IR 05000271/1987016
| ML20149M978 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee File:NorthStar Vermont Yankee icon.png |
| Issue date: | 02/25/1988 |
| From: | Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20149M969 | List: |
| References | |
| TASK-2.K.3.18, TASK-TM 50-271-87-16, NUDOCS 8802290339 | |
| Download: ML20149M978 (60) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.:
50-271/87-16 Docket No.:
50-271 License No.: OPR-28
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Licensee:
Vermont Yankee Nuclear Power Corporation RD 5, Box 169 Brattleboro, Vermont 05301 Facility Name: Vermont Yankee Nuclear Power Station Inspection At: Vernon, Vermont Inspection Conducted: August 1 - October 30, 1987 Inspectors:
Donald R. Haverkamp, Project Engineer, Reactor Projects Section No. 3C Geoffrey E. Grant, Senior Resident Inspector William J. Raymond, Senior Resident Inspector, Millstone Harold Eichenholz, Senior Resident Inspector, Yanksa David. Ruscitto, Re ident Inspector, Seabrook-Approved By:
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2hf/87 Donald R. Haverkamp, Chief
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Reactor Projects Section No. 3C Inspection Summary:
Inspection on August 1 - October 30, 1987 (Report No. 50-271/87-16)
Areas Inspected:
Routine onsite regular and backshift inspection by five resident and regional inspectors during a three-month period that included preparations for, conduct of and startup from refueling / maintenance outage XIII (331 hours0.00383 days <br />0.0919 hours <br />5.472884e-4 weeks <br />1.259455e-4 months <br />).
Areas inspected included licensee action on previous inspection findings, outage management, operational safety verification, physical security observations, fitness for duty program, plant startup preparations and activ-ities, release of radioactive material from the RCA, failed residual heat removal pump motor terminations, periodic and special reports, and licensee event reports.
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Results:
One violation was identified in the area of control of radioactive o
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material.
The incident that precipitated this violation was the fourth-in a recent series of failures to adequately control very low level radioactive material.
Although of low safety significance and no hazard to the public,
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the licensee inability to prevent recurrence is indicative of a less than fully effective corrective action program (Section 10.0).
Outage activities including modifications and testing were well coordinated and l
controlled (Sections 4.0 and 8.0).
The suspension of refueling activities on August 20, 1987 was due to a licensee-identified failure to meet technical specification requirements.
This misinterpretation of requirements demon-strated a deficiency in training and need for clarification. Licensee response was both prompt and effective (Section 9.3).
The licensee investigative approach to the RHR pump B motor termination f ailure was thorough and well
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coordinated (Section 11.0).
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Facility activities during this three-month inspection period were complex, and both normal operations and off-normal events were challenging.
However, no i
safety-significant concerns were identified by the inspectors.
Licensed operator and non-licensed personnel performance l at all levels and within all departments, and particularly plant and outage management performance, was
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considered superior throughout the inspection period.
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TABLE OF CONTENTS Page 1.0 Persons Contacted.................
2.0 Summary of Facility and NRC Activities.......
3.0 Licensee Action on Previous Inspection Findings..
3.1 Follow Item 83-17-01: Closed, Corrective Actions for MSIV 86A and 80C.........
3.2 Follow Item 84-01-01: Closed, Licensee Action on TAP Item 11.K.18-ADS Logic Change.....
3.3 Unresolved Item 87-04-02:
Closed, Feedwater Leak Detection System.............
3.4 Violation 86-25-01:
Open, Pump Testing per ASME Code Section XI.............
3.5 Unresolved Item 87-04-03:
Closed, Contaminated Material Control.........
3.6 Unresolved Item 82-03-02:
Closed, Standby Liquid Control System......
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3.7 Unresolved Item 83-21-05:
Closed, Cobalt Release Pathway via the Turbine Building Vents.....................
3.8 Follow Item 84-08-08: Closed, Actions to Improve Reliability of Motor Operated Valves....................
3.9 Follow Item 84-21-08: Closed, Corrective Actions for Review of Operating Experience..................
3.10 Unresolved Item 85-02-03:
Closed, Staffing Criteria...................
3.11 Unresolved Item 85-10-03: Closed, Repair of Drywell Sample Valves.............
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3.12 Follow Item 85-20-05: Closed, Examination of Diesel Components Removed from Service....
3.13 Unresolved Item 86-10-01: Closed, Maintaining Isolation Zones Clear of Obstructions.....
4.0 Outage Management.
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4.1 Outage Activities...............
4.2 Facility Changes...............
4.3 Outage Organization.
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P_agg 5.0- Operational Safety Verification..........
5.1 Safety System Review.......
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5.2 Feedwater Leak Detection System Status....
5.3 Inoperable Equipment....
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5.4 _ Review of Jumpers, Lifted Leads and-Hechanical Bypasses..............
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5.5 Review of Switching and Tagging Operations..
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6.0 Physical Security.................
6.1 Security Events.................-
'6.2 Security Event Reports............
7.0 Fitness for Duty Program.
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8' 0 Plant Startup Preparations and Activities.....
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8.1 Integrated ECCS Test.
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8.2 Reactor Vessel Hydrostatic Test.
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. 8.3 Reactor Startup.
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8.4 Low Power Testing...............
9.0 Operational Event Review..............
9.1 Reactor Scram: August 7, 1987.........
9.2 Lo s s o f N o rma l Powe r.............
9.3 Suspension of Refueling Activities......
9.4 Loss of. Shutdown Cooling...........
9.5 Reactor Scram: October 3, 1987........
9.6 Additional Items...............
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10.0 Release of Radioactive Material from the RCA....
11.0 Failed Residual Heat Removal Pump Motor Termination
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13.0 Licensee Event Reports...............
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14.0 Managements Meetings................
Attachment A:
Facility Activities
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Attachment B:
Inoperable Equipment Attachment C:
Required 10 CFR 50.72 Notifications
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Attachment 0: Non-notification Events of Interest
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Attachment E:
LER Summary
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DETAILS 1.0 Per:ons Contacted Interviews and discussions 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 periodically with the management and supervisory personnel listed below.
P. Donnelly, Maintenance Superintendent G. Johnson, Operations Supervisor R. Lopriore, Maintenance Supervisor R. Pagodin, Technical Services Superintendent J. Pelletier, Plant Manager J. Sinclair, Plant Administrative Supervisor R. Wanczyk, Operations Superintendent 2.0 Summary of Facility and NRC Activities The plant continued end-of-cycle power coastdown operations until August 7,1987 when a planned reactor shutdown was commenced to begin refueling / maintenance outage XIII.
The reactor experienced an automatic scram from 6% power during the shutdown procedure.
The scram was due to a high reactor pressure condition caused by a mechanical pressure regula-tor malfunction (See Section 9.1).
The plant completed an eight-week outage on schedule and conducted startup operations on October 1,1987 (See Section 8.3).
On October 3, 1987 during startup, the reactor scrammed from 18% power while placing the main turbine on line (see Section 9.5).
The plant was restarted on October 5,1987 and was essen-tially at full power by the end of the report period. The level of com-plexity of facility activities and the challenge of normal operations and off-normal events during the inspection period are detailed in Section 4.0 and Attachment A.
An NRC Region I specialist inspector completed a review of Vermont Yankee Nuclear Power Corporation (VYNPC or the licensee) preparations for refuel-ing during the period of August 3-7,1987 (Inspection Report 87-11).
A Region I based specialist completed a routine review of radiological con-trols during the period of August 17-21,1987 (Inspection Report 87-15).
A Region I based specialist completed a review of maintenance and quality assurance programs during the period of August 23-28,1987 (Inspection Report 87-18).
An NRC operater licensing exam was conducted during the period of August 25-27,1987 (Inspection Report 87-10). A Region i based specialist completed a review of selected emergency preparedness items during the period of September 3-4, 1987 (Inspection Report 87-17).
A Region I based specialist team completed a review of the licensee response
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to Unresolved Safety Issue (USI) A-7: Mark I Containment Long Term Pro-gram during the period of October 5-9, 1987 (Inspection Report 87-14). A Region I based team completed a review of the licensee environmental qualification program during the period of October 19-23, 1987 (Inspection Report 87-19). A Region I based specialist inspection of plant security practices was performed during the period of October 26 30, 1987 (Inspection Report 87-20).
Mr. Geoffrey Grant assumed full-time duties as Senior Resident Inspector at Vermont Yankee Nuclear Power Station (VYNPS) on September 20, 1987. In the intervening period between the beginning of August and Mr. Grant's arrival, inspector coverage was provided by Messrs. William Raymond, Harold Eichenholz, Donald Haverkamp and David Ruscitto. Nearly full-time resident coverage was maintained during this period.
3.0 Licensee Action on Previous Inspection Findings 3.1 [ Closed) Follow Item 83-17-01:
Corrective actions for MSIV 86A and 80C. This item concerned the failure of position indication circuits
'f3 main steam isolation valve 80C caused by binding of the actuator spring plate on the guide rods. The binding was caused by interac-tion between the guide rods and the spring plate bushings which resulted in gauling on the guide rods. The licensee installed vendor supplied rebuild kits for the actuators which included bronze bush-ings for the guide rods.
The bronze bushings were installed on two inboard MSIV's on a trial basis to check performance.
The bronze bushings eliminated the gauling problem and no subsequent failures occurred. The licensee installed bronze bushings on other MSIV's in phases during routine refueling outages, and ali inboard valves and two of four outboard valves have been modified as of the 1987 outage.
The inspector had no f urther comments on this item.
This item is closed.
3.2 [ Closed) Follow Item 84-01-01:
Licensee Action on TMI Action Plan (TAP) Item II.K.3.18-ADS Logic Change.
The licensee reversed its
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initial position to rely on the new symptom-oriented emergency opera-ting procedures, and agreed to implement one of the ADS designs recommended by the BWR Owners Group and approved by the NRC staff.
In a safety evaluation attached to a letter dated December 24, 1986, the NRC staff accepted the licensee plan to moc;ify the ADS logic by bypassing the high drywell pressure permissive with a (eight minute)
timer and adding a manual inhibit switch.
The inspector reviewed design change package EDCR 86-409 and noted that the NRC-approved ADS logic change was implemented during the 1987 refueling outage with completion of the installation on September 15, 1987.
The licensee has satisfied the NUREG 0737 requirements for this item. The item is close _ _ _ _ _ _ _ - _ _ _
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3.3 { Closed) Unresolved Item 87-04-02:
Feedwater Leak Detection System.
This item was opened pending NRC:NRR staff review of the March 28, 1986 licensee request to eliminate the requirement to con-duct liquid dye penetrant (PT) examinations of the feedwater nozzles.
As discussed in Section 5.2 of this report, NRC:NRR denied the licensee request but did extend the PT examination schedule to every six fuel cycles.
This item is closed.
3.4 {0 pen) Violation 86-25-01:
Pump Testing per ASME Code Section XI.
This violation concerned a discrepancy in the licensee interpretation and implementation of provisions in ASME Code Section XI IWP-3220 and IWP-3230 relating to IST vibration testing of core spray (CS) pumps.
The original Notice of Violation (NOV) was issued on February 6, 1987 as part of Inspection Report (IR) 50-271/86-25.
The licensee March 12. 1987 response to the NOV was reviewed as discussed in NRC:RI correspondence dated April 23, 1987 (IR 50-271/87-06).
The inspector found that no new information was provided in the licensee NOV response, but left the item open pending further review.
The NRC:RI correspondence dated June 25, 1987 (IR 50-271/87-09) revisited this issue and discussed in detail the rationale supporting the original NOV and the lack of responsiveness of the licensee correc-tive actions.
No consensus was achieved regarding acceptance and implementation of the NRC staff position on this issue and the licen-see requested that the inspector review this matter further with NRC:NRR.
Subsequent to this, NRC:NRR, in a memorandum dated August 31, 1987, reaffirmed the original (March 17, 1980)
staff position regarding this issue.
This information was made available to plant management on October 9,1987 and was discussed with both the Operations Superintendent and the Plant Manager. In light of the foregoing, NRC:RI considers this a closed issue and notes that the licensee response to the NOV remains inadequato considering the reaf firmed staf f position.
This item remains open pending further licensee review and implementation of revised corrective actions.
3.5 (Closed) Unresolved Item 87-04-03:
Contaminated Material Control.
This item was opened for a particualr incident described in IR 50-271/87-04.
Additional incidents of lack of radioactive material control were detailed in IR 50-271/87-09 and IR 50-271/87-12 and carried under this unresolved item.
Section 10.0 of this report describes a fourth incident in this area that has subsequently become a violation.
Licensee corrective actions for all of these incidents will be tracked under VIO 50-271/87-16-02. Although current correc-tive actions appear adequate, this area will remain open pending review of the long-term effectiveness of the licensee progra.
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3.6.(Closed) Unresolved Item 82-03-02:
Standby Liquid Control System Boron Anomalies.
A licensee task force completed a review of the boron anomalies associated with the standby liquid control (SLC)
system; however, no cause for the apparent loss of boron was iden-tified. There have been no further problems noted in accounting for boron additions to the SLC tank during subsequent operation since 1982. No further licensee actions were taken or are warranted. This item is closed.
3.7 (Closed) Unresolved Item 83-21-05: Cobalt Release Pathway via the Turbine Building Vents.
The licensee completed surveys of air released from the turbine building roof vents during outage condi-tions, which confirmed the release path to the north outfall dis-charge via the roof drains and the storm sewer system. The licensee subsequently identified the north storm sewer outfall as a release path to be monitored in the environmental monitoring program. This item is closed.
3.8 (Closed) Follow Item 84-08-08:
Action? Jo Improve Reliability of Motor Operated Valves.
The licensee engineering organization recom-mended additional preventive maintenance steps be taken for safety-related valves due to the number and types of valve failures observed during the plant operating history. The licensee augmented the pre-ventive maintenance program starting in 1985 using the Motor Operated Valve Analysis and Test System (MOVATS) as a diagnostic tool to better define valve compon2nts needing maintenance. The valve test-ing technique has gained general industry acceptance as a method to improve the overall performance of motor-operated valves.
The per-formance and reliability of motor-operated valves at Vermont Yankee will be reviewed during subsequent routine inspections of long-term facility operations. This item is closed.
3.9 (Closed) Follow Item 84-21-08:
Corrective Actions for Review of Operating Experience.
The inspector noted that for subsequent mat-ters reviewed under the Operating Experience Assessment Program, including Information Notices issued by the NRC, the licensee reviews were adequate and actions taken were appropriate. The problem noted during inspection 84-21 appears to be an isolated case. No further licensee actions are required.
This item is closed.
3.10 (Closed) Unresolved Item 85-02-03:
Staffing Criteria.
The licensee criteria defined in procedure AP 0036 requires shift staf fing with licensed operators and senior operators that meet the requirements of 10 CFR 50.54(m).
The AP 0036 also requires that at least one licensed operator who is designated "at the controls" be within a
"line-of sight" area of the control room front panels. The inspector noted that no further clarification of "at the controls" was subse-quently provided by the NRC.
The licensee staffing criteria is acceptable.
This item is close,
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3.11.(Closed) Unresolved Item 85-10-03:
Repair of Drywell Sample Valves.
The licensee completed actions to repair sample isolation valves 75-C1 and B2. The inspector verified during routine reviews of plant status during subsequent operations that the drywell-torus sample isolation valves were operable.
No further problems were noted.
This item is closed.
3.12.(Closed) Follow Item 85-20-05:
Examination of Diesel Components Removed from Service.
The licensee completed actions to examine the interconnecting straps removed from between the amortesieur coils installed on the pole pieces of the emergency diesel generators. No cracks were found of the type identified at other facilities.
No further licensee actions were required. This item is closed.
3.13 (Closed) Unresolved Item 86-10-01: Maintaining Isolation Zones Clear of Obstructions.
The licensee took acceptable corrective actions at the time of the initial finding to assure that the isolation zone in the vicinity of the well drilling operation remained free of obstruc-tiens. The licensee actions satisfied items of potential concern to the inspector and no nonconformance ' with regulatory requirements occurred.
The drilling equipment was subsequently removed.
The inspector verified during subsequent routine reviews that isolation zones were kept clear.
No further inadequacies were identified.
This item is closed.
4.0 Outage Management
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4.1 Outage Activities Outage XIII commenced on August 7,1987. This refueling outage was completed essentially on schedule after eight weeks and included the following major activities:
Initial shutdown and cooldown of the plant. This phase included
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valve leak rate testing; control rod friction testing; centrol rod drive changeouts; reactor disassembly; and refueling preparations.
Refueling operations.
This phase included replacement of 136
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fuel bundles with new "barrier" fuel; one control rod blade replacement; four local power range monitor replacements; con-trol rod drive replacement; fuel sipping operations; control rod friction testing; core verification; and shutdown margin l
testing.
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Implementation of design changes and modifications. This phase r
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included 10 CFR 50, Appendix R fire separation activities; modification 'of reactor water level reference legs; standby t
liquid control (SLC) system modification; modification of the i
automatic depressurization system (ADS) logic; in-vessel Inser-
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vice Inspection (ISI); ISI of reactor vessel flange and studs *
and reactor vessel reassembly.
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System and modification testing.
This phase included major
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determinations; integrated emergency core cooling systems (ECCS)
testing; primary containment isolation system (PCIS) testing;
. reactor protection system (RPS) response time testing; control rod scram testing; and reactor vessel cold hydrostatic testing.
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Return to power operations.
This phase included plant heatup;
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reactor startup; high pressure coolant injection (HPCI) system, reactor core isolation cooling (RCIC) system and safety relief valve testing; hot hydrostatic testing; nuclear instrumentation adjustments; and main turbine testing.
4.2 Facility Changes Facility modifications included:
Reactor vessel water level reference leg upgrade:
piping for
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the reactor water level measuring system in the drywell was
replaced as a result of a review of Generic Letter 84-23. Both
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the temperature compensated and cold reference columns were i
replaced with a dual cold reference leg system to increase their range of accuracy. Safeends for both nozzles were replaced as i
well.
Safeends were replaced due to the suseptibility for intergranular. stress corrosion cracking (IGSCC).
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I Modification of SLC:
This change completed modifications made
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to comply with 10 CFR 50.62. The tank was drained of the cur-rent sodium pentaborate solution and replaced with an enriched i
solution.
The requirements for pump capacity were increased F
from 35 to 41 GPM.
No physical modifications were required.
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Logic change to ADS:
The ADS logic was modified to provide a i
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bypass for the high drywell pressure signal after a sustained
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low reactor ieval signal.
In addition, manual inhibit switches i
for the autocatic initiation of ADS and a block switch to block
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inadvortant initiation of ADS were installed on control room panel CRP 9-3 for 10 CFR 50, Appendix R concerns.
After all modifications were complete, an integrated functional test was
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performed to insure the pro,ner operation of affected ADS, core
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spray, and RHR/LPCI circuitry. The change satisfied NUREG-0737
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requirements to assure adequate core cooling for a broader range i
of events.
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Regulatory Guide 1.97 modif_ications:
several changes'were made
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to meet RG 1.97 requirements including; torus water temperature indication, reactor vessel level / pressure recorders, vital a-c
bus; voltage-and frequency indicators, and drywell temperature thermocouple upgrades.
10 CFR 50, Appendix R modifications:
several changes were made
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to satisfy Appendix R requirements, including rerouting ECCS
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cables and conduits to provide separation, providing' dual power
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and control circuit feeds for valve RCIC-15, and relocation of
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diesel generator room exhaust fan control cables and switches.
4.3 Outage Organization
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The outage organization was established essentially along the normal
operational organization tree.
An Outage Manager was designated by
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and reported to the Plant Manager and was responsible for the conduct
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of the outage.
N_ormally filled by the Operations Superintendent, this position was periodically rotated to other superintendents to maintain full-time coverage. The outage organization reported to the
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Outage Manager on all matters pertaining to outage-related activ-F ittes. Daily outage meetings were held in the morning and chaired by the Outage Manager. These meetings were attended by all key outage
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supervisory personnel and served to monitor outage progress, provide
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activity planning and coordination, identify and resolve schedule or
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work conflicts and discuss near-term activities. Changes resulting
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from these meetings were assimilated by the Outage Planner and used
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to develop and modify the outage plan and schedule.
An oversight group was established to aid in transition through the various outage i
phases.
This group was tasked with verification of conditions and activities necessary to progress through the various outage mile-stones.
Culmination of this process was the determination that the i
plant was prepared to return to power operations.
Critical item
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tracking, checklists and other administrative controls were used to l
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achieve a smooth progression through the outage milestones.
Overview and control of the outage culminated with preparations for
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reactor startup.
A separate bar chart and schedule were developed i
for this phase of the outage. Preparations were controlled by check-lists, administrative procedures and detailed overview by the Plant
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i Operations Review Committee (PORC).
The p0RC involvement in this process was noteworthy, as PORC review of maintenance, surveillance,
modifications, required retests, and operability determinations was i
extensive.
Also reviewed for acceptability were lifted leads,
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jumpers, mechancial bypasses, and station tagouts.
These compre-hensive reviews provided assurance that plant conditions could sup-
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port a safe reactor startup and test program. This multi-day process l
demonstrated a commitment to safe operations and supertoi performance.
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5.0 Cperational Safety Verification The inspector observed plant operations during regular and backshift tours of the following areas:
Control Room Cable Vault Reactor Building Fence Line (Protected Are:)
Diesel Generator Rooms Intake Structi.re Vital Switchgear Room Turbine Building Control room instruments were observed for correlation between channels, proper functioning, and conformance with Technical Specifications. Alarm conditions in effect and alarms received in the control room were reviewed and discussed with the operators.
Operator awareness and response to these conditions were reviewed. Operators were found cognizant of board and plant conditions.
Control room and shift manning were compared with Technical Specification requirements.
Posting and control of radiation, contaminated and high radiation areas were inspected. Use of and compli-ance 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 compliance with station proced-ures, to determine if entries were correctly made, and to verify correct communication of equipment status.
These records included various opera-ting logs, turnover sheets, tagout and jumper logs, and Potential Report-able Occurence reports. The inspector observed selected actions concern-ing site security including personnel monitoring, access control, place-ment of physical barriers, and compensatory measures.
Inspections of the control room were performed on weekends and backshifts including August 1, 14, 17, 18, 19, 20, 27, 29, September 9,10 and October 1, 2, 4, 26, 27, 28, 29 and 30. Operators and shif t supervisors were alert, attentive and responded appropriately to annunciators and plant conditions.
A wide variety of outage activites were in progress during these inspections.
The inspector noted no safety-significant concerns. Licensed operator and non-licensed personnel performance, at all levels and within all depart-ments, and particularly plant and outage management performance, was con-sidered superior throughout the three-month inspection period.
5.1 Safety System Review The residual heat removal, core spray, residual heat removal service water, high pressure coolant injection, and reactor core isolation cooling systems, were reviewed to verify proper alignment and opera-tional status in the standby mode.
The review included verification that (1) accessible major flow path valves were correctly positioned; (ii) power supplies were energized, (iii) lubrication and component cooling was proper, and (iv) components were operable based on a visual inspection of equioment for leakage and general conditions.
No inadequacies were identifie _ _ _ _ _ _ _ _ _ _ _ -.
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5.2 Feedwater leak Detection System Status The inspector reviewed the feedwater leakage detection system and the monthly performance sunmary provided by the licensee in accordance with letter FVY 82-105.
The licensee reported that, based on the leakage monitoring data reduced as of October 29, 1987, there were no deviations in excess of 0.10 from the steady-state value of normal-ized thermocouple readings, and no failures in the sixteen thermo-couples installed on the four feedwater nozzles.
No unacceptable conditions were identified.
By letter dated August 7, 1987, the NRC Office of Nuclear Reactor Regulation (NRC:NRR) informed VYNPC that its request for permanent elimination of the liquid penetrant (PT) exauination of the feedwater nozzles had been denied.
The PT examination requirements stem from the NRC resolution of the generic BWR feedwater nozzle cracking issue documented in NUREG-0619.
The regulatory examination requirements for plants having feedwater nozzle configurations similar to those at VYNPS normally include: PT examination every two fuel cycles; ultra-sonic (UT) examination every fuel cycle; and visual examination of the feedwater spargers every two fuel cycles. The NRC:NRR found the requested total elimination of PT examinations to be unacceptable for three reasons including: (1) lack of assurance or confidence that UT examinations can replace PT examinations in accurately detecting minor surface cracks; (2) the PT examinations provide redundant assurance for cracks not otherwise detected by UT examination; and, (3) as the reactor vessel ages, the feedwater nozzle /sparger con-figuration could possibly develop feedwater leakage which could even-tually cause cracking. However, due to the lack of crack indications in examinations of all types performed to date, the adequacy of the VYNPC UT examination procedures, and the lack of any feedwater leak-age as recorded by the leakage monitoring system, NRC:NRR approved lengthening the PT examination schedule from the exisitng two fuel-cycle interval to a six fuel-cycle interval. This extension does not affect the UT or visual examination schedule. Additionally, the PT schedule will revert to a two fuel-cycle interval if any future cracking is detected.
Examinations performed during the 1987 outage showed no evidence of cracking, i
5.3 Inoperable Equipment Actions taken by plant personnel during periods when equipment was inoperable were reviewed to verify that: (1) technical specification limits were met; (2) alternate surveillance testing was completed satisfactorily; and, (3) equipment return to service upon completion i
of repairs was proper. This review was completed for the 40 items
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i Na violations or safety concerns were identified by the inspector.
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5.4 Review of Jumpers, Lifted leads and Mechanical Bypasses Jumper and lifted lead (J/LL) requests and mechanical bypasses (MB)
were reviewed to verify that controls established by AP 0020 were met, no conflict with the technical specifications were created, the requests were properly approved prior to installation, and a safety evaluation in accordance with 10 CFR 50.59 was prepared if required.
Implementation of the requests was reviewed on a sampling basis.
Additionally, the entire J/LL and MB outstanding items list was ieviewed as part of a comprehensive pre-startup systems verification process. Many of these bypasses were cleared as a result of outage activites.
Remaining bypasses were verified as correct, necessary and appropriately documented.
No inadequacies were identified.
5.5 _ Review of Switching and 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.
Additionally, a thorough review of switching and tagging activities was conducted as part of the pre-startup verification process.
The volume of tagging resulting from outage-related activities required careful review to avoid oversights and system alignment problems.
The licensee control of this process was very good. No inadequacies were identified.
6.0 Physical Security Selected E,ects of plant physical security were reviewed during regular and backshift hours to verify that controls were in accordance with the security plan and approved procedures. This review included the following security neasures: guard staffing; vital and protected area barrier integ-rity; maintenance of isolation zones; and, implementation of access con-trols, including authorization, badging, esenrting, and searches.
No inadequacies were identified.
I 6.1 Security Events i
The inspector reviewed the licensee response actions for events that occurred on August 7, 17 and 27 and September 4, 12 and 18,1987.
With the exception of the September 18 event, prompt and adequate compensatory measures were taken during each event and maintained for the duration of the hardware outage. The events were reported to the NRC Operations Officer as required by 10 CFR 73.71 (see Attachment C).
The events of August 7 and 27, and September 4 and 12 had similar. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _.
a
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root causes. In each instance the licensee took effective corrective action to address the individual malfunction.
Additionally, the licensee identified the similarity of these events and implemented corrective measures to address the generic issues involved.
The event of August 17 was precipitated by a loss of normal site elec-trical power as described in Licensee Event Report 87-08 and Section 9.2 of this report. No system malfunctions occurred and a return to normal operations followed restoration of normal site electrical power.
The licensee took immediate and comprehensive corrective actions upon discovery of the deficiency in the September 18 event.
An extensive investigation was conducted by the licensee and reviewed by the inspector. Immediate and long-term corrective actions address all of the issues and concerns related to this event.
Otscussions with licensee security supervision demonstrated a commitment to thorough analysis, effective corrective actions and superior performance.
6.2 Security Event Reports The inspector reviewed Security Event Reports Nos. 87-13, 14, 15, 16, 17 and 18 dated August 11, 21, 31 and September 8,19 and 25 respec-tively, which described the above events.
The event reports accur-ately described the circumstances of each incident and the licensee follow-up actions. With the concurrence of the NRC Region I cognizant security inspector, Reports 87-17 and 87-18 were submitted bayond the five-day time period alloweo by 10 CFR 73.71. No inadequacies were identified.
7.0 Fitness for Duty Program The licensee has a fitness for duty program that includes a drug and alcohol policy, chemical screening program, continuous behavior observa-tion program and employee assistance program.
The overall program is applicable to VYNPC employees, contractors and visitors.
The program's
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main tenet is that individuals (employees, contractors or visitors) under the influence of or in possession of controlled drugs or alcohol consti-tute a threat to the safety of themselves, VYNPC employees and the public.
Such use or possession will not be tolerated.
Key attributes of the pro-gram include the following.
Effective communication of the policy to all levels of VYNPC
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employees and contractors as well as prospective employees and contractors.
Comprehensive employee, contractor and supervisory training.
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A continuous behavior observation program to support earliest
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possible identification of potential drug / alcohol problems.
Pre-employment drug / alcohol screening.
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Drug / alcohol screening for substantiated cause.
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Retesting of personnel with confirmed positive drug test results
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after 30 days.
Random screening of an individual returned to duty following a con-
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firmed drug / alcohol policy violation.
A drug / alcohol policy violation responsibility / action matrix.
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A uefinitive screening program including test methods and protocol.
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The licensee program has proven to be effective, especially during the recent refueling outage. Activities during an outage result in a large influx of temporary contractor personnel which tests the effectiveness of the pre-employment screening program.
During this period, the program demonstrated its ability to identify drug / alcohol related problems.
The small number of applicants who failed the screening process were not employed.
The licensee post-employment program proved effective on August 13,1987 when information supplied' by a local law enforcement agency (LLEA) resulted in the licensee determination that probable cause existed to request drug tests of two outage contractor employees.
The individuals were removed from the site and voluntarily agreed to submit to testing. One individual tested negative and returned to work the follow-ing day.
The other individual tested positive for cocaine, was denied site access for 30 days and never returned.
This was the only internal challenge to the licensee drug policy known by the NRC.
The inspector found no inadequacies and had no further questions.
Recent State of Vermont legislation (effective September 1, 1987) has impacted the licensee fitness for duty program.
Employers are now pro-hibited from conducting random drug screening and routine post-employment drug screening (annual physicals, etc.).
Additionally, erployers are required to rehabilitate individuals who test positive for drugs.
No suspension or termination is allowed on initial positive testing.
Pro-bable cause testing remains authorized. These recent legislative changes have caused the licensee to modify the VYNPC fitness for duty program.
The inspector will review the new program during routine inspection activities.
8.0 Plant Startup preparations and Activities The inspector reviewed the licensee activities to recover from the outage and prepare plant systems for operations.
The inspector reviewed the completion of prerequisites identified on milestone punchlists and startup checklists. Several major tests were witnessed and results were reviewed to verify that system operability was appropriately demonstrated. System valve lineups were reviewed to verify the adequacy of the licensee admin-istrative controls to assure proper system alignment.
The tests and evolutions inspected are listed belo __
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+ Scram Time Testing
+ Reactor Startup
+ Integrated ECCS Test
+ Low Power Testing
+ Reactor Hydrostatic Test The inspection of the above events determined that the licensee had detailed procedures and milestone punchlists to adequately control restor-ation and startup activities, and to verify that startup prerequisites were satisfactorily accomplished.
Procedures and administrative controls were adequately followed.
Specific items are discussed further below.
8.1 Integrated ECCS Test The inspector witnessed the conduct of surveillance procedure OP 4100, "ECCS Integrated Automatic Initiation Test," which tests the proper response of the emergency core cooling systems to automatic start signals concurrent with simulated loss of offsite power.
The automatic initiation test is performed by simulating a high dry-well pressure and low-low water level and low reactor pressure signal and a concurrent low voltage on Buses 3 and 4.
Diesels, pumps, motors and valves are checked for starting time, sequence and total KW load. The emergency load is manually applied by starting vital equipment.
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The following sequence of events occurs with a simultaneous loss of normal power and a high drywell pressure or low-low reactor water level with low reactor pressure:
The low voltage condition, sensed on Buses 3 and 4, combined with the ECCS initiation signals, de-energizes buses 3 and 4 and initiates the diesel generators starting circuits within three seconds.
At the same time, the high drywell pressure and low-low reactor water level signals initiate HPCI and RCIC and trip the UPS feeder breakers in Buses 8 and 9.
Within thirteen seconds the diesels will accept the following automatic starting loads; diesel auxiliaries, diesel room fans, a-c motor-operated isolation valves, emerger.cy lighting, sta-tion service water pumps C and D, and RHR pumps A and D.
Five seconds after diesel generator breaker closure, the remaining two RHR pumps B and C start.
Ten seconds af ter diesel generator breaker closure, both core spray pumps start. After one minute has elapsed, an RBCCW pump starts.
The remaining essential loads are operated manually by the operator when required and as the diesel generator capacity permits.
The performance of plant systems during the test was satisfactory,
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The pre-test verification of initial conditions. test personnel per-
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L formance and test control were excellent. The integrated ECCS test
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provides an indication of the effectiveness and quality of various
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licensee. outage activities including:-
pre-maintenance planning;
maintenance quality control; post-maintenance testing; _ surveillance
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testing; equipment / system control; operability determinations; coor-
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dination; and, supervision.
The success.of this test and the pro-
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fessional manner in which it was conducted attest to the licensee
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assurance of quality in these activities.
No inadequacies were identified.
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8.2 Reactor Vessel Hydrostatic Test
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A cold operational test provides assurance that all vessel boundaries
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which have been interrupted during a refueling or maintenance outage
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have been returned to an operable condition.
For such a cold opera-
tional test, the reactor pressure vessel is heated above the minimum pressurization temperature (MPT) by means of core decay heat and RHR L
pump operation.
When the MPT requirement has been satisfied, the
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reactor vessel is filled two feet ab6ve head flange and the head i
vents shut.
Pressure is then increased to approximately 85 psig and L
a rapid visual inspection of all pressurized piping, seals, flanges,
etc., is conducted. Tha RHR pumps are stopped, the shutdown cooling i
lineup secured, and the recirculation pumps started following the 85 l
psig inspection.
Vessel pressure is -increased to approximately 500 l
psig using the control rod drive or condensate systems as a source of-
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pressure.
A rapid visual inspection is then conducted.
Following
the successful completion of inspection at 500 psig, the reactor
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vessel pressure is increased to 1018 psig using the control rod drive
t system. The cleanup system and/or bottom vessel drains are throttled I
concurrently with the feeding systems to maintain the desired
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j pressure and level.
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Following repairs by welding on any pressure retaining boundary or
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j components, and at or near the end of each inspection interval, a hot j
systim leakage and hydrostatic pressure test must also be performed,
,
This hot test is done following the cold test and in accordance with l
routine station startup procedures.
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The inspector reviewed the conduct of the reactor vessel Class 1 l
hydrostatic test and noted that the test was completed satisfac-i
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torily. Packing and flange leaks were identified and repaired by the licensee. A housing flange leak on control rod drive (CRD) 30-11
required a more exten, ve repair involving dropping the CRD and
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replacing the seal.
This repair was accomplished satisfactorily.
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8.3 Reactor _Startup The inspector reviewed the preparations for a reactor startup in accordance with procedures OP 0100 and OP 0101.
The completion of prerequisites in the startup punchlist and the precritical checklist were reviewed with shif t personnel. The status of plant systems was reviewed and they were found properly aligned for restart based on a review of control room indications and a walkdown of safety systems in the reactor and turbine buildings.
No inadequacies were identified.
The inspector witneseed the reactor startup to critical at 2:20 a.m.
on October 2,1987.
The startup was conducted in a professional, controlled and orderly manner.
No inadequacies were identified.
The subsequent reactor scram from 18% power due to main turbine con-trol oil pressure problems was reviewed as described in Section 9.5.
8.4 Low Power Testing Various post-startup testing evolutions were observed by an augmented resident inspector staff. Activities were reviewed to determine com-pliance with procedures, adequacy of procedures, supervisory control,
adherence to technical specifications and test results.
Startup testing activities included safety relief valve lift test, reactor core isolation cooling (RCIC) overspeed test, reactor system hot hydrostatic test, containment inerting, high pressure coolant injec-tion (HPCI) and RCIC flow tests, main turbine testing, nuclear instrumentation calibrations and loop flow stability testing.
The inspector observed that implementation, coordination, and control of the test program were performed in a professional manner.
No inade-quacies were identified.
9.0 Operational Event Review 9.1 Reactor Scram:
August 7, 1987 On August 7, 1987 while in the process of plant shutdown for a scheduled refueling outage, a reactor scram occurred from 6% of rated power as a result of high reactor pressure. The pressure transient was caused by a malfunction in the turbine control system. As part of the shutdown process, pressure control was shif ted from the elec-trical pressure regulator (EPR) (a narrow range controller) to the mechanical pressure regulator (MPR) (a wide range controller).
A malfunction in the MPR caused turbine by pass valve closure, reactor i
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pressure increase and subsequent scram. The MPR inability to regu-
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late pressure was caused by a clogged pressure pulsation dampening F
(PPD) valve that prevented the MpR pressure sensing system from
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receiving an accurate representation of reactor pressure.
Further
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licensee investigation determined that the PPD valve and a portion of
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the-associated pressure sensing line were constructed of carbon i
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steel.
Corrosion products from these components accumulated in the v
.E PPD valve and caused a blockage, j
i Licensee corrective actions included carbon steel component replace-ment during the outage, system inspections and functional testing
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during plant startup. No deficiencies were noted.
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9.2 Loss of Normal Power l
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i On August 17, 1987, while the plant was shutdown in a refueling out-
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age, an interruption on the grid caused a loss of normal offsite
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power supplies. Onsite electrical loads were in a backfeed lineup
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from the offsite grid through the main and auxiliary transformers.
The power loss occurred when one of two parallel breakers to the main
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transformer tripped as a result of two transfer trips from a fault on l
the Northfield transmission line.
The other parallel breaker was i
t tagged open for preventive maintenance and was unavailable to provide
alternate power. Both emergency diesel generators started and sup-I l
plied power to all necessary systems. All engineered safety features
actuated as expected and all components operated normally. However, a
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mechanical bypass (PVC pipe) ruptured that was providing temporary
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i water from the fire system to the service water header which was
supplying the reactor building air conditioning units. The licensee
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postulates that the PVC pipe rupture resulted from initial drawdown i
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and probable voiding of that section of piping, which is a high point
in the fire system, followed by the quick and nearly simultaneous t
l starting of the fire and service water pumps when power was restored.
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The line rupture was secured by isolating the fire service supply
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valve.
The rupture caused a temporary overflow (backup) of the
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reactor building floor drains and some minor contamination of base-l i
ment floor areas.
Spill cleanup occurred within the next day. Nor-
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I mal power was restored and the diesel generators were secured within
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twelve minutes of the loss.
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The licensee response to the event was appropriate. The licensee is
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addressing two weaknesses exhibited by this event.
The first is a
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l procedural change to warn against routing all sources of offsite i
power through a single set of breakers.
The second is increased i
engineering review of mechanical bypasses to include analysis of the
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potential for pressure surges.
The resident inspector will review l
l licensee corrective actions during routine inspections.
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9.3 Suspension of Refueling Activities On August 20, 1987, while performing refueling activities, the licen-
. see determined that plant technical specification requirements for minimum core and containment cooling systems availability were not met.
Refueling activities were immediately halted and the mode switch was placed in shutdown. Technical specification (TS) 3.5.H.4 permits both low pressure coolant injection (LEI) loops, or both core spray (CS) loops, or one emergency diesel generator to be inoperable when irradiated fuel is in the reactor vessel and the reactor is in a refueling condition.
In this event, the reactor was in a refueling condition with irradiated fuel in the vessel, LPCI loop A was inoperable for maintenance, and emergency diesel generator DG-1-1B was considered inoperable because battery backup - control power was not available due to station battery A being out of service for testing. Failure to maintain minimum core cooling system avail-ability during refueling operation is a violation of TS 3.5,H 4.
The root cause for this event was a misinterpretation of technical specifications as to what constitutes the emergency d-c power supply for a diesel generator. Licensee determination of the root cause and appropriate corrective actions were prompt.
Interim clarification and guidance relating to this technical specification were provided to the operators.
Investigation of further clarifications necessary
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to avoid future misinterpretations is in process. The issue will be addressed in operator training.
Because the event was identified by
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the licensee, was reported in LER 87-11, was of low severity level, i
had prompt corrective actions taken and was not related te corrective actions for a previous violation, no notice of violation will be issued in this instance (50-271/87-16-01).
9.4 t.oss of Shutdown Cooling On August 24, 1987, while shutdown for refueling, a loss of shutdown cooling occurred when the operating residual heat removal (RHR) pump
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D tripped. The RHR pump D tripped due to a loss of an interlock from
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j the position indication of the shutdown cooling suction supply valve RHR V10-18.
Reactor water temperature was 90 degrees F at the time
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of the pump trip.
Operators placed alternate cooling in service l
using the reactor water cleanup and control rod drive systems, ver-ified maximum spent fuel cooling to the refueling cavity and spent fuel pool, and monitored vessel temperatures.
Reactor vessel tem-
t perature reached a maximum of 103 degrees F when normal decay heat
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removal was restored by restarting the RHR pump D af ter temporarily l
bypassing the RHR-18 valve interlock.
The licensee identified a failed coil as the cause of the faulty valve position indication.
The coil was replaced and RHR-18 was returned to normal service, j
Execution of off-normal operating procedures by operators following the loss of shutdown cooling was good.
No inadequacies were identifie.
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9.5 Reactor Scram: October 3,1987 On October 3, 1987, while performing a plant startup, the reactor scrammed from 18% power.
The scram was caused by a turbine control valve fast closure scram signal while bringing the main turbine up to speed in preparation for placing the generator in service.
Turbine control was being maintained by the load limiter and speed was being increased by raising the load limiter setpoint.
At low turbine speeds the turbine auxiliary oil pump develops the required control oil pressure. As turbine speed increases, crossover of oil pressure control between the auxiliary oil pump and the shaft driven oil pump occurs at approximately 1400 to 1500 rpm.
Licensee investigation determined that at lower speeds the auxiliary oil pump was providing insufficient control oil pressure. This resulted in a progressively larger difference being developed between the increasing load limiter setpoint and the actual turbine control valve position.
When the shaft driven oil pump took over pressure control, the resulting increase in control oil pressure caused a rapid opening of the con-
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trol valves to a position corresponding to the load limiter setpoint.
The rapid opening and subsequent overshoot caused steam flow to increase momentarily to the equivalent of 50% as measured by first stage turbine pressure.
This increase removed the automatic bypass of the turbine control valve f ast closure scram (30%). Since this scram signal had not been reset, upon removal of the bypass it caused a reactor scram. All safety and protection systems operated normally and the transient was stabilized within minutes.
The inspector observed corrective actions and preparations for sub-sequent startup including installation of augmented monitoring instruments t. the turbine control syPem. Subsequent reactor start-up was normal.
Bringing the turbine to rated speed was a closely monitored and carefully controlled evolution. No abnormal conditions were noted. The licensee is continuing to investigate the auxiliary oil pump poor performance and is formulating long term corrective actions.
The inspector had no further questions.
9.6 Additional Events Other operational events were reviewed by inspectors as part of the routine inspection program.
The events were reviewed to determine overall scope, level and appropriateness of licensee response, repor-tability, licensee documentation of event, corrective actions taken and planned, regulatory interface, and need for expanded inspector followup.
Attachment C identifies events that resulted in the licensee making required 10 CFR 50.72 notifications to the NRC, and Attachment 0 identifies non-notification events of interest.
No inadequacies were identifie.
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10.0 Release af Radioactive Material from the RCA The-inspector reviewed a
health physics incident report dated September 28, 1987, concerning the discovery of radioactive material out-side the radiation control area (RCA), but within the protected area.
Details of the event were discussed with the Plant Manager and the Plant Health Physicist (HP). During a routine survey of areas outside the RCA, a radiation protection technician discovered some trash bags containing ribbon used to demarcate radiation areas.
He determined that the bag contained no radioactivity. However, an expanded survey of the remaining trash in the dumpster identified one bag containing some dirt that read 500 cpm using an RM-14.
This is above the licensee RCA release limit detailed in procedure RP 0521. The licensee investigation also noted that several of the bags in the dumpster had not been tagged in accordance with their frisking policy.
This policy is part of a revised procedure and policy program developed in response to prev 1ously identified NRC concerns regarding control of radioactive materials The licensee concluded that
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the volume and pace of activity in the turbine building loading bay area (frisking control area) contributed to the radioactive material control system breakdown. Subsequent licensee analysis determined that the radio-active material was debris from insulation work in the turbine building.
Further, the insulation being used contained naturally occurring radio-activity. Regardless of the source of radioactivity (naturally occurring or plant generated), unmonitored release of the material outside the RCA represented a breakdown in the control system.
The inspector noted that although no regulatory limits were exceeded, the licensee procedural limits in RP 0521 were not met nor were various requirements of plant HP policies and guidance met. This specific incident did not create a sig-nificant hazard or safety concern. However, the incident was similar to previous losses of control over low level radioactive materials that occurred on February 26, April 21 and June 15.
In those past instances, failure to meet the frisking and release requirements of procedure RP 0521 constituted a violation of Technical Specification 6.5.B that was iden-tified by the licensee and where enforcement action was waived per 10 CFR 2.
However, in this incident, failure to meet the frisking requirements of RP 0521 and the frisking policy is a violation of Technical Specifica-tion 6.5.B that does not meet the waiver criteria of 10 CFR 2.
Specifi-cally, previous corrective actions for previous violations should reason-ably have been expected to prevent recurrence. Therefore, this incidence of failure to meet the frisking requirements, and previous incidents of failure to meet the radioactive material release limits, of procedure RP 0521 constitutes a violation (50-271/87-16-02).
The licensee corrective actions in response to this incident appear l
adequate.
In a memorandum from the Plant Health Physicist dated September 29, 1987, enhanced control and segregation of material in the l
turbine loading bay awaiting release from the RCA has been implemented.
L Additionally, the licensee has conducted a full review of contaminated material control practices.
Pending further inspector review during routine inspection activities of the results and effectiveness of licensee
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l action
'n this area, this item will remain open.
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11.0 Failed Residual Heat Removal Pump Motor Termination On September 28, 1987, while performing pre-startup residual heat removal (RHR) pump operability testing, the RHR pump B motor -experienced severe arcing and was immediately secured.
The licensee practice of having an operator located in the pump area during testing allowed rapid communica-tion of the problem to control room personnel who were able to secure the pump quickly. As determined by subsequent motor inspection and testing, this fast reaction prevented damage to the motor windings. The arcing was caused by a failure of the connection between the motor and power leads in one of the three phase connections of the motor. Further licensee inves-tigation determined that the exact point of failure was the termination lug on the motor lead.
Because the exact failure mode of the "B" RHR motor lug was unknown and considering that a
"D" RHR motor lead lug had been replaced in May 1987 during RHR pump wear ring inspections, the licensee determined that inspection and replacement of motor lead lugs on all recently worked pumps was indicated. This initial group included all RHR pumps and core spray (CS) pump B.
Subsequently, CS pump A wa's included in the inspection group.
The power lead lugs were inspected in place and did not exhibit any adverse deterioration.
The motor lead lugs were visually and dye penetrant (PT) tested following removal. Of the seventeen remaining motor lead lugs, seven exhibited varying degrees of cracking.
Most of the cracking was minor, however, one lug from the
"A" RHR motor exhibited a major crack that could have led to failure during the current operating cycle.
All of these lugs were original equipment supplied with the General Electric motors and were AMP (vendor / manufacturer), ring tongue (type), wire range 2 (size), model #35184. During inspection, it appeared that manufacturer stamping on the "throat" of the lug contributed to the observed cracking.
Also believed to be a contributor was a stamp (a numeral 1, 2 or 3) on the opposite side of the "throat" believed to be a phase indication. The cracking of these lugs was ultimately attributed to excessive bending during maintenance activities with the stamping provid-ing pre-stressed flaws for crack propagation.
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The confined work space inside motor terminal housings coupled with the rigidity of required Raychem splices contributed to fatiguing the lugs during maintenance activities.
The licensee further expanded the inspection to include RHR service water (RHRSW) and station service water (SW) pumps. The Westinghouse motors on these pumps wem found to have had the original lug connectors replaced with Thomas and Betts (T & B) brand lugs.
Those lugs were found to be generally in very good condition. This concluded the licensee investiga-tion. All of the RHR and CS motor lead lugs were replaced with T & B l
model 54148 connectors.
Those lugs appear to be of more substantial construction and more resistant to bending than the AMP lugs.
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ally, manufacturer stamping on the T & B lugs is on the "tongue" of the
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connector, removing it from the high stress "throat" area.
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The inspector observed much of the licensee investigation and corrective actions including de-terminating and reterminating motor lead connections and application of Raychem splices. Good quality work practices were used and quality control inspections were performed at appropriate process points.
An increased sensitivity to minimizing bending of electrical connections was evident but the confined work space still makes this a difficult task. The licensee investigation and corrective action process was timely and thorough. The inspector identified no deficiencies and had no further questions.
12.0 Periodic and Special Reports Upon receipt, the inspector reviewed periodic and special reports sub-mitted pursuant to technical specifications.
This review verified, as applicable: (1) that the reported information was valid and included the
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NRC-required data; (2) that test results and supporting information were consistent with design predictions and performance specifications; and (3)
that planned corrective actions were adequate for resolution of tne prob-lem.
The inspector also ascertained whether any reported information
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should be classified as an abnormal occurrence. The following report was reviewed:
Monthly Statistical Report for plant operations fw the month of
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September, 1987.
The inspector noted no deficiencies.
13.0, Licensee Event Reports The licensee event reports (LERs) listed in Attachment E were reviewed to verify report submittal in accordance with the requirements of 10 CFR 50.73.
For each report, the inspector verified that: (1) the LER accur-ately described the event; '(2) the root cause was identified; and (3) actions taken or planned were appropriate to prevent recurrence. No inadequacies were identified.
14.0 Management Meetings
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l At periodic intervals during this inspection, meetings were held with l
l senior plant management to discuss the findings. A summary of findings for the report period was also discussed at the conclusion of the inspec-tion and prior to report issuance.
No proprietary information was iden-tified as being in the inspection coverage.
No written material was l
provided to the licensee by the inspector.
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The resident inspector met with the plant manager to discuss the generic implications of operator inattentiveness.
The purpose of the meeting was to sensitize licensee management to the potential impact of allegations of sleeping employees in light of events at other facilities. The inspector indicated that the licensee should continue to maintain the present open line of communication to the NRC resident staff concerning known or sus-pected instances of inattentiveness.
The scope of these notifications should include both licensed and non-licensed individuals who are per-forming a regulatory-related duty or function.
The licensee agreed that such notifications were appropriate.
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ATTACHMENT A FACILITY ACTIVITIES Date Time Facility Operation / Event / Status August 1, 1987 12:01 a.m.
Reactor operating at 82% of rated power, continuing end-of-cycle coastdown using feedwater level control A August 2, 1987 12:30 a.m.
Power decreased to 79% of rated power for weekly surveillance August 2, 1987 1:05 a.m.
Weekly surveillance completed satisfac-torily; normal power operations resumed August 4, 1987 3:00 a.m.
Diesel generator (DG) A started for monthly surveillance August 5, 1987 1:25 a.m.
Ames Hill public notification system trans-mitter out of service; states and NRC notified 11:12 a.m.
'A'
secured; surveillance completed satisfactorily 12:24 p.m.
'B'
started for monthly surveillance 8:43 p.m.
DG 'B' surveillance completed satisfactorily August 6, 1987 Refueling platform checkout performed in preparation for fuel moves; two bundles moved August 7, 1987 3:00 p.m.
Reactor shutdown commenced from 80.4% of rated power for refueling / maintenance outage XIII (see discussion in Section 4.0)
9:36 p.m.
Generator off line 9:59 p.m.
Reactor scram as result of high reactor pressure which occurred soon after placing manual pressure regulator in control (see discussion in Section 9.1)
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Attachment A
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Date Time Facility Operation / Event / Status
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August 8, 1987 3:34 a.m.
Mode selector switch placed in Refuel 3:45 a.m.
Reactor coo.lant temperature <212 F August 10, 1987 1:32 p.m.
Reactor pressure vessel (RPV) head vent and level piping removed in preparation for head'
removal August 11, 1987 1:25 a.m.
Secondary containment capability test per-formed satisfactorily 6:38 a.m.
Control rod drive (CRD) 22-35 changed out; first of ten planned CRD replacements 2:05 p.m.
RPV head lift commenced 5:10 p.m.
RPV head pulled; placed in setdown area August 13, 1987 2:50 p.m.
Vessel fill completed 8:05 p.m.
Fuel pool gates removed August 14, 1987 7:10 a.m.
Fuel moves commenced 4:05 p.m.
Toxic gas system initiation on high carbon dioxide buildup in control room caused by inlet ventilation damper closing 6:15 p.m.
First suspect failed fuel assembly visually inspected; one pin found to have "massively" failed; preliminary results indicated fail-ure caused by crud-induced corrosion; failed pin was in a discharge bundle August 15, 1987 2:50 a.m.
Source range monitor (SRM) C found inoper-able during response check 11:00 a.m.
Fuel moves halted to revise schedule, to defer moves around SRM 'C'
3:55 p.m.
Commenced backfeeding offsite power through main transformer 4:10 p.m.
Fuel moves resumed with revised schedule
_ _ _ _ _ _
...
~
Attachment A
..
Date Time Facility Operation / Event / Status August 16, 1987 4:44 a.m.
Fuel _ loading activities secured due to problem _ with fuel 51oading schedule (step No.
204 was. missed allowing half of a fuel call to.be voided at locations 01~-22 and 01-24);
reactor engineer commenced an evaluation to correct problem 11:10 a.m.
Fuel reloaded in cell 01-24; fuel moves continued 4:00 p.m.
Fuel movements secured to allow maintenance work on proximity switch 6:10 p.m.
Fuel moves resumed Evening Fuel sipping suspended due to equipment in-compatibility with fuel assemblies -(sipping cans too short)
August 17, 1987 2:00 p.m.
Loss of normal (off-site) power as result of breaker 81-1T opening, due to two trans-fer trips from Northfield, apparently doing breaker testing;. diesel generator started (see discussion in Section 9.2)
2:05 p.m.
Mechanical bypass isolated to refuel floor air conditioning which developed leakage on start of fire pumps 2:12 p.m.
Normal power restarted; diesel generators secured 2:25 p.m.
Shutdown cooling reestablished August 18, 1987 12:50 p.m.
CRD 18-31 changed out; CRD replacement completed August 19, 1987 10:25 a.m.
Channel swaps completed; changeout of five local power range monitors (LPRMs) completed August 20, 1987 3:30 a.m.
Groun III isolation received during reactor building heating, ventilation and air condi-tioning (HVAC) and refuel area zone monitor surveillance per procedure OP-4511 n
_
.
l Attachment'A'.
,
.
Date Time Facility Operation / Event / Status August 20, 1987 3:20 p.m.
Fuel moves _ halted to' determine operability of low pressure coolant injection (LPCI)
loop B (see discussion in.Section 9.3)
4:40 p.m.
Mode-selector switch placed in shutdown, due to discovery that LPCI loop B was out of service while moving fuel; fuel moves remained halted August 21, 1987 10:25 a.m.
Breaker DC-1 replaced; diesel generator B and LPCI loop B. declared operable 12:26 a.m.
Mode selector switch placed in Refuel 1:30 a.m.
SRM response check completed; SRM _ 'C indi-cation remained downscale with detector fully inserted; SRM
'C' was bypassed
,
3:50 p.m.
Signal to noise (S/N) ratio. test satisfac-torily performed on dunking chamber in quadrant C 4:15 p.m.
Fuel moves resumed August 23, 1987 6:50 p.m.
Fuel moves suspended for proximity switch repair 8:50 p.m.-
Fuel moves resumed August 24, 1987 7:47 a.m.
Fuel sipping moves commenced in spent fuel pool 8:22 a.m.
Residual heat removal (RHR) pump D tripped, resulting in loss of shutdown cooling (SDC);
fuel movements secured (see discussion in Section 9.4)
1:22 p.m.
SDC restarted with RHR pump D 11:30 p.m.
CRD pump A tripped; fuel moves secured in reactor i
_ _ _ _ _ - - _ _ _ _ _ _ _ _ _.
_ _ _ _ _ _ _ _ _ _ _ _.
.,.
--Attachment A
.
,
Date Time Facility Operation / Event / Status August 25, 1987 12:01 a.m.
CRD pump A restarted; fuel moves resumed
-
12:45 p.m.
Core loading completed, core verification started 9:25 p.m.
Core verification completed 9:30 p.m.
House electrical loads shifted to startup transformer August 26, 1987 12:02.a.m.
Mode selector switch placed in Startup for shutdown margin check 12:19 a.m.
Mode selector switch returned to Refuel and locked 1:00 a.m.
Friction testing commenced 4:30 a.m.
Reactor scram received as result of main steam line radiation monitor greater than three times normal, caused by radiography in steam-tunnel 6:00 p.m.
Fuel sipping moves completed in spent fuel pool; two leaks identified.in discharge bundles August 27, 1987 11:07 a.m.
Friction testing completed 2:50 p.m.
Fuel pool gates installed 5:22 p.m.
Mode selector switch placed in Startup for in-sequence critical startups 6:10 p.m.
In-sequence critical startups commenced (refuel floor cleared of personnel)
8:20 p.m.
Reactor critical on sequence 12-A-2 8:28 p.m.
Reactor shutdown commenced 8:49 p.m.
Reactor shutdown, all rods at 00; mode selector switch placed in Refuel and entry authorized to refuel floor 9:05 p.m.
Mode selector switch placed in Shutdown; commenced outage phase III
- -..
. _ - -
-
_
.-..
.
.
.
.
Attachment A
'6-
,-
Date.
Time-Facility Operation / Event /St'atus August-27, 1987 9:48 p.m.
Cavity drain down - commenced to condensate storage tank via fuel pool cooling system in preparation for reactor vessel level reference leg modifications August 28, 1987 12:30 a.m.
Reactor water cleanup (RWCU) system isolated when pulling fuses for engineering design change request (EOCR) No.86-403; fuses were reinstalled and RWCU system was restarted August 29, 1987 10:25 a.m.
Drain down of standby liquid control (SLC)'
tank commenced for EDCR No.87-407 12:15 p.m.
SLC tank drained, filled to 80% capacity with demineralized water and heating commenced per EDCR No.87-407 6:20 p.m.
Reactor cavit9-hydrolazing completed-August 30, 1987 6:10 a.m.
Reactor vessel level instrument nozzles N-11 and N-12 hydrolazing completed; plug installations commenced 7:20 a.m.
Nozzles. N-11 and~ N-12 plugs installed in preparation for vessel level modifications (no detectable leakage)
August 31, 1987 12:31 p.m.
CR0 system secured, as system not needed for existing plant configuration; CRD pump rebuild commenced September 1, 1987 9:15 a.m.
SDC loop B flow lost while throttling valve RHR-27B - for vessel inspection (valve drove shut); SDC loop A was available if needed 9:40 a.m.
SDC loop B back in service September 2, 1987 7:15 a.m.
SLC chemical addition completed 2:38 p.m.
SDC secured for jet pump inspection 6:30 p.m.
>
,,.
- - - -
- -., -.. -..
-.
.
p Attachment A-
,
Date-Time Facility-Operation / Event / Status September-3, 1987
'5:00 a.m.
SDC secured for jet pump. inspection
-
10:40 a.m.
SDC started on RHR lo'op B 2:05 p.m.
SDC secured again to allow continuation' of in-vessel inspection 2:30 p.m.
Vessel inspection completed by reactor engineering and GE engineers; no problems noted 2:45 p.m.
SDC started on RHR pump B September 4, 1987 6:55 p.m.
Transformer T-8 de-energized, causing loss of RPS M-G
'A', which resulted in full scram and group isolations 7:10 p.m.
RPS M-G sets returned to service; scram and isolations reset September 8, 1987 8:50 p.m.
Bus 8 restored to normal power source and auto scram on RPS channel A received as expected; neutron monitor system trip also received on RPS channel B, caused by APRM
'D'
and 'F' actuations September 9, 1987 2:30 a.m.
RWCU, SDC and battery charger CB-1-1C secured for motor control center MCC-8B feeder breaker swsp for maintenance 2:56 a.m.
Spare breaker installed for MCC-8B feeder; RHR pump A' started on SDC, RWCU system started and battery charger CB-1-10 place.J back on station battery B 5:32 a.m.
Reactor building (RB) ventilation restarted and standby gas treatment (SBGT) ' A and B secured; control room operator received report of large water spill in area of southwest double door entry to RB when ven-tilation tripped; water traced back to HVAC RB exhaust fan area was reported as non-contaminated by health physics
..
.
.
. -
.
.
._
.
.
,
- ..-
-
~
' Attachment A-8
",
Date
~ Time-Facility Operation / Event / Status September 10, 1987.2:57 a.m.
MCC 8A. feeder breaker opened to allow main-tenance.to swap ' breakers;- expected auto
. scram received on channel A due to loss of RPS alternate power. supplying RPS bus A; auto ' scram' also received on~ channel B due to neutron monitor system trip, caused by.
inoperable APRM 'D'
and 'F'
3:20-a.m.
RHR -pump A was restarted -on SDC; RWCU back in service September 11, 1987 11:35 a.m.
Nozzles-N-11 and N-12 plugs removed September 12, 1987~ 5:15 a.m.
MCC 8A was returned to normal lineup
.5:35 a.m.
Reactor cavity water level raised for
- 10.:05 a.m.
moisture separator installation
,
,
12:01 p.m.
Group III isolation received from fuel pool radiation monitor- (refuel floor west) due to maintenance activity on refuel floor (moisture separator lifting)
12:15 p.m.
Group III isolation reset
12:35 p.m.
Moisture separator in latch position; com-menced decreasing reactor-cavity level September 13, 1987 12:40 a.m.
MCC 9A lde-energized for maintenance; expec-ted half scram and Group III isolation
.
received
,
,
12:43 a.m.
MCC 9A re-energized 1:00 a.m.
Trips reset from MCC 9A feeder breaker swap 5:15 a.m.
Reactor cavity level at vessel flange; draining secured
'
6:35 p.m.
On-site civil defense siren began sounding; Vernon fire department was notified and began investigating
,
.. -. -. -.
...
v
.
i Attachment A 9-
.
- -
.
. ~
Date Time Facility Operation / Event / Status September 13, 1987 6:50 p.m.
Vernon fire department' reported siren main-tenance contractor (Al Comm) had been notif-ied of on-site siren sounding false alarm;
rao#o stations were-contacted and were to pass word of siren failure 7:00 p.m.
Al Comm representative ~ reported. that a repairman would be onsite in approximately one-half hour 7:35 p.m.
Siren repairman arrived onsite and stopped siren sounding 8:35 p.m.
On-site siren repaired; failure attributed to a short across a pair. of control wires induced by carbon buildup and moisture; carbon was removed September 14, 1987 10:50 a.m.
RPS ' A' was returned to normal power supply; RPS 'B' was shifted tc alternate for RPS M-G
'B' maintenance; no problems occurred September 15, 1987 1:57 a.m.
RPS 'B' was returned to normal power supply 6:30 p.m.
Reactor water ' level was lowered below the RV flange in preparation for flange in-service inspection September 17, 1987 8:00 a.m.
DG room B reinsulation completed 8:55 a.m.
Vessel level lowered in preparation for main steam line plug removal 9:08 a.m.
Vessel drain completed down to top of separator 11:00 a.m.
Main steam line plugs removed 2:09 p.m.
SDC secured for LPCI loop B logic testing 3:00 p.m.
Main steam dryer placed in cavity 10:55 p.m.
Vessel head placed on vessel flange
-
i e
Attachment A
,
Date Time Facility Operation / Event / Status-September 18, 1987 2:44 a.m.
RHR service water (SW) pump -A and RHR pump A started on SOC L12:01 p.m.
RPV head tensioning commenced 2:45 p.m.
RPV head tensioning was completed 2:46 p.m.
DG 'A' overspeed testing was conducted; test was unsatisf actory. as trip occurred below the acceptable overspeed rpm limit 3:25 p.m.
'B'
overspeed testing was conducted-satisfactorily 3:50 p.m.
DG 'A' overspeed test re-conducted; test was again unsatisfactory (trip occurred at '970 rpm); MR No. 87-2323 submitted 4:47 p.m.
During core spray logic testing, core spray valve CS-128 breaker tripped open; also various LSR breakers tripped on MCC-8, -8A and-8B; maintenance electricians were-notified; all LSR breakers were reset and CS-128 breaker was reset; testing was redone without problems 10:05 p.m.
Core spray logic testing completed satis-factorily September 19, 1987 3:54 a.m.
Core spray valve operability surveillance
>
completed satisfactorily
,
7:00 a.m.
'A'
overspeed test attempted; test remained unsatisfactory (unit tripped at 980 rpm)
7:00 p.m.
Reactor head piping installed September 20, 1987 3:20 a.m.
Core spray pumps A and B operability tests completed satisfactorily September 21, 1987 12:32 p.m.
Emergency core cooling systems (ECCS) inte-grated automatic initiation test conducted satisfactorily (see discussion in Section 8.1)
.
v r
r
-
"
e
-, -
r-r
-
,y
. _ _ _ _ _ -___.
.,-
' Attachment A
.
'
Date.
Time Facility Operation / Event / Status September 22, 1987 11:17 a.m.
Neutron monitoring high half scram received; APRM 'B' found to be ' indicating 15% of full power; APRM
'B'
bypassed, half scram reset and I&C department notified 11:25 a.m.
LPRM 08-33 -found to be failed high, was-bypassed by I&C 11:30 a.m.
Internal inspection of torus completed satisfactorily 2:10 p.m.
'A'
started for maintenance to conduct overspeed test 2:15 p.m.
DG ' A' overspeed trip test was unsatisfac-tory (984 rpm)
2:18 p.m.
DG ' A' overspeed trip test conducted satis-factorily (989.5 rpm)
2:25 p.m.
DG ' A' overspeed trip test again conducted satisfactorily (991 rpm)
2:42 p.m.
DG 'A' started and loaded for eight-hour run 9:40 p.m.
Torus hatches installed 11:00 p.m.
'A'
secured from eight-hour run; com-pleted satisfactorily September 23, 1987 1:15 a.m.
DG 'B' started and loaded for eight-heur run 8:25 a.m.
SDC secured for RHR-17 motor-operated valve actuator tests (MOVATS)
9:35 a.m.
'B'
secured; eight-hour run completed satisfactorily 10:15 a.m.
CRD pump A started, to increase vessel level to flange 7:27 p.m.
CRD pump B secured; reactor water level at vessel flange
'
y
...
.
Attachnient A
,
Date Time
' Facility Operation / Event / Status September 24, 1987 12:30 a.m.
Reactor scrammed during I&C surveillance
'
testing per OP 4337 due to inadvertent skipping of procedure step which initiated alternate rod insertion (ARI) recirculation pump trip-(RPT).
7:40 a.m.
CRC. pump A was started to fill vessel to two feet above flange which was a hydrostatic test (hydro) prerequisite 9:40 a.m.
RHR pump D started for vessel heatup 11:59 a.m.
RHR pump D secured 6:07 p.m.
Reactor head vent was shut; vessel pressur-ization commenced for cold hydro (see dis-cussion in Section 8.2)
,
8:55 p.m.
Reactor pressure at 85 psig 9:37 p.m.
Reactor pressure at 500 psig 10:17 p.m.
Reactor pressure at 1020 psig September 25, 1987 12:45 a.m.
Cold hydro inspections completed satis-factorily 12:52 a.m.
Mode selector switch placed in Refuel 4:40 a.m.
Single' rod scram testing started 2:35 p.m.
I&C completed excess flow check valve sur-veillance with one failure (valve 2-13-19A)
Reactor engineer finished single rod scrams with the exception of rods 06-35 and 26-35;.
reviewing scram times for any retests 5:20 p.m.
Rod 06-35 determined to have had a drift-in problem caused by a scram inlet valve 6:55 p.m.
Mode selector switch placed in Shutdown 7:05 p.m.
Reactor pressure and level reductions commenced l
l
!
(
i
! _ _ _ _ _ _ _ _.
-
+
Attachment A
,
,
Date Time Facility Operation / Event / Status September 25, 1987 8:40 p.m.
RHR SW pump B was attempted 'to start; oper-ator noted that full load starting current was received, but the pump motor breaker then tripped free (amber lights) with no targets locally; MR No.
~87-2495 was-initiated September 26, 1987 10:s a.m.
The toxic gas system actuated on a spurious carbon dioxide (CO ) signal; the C0: indi-
cation was observed by operators to be cycling from zero to full scale; system was I
reset and an MR initiated f
f 5:39 p.m.
Stuck breaker (13 and 23) testing completed satisfactorily 9:15 p.m.
Shield blocks were installed September 27, 1987 6:50 a.m.
Mode. selector switch placed in Refuel 7:50 a.m.
RHR SW pump B was again attempted to start; start operation was completed satisfactorily and the pump was secured 4:45 p.m.
Mode selector switch placed in Shutdown 5:00 p.m.
Full scram and PCIS (primary containment
- 7:10 p.m.
isolation system) Groups I-VI surveillance completed satisfactorily September 28,1987 6:00 a.m.
During RHR system monthly surveillance RHR SW pump B would not start (see remarks for September 25, 1987 at 8:40 p.m.
and for September 27, 1987 at 7:50 a.m.)
7:40 a.m.
EDCR No.87-402, -Rockwell modifications, reported completed by engineering support department (ES0)
2:56 p.m.
Main steam isolation valve fast and slow closure timing tests completed sati sf ac-torily
.
)
4:30 p.m.
EOCR No.86-403, DG fan modification, reported complete by ESO
__
...
._
--
- .
Attachment-A
.
lDate Time Facility Operation / Event / Status Septembt.r 28, 1987 9:27 p.m.
RHR pump B was attempted to start for (Continued)
surveillance; auxiliary operator reported a two-foot ball of flame erupted from base of motor; control room operator immediately secured pump (about 'four-second run time);
bus 2 ground alarm received, but no local breaker targets; maintenance commenced an investigation of problem (see discussion in Section 11.0)
10:50 p.m.
RHR and RHR SW train A surveillance com-pleted satisfactorily September 29, 1987 '1:00 p.m.
MR No. 87-2442 was released for RHR pump D motor inspection 1:45 p.m.
Drywell closeout started; security notified 7:00 p.m.
Drywell closecut inspection completed with the exception of lighting 7:30 p.m.
Drywell access strong backs installed September 30, 1987 1:00 a.m.
Drywell personnel air lock leak rate test completed satisfactorily 3:30 a.m.
Inspections of motors and cables on RHR pump D and core spray (CS) pump B completed 4:13 a.m.
Hydraulic control unit (HCU) 06-35 scram-accumulator cylinder bottom flange blew an 0-ring; maintenance notified and MR initiated October 1, 1987 9:45 a.m.
CS pump A ran satisfactorily; also noted that SW pump A ran satisfactorily after terminal lug inspection / replacement 12:46 p.m.
Mode selector switch placed in Refuel for testing 1:02 p.m.
CRD 06-23 stroked to aid I&C conduct posit-
,
ion indication troubleshooting
,
)
.
,
,
' Attachment'A
.,
,
Date Time
' Facility Operation / Event / Status October 1, 1987 3:51 p.m.
Performed satisfactory pump runs following (Continued)
terminal inspections for SW pumps C and D 4:00 p.m.
As above, for RHR SW pump A 4:02 p.m.
As above, for RHR pump A 4:07 p.m.
As above, for RHR pump C 4:45 o m.
As above, for CS pump B 5:30 p.m.
Mode selector. switch placed in Startup for rod worth minimizer surveillance 10:20 p.:a.
Recirculation M-G sets A and B were started
- 10:22 p.m.
11:00 p.m.
Protection channel DPIS-2-120C placed in trip due to faulty switch (40% flow when not in Run)
October 2, 1987 12:01 a.m.
Continuous fire watch established in cable vault, as compensatory measure for failed damper from cable spreading area to battery room 12:15 a.m.
One-hour fire watch established for DG ' A'
day tank room, as compensatory measure for the No. 1 fire detector for the diesel day tank in the alarm condition 1:16 a.m.
DPIS 2-120C 40% flow isolation surveillance completed satisfactory; channel declared operable 1:20 a.m.
Reactor startup was commenced (see discuss-ion in Section 8.3)
2:20 a.m.
Reactor was critical on group 2 rod 26-31 position 10; reactor coolant temperature was i
198 F and reactor startup period was 72 seconds 2:32 a.m.
Turbine generator was placed on the jack 2:42 a.m.
Reactor coolant temperature was greater than 200 F
. -
,
Attachment A
,
Date Time Facility Operation / Event / Status October 2, 1987 8:20 a.m.
Reactor core isolation cooling (RCIC)
(Contir.ued)
turbine overspeed test was attempted, but the turbine tripped on high exhaust press-ure; operators suspended further testing while awaiting addition of oil to bearings 8:50 a.m.
RCIC turbine again tripped on high exhaust pressure; auxiliary operators attempted manual draining of turbine and exhaust line 9:22 a.m.
RCIC exhaust stop check valve RCIC-9 found by operator to be only one quarter open for unknown reason; RCIC-9 opened for attempting another overspeed test 9:25 a.m.
RCIC turbine tripped too high at 5825 rpm 9:52 a.m.
RCIC turbine ' tripped too high at 5800 rpm; adjustment to be made to overspeed mechanism 10:16 a.m.
RCIC turbine tripped too low at 5500 rpm 10:30 a.m.
RCIC turbine tripped too high at 5678 rpm 10:45 a.m.
RCIC turbine tripped too high at 5650 rpm 11:15 a.m.
RCIC turbine tested satisfactorily at 5600 rpm 11:23 a.m.
Reactor heatup being continued to hot hydro-pressure 11:45 a.m.
Drywell entry made at 200 psig reactor pressure, and no primary system leakage was observed 1:40 p.m.
Vernon offsite power tie line was renoved from service at Vernon end 1:55 p.m.
Fire watches were terminated at the DG ' A'
day tank room 2:15 p.m.
Vernon tie line returned to service
.
.,,.
...
,
t
.
.
-,-
.
.
-
-5-
- - - - - - - - - - - - -
a
.,.
? Attachment A
,-
,,
Date Time Facility Operation / Event / Status
- .
.0ctober 2, 1987 4:00 p.m.
CRD 22-35 did not have'"4P" indication;.
L (Continued)
reactor engineering and I&C notified
!
6:28 p.m.
Paactor pressure at 1028 psig 11:25 p.m.
Hot hydro. inspection completed in drywell; all conditions were satisfactory (see dis-cussioninSection8.2)
f
' October 3, 1987 1:28 a.m.
Mechanical pressure regulator (MPR) placed in service with reactor pressure about 910 psig 1:32 a.m.
Reactor operators commenced pulling rods and increasing power 2:07 a.m.
Electrical pressure regulator (EPR) placed in service after MPR pressure swings of 30 psi caused turbine bypass valve I to cycle from 80% open to close 2:20 a.m.
Mode selector switch placed in Run 10:46 a.m.
Control rods pulled to lh bypass valves open 11:00 a.m.
Pressure control shifted to MPR; adjustments-were in progress 11:55 a.m.
Operators commenced rolling turbine 12:05 p.m.
MPR pressure control was satisfactory; shifted to EPR control 1:56 p.m.
Reactor scram due to control valve fast closure; increase in turbine rpm occurred at about 1400 when the shaft lube oil pump cometenced supplying lube oil pressure; con-trol valve opening had armed the control valve fast closure and the scram occurred when the valves shut down (see discussion in Section 9.5)
3:07 p.m.
Cable vault fire damper declared operable; fire watch was secured 10:07 p.m.
Mode selector switch placed in Startup 10:45 p.m.
Reactor operators commenced pulling rods for reactor startup
_ _ _ _ _ _ _ _ - _ - - _
_
_ _ _ _ - _. _ _ _ - _ _ _ _ _ _ _ _
,
x
'Ir gy w
'!,ttachment A-
-. ;
,
Date Time
.FacilityOperation/Even_t/ Status October 4,11987.
12:34 a.m.
Reactor was critical-i6:15 a.m.
Containment..inerting was commenced (see
.
discussion of ~ low power. testing' in Section
.8.4)
6:35 a.m.
Mode selector switch placed in Run 7:50 a.m.
RWM was bypassed to. insert control rod 34-11 to its alternate position of "10" ; due to
reactor position-indication system (RPIS)
loss at "12";. RWM was. then returned to service and rod block cleared 9:00 a.m.
Operators. noted-increasing conductivity trends in both 'B' hotwells-9:25 a.m.
Control rods pulled to 1 bypass valves open (~20% of rated power)
11: 20 a.m.
Turbine rolling was commenced 12:15 p.m.
Turbine generator at 1800 rpm 12:39 p.m.
Generator synchronized to the grid 1:45 p.m.
Health physics : informed operators that-dry-well and torus oxygen concentration was at 6%
2:00 p.m.
I&C foreman reported that the hydrogen /
oxygen analyzers 'were calibrated and oper-able; System I indicated drywell oxygen was 2.7% and torus oxygen was 1.9%; System II indicated drywell oxygen was 2.8% and Torus oxygen was 1.9%
2:05 p.m.
Containment inerting was secured; operators commenced establishing drywell-to-torus differential pressure 2:45 p.m.
Operations surveillance (emergency communi-cations check)
was completed with the Vermont Nuclear Alert System phone check unsatisfactory; Westborough (Yankee Atomic Electric Company corporate office)
was
'
notified
[
'
_
k I
f
,g
/
$
Attachment.A-
Date Time Facility Operation / Event / Status
- October 4,'1987 7:07 p.m.
Main generator wa.; removed from the grid in-(Continued)
preparation for overspeed test, and a tur-
.
bine trip was received from moisture.separ-ator' high level; operations personnel decided to not reset-trip of that time to investigate oil pressures 7:40 p.m.
Operators attempted to bring the turbine up to speed, but lower viscosity of higher temperature oil prevented proper operation of turbine valves; turbine was shutdown while cooling oil October 5, 1987 9:15 a.m.
Turbine rolling was started 9:45 a.m.
Minimum speed oil trip was completed satis-factorily 10:41 a.m.
Generator was phased to the grid 11:50 a.c.
Commenced increasing reactor power to 23%
with the control rods 11:51 a.m.
Operators noted an increase in condenser B hotwell conductivity; also condensate demineralizer influent 1:10 p.m.
Reactor at 23% of rated power at hold point for startup testing October 6, 1987 12:15 a.m.
Commenced increasing power via control rods 1:15 a.m.
These electrical loads swapped to auxiliary transformer 3:45 a.m.
Commenced increasing power to 43% via recir-culation flow 3:55 a.m.
Reactor at 43% of rated power, hold point for startup testing 8:30 a.m.
Commenced increasing power to 50%
10:08 a.m.
Started decreasing power due to condenser low vacuum alarm, caused by south condenser north water box tube leak;
...
- - -
y
-
,
s
.,e.
Attachment A
i Date Time Facility Operation / Event / Status October'7, 1987 12:10 a.m.
' Commenced increasing power via recirculation flow 12:25 a.m.
At 42% power, commenced pulling rods to 50%
1:00 a.m.
Increased power to 58%
10:45 p.m.
Increased power to 70%
October 8, 1987 7:00_a.m.
Reactor at 78% of rated power 11:00'p.m.
Reactor at 82.?% of rated power October 9, 1987 7:00 a.m.
-Reactor at 88% of rated power 11:45 a.m.
Reactor core flow was decreased to minimum per reactor engineering startup plan
,
12:20 p.m.
Control rod and turbine tes'.ing was commenced at 61% of rated power 1:20 p.m.
Control rod and turbine testing completed satisfactorily
1:42 p.m.
Core flow at minimum for stability m)nitor-ing; reactor at 48% of rated power 8:32 p.m.
Recirculation system stability monitoring completed satisfactorily 11:00 p.m.
Rod pattern and recirculation flow adjust-
,
ments were continued; reactor at 61% of rated power
,
October 10, 1987 9:43 a.m.
Recirculation flow control placed in master
,
control
12:55 p.m.
I&C adjusted rod block monitor setpoint to 41% of rated power 11:25 p.m.
Standby liquid control (SLC) squib valve B lost continui+s indication on control room panel (CRP).,; indicated 0.2 milliamps (ma) by meter indication; began taking meter reading every two hours
. _ _ _ _ _ _ _ _
,,
,
V Attachment A-
Date Time
. Facility Operation Kvent/ Status October 11, 1987--
1:30 p.m.
' Operators commenced hourly PCIOMR increases 8:45 p.m.
System voltage was raised 2 Kv; SLC squib'
-
valve continuity loss alarm ' cleared (squib valve B at 0.22 ma with bus 8 at - 478v)_
October 12, 1987 8:30 p.m.
."CIOMR was completed at 1593 MW (thermal)
_
and 45.5 E'
lbs/hr core flow (essentially 100% of rated power)
October 14, 1987 6:25 p.m.
Alarm "PP Motor B VIB HIGH" received on recirculation pump B; other pump indications.
were monitored and none found abnormal 8:05 p.m.
Recirculation loop B flow experienced a decrease of 0.25 to 0.30 K gpm 9:50 p.m.
Recirculation loop B flow returned to pre-vious value 11:00 p.m.
Recirculation loop B flow again decreased same magnitude as previous occurrence October 15, 1987 12:07 a.m.
Recirculation pump. B experienced ongoing speed and flow oscillations with pump motor B vibration high alarm in and out; monitor-ing of indications for the cause of any abnormal operation was cor.tinued 1:37 a.m.
Recirculation pump B was placed in indi-vidual manual control to dampen oscillations 4:15 a.m.
Alterex and generator cold gas temperatures were adjusted per night orders, based on GE recommendation; Alterex bearing vibration points Nos. 9 and 10 decreased to normal values of four-to-five mils 7:30 a.m.
Recirculation pump B speed control placed
,
in automatic and pump speed reduced to 93%
6:20 p.m.
High vibration alarm on recirculation pump B came in and out; all other pump parameters were satisfactory
.
.
.,
-
cy r
- O l Attachment'A'
-22 Date Time Facility Operation / Event / Status October 16, 1987 1:50:a.m.
' SLC squib valve B' loss of continuity ' alarm
.
occurred at; 0.2: ma; system ~ voltage' was raised to clear alarm 4:15 p.m.
Recirculation pump B high vibration alarm came in; all other'. parameters were. satis-
-factory 9:30 p.m.
Reactor building closed' cooling water
"
(RBCCW) pump surveillance was performed; pumps were satisfactory but RBCCW pump B remained in Alert on differential pressure
-
11:15 p.m.
SLC squib valve B loss 'of continuity alarm-came in; SLC system II squib continuity was at 0.2 ma October 17, 1987 1:45 a.m.
SLC squib val've B loss of continuity alarm cleared 7:35 a.m.
Recirculation pump B high. vibration alarm cleared 8:03 a.m.
Reactor power reduction to 85% of rated power was begun for turbine surveillance and then to minimum recirculation flow for rod pattern adjustment 11:50 a.m.
Rod adjustments were
' completed; power increase was started with recirculation flow 11:25 p.m.
SLC squib valve B loss of continuity alarm
!
came in at 0.2 ma'
October 18, 1987 8:15 a.m.
SLC squib valve B loss of continuity alarm cleared
9:30 p.m.
PCIONR was completed; reactor at 100% of rated power 10:55 p.m.
SLC squib valve B loss of continuity alarm came in at 0.2 ma (
,
_ _ - _ _ _ _ _
d
- m.
~%
' Attachment A
Date Time Facility Operation / Event / Status October 19, 1987 2:40 a.m.
Recirculation pump B high v_ibration alarm came in; all other parameters were normal 6:30 a.m.
Operators noted an erratic trend on vessel level recorder; discovered feed regulating valve (FRV) A at 100% open, FRV 'B'
at 20%
open by local indication 6:40 a.m.
'B' was manually gagged with its hand-wheel and opened locally 7:00 a.m.
SLC squib valve B loss of continuity alarm-cleared with increasing system voltage 7:30 a.m.
'A'
and
'B'
were returned to normal operation; FRV 'B'
handwheel was backed off 10:30 p.m.
Surveillance testing of RBCCW pumps was per-formed satisfactorily; RBCCW pump B was no longer in Alert range 11:15 p.m.
SLC squib valve B loss of continuity alarm came in at 0.2 ma; house voltage was raised to clear the alarm October 20, 1987 9:30 a.m.
Security drill conducted
- 9:45 a.m.
9:55 a.m.
Fire drill cot. ducted in maintenance shop
- 10:15 a.m.
10:40 a.m.
Auxiliary offgas recombiner A isolation was received while shif ting between temperature sensors; operators shifted to recombiner B and after flow stabilized returned to recombiner A October 22, 1987 10:05 a.m.
Fire drill conducted in stock room
- 10:25 a.m.
October 25, 1987 12:30 a.m.
Power decrease was commenced to 90% of rated power for turbine and contre? rod surveil-lance 1:25 a.m.
Surveillance was completed satisfactorily; power increase was commenced to 97%, then PCIOMR to 100*4 of rated power (
___ ____ __________ _ __ - _
l
LVE'.s per
'h i
i fg-
~ Attachment A'
.
'
Date Time Facility Operation / Event / Status
,
t October 25, 1987 5:30 a.m.
'PCIOMR was completed; reactor at 100% of -
(Continued)
rated power 7 c2'?.. m.
High vibration alarm on recirculation pump B was in and out 12:55 p.m.
An offgas detonation appeared.to occur (offgas monitor flow low alarm came in with normal flaws reported by chemistry / health physics): MR was submitted October 26, 1987 9:15 a.m.
Standby gas treatment (SBGT) train A was started and reactor building ventilation was
!
secured for damper repairs
.
10:45 a.m.
SLC squib valve B loss of continuity alarm came in due to I&C work on circuit; con-tinuity was at 0.2 ma 11:55 a.m.
' Reactor building ventilation was restarted; SBGT train A was placed in standby 1:10 p.m.
SLC squib valve B loss of continuity alarm cleared; I&C changed alarm circuit ' detector bulb October 27, 1987 9:40 a.m.
Recombiner B was placed in service and recombiner A was placed in standby after seat leakage was detected on valve A0V-0G-101B 10:33 a.m.
Fire drill was conducted in south warehouse
- 10: 48 a.m.
October 28, 1987 10:02 a.m.
Operators notified Vermont, New Hampshire and Massachusetts state police of microwave radio replacement that would cause the NAS phone to be inoperable at 10:15 a.m. ; land line uced for calls to confirm backup communication channels 10:45 a.m.
NAS microphone work was completed; tested satisfactorily except Massachusetts due to maintenance at that end f
,.
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-.
- - - _ - - -
_ _ - _ _ _ _ _
. - - - - -
- - _ _ _ _ - - _ _ _ - - _ _ - - _ - _ - - - - _ _ - - - - - - _ _ _ - - -. - -. - - - _ _ - - - - - _ _ _ _ _ _ _ _ _ _ _ _ _ - - - _ - - _ _ _ _ _
- .,.
L'-g. # ~ '
-
,4
,
,
(4,.
Y
'
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-s Attachment A
l
,
,
Date Time Facility Operation / Event / Status
,
October 29, 1987 8:15 a.m.
Operators notified Vermont, New. Hampshire and Massachusetts state police of' microwave radio work that would cause NAS to be inoperable; land line used-'for calls ' to confirm backup channels 9:40 a.m.
Reactor engineering returned LPRMs35-25B and'24-25B to service 10:35 a.m.
Fire drill conducted in pipe storage
- 10:55 a.m.
building
'
2:32 p.m.
End of-facility operations review for inspection period (
.-
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k'
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h'
ATTACHMENT B INOPERABLE EQUIPMENT DURING INSPECTION PERIOD (See discussion in Section 5.3)
,
Date/ Time.
Date/ Time.
Inoperable System / Component-Cause'
Inoperable Operable Intermediate range monitor D - cause March 14, 1987 August 27, 1987 not determined by inspector _
8:00 a.m.
7:45 a.m.
Toxic gas monitors A & B - removed August 4, 1987
- August 4, 1987 from service to allow work on freon 1:00 p.m.
5:00 p.m.
lines Ames Hill nuclear alert system August 5, 1987 August 5, 1987 transmitter - cause not determined 1:25 a.m.
8:30 a.m.
by inspector Toxic gas monitors A & B - removed August 5, 1987 August 5, 1987 from service to allow work on freon 2:37 p.m.
3:20 p.m.
lines
,
Toxic gas monitors A & B - welding in August 10, 1987 August 10, 1987 area of cabinets 10:30 a.m.
10:55 a.m.
,
Reactor water cleanup system-unable August 12, 1987 August 13, 1987 to establish flow due to cleanup 8:28 p.m.
7:00 p.m.
-
spool installed in wrong location Toxic gas monitors A & B - bypassed to August 14, 1987 August 14, 1987 investigate cause of initiation and 4:50 p.m.
10:55 p.m.
to recharge air bottles
'
Toxic gas monitor B - cause not August 14, 1987 August 31, 1987 determined by inspector 11:30 p.m.
9:50 a.m.
Source range monitor C-failed during August 15, 1987 August 16, 1987 monitor response check 2:50 a.m.
1:35 a.m.
Toxic gas monitors A & B-failed to August 17, 1987 August 18, 1987 initiate on loss of normal power; 3:15 p.m.
11:12 a.m.
systems placed in Abort
' Toxic gas monitor 8 ammonia channel-August 19, 1987 August 31, 1987
'
setpoint greater than Technical 11:15 a.m.
9:50 a.m.
Specification limit low pressure coolant injection loop B-August 20, 1987 August 21, 1937
emergency power supply not available 4:40 p.m.
12:25 a.m.
.
.
w
,
, -.. -, - -
r
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
__
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k l
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Attachment B
.
Date/ Time Date/ Time Inoperable System / Component-Cause Inoperable Operable Source. range monitor C-indication August 21,'1987 August 25,J1987 remained downscale with detector 1:30 a.m.
3:30 p.m.
fully inserted; monitor channel bypassed Residual heat removal pump 0-failed August 24, 1987 August 24, 1987 relay 16 AK 31 in position indication-8:22 a.m.
1:22 p.m.
circuit af RHR suction valve V-18 resulted in logic trip Control rod drive pump A - tripped, August 24, 1987 August 25, 1987 cause not determined by licensee 11:30 p.m.
12:01 a.m.
Diesel generator A sprinkler system -
August 27, 1987 Sept. 17, 1987 removed from service to allow work 7:57 a.m.
1:45 p.m.
3" room
Diesel generator 8 sprinkler system -
Augu:'. 27, 1987 Sept. 17, 1987 removed from service to allow work 5:30 p.m.
1:45 p.m.
in room
<
Toxic gas monitor A - cause not August 31, 1987 Sept. 2, 1987
,.
determined by inspector 8:05 a.m.
12:37 p.m.
Toxic gas monitor 8 - I & C calibration Sept. 2, 1987 Sept. 9, 1987 t
12:38 p.m.
11:15 a.m.
l Service water discharge effluent Sept. 3, 1987 October 6, 1987 monitor - monitor calibration 6:45 p.m.
7:55 a.m.
Electric fire pump-breaker removed Sept. 10, 1987 Sept. 10, 1987 I
for preventive maintenance; spare 3:42 a.m.
5:25 a.m.
breaker installed
,
Electric fire pump-normal breaker Sept. 10, 1987 Sept. 10, 1987 reinstalled after maintenance 8:15 a.m.
10:15 a.m.
Service water pump D planned Sept. 11, 1987 Sept. 12, 1987 maintenance 9:50 a.m.
1:43 p.m.
Toxic gas monitor A - high alarms Sept. 12, 1987 Sept. 14, 1987 remained ir, after short duration 5:15 a.m.
12:55 a.m.
(
deenergization of motor control center MCC-8A for breaker swap i
,
,
.
.
-
_ _
_
_
,
_ _ _. -
._
____
_.
<
.
?
-
Attachment 8'
1.
r Date/ Time Date/ Time Inoperable System / Component-Cause Inoperable Operable i
Service water. pump B planned Sept.'12, 1987 Sept. 12, 1987 maintenance 7:55 a.m.
1:43 p.m.
Service water pump A planned Sept. 12,-1987 Sept. 12, 1987
~
maintenance'
2:30 p.m.
4:55 p.m.
,
Onsite civil defense siren -
Sept. 13, 1987 Sept. 13, 1987 short across control wires 6:35 p.m.
8:35 p.m.
ECCS battery charger A - cause not Sept. 17, 1987 Sept. 17, 1987 identified by inspector 11:15 a.m.
1:15 p.m.
-
- Toxic gas monitors A & B - I & C Sept. 21, 1987 Sept. 21, 1987 calibration 11:20 a.m.
2:20 p.m.
t Toxic gas monitors A & B - monitors Sept. 24, 1987 Sept. 24, 1987 bypassed for C0: surveillance in 9:40 a.m.
2:10 p.m.
,
switchgear room
,
Control rod drive assembly 06-35 -
Sept. 25, 1987 October 2, 1987 i
spontaneous drift in after withdrawal 3:30 a.m.
12:30 a.m.
attempt; assembly inserted and valved out Toxic gas monitor B carbon dioxide Sept. 26, 1987 October 22, 1987 channel - indication cycling from 10:07 a.m.
10:00 a.m.
zero to full scale
.
Cable vault damper from cable October 2, 1987 October 3, 1987
'
spreading area to battery room -
12:01 a.m.
3:07 p.m.
damper failed
.
Containment continuous air monitor October 8, 1987 October 8, 1987 particulate monitor - failed filter 5:10 p.m.
8:25 p.m.
advance
,
Toxic gas monitor A - I & C calibration October 21, 1987 October 21, 1987'
11:15 a.m.
1:15 p.m.
Reactor core isolation cooling (RCIC)
October 21, 1987 October 21, 1987 system - declared inoperable while 2:08 p.m.
3:05 p.m.
valve RCIC-15 was shut to allow packing adjustment on RCIC-16.
$
!
+
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' Attachment B
!
Date/ Time Date/ Time Inoperable = System / Component-Cause-Inoperable Operable'
~ Orywell equipment drain system - drain.
October-22, 1987 October 22, 1987
. valves closed for adjustment on 10:40 a.m.~
1:40 p.m.
!
inoperable valve LWR-95
,.
Toxic-gas. monitor B hydrocarbon and-October 22, 1987 October 23,'1987
'
ammonia analyzers-cause not determined 3:20 p.m.
2:50 p.m.
<
by inspector
'
Nuclear Alert System orange phone-
~ October 28, 1987 October 28, 1987 scheduled maintenance of microwave 10:15 a.m.
10:45 a.m.-
transmitter
,
i Nuclear Alert System orange phone-October 29, 1987 October 29, 1987
-
,
microwave upgrade work
'
8:30 a.m.
j
!
I P
.
,
L a
.
I
!
'
!
i
i I
t
!
.
!
"
f
'
!
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-,.-
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_ _ _ -.
-.
_, _ _ - _ _. ___,,
..
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.. -.
,-
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_ e ATTACHMENT C
'
REQUIRED 10 CFR 50.72 NOTIFICATIONS (See discussion in Section 9.6)
<Date.
Time Event August 5, 1987
~1:45 p.m.
Ames Hill public notification system trans-mitter out of service at 1:25 a.m. (one-hour notification per 10 CFR 50.72(b)(1)); States-of Vermont, New Hampshire and Massachusetts.
notified August 7, 1987 6:40 p.m.
Loss of security computer (one-hour notifi-cation; 24-hour security event report No.
87-94)
10:45 p.m.
Reactor scram at 9:59 p.m. (four-hour notif-ication per 10 CFR 50.72(b)(2)(ii))
August 17, 1987 2:40 p.m.
Loss of normal power upon breaker 81-1T opening at 2:00 p.m., due to two transfer trips from Northfield, apparently doing breaker testing (four-hour; 10 CFR 50.72 (b)(2)(ti))
2:42 p.m.
Loss of security computer (one-hour notifi-cation; 24-hour security event report No.
87-96)
August 20, 1987 3:40 p.m.
Group III isolation during reactor building HVAC (heating, ventilation and air condi-tioning) refuel area. zone monitor surveil-lance per procedure OP 4511 (four-hour; 10 CFR 50.72(b)(2)(ii))
4:40 p.m.
Low pressure coolant injection loop B out of service while moving fuel (four-hour; 10 CFR 50.72(ta(2)(iii))
5:10 p.m.
Sum total type B&C leakage exceeded limit stated in procedure OP 4030 (four-hour; 10 CFR 50.72(b)(2)(iii))
I i
L______.__.___._._._____._._.__
. _ _ _ _. _ _ _ _ _ _ _ _ _ _ _ _. _.. _ _ _
__
-
-
.
-.
.:
i Attachment-C
Date Time Event August 24, 1987 11:25 a.m.
Shutdown cooling lost at. 8:22 a.m.
when residual heat removal pump-D tripped; cause unknown. Fuel movements were secured (four-hour; 10 CFR 50.72(b)(2)(i))
August 25, 1987 9:55 a.m.
Failed primary coolant leak rate tests of -
valves SB-16-19-8, 9,10 and 23 and SB-16-19-6, 7, 7A, 78, 6A. and 6B (four-hour; 10 CFR 50.72(b)(2)(1))
August 26, 1987 4:55 a.m.
Reactor scram at 4:30 a.m. as result of main steam line radiation monitor greater than three times normal, caused by radiography in steam tunnel (four-hour; 10 CFR 50.72(b)
(2)(11))
August 27, 1987 11:05 a.m.
One-hour notification; 24-hour security event report No. 87-97 September 4, 1987 7:40 p.m.
Reactor protection system actuation at 6:55 p.m.
(four-hour; 10 CFR 50.72(b)(2)(ii))
September 5, 1987 2:10 p.m.
Abort of security computers due to typo-graphical arror put into software program on August 24, 1987 (one-hour notification; 24-hour security event report No.87-100)
September 8, 1987 9:55 p.m.
Neutron monitoring system trip on reactor protection system B at 8:50 p.m.,
caused by actuation of average power range monitor channels D and F (four-hour; 10 CFR 50.72 (b)(2)(ii))
September 10, 1987 4:15 a.m.
Reactor protection system actuation at 2:57 a.m.
(four-hour; 10 CFR 50.72(b)(2)
.
(ii))
September 13, 1987 1:15 p.m.
One-hour notification; 24-hour security event report No.87-102 7:05 p.m.
Inadvertent actuation of onsite civil defense siren at 6:35 p.m. (one-hour; 10 CFR 50.72(b)(1))
7:10 p.m.
State af Vermont notified
,.
.
.
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g.-
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e I '..*
..
L-
)
Attachment C
-
'Date Time Event September 13, 1987 7:20 p.m.-
States of Massachusetts and New Hampshire (Continued)
notifled-8:40 p.m.
Civil defense siren operational'
-September 19, 1987 8:11 a.m.
One-hour notification; 24-hour security event report October 3, 1987-2:25 p.m.
Reactor scram at 1:56 p.m., caused by con-
-
trol valve fast closure. (four-hour; 10 CFR 50.72(b)(2)(ii))
October 28, 1987 10:21 a'm.
Loss of-Nuclear Alert System (NAS) phone
.
during microwave upgrade work (one-hour; 10
'
CFR 50.72(b)(1)(v))
October ~29,-1987 8:50 a.m.
Loss of NAS phone during microwave upgrade work (one-hour; 10 CFR 50.72(b)(1)(v)
i
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ATTACHMENT D j
NON-NOTIFICATION EVENTS OF INTEREST (See discussion.in_Section 9.6)
Date Time-Event
~
August 14, 1987 4:05 p.m.
Toxic gas system initiatio i-in control' room, as result of high carbon-dioxide condition.
The control. room was evacuated of unnecessary personnel, air packs wera obtained and the health physics group was notified to' take air samples August 21, 1987_
9:10 a.m.
Medical emergency reported in diesel gener-ator room B; medical assistance team was j,
-
dispatched
'
9:15 a.m.
Medical assistance team reported that work-man in diesel generator room B had been feeling weak; no outside assistance was needed 9:40 a.m.
Workman _was being taken to Brattleboro hospital with private vehicle August 24, 1987 1:34 a.m.
Fire in laundry machines 1:40 a.m.
Power secured; fire reported out August 31, 1987 1:15 p.m.
Medical emergency reported; a man cut his ear in a diesel generator room. The medical
,
assistance team determined that the cut was not severe, and the man was taken to the hospital for stitches r
October 7, 1987 12:47 p.m.
Medical emergency reported in pipe storage warehouse; medical assistance team was dis-
!
patched 12:50 p.m.
Ambulance service was notified to transport the injured person to the hospital
.
1:15 p.m.
Ambulance departed to Brattleboro hospital with person who had suffered a lower back injury
.
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t ATTACHMENT E LICENS{E EVENT REPORT (LER) SUMMARY (See diicussion in Section-13.0)
LER Number Summary Description
'87-05
. Turbine control system malfunction results in~ reactor scram due to pressure transient 87-06 Missed standby liquid control - solution concentration samp-ling due to human error 87-07 1987 Appendix J, Type B and C failures due to seat leakage
.
87-08 Loss of power during shutdown due to routing all off-site power sources through one breaker 87-09 Relief valve accumulator failed leak test due to solenoid valve leakage 87-10 Inadvertent. primary containment isolation system actuation as a result of a defective procedure 87-11 Procedural (TS) interpretation leads to degraded condition during refueling 87-12 Scram due to radf ographers. following inadequate procedures 87-13 Inadvertent scram due to incorrect listing of electrical loads caused by operator error 87-14 Inadvertent scrams due to unexpected lack of inputs to the power range neutron monitors due to inadequate operator training 87-15 Reactor scram due to transient in turbin, control oil system
,