IR 05000271/1989009
| ML20248E018 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee File:NorthStar Vermont Yankee icon.png |
| Issue date: | 07/31/1989 |
| From: | Blough A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20248E017 | List: |
| References | |
| 50-271-89-09, 50-271-89-9, NUDOCS 8908110202 | |
| Download: ML20248E018 (25) | |
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U.S. NUCLEAR REGULATORY COMMISSION
< REGION.I
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License 'No. ')PR-28 Docket No.
50-271-
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Licensee:
Vermont Yankee Nuclear Power Corporation
RD 5, Box 169 Brattleboro, Vermont- '05301
. Facility:
1 Vermont Yankee Nuclear Power Station Inspection At: Vernon, Vermonty
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Inspection. Conducted: May 31 - July 17, 1989 Inspectors:
Geoffrey E.. Grant, Senior Resident Inspector
. Michael Kohl, Acting Resident Inspector C. Woodard, Reactor Engineer ~
Approved by:
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~N A. R. Bloughpief, Reactor Projects Sect' ion 3A Date Inspectix. Summary: Inspection on May 31 - July 17,1989 (Report No. 50-21.7/89-09)-
. Areas Inspected: _ Rcutine inspection on daytime and backshifts by two resident
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inspectors of: ni:tions on previous inspection findinos; operational safety; s
security; plant operations; maintenance and surveillance; engineering support; licensee event-reports; licensee response to NRC initiatives; and, periodic reports.
Results:
1.
. General Conclusions on Adequacy, Strength or Weakness in Licensee Programs The licensee response to indications of fuel failure was excellent.
Prompt'and effective mana pient involvement was evident. Conservative actions including a power reduction to 90% were prudent, timely, and demonstrated good engineering judgement. The decision to return to full power was bared or a sound engineering assessment of the probable fuel response. Management' oversight anc' concern with safe plant. operations were evident _in all aspects of this event (Section 6.1).
Licensee root cause determinations have been continually improvinc. The evaluation performed on a motor operated valve failure (Section 7.2) was very good. The detail, thoroughness, and timeliness of that effort demonstrated an effective approach to failure mechanism assessment.
2.
Violations
o The licensee identified a design deficiency in the residual hest removal
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. (RHR) service water (SW) system that rendered the system susceptible to a single mor', failure. The failure of the design control program to prevent 8908110202 890801 cr.
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this deficiency was considered a violation of 10 CFR 50 Appendix B re-quirements Licensee prompt corrective action remedied the design de-ficiency. No Notice of Violation is being issued (Section 8.1).
3.
Unresc'ved Items Two unresolved items were identified during this inspection period:
Review of corrective actions to address vendor recommended motor
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operator valve cveling limitations (Section 7.2).
Review results of licensee design control task force findings and any
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long-term corrective actions (Section 8.1).
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TABLE OF CONTENTS PAGE 1.
Persons Contacted.....................................................
I 2.
S umma ry o f Fa c i l i ty Ac ti v i ti e s.......................................
3.
Status of Previous Inspection Findings (IP 92702*)...................
3.1 (Closed) Varesolved Item 88-20-02: Actions to More Effectively Implement TS 4.13.E.1 Surveillance Requirements...............
3.2 (Closed) Unresolved Item 88-10-01: Improvement of Fire Protection System Operability Determinations.................
3.3 (Closed) Violation 88-14-01: Failure to Establish a TS Required Firewatch.....................................................
3.4 (Closed) Unresolved Item 88-08-02: Improvement of Fuel Oil QA Program.......................................................
4.
Operational Safety (IP 71707,71710).................................
4.1 Plav. Operations Review...........................
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4.2 Safety System Review............
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4.3 Feedwater Leak Detection System.................................
4.4 Inoperable Equipraent.............
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4.5 Review of Tempora ry Modi fi cati on s..............................
4.6 Review of. Switching and Tagging Operations......................
4.7 Operational Safety Findings...................
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Security (IP 71707)..................................................
5.1 Observations of Physical Security.............................
6.
Plant Operations (IP 71707,93702)...................................
6.1 Failed Fuel Indications.............................
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7.
Maintenance / Surveillance (IP 71710,40500,61726,62703).............
7.1 UPS-1A Inoperability.........................
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7.2 RCIC System Inoperability.......................................
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Engineering Support (71707, 35502, 37700, 40500).....................
8.1 RHR Service Water Design Deficiency........
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9.
Licensee Event Reporti ng ( LER) (IP 93702)..........................
9.1 LER 89-06.....................................
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Table of Contents
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PAGE 10. Review of Licensee Response to NRC Initiatives (IP 35502)............
15-10;1 tmergency Diesel Generator (EDG) Fuel 011 (TI 2515/100).........
11. Re"iew of Periodic and Special Reports (IP 71707)....................
12. Management Meetings (IP 30703)........................................
12.1 Routine.........................................................
12.2 Licensee / Region I Management Meeting.............................
ATTACHMENTS Attachment A: Meeting Notice, June 15, 1989 Attachment B:
List of Attendees Attachment C:
Figure 1 - RHRSW-89B Power Supply
- The NRC Inspection Manual inspection procedure (IP) that was used as inspec-tion guidance is listed for each applicable report section.
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DETAILS 1.
Persons Contacted Interviews and discu nions were conducted with members of the licensee staff and. management during the report period to obtain information per-tinent'to the areas inspected.
Inspection findings were discussed peri-
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odically with the management and supervisory personnel listed below.
Mr. P. Donnelly, Maintenance Superintendent l
- Mr. R. Grippardi, Quality Assurance Supervisor
Mr. S. Jefferson, Assistant to Plant Manager l
Mr. J. Herron, Ooerations Supervisor Mr. R. Lopriore, Maintenance Supervisor Mr. R. Pagodin,' Technical Services Superintendent i
- Mr. J. Pelletier, Plant Manager Mr. R. Wanczyk, Operationi Superintendent
- Attendee at post-inspection exit meeting conducted on July 27, 1989.
2.
Summary of Facility Activities Vermont Yankee Nuclear Power Station (VYNPS or the plant) continued full power operations during this report period with a few excep;.icns.
Throughout the period, short term scheduled power reductions to 80-95%
full power were conducted weekly to perform routine surveillance on con-trol rod drives, main turbine and bypass valves. On June 3 power was re-duced to 68% for a main steam isolation valve surveillance and rod pattern exchange. Return to full power operation was accomplished on June 4.
Subsequently, elevated off gas radiation levels were detected and power was reduced to 90%-(see Section 6.1).
A slow-ramp power increase (0.5%
per four hour period) was commenced on June 12 with full power reached on June 15. Power was reduced to 96% for a short period on June 24 and 25 to facilitate work on the off-site transmission system. On July 8 power was reduced to 37% to support recirculation pump motor generator brush re-placement. Full power operaticn was restored on July 9.
Licensee noti-fications to the NRC were made in accordance with 10 CFR 50.72 on June 5
.for the elevated off gas levels and power reduction, on June 7 for reactor core isolation cooling (RCIC) system inoperability, and on June 28 for a RCIC system inoperability.
3.
Status of Previous Inspection Findinos 3.1 (Closed) Unresolved Item 88-20-02: Actions to flore Effectively implement TS 4.13.E.1 Surveillance Requirements. This issue ad-dressed deficiencies in the licensee implementation of technical specification (TS) 4.13.E.1 fire protection surveillance require-ments. Specifically, OP 4020, " Surveillance of Fire Protection r
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Equipment," was found to be deficient in a number of areas.
Imple-mertation of OP 4020 surveillance activities was also found to be l
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In LER 88-15 the licensee committed to revision of OP 4020 to clarify surveillance activities. The licensee developed and issued OP 4019, " Surveillance of Vital Fire Barriers" on April 1, 1989.
Review of OP 4019 indicates that it is a significant improve-ment over the portion of OP 4020 that it replaces. The procedure contains detailed information for surveillance performance. The en-hanced procedure was used during the 1989 outage and proved to be more effective in implementation of surveillance requirements. The licensee intends to further implement refinements and improvements to this program during revision of the remaining portions of OP 4020.
This item is closed.
3.2 (Closed) Unresolved Item 88-10-01: Improvement of Fire Protection System Operability Determinations. This issue addressed a licensee identified violation for failure to post a TS-required fire watch when portions of a vital fire suppression system were inoperable. An adjunct to this issue was a deficiency related to OP 4020, " Surveil-lance of Fire Protection Equipment." Procedure OP 4020 was revised and issued February 10, 1989. As noted in Section 3.1 above, further improvements to OP 4020 were made on April 1, 1989 and more are planned for completion by the end of 1989. These actions address this aspect of the issue.
A similar. deficiency in this area was identified in IR 88-14 and was issued as a violation (88-14-01). The corrective actions developed to respond to 88-14-01 adequately address the concern identified in 88-10-01. These actions are described in Section 3.3 of this report and form the basis for closure of 88-10-01.
This item is closed.
3.3 (Closed) Violation 88-14-01: Failure to Establish a TS Required Firewatch. This violation addressed a repetitive f ailure of the lic-ensee to establish a firewatch when TS required fire protection equipment was inoperable. The licen.ee responded to the violation in a letter dated December 2,1988 which was reviewed and found satis-factory in IR 88-20 of January 24, 1989.
Long term training program changes remained to be accomplished in order to close out this issue.
The inspector reviewed licensee training module LOR-89.1-401, "Ap-pendix R Overview and Fire Protection Systems." The module ade-quately covered systems and associated technical specifications. The module was incorporated into licensed operator training and shift engineer training and was covered in 1989 cy le 1 requalification training. The effectiveness of this training in ensuring understand-ing and correct implementation of fire protection system TS require-ments will continue to be assessed during routine inspections. This item is closed.
3.4 (Closed) Unresolved Item 88-08-02: Improvement of Fuel Oil QA
Program. This item represented a number of issues relating to the
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quality of the emergency diesel generator (EDG) fuel oil system in-cluding fuel oil sampling, fuel oil analysis and system preventive
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maintenance. The licensee effectively addressed each of these areas
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by procedure and equipment-modifications. As described in Section
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'10.1 of this report each of the improvements was reviewed-and con-sidered adequate. This item is closed.
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Operational Safety
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'4.1 Plant Operations Review.
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The inspector observe;d' plant operations during regular and backshift tours of the following areas:
' Control Room Cable Vault Reactor Building Fence Line (Protected Area)
Diesel Generator Rooms Intake Structure
' Vital Switchgear Room Turbine Building Control room instruments were observed for correlation between chan-nels, proper. functioning, and conformance with technical specifica-tions. Alarm conditions in effect and alarms received in the control room were reviewed and discussed with the operators. Operator cware-ness and response to these conditions were reviewed.
Operatccs were found cognizant of board and plant conditions.
Control ream and:
shift manning were compared with technical specificatica require-ments.
Postir.g and control of radiation, contaminated and high radt-ation areas were inspected. Use of and compliance with radiation-work permits and use of required personnel monitoring devices were checked. Plant housekeeping controls were observed including control of' flammable and other hazardous materials.
During plant tours, logs and records were reviewed to ensure ccmpliance with station proce-dures, to determine if entries were correctly made, and to verify.
correct communication of equipment status. These records included various operating logs, turnover sheets, tagout and jumper logs, and potential reportable occurrence reports.
Inspections of the control room were performed on weekends and backshifts including June 1,6,15 and July 13, 1989.
" Deep backshift" inspections were conducted as f>llows:
Date Time June 1 9:00 p.m. - 11:30 p.m.
June 6 9:00 p.m. - 11:30 p.m.
Jur:e 11 9:30 a.m. - 6:15 p.m.
July 4 11':00 a.m. - 7:45 p.m.
July 13 9:00 p.m. - 11:30 p.m.
Operators and shift supervisors were alert, attentive and responded appropriately to annunciators and plant conditions.
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4.2 Safety System Review The emergency diesel generators, reactor core isolation cooling, core spray, residual heat removal, standby gas treatment, residual heat removal service water, safety related electrical, and high pressure coolant injection systems were reviewed to verify proper alignment and operational status in the standby mode.
Th! veview included verification that (i) accessible major flow path valves were cor-rectly positioned: (ii) power supplies were energized, (iii) lubri-cation and component cooling was proper, and (iv) components were operable based on a visual inspection of equipment for leakage and general conditions. No violations or safety concerns were identi-fied.
4.3 Feedwater Leak Detection System Status The inspector reviewed the feedwater leakage detection system and the monthly performance summary provided by the licensee in accordance with VYNPC letter FVY 82-105.
The licensee reported that, based on the leakage monitoring data for June 1989, there were no deviations in excess of 0.10 from the steady state value of normalized thermo-couple readings. The inspector had no further questions in this area.
4.4 Inoperable Equipment Actions taken by plant personnel during periods when equipment was inoperable were reviewed to verify: technical specification limits werc met; alternate surveillance testing was completed satisfac-torily; and, equipment return to service upon completion of repairs was proper. This review was completed for the following items:
Date Out Date In System 5/31 6/1
"B" Reactor building venti 1 on radiation monitor 6/5 6/6
"A" UPS 6/5 6/8
"B" SBGT 6/7 6/8 RCIC 6/7 6/10
"A" UPS 6/28 6/28 RCIC 6/28 6/28
"B" Cuatainment spray 7/10 7/11 Ames Hill NOAA transmitter 4.5 Review of Temporary Modifications Temporary modifications were reviewed to verify that controls estab-lished by Ap 0020 were met, no con'lict with technical specifications were created, safety evaluations were prepared in accordance with 10
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i CFR 50.59 if required, and requests were reviewed and approved prior to installation.
Implementation offthe requests was reviewed on a-sampling basis. The following requests were reviewed:
89-035 -' June 26: Use'of helium leak testing e gipment.
t 89-036 - June 21:
Reactor water clean-up non-regenerative heat
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exchanger high temperature trip 89-038 - June 28:
Modify RHRSW-89B. instrument power supply
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Additionally, the licensee closed out temporary modifications during-the report period. These were reviewed by the inspector for com-pleteness and adequacy of system restoration.
4.6 Review of-Switching & Tagging Operations The switching and tagging log was reviewed and tagging activities were inspected to verify plant equipment was controlled-in accordance-with the requirements of AP 0140, Vermont Local Control Switching Rules.
Switching and tagging orders were reviewed for the majority of inoperable equipment repairs identified in Section 4.4.
4.7 Operational Safety Findings Licensee' administrative control of off-normal. system configurations by the use of temporary modifications and switching and tagging pro-cedures, as reviewed in Sections 4.5 and 4.6, was in compliance with procedural instructions and was consistent with plant safety. Back-shift inspections have consistently found operators to be alert and attentive.
Operations are routinely. conducted in'a professional manner in an atmosphere of quiet control and competence. Overall plant cleanliness and material conditions continue to be good. The number and durations of periods of inoperable safety-related equip-ment were minimized by licensee maintenance practices and planning.
No deficiencies were' identified in licensee operations associated with the reviews covered in Section 4.
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Security 5.1 Observations of Physical Security Selected aspects cf plant physical security were reviewed during regular and backshift hours to verify that controls were in accord-ance with the security plan and approved procedures. This review included the following security measures: guard staffing; vital and protected area barrier integrity; maintenance of isolation zones; y
and, implementation of access controls, including authorization, badging, escorting, and searches. No inadequacies were identified.
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o 6.
Plant Operations 6.1 - Failed Fuel Indications
.On June 5,1989 with the reactor at 100% full power, control room operators noted a higher than normal radiation level in the off gas monitoring system. An off gas sample was obtained at 10:21 a.m. and indicated an increase in activity:to 4190 uc/sec. Normal off gas levels had previously been 1000-2000 uc/sec.. Subsequent confirmatory measurements indicated off gas activity was continuing to trend up-ward vith sample results of 15,100 uc/sec, 24,000 uc/sec, 35,000 uc/sec and 39,800 uc/sec taken at 2:00 p.m., 4:00 p.m., 6:00 p.m. and'
9:00 p.m. respectively.
Concurrent increases in radiation. levels of associated systems also occurred.
The steam jet air ejector (SJAE)
radiation levels increased from 40 mr/hr to approximately 100 mr/hr as measured by installed detectors. The radiation levels at the in-let to the advanced off gas (A0G) guard bed increased from 2000 cpm to approximately 400,000 cpm.
The plant stack radiation monitor.
showed a slight increase above the normal level of approximately 60 cpm.
The off gas levels remained well below the-technical specification 3.8.K.1 limit of 160,000 uc/sec. Reactor vessel isotopics for' dose equival.ent I-131 at approximately 7E-5 uc/gm remained well below the technical spec:fication 3.6.B.1 limit of 1.1 uc/gm.
Environmental release rctes, calculated by the licensee based on the methodologies in the Offsite. Dose Calculation Manual (ODCM) were very small and remained several orders of magnitude less than technical specifica-tion 3.8.E.1 limits of 500 mrem /yr (whole body) and 3000 mrem /yr (skin).
Although the elevated off gas levels occurred while the plant was operating steady-state at 100% full power, the increases followed by about 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> a scheduled rod pattern exchange on June 3,1989.
The exchange consisted of a power reduction to 80%, rod pattern adjust-ment, and return to 100% full power following pre-conditioning (PCIOMR) recommendations.
Full power was attained at 2:00 a.m. on June 4, 1989. Operators noted small off gas level spikes during the rod pattern exchange, but an off gas sample analytis at 11:22 a.m. on June 3 showed a level of 2010 uc/sec which was roughly consistent with previous levels. With off gas levels continuing to trend upward on June 5, the licensee conserve ively reduced reactor power to 90%
in an cffort to stabilize the release rate.
Off gas levels immedi-ately began decreasing and within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> had reached an equilibrium level of 16,000-18,000 uc/sec.
The licensee established an investigation team on June 6 to review the event and determine any identifiable root causes. The licensee determined that, pending review of the team conclusions and fuel ven-dor information, power would be maintained at 90%.
The team per-formed an extensive investigation of the event which included several l
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discussions with the fuel vendor.
In addition to data collection, reduction and analysis, the team addressed several related' concerns including:- guidance to operators for conducting recommended core power changes, assessing the long-term effects of maintaining power at 90%, examination 'of the possibility of calculational problems as-s'ociated with the rod pattern exchange, verification of the correct-ness of the PCIOMR limits, and examination of the rod pattern ex-change implementation.
The team found no errors in either the pre-paration for or execution of the rod pattern exchange. The team con-cluded, as had previously been surmised, that the cause of the in-creased off gas levels was most likely a small failure (s) of fuel pin cladding. This was primarily based upon the correlation of the in-crease with a core flux shape change and the mixture of isotopics present-in the off gas. A number of potential causes for the clad-ding failure were analyzed. Although a conclusive determination is not possible without direct observation of the leaking fuel, the cladding failure appears to have been induced by pellet-clad inter-action (PCI). This conclusion is consistent with the observed be-havior of off gas levels and the slope of the isotopic mixture pre-sent in the off gas.
Based on team recommendations, operating guidelines were changed tc iimit core power changes to one percent per three minute' period.
zUpon review of the event, investigation team findings and discussions with the fuel vendor, the licensee determined that a return to 100%
full power was acceptable and appropriate.
Following scheduled sur-veillance testing, on June 12 the licensee commenced a slow power ramp-to 100%.
Power increases were limited to 0.5% per four hour
. period.
Standing and night operation orders were developed to ensure a controlled power increase was maintained and appropriate super-visory control exercised if unanticipated increases in off gas levels were observed. The power increase was successfully completed without incident and off gas levels remained relatively constant in the 16,000-20,000 uc/sec range. Off gas levels remained in this range until July 8 when a scheduled power reduction to 40% full power was performed in order to rebrush the recirculation pump motor generator sets. The downpower' caused a spike in.off gas levels to approxi-i mately 60,000 uc/sec. Upon return to full power, off gas levels re-turned to approximately 20,000 uc/sec. The spike in levels assoc 1-ated with the power reduction was probably due to the reactor pres-
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l sure drop which accompanies a power reduction.
The pressure drop would have increased the pressure differential seen by the failed pin (s) (internal pin pressure relative to reactor pressure) allowing additional fission gases to be released. At the end of the inspec-
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tion period, off gas levels had reached an equilibrium value of ap-
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proximately 20,000 uc/sec.
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Findings Licensee response to this event was excellent.
Internal and external communications were effective and prompt. The licensee decision to reduce power to 90% on June 5 was conservative and prudent. This action allowed the off gas release rate'to stabilize at an acceptable
. level while providing time for licensee arP < sis of the event. The licensee decision to remain at 90% fuis power,;ending a thorough analysis and review was also conservative and demonstrated applica-tion of good management and engineering judgement. Analysis of potential event causal factors was timely and complete.
Involvement of offsite resources including the fuel vendor was well managed. The subsequent decision to return to full power was based on a sound engineering assessment of the probable fuel responu. The power in-crease was performed in a controlled and conservative manner. Man-agement oversight was evident in all aspects of the event, analysis, review and strategy formulation.
Inspector review of available data indicates that the fuel cladding defect may have existed prior to the rod pattern exchange. Off gas levels upon startup from the refueling outage were 1500-2000 uc/sec.
This level exceeded the 300-600 uc/sec range observed following pre-vious outages.
The rod pattern exchange shifted the core power dis-tribution, possibly causing accelerated release from existing clad-ding defects. Although a rapid increase in off gas levels following the rod pattern exchange was not anticipated, no technical specifi-cation limits were approached.
The licensee continuing response to the elevated off gas levels will be assessed during subsequent routine inspections.
Reviews will con-tinue of plant status to confirm that plant operation remains within license requirements. Additionally, licensee preparation for and conduct of future power maneuvers and rod pattern exchanges will be reviewed on a sampling basis to ensure potential plant responses are effectively anticipated.
7.
Maintenance / Surveillance 7.1 UPS-1A Inoperability At 6:35 a.m. on June 5 the uninterruptible power supply (UPS) 1A was declared inoperable.
This was a result of a spurious loss of voltage indication on the 9-3 panel and loss of indication for valves RHR-25A and RHR-27A. The licensee, with assistance from vendor technica'l representatives, performed extensive diagnostic testing of the unit.
Testing included comparison of existing circuit cards with new or factory rebuilt cards under a variety of induced trip situations.
The licensee monitored selected points using a multipen chart recor-der and a video camera. The troubleshooting techniques used included infrared thermography to detect temperature abnormalities in various i
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circuits and components. The testing and troubleshooting-efforts did not identify a definite fault or malfunction.
However, through the use of infrared spectrometry equipment, one component was discovered to be heating more rapidly than other components after being er9r-gized. Although this condition was not always causing a UPS tr^1, it y
could have caused intermittent or spurious trips.
Based upon the discrepancy, the card was replaced. The circuit board vas thermo-graphed again, and the same component on the new card exhibited uni-form heating characteristics.
Based on.this, the new circuit board was permanently installed and the removed circuit board was sent to the vendor for detailed analysis.
The system was restarted and ex-hibited normal system operation. The system was post-maintenance tested satisfactorily and returned to service at 12:55 p.m. on June 10.
The licensee responded to the UPS trips in a controlled, technical manner.
Early vendor expertise was enlisted. Troubleshooting was performed in accordance with procedures and technical manuals. All operational and maintenance evolutions relating to the UPS repair were accurately and thoroughly documented in MR 89-2267.
The licen-see is in the initial planning stages for installing e temporary modification for additional monitoring of UPS-1A for any future
spurious trips.
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The UPS system continues to experience periods of unavailability.
Due to the apparent random nature of UPS component failures, and a less than optimal system application, licensee efforts to improve system reliability and availability have been less than fully effec-tive.
The licensee has recently completed a feasibility study to examine potential options to the existing system design.
The initial options include eliminating UPS, replacing the existing UPS with a new UPS, refurbishing the existing UPS, and installing a new UPS con-figuration. The licensee is currently reviewing these options. The
inspectors will continue to monitor the UPS system performance during routine inspection activities. The inspectors had no further ques-tions.
7.2 Reactor Core Isolation Cooling Syrtem Inoperability
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On June 7, 1989 the reactor core isolation cooling (RFIC) system was declared inoperable while performing procedure OP 4121, "RCIC Valve Operability." During this scheduled monthly surveillance, after the valve had been successfully opened, the breaker for RCIC-21 tripped when valve closure was attempted. A subsequent attempt to close the valve after resetting the breaker was also unsuccessful.
The licen-see declared the RCIC system inoperable and performed the actions required by TS 3.5.6.2.
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Licensee troubleshooting of the valve failure was extensive.
Various electrical checks were performed at the valve breaker enclosure on l
MCC DC-28. Although th; breaker appeared to be satisfactory, a re-placement was installed to verify an electrical fault was not present in the breaker.
Subsequent tests indicated the probable location of s
the fault was at the valve.
The RCIC-21 valve is the outboard dis-
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charge isolation valve and is located in the steam tunnel. The steam i
tunnel is a high ambient temperature and high radiation area. Main-tenance personnel made two entires into the steam tunnel. The first entry was for investigation and valve operator motor removal. The second entry was for motor. replacement and testing. The licensee determined that RCIC-21 operated freely in the manual mode and that the most probable cause of failure was a motor fault.
Performance of OP 5220, "Limitorque Operator Inspection," indicated no problems with the operator or gear train.
Further analysis of the valve motor in-dicated the armature had failed.
The motor was replaced and tested satisfactorily. The RCIC system was returned to operable status on June 8, 1989.
The licensee performed an extensive root cause failure analysis on this maintenance activity.
The motor and operator sere original t
equipment installed in 1971.
The maintenance history for this valve indicates no operator or electrical problems were encountered prior to this failure. Although the valve was repacked during the 1989 outage, the licensee determined that, due to the manual mode freedom of valve movement, repacking was not a contributor to valve failure.
The licensee focused the analysis on the possibility that MOVATS valve testing contributed to the motor failure.
Licensee discussions with MOVATS test personnel, maintenance personnel, and the valve operator vendor indicated a potential link existed between MOVATS testing and the motor failure. The valve had been MOVATS tested during the 1985-86, 1987 and 1989 outages. Typically MOVATS testing requires 10-15 (and sometimes more) valve cycles to verify all tested parameters are satisfactory.
Per the motor operator vendor, the operator for RCIC-21 has a five minute duty cycle limit. That is, the summation of valve stroke times should not exceed five minutes
without a rest period (nominally one hour).
Current vendor guidance
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is to limit valve stroking to one half of the maximum duty cycle prior to a one hour cooling period.
The concern addressed by this
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limit is excessive internal motor heating and consequent insulation breakdown due to repetitive valve operation.
A review of the testing performed on RCIC-21 during the 1989 outage indicated that at a point i
in the MOVATS testing (after several valve strokes) a " hot electrical motor" smell was noted. Subsequent review by maintenance engineering and successful completion of the testing indicated no detectable problem existed with the valve or operator. The licensee initial root cause conclusion was that the RCIC-21 motor failure was age re-lated (end-of-life) with a strong potential for acceleration due to prior instances of reaching or exceeding the operator duty cycle limitation.
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1 Findings This maintenance activity is an example of the licensee's sound ap-proach to performing corrective maintenance and performing post-failure root cause analysis. The maximization of troubleshooting outside of the steam tunnel reduced the potential personnel exposure associated with this maintenance activity.
Planning, set-up, pre-briefing and performance of both steam tunnel entries were very good.
These activities fully supported ALARA principles and minimized per-sonnel exposures.
The root cause analysis was thorough, timely and effective. The potential linkage of MOVATS testing to motor degradation or failure demonstrated both a thorough review and insightful engineering as-sessment. However, failure to adequately incorporate vendor recom-mended valve operator limitations into maintenance control procedures appears to be a weakness. The licensee is reviewing this situation and is developing long-term corrective actions.
Completion and re-view of these actions is an unresolved issue (50-271/89-09-01).
8.
Engineering Support 8.1 RHR Service Water Design Deficiency On June 28, 1989 during an engineering review of portions of the electrical distribution system, the licensee determined that the de-sign of the residual heat removal (RHR) service water (SW) system made the redundant portions potentially susceptible to a single mode of failure and subsequent degradation of capability. The error that was identified was that the power supply to the control instruments-tion for the "B" train RHR heat exchanger SW outlet valve (RHRSW-898)
was powered from motor control center (MCC) 90 which is in the S2 division of the emergency power system. On a loss of offsite power, the S2 division is powered by the
"A" eme.'gency diesel generator (EDG). Thus a loss of offsite power with a failure of the "A" EDG would affect both RHR/SW systems.
In that case, the "A" train of RHR/SW would be totally inoperable due to the power loss to all of its components. The
"B" train of RHR/SW would be rendered inoperable due to the loss of power to the control instrumentation for RHRSW-89B.
Therefore, a single mode of failure could have affected both trains of RHR/SW.
Upon discovery, the licensee took immediate corrective actions to restore redundancy to the RHR/SW system. Temporary modification (TM)89-038 was implemented to change the power source for the RHRSW-898 instrumentation. The power source was shifted to the vital a-c cir-cuit which is part of the S1 ("B" EDG) division of the emergency power system. The vital a-c system is powered by a motor generator which has the capability of being driven by either safety-related a-c or the station batteries. This TM restored the independence of the
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Results of the review indicated that no other similar conditions existed on these panels.
I The licensee traced the most probable origin of this design defi-I ciency.to a plant modification implemented in 1977. A previous change installed two 480 volt uninterruptible power supplies (UPS) to
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support the emergency core cooling system (ECCS). The plant design at that time (see Figure 1) incorporated a " swing" bus, MCC 89, alternately powered from either MCC 9B or 8B. The RHRSW-898 control instrumentation was powered from PP-89 which was powered from MCC 89.
After the establishment of the UPS, the 1977 modification removed the MCC 89 swing bus and replaced it with MCC-90 and MCC-8E. When the old MCC 89 loads vare divided between the two new MCCs, PP-89 was placed on MCC 9D which is a S2 divisian ("A" EDG) load.
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initial analysis indicated that a root cause of this situation was a failure of the design modification process to identify that the RHRSW-89B control instrumentation was shifted to an inappropriate (S2 division) power supply.
The review of the MCC 89 load redistribution to MCC 90 and 8E was insufficient tc detect this error.
Findings The as-built configuration for the power supply to RHRSW-89B control
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instrumentation rendered the RHR/SW system susceptible to a single mode failure.
Loss of offsite power concurrent with a failure of the i
"A" EDG would have resulted in a loss of the "A" train of RHR/SW and an inability to remotely open RHRSW-893, thus causing a loss of the
"B" train of RHR/SW.
Loss of the RHR/SW system would render the con-tainment cooling, torus cooling and shutdown cooling modes of the RHR system inoperable.
In a low probability design basis event [ loss-of-coolant-accident with a loss of offsite power and single failure ("A" EDG)], sustained loss of the RHR/SW system and supported cooling modes of the RHR system would degrade overall post-accident cooling capabilities.
In this instance, the sustained loss of RHR/SW was considered un-likely for the following reasons:
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RHRSW-89B could be manually opened within minutes if the reactor building was habitable.
This would allow the restoration of the
"B" train of RHR cooling which is sufficient to meet design ob-jectives.
The S2 division ("A" EDG) of the emergency power system could
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immediately be powered from the Vernon Tie Line (4160 volt power from the Vernon dam hydroelectric station). This action is pro-ceduralized in OT 3122, " Loss of Normal Power." This would
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the entire "A" train of. safety equipment.
Subsequently, the m
full cooling capabilities of the RHR system would be restored.
The TM which was used to correct the design deficiency and pro-
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vide alternate control power to RHRSW-89B was easily formulated and implemented. This action could have been' accomplished re-latively quickly once the RHRSW-898 failure was recognized.
Ample post-LOCA time is avail.able to restore power.to the S2
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division either by use of off-site power or restoration of the
"A" EDG. The containment response to the design basis event as; described in the final safety analysis report (FSAR) Section 14.6.3.3.2 indicates that operation of containment cooling could be delayed by up to eight hours without incurring unacceptable
. consequences.
Although thase factors significantly mitigate and minimize the safety impact.of tne design flaw, the error degraded the design capabilities of the RHR/SW system. The susceptibility of the RHR/SW system to a single failure mode with subsequent loss of system capability devi--
ates from the requirements of the facility FSAR.
Licensee development and initial response to this situation were good. Detection of the design flaw attests to'the' diligent and cap-able current engineering support staff.
Rapid development and imple-mentation of a temporary modification which rectified the condition and restored redundancy to the RHR/SW system was noteworthy. A com-plete review of the load redistribution associated with the 1977 de-sign change was appropriate. However, the design flaw indicates.a weakness existed in the engineering process that developed, reviewed, implemented and tested the modification.
The failure of this process to prevent the design deficiency represents an apparent violation of 10 CFR 50, Appendix B, Section III, " Design Control" requirements.
The preliminary. licensee analysis considered the improvements and enhancements made to the design change program in the ensuing years since 1977 to be sufficient to minimize the potential of a similar condition. The inspector noted that a few instances of design change program deficiencies (hardware and/or documentation) have been iden-tified 'in the past year (IR 89-07, 89-05, 88-03 and 88-14, as well as licensee identified items). Although not excessive, these instances indicate the potential for past generic weaknesses in the design change program. The efficacy of the past design change program and the potential for as yet undiscovered deficiencies were discussed with licensee management. The inspector considered the initial long-term licensee corrective actions not to be fully comprehensive because this concern was not being adequately addressed.
Subse-quently, the licensee established a task force to review this event and determine an appropriate corrective action response. Addi-tionally, the inspector noted that several recent deficiencies have l
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involved the RHR/SW system including: The RHRSW-89B control instru-
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mentation power'. supply design flaw (discussed above), stem failures-of RHRSW-89A (IR 89-07), the RHRSW-89A orientation error (IR 89-07),
failures of RHRSW-43A and B. (IR 89-07), and RHR heat exchanger baffle plate degradation (1989 outage)..The sum of these conditions war-rants further licensee' evaluation of the RHR/SW system as a whole.
Because the violation of 10 CFR 50 Appendix B requirements noted above was identified by the licensee, was of a low severity level, had prompt corrective actions taken, will be reported as LER 89-09,.
was not related to corrective actions for a previous violation, and was significantly mitigated by the available remedial actions noted above,.the NRC is exercising enforcement discretion in accordance with 10 CFR 2 Appendix ~C and no Notice of Violation wil1 be issued in this instance.
Corrective actions relative to this occurrence appear effective to prevent racurrence and this licensee identified. item is closed (50-271/89-09-02).
Review of the task force findings and any resultant long-term corrective actions is an unresolved issue'(50-271/89-09-03).
9.
Licensee Event Reporting (LER).
The~ inspector reviewed the licensee event reports (LERs) listed below to determine that with respect to the general aspects of the events:
(1) the.
report was submitted in a timely manner; (2) description of the events was accurate; (3) root cause analysis was performed; (4) safety implications were considered; and (5) corrective actions implemented or planned were-sufficient to preclude recurrence'of a similar event.
9.1 LER 89-06'
The LER 89-06, " Inadvertent Primary Containment Isolation System Ac-tivation and Standby Gas Treatment System Start Due to Personnel Error," addressed a PCIS Group III isolation which occurred on May 24, 1989.
Details of this event appeared in Section 6 of IR 89-07.
This LER was minimally acceptable.
Further explanation in several areas would have enhanced the LER.
The description of events did not j
identify what system was under test. The fact that a supervised trainee was performing the testing was also not identified in the LER. The causal analysis indicates that there were some contributing human factor problems but does not identify what they were. Although not of the same high quality of other recent LERs, this LER margin-ally fulfilled the above criteri __. -_
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10.
Review of Licensee Response to NRC Initiatives 11.1 Emergency Diesel Generator (EDG) Fuel Oil (TI 2515/100)
-Background
i For proper operation of the standby' diesel generators, it is neces-sary to ensure the quality of the fuel oil. Appendix B to 10 CFR 50,-
' as supplemented by Regulatory Guide (RG) 1.137, serves as an accept-able basis for licensees to maintain a program to ensure.the quality of EDG fuel oil.
In response to industry problems, the NRC issued Information Notice 87-04 on January 16, 1987 to alert licensees to potentially signi-ficant problems pertaining to the long-term storage of fuel oil.
This information notice documents the inoperability of an emergency diesel generator due to a high concentration of particulate in the
' fuel oil. Assurance of quality fuel oil requires purchasing the cor-rect fuel oil and-a receipt inspection to verify that the fuel oil is proper prior to addition to the storage tanks..Since fuel oil de-grades with time and external sources contribute contamination, periodic inspection is required to assure continued fuel oil quality.
This inspection was performed as a followup to IR 88-08 to determine the adequacy of the licensee program for the procurement, receipt, storage, handling and control of EDG fuel oil.
Diesel Fuel Oil Receipt / Storage Description The licensee No. 2 diesel fuel oil system for the site is comprised of a 75,000. gallon fuel receipt / storage tank which provides fuel oil to two separately powered redundant pumps.
These pumps supply fuel oil to the heating boiler 5,000 gallon tank, the diesel fire pump 350 gallon tank, and to the two EDG unit 800 gallon day tanks. The day tanks gravity feed fuel oil to the diesel engine driven fuel pumps which provide fuel at pressure through duplex filters to the engine fuel header and injectors. The fuel system does not provide for re-circulation of the fuel.
Normal usage of fuel for heating and test-ing of the diesels provides for several fuel turnovers per year of fuel in the storage tank and several times per year in the EDG day tanks.
Fuel Oil Requirements / Procurement The licensee procures all No. 2 diesel fuel for the site as quality assurance material' and requires that the fuel meet the requirements of ASTM D975-68 for No. 2 diesel fuel.
This requirement is consis-tent with recommendations for fuel oil systems for standby diesel generators as established in Regulatory Guide 1.137.
The Licensee technical specifications requires that there be a minimum of 25,000
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usable gallons of diesel fuel in the storage tank, that it be veri-fied weekly and.after each EDG operation, and that once a month a sample of the fuel be analyzed to verify conformance with ASTM D975-68.
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Fuel Oil Chemistry / Analysis Incoming new fuel and stored fuel are analyzed in accordance with licensee procedure Op 4613, " Sampling / Testing of Diesel-Fuel 011."
Analyses for-viscosity, water and sediment are performed and com-pleted on-site prior to offloading new fuel. The complete ASTM D975-68 analysis for fuel parameters is performed by an independent offsite laboratory. This laboratory provides verification of all
. ASTM D975-68 parameters. The offsite analysis is performed under licensee. Purchase Order 35311. This purchase order requires verbal notification of the analysis results within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of sample re-ceipt and written results within five days. 'The purchase order fur-ther provides for licensee quality assurance (QA) witness of selected tests. The inspector reviewed the purchase order in-detail and a recent fuel analysis. No discrepancies were noted in either the chemistry procedures.or in the analyses performed. The inspector performed a walkdown of the fuel system including the fuel sample locations. The inspector noted that a combination of the physical arrangement of the fuel ~ sample lines and the procedure for sampling (OP 4613) might result in a non-representative sample.
The licensee maintained that the current sampling process is conservative and en-sures a " worst case" sample is obtained. However, the' licensee agreed to review the sampling methodology.
Fuel Storage IE Information Notice 87-04 addresses EDG failures due to fuel foul-ing from oxidation and biological contamination which clogged fil-ters/ strainers and caused EDG shutdown. This item was addressed ex-tensively in IR 88-08 with findings in the areas of fuel analysis, fuel filter / strainer maintenance, and the need for an overall unified EDG fuel oil system quality assurance system.
This inspection confirms that the liccasee has established an overall fuel sampling analysis program to ensure fuel quality with proper QA involvement. The licensee has established, as a part of the preven-
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tive maintenance program, the yearly cleaning / replacement of fuel
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strainers / filters.
Conclusion The licensee has substantially improved the quality of the EDG fuel oil system.
Improvements in fuel sampling, sample analysis and sys-tem preventive maintenance have adequately addressed the concerns l
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- identified in-IR 88-08 (unresolved item 88-08-02). The. inspector determined that the fuel system is currently maintained in a quality.
manner and.is adequate to support continued' reliable EDG operations.
11. Review of Periodic'and Special Reports Upon receipt, thel inspector reviewed periodic and special reportr, sub-mitted pursuant to Technical Specifications. This review verifi,ed, as applicable:
(1) that the reported information was valid and included the NRC-required data;-(2) that test results and supporting information were consistent with design predictions and performance specification; and-(3) that planned corrective actions were adequate for resolution of the problem. The inspector also ascertained whether any reported information should be classified as an abnormal occurrence. The following reports were reviewed:
Monthly Statistical Report for plant operations for the months of May
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and June 1989.
'No deficiencies were identified.
12. Management Meetings 12.1 Routine At periodic intervals during this inspection, meetings were held with senior plant management to discuss the' findings. A summary of find-
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ings' for the report period was also discussed at the conclusion of the inspection and prior to report issuance.
No proprietary infor-mation was identi_fied as being included in the report.
12.2 Licensee / Region I Management Meeting On June 15, 1989 a management meeting was held by mutual NRC and licensee request (see Attachment A for Meeting Notice) in Region I
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offices (see Attachment B for attendees). Matters discussed during
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Radiation department personnel and administrative changes.
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ALARA program. Radiation program improvements.
l Completed outage activities.
Emergent work challenges.
Prob-
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lems associated with control of evolutions.
Maintenance program development.
Vendor information program
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improvements.
Fire protection program improvements. Response to identified
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problems.
Improvements to the corrective action program.
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ATTACHMENT A
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U.S. NUCLEAR REGULATORY COMMISSION No.89-089
REGION I
NOTICE OF SIGNIFICANT LICENSEE MEETING Licensee:
Vermont Yankee Nuclear Power Corporation Facility:
Vermont Yankee Nuclear Power Station l
Docket No.:
50-271 Time and Date:
1:00 p.m., June 15, 1989 1:
. Location:
Region I Office, King of Prussia, Pennsylvania
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Division of-Reactor Projects (DRP) Conference Room Purpose:
Discuss Licensee Initiatives and Corrective Actions Related to the Systematic Assessment of Licensee Performance (SALP)
in the Areas of Maintenance, Radiological Centrols and
' Assurance of Quality.
Discussions will include Performance in the Areas of Fire Protection, Corrective Action Effectiveness and Self-Assessment L
NRC Attendees:
W. Kane, Director, Division of Reactor Projects (DRP)
5. Collins, Deputy Director, DRP J. Wiggins, Chief, Reactor Projects Branch No. 3, DRP D. Haverkamp, Chief, Reactor Projects Section No. 3C, ORP
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W. Johnston, Acting Director, Division of Reactor Safety (DRS',
R. Bellamy, Chief, Facilities Radiological Safety and Safeguards, Division of Radiation Safety and Safeguards (DRSS)
L. Doerflein, Project Engineer, DRP G. Grant, Senior Resident Inspector R. Wessman, Director, Project Directorate I-3, Office of Nuclear Reactor Regulation (NRR)
M. Fairtile, Project Manager, NRR Licensee Attendees: G. Weigand, President and Chief Executive Officer W. Murphy, Vice President and Manager of Operations D. Reid, Operations Support Manager R. Wanczyk, Operations Superintendent R. Pagodin, Technical Services Superintendent Note: Attendance by NRC personnel at this meeting should be made known by June 13, 1989, via telephone call to Donald R. Haverkamp, Region I, at FTS 8-346-5120 or (215) 337-5120.
I Prepared by:
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W Donald R. Haverkamp, Chi f Re:)ctor Projects Section No. 3C I
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UllN 07 m Meeting Notice No'.89-08i
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Distribution:
V. Stello, Jr., Executive Director for ' Operations J; ' Taylor, Deputy' Executive Director for Nuclear Reactor Regulation, Regional Operations and Research i H. Thompson, Deputy Executive Director for Materials Safety, Safeguards and Operations Support B. Grimes, Director, Division of Reactor Inspection and Safeguards, NRR J. Lieberman, Director, Office of Enforcement L. Chandler, Assistant General Counsel for Enforcement T. Murley, Director, Office of Nuclear Reactor Regulation F. Miraglia, Associate Director for Inspection and Technical Assessment, NRR S. Varga, Director, Division of Reactor Projects - I/II', NRR B. Boger, Ar sistant Director-for Region I Reactors, NRR R. Wassman, Director, Project Directorate I-3, NRR l.
M. Fairtile, Project Manager, PD I-3, NRR I
B, Clayton, Regional. Coordinator, EDO Public Document Room (PDR)
Local Public Document Room (LPDR)
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State of Vermont State of New Hampshire Commonwealth of Massachusetts
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-NRC Resident Inspector
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ATTACHMENT B Vermont Yankee Management Meeting Attendees l
June 15, 1989 U.S. Nuclear Regulatory Commission J. Wiggins, Chief, Reactor Projects Branch No. 3, DRP, RI D. Haverkamp, Chief, Reactor Projects Section 3C, PB3, DRP G. Grant, Sr. Resident Inspector, Vermont Yankee, PB3, DRP L. Doerflein, Projects Engineer, RPS 38, PB3, DRP R. Wessman, Director, Project Directorate I-3, NRR M. Fairtile, Project Manager, NRR V. Rooney, Project Manager, NRR W. Johnston, Acting Director, DRS R. Bellamy, Chief, Facilities Radiological Safety & Safeguards Branch, DRSS J. Strosnider, Chief, MPS, Engineering Branch, DRS C. Anderson, Chief, Plant Systems Section, EB, DRS L. Cheung, Sr. Reactor Engineer, PSS, EB, DRS A. Krasopoulous, Reactor Engineer, PSS, EB, DRS R. Loesch, Radiation Specialist, FRPS, FRSSB, DRSS Vermont Yankee Nuclear Power Corporation J. Weigand, President and Chief Executive Officer W. Murphy, Vice-President and Manager of Operations R. Pagodin, Technical Services Superintendent S. Jefferson, Assistant to Plant Manager D. Reid,'Dperations Support Manager Public W. Sherman, Nuclear Engineer, State of Vermont
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ATTACHMENT C: Figure 1
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