500-W3) was found with a setpoint out of calibration low and was recalibrated. The cause of the setpoint drift was not determined. 3.14 Vogtle 1 (12/22/86) A Calcon lube oil low precure sensor (Model B4400) would not calibrate in specification end was replaced. The cause of the malfunction was not determined. 3.15 Vogtle 2 (1/24/88) A Calcon vibration switch sensor (Model E4600) was found defective and replaced with new vibration switch. The cause of the malfunction was not determined. Appendix I I 10 NUREG-1410
l. 1 3.16 Vogtle 2 (2/5/88) A Calcon low tubo oil pressure sensor (Model B4400) was discovered with a setpoint out of calibration high and was recalibrated. The cause of the setpoint drift was not determined. 3.17 Vogtle 2 (2/26/88) 4 A Calcon lube oil high temperature sensor (Model A 3500-W3) was discovered with a setpoint ont of calibration low and was recalibrated. The cause of the setpoint drift was not determined. 3.18 Vogtle 2(4/13/88) l A Calcon vibration detector sensor (Model E4600) was replaced due to a defective switch. i The cause of the defective switch was not determined. 3.19 Vogtle 2 (04/21/88) A Calcon jacket water high temperature sensor (Model A-3500.W3) was discovered with 2 a setpoint out of calibration low and was recalibrated. The cause of the setpoint drift was not determined. 3.20 Vogtle 2 (4/24/88) i Three Calcon high jacket water temperature sensors (Model A-3500-W3) were discovered with setpoint out of specification low and were recalibrated. The cause of the setpoint drift was not determined. 3.21 Vogtle 2 (7/22/88) Three Calcon jacket water high temperature sensors (Model A-3500-W3) were discovered with a setpoint out of calibration low and were recalibrated. The cause of the setpoint drift was not determined. 3.22 Vogtle 1 (9/30/88) Three Calcon jacket water header outlet temperature sensors (Model A 3500-W3) were discovered with a setpoint out of calibration (2 high,1 low) and were recalibrated. The cause of the setpoint drifts was not determined. 3.23 Vogtle 1 (10/10/88) Ten Calcon bearing high temperature sensors were found to be defective and were j replaced. The cause of the malfunction was not documented. NUREG 1410 1-11 Appendix I
3.24 Vogtle 1 (10/18/88) J A Calcon jacket water high temperature sensor was discovered out of calibration high ] and was recalibrated. The cause of the calibration drift was not determined. j i 3.25 Vogtle 1 (10/19/88) J A Calcon jacket water high temperature sensor (Model A-3500 3W) was not working properly and was replaced. The reason for the switch malfunctioning was not documented. 3.26 Vogtle 1 (10/20/88) A Calcon low lube oil pressure sensor (Model B4400) was discovered with a setpoint out i of calibration high and was recalibrated. The cause of the setpoint drift was not determined. 3.27 Vogtle 1 (10/20/88) A Calcon jacket water header pressure sensor (Model B4400) was discovered with a i setpoint out of calibration high and was recalibrated. The cause of the setpoint drift was not determined. 3.28 Vogtle 1 (10/21/88) A Calcon low lube oil pressure sensor (Model B4400) was discovered with setpoint out of calibration high and was recalibrated. The cause of the setpoint drift was not determined. I 3.29 Vogtle 1 (10/23/88) Two Calcon normal trip pressure sensors (Model B4400) failed. One sensor would not respond and the other failed to reset within tolerance. The cause of the failures were i not documented. ] 3.30 Vogtle 1 (10/26/88) A Calcon jacket water header outlet temperature sensor (Model A-3500-W3) switch would not calibrate. The cause of the failure was not determined. 3.31 Vogtle 1 (10/30/88) Two Calcon jacket water temperature sensors (Model A-3500.W3) were found to.be defective and were replaced. The cause of the failures was not documented. Appendix I I-12 NUREG-1410
~ 332 Vogtle 1 (10/31/88) { Two Calcon jacket water header outlet temperature sensors (Model A 3500 W3) were replaced. The reason was not documented. 333 Vogtle 2 (12/9/88) A Calcon vibration sensor (Model E4600A) was malfunctioning causing the emergency diesel generator to trip. The sensor was replaced. The cause of the malfunction was l not documented. 334 Vogtle 1 (11/19/89) A Calcon high jacket water temperature sensor (Model A-3500-W3) was discovered with a setpoint out of calibration low and was recalibrated. The causc of the setpoint drift was not determined. 335 Vogtle 1 (12/5/89) A Calcon lube oil pressure sensor (Model B4400) was found defective during a calibration check and was replaced with a new switch. The cause of the failure was not documented. i 336 Vogtle 1 (1/3/90) A Calcon turbo oil pressure sensor (Model B4400B) was venting and was replaced. Cause of the failure was not determined. 337 Vogtle 1 (1/25/90) A Calcon lube oil temperature sensor (Model A-3500-3W) was discovered with a setpoint out of calibration high and was recalibrated. The cause of the setpoint drift was not determined. 338 Vogtle 1 (1/25/90) Three Calcon jacket water header outlet temperature sensors (Model A-3500-W3) were discovered with setpoints out of' calibration high and were recalibrated. The cause of the setpoint drifts was not determined. 339 Vogtle 1 (3/3/90) ( A Calcon jacket water low pressure trip sensor (M'odel B4400) was discovered with a setpoint out of calibration high and was recalibrated. The cause of the setpoint drift was not determined. NUREG-1410 I-13 Appendix I
-e \\. 3.40 Vogtle 1 (3/4/90) A new Calcon high temperature main bearing sensor (Model 3434) switch was installed. The reason the new switch was needed was not documented. 3.41 Vogtle 1(3/23/90) Three Calcon jacket water header outlet temperature sensors (Model A-3500-3W) were i chscked for calibration. Two switches were found out of calibration. One switch did not pass the bubble test.and was replaced. The other two were recalibrated. 3.42 Vogtle 1 (3/25/90). A Calcon lube oil high temperature sensor (Model A-3500 3W) was discovered with a setpoint out of calibration high and was recalibrated. The cause of the setpoint drift was not determined. 3.43 Vogtle 1 (3/25/90) A Calcon start logic air pressure sensor (Model B4400) was found malfunctioning during a surveillance procedure. The defective sensor was replaced The defective switch was subsequently tested satisfactorily. The cause of the malfunction was not determined. [ 4 OPERATING EXPERIENCE REPORTS OF CALCON SENSOR PROBLEMS The industry has experienced some problems with Calcon pressure and temperature sensors as discussed in the 10 CFR Part 21 report submitted to the NRC by Imo Delaval, Inc., on npril 29,1988, and their addendum submitted on May 12,1988. The initial report stated that recent field failures had occurred in air start valves and the lube oil pressure, jacket water temperature, and crankcase pressure sensors. Imo Delaval, Inc., requested that all spare sensors be returned to them. Although the report did not request that installed sensors be removed, the report did recommend implementing a surveillance plan. The addendum report discussed a problem with Calcon lube oil pressure sensor trip setpoints caused by stack up of the mechanical dimension tolerances in the sensor. The report also 4 stated that a new sensor configuration corrected the problem. When the Part 21 reports on Calcon sensors was received, the plant Vogtle response: returned the spare parts stored in the warehouse to the diesel generator manufacturer. In addition, the reported problem with the sensors was evaluated as not representing a reportable condition as defined by 10 CFR 50.73 because the problem has no effect on the operability of the diesel generator. The problem was determined to impact the reliability of spare parts. The recommendation in the initial Part 21 report to implement a surveillance plan for the sensors was not evaluated. I-14 NUREG-1410 Appendix I
'Ihble I.2 'Ibtal Vogtle Experience vs. Industry (NPRDS) Experience for Calcon Sensor Failures l Number of Failures (Vogtle/ Industry) Sensor Service 1984 1985 1986 1987 1988 1989 1990 Total ~ High Jacket Water -/0 9/0 0/0 0/2 17/3 1/0 6/- 33/5 Temperature High Lube Oil -/0 0/0 1/0 0/0 1/0 0/1 2/- 4/1 Temperature i High Bearing -/0 0/0 0/0 0/0 10/0 0/2 1/- 11/2 Temperature J ) High Crankcase -/0 0/0 0/0 0/2 0/3 0/1 0/- 0/6 Pressure i Low Lube Oil -/0 3/0 1/1 0/0 2/7 1/1 0/- 7/9 i Pressure 1 Low 'Ihrbo Oil -/0 1/0 0/0 0/0 1/3 0/0 1/- 3/3 Pressure Law Jacket Water -/0 1/0 0/0 0/0 1/0 0/0 1/- 3/0 l Pressure High Vibration -/0 0/0 0/0 0/0 3/0 0/0 0/- 3/0 i Overspeed -/0 0/1 0/0 0/0 0/0 0/0 0/- 0/1 Air 'llip Valve -/0 0/0 0/0 0/0 2/3 0/0 1/- 3/3 (P3) Unknown -/2 0/0 0/0 0/0 0/0 0/0 0/- 0/2 Total -/2 14/1 2/1 0/4 37/19 2/5 12/- 67/32 NUREG-1410 ~ I-15 Appendix I
l 1hble I.3 Vogtle Experience vs. Industry Experience l for Calcon Sensor Failures Reportable to NPRDS l l Number of Failures (Vogtle/ Industry) Sensor Service 1984 1985 1986 1987 1988 1989 1990 Total High Jacket Water -/0 0/0 0/0 0/2 10/3 1/0 6/- 17/5 Temperature High Lux Oil -/0 0/0 0/0 0/0 0/0 0/1 2/- 2/1 Temprature High Bearing -/0 0/0 0/0 0/0 10/0 0/2 1/- 11/2 Temperature High Crankcase -/0 0/0 0/0 0/2 0/3 0/1 0/- 0/6 Pressure Low Lube Oil -/0 0/0 0/1 0/0 2/7 1/1 0/- 3/9 Pressure Low lbrbo Oil -/0 0/0 0/0 0/0 0/3 0/0 1/- 1/3 Pressure Low Jacket Water -/0 0/0 0/0 0/0 1/0 0/0 1/- 2/0 Pressure High Vibration -/0 0/0 0/0 0/0 0/0 0/0 0/- 0/0 Overspeed -/0 0/1 0/0 0/0 0/0 0/0 0/- 0/1 Air Trip Valve -/0 0/0 0/0 0/0 2/3 0/0 1/- 3/3 (P3) Unknown -/2 0/0 0/0 0/0 0/0 0/0 0/- 0/2 'Ibtal -/2 0/1 0/1 0/4 25/19 2/5 12/- 39/32 Appendix I I-16 NUREG-1410 u. .}}