IR 05000423/1987021
| ML20236S683 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 11/23/1987 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20236S679 | List: |
| References | |
| 50-423-87-21, IEB-84-03, IEB-84-3, NUDOCS 8711300032 | |
| Download: ML20236S683 (19) | |
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U.S. NUCLEAR REGULATORY
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REGION I
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Report No.
50-423/87-21 Docket No.
50-423 License No.
Licensee:
Northeast Nuclear Energy Company i
P.O. Box 270
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IIirtford, CT 06101-0270
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Facility Name: M111 stone Nuclear Power Station, Unit 3 t
Inspection At: Waterford, Connecticut j
Inspection Conducted: September 22, 1987 - November 2, 198/
Inspectors:
W. J. Raymond, Senior Resident Inspector G. S. Barber, Resident Inspector E. L. Conner, Project Engineer 004 C. & de.Ae d.-
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_ 3/23/87 Approved by:
_E. C. McCabe, Chief, Reactor Projects Section 1B Date
_ Inspection Summary; Inspection on September 22, 1987 - November 3, 1987, 50-423/87-21.
I Areas Inspected:
Routine, unannounced inspection (133 hours0.00154 days <br />0.0369 hours <br />2.199074e-4 weeks <br />5.06065e-5 months <br />) during day and
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backshifts of: physical security; plant operations, including operational status reviews and facility tours; elimination of unnecessary annunciations; icst radiation exposure history; IEB 84-03; refueling cavity water seals; maintenance and surveillance; licensee event reporting; review of committee I
activities; and followup of licensee event reports (LERs).
I Results:
No violatione were cited and no unsafe plant operating conditions were found.
- isolation valve failure (Detail 4.1), control room annunciators (Detail 6.1), and feedwater heater shell relief discharge (Detail 6.3) were identified as concerns which will receive further NRC fc110w-up.
Two security events (Detail 3.2) will receive further consideration in j
conjunction with the recent specialist inspection of security (Report 50-245/87-22; 50-336/87-20; 50-423/87-18). Continued concern about lighted control room annunciators (Detail 9) has been identified to licensee management.
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TABLE OF CONTENTS Page 1.0 Persons Contacted.
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2.0 Summary of Facility Activities
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3.0 Observations of Physical Security.
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3.1 Temporary Inability to Deactivate Lost Badge...
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3.2 Unescorted Nisitors
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4.0 Review of Specific Plant Activities.......
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4.1 September 23 Reactor Trips.
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4.2 Unexpected Feedwater Isolation Signal
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5.0 Plant Operational Status Reviews
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5.1 Safety System Operability Review.
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5.2 Review of Plant Incident Reports.
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5.3 ESF System Walkdown
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l 6.0 Facility Tours
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6.1 Radiation from SLCRS Release Point.
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6.2 Control Building Isolation Deportability.
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6.3 Feedwater Heater Shell Relief Discharge Point
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7.0 Committee Activities
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8.0 Licensee Event Reports
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8.1 Review of Licensee Event Reports.....
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8.2 Licensee Event Reporting....
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9.0 Elimination of Unnecessary Annunciations
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10.0 Lost Exposure History.
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11.0 Maintenance..........
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12.0 Surveillance
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i 13.0 IE Bulletin 84-03, Refueling Cavity Water Seals (TI 2515/66)18 14.0 Management Meetings...................
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l DETAILS'
1.0 Persons Contacted Inspection findings were discussed periodically with the supervisory and
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management personnel identified below.
S.'Scace, Station Superintendent C. Clement, Unit Superinte_ndent, Unit 3 J. Harris, Acting Operations Supervisor M. Pearson, Unit 3 Operations R. Rothgeb, Maintenance Supervisor K. Burton, Staff Assistant to Unit Superintendent M. Gentry, Acting Engineering Supervisor D. McDaniel, Unit 3 Engineering R. Satchatello, Health. Physics F. Perry, Assistant Supervisor Health Physics R. Enoch, Unit 3 I&C 2.0 Summary of Facility Activities The plant operated at 100% power from the beginning of the inspection period until a reactor.. trip occurred at 1:51 p.m. September 23. Failure of a normally energized solenoid for the "A" Feedwater Outboard Containment Isolation Valve (CTV 41A) then caused a loss of feedwater flow to the "A" Steam Generator (SG).
The loss of flow caused the reactor to trip on Low-Low SG level. The valve was reopened after replacement of the failed solenoid. The reactor was made critical at 5:50 a.m. Se'ptember 24, and l
returned to full power at 10:00 a.m. September 26.
The plant began to coast down for the first refueling outage at 1:00 p.m.
October 15.
Coastdown rate was approximately 1% per day.
The plant began-I a load decrease at 4:00 a.m. October 30,.and began outage activities at 9:00 p.m. that date. The outage is scheduled to last about 58 days. Major work scheduled is refueling, resistance temperature detector (RTD) bypass manifold elimination, snubber reduction, steam generator sludge lancing, containment local leak rate testing, motor-operated valve testing, and safety system train-related maintenance.
3.0 Observations of Physical Security Selected aspects of site security were examined during inspection tours, including site access controls, personnel and vehicle searches, personnel monitoring, placement of physical barriers, compensatory measures, guard force staffing, and response to alarms and degraded conditions. The following items warranted inspector followup.
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3.1 Temporary Inability to Deactivate Lost Badge An individual lost his vital area badge inside the protected :rea on October 22, 1987. Because of onosing maintenance'and an additional minor problem with the surveillance system, the individual's badge could not be deactivated for six minutes.
The licensee notified the NRC via the ENS as required by 10 CFR 73.71(c).
The inspector reviewed the licensee's compensatory measures and had no further l
questions regarding this situation.
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3.2 Unescorted Visitors
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i Two apparent violations identified during the inspection involved visitors who were not properly escorted.
The first incident occurred on October 16, 1987 and involved a contractor employee who entered the protected area without completing all access requirements and without an escort. This contractor employee, authorized escorted access to the protected area, arrived for work at 6:48 a.m. on October 16, 1987.
The individual had been working daily at the site in a visitor status since October 13, 1987 and was awaiting the results of medical screening prior to being
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granted unescorted access.
Upon obtaining a visitor's badge from the
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access control officer in the North Access Point at 6:48 a.m.,
she proceeded into the North Access Point office area without the
required escort ind without completing all protected area entry
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search requirements. Once inside the protected area, the individual
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notified her supervisor by telephone of how she entered the site.
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Another employee with unescorted site access found the individual at 6:49 a.m. and remained with her, on his own initiative, to provide the escort function. The individual was subsequently taken to her work station in the North Warehouse, where she worked under escort.
Her supervision notified Security of the event at 10:10 a.m.
Security removed her from the protected area for questioning and
verified she had not entered any vital areas.
The employee admitted she knowingly entered the protected area without the required escort, even though she knew the requirements.
She was allowed to return to work on October 16, 1987 after being counseled on security require-
ments. The licensee notified the NRC HQ Duty Officer at 12:07 p.m.
I This event was reportable within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> per 10 CFR 73.71. The employee was subsequently denied further protected area access starting on October 19, 1987.
The inspector reviewed the event with the licensee.
Concerns
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identified included the method used by the employee to gain access,
the performance of the guard force, and the sensitivity of site
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personnel to security requirements.
Requirements for individuals providing escort were re-emphasized with station personnel by the licensee.
The licensee identified the access control officers who were on duty at the time and counseled them regarding their respon-sibilities for access control.
The licensee further notified the inspector on October 20, 1987 that the method for allowing visitor access would be changed pending further review and improvements to assure more positive control. The inspector concluded that these followup actions were responsive to NRC concerns.
The resident i
inspector will follow the licensee's subsequent actions.
In the second instance, on October 29, 1987, the inspector noted a visitor in the west vending machine area of of the Administration Building without a proper escort. The individual was informed of the need for an escort by the inspector and returned to the escort.
The inspector informed the licensee, who identified the individual and escort and interviewed them to determine their knowledge of security procedures. The escort was not aware of the importance of her escort responsibilities but had been trained in this area.
The escort was counseled by the licensee regarding the importance of obeying the rules for proper escorting.
The visitor was counseled and is not scheduled to return to the site in the future.
Additional measures are being taken by the licensee to insure escort are with visitors at all times. The licensee is requiring escorts to sign on a daily basis that they understand their escort responsibilities.
Previously, only one signature was required upon initial entry of the visitor. The need for heightened awareness of escort responsibilities was also identified to all supervisors at a daily Station Superintendents' meeting.
The above security events were addressed in a November 3, 1987 enforcement conference at NRC Region I.
4.0 Review of Plant Specific Activities Performance of operators and equipment was reviewed to ensure safe opera-tion. The following areas identify operations and equipment functioning that received specific inspector follow-up and review.
4.1. Reactor Scram - September 23
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With the plant at full power, the "A" Feedwater Line Isolation (FWLI)
valve (3FWS*CTV41A) failed closed on September 23. A reactor trip on Steam Generator (SG) "D" low-low level occurred 19 seconds af ter the valve started to close. The cause of the valve closure was failure of normally energized solenoid valve 50V-41A1.
The normally energized solencid open circuited, causing its associated FWLI valve to close.
The reactor was operating at steady state full power prior to the trip with the "A" turbine driven train feedwater pump and the motor
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driven main feedwater pumps in operation.
The "B" turbine driven
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main feedwater pump was out of service for replacement of the pump i
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seals. The "B" emergency diesel generator was also out of service for maintenance and the "A" emergency diesel generator was running to verify its operability.
The following sequence summarizes the transient:
13:51:28.460 Partial closure of "A" FWLI Valve (3FWS* CTV41A)
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"A" FWLI valve closed 13:51:47.296
"A" SG Low Low Level Trip (1st Channel)
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"A" SG Low Low Level Trip (2nd Channel)
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"A" Reactor Trip Breaker Open 13:51:47,640
"B" Reactor Trip Breaker Open 13:51:47.748 Turbine Trip Level shrink in the steam generators following the trip caused a feedwater system isolation on low level and automatic initiation of the auxiliary feedwater system as expected. The reactor and plant systems responded as expected to the trip and plant operators stabilized the reactor in hot shutdown using procedures E-0 and ES-0.1.
The resident inspectors responded to the control room to verify stable plant conditions and monitor licensee post trip recovery actions. Actions were timely, proper and demonstrated the licensee's safety perspective.
No inadequacies were noted.
This is the second such solenoid valve failure in 7 months.
During the first failure, the normally energized solenoid operated valve (50V4101) for CTV410 failed in the same manner causing a reactor trip on SG "0" low' low level.
(See Inspection Report 50-423/87-05).
Since this is the second failure, the licensee is having their Reliability Engineering department evaluate the failure mechanism.
The inspector will follow the licensee's review to determine the root cause of the solenoid valve failure.
The inspector reviewed Licensee Event Reports (LERs) to determine if there were other solenoid valve failures and noted that an inter-mittent failure of 3 FWS*CTV410 caused a reactor trip on September 6,
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1986 (LER 50-423/86-51-00).
It was assumed an intermittent open I
circuit caused its closure since the licensee could find no hydraulic
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or nitrogen leaks from the valve actuator.
Retect of the valve's closure time found it consistent with the other FWLI valves. The licensee identified potential failure mechanisms as excessive vibration and steam impingement from a packing leak.
The inspectors toured the FWLI valve area af ter the trip and noted that the "A" FWLI valve did have an active packing leak and that the
"B" & "0" valves had steam leaks due to open FWLI relief valves. The inspector questioned the licensee regarding the steam leaks. The licensee will include them in their assessment of the solenoid valve l
failure.
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The inspector reviewed the work order to replace the_ defective l
solenoid valve (M3-87-12395). The review found that the licensee f
followed_the applicable portions of Administrative Control Procedure
ACP-QA-2.02C, Work Orders. Additionally, the FWLI valve was tested
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to ensure it closed within the maximum allowable time limit of 5 seconds.
It closed in 1.7 seconds, satisfying the test requirements.
Following the reactor trip review and replacement ana retest of the
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"A" solenoid valve, the reactor was made critical at 5:50 a.m.,
l September 24. The turbine generator was on line at 1:00 p.m.,
L September 24.
Full power was achieved on September 26.
4.2 Unexpected Feedwater Isolation Signal A Feedwater Isolation Signal (FWI) was generated due to SG "C" high level while the plant was in Mode 4 in November 1, 1987.
FWI occurs
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during power operations. Normally, the signal causes a turbine trip, trip of all main feedwater pumps, and closure of the feedwater isolation, regulating and bypass valves.
(The turbine was already tripped, prior to entry into Mode 4.) Due to. leaky feedwater i
l regulating valves, the steam generators are normally fed up to 70% to i
75% and allowed to steam down.
However, during this event, SG 1evel
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increased enough to cause a FWI signal.
Steam generator swell due to steam dump valve modulation may have also contributed to the level increase. All systems responded as expected. After the actuation, feedwater system lineups and levels were restored to normal.
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inspector questioned the licensee regarding the event. The licensee stated that the combination of feeding a little higher than normal, in combination with SG swell and a'slightly reduced setpoint, caused the trip.
The operator involved was counseled on the importance of maintaining level in the required band.
The inspector had no further questions on this specific item.
It is noted, however, as an instance of inadequate personnel performance and will be evaluated further during overall review of licensee performance.
5.0 Plant Operational Status Reviews The inspector reviewed plant operations from the control room and reviewed l
the operational status of plant safety systems to verify safe operation of the plant in accordance with technical specifications and plant operating procedures. Actions taken to meet technical specification requirements when equipment was inoperable were reviewed against limiting conditions for operation.
Plant logs and control room indicators were reviewed to identify changes in plant operational status since the last review and to assess whethei changes in the status of plant equipment were properly documented in logs and records.
Control room instruments were observed for correlation between channels, proper functioning, and conformance with technical specification.s. Alarm
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conditions in effect were reviewed with control room operators to verify proper response to annunciated conditions and to verify operators were knowledgeable of plant status. Operators were found cognizant of control room indications and plant status with the exception of the item addressed in Section 6.1.
Control room manning and shift staffing were compared to technical specification requirements. No inadequacies were identified.
The following. specific activities were also addressed.
5.1 Safety System Operability Review The high pressure safety injection, quench spray, auxiliary feedwater, recirculation spray, charging, residual heat removal, safety injection accumulator, and the emergency diesel generator systems were reviewed to verify the systems were operable in the standby mode.
The review included consideration of: proper positioning of major flow path valves; operable normal and emergency power supplies; indicators and controls functioning properly; and a visual inspection of major components for leakage, cooling water supply, lubrication and general condition.
No inadequacies were identified.
5.2 Review of Plant Incident Reports The plant incident reports (PIRs) listed below were reviewed during
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the inspection period to: (1) determine the significance of the
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events; (ii) review the licensee's evaluation of the events; (iii)
I review the licensee's response and corrective actions for
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appropriateness; and, (iv) determine whether the licensee reported the events in accordance with applicable requirements. The reports reviewed were: PIR's 139-87 dated 6/25/87, 174-87 dated 9/23/87, 175-87 dated 9/26/87, 176-87 dated 9/29/87, 177-87 dated 9/30/87, 178-87 dated 9/30/87, 179-87 dated 9/30/87, 181-87 dated 10/2/87, 183-87 dated 10/3/87, 184-87 dated 10/4/87, 185-87 dated 10/7/87, 187-87 dated 10/13/87, 188-87 dated 10/14/87, and 190-87 dated 10/13/87. The following items warranted inspector followup:
PIR 139-87 dated 6/25/87, concerned a potential problem with the FSAR Chapter 14 analysis for turbine trip / loss of external electrical load.
The inspector noted that the licensee obtained notification of the potential concern based on a telephone call from the vendor on 6/24/87 and promptly evaluated the issue for specific applicability to Millstone Unit 3.
The results of the licensee's review, documented in the completed PIR on 6/25/87, concluded that the potential issue was not a problem at Millstone Unit 3.
The concern arose based on a review by the Nuclear Steam Supply System (NSSS) vendor of the turbine trip / loss of electrical load generic analysis.
In the safety analysis, no credit is taken for the reactor trip on turbine trip and protection for the transient is provided by the high pressurizer pressure and over-temperature delta-T reactor trips. The standard electrical system design is i
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assumed in the vendor's scenario in which a generatbr trip occurs approximately 30 seconds after the reactor trip, followed by a fast transfer to alternate (grid) power for the continued supply of onsite loads. The NSSS vendor postulated that, should a reactor trip not occur in the first 30 seconds following a turbine trip, then a complete loss of forced coolant flow should be assumed to occur due to a postulated failure in the fast bus transfer to offsite power.
Under this scenario, the-pcstulated loss of conlant flow occurs at essentially full power with the' reactor having' inlet temperatures 15F to 20F above nominal. The FSAR loss of flow analysis is not bounded by this event and the minimum DNBR design basis would be violated.
- The Millstone 3 electrical system design uses a generator output breaker between the generator and the main and auxiliary transformers and the 345 KV switchyard.
Upon trip of the' turbine, the generator output breaker is opened by the generator reverse current relay.
- 4 Power to the reactor coolant buses is assured by continuous feed from
the 345 KV switchyard via the main and normal station service transformers.
Should the normal feed fail, then a fast transfer to the reserve station service transfer supply occurs. The licensee
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determined that this issue was not a concern for Millstone 3 because no single failure could prevent the generator breaker from opening and also disable the fast transfer scheta. The inspector reviewed the station electrical system design and the generator control circuit and the fast transfer scheme, and identified no inadequacies in the licenste's conclusions.
The inspector had no further comment on this item.
P1R 177-87, dated 9/30/87, concerns an oil spill outside the Unit 3 intake structure oil boom area. The licensee notified the NRC in l
accordance with 10CFR50.72.
The oil boom is a set of oil absorbent cylindrical floats connected on a common rope to contain any oil from
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l-t the storm sewer outfall to a 500 square foot area. The inspector observed that a small sheen of oil was visible outside the oil boom.
The sheen, cbout thr?e to five feet in diameter, amounted to less
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than a cuo of oil. The licensee's environmental lab placed oil absorbent pillows and sheets in the area and cleaned up the sheen.
State officials ard the NRC were properly notified of the event.
l The event was caused by oil-water separator overflow into the turbine building sump. When the turbine building sump pump energized on high level, a small amount of oil was sent to the storm drains.
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travelled to the outfall directly above the oil boom area.
The majority of the spilled oil was enclosed by the oil boom.
However, a very small amount escaped past one of the two tie-off points of the boom. The licensee is precuring a newly designed oil boom to minimize leakage past these tie-off points. The inspector reviewed the flowpath and source of water and verified that no radiation was released. Additionally, the inspector reviewed the licensee's e
corrective actions and had no further questions. No unacceptable conditions were identified.
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5.3 ESF System Welkdown A complete walkdown of accessible portions of the Safety Injection (SI) system was perforud to verify operability. The licenseo's valve lineup procedure (CP 3308) was compared tc plant drawings (S&W
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'g DWG. Nos.12179-EM-112A-6,1128-h 213B-4) to ensure there were 'rio discrepancies.
Valvas in the flowpath were verf fled to be !n their required ESF Standby readin us alignment.
Equipment condition and support systems were inspected to ensure conditions diindt exist t
which might degrade system performance, includinga proper supports'
and hangers, appropriate housekeeping, adequate tream protection, no
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prohibited ignition sources ori flamk.able naterial, up-to-date instrument calibrations, and overall pump and valve conditions.
The q
inspector inspected accessible. areas tvf the SI system and no inadequacies were identified.
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6.0 Facility Tours The resident inspectors observed plant operations, maintenance, and surveillance activities during regular and back-shift hours to verify safe operating practices and that activities were condected in accordance with approv6d procedures.
The back-shift inspections included tours made at 8:00 p.n.; on September 24, 7:00 p.m. on September 28, 4:00 p.m. on October 25, and 3:00 p.m. on October 31.
fcsting and control of radiation, contamination and high radiation
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areas was reviewed. 'The use of p.ersonnei monitoring devices and l
compliance with RWP requirements was verified. Plant housekeeping
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controls were observed, including the control cf flammable and other hazardous materials. No inadequacies were identified.
6d Radiatfor. frorr, Supplegntal_ Leak Collection Rele&se System (SLCRS)
During 6 routine inspection of control room activities on September 28, the inspector discovered a high radiation level on HVR-198 as indicated by the yellow light for HVR-19B.
The control operator (CO) was questioned regarding the alarm.
The C0 was not aware of the alarm and there had been no mention of the alarm in shift turnover.
Frequent ouisance ' Radiation Monitoring System (RMS)
alarms inhibit operator ability to detect valid high radiation conditions.
This item is further discussed in Deta11.9 of this report. A review of histogran of HVR-19B activity shewed that it reached the alert level at approximately 3:00 p.m., September 28.
The reading shifted from an average level of 5.0 E-07 uCi/cc to 5.0 E-05 uC1/cc.
The inspector questioned the Assistant Operations Supervisor about the alarm to determine if he was aware of its status and if appropriate corrective actions had been taken. The inspector reviewed the alarm respnnse procedure with licensee personnel to ensm e adequate actions were taken.
The licensee completed the
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procedure as required.
In addition, the event was reviewed fcr deportability. The inspector noted that the lowest threshold for deportability was 1500 uCi/sec.
The inspector independently calculated that the actual release rate was about 1.5 uCi/sec.
The inspector continu7d to review the event to ensure the licensee determined the root cause. A review of the Shift Supervisor log
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showed that the Vacuum Degussifier for the Chemical and Volume Control System (CVCS) was shutdown at 9:33 a.m.
The Vacuum Degassi-e fier rcmoves hydrogen and fission gasses upstream of the Volume
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Control Tank (VCT).
Since it was out of service, normal leakage through charging system pump and valve packing would show increased
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radiatior levels. However, increased levels were not seen until 3:00 p.m. when the "A" Supplemental Leak Collection and Release Fan was
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stopped.
Radiation icvels were minimized since this system sweeps p-large quantities of air from the auxiliary building. Thus the
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activity was seen when the system was shut down allowing the activity x,
to build up. Adding to the activity buildup was +.h2 fission gas release to the Reactor Coolant System (RCS) from the September 23 reactor trip discussed in Section 4.1.
The inspector questioned the licensee to determine why this condition was not identified at turnover or by shift personnel. The licensee stated that there are numerous Radiation Monitoring System (RMS)
Alarms that annunciate throughout the shift due to spiking or improper setpoints.
These frequent nuisance alarms act to detract attention from valid alarms.
This matter is discussed further in Report Detail 9.0.
The inspector has noted this condition on control room tours and concurs with the licensee explanation.
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The licensee has established an RMS setpoint change study to reduce nuisance alarms and safeguard against the desensitization of licensed operators to frequent RMS alarms. The licensee expects to have procedures in place to allow resetting nuisance RMS alarms by the end of the first refueling outage.
The inspector will continue to follow licensee corrective measures in this area.
6.2 Control Building Isolation (CBI) Deportability
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During a routine review of control room t.ctivities, the inspector noted a CBI signal was initiated due to high radiation from HVR 16B.
HVR 16B is the Control Building inlet ventilation monitor.
Following a high radiation alcrm, it initiates a CBI, closing both Control Building inlet dampers and a kitchen fan damper.
Operators normally act within 60 seconds to reset the CBi in order to prevent the discharge of the control room bottled air supply.
Licensee personnel stated that the HVR 16A or HVR 16B spikes occur periodically throughout the day. A review of the logs showed an
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HVR 16A and HVR 168 spiking was previously identified by
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The inspector questioned the licensee to determine if the required reports are being made regarding these periodic events per 10 CFR 50.72 (b)(2)(ii).
The licensee initially identified that Plant Incident Report (PIR) 3-55-86 documented that a 30 day LER was required for the HVR 16A spiking.
The inspector questioned the need to make continued reports for each spiking occurrence that caused a CBI.
LER 86-11-0 stated that the spiking was a periodic problem and, as yet, no root cause could be determined.
Future spiking is suspected to be due to the same cause and as such will be reported as a single event as described in the LER. The inspector reviewed the LER and noted that, as long as the control room bottled air supply does not discharge, the deportability provisions of this LER will be met. The inspector concurred with the licensee's plan for reporting future spiking of HVR 16A and HVR 16B.
The inspector has no further questions in this area.
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6.3 Feedwater Heater Shell Relief Discharge Point During a routine tour of the turbine building, the inspector noted a potential industrial sr.fety hazard which concerns the discharge point of feedwater (FW) heater shell side relief valves.
The relief valve is piped into the shell side of the FW heater in the top center section. The relief valve discharge pipe runs downward alongside the heater to the floor.
The discharge pipe connects to a distribution nozzle that would relieve steam or water parallel to the floor in a fan shaped pattern.
The distribution nozzle would focus the steam or water spray in a full 360 degree pattern at floor level.
The area is roped off with Steam Relief Area signs.
Entry is prohibited unless work is required in the area.
The inspector has observed these controls and has noted that they adequately limit access to the area.
The inspector questioned the licensee regarding the effects of a relief valve lifting with a worker in close proximity to the distri-bution nozzle. The licensee stated the worker could be severely burned and possibly killed.
In addition, the licensee stated they are scheduled to hard pipe the reliefs away from worker accessible areas. Originally, the repair work had been scheduled for the first j
refueling outage but it has been delayed due to problems encountered with the engineering analysis.
Relief valves will have to be relocated on the shell side of each FW heater prior to repiping the discharge flowpath.
This relocation will involve the installation of
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new relief valve nozzle pads during the first refueling outage (PDCR 3-87-58). The repiping is presently scheduled to be completed during the second refueling outage. The inspector will continue to monitor the licensee's progress towards repiping the FW heater relief discharge piping away from worker accessible areas and completion of
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the work required by PDCR 3-86-093.
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o 7.0 Committee Activities The inspector attended meeting 87-139 of the Plant Operations Review Committee (PORC) on September 30, 1987 and reviewed the minutes for PORC meetings87-123 and 87-136.
The inspector noted by observation and/or from the written record that committee administrative requirements were
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(F met for the meetings, and that the committees discharged their functions
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in accordance with regulatory requirements. The inspector ob:erved a thorough discussion of matters before the PORC during meeting 87-139 and a
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good regard for safety in the issues under consideration by the committee.
No inadequacies were identified.
The following item warranted inspector followup.
l PORC meeting 87-123 reviewed a change to OP 3211A, New Fuel Assembly and F
RCCA Receipt and Inspection.
One of the changes involved the deletion of h
a clearance dimension on new fuel assemblies.
The distance between the l
fuel rod end plugs and the top and bottom nozzle had been an established,
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small clearance. The new requirement is no physical contact between the
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l end plugs and top or bottom nozzles and the full diameter of the end plug
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must be visible above the upper plane of the top grid and below the lower plane cf the bottom grid, respectf vely. The change was transmitted to the licensee by Westinghouse Memorandum 87NE*-G-0110, dated August 30., 1987.
The purpose of this change was to improve the quality of the fuel assemblies by precluding rod gap adjustment in the loading fixture.
It is possible that the procedure for adjusting rod gap can lead to distorted
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grid cells in the bottom grid. This condition is known to cause fuel rod failures due to fretting type corrosion.
The inspector questioned the licensee regarding the mechanical stresses that might be developed if a fuel pin came into hard contact with one of the nozzles during heatup. The licensee reviewed the matter and stated this event would be unlikely since the pins are slip fit into the spacer
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grids with very low contact pressure at each grid.
There is a very small pressure that must be exerted by each grid and a small total force that must not be exceeded from ali the grids.
Even with hard contact at one end, the pin would expand in the opposite direction due to the low drag force. The inspector stated that drag forces may increase significantly as the fuel assembly is structurally skewed due to neutron flux. The licensee stated that grid drag force should be exposure independent and that a pin should expand freely throughout its core lifetime. Addition-ally, the licensee stated that the Departure from Nucleate Boiling (DNB)
analysis has a significant allowance for rod bowing and that typical bowing is significantly less than that allowance.
The inspector reviewed
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the issue and had no further questions in this area.
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8.0 Licensee Event Reports (LERs)
This section documents the routine review of Licensee Event Reports (LERs)
and a concern with the terminology used when making 10 CFR 50.72 notifi-cations for LERs.
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8.1 Review of Licensee Event Reports LERs submitted during the report period were reviewed to assess accuracy, the adequacy of corrective actions, compliance with 10 CFR 50.'73 reporting requirements, and to determine if there were generic implications ~or if further information was required.
Selected corrective actions were reviewed for implementation and thoroughness.
The LERs reviewed were:
87-034-00, Reactor Trip due to Low Low Steam Generator (SG)
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Level Caused by Failed Solenoid Valve, September 23, 1987.
The reactor trip, due to low low level in the "A" SG, was caused by an open circuit in 3FWS*S0V41A1 which resulted in closure of
"A" SG Feedwater Isolation Valve 3FWS*CTV41A.
The root cause was identified as equipment failure.
This event was reviewed by the inspector in detail in Section 4.1.
The licensee's corrective actions were reviewed and no inadequacies were identified.
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86-58-02, Inadequate Radiation Monitor Surveillance Due to Inadequate Technical Specification Rev'ew.
At 1:00 p.m. December 17, 1986, while operating at 100% power in Mode 1, it was noted that surveillance procedures for effluent radiation monitors were inadequate to meet the requirements of the Technical Specifications (TSs). The effluent radiation monitors were declared inoperable, and the corresponding action
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statements were entered.
Periodic grab samples were obtained.
Surveillance procedures were revised and proper operation of effluent monitors was verified.
i Revision 1 of this LER identified a possible programmatic
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weakness in the surveillance procedures written to support TS l
requirements.
The licensee formed an Evaluation Team to analyze a sample of twenty surveillance procedures. A representative sample of surveillance were reviewed by this multi-disciplined team.
The procedures were reviewed for software usage, calculations, unit conversions, implementation of vendor supplied information, frequency, overall accuracy, and support of overall TS requirements. The licensee found no programmatic weaknesses although minor errors were uncovered and were reported in LER 86-58-02.
The inspector reviewed the licensee's corrective actions and no inadequacies were identified.
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8.2 Licensee Event Reporting Inspection Reports (IR) 50-423/86-21, 50-245/86-13, 50-423/87-05 and 50-245/87-12 address a problem with the Millstone event reports to the NRC Incident Response Center.
The problem involves the use of the term " General Interest Events," a term used by the State of Connecticut but not defined by the NRC, and not familiar to NRC
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officials who have received such non-emergency reports on the l
Emergency Notification System (ENS). After meetings with Millstone management, corrective actions including revision of Emergency Plan Implementing Procedure (EPIP) Form 4112-1 (General Interest Event on the front page) and training of shift personnel were proposed by plant management. The issue left open in IR 50-245/87-12 was documentation of the licensee's corrective actions.
By letter dated October 23, 1987, Northeast Utilities documented their corrective actions as follows.
All Millstone Shift Supervisors (SSs) and SS Staff Assistants
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(SSSAs) have received a memorandum from the Station Superintendent explaining the problem and giving explicit instructions that the term " General Interest Event" is not to be used when making 10 CFR 50.72(b)(2)(v) non-emergency reports to the NRC.
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The above instructions are being included in the formal training of emergency response personnel at Millstone.
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NNEC0 is working to alter their EPIP and reporting forms to derive a reporting system which has a more reliable human performance interface.
They expect that this action will be completed in November 1987.
During the current inspection period, the inspector discussed this problem with shift supervisors (SSs), their assistants (SSSAs), and plant management responsible for each unit. The SSs and SSSAs were knowledgeable about the problem and had received additional training on making ENS reports. The NRC Incident Response Center was con-tacted and provided information that, of the 15 event reports received from the Millstone units in the last two months, no reports contained the non-NRC words and the general quality of event classi-fication had noticeably improved.
The revision of event reporting forms will be reviewed during a subsequent routine inspection. The inspector had no further questions.
9.0 Elimination of Unnecessary Annunciator Windows Millstone 3 Team Inspection Report 50-423/86-12 documented a large number l'
of illuminated control room annunciators. Approximately 100 annunciators were lighted with the plant at 90% power. Discussion with the operations
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staff and reactor operators revealed that most were simply nuisance alarms.
However, two annunciators, the " computer" and the " radiation monitor," were significant in that they indicate when other multi point status devices are also in an alarm condition. Thus, a later input by an out-of-specification parameter could be masked by an already lighted annunciator and go unrecognized by the operators.
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The NRC concerns summarized in Report 86-12 were:
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Operators may become complacent in that, when alarms are either continuously energized or repeatedly cleared and re-energized, tha operators may not recognize or believe an actual alarm indication and may respond inappropriately.
b.
If several annunciators are continuously flashing in an unacknow-ledged state and an active alarm condition exists in another annun-ciator unit, operators may not readily distinguish which annunciator is the new, real alarm.
c.
Annunciators which are either continuously recurring or energized may distract the operators from monitoring other plant parameters.
The NRC requested that the licensee further investigate the high. umber of energized control room alarms. The licensee transmitted a report on June 19,1986 (J.F. Opeka to R. W. Starostecki), describing a multifaceted program that would reduce the number of lighted annunciators during plant j
operation to achieve a total " black board" concept. The proposed program
was to implement several plant modifications to alarms / annunciators to
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either delete those considered to be unnecessary, revise setpoints, or
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revise logic circuitry. The licensee also stated their intention was to complete these design improvements prior to the end of the first refueling outage.
In an August 27, 1987 letter from E. J. Mroczka to the NRC, the licensee reevaluated this commitment.
The licensee now plans to complete j
the annunciator reduction program on or before the third refueling outage.
t Additionally, this letter redefines the scope of the program. The
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t licensee reiterated their commitment to this program in the September 2, 1987 response to SALP Report 50-423/85-98. That response concurred in the board recommendation to reduce lighted annunciators.
The inspector has noted that the number of lighted annunciators is now on the order of 30 to 40 at any one time. Although this is a significant reduction, operators tend to be desensitized to frequent annunciators associated with the Radiation Monitoring System (RMS).
Annunciators are illuminated from the RMS on a frequency of 10 to 50 times per hour during
power operation.
In response, operators must stop to read the alarm l
printer and verify no abnormal radiation condition exists.
This frequent
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annunciation was a direct contributor to an operator's failure to discern a high radiation condition as described in Detail 6.1 of this report.
The inspector will continue to monitor licensee actions to minimize the frequency of RMS alarms.
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Annunciations from other windows are less frequent but still tend to distract operators from safe operations.
PDCR MP3-87-032 has been issued I
to revise the associated logic and eliminate four existing annunciators.
The inspector will continue to follow the licensee's progress on this PDCR and will continue to monitor the completion of the annunciation reduction program. Also, performance such as that associated with the above noted failure to discern an alarm condition will be evaluated during licensee
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performance assessment.
10.0 Lost Exposure History A Stone & Webster contract employee contacted the Resident Inspector on November 29, and stated that he had not received his exposure history from
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a prior work location, the Grand Gulf Nuclear Power Station. He stated
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that the exposure history had not been sent to him as required by 10 CFR
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20.408.
The Grand Gulf Senior Resident Inspector was contacted.
It was found that the individual's exposura history was sent to him within the a
required 90 days but was returned marked " Moved-Left Nu Forwarding Address." Thus, the requirements of 10 CFR 20.408 were fulfilled. The licensee's first request for the individual's exposure history was reportedly sent to Grand Gulf on June 6,1987 but was not received. A
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subsequent request sent by the licensee was received by Grund Gulf on October 14. Grand Gulf dosimetry personnel faxed the individual's exposure records at 4:30 p.m. the same day.
The licensee was unable to locate the exposure history sent via this fax. Grand Gulf sent the records again on October 30. The licensee received the records and the inspector had no further questions in this area.
11.0 Observation of Maintenance c,
The inspector observed and reviewed selected portions of preventive and corrective maintenance to verify compliance with regulations, use of administrative and maintenance procedures, compliance with codes and
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standards, proper QA/QC involvement, use of bypass jumpers and safety tags, personnel protection, and equipment alignment and retest. The following activities were included:
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Repair of "A" Feedwater Line Isolation Valve (3FWS*CTV41A).
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Verification of MOV testing data.
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Resin Hold Tank Desludging.
No inadequacies were identified.
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12.0 Observation of Surveillance Testing The inspector observed portions of surveillance tests to assess performance in accordance with approved procedures and Limiting Conditions of Operation, removal and restoration of equipment, and deficiency review and resolution. The following tests were reviewed:
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l Main Turbine Stop Valve Stroke Time, SP 3623.3.
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Main Turbine Generator Stop and Control Valve Tightness Test, SP
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Main Turbine Generator Testing, OP 3623.1-3.
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No inadequacies were noted.
13.0 IE Bulletin'84-03, Refueling Cavity Water Seals (TI 2515/66)
The inspector reviewed the actions taken by the licensee to meet the requirements of IE Bulletin 84-03 dated August 24, 1987.
The licensee responded to the bulletin by letter. dated November 29, providing the results of their review regarding the potential for failure of the refueling cavity water seal on Millstone Unit 3.
l The inspector determined that the licensee adequately responded to the bulletin issues by identifying the worst credible failure mode, and by including in their response an eva?uation of the potential consequences of-the failure.
The licensee determined that the worst case credible event would be the catastrophic failure of the inner redundant neoprene gasket seals. The inspector independently reviewed the design of the cavity s'.al as described in S&W Drawing 12179-EV and identified no inadequacies in the licensee's conclusions.
The licensee concluded that, for the worst case credible failure, an operator would have sufficient time to mitigate the event by placing spent fuel assemblies in safe storage locations, and to establish a source of make-up to the cavity and spent fuel pool in time to
. prevent fuel uncovery at all safe storage locations. The licensee further
~ determined that, although direct line-of-sight dose rates in the containment or the spent fuel building area would be high following the postulated
.ent, the offsite doses were negligible (and thus well within the 10 CFR ' art 100 limits) and the onsite doses were acceptable.
The inspector identified no inadequacies in the licensee's conclusions based on a review of the evaluation and the tabulated results.
In their response, the licensee identified several followup actions that would be taken to complete the evaluation of the event, including:
(i)
further study of the adequacy of the calculated time interval available to the operator to place fuel in transit into a safe storage location ; (ii)
evaluation of the consequences of dropping a fuel assembly in transit in the cavity on the cavity seal; (iii) evaluation of activities that would store bundles in the spent fuel cask loading area to verify that activity would not result in a more limiting event; and, (iv) review of refueling procedures to verify they contain adequate operability verification of systems used to alert the operator to a decrease in cavity water level -
namely, the spent fuel pool low level alarm, the containment sump level instrumentation, and the area radiation monitors.
The inspector noted that the licensee planned to complete the above activities by the 1987 refueling outage.
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The following items will also be reviewed per the TI 2515/66 inspection I
requirements: adequacy of the licensee's failure mode evaluation, hydrostatic or preoperational tests of seal integrity, adequacy of licensee seal inspection procedures, adequacy of the failure consequence evaluation, adequacy of the calculation method for cavity drainage time, verification of makeup sources and the adequacy of makeup rates, and verification that procedures for mitigating seal failure are approved,
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documented and implemented.
The completion of the licensee's actions on the above items will be reviewed during a subsequent inspection.
l 14.0 Management Meetings II
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I Periodic meetings were held with station management to discuss inspection findings during the inspection period. A summary of findings was also discussed at the conclusion of the insnection, No proprietary information was covered within the scope of the inspection. No written material was given to the licensee during the inspection period.
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