IR 05000245/1989023
| ML20005G219 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 12/29/1989 |
| From: | Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20005G215 | List: |
| References | |
| 50-245-89-23, 50-336-89-22, NUDOCS 9001180294 | |
| Download: ML20005G219 (39) | |
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION I
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Report'No.
50-245/89-23: 50-336/89-22
- Docket No.
50-245; 50-336.
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License'No.
Licensee:
Northeast Nuclear Energy Company
,y-P.O. Box 270-Hartford, Connecticut 06101-0270
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' Facility Name: Millstone Nuclear Power Station, Units 1&2
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p Inspection at: Waterford, Connecticut-
e Dates:
September 6, 1989 - October 20, 1989
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Reporting L
Inspector:
P.-J. Habighorst, Resident Inspector
Inspectors:
W.'J. Raymond, Senior Resident Inspector j
P. J. Habighorst, Resident Inspector D. A. Dempsey, Reactor Engineer, DRP, Section 4A N.
. Dudley, Project Engineer, DRP, Branch 4 Approved by:
8N/auu[~4 42/r#q Donald R. Haverkamp, Chief, K ctor Projects Date j
Section 4A, Division of' Reactor Projects
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Insp'ection Summary:
Combined ~ Inspection Report Nos. 50-245/89-23 and 50-336/89-22
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Areas Inspected:
Routine NRC resident and specialist inspection of plant operations, surveillance, maintenance, previously identified items, engineering / technical support, committee activities, radwaste transportation, j
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allegation follow-up, plant incident reports, licensee event reports, and
security.
Results:
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General Conclusions on Adequacy, Strength or Weakness in Licensee Program
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Good. operations control of plant transients was noted; specifically, the i
reactor scram at Unit 1, and turbine stop valve closure at Unit 2
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-(sections 3.5.1 and.3.5.2).
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Weaknesses were noted in initial licensee corrective actions on a Unit 2 fire barrier seal repair (section 5.5); and, modification /PORC review of Unit 1 instrument air compressor reliability and availability (section 6.2.2).
l 9001180294 900103
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{DR ADOCK 05000245 PDC
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2.
Violations-Within the scope of-this inspection, one violation and one apparent violation were observed. The violation involved ineffective implemen-tation of' scheduling, tracking and performance of required surveillance at
' Unit 1 (sections 5.3 and 8.5).
The apparent violation involved a shipment
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of a limited quantity of radioactive material with exterior dose rates in excess of 49CFR 173.421 limits (section 4.2).
3.
Unresolved Items Two unresolved items were opened, and three items were closed during-the inspection period. One item is open pending a utility evaluation to assess the fire consequence of a Unit 2 open fire barrier seal (section 5.5)..A second item involves the adequacy of licensee corrective actions to correct programmatic weakness in the health physics program for the unconditional release of material from the site (section 4.3).
The unresolved items closed involved the adequacy of QA/QC involvement in LLRT program, manu-facturer notification of. environmental qualification concerns regarding Limitorque melamine torque switches; and failure to complete surveillances in the required time interval (sections 6.4.1, 6.4.2, and 8.3).
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i TABLE OF CONTENTS Page'
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1.0 ' Persons Contacted (IP 30703*)...................
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- 2.0 Summary of Facility Activities..................
- 3.0. Plant Operations (IP 71707/71710/93702)...
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3.1 Control Room Observations.......,.........._.
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3.2 Plant Tours........................-..
3.3 Stand-by Readiness of Engineered Safety Feature Systems and System Walkdown - Unit 2................
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3.4 Review of Plant Incident Reports...............
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3.5 On-site Followup'of Operational Events...........
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' 3.5.1 Reactor Scram due to Turbine Trip on High Reactor
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Level - Unit 1....................
i 3.5.2 Secondary Steam Leakage Inside Containment - Unit 2..
3.5.3 -Turbine Control Valve Closure - Unit 2........
3.6 Summary...........................
4.0 Radiological Controls (IP 71707/92701)..............
4.1-Posting and' Controls of Radiological Areas..........
4.2 Radwaste Transportation - Millstone' Station........
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4.3 Contaminated Tools Discovered in Offsite Warehouse.
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4.4 Summary............................ '13
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5.0 Maintenance / Surveillance (IP 62703/61726/92702)..........
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5.1 Observation of Maintenance Activities - Unit 2........
5.2 Grine11 Snubbers - Unit 2..........-........
5.3-Observation of_ Surveillance Activities - Units 1 and 2-
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5.4 Maintenance-~ Conducted During Downpower - Unit 1.......
5.5 Corrective-Activities-Fire Seal Inoperability - Unit 2.... _16 i
5.6 Summary...
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6.0 ' Engineering / Technical Support (IP 92700/92702)..........
6.1 Plant Design Modifications - Unit 1.............
6.2 Engineering Support of Plant Operations...........
6.2.1 Reactor Coolant System Hot Leg Temperature Indications - Unit 2..........
6.2.2 Modification of the Control Circuitry for
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Instrument Air Compressors - Unit 1....
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6.3 Inservice Testing - Unit 2..................
6.4 'Previously Identified Items - Unit 2..
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6.4.1 (Closed) UNR 50-336/86-28-01:
Adequacy of QA/QC Direct Involvement in the Local Leak Rate Testing Program.
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6.4.2 (Closed) UNR 50-336/88-28-01: 10 CFR 21 Report,
"Limitorque Melamine Torque Switches.......
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6.5 Justification for Continued Operation Evaluations -
Units 1 and 2....................... 24 6.6 Summary.
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g Page 7.0 Security-(IP 717107)....................... 26-7.1 Security Tours.,....................... 26 7.2 Review of Security Perimeter................. 26 7.3 Security Guard Fitness for Duty...........
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7.4 Allegation Concerning Security. Post Manning During Severe Weather Conditions..................... 27 7.5 Summary....,.....:........-.... -...... 27
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8.0 Safety Assessment / Quality Verification (IP 30703/40500/90712/92702).................. 28:
8.1 Committee Activities..................... 28 8.2-Periodic Reports - Unit 2.............
.... 28 8.3 Previously Identified Item (Violation / Deviation)
(Closed) UNR 50-245/89-12-01: LER 89-10, Failure to Complete Surveillances in Required Time..........
8.4 Surveillance Procedure Timeliness............-.. 29 8.5 Licensee Event Reports (LER) Review.............
8.6 Summary....
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9.0 Reactive Inspection Activities (IP 92702).............
9.1 NRC Bulletin / Generic Letter /Information Notice........
9.2 Allegation:
Reactor Protection System (RPS) Matrix Testing (RI-88-A-0040)..-..................... 33 9.3 Followup on Previous Allegations............... 35 10.0 Management Meeting........................
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- The NRC inspection manual inspection-procedure (IP) or temporary
' instruction (TI) that was used as inspection guidance is listed for each applicable report section.
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DETAILS
.1.0L Persons Contacted
1 Interviews'and discussions were conducted with licensee staff and management during the report period to obtain information_ pertinent to the areas inspected.
Inspection findings were discussed periodically with the supervisory and management personnel identified below.
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S. Scace, Millstone. Station Superintendent
- J. Stetz,. Unit 1 Superintendent i
N.' Bergh, Unit 1 Maintenance Supervisor
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W. Vogel, Unit 1 Engineering Supervisor
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- P. Prezkop, Unit 1 Instrument and Controls Supervisor R. Palmieri, Unit 1 Operations Supervisor
- J. Keenan, Unit 2 Superintendent J. Riley, Unit-2 Maintenance Supervisor
F. Dacimo Unit 2 Engineering Supervisor l
- J. Becker, Unit 2 Instrument and Controls Supervisor
.j J. Smith, Unit 2 Operations Supervisor
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- Attendee at' post-1nspection ' exit meeting on November 3, 1989,
2.0 Summary of Facility Activities Millstone 1 i
During the period between September 6 and October 19 the unit remained at
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power.
Various downpower evolutions occurred to repair balance-of plant i
equipment, repair condenser tube leaks, and conduct required turbine stop valve surveillances, i
On October 4, a partial participation emergency planning exercise was conducted. The NRC evaluated and participated in the response to the
emergency exercise. The results will be documented in NRC inspection
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report 50-245/89-81.
On October 19, plant power was reduced to 50% of rated power to perform routine testing and maintenance, including adjustment of the "B" feedwater
regulating valve (FRV) packing. While returning the "B" FRV to service at 3:16 p.m., control of feedwater flow was lost due to a malfunction of the
"A" FRV.
The turbine and reactor tripped when vessel level reached the high level setpoint (see section 3.5.1).
The plant was taken to cold shutdown at 9:34 p.m., October 19, to conduct repairs.
The plant remained shut down at the end of the report period pending repairs to the feedwater pump discharge check valves.
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' Millstone 2
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The unit operated at rated power unt11' September 9 when the No. 2 turbine
-control valve inadvertently closed.
The unit was restored to full power
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untilsSeptember 12 when the control valve again went closed.
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. events the unit downpowered to 90% of rated power. The control valve remained shut throughout the remainder of the inspection period,.and the plant was operated at 92% of rated power.
e NRC Activities On September 28, NRC Commissioner Rogers visited the Millstone station.
The. Commissioner was accompanied by the Region I Director, Division of Radiation Safety and Safeguards and the resident inspectors.
The Commissioner met with licensee management, toured plant areas and the
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training facilities.
Routine NRC resident and specialist inspections were conducted during 331 regular. hours, 49 backshif t hours, and 9 deep backshift hours.
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'3.0 Plant Operations (IP 71707/71710/93702)
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3.1 Control Room Observations Control room instruments were observed for correlation between l
channels, proper functioning, and conformance with Technical p
Specifications.
Alarm conditions in effect and alarms received in
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the~ control room were discussed with operators.
The inspector periodically reviewed the night order log, tagout log, plant incident report (PIR) log, key log, and bypass jumper log.
Each of the p'
respective logs was discussed with operations department staff. No inadequacies were noted.
On September 27, during inspector observation of the Unit 2 control room, an off-duty shift supervisor was observed reading a newspaper.
The inspector discussed the observation with licensee management.
Based on the discussions, management reinforced the requirements to control room operators of Administrative Control Procedure (ACP) 6.01
" Control Room Procedure."
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The inspector discussed the issue with the off-duty shift supervisor.
The shift supervisor explained he was reviewing the newspaper for recent articles on the Millstone 3 NRC requalification examination results. The off-duty shift supervisor was not responsible for plant operations during the time of inspector observation.
The inspector considered this an isolated occurrence, based on no previous observation.
The inspector will continue to routinely observe control room activities as it relates to ACP 6.01 during future resident inspections.
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3.2= Plant Tours
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The inspector observed plant operations during regular and backshift tours of the following areas in Units 1-and 2:
Control Room Reactor Building Vital Switchgear Room Diesel Generator Room Turbine Building Intake Structure Enclosure Building ESF Cubicles During plant tours, logs and records were reviewed to ensure compliance with station procedures, to determine if entries were correctly made, and to verify correct communication and equipment status.
Inspection of the Unit 1 ventilation room and the condensate bay in the turbine building noted the following housekeeping deficiencies:
fire equipment was' blocked; dirt and debris existed on the floors behind ventilation piping and under feedwater heaters; ladders were not properly tied off; and tools were not: properly stored. The inspector informed the shift supervisor of the deficiencies important to personnel safety and verified that the deficiencies were promptly corrected.
The inspector had no further questio n.
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3.3 Stand-by Readiness of Engineered Safety Feature Systems and System Walkd'own - Unit 2 Two engineering safety feature (ESF) systems were reviewed to verify system operability.
The systems reviewed were~ Facility I diesel generator auxiliary support systems and the Facility II auxiliary feedwater system..The inspection included proper positioning of ma.ior'flowpath valves, proper operation of indication and controls, and visual inspection for proper lubrication, cooling, and other conditions. 0utstanding authorized work orders,' tag-outs, and
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trouble reports were reviewed to assess the effects on system operability.
References used were:
Final Safety Analysis Report; tag-out log; plant. instrument and piping diagrams (P& ids) 25203-26008, 25203-26005; and operations procedures (0P) 2513A and 2610C.
Minor housekeeping deficiencies were identified that did not affect safety system operability. The items were discussed with the licensee and corrected. The inspector had no further questions.
3.4 Review of Plant Incident Reports The Unit 2 plant incident reports (PIRs) listed below were reviewed during the inspection period to (1) determine the significance of the events; (ii) revi6w the licensee's evaluation of the events; (iii)
verify that the licensee's response and corrective actions were proper; and, (iv) verify that the licensee reported the events in accordance with applicable requirements, if required.
The PIRs reviewed were:
89-94, 89-96,89-100, 89-101, and 89-106.
The following items warranted inspector followup:
-- -PIR.89-96 and 89-100 (see section 3.5.3)
PIR 89-106 (see section 5.4.1)
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l The. inspector had no further questions, 3.5 On-Site Followup of Operational Event's i
3.5.1-Reactor Scram due to Turbi% Trip on High j
Reactor Level - Unit 1
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On October 19, a power reduction to 50% occurred to repack the "B" feedwater regulating valve (FRV) and perform other maintenance.
Upon completion of repairs, p'lant operators increased power to about 700 full power (FP) using the reactor recirculation system and made preparations to place the "B" feedwater train in service.
The plant was operating with the "A" FRV in automatic and controlling vessel.
level as the "B" feedwater valve was placed in service.
While placing the "B" FRV in service, the "A" FRV failed full open, causing vessel level to increase to the high level trip setpoint.
The main-turbine tripped at 3:16 p.m. on high vessel level (+48 inches), followed-immediately by an automatic reactor trip. An NRC inspector was in the control room at the time and monitored the licensee's response.to the scram.
Plant operators stabilized the reactor in hot shutdown. The turbine bypass valves were used 'to maintain reactor pressure control and vessel level was stabilized in the normal control band using the reactor water cleanup system and the feedwater system on the startup-feedwater regulating valves.
The plant response to the scram was normal. All safety and other plant systems functioned as required.
The licensee reported the scram to the NRC headquarters duty officer per 50.72(b)(2)(ii) at 3:40 p.m.
The' inspector identified no inadequacies in the licensee's immediate response to the scram or in the actions to follow reactor scram and recovery procedures.
The "A" FRV was removed following draining and cooldown of the header. A bolt from the "A" feedwater pump discharge check valve was found under the "A" FRV seat.
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The resident inspector reviewed the licensee's post trip actions and investigation of the trip cause, corrective actions to prevent recurrence, and the maintenance and testing activities to support plant restart. The inspection findings will be summarized in Inspection Report 50-245/89-25.
3.5.2 Secondary Steam Leakage Inside Containment - Unit 2 During the early part of September, the licensee identified an increase in containment sump refill frequency.
The containment sump collects both reactor coolant system and secondary system leakage from inside containment. The utility plant staff conducted contain-ment entries on September 11 and 18 in an attempt to identify the source of leakag l ya
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On September 11, the licensee's containment entry was to troubleshoot a dual indication of inboard containment isolation valve 2-SPP-16.1.
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-At-10:50 a.m., the dua1' indication on valve 2-SPP-16.1 was
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acknowledged by the control room operator's subsequent entrance into
the limiting condition for operation (LCO) action statement.of technical specification (TS) 3.6.1.1, " Containment Integrity".
At 10:58 a.m., the operators de-energized the in-line outboard isolation valve and exited LCO 3.6.1.1, but entered 3.6.3.1.b. " Containment
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Isolation Valves". At 5:32 p.m.,
the utility adjusted-the valve actuator position switches and exited LCO 3.6.3.1.b.
The containment entry also identified excessive drainage'from the containment air recirculation cooler drains.
The containment sump total activity was measured at 3.25X10 -4 microcuries (pC1)/ milliliter (ml) with a boron con' centration of 62 parts per million (ppm).
The RCS gross activity was.399-pCi/ml with a boron concentration of-724 ppm.
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On September 18, the licensee entered containment and identified a-body-to-bonnet steam leak from valve 2-MS-248. The Velan one-inch gate valve is a high side instrument stop valve for pressure transmitter PT -10138 and level transmitter LT -1113B on the No. I steam generator. Transmitter LT-1113B:is an input for the "B" reactor protection system' for low steam generator level trip and PT-1013B is the input to "B" engineered safety actuation system signal for main steam is'olation.
On 0ctober 11, the licensee' provided to the resident staff its
- evaluation of the impact of the steam leak from 2-MS-24B on plant operations.
The evaluation included: the containment profile on the catastrophic failure of the valve, steam leak impingement on the adjacent steam generator shell, the available stud stress if one of four studs were to erode and fail, and transmitter responses on a catastrophic failure.
The evaluation concluded sufficient monitoring methods exist to allow for. prompt identification of further valve
degradation.
l The. operators were cognizant of the cor.dition and the required response to control room alams in regards to a potential catastrophic failure of 2-MS-24B.
The NRC acknowledged the licensee's evaluation ar.d position, however i
further questioned the potential secondary boric acid deposition of SG carbon steel components.
This was still under licensee review at the end of the period.
l The valve was scheduled for repair during the mid-cycle outage commencing on October 21, 1989. The inspector concluded that good
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i licensee awareness was demonstrated by tracking of leakage, contain-ment entries, personal safety hazard considerations during leak
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identification,.and' analysis of'the event in appropriate perspective to maintain' safe operation of Millstone 2.
3.5.3 Turbine Control Valve Closure - Unit 2 On September 9 at approximately 6:40 p.m. the #2 turbine control valve (2-MS-61B) inadvertently closed. The unit was operating at full power at the time of the event.
'The plant' transient following closure of the main turbine control-valve included an increase of reactor coolant system cold leg tem-
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peratures, an open signal for condenser bypass valves, fully. opening.
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the remaining turbine control valves, and an increase in pressurizer
. pressure. The operators immediate response to the transient was to reduce reactor power by commencing boration.
The boration method to reduce power was-utilized due to a previous limiting condition of.
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operation (LCO) on a controlling bank control element drive assembly position indication anomaly. The operators entered the action i
statement for technical specification 3.2.6 for reactor coolant system cold leg temperature exceeding-549 degrees Fahrenheit. The
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basis for the action statement is to maintain assumed margins to departure from' nucleate boiling (DNB). The reactor coolant system cold leg temperature in excess of 549 F exceeds the initial condition in the accident and transient analysis documented in the Final Safety Analysis Report. The licensee restored RCS cold leg temperature below 549 at 6:47 p.m. and complied with technical specification action statement 3.2.6 requirements. At 7:32 p.m. the licensee reopened the control valve using the first stage feedback control circuit as prescribed in procedure SP 2651, section 7.14.
The control: valve was retested using SP 2651-14 " Control. Valve Opera-bility Test". The surveillance was successful and the unit was
restored to rated power at 11:50 p.m.
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On September 12, at 4:06 p.m. the plant again experienced an in-advertent closure of the #2 control valve.
The plant response was similar to the event on September 9.
Licensee troubleshooting on September 13 identified a malfunction of the servo valve connected to the electro-hydraulic control (EHC). positioning circuitry.
The servo valve controls hydraulic pressure to the control valve position operator. By pass jumper 2-89-65 was installed to bypass the EHC electric signal to the servo valve to maintain the control valve in a closed position. The unit remained at 92% of rated power until the scheduled outage beginning on October 21.
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The inspector reviewed the by pass jumper installation and potential affect on turbine trip functions.
The turbine trip signals are unt.ffected by the by pass jumper 2-89-65 installation. The hydraulic trip signals are located downstream of the servo valve actuator, and do not affect the processing of the turbine trip rela..
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- The-inspector reviewed the Final-Safety Analysis Report (FSAR)
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section 14.9 " Loss of External Electric Load and/or Turbine Trip" accident description to verify the licensee was operating within the initial conditions and system configuration of the control valves.
Plant. operations remained within the initial conditions assumed in the accident analysis.
No inadequacies ~were noted in the review of~
the accident description.
The utility will repair the #2 control valve servo valve during the mid-cycle outage.
Inspector follow-up of the licensee repairs and causal determinations, and an NRC review of the servo valve preventative' maintenance program is planned in future inspections.
3.6~ Summary
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Generally, good operations control of plant transients was noted in the reactor scram at Unit 1, and the turbine control-valve closure at Unit 2.
Minor housekeeping deficiencies were noted specifically in the Unit 1 ventilation room and condensate bay. An isolated. instance was observed of an off-duty shift supervisor reading non-job related
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4.0 Radiological Controls (IP 71707/92701)
4.1-Posting and Controls of Radiological Areas During plant tours, posting of contaminated, high airborne, radiation, and high radiation areas were reviewed with respect-to boundary identification, locking requirements, and appropriate control points. No inadequacies were noted.
= 4. 2-Radwaste Transportation - Millstone Station On September 14, 1989, the licensee shipped to the Haddam Neck Plant a package containing contaminated ladders and a fiberscope as a Limited Quantity package.
The fiberscope, which had a maximum dose rate on contact of 1.1 millirem per hour, was placed in the middle of the shipping container,-wedged between several ladders. A survey conducted by the licensee at the time of the shipment indicated the maximum dose-rate on the external surface of the package to be 0.1 millirem per hour, 10 CFR 71.5 requires that NRC licensees comply with the regulations set forth in 49 CFR Parts 100-179, for the transportation of radioactive materials. 49 CFR 173.421 requires that in order for a package of radioactive materials to be shipped as Limited Quantity, the maximum external dose rate on the surface of the package must not exceed 0.5 millirem per hour.
Upon receipt at the Haddam Neck Plant on September 14, 1989, the package was surveyed by Haddam Neck health physics personnel and
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determined to-have a maximum dose rate of 0.7 to 0.8 millirem per hour on the_ bottom. A representative of the licensee's shipping
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staff was notified telephonically on September 14, 1989 by the Haddam-Neck staff.- Millstone plant staff traveled to Haddam Neck to survey
.the package. That survey, conducted with the same survey instrument
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i utilized for the shipping survey at Millstone, revealed a maximum ll surface dose rate of 0.6 millirem per hour on the bottom of the
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package.. Upon opening the package, it was discovered that_the fiber-'
l scope had shifted in transit and now rested on the bottom of the-
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package at the location of the maximum survey reading.
This is an J
apparent violation of 10 CFR 71.5 (50-245/89-23-01 and 50-336/89-22-01).
4.3 Contaminated Tools Discovered in Offsite Warehouse The licensee informed the inspector on September 7 that contaminated tools had been discovered at an offsite Northeast Utilities Service Company (NUSCO) warehouse. The NUSCO warehouse is located on Great
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Neck Road (GNR)-in Waterford, about three miles from the site and is.
i used for support equipment during refueling outages at Millstone,
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Connecticut Yankee and other NU facilities.
The inspector visited the warehouse with licensee personnel on September 7 to review licensee actions to identify and control the contaminated tools. Mr.
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'S. Linscott from the State of Connecticut Department of Environmental Protection was-also in a'ttendance during the warehouse tour.-
As-of September 7, of the 8000 tools that had been surveyed at the i
GNR facility. -20 had been found to be contaminated.
Contamination was found on small hand tools located in tool storage bins at the
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facility, and a significant level of contamination was found on a
hydrolaser skid stored at the-warehouse.
The 20 hand tools had fixed contamination in the range of 200-7000 corrected counts per minute
(ccpm) of beta gamma activity as measured with an RM-14/HP-210
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frisker.
Loose. surface contamination up to 50,000 disintegrations
per' minute (dpm) per 100 cm.sq was found on two tools.
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l The hydrolaser skid had last been used at Millstone I and was sent to the warehouse in February,1989. The hydrolaser had contamination
distributed over the skid, with the highest reading of smearable contamination of 10,000 dpm, and a on contact dose rate reading of 3 mrem /hr from a small valve on the skid.
The dose rate was due to
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internally deposited contamination.
Inspector review of the health physics survey sheet (FORM OP2459, dated 9/6/89) noted that the dose rate at six inches from the valve was 0.7 millirem /hr. The dose rate from the valve could not be considered a "whole body" dose rate due to its location on the skid.
Further, the limiting "whole body" dose rate from the skid was 0.1 mrem /hr due to contamination inside a water holding tank.
The licensee took actions to segregate the hydrolaser and contami-
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nated tools, established controls over them as radioactive and contaminated materials, and made preparations to ship the materials
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'back to,the Millstone site. The hydrolaser skid was returned ~to the-e site on September 7 and stored inside the radiation controlled area
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.(RCA) in a radwaste building.
Background The licensee began a survey of all materials in the warehouse on September 5.
The survey was initiated generally-as a result of the licensee's review of its program for the unconditional release of material from the site.
This review was prompted after a radio-
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actively contaminated hydrolaser-(different from the unit described L
above) was released from the site and sent to the vendor in New Jersey on May 11, 1989.
The NRC review of-that event was summarized
.in Inspection Report 50-245/89-13, issued on June 9.
A Notice of Violation and Civil Penalty was issued by the NRC on August 31 as a result of that event.
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As part'of the program review in response to the May event, the licensee surveyed equipment outside the radiation controlled area at the site.
The licensee ~ survey resulted in the identification of contaminated tools stor:d in tool cribs-outside the RCA but within the protected area at the Millstone station. The tools had contami-nation in excess of procedural release limits.
Based on this finding,-
the licensee expanded the scope of its review to offsite tool storage locations and began the survey of the GNR facility on September 5.
Followup Actions at the GNR Facility The licensee briefed the inspector of the actions that had been taken
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or were in progress as of September 7.
The licensee further updated j
the inspector of the status of actions periodically throughout the report, period. A task force was created to develop a plan to system-
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atically evaluate and investigate how material-becamt: uncontrolled,
~j what areas required further investigation to assure all uncontrolled j
contaminated materials have been identified, and to verify that no i
contamination was inadvertently spread in the unrestricted area. A senior health physics qualified individual, the Millstone 3 health i
physics supervisor, was assigned to head the task force.
The task force initiated a formal Action Plan to address four major areas:
(i) release of the contaminated hydrolaser skid from Millstone 1 to
-
the GNR facility; (ii) specific short term actions to control the GNR facility; (iii) general tool and equipment locations and followup actions; and, (iv) ongoing review of the unconditional release-program.
Licensee actions at the GNR facility are addressed below.
,
The licensee established full time HP coverage at the GNR facility to control movement of material and to complete surveys to identify other contaminated tools. The licensee assigned up to 15 HP
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F technicians, working 6 days per week,10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> per day on the warehouse survey, Swipe surveys of the warehouse floors and areas-were completed and no contamination was found.. The licensee also conducted ~an additional survey of material received at or shipped-from the warehouse at the point of exit as a double check that tools and materials were-free of contamination.
Surveys of storm sewer catch basins and the'outfall from the sewer system were completed (reference FORM Of 2459 dated September 20, 1989) and no E
contamination was found..
The inspector observed frisking activities in progress on September-7..' Surveys were first conducted with highly sensitive scintillation detector instruments (Ludium micro-R meter) to identify areas
~
requiring further investigation with frisking equipment. This survey was followed by a detailed piece - wise survey of tools and equipment stored in the' warehouse using either Eberline E140 or RM - 14 friskers, with HP 210/260 pancake probes.
Frisking speeds were
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maintained at an optimum 10-15 seconds per area to ensure acceptable
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instrument response.
j
.i The background r:dioactivity level at the warehouse was 40-50 cpm
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(RM-14/HP-210), which was 2 to 6 times lower than the background at the. site where frisking is normally conducted. The friskers had 10%
i counting efficiency and 'the station release limits of 100 cpm above
background was used as the criteria for identification of
!
contaminated materials. On contact readings were used rather than j
the typical industry standard of 1/2 inch abov'e the surface.
The
'
survey. proceeded in a systematic manner by frisking each tool in each storage bin in each storage rack in the warehouse.
Storage bin.s were marked with an orange sticker to show the material inside had been
found free of contamination, j
!
The licensee briefed warehouse personnel to explain the reasons for i
the surveys, the controls established to identify and prevent the
inadvertent spread of contamination, and the interim measures to be followed for handling materials in the warehouse to prevent the inadvertent release of contamination. Worker questions on radiation hazards were addressed. The licensee determined, based on the low levels of radioactivity discovered, that no dosimetry was required for warehouse personnel. All warehouse personnel were frisked and whole body counted. All personnel were found free of internal and external contamination.
The inspector met with licensee personnel and reviewed the survey results throughout the report period. The inspector identified no inadequacies in the survey methodology or controls established at the
warehouse.
Meetings to review findings were held on September 11 and 28.
Licensee surveys at the GNR facility were completed on October 12. All tools found contaminated contained only low levels of beta gamma activit _ _ _ _ _ _
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.
.
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. ' r , The total number of tools surveyed from the warehouse exceeded 230,000, of which 233 items (about 0.1%) were.found to have low levels of contamination in excess of free release limits.
The ' c contamination levels ranged from 100 counts above background to 10,000 counts above background, with.the following distribution: of the 233 items.with greater than 100 corrected counts per minute - (ccpm), the contamination was less than 200 cepm on 133_of the items (57.1%), less than 500 ccpm on 192 of the items (82.4%), less than 1000 ccpm on 211 of the items (90.6%), and less than 2000 cepm on 229 of the items (98.3%). The total measured activity was 119,410 ccpm, which~ represents a total activity of less than 7 microcuries. The major isotope was Cobalt-60 with no transuranic or alpha activity detected.
Followup Corrective Actions The licensee determined the~ root cause of the event involved both a failure to establish adequate procedures to prevent the spread of contacinated materials outside the RCA, and a' failure to adequately survey material prior to release from the RCA. Additional measures were instituted to address the root cause as follows: a.
Health physics personnel are now responsible for surveying tools and equipment relea' sed from the RCA.
Health physics personnel were assigned to monitor principle exits from the RCA. This control replaces a previous practice that relied on the work force to properly frisk materials from the RCA.
Previously, HP personnel were required to only frisk material that came from known contaminated areas.
b.
Health physics personnel must now co-sign property passes that allow the removal of equipment from the site.
c.
A program for surveying vehicles leaving the protected areas was instituted.
The inspector observed the above augmented controls in progress during inspection tours of all three Millstone units. The licensee is further considering augmenting station work-order procedures to require HP involvement when support equipment is connected to potentially contaminated systems.
Upgraded, state-of-the-art monitoring equipment is undergoing field testing and is under evaluation for future use.
The licensee also has a tool loan program.
All tools released from the site were returned and found free of contamination. The trash removal monitoring program was reviewed and revised. The licensee has automated surveying equipment on order to support this effort.
The licensee is conducting a dose assessment to determine the consequences related to the uncontrolled release of about 7
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, microcuries of radioactivity.
The activity calculation is expected to show an insignificant dose potential to the general public.
This evaluation is pertinent to assess the public risk from tools that have been sold at public auction and which may have been released with contamination in excess of the free release limits.
-Licensee evaluations and followup actions are ongoing. The task force is expected to conclude its review and complete its recommended actions by December 30, 1989.
The licensee plans to perform a' survey .of equipment at a non-nuclear facility (Devon Station).that uses tools from the GNR warehouse. The survey will start in early November 1989 and is expected to be completed in 2 days.
Findings -! The failure to control contaminated materials and to complete a proper frisk of equipment such that tools were released from the site with contamination in excess of the free release limits is a violation of procedure HP 905 (Control and Accountability of Radioactive Material, Rev.10) and is contrary to the-requirements of
_ ' Technical ~ Specification 6.8.1 for Millstone 1.
Although the requirements of Millstone 1 are cited herein, the programmatic weakness identified by the licensee is considered.to be a problem applicable to all three Millstone units, i i The inspector reviewed the findings from the contaminated materials j found at the CNR facility.
No regulatory limits were exceeded based
on a review of.10 CFR Part 20 requirements for posting, labeling, l dose monitoring, and the controls intended for " radiation areas" or -) " radioactive material s."
Licensee actions upon discovery of the contaminated. tools at the GNR facility were excellent, and were found by the inspector to be
comprehensive and aggressive to identify the scope and severity of ! the problem, and to initiate the necessary corrective actions. The
health and safety significance of the uncontrolled materials i identified to date is deemed to be minimal.
The licensee stated that an informal report (in LER format) will be submitted to the NRC to describe the event and corrective actions taken and planned.
The inspector noted that a licensee shipment of tools and equipment to the Connecticut Yankee facility for use during the outage arrived at that site with radiation levels in excess of the transportation limits. This matter is discussed further in Section 4.2 above.
The inspector noted that licensee corrective actions in response to the August 31, 1989 hydrolaser Notice of Violation and Civil Penalty are still in progress.
Based on the above, the inspector determined that the circumstances in this (warehouse) event warrant consideration as a licensee identified violation in accordance with l 10 CFR 2.
This matter is considered unresolved, pending further i j ' - .
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p review of the licensee program and corrective actions in response to the August 31 Notice of Violation,.during future routine inspections , ofthelicensee'sradiologicalcontrolsprogram(50-245/89-23-02).
4.4 Summary , A shipment' of a Limited Quantity of radioactive materials that had a dose rate on contact in excess of the 49CFR limits-is considered an-Lapparent violation.
The event was of low safety significance; however, I . a recent escalated enforcement action on a previous inspection (50-245/89-13) concluded that there was an inadequacy in radiological- -j support for transportation activities.
-{ The adequacy'of the licensee corrective actions to correct programmatic weakness in the health physics program for the unconditional release of material from the site is considered an unresolved item.
5.0 Maintenance / Surveillance (IP 62703/61726/92702) ' 5.1 Observation of Maintenance Activities - Unit 2 The inspector observed and reviewed selected portions of preventive i and corrective maintenance to verify compliance with regulations, use ' of administrative and maintenance procedures, compliance with codes and standards', proper QA/QC involvement, use of bypass jumpers and.
safety tags, personnel protection, and equipment alignment and retest, The following activities were included:
-- AWO M2-89-10410 Fire Seal Repair (See Detail 5.4.1) I -- PT 214618 " Timing Device Setpoint Cortrols" ! -- Turbine Control Valve Hydraulic Control Unit q Mock-up/ Freeze Seal ' ' - No inadequacies were identified.
! 5.2 Grinell Snubbers - Unit 2 l i The inspector reviewed LER 89-007-00 dated May 11, 1989, issued from Millstone Unit 1, and routine resident inspection report 50-245/89-14 to determine the impact on Millstone Unit 2.
Millstone 1 identified cracks in the safety-related hydraulic snubber plastic reservoirs during surveillance testing per TS 4.6.I.1 during the most recent e refuel outage. At the time, the licensee contacted ITT Grinell and learned dimensional changes had been made to the end plates and j plastic reservoir cylinders on later model snubbers.
Millstone 1 i snubbers pre-dated this change.
The reservoirs purchased for rebuilt snubbers cracked due to clearances between the raised flange on the snubber end plate and the cylinder inner diameter were less than the minimum design tolerance (0.006 versus 0.015 inch).
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h '14 e ! ,. To understand the potential impact at Millstone 2, the inspector ' ' reviewed'the licensee. technical manual on Grine11 snubbers, held , ' discussions with maintenance engineering, and reviewed procedure MP 2721I " Hydraulic Snubber Overhaul." On May 17, 1983 ITT Grine11
informed Northeast Utilities of the different reservoir assemblies and' appropriate assembly numbers.
The licensee on June 10, 1983 . prepared'a significant operating experience report based on Millstone u 1 LER 82-20. The LER 89-007 causal analysis indicated personnel
error in refurbishment of snubbers with inappropriate reservoir assemblies.for the given vintage snubber.
Routine resident follow-up of NRC unresolved items 89-14-01 and 89-14-02 will address this
issue further at Millstone 1.
Procedure MP 27211 details reservoir parts, drawings, and special , precautions for pre / post November 1974 Grine11 snubbers.
The procedure ircorporates vendor information, and lessons learned from the similar occurrence at Millstone 1 in 1982 (LER 82-20).
The procedural steps adequately prevent the. lessons learned in LER 89-007. -The inspector had no further questions in regards to this matter.
5.3' Observation of Surveillance Activities - Units 1 and 2 The inspector observed and reviewed selected elements of the .fo11owin9 surveillance procedures: for conduct in accordance with curren_t approved procedures; for test result compliance with technical specifications and administrative. requirements; and for correction of deficiencies in accordance with administrative requirements. The inspector noted that the surveillance teams displayed thorough coordination and adherence to procedures. The following activities were reviewed: SP 412L, Isolation Condenser' Isolation Instrument Functional and -- Calibration Test SP 631.2, Control Rod Exercise - Stuck Rods -- SP 1040, APRM Calibration Using Heat Balance -- IC 421G, Drywell Hydrogen and Oxygen Functional Test -- IC 403C, LPRM Detector Current / Voltage Curve Diagnostic Test -- OPS 622.7, LPCI System Operability Test -- OPS 621.10, Core Spray System Operability Test -- L IC 2401B Wide Range Nuclear Instrumentation Functional Test -- ! SP 21107 Terry Turbine Auxiliary Feedwater Pump Operational -- Readiness Test OPS 2654-24 Nitrogen Add to Primary Drain Tank -- On June 16, 1989, the licensee notified the NRC that the setpoints , l for isolation condenser group IV condensate line differential pressure indicating switches (DPIS) 1349A and 1349B had been found to i ! be out of specification (low) during the performance of surveillance ' procedure SP-412L, Isolation Condenser Isolation Instrument L Functional and Calibration Test.
Technical Specification 3.2, ! Protective Instruments Table 3.2.1, specifies a differential pressure .- - - -
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- trip setting b'nd of 3 to 44 inches of water. The notification was a
made pursuant to 10 CFR Part 50.72(b)(2)(iii), Non-emergency events i .. -four-hour reports.
' Licensee investigation revealed that the out-of-specification.results-i had been obtained using gage QA-256,.a 0-450 H2O standard which H exhibited a large hysteresis in-the required range.
Based on subsequent calibration of the switches with a standard of more suitable range (0-280 H20), the licensee concluded that at-no time had the DPISs been out of specification.
License corrective actions-included review of equipment recently calibrated using QA-256, J modification of SP-412L to specify use of a gage with a suitable < range, and briefing instrumentation and control personnel on the
event and the proper use of maintenance and test equipment. On I . October 3,1989, the inspector witnessed the performance of SP-412L l and verified that the required procedure change had been incorporated. The inspector considered licensee response to be satisfactory and had no further questions.
During-its review of SP-412L results on October 3, the licensee .j determined that the-surveillance procedure had not been performed l within the frequency required by the technical specifications.
Plant ! incident report 1-89-76 was generated and the appropriate licensee ! personnel were notified in accordance with licensee administrative [ procedures.
Details of this event are addressed in section 8.5 of this inspection report.
No other inadequacies were identified.
-i 5.4 Maintenance Conducted During Downpower - Unit 1 The inspector observed, from the main control room and locally, the , conduct and control of maintenance activities conducted during a ,[ planned power reduction to 50% power. The maintenance activities, which focused on reducing steam leaks in the condenser bay, included ' repairing a steam trap, repacking valves in steam line drains, and
adjusting packing on a normal drain line valve to the high ' intermediate pressure heat exchanger.
The power reduction was completed on schedule without incident and operations maintained a power level of approximately 45% to reduce
the pressure in the heat exchangers as low as possible while . maintaining adequate net positive suction head to the condensate and ' feedwater pumps. A radiation survey was completed, required tagouts were hung and the appropriate work orders were approved.
The maintenance was conducted in a safe manner, including adherence to health physics practices for jobs conducted in radiation and contaminated areas. The work was well supervised and completed in a timely manner. The inspector concluded that the maintenance was well planned and that an effective interface exists between department, , , y, .-- t . ..'
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. L J.- ' -16 , , ' .5.5 Corrective' Activities --Fire Seal Operability - Unit 2 ' On September 28, the inspector notified the control room of a-potential inadequate fire barrier in the west DC switchgear room. A . licensed operator accompanied the inspector to the switchgear and ' confirmed the two-inch conduit was not sealed between the switchgear e , room and the cable vault. At 8:30 a.m., the operators entered the , limiting condition for operation (LCO) action statement of TS 3.7.10.a 1, and at 12:00 p.m. the licensee prepared plant incident report (PIR) 89-106. At approximately 3:37 p.m. the licensee exited l the LCO action statement.
According to discussions with engineering personnel, the reason for no longer being in the LCU action statement was based on maintenance repair activities earlier in the day. Maintenance action for the fire penetration was to install a metal cap, with the understanding
that this was acceptable based on a 1984 engineering generic evaluation (GMB-84-331) of open conduits.
The GMB-84-331 evaluation considered the NRC's Branch Technical position 9.5-1 Appendix A " Fire Protection," vhich states openings inside conduits four inches or 'less in diameter should be sealed at the barrier unless the conduit extends at least five feet on each side of the barrier and is sealed at both ends with a non-combustible material (to prevent passage of smoke and hot gases.) The open conduit passed approximately twelve feet in the cable vault and opened directly into~the DC switchgear room.
On September 29, at approximei.ely 11:45 a.m., the licensee re-entered LCO 3.7.10.a.1 and mmplied with the TS requirements.
The - re-entrance into t ie requirement was based on questions from control room operators on che adequacy of the fire seal repair. The opening was repaired undec authorized work order M2-89-10410 on September 28, .. by installing a conduit cap in the cable vault. The initial licensee evaluation determined this was a permanent seal repair. The initial conclusion was inadequate, based on not maintaining a three-hour fire barrier configuration, as required by branch technical position 9.5.1.
On October 3, an engineering evaluation was developed to evaluate if the installed conduit cap was acceptable as a temporary fire seal, as defined in the technical specifications.
The technical justification included: fire barrier rating; operability of each affected fire zone detection / suppression system; proximity of combustible material to the. conduit; and fire zone loading as prescribed in the Fire l Hazards Analysis. The licensee evaluation determined the repair was
considered a temporary seal. On October 4, the penetration was l permanently sealed with a three-hour barrier and the LCO was exited.
L , The inspector further considered: recent unacceptability of fire seals; the length of time the conduit was opened; regulatory y L I - - - - - - - . - - . - .
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s' requirements; and, the licensee's seal _ inspection program and results.
g A review of licensee event reports (LER's) and plant incident reports (PIR's) since early 1988 was conducted, in relationship to fire barrier seals.
Four PIR's (89-51, 89-07, 88-24, and 88-01) , ' identified wrong sealant material used, unsealed conduit barrier, and ' two ' instances of barriers not repaired within the required thirty days.
LER 89-01 further documented an inoperable _ fire seal based on wrong sealant material.
Previous inspector follow-up of LER 89-01 is
documented in routine inspection-report 50-336/89-05 as a ' licensee-identified non-compliance. The inspector. concluded from the above review that the licensee does not have a significant .. programmatic breakdown with open fire barrier seals.
l , The inspector reviewed the purpose of the conduit, and the time interval it was placed out of service.. The conduit (1K267) was
utilized to de-energized power panels in the computer room in the ! event of a fire and halon injection in the computer room. The cable' was removed between 1976-1978 based on plant drawing revisions.
' i Regulatory requirements for the operability of a fire seal barrier l are described in 10CFR 50 Appendix R section II.A. 10CFR 50 Appendix
R section II.B.4. and te'chnical specification 3.4.7.10.
The purpose of f_ ire barriers, in parallel with fire suppression systems, is to be
installed as necessary to protect redundant systems / components ' necessary for safe shutdown of the facility.
' ! ! The licensee's seal inspection program consists in part of procedures SP 27340 " Fire Penetration Seal Inspection," and MP272IN " Scaling and Seal Repair of Electrical Cable and Piping Penetrations." The seal-inspection program, as specified by TS surveillance 4.7.10.b, requires 10% of all seals to be inspected every 18 months; if an inoperable seal is identified, another 10% sample is required.
The inspector reviewed the last two completed SP 2734D surveillances and-identified no discrepancies; however, the open conduit was not identified by those reviews.
In conclusion, the licensee did not-init' ally address the appropriate . ' corrective actions on the seal discrepancy.
Specifically, the seal L was repaired based on an out-dated engineering evaluation (GMB-84-331), and requirements were relaxed without full evaluation of the con-sequence of a fire in one zone affecting the adjacent area without the barrier for approximately twelve years.
This evaluation will be an input into the licensee's fire consequence / significance deter-mination of the event. This is an unresolved item pending licensee , evaluation of the specific fire consequence without sufficient fire I barrier seals. (50-336/89-22-02) (' The inspector acknowledged on going licensee efforts under Project Assignment (PA) 83-030 to conduct a 100% fire barrier walkdown, to l- ! I ' -
- - - - - - - -
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, develop a generic program (unique upgrade of repair procedures, and upgrade'of penetration drawings).
Northeast Utilities identified the fire barrier upgrade program by docketed correspondence on September 28, 1988 to the NRC.
' 5.6 Summary i The NRC noted satisfactory response and follow-up of the out-of-
specification _DPIS's for the condensers at Unit 1.
Maintenance activities during the Unit 1 downpower were conducted in a safe manner, including adherence to health physics practices for activities conducted in radiation and contaminated areas, m i The NRC identified inadequate initial licensee actions to address appropriate corrective actions on a fire barrier seal discrepancy.
The lack of barrier seal consequence / significance determination is an NRC unresolved item pending licensee evaluation.
i 6.0 Engineering / Technical Support (IP 37700/37828/92702) 6.1 Plant Design Modifications - Unit 1 , The inspector selected and reviewed two plant design change requests (PDCR's) written in 1989.. Plant design change request 1-3-89, raised the minimum recirculation pump speed to 32%. The inspector concluded that the change was well documented and an adequate safety evaluation.
had been performed.
However, the independent engineering review of
the design was not formally conducted until July 17, 1989, two months
after the PDCR had been completed.
Through discussion with the licensee,-the inspector determined that the licensee performed the formal design review after the department director identified, through his final review of the PDCR, that the initiator of the pDCR also signed for the review which is not in accordance with program - requirements.
The deviation from program requirements was compensated for by conducting and documenting an independent review of the design after the fact.
The inspector concluded that the design change was made in accordance with a recommendation by General Electric, the deviation was identified by the licensee, and no safety concern existed.
Plant design change request 1-8-89, incorporated a high drywell pressure isolation signal for the reactor water cleanup system, and Revision 1 of the PDCR removed the modification after environmetal upgrades to certain qualification motor operated valves were completed.
The inspector concluded that the engineering analysis and, justification for the installation and testing of the modifications were acceptable.
The inspector had no further questions on the development of PDCRs.
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r , , 6,2 ~ Engineering Support of Plant' Operations 6.2.1 Reactor Coolant System Hot Leo Temperature Indications - Unit 2 ~ -; - . Routine resident inspection report 50-336/89-11 documented unexpected hot-leg temperature (Th) oscillations and' , channel differences in both reactor coolant system (RCS) , [- hot legs resulting in thermal margin low pressure pre-trip ' alarms. After completion of the cycle 10 refueling outage n and return to power operations, the licensee observed L oscillations in specific channel readings between 1-2.5 _ degrees F, with differences in channel readings up to 7 degrees F.
On June 8, the NRC requested a conference call with the-licensee to discuss the variations and impact of Th-indications.
The licensee discussed the following: g in-core exit thermocouples response, Th variations were-observed on previous cycles that were less pronounced, previous experience of other utilities, and: future licensee l actions. The licensee actions included a Combustion Engineering review and analysis, determination of the root cause, and a f,uel' vendor review.
On July 26, Northeast Utilities submitted to the NRC the evaluation by Cumbustion Engineering (CE) on RCS hot leg temperature fluctuations.
The review consisted of two evaluations.
One part of the evaluation discussed the possible cause of temperature fluctuations and a comparison c i with other CE plants. The second.part of the evaluation reviewed the impact of Th fluctuations on the thermal ' margin low pressure trip system.
L . The first CE evaluation concluded the short-term Th fluctuations (20-120 seconds) at Millstone 2 are caused by flow pattern variations in the region between the core exit and hot leg temperature positions. The characteristics of the Th short-term fluctuations observed at Millstone 2 are - similar to those observed during operating cycles at the . ANO-1 (Cycle 1), St. Lucie (Cycle 5), and San Onofre 3 (cycle 1) nuclear power plants.
i Two conditions of long-term Th fluctuations (6-300 minutes) were observed.
Since both long term fluctuations affect both RCS hot legs simultaneously, CE does not rule out motion of an internal RCS component as the potential cause.
CE recommends implementations of an internal vibration monitoring (IVM) system in parallel with excore neutron ' flux detector noise analysis to monitor reactor vessel core barrel motion.
The inspector questioned licensee engineering on the status of implementation of CE's , ,
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Inspection of licensee activities in this matter will be tracked unde ~r routine resident follewup.
The impact of RCS Th fluctuations on the thermal margin low pressure (TMLP) trip system was a potential non-conserva-- a tive protective-signal based on a false gain in margin to trip. A September 27, 1989 licensee letter to the NRC
' documented the results of the fuel. vendors' (Advanced - Nuclear Fuels) impact of temperature fluctuations on the plants accident analysis. The transient analysis by Advanced Nuclear Fuels only modelled nuclear instrumen-tation inputs into TMLP.
The nuclear instrumentation L signals are more responsive than delta-T power measure-t ments.
For events where delta-T power would provide the ' initial.RPS trip function, delaying the model until an NI power trip occurred generated conservatism in the analysis, i The licensee concluded, based on the fuel vendor and CE analysis, no impact un the_ safety accident analysis or licensing basis at Millstone 2 exists for RCS Th oscillations. The inspector had no further questions on the evaluations and licensee's conclusions.
Northeast Utilities actions on implementation'of CE's recommendations for installation of an IVM to monitor rector vessel internal movement will be reviewed in the future.
6.2.2 Modification of Control Circuitry for Instrument Air Compressors - Unit 1 The inspector observed the modification being conducted on the
control circuit for the non-safety-related instrument air compressor MS-4B which was controlled by work orders M1-89-10193 and M1-89-11372.
The work orders directed the I&C technician to make modifications in accordance with document change notice (DCN) 594-89, but provided no step-by-step procedure for completing the wiring L changes required by the modification. A second I&C technician, who < conducted the red line check to test circuit continuity identified two leads which were not relanded and one lead which was incorrectly landed.
In addition, the technician determined that the new design was faulty due to the improper location of a new relay. The control circuit was restored to its original configuration and the DCN was returned to engineering for redesign. The licensee acknowledged that the review of the initial design should have identified the design error.
A new DCN was prepared, which utilized a different contact and the modification was installed in instrument air compressor M5-4A.
During operational testing of the modification, a relief valve lifted as the instrument air compressor was started and loaded.
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However, workers stopped the leak by closing a manual
valve before the scram header air pressure decreased to the trip setpoint.
In addition, the fuse and power supply to the annunciators for the MS-4B instrument air compressor failed during testing of the M5-4A instrument air compressor. The inspector noted that for two , ' , days the facility operated with one instrument air compressor with an untested modification and a second instrument air compressor with inoperable annunciators.
Even though there is no regulatory requirement for operability of instrument air compressors, the ' reliance on untested or not fully functional auxiliary equipment is considered a poor operating practice.
The approved test procedure, which had been reviewed by the Plant Operations Review Committee (PORC) was modified to include a
requirement to establish direct communications between the main control room, the instrument air compressor control panel, and the local scram header pressure instrument.
The PORC approved the , requirement to test the trip function and a requirement to have the second instrument air compressor running in the lag mode, as well as a note which stated that if a scram signal was generated, the event , was reportable to the NRC.
The inspector observed the PORC review of the modified test i procedure, No discussion was held 2s to whether all control functions potentially effected by the modification would be tested or whether the instrument air receiver pressure could be accurately read > while throttling the air header discharge valve.
The second attempt to conduct the operations test identified that the instrument air compressor relief valve e s lifting below its 160 psig set point.
> , The inspector concluded that the initial design review for the DCN was inadequate to identify the design error and that the initial PORC review of the procedure was not of sufficient extent or depth to identify the needed modifications which were later made to the . procedure. However, the errors in design and enhancements to the test procedure were properly identified by the licensee through its testing programs.
6.3 Inservice Tecting - Unit 2 On October 3, Northeast Utilities corporate engineering, unit engineering and licensing personnel met with the NRC staff on a recently developed and modified steam generator eddy current testing probe. The meeting was established as a result of the NRC's requested mid-cycle shutdown for SG inspections. The initial probe design was manufactured by Atomic Energy of Canada to detect circumferentially-oriented cracks in steam generator tubes.
The probe is called a transmit-receive probe, having eight transmit and
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i i , s eight receive coils located on different radial planes on the probe.
The utility modified the initial transient-receive probe to install a
bobbin coil to detect and size nonerack flaws.
The capability goals of the probe are: to detect circumferential L cracks, to detect cracks and non-cracks, service life greater than a ! thousand tubes, and compatability with the utilities computer data acquisition system.
L The licenses discussed th'e qualification data of the modified I t transmit-receive probe.
The qualification data consisted of: !- detectability comparison with the rotating pancake coil; and ' comparison to various qualification standard flaws. The probe
L capability equates with the rotating pancake coil for both stress ! corrosion crack and controlled test specimens.
The limit of l detectability of circumferential cracks is approximately 42% deoth i
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with a 17 degree circumferential extent, i , ' Northeast Utilities presented a demonstration of the probe with various tube specimens. The utility had planned to implement the probe for steam generator eddy current testing during the mid-cu le , shutdown to commence on October 21.
In an August 30 letter t'o the NRC, the licensee documented the steam generator inspection scope and acceptance criteria. The steam generator inspection is not a required technical specification (TS) 4.4.S.I.3 surveillance; however, repair of any defective tubes will
be as required per TS 4.4.5.1.4.a.
The licensee has considered that ! the steam generators are operable, based on successful surveillance completed in April, 1989. Millstone Unit 2 TS 4.4.5.1.3 currently i requires a 20-month inspection interval based on category C-3 test results.
The planned inspection scope for the mid-cycle outage will be an inspection of 100% of the unsleeved tubes in the suspected cracking , i region.
This region was based on previously identified cracks, and consideration of sludge pile height.
The inspection scope will be expanded based on results to maintair, a border of three uncracked tube rows along the perimeter of the inspection region.
The NRC has not developed any further questions on the SG tube inspection scope for the mid-cycle outage.
In conclusion, the inspector noted good ongoing licensee efforts to continue to enhance the steam generator eddy current testing program based on the modification and future implementation of the transmit-receive probe.
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, , 6.4 P,r.e_viously Identified Items - Unit 2 6.4.1 (Closed) UNR 50-336/86-28-01: " Adequacy of QA/QC Direct Involvement in the Local Leak Rate Testino Program" n l 1he inspector questioned the adequacy of quality [ assurance (QA)/ quality control (QC) involvement in local leak rate testing during a 1986 inspection. As documented in inspection report 50-336/88-04, the licensee provided QA
coverage of the test preparations such as valve line-ups for the integrated leak rate test.
The QA personnel were < knowledgeable of their responsibilities on how to perform their duties and whom to report findings.
This item is closed.
, 6.4.2 (Closed) UNR 50-336/88-28-01: _10 CFR 21 Report2 "Limitorque Melamine Torque Switches" . Routine resident report 50-336/88-28 documented licensee initial actions on Limitorque SMB-00, and SMB-000 actuators installed in systems important to safety as it related to a November 3, 1988 10 CFR 21 report. The report documented potential common mode failure of melamine torque switches installed in,L'imitorque SMB-00 and SMB-000 actuators.
The open item dealt with licensee corrective actions, and circumstances of why Limitorque did not notify Northeast Utilities specifically in the 10 CFR 21 report.
The initial licensee action included: development of a plant design change request evaluation (POCE MP2-89-014) to replace the melamine torque switches; implementation of the vendor recommended actions of identifying failed limit switches; and review of previous motor operated valve analysis and test system (MOVATS) surveillance testing results.
During the Cycle 10 refuel outage (February - May, 1989) the licensee replaced all safety-related identified SMB-00 or SMB-000 actuator melamine limit switches.
The total population was 30 actuators in the - safety injection, charging, reactor coolant system, main steam and reactor component cooling wPter system.
The inspector reviewed all authorized work orders and retest acceptance criteria.
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!- Limitorque notification to Northeast Utilities was l completed prior to NRC review, however, the notification was initially sent to the QA organization for disposition.
This item is closed.
6.5 Justification for Continued Operation Evaluations - Units 1&2 On October 6, 1989, the inspector expressed concerns to the licensee about the quality of work performed by Satin America on refurbishing ' overload trip units based on information contained in NRC Information Notice 89-45.
The licensee committed to completion of a justification for continued operation ar. an engineering evaluation by October 16, 1989. The inspector reviwed the Unit I and 2 t engineering evaluation, Unit 1 justification for continued operation, purchase order, quality assurance section inspection package, , certification of compliance, trip test procedure and trip test ! results.
The inspector also requested Unit 2 management to provide a justification for continued operation for the affected refurbished - overload trip unit.
The engineering evaluation at Unit 1 identified only two DC overload trip units which had been refurbished by Satin America that are still installed in IE breakers'. The engineering evaluation at Unit 2 identified one DC overload trip unit refurbished by Satin America that is still installed in a IE breaker, which is located at the output of the ' spare' battery charger and is not normally in service.
At the end of the inspection period, the utility " caution tagged" the i breaker for limited use and had yet to complete the Millstone 2 l documented justification for operation.
The two breakers involved at Unit 1 are installed in DC switchboard 101B, one being the "B" station battery output breaker (battery connection to the bus) and the other being the normal supply from the switchboard to MCC DC-11A-1.
Due to the limited refurbishment done by Satin America, only two failure modes are possible.
Either the time overcurrent device can fail to trip the breaker or the time overcurrent device can trip the breaker prematurely.
Failure of the time overcurrent device to trip the breaker would allow the equipment powered from the DC buses to perform its safety related function. Also, the failure to trip has a low probability of i occurrence since both DC circuit breakers involved heve two separate ' overload trip units, one per pole, with only one of the overload trip units having been refurbished by Satin America. Assuming a failure of the refurbished overload trip unit, the time overcurrent function would not be lost as overcurrent detection on one pole would remain > to trip the breaker.
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- Premature tripping of the DC breakers due to the time overcurrent device would deenergize loads required for safety related functions.
The licensee has conducted several tests which demonstrate that the breakers will not trip prematurely.
Prior to installation of the overload trip units, calibration procedure PT1437, "125 VDC Power Circuit Breakers Test Procedures" was performed. The procedure included a timed tripping of the time overcurrent device.
In both cases, the overload trip units refurbished by Satin America met the timed trip criteria of between 24 to 80 seconds for a current of 300% of the long time setting.
In addition, the refueling outage service test on the battery was run in 1985 and the battery service test was maintained.
Successful completion of the tests demonstrated that the breakers did not trip prematurely when the battery was loaded.
Since the test, neither excessive exercising nor change in physical orientation of the time overcurrent devices have occurred which would effe:t the response of the overload trip units.
The inspector visually inspected nine AC and four DC overload trip units which had been refurbished by Satin America. One of the AC time overcurrent trip dashpots had a leaking boot and three other AC time overcurient trip dashpots appeared to have been replaced.
Even ' though the licensee's-purchase order required witnessing of the refurbishment of the two overload trip units, the refurbishments were not witnessed.
The two' units were inspected to verify proper assembly after the work was completed and the units were accepted.
Based on the apparent replacement of dashpots on some time overcurrent trip devices and the failure of the licensee to observe the remanufacturing process, the inspector questioned whether the refurbishment of the time overturrent devices was conducted in accordance with the licensee purchase order.
In order to verify the proper refurbishment of the time overcurrent devices, the overload units must be removed from the breakers and the licensee plans to replace the overload units when they are removed.
Irrespective of how the overcurrent devices were refurbished, the inspector concluded that sufficient testing and operational experience exists to allow continued operation with the installed overload trip units until the devices can be replaced with new General Electric supplied devices before the startup following the 1991 refueling outage. The inspector had no further questions.
6.6 Summary Licensee actions to maintain instrument air compressor operability for two days and sufficient review to identify the needed modifications under initial PORC review were minimal; improvements are warranted.
Future NRC follow-up of utility actions based on CE recommendations for long-term RCS temperature fluctuations and potential vessel internal movement is warranted.
Generally, good on going efforts to enhance the steam generator eddy current testing program were noted.
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7.0 Security (Ip 71707) ' ' 7.1 Security Tours During inspection tours, the inspector reviewed selected aspects of >;t; security, including site access controls, personnel searches, personnel monitoring, placement of physical barriers, compensatory measures, guard force staffing, and response to alarms and degraded conditions.
No inadequacies were noted.
7.2 Review of Security perimeter The inspector walked down portions of the protected area security fence on October 4 to verify the facilities met the requirements of the security plan.
No conditions contrary to the minimum security requirements were identified.
The following matter required followup.
The inspector noted an armed guard posted as a compensatory measure along the east side of the site.
The inspector interviewed the guard to determine the purpose for his post and how his duties were being met.
The inspector noted that a booth that normally provides shelter for the guards in inclement weather was lying on its side and not useable for its intended purpose.
Although the minimum security requirements of the Security Plan were being met for both the established post and the guard's assigned rounds, three concerns were identified and discussed with the security supervisor, including: 1) use of armed response personnel for certain posts; 2) adequacy of staffing to cover needed posts; and, 3) sensitivity to guard personal needs while standing watch.
The licensee noted the inspector's comments and stated actions would be taken to provide proper shelter as required.
Licensee review of the guard assignments for the day in question determined the central alarm station (CAS) supervisor acted independently for assignment of the post.
He was counseled on i licensee expectations to use utility security supervisors to assist
in reassigning post priorities.
The licensee plans to issue further t guidance in a memorandum to clarify this matter with all supervisors.
The inspector reviewed the guard staffing for the general duty roster and particularly for the day in question. The licensee demonstrated that adequate staffing was available.
No inadequacies were identified regarding the availability of armed responders and response weapons.
The inspector had no further comments on this matter at this time.
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' , 7.3 Security Guard Fitness for Duty The licensee informed the resident inspector that a security guard , had been suspended from duty effective October 5, 1989.
The action was taken upon receipt of the announced annual drug screening' test , results that showed THC present in the individual. The guard s badge l was inactivated. to deny access to the protected area and the individual was placed on suspension pending further review of the matter.. The guard was terminated on October 11 following a licensee contractor / employee disciplinary hearing, , The inspector reviewed the requirements of the licensee's fitness for duty program and discussed the actions taken by the licensee with the NNECO security supervisor. No inadequacies were identified.
7.4 Allegation Concerning Security Post Manning During Severe Weather Conditions > On July 17, the inspector received a concern from a security employee on manning of a security post during severe weather conditions.
Specifically, the individual questioned if a guard should be on station at the vehicle access to the north and south entrance points during a lightning storm. The individual initially approached the licensee on this item and was told during severe weather to stand the post as required.
The inspector discussed the above issue with the station services superintendent on July 28.
The licensee has established a security department instruction to . provide guidelines to protect security personnel during severe weather conditions. The responsibility of implementation of the departmental instruction is the security shif t supervisor. The instruction generally describes actions during high wind and lightning storms, and specifically to the extent if security measures can no longer be maintained based on severe weather, and required reportability issues to the NRC.
The inspector discussed the licensee actions with the security employee.
The employee was satisfied and had no further questions.
This item is closed.
7.5 Summary One security allegation was closed with appropriate licensee cor-rective actions.
The licensee demonstrated adequate staffing and no inadequacies were identified regarding the availability of armed responders and response weapons.
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1 i E 8.0 Safety Assessment / Quality Verification (IP 30703/40500/90712/92702) 8.1 Committee Activities The inspector attended meetings 2-89-144, 2-89-145, 2-89-146, 2-89-152, 2-89-158, 2-89-160, and 2-89-162 of the plant operations review committee (PORC) on September 5, September 5, September 8, ~ September 19, October 6, October 18, and October 19, respectively.
l The inspector noted by observation that committee administrative ' requirements were met for the meetings, and that the committees discharged their functions in accordance with regulatory requirements. The inspector observed a generally thorough discussion of matters before the PORC, except as discussed in section 6.2.2, ' ! and a good regard for safety in the issues under consideration by the cominittee.
Topics discussed and approved at PORC included: Revision to procedure SP2401G "RPS Bistable Trip Surveillance" -- Operability evaluation for the "A" emergency diesel generator -- Update ASME Section XI program to include selected emergency -- diesel generator auxiliary valves Plant incident report 89-59 closeout -- Non-intent changes to instrument and control and ISI -- surveillance procedures
Update ASME Section XI maintenance procedure MP-27015 -- Bypass jumper approval of SDC system suction valves 2-SI-651 -- and 2-SI-652 during reduced inventory operation Modification of instrument air compressor test procedure -- No inadequacies were identified.
8.2 Periodic Reports - Unit 2 Upon receipt, periodic reports submitted pursuant to technical specifications were reviewed. This review verified that the reported information was valid and included the required NRC data.
The inspector also ascertained whether any reported information should be classified as an abnormal occurrence. The following reports were reviewed: Monthly Operating Report 89-08 -- Monthly Operation Report 89-09 -- No inadequacies were identified.
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8.3 previously Identified Item (Violation / Deviation) (Closed) UNR 50-245/89-12-01: LER 89-10. " Failure to ! Complete Surveillances in Required Time" This item concerned failure to perform monthly surveillance tests at the required frequency. The instruments involved were the reactor [ building ventilation exhaust duct, refueling flow, and steam tunnel
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ventilation radiation monitors, and the fire protection non-supervised' lines. No violation was issued as a result of these failures pursuant to the criteria listed in 10 CFR Part 2 Appendix C, Section V.G.1, Exercise of Discretion.
' Licensee corrective action included the promulgation of instrumentation and controls (I&C) department procedure IC-491A, Review of Deferral of Technical Specifications Surveillance, Revision - 0, dated July 26, 1989.
This procedure provides instructions to
ensure that the surveillance schedule is followed.
Specifically, the department supervisor is assigned the responsibility to ensure that ' TS surveillance tests are performed within the required periodicity, and to approve the independent review of the weekly swveillance list as required to be performed by the I&C preventive maintenance management system (PMMS)'1A and found that it adequately addressed NR planner / station technician.
The inspector reviewed procedure IC-49 concerns regarding a forn.al surveillance tracking program.
This item ' is closed.
8.4 Surveillance Procedure Timeliness On October 3,1989, I&C surveillance procedure SP-412L, Isolation Condenser Isolation Instruments Functional and Calibration Test, was performed. During a review of the test results, the licensec ' determined that the procedure had not been performed by September 25, i 1989 within the period required by TS, including the 25 percent of test' interval extension permitted by TS 1.0.X.2.
The inspector discussed this late surveillance test with the , , ! assistant I&C department supervisor and learned that SP-412L had not been entered into the PMMS planners' computer list.
As a result, when checked, the computer failed to include the procedure in the l-list of required tests for the week of September 10-16, 1989.
The supervisor further stated that the I&C department PMMS planner / station technician maintains a backup status board but had been in training during the week involved. The inspector expressed p concern that the department tracking system not be dependent on the presence of a particular individual to ensure adequate program t implementation. The assistant supervisor acknowledged this concern.
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" The isolation condenser is an engineered safety feature which provides a heat sink for the reactor in the event of 1) a scram t T followed by group I isolation of the reactor from the unit main
condenser, or 2) a small break loss of coolant accident concurrent with a loss of feedwater injection to the reactor vessel.
Redundant , differential pressure indicating switches sense flow through the system steam and condensate lines and isolate the system from the
primary coolant system in the event of a line break. This group IV isolation function is designed to mitigate the consequences of an accident and protect against a gross release of radioactive material from the primary containment.
! The safety significance of this event is small based on the satisfactory completion of the surveillance test on October 3, 1989.
Conditions requiring the isolation of the isolation condenser system are annunciated in the control room, where the isolation yalves can , , be manually operated.
Further, in the event of a spurious system isolation, automatic valve close demand signals are overridden by , operation of remote-manual switches.
i Nonetheless, the failure to perform a surveillance within the time , pariod required by TS is a violation (VIO 50-336/89-23-03). The violation is being cited in this case because of the apparent failure of licensee corrective actions to preclude recurrence of a previous event (see section 8.3).
Effective implementation of the licensee program for scheduling, tracking, and performing surveillance tests required by TS will continue to be monitored as part of the routine resident inspector program.
8.5 Licensee Event Reports (LER) Review License event reports submitted during the period were reviewed to assess LER accuracy, the adequacy of corrective actions and l compliance with 10 CFR 73 reporting requirements, and to determine if ! there were any generic implications or if any further information was required.
Three LERs were reviewed.
, LER 89-007-01: " Missed Radiation Monitor Source Check": The Nuclear , l Review Board (NRB) identified two process radiation monitors surveillance procedures previously conducted without the required i l source check. The two radiation monitors were the condensate l polishing facility and waste gas radiation monitor.
The environmental technical specifications were changed to the l radiological effluent technical specifications on February 1, 1986.
During the change in specifications, the source check surveillance requirement was added to both process radiation monitors. The l licensee reported the event under 10 CFR 50.73(a)(2)(1)(B). Upon ' licensee identification, the source check was included in the
surveillance procedures on March 22 and August 24, 1989 for the l-respective monitors.
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The root cause of the event was failure to adequately implement TS requirements into the appropriate surveillance procedure. The significance of the missed source check surveillances is minimal, ' > based on successful functional and calibration surveillances with no identified deficiencies such that the monitors were unable to monitor radii; active discharges.
Licensee corrective actions included revisions to both radiation ! t monitor surveillance procedures and a programmatic review of other radiological effluent technical specifications for surveillance agreement. The current utility program on TS revisions include operations department review to ensure the requirements are fully , implemented. The program is continually on going and currently being upgraded.
, The LER addressed the 10 CFR 50.73 reporting requirements. The ' licensee identified the missed surveillances, and took appropriate actions to preclude the recurrence of a similar event.
The inspector noted that this event was addressed previously in NRC Region I inspection report 50-336/89-16 and had no further questions.
LER 87-007-01: " Reactor Trip": On September 22, 1989, the licensee provided an update LER to docurrent the completion of corrective actions for a turbine tr'ip/ reactor trip on April 16, 1987, which was described in routine resident report 50-336/87-06..The update corrective actions included monitoring for six months, voltage inputs to determine the root cause of the main generator volts / hertz relay 59X2 inadvertent actuation on April 16, 1987. The monitoring noted no spurious actuation voltages.
The root cause of the 59X2 relay actuation is unknown.
The 59X2 relay protects the main generator against over-excitation during the time interval when the generator is excited but not paralleled to the grid.
The licensee reinstalled the 59X2 relay after the six-month monitoring period.
No other actuations have occurred since April 1987.
The inspector had no further questions.
l l LFR 87-003-01. " Defective Steam Generator Tubes Not Repaired l Pfior to Startup": On September 28, 1989, the licensee updated LER 87-003 initially documented on February 26, 1987. The update information was long term corrective actions to prevent a steam generator tube defect not being repaired as required in action statement for TS 4.4.5.1.4.b.
The long-term corrective actions include: plant specific data analysis training including written and .. practical examinations.
The inspector had no further questions on E l the update LER.
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> 8.6 Summary A missed surveillance test, as a result of ineffective implementation of the licensee program for scheduling, tracking and performing surveillance tests required by TS at Unit 1, is being cited as a violation.
L LER 89-07-01 adoressed missed surveillance requirements of process radiation monitors at Unit 2, which is considered a non-cited, licensee-identified violation. A licensee programmatic review program to ensure requirements are fully satisfied is currently in progress.
9.0 Reactive Inspection Activities (92702) 9.] NRC Bulletin / Generic Letter /Information Notice Follow-up On August 3, 1989, the NRC issued Information Notice (IN) 89-58 " Disablement of Turbine Driven Auxiliary Feedwater Pump Due to Closure of One of the Parallel Steam Supply Lines." The notice alerted lic u sees to a potential for causing the turbine driven auxiliary feedwater pump to be incapable of performing its intended safety function by closing one of the turbine parallel steam supply ' valves.
On June 22, the licensee issued plant incident report (PIR) 89-63 documenting the in-service test failure of steam supply check valve 2-MS-4B to the turbine-driven auxiliary feedwater pump. The licensee's actions upon surveillance failure was to isolate one of two parallel steam supplies to the turbine-driven pump.
The inspector reviewed the licensee's auxiliary feedwater configuration, safety analysis report on loss of normal feedwater accident, TS basis for auxiliary feedwater pump operability and - supporting licensee documentation, and discussed licensee actions in response to IN 89-58. The review considered if the Millstone 2 current auxiliary feedwater system configuration met the intended safety function.
The intended safety function for the AFW system is to remove stored and riactor decay heat to prevent reactor coolant system overpressurization, coincident with the single-failure criterion and loss of normal feedwater.
The applicable TS basis documents that one of the motor-driven AFW pumps provides adequate flow to the steam generators without challenging RCS overpressure protection.
The inspector reviewed the licensee's calculation for the TS bases provided in a May 20, 1980 letter to the NR _ o.. .- .e , c' . .. '
The loss of normal feedwater analysis assumes the normal feedwater regulating system is inoperative. Assuming single active failure of one of the two motor driven putnps, and a passive AFW feedline break, one motor driven AFW pump is still available to maintain a heat sink in the-steam generators. The turbine-driven AFW pump is inoperative due to loss of steam flow from the steam generator with the passive failure.
In the course of this review the inspector noted an apparent discrepancy between the FSAR accident review and the TS basis for the combination of AFW pumps necessary to remove reactor decay heat. The discrepancy was presented to the licensee for disposition.
In conclusion, the licensee maintains the auxiliary feedwater system's intended safety function with one of two parallel steam supply valves shut to the turbine driven auxiliary feedwater pump.
9.2 Allegation: Reactor Protection System (RPS) Matrix Testing (RI-88-0040) On September 22, the inspector received two concerns from a licensee employee.
The concerns were: During performance of RPS matrix testing, an 6bnormal time delay was indicated in the activation of the hold / drop-out light'in the trip path for channels A and D RPS logic combination, potentially resulting in a time delay impacting RPS response time and operability, and the alleger was " directed" by the shift supervisor to continue the surveillance rather than investigate the identified test discrepancy as required per procedure.
On September 22, the alleger was performing monthly surveillance procedure SP 24010 "RPS Matrix Logic and Trip Path Relay Test" as required per technical specification 3.3.1.1, Table 4.3-1, Item 12 and 14.
Procedural step 6.18 says to place the AD matrix channel trip select switch to off and verify the AS-1, AD-2, AD-3, and AD-4 hold / drop-out white lights are on. The acceptance criterion is that the lights are illuminated with no prescribed time interval. The alleger indicated that the hold / drop-out lights illuminated with an abnormal time interval (two-four seconds). The initial concern was if the time delay potentially impacted the RPS operability. The inspector assessed RPS operability utilizing licensee wiring diagrams, FSAR 7.2.3.2.2, and 7.2.4, discussions with licensee personnel, review of SP 24010, and review of TS 3.3.1.1 requirements.
RPS matrix testing (SP 24010) is performed by opening a pair of contacts in the trip matrix and then selectively allowing one matrix relay at a time to operate.
Matrix testing on 9/22/89 noted a time delay between when position 2 was selected on the AD matrix trip select switch and when the matrix relay dropped out.
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y The contacts in the trip matrix are selected by the channel trip select switch. This selects the parameter (e.g., high power) to be tested. When a valid. position is selected on the channel trip select , switch, and the matrix relay hold push button is pressed, power is applied to the " buck" coil in each of the two trip matrix relays ' selected. The buck coil opposes the normal coil and forces the trip matrix relays to open. When the relays open, the corresponding trip lights illuminate on the RPS bistable indicating the trip matrix relays have opened. Opening the trip matrix relay contacts removes i power to the matrix relays. The matrix relay hold push button also ' applies power to the matrix relay " boost" coils.
The boost coils ! hold the matrix relays closed when the power is removed from the normal coils.
This prevents a plant trip during matrix testing. The matrix trip select switch opens the circuit to the boost coil of one matrix' relay at a time.
The matrix relay selected then drops out and a pair of scram breakers opens.
If the contacts on the matrix trip select switch do not open, the power to the boost coil isn't removed and the matrix relay won't drip out. The buck and boost test circuit coils in the trip matrix relays and matrix relays are electrically separate from the normal trip relay coils. The normal relay coils continue to function even while the test circuit coils are being used.
The function of the RPS to open the scram breakers in the required time when a trip condition exists is not affected by position 2 of the AD matrix trip select switch and subsequently the time delay associated with the hold / drop-out lights.
The licensee investigation further indicated this item was previously identified on August 18, 1988 during the performance of surveillance SP 26010. Work order M2-88-09225 was generated to replace the matrix relay select switch for the RPS AD matrix during the mid-cycle outage starting on October 21, 1989.
The inspector interviewed the shift supervisor on September 23. The shif t supervisor stated that during the matrix test, the alleger came to him to report an anomaly in completing the test which the alleger ! thought was an anomaly required to stop the test pending further I investigation. The problem presented to the shift supervisor was l that the drop-out light was delayed by several seconds while j performing the test of the AD logic.
' The shift supervisor stated he spent time with the alleger reviewing the step in question, what action was required, and what procedure requiretrents existed for completion of the step. Based on this review, the shift supervisor stated he concluded there was little significance in the delay in illuminating the drop-out light, since there is no explicit acceptance criteria stated or implied to complete the step.
Since the desired action did oe:ur after only a few seconds, the shift supervisor concluded that the delay was not significant, that the intent of the step had been met, and that there _ - --__, .
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was no anomaly that would warrant immediate investigation such that testing should be suspended. The shift supervisor stated that during the test he requested the test be continued, ("I would like to finish the test"). The shift supervisor stated he tried to contact I&C supervision to request evaluation of the test results after comple-tion. The shift supervisor was aware that the issue was evaluated later on September 22 and determined to be a known problem that involved the RPS matrix test circuitry only. The shift supervisor's basis to continue the surveillance at the time of the test, was that the delay was not significant because of the lack of explicit or implied acceptance criteria in the procedure on the completion of the step. The shift supervisor was confident at the time that RPS operability was not at issue based on his general knowledge of testing procedures at Hillstone, and critical test results are highlighted by acceptance criteria.
Followup review by the inspector indicated the licensee was aware of the problem in the RPS test circuit since August, 1988. The inspector concluded that control of trouble report identification for this item was inadequate, and a work brief prior to conducting the surveillance procedure should have identified the known discrepancy.
Inspector review has concurred with the licensee conclusion that RPS operability was not af fected. When looking at the basis for the shift supervisor's decision, it can be said it was reasonable given the facts available, and it was ultimately proven acceptable when the issue had the benefit of full review by management on the same day of occurrence. The inspector concluded a difference of opinion exists between the alleger and the shift supervisor. The inspector considered that the shift supervisor decision, to continue testing and resolve the significance of the anomaly after the test was completed, was acceptable.
This item is closed.
9.3 F_ollowup on previous Allegations On October 11, the NRC issued special allegation inspection report 50-336/89-13 for Millstone 2.
As a result of the inspection, five violations were identified which dealt with 1) multiple examples of failures to follow procedures, 2) lack of seismic documentation for an electric conduit run, 3) technicians using outdated drawings, 4) failure to functionally test a radiation monitor alarm, and 5) improper control of overtime.
None of the violations, either singularly or collectively represented a major safety issue. The inspectors will review licensee actions in response to the special inspection report during future routine inspections.
10.0 Management Meetings 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 inspection.
No proprietary information was covered within the scope of the inspection.
No written material was given to the licensee during the inspection period. }}