ML20129F643
| ML20129F643 | |
| Person / Time | |
|---|---|
| Issue date: | 12/13/1990 |
| From: | Robinson L NRC OFFICE OF INVESTIGATIONS (OI) |
| To: | Vorse J NRC OFFICE OF INVESTIGATIONS (OI) |
| Shared Package | |
| ML20129F106 | List:
|
| References | |
| FOIA-94-208 NUDOCS 9610070011 | |
| Download: ML20129F643 (4) | |
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December 13, 1990 i
I MEMORANDUM FOR: James Y. Vorse, Director Office of Investigations Larry L. Robinson, Investigator FROM: Tate, Investigator
SUBJECT:
RECOMMENDATION OF TAPES FOR TRANSCRIPTION .
On Thursday, December 6, 1990, dKenneth tified:
Bro immediately transcribed and reviewed.
and in consultation with Mosbaugh, the following audio tapes are 9, 41, 42, 73, Zd, 75, 76, 81, 83, 98, 99, 100, 101, 156, 158, 159, 160, 165i 166, 167, 175, 182, i 223, 225, 226, 227, 230, 234, 245, 247, 249,254, 256J f l
Please relate these recommendations to Mr. Brockman at your ea convenience.
Also note that duplications 01 does not have of duplications the above numbered of these tapes. tapes have provided to Region II. d been The following is a list of the first group of tapes that have alrea y
/ / / /
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transcribed and reviewed: / / / /
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v' 57, 10, / /58, / 95, 155, 168, 169, 214, 216, / 246, / 248, 255, 264 i
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i To Steve Vias From Larry L. Robinson. 01 ;
Subject:
Listing of Mosbaugh Tapes Retained ;
Per your request in our phone conversation of April 10, 1991, this list of ;
76 Mosbaugh tapes currently retained by O! is hereby provided:
9, 10, 41, 42, 57, *8, 73, 74, 75, 76, 61, 83, 95, 98, 99, ;
100, 101, 155, 156, 158, 159, 160, 165, 166, 167, 168, 169, 175, 182, 183, ,
184, 185, 186, 187, 199, 200, 201, 204, 205, 212, 213, 214, 215, 216, 217, ;
219, 220, 222, 223, 224, 225, 226, 227, 230, ?34, 245, 246, 247, 248, 249, 250, 251, 252, 253, 254, 256, 257, 258, 259, 260, 261, 264, 266, 267, 268, 269 i i
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70: Steve Vias From: Larry L. Robinson, O!
Subjects Listing of Mosbaugh Tapes Retained Per your request in our phone conversation of April 10, 1991, this list of 76 Mosbaugh tapes currently retained by O! is hereby provided:
I Y, M , -4+T M M W =My- -4, M, -et; -997- -491 -997 WW, -44*r*, 449, **+r 4*, a5 -HHr; :HrP, w -Mer ++er-4eet w M4aer4e674e, e, .aeo och r -Ge+, 4657 4tt, +e, 4t*T 4tr, 4*, e N, 34h 49e - r24h *et -ett, 436, fe. -76h w+3 4 e , se , % ++e; a96h 36+ , eSe, M-G64, 456T E57, 458, 499, 46h 46+, 46&, 4M,-467, 26B M
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e July 8, 1991 To: Steven J. Vias, RI!
Fross Larry L. Robinson, 01:R!l +
Subject:
Mosbaugh Tape Transcripts Attached, please find copies of 74 transcripts of tapes provided to NRC by Allen Mosbaugh. These transcripts have been reviewed for voice identification and clarification by Mosbaugh, under O! observation. Mosbaugh's handwritten notations are on these transcripts. The annotated segments pertain prisarily to a!!egations under investigation by O! at this time, so there may be segments of interest to RI! that are not annotated. Neither these transcripts, nor the tapes f rom wk.ict. they have been transcribed should be disseminated outside NRC without express O! permission. For purposes of accountability, these transcripts are numbered as follows:
9, 10, 41, 42, 57, 58, 73, 74, 75, 76, 81, 83, 95, 98, 99, 100, 101, 155, 156, 158, 159, 160, 166, 167, 168, 169, 175, 182, 183, 184, 185, 186, 187, 199, 200, 201, 204, 205, 212, 213, 214, 215, 216, 217, 219, 220, 222, 223, 225, 226, 227, 230, 234, 245, 246, 247, 248, 249, 250, 251, 252, 253, 254, 255, 256, 257, 258, 259, 260, 261, 264, 266, 267, 269 l
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Docket Nos. 50-424 50-425 l U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555 !'
Gentlemen:
V0GTLE ELECTRIC GENERATING PLANT ADDITIONAL INFORNATION ON DIESEL GENERATOR JACKET WATER TEMPERATURE The purpose of this letter is to document the results of the NRC review conducted at the Vogtle Electric Generating Plant (VEGP) in December,1990.
That review concerned the implementation of Ilcense amendments, issued July 10, 1990, Aich note that the High Jacket Water Temperature (NJWT) trip may be bypassed for-the VEGP diesel generators. As you know, both Georgia Power Company (GPC) and the NRC concluded in their respective reviews of those amendments that the modificatich and associated Technical Specification change are consistent with the intent of Regulatory Guide 1.9.
The revised Technical Specification notes that the NJWT trip function may be bypassed. This bypass function is accomplished by closing isolation valves in the instrument sensing lines such that the jacket water temperature sensors will not provide input to the engine trip logic. With the trip bypassed, operators will receive an alam if the jacket water reaches 1900F but will not receive an additional alarm when the temperature reaches 2000F, which would have been the trip setpoint. In response to GPC's commitments to the NRC during the onsite review, the operators have been notified of this situation, through shift briefings which were completed in December, 1990. As discussed during the onsite review, associated revisions to Alarm Response Procedures are being made.
The revised procedures are expected to be issued for use by the end of January, 1991 and will be placed in the operations reading book for shift operators.
Training on the procedures will be included in the next c rator retraining which will be completed by March 8, 1991.
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i i Georgia Power Company is pursuing additional improvements to the DG i i
control / instrumentation system. One of the improvements is to change the manner !
- of bypassing the NJWT trip by implementing an automatic bypass on emergency DG !
start instead of the current method which requires that instrument sensing line isolation valves be closed. This would result in a trip logic more analsgous to i
, the other diesel generator trips.
1 This improvement would allow the currunt DG HJWT trip protection to be available i during norinal DG testing without having to manually open the isolation valves on ;
the instrument sensing lines. Georgia Power Company is currently evaluating the i most effective way to implement an automatic bypass for HJWT trip during an emergency DG start as part of the overall improvement of the DG i !
l control / instrumentation system. The method for implementing the automatic bypass of the HJWT trip and the schedule for its implementation will be
- determined in conjunction with the overall control / instrumentation system ,
i review. This review, including the schedule for implementation, is expected to j be developed by May 15, 1991 sad will be available for your examination.
4 Sincerely, i4'. .
.sm j W. G. Hairston, III
,' WGH,III/HIM/gm
- xc: Georeia Power Cannany
- Mr. C. K. McCoy Mr. W. 8. Shipman Mr. P. D. Rushton Mr. R. M. Odon l NDRMS '
U. S. Nuclear Reaulatory Commission !
Mr. S. D. Ebneter, Regional Administrator i Mr. D. S. Hood, Licensing Project Manager, NRR f
Mr. 8. R. Bonser, Senior Resident Inspector, Vogtle k
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[ p eg **, UNITED STAT E S !
.. '4 NUCLEAR REGULATORY COMMIS$10N l
) .' * [ >* o REGION 11 ;
5 I 101 MARIETTA STREET,N W. *
% ATLANTA, GEORGI A 30323 4
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"% . . . . . OhN 11 1991 ,
Docket Nos. 50-424 and 50-425 i
! License Nos. NPF-68 and NPF-81 j :
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Georgia Power company ATTN: Mr. W. G. Nairston, III t
- Senior Vice President - l i Nuclear Operations !
P.O. Box 1295 '
i Birmingham, AL 35201 1
. Gentlemen: .
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SUBJECT:
V0GTLE (NRC SPECIAL INSPECTION TEANNOS.
REPORT INSPECTION AND NOTICE O!
50-425/90-19) 50-424/90-19 AND ;
! This refers i i
Inspection Team to on theAugust inspection conducted by an NRC Special 6 through 17, 1990. The inspection !
! included a incility. review of activities authorized for your Vogtle discussed At the conclusion of the inspection, the findings were enclosed inspection with those members of your staff identified in the report.
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Areas examined Within these areas duringthethe inspection are identified in the report inspection consisted .
j examinations of proce,dures and representative recordsof int selective with personnel, and observation of activities in progr,ess.erviews Based on the results of this inspection, certain of your activiti appeared to be in violation of NRC requirements, as specified es in the enclosed Notice of Violation (Notice).
Although the inspection concluded that the facility was operated n i
a safe manner in accordance with the requiramints of the operating i
license, we are concerned that there were several operational i
policies and programs where weaknesses were identified.
L you are also requestedyour response to the violations As part of identified in the enclo I
the inspection summary.to address each of the weaknesses listed in ,
i You are required to respond to this lette' follow tho ' instructions specified in the and Notice and should
! ' preparing your response to the violations enclosed Notice
- should document ' the .
In your response,when you actions you plan to prevent specific recurrence actions taken and any additional response to this Notice, including your pr. After reviewing your and the results of future inspections, oposed corrective actions n whether further NRC enforcement action theisNRC will- determine !
t compliance with NRC regulatory requirements, necessary to ensure ,
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i Georgia Power Company 2 JAN 1 1 ESI i
f l Additionally, you should respond to each of the operational j weaknesses identified within the report. (These weaknesses are specifically annotated in the Inspection Summary.) The response 2
sr.culd address your analysis of the significance of the weaknesses i e
and your actions to ensure that these operational practices do not !
] evolve into items of non-compliance or reduce the margin of safety l j for the plant. '
l In accordance with section 2.790 of the NRC's " Rules of Practice,"
a copy of this letter and its enclosures will be placed in the NRC Public Document Room.
d
- The responses directed by this letter and the enclosed Notice are I i not subject to the clearance procedures of the Office of Management '
and Budget as required by the Paperwork Reduction Act of 1980,
- Pub. L. No. 96.511.
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j Should you have any questions concerning this letter, please j enntact us.
I
- sincerely, l
(? I b..
ewart D. no er i egional Administrator ,
i Region II l l, l Enclosurest
! 1. Notice of Violation l l 2. Inspection Report 50-424/90-19;
{ 50-425/90-19 i
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, l Georgia Power Company 3
- N 111891 !
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cc w/ enclosures:
R. P. Mcdonald Executive VI,ce Presidant-Nuclear
- Operations Georgia Power Corporation P. O. Box 1295 Birmingham, AL 35201 C. K. McCoy, Vice President - Nuclear Vice President-Nuclear
- Georgia Power Corporation ;
P. O. Box 1295 Birmingham, AL 35201 1 W. B. Shipman 1
- General Manager, Nuclear Operations '
Georgia Power Corporation -
P. O. 1600 Waynesboro, GA 30830 i J. A. Bailey Manager-Licensing Georgia Power Corporation
- P. O. Box 1295 ;
Birmingham, AL 35201 J. E. Joiner, Esquire Troutman, Sanders, Lockerman, and Ashmore 1400 Chandler Building .
127 Peachtree Street, NE Atlanta, GA 30303
- D. Kirkland III, Counsel 4
office of the Consumer's .
Utility Council Suite 225
- 32 Peachtree Street, NE Atlanta, GA 30302 Office of Planning and Budget 4
Room 615B 270 Washington Street, SW Atlanta, GA 30334 4
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Georgia Power Company 4 JAN 1138I cc w/ enclosures (continued): 1
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office of the County commissioner Rurke County Commission 4
I Waynesboro, GA 30830 i
Lonice Barrett, Commissioner Department of Natural Resources j
205 Butler Street, SE, Suite 1252 Atlanta, GA 30334 Thomas Hill, Manager Radioactive Materials Program Department of Natural Resources 878 Peachtree Street, NE, Room 600 J Atlanta, GA 30309 Attorney General Law Department
- 132 Judicial Building 4
Atlanta, GA 30334 1
1 State of Georgia i
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b ENCIASURE 1 t NOTICE OF VIOLATION '
f Georgia Power Company Vogtle Electric Generating Plant Docket Mos. 50-424 and 50-425 i
Units 1 and 2 License Nos. NPF-68 and NPF-81 l I i
1 violations of NRC requirements were identified.During 1990, an NRC i ;
the " General Actions," Statement 10 CFR Part 2, of Policy and Procedure for NRC EnforcementIn accorda l i listed below. Appendix C (1990), the violations are i A. Technical Specification 3.6.3 !
l isolation valves (CIVs) be operable in Modes 1, 2, 3,and requires
- 4. that the!i
- With one or more of the CIVs inoperable, at least one isolation valve penetration that must be maintained is open operable in each affected and the inoperable I
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' valves must be restored to the operable status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or be in Hot Standby within the following 30the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in Cold Shutdown within hours.
4 j contrary to the above, en August 7, 1990, the NRC identified that CIVsand, opened 2HV-2792A, thus, 2HV-2792B, 2HV-27918, and 2HV-27938 were I
the hydrogen monitor system for a total of 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> and 47 in minutes on Unit 1 while in Mode 1 and 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br /> and 11 minutes condition for operation (LCO) action statement.on Unit 2 whil 19-02; 50-425/90-19-02) (50-424/90-e i This is a Severity Imvel IV violation (Supplement I) .
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B. Technical Specification 4.2.5.3 requires that the reactor I
coolant system (RCS
! balance power. before oper)ation above 75 percent of rated thermalf
{ 7 days Furthermore, this specification requires that, within
- prior to performing the RCS flow measurement, the !
q instrumentation shall be calibrated. used for performing the precision heat balance
! 3 Contnry to t !
within seven (he above, the licensee failed to calibrate,
- 7) days prior to use, the instrumentation used {
i by TS 4.2.5.3 and performed on April 1990.
23,during the perform i I
(50-424/90-19-01; 50-425/90-19-01) 4 i
This is a Severity Level IV violation (Supplement I) .
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Pursuant to the provisions of 10 CFR 2.201, Georgia Power Cospany is hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN: i Desk, Washington, DC 20555, Document Control '
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 1
' 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 the steps that have been taken and the results achieved, (3) corrective steps that will be taken to avoid further violations, and (4) the date when full compliance will be achieved.
If an adequete reply is not received within the time specified in i this Notice, an order may be issued to show cause why the license i should not be modified, suspended, or revoked, or why such other ,
action as may be proper should not be taken. Where good cause is l i
shown, consideration will be given to extending the response time.
nFOR THE NUCLEAR REGULATORY COMMISSION 4
1 L.W D. Ebneter tagional Administrator i
Dated at Atlanta, Georgia this 11 day of Jan. 1991 l f
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LANITED STATES
. /'$388s94fo, NUCLEAR MEGULATORY COMMIS$10N
. O* 'n REGION 18 j
- j. g. 101 MARIETTA STREET.N W.
- ' y ;
, ATL ANTA, CEOmCI A 30323
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. I Report No.:
- 50-424/90-19'and 50-425/90-19 ;
l . Licensee: Georgia Power Company P.O. Box 1295 Birmingham, AL 35201 i
F Docket Nos.: 50-424 and 50-425 License Nos.: NPF-68 and NPF-81 Facility Name: Vogtle Electric Generating Plant, Units 1 and 2 !
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! Inspection Conducted: August 6-17, 1990 i i
i Team Members:
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Ron Aiello - Resident Inspector, Vogtle [
Morris Branch - Senior Resident Inspector, Watts Barr i
. Robert E. Carroll, Jr. - Project Engineer, DRP, Region II 2
l Larry Garner - Senior Resident Inspector, Robinson Neal.K. Huneauller - Licensing Examiner, NRR Iarry L. Robinson - Investigator, OI, Region II Robert D. Starkey - Resident Inspector, Vogtle 1
Craig T. Tate.- Investigator, OI, Region II j Peter A. Taylor - Reactor Inspector, DRS, Region II McKenzie Thomas - Reactor Inspector, DRS, Region II John D. Wilcox, Jr. - Operations Engineer, NRR Team Leader i
Chris A. VanDenburgh, Se gion Chief
) 78 Division of Reactor Inspections and Safeguards t
Office of Nuclear Reactor Regulation i
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Approved by: '
is A. Reyes rector Division of tor Projects
- Region II I
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TABLE OF CONTENTS 1
I INSPECTION
SUMMARY
........................................ 1 1.0 INS PECTION OBJECTI VES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
?.0 OPERATIONS FOLLOWUP.................................. 6 i 2.1 Operational Philosophy, Policies, Procedures, and Practices............................................
4 7
l 2.1.1 Implementation of Technical S i
2 Requirements.................pecification .............. 7 2.1.1.1 Review and Approval of TS Interpretations. 7 2.1.1.2 Calibration Requirements for RCS Flow Instruments................................ 9 2.1.1.3 Anticipated Actions for TS 3.0.3........... 11 1
i 2.1.1.4 Voluntary Entry Into TS LCO Action j
Requirements............................... 13 2.1.1.5 Implementation of TS Surveillance j
Requirements .............................. 16 2.1.1.6 Interdepartmental Review of TS Surveillance Procedures.................... 16 i 2.1.2 Review of Deficiencies for Unana
! Conditions......................lyzed ........... 18 2.1.3 Personnel Practices in the Operations Department................................. 19 2.1.3.1 Overtime and Shift Staffing Policies....... 19
) 2.1.3.2 Training of Plant Equipment Operators...... 20
- 2.1.3.3 Quality Concern Program.................... 22 l
2.2 Control Room Observations............................ 22 2.2.1 Plant Evolutions and Surveillance Testing.. 23 2.2.1.1 Containment Isolation Valve O
' 23 2.2.1.2 LCO Action Times. . . . . . . . . . . ............... .perability. . . . 26 I
2.2.1.3 Completed Surveillance Test Procedures..... 27
, 2.2.2 Operator Attentiveness and Response to i
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2.2.3 Plant Conditions...........................
Operations Procedural Compliance...........
27 29 i
2.2.4 2.2.5 Shift Communications....................... 29 4 Corrective Actions for Deficiencies and Equipment 2.2.6 Failures......................... 31 Performance of Plant E 31 2.2.7 Material Conditions...quipment .....................
Operators... 32 2.2.8 Event Classification and Notifications..... 33 EXIT
- 3.0 INTERVIEWS...................................... 34 APPENDIX 1 - PERSONS CONTACTED. . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 i
APPENDIX 2 - LIST OF ACRONYMS............................. 37 4
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INSPECTION
SUMMARY
Recent activities which have occurred at the Vogtle Electric l
Generating Plant (VEGP) have raised concerns within thm Nuclear
' Regulatory of the licensee Consission to o (NRC)the as to the ability and the dicarmination j
address this concern, perate facility in a safe manner. To i the NRC performed a special team inspection
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to determine if the licensee operates the facility in accordance
, with facility's approved procedures operating license.and within the rer,uirements of the t l
specific operational events at VEGP,In addltion NRC concernsto the occurrence of regarding the safe operetion of the facility were heightened with the receipt of i several allegations relating to operational activities at VEGP.
j The combination operational eventsof the facts and circumstances associated with the initiation of specialand the allegations inspection activities. warranted the immediate Specifically, the inspection objectives were to: :
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! Assess the operational philosophy, policy, procedures and j practices of the facility's regarding operational operating staff and management safety.
1 i 2) i Determine the technical validity and safety significance of
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sach of the allegations and their impact on the safe operation of the facility.
These inspection objectives were accomplished by the use of two
- inspection followup team. teams- an operations followup team and an allegations closely coordinatedf The efforts of these two inspection teams were however, they independently pursued the objectives outlined above.
! The24-hour a operations basisfollowup team monitored control room activities on
! in order to: 1) evaluate the operational philosophy, policies, procedures, a(nd practices of the operating staff and management and (2) determine if the: plant was being operatedlicense.
operating in a safe manner in accordance vita the facility's inspection report. The results of this effort are set out in this i
i I The allegations followup team examined the technical validity and safety significance of each of the allegations.
- the assistance the plant staffof the oI staff, this team interviewed members ofIn addition, with in order to determine (1) their personal l involvement and knowledge of the specific allegations and (2) their l practice and understanding of the station operational policies.
These interviews were transcribed.
assigned to the inspection team to assist during the transcribedAlthough a i
interviews, alleged this inspection was not an oI investigation of the violations. ,
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- are still under consideration and will be documented in separate correspondence.
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- Although two violations were identified, the inspection concluded *
- that the facility was operated in a safe manner in accordance with ;
j the requirements of the licensee's operating license. In addition, 3
there were several operational practices where weaknesses were >
identified.
The specific observations and conclusions of the operations ,
f followup team are detailed in the inspection report; however, the i bases for these overall conclusions are summarized below.
l Technical specifications l The inspection identified two instances in which the licensee !
l violated the requirements of the Technical Specifications.
- 1) The licensee indicated that the limiting condition for !
j operation (LCO) for TS 3.6.3, " Containment Isolation Valves," .
] did not require the containment isolation valves for the !
l hydrogen analyzer system to remain closed during Modes 1 i
! through 4. The inspection identified Violations 50-424/90 l 02 and 50-425/90-19-02 in this area. (Section 2.2.1.1) !
- 2) The licensee indicated that the surveillance requirements of i TS 4.2.5.3, (reactor coolant system precision heat balance j flow measurement) did not require the calibration of all the
- instrumentation used in the performance of the precision heat
- balance within seven days of performing the heat balance. The j failure to perform the calibration of all the instruments used j during previous performances of the precision heat balances i had resulted in the incorrect calculation of the RCS flow
! during the period of April 23 through May 21, 1990. The failure to accurately calculate the RCS flow was due to the
- failure to correctly perform the surveillance requirements of j TS 4.2.5.3. The inspection identified Violations 50-424/90-
. 19-01; 50-425/90-19-01 in this area. (Section 2.1.1.2)
- 2 Doerational Policias and Practices j The inspection identified several instances of operational policies j and practices where there were weaknesses. Specifically:
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- 1) The licensee's method for TS interpretations allowed the
- operations manager to be solely responsible for the approval j and distribution of the interpretations. The inspection team was concerned that the intent of the TS may be changed by the interpretations without an interdepartmental review and ,
approval of the interpretations, such as would be provided by j a plant review board (PRB) review. (section 2.1.1.1)
) .2) The licensee's method for interdepartmental review of procedures appeared to rely on the procedure writer's judgment
, or another department's request. As evidenced by the lack of j
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- l an Operations 24551-2, Department
" Containment Hydro review of Surveillance Procedure !
, and channel Calibration," gen Monitor Analog Operability Test that all procedures that this methodology had not ensured i !
receive affect the that department's review andOperations concur Department i
i j inspection team concluded that the licensee 'rence.
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needed improvement. performing intra- and interdepartmental s method of revi 1
i (Section 2.1.1.6) )
i 3) i The licensee indicated that the Lc0 action requirements of TS 3.7.8, j
" Snubbers the performance " allowed o,f snubber voluntary entry into the LCO for modifications i' i with fixed struts). (i.e., replacement i
LCO (during modes The licensee's voluntary entry into the i when the snubbers were required to be operational) not in con was performed maintenance. junction with other pre-planned as an operational convenience and I
service coolingInwater testing or
! addition, the method used for the nuclear
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safety features equipment. (NSCW) modifications unnecessary resulted reduction in in the anavailability 1
. were not necessary and were performed in order eto reduce scope of the subsequent refueling outage.
} 4) (Section 2.1.1.4) i The licensee indicated that the Lc0 for TS 3.0 3 . ,
" Shutdown i
i Actions," allowed a total of seven hours to achieve hot
{ until three hours after entry of the Lco. standby and that based
- This position was standby) on within their ability to go from Mode 1 to Mode 4 (hot four hours.
5)
(Section 2.1.1.3)
{ The licensee's method of certifying the qualifications for i
i plant equipment The training operators evaluator (PEOs) delegated thewas not correctly performed .
i responsibility for evaluating performance of trainee PE0 PEO. rounds to a qualified i The evaluator (without discussions with the qualified PEO) certified based that thePE0's on the qualified rounds were satisfactorily pcom e ed l t qualified initials, even though the
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PE0 had not observed the performance of the trainee's rounds.
i i a management training for PEOs. review of the implementation of the o
- (Section 2.1.3.2) {
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The licensee's method of identifying ca ons a
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actua i i
performance procedures nor,ofingeneral inspections was neither well some instances, defined in (0JT). (Section 2.2.6) by on-the-job training 7)
- . i Operations Department was considered e in thea weaknes I lack of recent work history information, frequent fact" ause" of aftthe authorisation of excess overtime, and the potential er the i
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inspection team also been performed by certain individuals.
concluded that
- a. excess me may have The ov l
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unbalanced 2.1. 3 .1) experience levels on the esult night in shifts!
[i (Section 8)
The for licensee's operations method Department of holding periodic mini was -safety meetings 4
fulfilling the personnel
} administrative not properly i (section 2.2.4) procedure requirements. t t
I 9) k Program had a potential weakness exit with respect uality concern t 1 (Section 2.1.3.3) interviews and theof assignment o the method of the investigations.
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! the assistance the plant staff in of the OI staff, order to this team interviewed determine members of involvement and knowledge of the specifictheir personal and (2)
! (1) allegations t
practice and understanding were transcribed.of the station operational policies heir ,
t 3
These interviews .
i assigned to the inspection team to assist during the transcrib dA i
i alleged violations. interviews, this inspection was not an on into the eoI investiga reviewcorrespondence.
separate are still under consideration and will be document n 3
i In addition to identifying the operations I followup team's conclusions several and findings, weaknesses in the this report identifies two violations prograns, and procedures. licensee's operational and policies, inspection and in the Inspection team's concerns Summary. are detailed in the a sections o low th t f 2.0 OPERATIONS FOIJ4WUP w
on e aoperations philosophy, 24-hour followup basis practices, teamtomonitored the control room activiti in order 1) evaluate the es statf, and operational manner inspection in a(2) determine if the plant was being ccordance with the facility's operating license. The team's shift schedule closely coincided with the operating staff's 12-hour shift rotation so that the NRC orsimpa t could interaction become familiar with other with the individualoperators ea.d ctheir operators.
The operations followup team conducted a performance-based operational philosophy, policies, procedures, operating staff and management. s a e the of the and p The inspection team observed and managsment during the shift monitoring ng staff activities 1 or substitute for theThis effort !
was not intended allegations followupto duplicate team but was efforts of the to those addressed implemented at the station, by the allegations team weroperatio similar e currently being !
The team used the guidance of Inspection Procedure i
" operational cperated in a safe Safety Verification," to evaluate manner. ifethplant 71707 was , ;
)
inspection requirements and guidance of Inspecti In addition, the team used the
- Sustained control Room and Plant observation "on Procedure 71715, cperational activities conducted by the licensee and observed
,to evaluate if !
4
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operators and conditions. ~were attentive and responsive to plant parameters l
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interpretation and interpretations. discussed both verbal The allowed either the written i procedure and superintendent, the initial operations manager or unit superintendent interpretation. shift to make j However, the final, i interpretation was signed by the operations managerwritten .
j A review of TS 6.4.1 regarding the function and responsibilit y of i
the for Plant Review reviewing those Board procedures (PRB) indicated that the PRB onsible was resp that
- administrative controls as well as any pro. established plant-wide PRS review is the review and audit posed changes to Ts. The 4
method specified by TS to !
ki provide an interdepartmental that the intent of the TS is not changed. review of proposed changes to ensure '
The TS did not As such, a licensee action, absent PRBaryreview, to
. app ensureofthat intent the the TS. TS interpretations have not and will not change e th l<
i qualified to interpret theThe licensee indicated that, managerbecause was the operat i
reviews were not necessary. Ts based on his experience, additional
}
described in section 4 of this inspection report,In addition, during the
- indicated that individual review it wasorundesirable to have any other thedlicensee
- concur in the Operations epartment or i interpretation based on the of the Technical specifications .
Department i additional personnellicensee's desire to minimize theThis position was cbility to implement to ensure that the licensed operators involvement had the of i the re i
specifications on a timely basis, quirements of the Technical I
! I
! Department written questions)to issue TS interpretations .
(i.eThe inspection e Operations i
i i answer was correct. allowed sufficient time ,towritten ensure answers to that the have dela The review of these interpretatio.% woul !
cddition,yed thea response inspectionto an team noted that immediate operational concern.d In not j
! interpretations were requested as clarifications b several of the cnd concerned areas that were beyond the y the operators routine knowledge of m licensed axial rcquired operators, flux difference such as the definition of core qu a rants, the d
ost (AFD) target i
" difference Icolation valves units, "and the applicability of TS 3 6band 3 for flux i
. , " Containment !
i vonting, draining,,surveillance or local leak requirements rate testing during sampling, (LLRT) v t es.
acti i i i The inspection team's review of several sets of nTserpretation it ,
manuals indicated that the TS interpretations were sr not uted di t ib i in a controlled manner and that there e o was no m th d to ensure that
, a complete cperations set wasandavailable.
manager's the control The inspection team found e
that th interpretations were not identical. room's copies
, of the i
iccued on August 14 maintained in the control room at was contained an 1988, concernit;q TS 3.0.3. This specific i
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3 the licensee indicated that calibration of equipment other than i special test instrumentation was not required by TS 4.2.5.3 and 4
! intended to pursue confirmation of the Operations Department's i original interpretation of the TS. The LER indicated that the !
surveillance procedures would be revised to require the calibration l l
l of the feedwater temperature computer points withinInthe 7 days addition, 1 before the performance of the precision heat balance. l the licensee reperformed the precision heat balance calculations :
using estimated values for the feedwater
! for both units temperatures. These estimated values were based on the average i drift indicated by a subsequent calibration of the feedwater l temperature computer points. The new calculations of the RCS flow l showed the RCS flow rates to be slightly less than the previously j calculated flows, but still above the minimum values specified in ,
j 3
j the Technical Specifications, i l
The inspection found that the licensee had previously identified l that the RCS flow balance had not been performed correctly for t another reason. The RCS flow balance was incorrectly performed on
}l April 23, 1990, because the computer points (which 'the licensee l
h<11cated were not required to be calibrated within 7 days of the surveillance) had been incorrectly calibrated during a previous maintenance activity. The inspection team discussed the chronology l
j of events for Unit 1 with the reactor engineer who indicated the
- following
j
- The precision heat balance and RCS flow calculation were l
performed on April 23, 1990, at approximately 74 percent i of reactor power.
l
- When the reactor power level was increased to l
approximately 100 percent, the system performance l
engineer questioned why electric output and turbine l
j first-stage pressure were lower than expected.
l
- On April 28, 1990, Deficiency card (DC) 1-90-240 was l
written when the licensee's investigation revealed that l
feedwater temperature, as indicated on Proteus computer's ;
final feedwater temperature points (T0418, T0438, T0458, l and T0478) were reading approximately 10 degrees i
l
! This error was caused by Fahrenheit lower than actual.
l use of the wrong resistance temperature detector (RTD43) l curves during calibration of the points under Maintenance Work order (MWO) 19000042 on January 23, 1990. It was l
not apparent from the DC that the effects on the RCS flow calculation were considered.
- On April 24, 1990, the feedwater temperature instruments
- in question were recalibrated under NWO 19002215.
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l = On May 21, 1990, the Reactor Engineering Group i
' recalculated the RCS flow based on applying a correction J j to the original feedwater temperature measurements. l The inspection team found that on both occasions the licensee I
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1 recalculated the RCS flow rates after finding that the precision i i
heat balance flow measurement was incorrectly performed. However, ;
the licensee did not reperform the precision heat balance surveillance procedure to develop the input data for the RCS flow !
i calculation. The inspection team discussed the licensee's basis !
I for not reperforming the RCS flow balances with the responsible ;
- staff of NRR and concluded that this position was technically j
acceptable, i
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On May 21, 1990, the licensee used a 3inear interpolation between l the wrong feedwater temperature indication and the correct i
! Andication to correct the RCS flow calculations performed on April j 23, 1990. This correction resulted in a 1.4 percent reduction in I i
the RCS flow calculation (412,822 gym to 407,294 gpm) . On August i 14, 1990, the licensee used estimated values for the calibration i drift of the feedwater temperature instruments as corrective action for the failure to recalibrate the instruments within seven days of
- the RCS flow calculation. The estimated values were based on the j average drift indicated by a subsequent calibration of the feedwater tesperature computer points. This correction resulted in
! a 1.5 percent reduction in the RCS flow calculation (407,950 gym to i 401,950 gps) . As a result of both corrections, the recalculated l RCS flow was 1.5 percent above the minimum value (396,198 gpa) l specified in Technical Specification 3.2.5, "DNB Parameters".
1 l Although the surveillance procedure was not required to be
- reperformed, the inspection team concluded that the failure to
! perform the calibration of all the instruments used during previous performances of the precision heat balances had resulted in the incorrect calculation of the RCS flow during the period of April 23
. through May 21, 1990. The inspection team concluded that the inaccurate calculation of the RCS flow rate was due to the failure i
l to correctly perform the surveillance requirements of TS 4.2.5.3.
! This violation will be followed as:
l VIO 50-424/90-19-01; 50-425/90-19-01, " Failure To Perform Calibrations of Surveillance Requirement 4.2.5.3 Resulting in Incorrect RCS Flow Measurements."
l 2.1.1.3 Anticipated Actions for TS 3.0.3
) The inspection team reviewed the Operations Department's actions with respect to the requirements of TS 3.0.3. TS 3.0.3 requires that, when a limiting condition for operation (140) was not met, except as provided in the associated action requirements, action
- shall be'taken within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to place the unit in a mode in which the specification did not apply by placing it in hot standby within i .
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! at least in cold shutdown within the-subsequent ,and 24 ho I i
i The NRC's allowed position regarding TS 3.0.3 is that a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> interval is to prepare i
change in plant operation. for an orderly shutdown before initiating a
! coordinate the reduction in electrical generation with the loadThis dispatcher to ensure the availability of the electrical grid . The i
the shutdown to proceed in a controlled and order well within the specified maximum cooldown rate and within the i
cooldown capabilities required equipment of the facility, assuming only the minimum is operable.
i Discussions with
! shutdown actions will not be initiated until 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> into TS and that only minimum preparations will be made within the. .first hour.
1 The unit superintendent indicated that the operations i
j Department interpreted the action statement of TS 3.0.3 to allow 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> to be in hot shutdown and to accomplish this, the shift can j
j wait for 3 shutdown. hours after entering the Lco before commencing a j first hour is to retrieve the shutdown procedure.The only activity
- notifications required within the first hour. There were no j
be accomplished within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. general manager indicated that an orderly The documentation for 10 previous entries into TS 3.0.3 indicated
- that the actions discussed in GL 87-09 i load dispatcher within the first hour (i.e., notification of the within the next required 6-hours) were not fully implemented.and aAlthough by the controllednotshutdown
! licensee's administrative procedures, j these I
was notified or that a change in plant operation was .
! specifically, that on December a review 22 of the control room's Iro logs indicated
{
period of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> an,d 56 minutes.1987, an entry into TS 3.0.3 was made for a i
action of requirement did not occur until 42 minutes after discovery the condition.
A review of the reactor operator logs and the chart recorders indicates that a steady-state power level of approximately 99 percent was maintained for the entire time Unit 1 i
was in a TS 3.0.3 condition on this e casion. Therefore, the !
with initiatingthea operations change in plant operation.
Department management's u es
,without ful concluded that the licensee's The inspection team requirements of TS 3.0.3 were an actions with respect to the considered to be a weakness. operational practice that was
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13 2.1.1.4 Voluntary Entry Into TS LCO Action Requirements During the inspection, the inspection team identified a concern with the licensee's voluntary entry into the limiting condition for operation (120) action requirements of Ts 3.7.8, " snubbers," to prform modifications to the snubbers of safety-related systers.
These modifications were performed as part of the licensee's snubber reduction program.
Phase II of the Unit 1 snubber reduction program involved the removal of snubbers during power operation. The installation of a rigid, fixed support was required to allow rcmoval of the enubber; however, the licensee removed the snubbers before the installation of the fixed support. The licensee coordinated the snubber modifications on a system basis in order to minimize the length and number of safety system outages required to perform the work. The total number of snubbers removed during this cycle on each of the safety systems with Unit 1 at power was:
RHR Train A 11 RHR Train B 16 CCW Train A 7 CCW Train B 6 NSCW Train A 14 AFW Train C 10 TOTAL 64 Ths operations manager stated that, after the second Unit I refueling outage (1R2), the modifications to the snubbers were done in conjunction with system outages which were required for other preventive or corrective maintenance. Although another licensee employee indicated that this may not have been entirely true for the residual heat removal (RHR) system, the operations manager stated that the majority of the modifications were performed in conjunction with pre-planned system outages. .
Although some of these modifications were made when the system was removed from service for other maintenance and testing, the
, inspection identified that few of the snubber modifications were done jointly with pre-planned system outages. The majority of the j snubber modifications were made during a mode when the safety system was required to be operable and there was no other maintenance or testing performed. Specifically, some of the residual heat removal (RHR) Train B snubbers were removed during the time the train was in a system TS Ic0 for other work activi-ties. However, seven of the nuclear services cooling water (NSCW)
Train A snubbers were removed during a system 140 that involved no other work activities. The trains and supported equipment had been secured by the use of the " pull-to-lock" start switches or by j positioning the switches to the "stop" position. The equipment was
' secured in response to the Engineering Department's recommendation
t a i
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l that these snubbers were useful in mitigating water hammer effects
! during closing of a check valve. The remaining snubbers were I j removed in accordance with the Mo action requirements of TS 3.7.8. l j During these modifications, no other work activities were in
- progress which required the system. MO to be in effect at this
- time.
l TS 3.7.8 requires that all snubbers be operable in Modes 1 through
! 4 and excludes only those non-safety-related snubbers whose failure ,
! would have no adverse effect on any safety-related system. The Mo 1 i action statement requires repair or replacement of all of the
+
inoperable snubbers within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and the performance of an
! engineering evaluation in accordance with TS 4.7.8 9 on the l
! attached safety-related system or the associated safety-related )
i system declared inoperable. Ts 4.7.8.g defines the engineering j evaluation required for those snubbers that are found inoperable.
- All of the work packages discussed above were completed within the
! 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement of either the system Mo or the snubber l LCO of TS 3.7.8.
l The licensee's decision to enter the snubber TS LCO action l :;tatements for the majority of the work was based upon VEGP interoffice correspondence from M. B. Lackey to W. F. Kitchens, dated August 2,1987. This correspondence indicated that (1) when the first snubber is removed, Ts 3.7.8 should be entered; (2) work j packages should be developed so that the work can be completed
- within the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed by the M0 action statement of TS 3.7.8, and (3) if problems were encountered, the additional 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of the safety-related system's LCO would allow time for resolution.
l The inspection team reviewed the safety evaluations for the design change packages (DCPs) associated with snubber reduction on the RHR
! respectively). The reason stated for the proposed modifications
- was to optimize the design and reduce the quantity of snubbers.
j The long-term effect anticipated was a significant savings in i inspection and maintenance costs, in addition to a reduction in i personnel radiation exposure over the life of the plant. l l' i l
The licensee performed an as-low-as-reasonably-achievable (AIARA) I review on each work package. In every case, except the RHR system !
j work package, the licensee determined that because of where the
- piping and supports were located, there was a minimal difference in i the expected exposure between performing the work with the Unit !
operating at full power and the unit shut down. For the RHR system modifications, the RHR piping provided a larger source term (i.e.,
more radiation exposure) if the work was performed while the RHR
. train was operating in shutdown cooling because at power the RHR 4 system is secured. However, the inspection team noted that if the
- modifications were performed when the unit was shut down, only one RHR train "ould be required to be operating in the shutdown cooling i
1 3
1 4
- 15 i mode. Therefore, the modifications on the secured RHR train could i be performed with essentially no difference in exposure than if they were performed with the unit at power.
l After discussions with knowledgeable NRR personnel, the inspection l 1..am concluded that TS 3.7.8 was not intended to provide action j' requirements for modifications to snubbers. The Lc0 for TS 3.7.8 should be entered only when a snubber is removed from service for required testing or maintenance. If the snubber is not returned to
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i service within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, the associated safety-related system'a 140 i must be entered. Furthermore, routine, voluntary entry into the i
action requirements of the 140s should adhere to the conservative principle that the entry represents a not safety benefit and should j be warranted by operational necessity, not just for convenience.
The licensee's removal and replacement of snubbers with fixed i struts provided a more reliable piping support system and,
! therefore, was a safety benefit to the facility. The licensee had l evaluated and implemented steps to preclude the potentiki damage to the associated systems and equipment under modification; however, h NSCW modifications, these steps included removing the entire ESF train from service. This included securing the NSCW train and l
l 1 the following supporting equipment: component cooling water, safety
} injection, residual heat removal, the chemical and volume control l pump, containment coolers, and ESF room coolers. The inspection I team was concerned that the removal of this ESF train from service for approximately 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> involved an unnecessary reduction in the availability of ESF equipment.
l
! Because the licensee removed the snubbers before installation of j the fixed struts, the operability of the associated system was
' affected. Based upon the time available to plan the modification, j the licensee had the ability to verify the effect of the j
modification on the operability of the associated systems and should have entered the 140 for the system vice the snubber LCO.
l In addition, the inspection team concluded that the voluntary entries into the action requirements of the I40 (during modes when j the . system was required to be operational) were performed as j operational conveniences and not in conjunction with other required testing or maintenance. These voluntary entries into the snubber j 140 (vice the associated system LCO) were performed in order to reduce the scope of the subsequent refueling outage.
J l
Although the snubber reductions resulted in a s lety benefit to the
- facility, the methods used for the snubber modifications (i.e., the
~
removal of snubbers before the installation of the fixed struts) l resulted in an unnecessary reduction in the availability of the ESF equipment during the NSCW modifications. Hence, in this respect,
! the snubber reduction program was an operational practice where a 1- weakness was identified.
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16 l 2.1.1.5 Implementation of TS Surveillance Requirements 1
! The inspection team reviewed the TS surveillance requirements to 1 ensure that a surveillance procedure had been developed for each requirement. As a result of this review, the inspection team found that a surveillance procedure did not exist for the surveillance requirements of TS 4.7.3.a, " Component cooling Water System." This TS requires that at least two component cooling water trains shall be demonstrated operable at least once every 31 days by verifying
- that each valve that is not locked, sealed, or otherwise secured in position is in its correct position. The inspection team 2 determined that, on April 11, 1989, the operations manager had initiated steps to delete surveillance Procedures 14551-1 and 14551-2 which previously fulfilled the surveillance requirements of
)
l These surveillances were last performed on April 4,1999, for Unit 4
1, and April 7, 1989, for Unit 2. The licensee in( 2:ed that TS
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4.7.3.a required verification once every 31 days of L.q the valves
- in the component cooling water (CCW) flow path that were not j locked, sealed, or otherwise secured in position. The licensee j also stated that surveillances were not required for any CCW flow i path valves at Vogtle because all CCW flow path valves are included
) in the Vogtle locked valve program.
! The inspection team noted that TS 4.7.3.a did not specifically l
exclude valves that were not flow path valves as did other
- surveillance requirements. For example, Surveillance Requirement 4.5.2.b.2 specifically requires position verification of only the
- flow path valves in the emergency core cooling subsystems (ECCS).
In addition, the inspection team noted that the surveillance l
i procedures for other TS surveillance requirements which were
{ written similar to TS 4.7.3.a (i.e., where valves that were not i main flow path valves were not excluded) required the verification i of valve positions for valves that were not in the main flow path.
! Specifically, Surveillance Procedures 14552-1 and 14552-2 which incorporate the requirements of TS 4.7.4.a for the nuclear service i cooling water (MSCW) specifically required valves that were not in l the main flow path to be verified.
1 Although the surveillance requirement of TS 4.7.3.a does not
! exclude the valves that are not flow path valves and the term " flow
! path" is not mentioned in the TS, the team, after discussions with i
NRR staff, concluded that the licensee correctly interpreted the j intent of the surveillance requirement to exclude the valves that
, are not flow path valves. The inspectors had no further concerns in this area.
f 2.1.1.6 Interdepartmental Review of Surveillance Procedures
. The inspection team reviewed the manner in which the operations j Department reviewed the procedures of other departments. The 1
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- procedures the operations ofof interest the plant. were those that had a potential to affect i operations Department did not review Surveillance Procedure 2 i 2,
- " Containment Hydro t Channel Calibration," gen Monitorimplementation.
Analog operability Test and i before l Administrative Procedure 00051-C, " Procedures Review Although and A
- pproval,"
j requiredofaffected deletions department departments to review revisions to, or the procedures, the operations Department ;
t failed to review surveillance Procedure24551-2 'Ibe inspection .
l to reviewprocess licensee's otherforMaintenance Department a procedurest failed i
because the informally and was not always documented. interdepartmental review was ,
i on the basis of this informal procesF of performing inter-departmental reviews, the team requested that the license ;
e identify
! the method used in the past for intra- and interdepartmental ;
i j reviews of such Maintenance Department procedures ce procedures. as surveilla NRC in the form of interoffice correspondence dated Aug i "*0, from D. E. Gustafson !
j
" Procedure Reviews."
to H. M. ,
Handfinger and titled, )
i i 1
The determination of the need for interdepartmental r I based on whether the procedure called on another eviews departmentwas t l action for or perform o takeexpress d desire a review. a service, or whether the department i
i e a i
Engineering procedure writer Department The need was for based a technical on the personal review by opi the i
! procedures were se. Also, for interdepartmental reviews n on of the i
! the procedure writer, knew the most about the subject of the p
- i In addition, with the exception of integrated leak (ILRT) procedures, e ure. ,
instrumentation andthe control Operations Department did not review therate testing !
them.surveillance procedures unless specifically how many asked to review of the interdepartmental review. surveillance The licensee procedures had received could not an indicate The inspection i team was concerned that the method for
! judgment or on another department'sure request.
writer's interde
' lack of an Operations Department review of SurveillaAs evidenced by the 24551-2, " Containment Hydrogen Monitor Analog nce Procedure Operabilit i channel Calibration," this methodology has not y Test and !
i procedures that concurred on by that department. affact the operations Department ensured that are all review d i that e and i j Maintenance Procedure 20022-C, Although the licensee indicated '
)
Maintenance Procedure Writer's Guide " Mechanical and Electrical and Review Guidelines," I' Revision 6, would be revised to cue cprovide more spec i
i direction for
- licensee's method of performing intra- and that the i andinterdepartmental j
reviews of procedures is a weakness needs to be improved .
i i h
! l
i
, . i I 19 .
r I
! processing changes to the Unit 2 fire alarm procedures to include !
the detailed guidance of the Unit 1 procedures. ;
! 2.1.3 Personnel Practices in the Operations Department l
! The inspection team identified several concerns and observations i
! with respect to the Operations Department's personnel practices.
Although this area was not originally included in the scope of the l
i inspection, it was raised by operators during other inspection {
j activities. !
2.1.3.1 overtime and Shift Staffing Policies The inspection team reviewed the amount of overtime worked by l Operations Department non-supervisory personnel, that is, reactor :
- operators, radwaste operators, and plant equipment operators ,
, (PEOs). The review of the overtime practices indicated that !
- excessive overtime, greater than the guidelines provided in TS ,
! 6.2.2.e, " Plant Staffing," was authorized almost exclusively to l
- support refueling activities. The inspection team also noted that j- the unit superintendent whose primary responsibility was scheduling l
manpower for the unit outages was also responsible for authorizing j the excessive overtime. These concurrent responsibilities had the
- potential to be in conflict. In addition, although the individual i excess overtime authorisation forms are routed to the operations i manager and general manager (who initialed the forms), the forms j did not provide information concerning the recent work history of j the individual. Thus, the context in which the excessive overtime
- was authorized was not readily available for the reviewers. In .
l addition, the authorization forms were signed frequently after the !
j excess overtime was worked.
i
- The inspection team reviewed the use of overtime which did not
- exceed the guidelines of TS 6.2.2.e, but was in excess of the i objective stated in TS 6.2.2.e (i.e. , greater than a nominal 40-j hour week while the plant was operating with a 12-hour shift i
schedule.) During the period April 21 through July 27, 1990, employees were allowed to work up to 40 percent above their normal schedule.
f
! The inspection team also noted that the operating shifts were not '
I well balanced with regard to the experience levels of non-
, superviscry personnel such as reactor operators and PEOs. People working on night shifts (shifts D and E) typically had less
, experience than people working day shifts. In response to this
- concern, the licensee indicated that the primary contributor to i this situation was the seniority system which allowed senior individuals (typically more experienced personnel) the choice of
! the more desirable day shift positions. Tn addition, the j operations Department policy of rotating supervisory personnel (i.e., senior reactor operators) every 24 weeks partially j compensated for the unequal distribution of experience. This
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l Li i !
i 20 rotation involved senior reactor operators (SROs) who have 'been
- assigned to shifts as well as those assigned to administrative ,
- duties. The inspection team did not find evidence that the '
- grouping of less-experienced reactor operators and PEOs had resulted in any disproportionate number of events or problems.
- ovever, since most of the surveillance activities and calibrations i are performed during the night shift, this staffing pattern haa the
! potential to become a weakness.
i b The inspection team concluded that the potential conflict of
} interest, the lack of recent work history information, and frequent
- "after the fact" authorization of excess overtime were weaknesses
! in the Operations Department's policies for overtime approval. In l addition, the non-supervisory staffing policy had the potential to ,
j result in unbalanced experience levels on the night shifts.
l l,
2.1.3.2 Training of Plant Equipment Operators !
2 During the inspection team's discussions with six plant equipment operators (PEOs), three PEOs indicated that they had been qualified
! for the auxiliary building without the evaluator having observed
! their performance of rounds, Two of the PEOs indicated that they had never accompanied another qualified PEO on auxiliary building
- rounds before being qualified One of these two indicated that he
! had already been assigned the position without having been with i
another qualified PEO during rounds in the auxiliary building.
i The Training Department reviewed the circumstances surrounding this qualifications process as described by the specific PEOs. The training manager indicated that the training evaluator responsible for certifying the PEOs had delegated his responsibility for evaluating performance of PEO rounds to a qualified PEO, an
{ individual not designated to be an evaluator. Instead of i accompanying the trainees on the rounds, the PEO instructed some
', of the trainees to make the rounds and return the completed rounds shects to him. After reviewing these sheets, the PEO initialled th.am, indicating that the rounds had been properly performed. The
! evaluator, without speaking with the qualified PEO, observed the i
PEO's initials perform the rounds. and assumed that the PEO had observed the trainees had been satisfactorilyThe evaluator then certified that this task demonstrated.
1 i The training manager and operations Department's training j
coordinator both indicated that to their knowledge neither Training i nor Operations Departments have reviewed the implementation of on-l the-job training (MT) for PEOs. The inspection team was shown that a management observation report (MORE-TQ-3) had been recently l
issued, but not yet implemented to evaluate OJT in all departments.
The Department.
lack of NT evaluations had been identified by the Training 1
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l The PE0 training program was summarized by the licensee. The j training was divided into four sejor sections: basic, turbine Each part j building, auxiliary building, and outside areas.
- involved 10 to 12 weeks of instruction. The basic training j consisted of classroom training in skills and knowledge for such j items as tagouts, lineups, and was supplemented with in-plant
- training ~ by an instructor. The three duty station training j sections involved
- 8 weeks of classroom instruction with half of the time spent in the plant with the instructor or qualified PE0; j 2 weeks of in-plant evaluation in which the trainee was assigned to j a shift and was evaluated on specified tasks by either a qualified
- PE0 or an instructor; observation of at least one turnover and
- performance of PE0 duties on one full shift while being evaluated i by a qualified PE0; and OJT on performing rounds. Once these items l
were completed, the PE0 was considered fully qualified on the area
- and assigned a shift. At the discretion of the shift 8 superintendent (SS), a newly qualified PE0 could be assigned to a j more senior PE0 for additional OJT.
i The operations manager indicated that he thought a " break-in period" for PEOs would be a good idea and he said would discuss i that possibility with the unit shift supervisor responsible for i training. The desirability of this was underscored when all of l seven PEOs interviewed indicated that either additional time under l
instruction was desirable or that they had already recommended to management that they receive more instruction.
! As discussed in Section 2.2.6 of thist inspection report, the inspection team identified inconsistencies in how the PEOs l
performed rounds. As a followup to this concern, the inspection l
team asked to see the PE0 training records associated with a recent
! PE0 class. As a result of this request, the licensee discovered j that when 10 PEOs had completed their qualifications on June 15, !
i 1990, the training qualification checklist had not been signed by l
, the operations manager. The licensee obtained the proper i
- signatures on August 8, 1990.
l A review of the qualification sign-off criteria sheets for 1 of 10 1
- PEOs indicated numerous examples of the same omission in properly i l completing the sheets. In each example,Section III, " Practical !
Requirements," failed to indicate whether the requirement was !
completed by either performance (p), simulation (s), observation i (o), or discussion (d). The following qualification sign-off .
- criteria sheets had the omission
- 1, 9, 10, 12, 13, 15, 16, 20, l 22, 24, 27, 29, 44, 45, and 51. These deficiencies were discussed j i with the operations manager.
i f The inspection team concluded that the licensee's method of
! certifying the qualifications for plant equipment operators was not I
! correctly performed. The PE0 evaluator, without discussions with
! the qualified Pa,0, observed the PE0's initials and assumed that the PE0 had observed performance of the rounds. The evaluator then j i
f,
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! - i l' .
22 ;
! certified that this task had been satisfactorily demonstrated. In j i addition, the licensee had not conducted a management review of the
- i. implementation of the PEO's OJT training. This is an identified weakness within the licensee's operational practices. (
i 4.1.3.3 Quality Concern Program l The licensee's Quality Concern Program was designed to encourage 1
f employees to identify items of concern that could potentially >
j affect quality, and to bring these items to the attention of plant l management. The program was implemented by the Quality Concerns j l
Coordinator in accordance with Administrative Procedure 00015-C, i
" Quality Concern Program."
The inspection team reviewed the list of quality concerns to l 4
determine if the items were being categorized appropriotely (i.e., j quality related or non-quality related) . The team also reviewed With
] selected concerns to determine the status of the resolution.
j respect to this review, the team observed that the method used to identify quality concerns during employment exit interviews did not
- include a personal interview with each employee because the Quality i
Concerns Coordinator was not always available. Because the Quality Concerns Coordinator was the only person assigned to the Quality i
Concerns Program, there were several examples of the exiting i
employee not having the opportunity to personally identify quality l
concerns. In addition, the method of assigning the quality concern j to the affected department could result in a lack of an independent j' review.
i Th inspection team concluded that the Quality Concerns Program had
- a potential weakness with respect to the method of conducting exit
- interviews and the assignment of the investigations.
2.2 control Room Observations l The inspection team observed control room activities on a 24-hour basis for a days. During this period, an NRC inspector accompanied the licensed and non-licensed operators on their rounds and observed activities in the control room to v. rify that facility ,
4 operations were being safely conducted within regulatory
} requirements. The team also interviewed licensee personnel, 1 independently performed verifications of safety systems status and l
1ros, attended licensee meetings, and reviewed facility records.
1 During these inspections, the team observed the conditiorm under
, which materials- and components were stored and the cleanliness i conditions in various areas in order to determine if safety or fire !
hazards existed. '
l l
The following attributes were verified, as appropriate. )
4 1
- Control room staffing l
j
s .- . ;
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- Control room access and operator demeanor I
! . Adherence to approved procedures for activities in j progress
. Adherence to TS limiting conditions for operations '
1
. Observance of instruments and recorder traces of safety-
'! related and important to safety systems for abnormalities
! . Review of annunciators alarmed and action in progress to correct '
!
- Control room panel walkduwns J
l
. Safety parameter ~. display and the plant safety monitoring
, system operability status ,
. Plant status, licensee plans, and operator knowledge
~
. Reactor operator logs, unit shift supervisor logs, and shift turnover sheets.
2.2.1 Plant Evolutions and Surveillance Testing I The team monitored control room activities to determine if the l operators were attentive and responsive to plant parameters and l
conditions. In addition, the inspection team observed surveillance j tests to verify that approved procedures were being used; qualified l
personnel were conducting the tests; tests were adequate to verify i
equipment operability; calibrated equipment was utilized; and TS 4 requirements were satisfied. As a result of this effort, the inspection team identified several concerns which are discussed in Sections 2.2.1.1 through 2.2.1.3.
l 2.2.1.1 Containment Isolation Valve Operability
! On August 6, 1990, during its initial tour of the facility, the inspection team noted that the Unit 2 containment isolation valves (CIVs) associated with Train A of the Hydrogen Analyser System were l open. The open valves were 2HV-2792A, 2HV-2792B, 2HV-2791B and 2HV-27938. These remotely-operated, manual valves were designated as centainment isolation valves in the Final Safety Analysis Report (FSAR) and are not normally open during power operations. Upon questioning, the unit shift supervisor (USS) told the team that the
.' CIVs were opened to allow the performance of Surveillance Procedure 24551-2, " Containment Hydrogen Monitor Analog Operability Test and l
Channel Calibration." Additionally, the USS indicated that these valves received a containment isolation signal. The operations l l
manager confirmed this statement in a later discussion with the inspection team. The inspection team determined that the CIVs were l
d
, ,. - , , -a,,..w.. ---,,--a ,--,n - - - - . ,- e- , ,e - , . - ,
i i !
t i 24 ,
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! remotely-operated, manual valves which did not receive an automatic j containment isolation signal. l 1 .
On August 7, 1990, at 2053 hours0.0238 days <br />0.57 hours <br />0.00339 weeks <br />7.811665e-4 months <br />, the licensee opened the CIVs and i initiated similar testing on Unit 1 even though the inspection tea '
2 had expressed a concern to the operations manager earlier in the 3
day that opening the CIVs violated the Lco of Ts 3.6.3. After discussion between the inspection team and the Unit I shifd, i superintendent (SS), the SS instructed the reactor operator te
- close the CIVs and to terminate the surveillance test.
- TS 3.6.3, " containment Isolation valves," requires when in Modes 1 i through 4 that with one or more of the CIVs inoperable, Maintain at least one isolation valve operable in each
! - affected penetration that is open and (1) restore the
- inoperable valve to the operable status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, i or (2) isolate each affected penetration with 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> by the use of one deactivated automatic valve secured in the isolated condition, or (3) isolate each affected penetration within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> by the use of a closed manual valve or blind flange, or (4) be in hot standby within
- the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
l The licensate did not believe that TS 3.6.3, " containment Isolation
- valves," required these CIVs to be closed because an open manual i isolation valve was not considered inoperable and the hydrogen
- monitoring system had been designed to withstand accident j containment pressures. However, the inspection team noted that an i interpretation for TS 3.6.3 which was approved and issued by the operations manager on January 18, 1990, specifically defined these
- valves as containment isolation valves and defined an open manual j isolation valve as inoperable. In addition, Section 4.2 of
- operation? Procedure 13130-2, " Post-Accident Hydrogen control j System," Revision 2, cautions that the hydrogen monitoring system l isolation valves must remain closed except durj .g hydrogen monitor l operation to ensure containment integrity is maintained. Also, i FSAR Table 6.2.4.1 listed these valves as containment isolation
!' valves and indicated in Paragraph 6.2.4.2.3 that lines not in use j during power operation are normally closed under administrative controls during reactor operations.
3 l The inspection team was al- told that the brirogen monitoring
- system was considered to be ar3 extension of the primary containment j boundary. However, when questioned as to when it was tested as 4
part of the integrated leak rate test (ILRT), the licensee was not j sure. The inspection team asked for copies of the system design
- and test information to determine if the system was designed and
- tested to a value greater than or equal to the containment design
. pressure and wheths:: it was tested as part of the ILRT. This i
information indicated that the hydrogen analyzer system was not tested as part of the ILRT. However, the Unit 2 hydrogen analyzer i
1 1
i . .. ,
t
) 25 j system was tested by Maintenance Work order (MWo) 28817590 to 90 i pounds per square inch gauge (psig) in accordance with the vendor's
- instruction. In addition, the instrument tubing between the CIVs i
was designed to 80 psig. Although this information indicates that
, the system was designed and initially tested to a pressure higher l than containment design pressure, it does not confirm that this
- equipment will be periodically tested as part of the primary
- containment boundary.
i~
i Additionally, the inspector reviewed the local leak rate procedure ,
l (Surveillance Procedure 24932-2) for testing the Unit 2 hydrogen analyzer system CIVs (valves 2HV-2792A, 2HV-28928, and 2HV-27918.)
- Step 3.2 of this procedure stated that "If test is performed in i Modes 1 through 4, obtain shift supervisor permission to open I valves 2HV-2792A, 2HV-2792B and 2HV-27915. Opening valves requires
! entry into an 140." The review of local leak rate procedures I
(Surveillance Procedures 24910-2, 24930-2, 24931-2, 24932-2, and i 24933-3) indicated that the test was required to be completed within 24-month intervals and should result in testing the : piping
- in question to 45 psig. The inspector was provided coptes of l ==pleted tests performed in 1988 and 1989 (i.e., within the last l 24 months) l A subsequent review of Surveillance Procedure 24551-2, which was
- one of the four surveillance procedures required for testing che j hydrogen analyzers for both units, revealed the following
- 1) The procedure's review cover sheet indicated that the operations Department was not involved in the review and
- approval process.
i 2) The procedure's safety evaluation was inadequate, in that the
! safety evaluation did not explain why the procedure did not
- involva 4. change to the Technical Specifications.
h
! 3) The procedure was technically inadequate in that it instructed operations 'of the- CIVs and did not caution or specify 2
administrative controls over valve operation. This resulted
- in violation of TS 3.6.3 requirements. Also, the procedure
! allowed the test to be conducted in any mode of reactor i
operation when containment integrity is required.
' Afte- discussing its obrervations with NRR staff, the inspection team concluded that, from a. technical position, opening the CIVs
'did not pose a high risk as long as the equipment was capable of withstanding full containment design pressure. Under these
- conditions, strict administrative controls for compensatory
- measures would be acceptable for ensuring that a failure of the
! equipment would be rapidly detected and would result in timely
[ isolation of the penetration in question. However, opening tae CIVs at power should be controlled by the action requirements of i- the LCO for TS 3.6.3. The team discussed this information with 'Ae 4
i i
t i
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l licensee, and asked the licensee to reevaluate the need to open the i normally closed CIVs for the purpose of calibrating the hydrogen
- monitor.
l The inspection team concluded that the failure to comply with the j
action requirements of TS 3.6.3 during the time the CIVs were open j was a violation. With inoperable CIVs, TS 3.6.3 required that j operability be restored within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or the units be placed in !
j hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown within the l M11owing 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. The CIVs were opened on Unit 2 on August 6,
} 1990, at 0411 hours0.00476 days <br />0.114 hours <br />6.795635e-4 weeks <br />1.563855e-4 months <br />, and were not closed until-August 7, 1990, at 1 0122 hours0.00141 days <br />0.0339 hours <br />2.017196e-4 weeks <br />4.6421e-5 months <br />; therefore, the Unit 2 CIVs remained open in violation
! of TS 3.6.3 for a period of 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br /> and 11 minutes. On Unit 1,
! the CIVs were open for a duration of 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> and 47 minutes befora i they were closed in response to the inspection team's concern.
i Both units were operating in Mode 1 during the entire period when
! the CIVs were open. The inspection team also concluded that this violation resulted due to the failure of the operations Department j to adequately review Surveillance Procedure 24551-2, " Containment l Hydrogen Monitor Analog operability Test and channel Calibration."
th 4 item will be followed as violation:
I VIo 50-424/90-19-02; 50-425/90-19-02, " Inadequate i Surveillance Procedure Results in a Failure To Maintain Containment Isolation as Required by TS 3.6.3."
i j 2.2.1.2 140 Action Times
! On August 10, 1990, emergency diesel generator (EDG) f1B was taken
! out of service at 1354 hours0.0157 days <br />0.376 hours <br />0.00224 weeks <br />5.15197e-4 months <br /> for a weekly surveillance. The proper
. 140 entry time was recorded. However, the inspection team noted
) that the unit shift supervisor (USS) considered the EDG to be
{ operable and exited the 140 after the local / remote switch was
- returned to the remote position and before the independent i verification steps of the surveillance procedure were completed.
- Although the EDG was available to start automatically, the USS
! baised his I40 exit on visual confirmation that the remote control of the EDG had been restored and not on the actual performance of a the steps of the surveillance procedure. The inspection team also 1 noted that the EDG was considered operable at 1420 hours0.0164 days <br />0.394 hours <br />0.00235 weeks <br />5.4031e-4 months <br /> by the
- USS; however, the reactor operator did not record it as operable until 1430 hours0.0166 days <br />0.397 hours <br />0.00236 weeks <br />5.44115e-4 months <br /> when the auxiliary building operator reported that the EDG cylinder 1 moisture checks were completed.
The licensee indicated that this was not the usual method of exiting Iros and that all the surveillance procedure steps and j verifications were required to be completed before exiting the I40
- action statement. As followup to this concern, the inspection taan
- observed that, during EDG testing on August 7,1990, the Unit 2 USS properly entered and exited the Iro following an EDG surveillance 4
test. The inspection team had no further concerns in this area.
J i
- - , - ~ ,-
I I
k 27 2.2.1.3 Completed Surveillance Test Procedures The officeinspection contained team verified that the shift superintendent's (SS's)
{j procedures. some completed . copies of past surveillance l
i.
used the procedures differently. Discussions with the operators One shift superintendent statedindicated t
.' that the procedures surveillances, were used to verify completion of previous especially during mode changes.
i This was i reemphasized by a unit shift supervisor. However three different 2
unit information shift supervisors only. stated the procedures wer,e to be used for The licensee indicated that the records were actually intended to be used to (1) determine when the surveillance
}
j 4
was any confusinglast run, (2) trend steps to any previouschanging surveillances. conditions, and (3) compara
)
! The inspection procedures were not team verified that these completed surveillance controlled and that several completed i surveillances were missing in numerous packages.
Department did not The Operations procedures. The have any administrative controls for these inspection team concluded that ei.tention is necessary to ensure that these additional procedures are j
4 appropriately controlled and used.
i
! 2.2.2
! Operator Attentiveness and Response to Plant conditions Operators were observed to be prompt in acknowledging all i
annunciators procedures (ARPs and changes in plant conditions. Alarm response Operators werewere used when uncommon the alarms were equipment annunciated. operator i
p)rompt to dispatch plant (PEOs) the to respond control room.
to local conditions when an alarm was received in Observation of responses to specific
' annunciators included: 1)
} which excitation required cabinet, sending a (PE0 to the Unit 1 turbine / generator" Genera and (2)
- Trouble," which required that
" Hydrogen Stator Cooling System the turbine building j.
! dispatched to the local alarm panel for the cooling system.PE0Each be response was proper and in accordance with the ARP.
On August 7, 1990, Unit 2 Operations
, Department personnel determined that steam generator (SG) No. 4 narrow range level transmitter (LT-554) was indicating arratically. The instrucent j channel tripped. was declared inoperable and the associated bistables were I bistables, The inspection team observed that, before tripping the j
operator (SRO) the reactor operator (RO) asked the senior reactor
_ identified. to- verify that the proper bistables had been i
tripped bistables OneinSRO- several declined years. to verify this since he had not Another SRO verified that the identified bistables were the proper bistables. ones prior to tripping the
.. These actions were considered conservative in that I similar failure of bistables LT-553.associated with SG No. 3 were tripped due to a '
i If another channel associated with SG No. 3 had l
_ .. _ _ _ ___ __ _ _._ _ ___.~_ _ _ . _ _ _ _ _ _ _ __ __
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inadvertently tripped, the unit would have experienced an indicated ;
low-low SG 1evel trip or a feedwater isolation. :
i The inspection team also reviewed TM 1-90-023 for the repair of a i
SG 1evel transmitter (1LT-503) and the coordinated effort to remove tr.a Unit 1 component cooling water (CCW) Pump 1 for repair. Both .
j of these examples indicated that the Operations Department and
! other departments worked well together to accomplish the necessary
] task.
5 shift superintendents and support shift supervisors frequently t i conducted plant tours. However, the unit shift supervisors seldom
! toured the plant. Although required by the operations Department ;
- administrative procedures, plant tours by USSs did not always ;
- appear to be feasible or practical because of work demands in the i control room. Additionally, discussions with operators indicated that plant managers almost never conducted backshift plant tours.
) The inspection team accompanied PEos on several building tours
{ during routine rounds. Generally, each PEO was knowledgeable and
, conducted a detailed tourt however, specific concerns regarding one j tour.are discussed in section 2.2.6 of this inspection report.
i The inspection team also noted that the plant equipment status was
- noted in the control room logs and, when appropriate, LCO logbook j entries reflected the status of Ts-related equipment.
The inspection team observed activities in the shift j superintendent's (ss's) office and noted two minor examples of administrative errors. These were:
- 1) Two limiting condition for operation (ICO) forms were numbered
- 1-90-564. However, each was applicable to different sections
! of the TS. One of the Lcos dealt with turbine-driven l
auxiliary feedwater system and the other Lc0 dealt with 1 shutdown rod 15.
i l 2) The operating crew entered an information Ito when boric acid l' storage tank pressure indicator PI-10115 failed its l surveillance. The Lc0 number listed on the form was 2-90-180.
This number did not agree with the number in the 140 log, nor 1,
was the subject matter for 140 2-90-180 the same. The actual LCO number from the Lc0 log was 2-90-221-I. The shift i supervisor corrected the 140 to reflect the correct tracking l
! number.
Through discussions and observations, the inspection team concluded
. that control room personnel were aware of plant conditions, j monitored appropriate parameters, and responded to plant conditions -
l in a satisfactory manner.
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2.2.3 Operations Procedural Compliance The Anspection team performed numerous observations of on-shift i licensed and non-licensed personnel during procedural ,
- implementation. The team observed that personnel adhered to j procedures during implementation. Alarm response procedures were i followed exp1!citly. The team observed the performance of the i following surveillance procedures
- 14000-2, Operations Shift and Daily Iogs
- 14030-1, Power Range Calorimetric Channel Calibration
+ 14220-1, Main Turbine valves Weekly Stroke Test
' + 14410-1, Control Rod Operability Test
- 14445-2, Remote Shutdown Monitoring Instrumentation
- Channel check
- 14546-1, TDAFW Pump Operability Test
- 14600-1, ESFAS Slave Relay and Final Device Train A
- Block Test
- 14616-2, SSPS Slave Relay K609 Train A Test Safety Injection j
- 14618-1, SSPS Slave Relay K610 Train A Test Safety i Injection 3
- 14618-2, SSPS Slave Relay Train A Test Safety Injection
- 14622-2, SSPS Slave Relay K615 Train A Test Safety l Injection
.
- 14803-1, CCW Pumps and Discharge Check Valves Inservice 3 Inspection j
- 14905-1, RCS Leakage Calculation
! + 14905-2, RCS Leakage calculation
+ 14915-1, Special Condition Surveillance
- 14915-2, Special Condition Surveillance
!
- 14980-2, Diesel Generator Operability Test
- 24670-1, Waste Liquid Effluent Process Monitor 1RE-0018
. ACOT and Channel Calibration l
- 24670-2, Waste Liquid Effluent Process Monitor 2RE-0018
, ACOT and channel Calibration l The inspection team did not identify any deficiencies or concerns l
with respect to the performance of these procedures. i l
2.2.4 Shift Communications '
1
' Communications within the operat'ons Departaent and between l operations personnel and other groups were gesterally adequate.
However, on some occasions communications could have been more effective. On August 8, 1990, a high-radiation alarm was received on the SG No. 4 steam line. Apparently, during shift turnover, j 1
control room personnel had been told that a source check was to be J l
performed during the shifts however, several hours into the shift, 2 the technician failed to notify the control room before beginning the test. On another occasion, a Unit 2 unit shift supervisor !
- repeatedly acknowledged the receipt of information directed to him j
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j by just looking up at the informant. During the performance of a j surveillance test, the reactor operator had to repeat the j information before the USS acknowledged verbally that he had j received the information. In one instance, when the reactor i operator repeated that he was about to trip a histable, the USS j appeared irritated, but did respond by stating that he understood i that a bistable was about to be tripped. Though communications l could be improved, the inspection team concluded that .
j communications had been adequate during this activity.
i f The inspection team observed that the control room and PEOs i maintained continuous communications via headsets during valve l 2anipulations for removing the heater drain tank 1B high-level dump i valve from service for maintenance. This activity required close coordination between the control room and PEOs at two different locations in the turbine building. The team concluded that the j activity was properly coordinated and appropriate communications vere defined and properly executed.
I
! The inspection team routinely attended shift briefings and observed '
i shift turnovers during the inspection period. On August 10, 1990, l during the 0700-hour shift briefing, the team observed that some ,
i personnel were standing in the hall. Although these people could not hear what was being said, they signed the attendance sheet.
After the team identified this concern to the shift superintendent,
- the situation improved.
The shift turnover meetings tended to be concise and informative.
e The discussion involved plant and equipment status as well as
{ descriptions of planned major evolutions and work activities. The i shift turnover meetings of reactor operators, unit shift l supervisors and shift ruperintendents gave these employees j sufficient information on plant status before the oncoming shift ,
assumed its duties. These turnovers involved control board walkdowns, review of appropriate logs, and discussions.
l The inspection team also attended the 0715-hour supervisor meetings. At these meetings, supervisors discussed such work :
! activities as maintenance and testing. The inspection team !
j determined that the meeting adequately informed the various group l supervisors of required support for scheduled and emergent !
activities. 6
! The inspection team was informed by the shift superintendent, and j -later confirmed by the operations manager, that the shift briefings i i are viewed as being mini-safety meetings. Section 4.5.1 of Operations Procedure 00250-C, " Safety Committee and General Safety Meetings," stated that mini-safety meetings will be held by each department, section, team, discipline, and so forth, on a bi-weekly
. basis. However, three PEOs assigned to the Operations Department
! for at least two years indicated that no safety meetings have been ,
held. The only items they could remember being addressed concerning ;
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4
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- personnel safety were infrequent statements such as, "Be careful 2
out there," and, " Wear your hard hats."
! The inspection team concluded that the Operations Department was
! not properly fulfilling the administrative requirement for !
! performW periodic mini-safety meetings and that this was an
] operational weakness.
l 2.2.5 Corrective Actions for Deficiencies and Equipment j Failures i
l The inspection team observed on-shift crew actions during equipment malfunctions and failures. The team noted that the shift crew took prompt actions to identify equipment problems to the appropriate
- departments for corrective actions. The operating crews monitored .
3 operating conditions associated with the malfunctioned equipment ,
i and used backup instrumentation, measurements, and readings, as
- necessary, to verify plant parameters and conditions. The team observed the on-shift crew during times when components had failed i or were not functioning properly. For those instances, the Uss or
! RM made the determination whether the component was operable. The i team did not observe any instances of the on-shift crew making an
! improper operability determination. No deficiencies were noted.
1 The inspection team noted that there have been several recent
- instances of SG narrow range level instrument failures. Work 3
request tickets (WRTs) were written to c:$rrect the problems; i however, the root cause of the failures does not appear to have
- been identified as evidenced by the continuing problems. Further l action is needed by the licensee to identify and correct the root
- cause of the failures.
2.2.6 Performance of Plant Equipment Operators The inspection team accompanied plant equipment operators (PEOs) l during portions of their routine rounds. In each instance, the
- tema determined that the PEOs were knowledgeable about plant systems, knew the location of major components, and conscientiously
- performed their duties. In some instances, the team determined i that the PEO performed a detailed tour. However, in other i instances, inconsistencies were evident in the level of detail to i
which the general area inspections were performed. Instructions on performing a general inspection while performing rounds were contained in Section 3.3 of Operations Procedure 10001-C, "Logkeeping." This section references Table 1 of the procedure for
- inspection criteria when performing rounds and identifies it as the i minimum criteria to which an operator must inspect his assigned l area. Table 1 of Operations Procedure 10001-C is a 3-1/2-page list
+
of items which includes such instructions as:
- Pipe hangers intact Insulation installed J
. i 32
. Noise and vibration levels normal
. Hose stations properly equipped
. Radiation areas clearly identified
. Hold tags attached !
. Temporary modifications clearly marked
. Equipment locked with breakaway locks closed / locked as required
. Operator aids properly approved j
. Electrical enclosure covers installed with all fasteners engaged
. Bearing temperat"re, vibration, and noise normal
. Suction, discharge, and recirculation flow path available
. Ground straps connected Inconsistencies observed by the inspection team included such items as:
- 1) One PE0 reset every thermal overload on each breaker.
- 2) One PE0 failed to check any hose stations for proper equipment.
- 3) One PE0 failed to identify missing instrument tubing supports
! and bent tubing during their tours.
- 4) Not all operating rotating equipment was touched to sense i temperatures and vibration.
Discussions with a USS, SS, and the operatiens manager indicated
- that Table 1 is meant to be guidance. However, this appears to be in conflict- with Section 3.3 of 10001-C which seems to impose l
, minimum criteria. The inspection team was concerned that the ,
actual expectations involving minimum acceptable performance of general inspections were not well defined in procedures nor, in *
- some instances, by on-the-job training (OJT) as described in !
Section 2.1.3.2 of this inspection report. This was identified as a potential weakness in the licensee's program.
l 2.2.7 Material Conditions The team inspected various plant buildings and accompanied licensed '
and non-licensed shift personnel on their rounds in order to assess l
33 the overall status of the plant and equipment. During these tours, the team made several observations concerning the status and condition of equipment. observations included the following:
- 1) Excessive amounts of oil on and around EDG $2A.
- 2) Standing water on the floor in the Unit 1 turbine-driven auxiliary feedwater pump room due to excessive leakage past the pump seals. Although a WRT was written to identify the problem in November 1989, the problem has not been corrected.
A second WRT was written in June 1990, which stated that the j leakage had gotten worse. l
- 3) There appeared to be a distinct separation in responsibilities i for equipment that belonged to the Operations Department and I equipment that was the responsibility of other departments or groups (e.g. , Chemistry, Radwaste, and Instrumentation) . PEOs indicated that they would monitor equipment belonging to another department, but the maintenance and operation were the responsibility of the other departments and not the Operations Department. This was raised when the team asked the PE0 to explain why missing instrument tubing supports and bent tubing were not identified by PEOs during their tours.
- 4) Iabels inside breaker panels only have breaker numbers marked; and devices (equipment energized by the breakers) are not designated. To help operators, the Operations Department had to add a cross-reference between the breaker number and the j and device on the inside of the panel doors. In general, the i non-safety-related panels did not have any designations.
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- 5) on Units 1 and 2, there were several instances of pressure
! boundary leaks at valve bonnet flanges with a buildup of boric acid precipitate. This boric acid buildup had resulted in i surface corrosion.
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Despite these deficiencies, the inspection team concluded that the material condition of the facility was acceptable, f 2.2.8 Event Classification and Notifications
- on August 8, 1990, at 0738 hours0.00854 days <br />0.205 hours <br />0.00122 weeks <br />2.80809e-4 months <br />, the control room received a
. Notification of 'an Unusual Event (NOUE) from the Savannah River site (SRS) involving a Phase I security condition. The emergency notification system (ENS) communicator recorded the message as required. The shift superintendent (SS) promptly notified the VEGP The SS informed the inspection team that if ;
- on-call duty manager.
l a potential radiological release condition had existed at the SRS, !
he would have made a courtesy " red phone" report to the NRC. At 2002 hours0.0232 days <br />0.556 hours <br />0.00331 weeks <br />7.61761e-4 months <br />, a second message was received from SRS which stated l- that the NOUE had been cancelled. The SS notified off-site management of the cancellation.
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34 On August 10, 1990, at 0310 hours0.00359 days <br />0.0861 hours <br />5.125661e-4 weeks <br />1.17955e-4 months <br />, assigned (CAS). patrol duty, was found asleep in the central alarm station Upon notification, the SS and Unit 1 Unit shift superviso r referred The on-dutytomanager the notification procedure to determine reportability was notified. .
.my not be reportable because of the specific circumstancesThere The was d SS was - informed that management would get back to him. .
SS believed that0407 hours, the SS had not been contacted byAt managemen the event met .
Since the phone" report, he notified the NRC of the event.the criterion of a 1-hour " red On another occasion, the inspection team observed that th notified drug the NRC e SS had positive test ofduty officer upon a non-licensed discovery of a confirmed supervisor. The made as required by the VEGP fitness for duty program. report was The inspection team concluded that the licensed operators had notifications.
appropriately classified the events and performed the proper "4 n EXIT INTERVIEWS The 1990,inspection with those persons scope and findings indicated in Appendix were summarized
- 1. son Augu 7,
t1 inspection The inspection team described results. the areas inspected and discussed The licensee a in det e
il th comments. made numerous materials inspection.
providedThe licensee did not identify as proprietary any of thedissen to or reviewed by the inspector during this i
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i APPENDIX 1 PERSONS CONTACTED (continued)
- NRC Employees Who Attended Exit Interview R. Aiello, Resident Inspector - Vogtle B. Sonser, Senior Resident Inspector - Vogtle M. Branch, Senior Resident Inspector - Watts Bar i K. Brockman, chief, Reactor Projects Section 3B - RII R. Carroll, Project Engineer - RII L. Garner, Senior Resident Inspector - Robinson N. Huneauller, Reactor Engineer - NRR ,
i D. Matthews, Project Director - NRR J. Milhoan, Deputy Regional Administrator - RII L. Reyes, Director Division of Reactor Projects - RII 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
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< LIST OF ACRONYMS AFD Axial flux difference i AFW Auxiliary feedwater l
, ALARA As-low-as-reasonably achievable !
ARP Annunciator response procedure CAS Central alarm station i
! CCW Component cooling water i CFR Code of Federal Regulations f CIV Containment isolation valve l DC Deficiency card DCP Design change package
- DNB Departure from nucleate boiling l i DRP Division of Reactor Projects l ECCS Emergency core cooling system EDG Emergency diesel generator l ENS Emergency notification system j ESF Engineared safety features :
ESFAS Engineered safety features actuation system FSAR Final Safety Analysis Report GL Generic letter l GPC Georgia Power Company GPM Gallons per minute l
ILRT Integrated leak rate test ,
kV Kilovolt
- LCO Limiting condit3on for operation LER Licensee Event Report LLRT Local leak rate test
NPF Nuclear power facility
- NRC Nuclear Regulatory Commission NRR Nuclear Reactor Regulation -
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NSCW Nuclear service cooling water OI Office of Investigations ,
OJT On-the-job training i 4
PEO Plant equipment operator
- PM Preventative maintenance PRB Plant Review Board i psig Pounds per sguare inch gauge QA Quality Assurance RCS Reactor coolant system j RHR Residual heat removal l RII Region II Office j RO Reactor operator ;
SG Steam generator SONOPCu Southern Nuclear Operating Company ;
SRO Senior reactor operator j i
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APPENDIX 2 LIST OF ACRONYMS (continued)
SRS Savannah River site SS Shift superintendent ,
SSPS Safety System Parameter System TDAFW Turbine-driven auxil.iary feedwater TM Temporary Modification ,
TS Technical Specification URI Unresolved item USS Unit shift superintendent :
VEGP Vogtle Electric Generating Plant !
l VIO Violation WRT Work request ticket j i
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