IR 05000245/1998006
| ML20207E126 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 03/01/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20207E123 | List: |
| References | |
| 50-245-98-06, 50-245-98-6, 50-336-98-06, 50-336-98-6, 50-423-98-06, 50-423-98-6, NUDOCS 9903100155 | |
| Download: ML20207E126 (45) | |
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U.S. NUCLEAR REGULATORY COMMISSION i
REGION I
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F Docket Nos.:
50-245; 50-336; 50-423 l
Report Nos.:
98-06 98-06 98-06
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License Nos.:
Licensee:
Northeast Nuclear Energy Company
~ P. O. Box 128 Waterford, CT 06385 Facility:-
Millstone Nuclear Power Station, Units 1,2, and 3 Inspection at:
~Waterford, CT
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Dates:
November 23,1998 - January 11,1999 Inspectors:
T. Eastick, Senior Resident inspector Unit 1 D. Beaulieu, Senior Resident inspector, Unit 2 A..Ceme, Senior Resident inspector, Unit 3 P. Cataldo, Resident Inspector, Unit 1 S. Jones, Resident inspector, Unit 2 B. Korona, Resident inspector, Unit 3 T. Bums, Engineering inspector P. Frechette, Safeguards Specialist J. Jang, Sr. Radiation Specialist
'J. Noggle, Sr. Radiation Specialist L
Approved by:
Jacque P. Durr, Chief
Millstone Inspection Branch
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. Office of the Regional Administrator l
Region l l
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A 9903100155 990301 F
PDR ADOCK 05000245
PDR L
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TABLE OF CONTENTS PAGE EXEC UTIVE SU M MARY....................................
..............v U 2.1 Operations............................................
............. 1 U2 01 Conduct of Operations.................................................. 1 01.1 General Comments (71707)....................................... 1 U2.ll M ainten ance.......................................................... 2 U2 M 1 Conduct of Maintenance................................................ 2 M1.1 Overhaul of the "B" Service Water Pump............................. 2
M1.2 Refueling Operations............................................. 2 M1.3 Integrated Test of Facility 2 Engineered Safety Features Components......
j U2 M8 Miscellaneous Maintenance issues........................................ 7 M8.1 (Closed) LERs 50-336/96-038-00 and 97-012-00; Inadequate Surveillance Procedures Used to Verify Emergency Diesel Generator Operability; (Open) eel 50 336/97-02-12; (Update - Unit 2 Significant items List No. 8.6).........
U2.lli Enginee ring........................................................... 8 U2 E1 Conduct of Engineering................................................. 8
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E1.1 Review of items to be Completed After Restart (Update - Unit 2 Significant items Lis t N o. 12)................................................... 8
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U2 E8 Miscellaneous Engineering Issues................................ 10 E8.1 (Closed) Follow-up item 50-336/94-201-90; Emergency Diese: Generator Fuel Oil Supply Tank Capacity - (Closed) Unit 2 Significant items List item N o. 4 2)................................................... 10
. E8.3 (Closed) eel 50-336/96-201-25; Failure to Effectively Track and implement I
Corrective Actions Concerning Dual-Function isolstion Valves; (Closed - Unit 2 Significant items List No. 30)..................................... 12 U 3.1 Operations............................................................ 15 U3 01 Conduct of 0perations................................................. 15 01.1 General Comments (71707)...................................... 15 U3 02 Operational Status of Facilities and Equipment............................. 16 O2.1 Automatic Reactor Trip During Main Steam isolation Valve Partial-stroke l
Te sti n g....................................................... 1 6
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' TABLE OF CONTENTS (CONT'D)
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PAGE U3 08 Miscellaneous Operations issues (92700)................................. 19
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08,1 : (Closed) Violation 50423/g6-05-12: Failure to Audit the Technical Specifications................................................. 19
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U 3.11 M aintenance.......................................................... 20
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U3 M1 Conduct of Maintenance............................................... 20 M1.1 Maintenance Observations....................................... 20 U3 M2 Maintenance and Material Condition of Facilities and Equipment.............. 21
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M2 Maintenance and Material Condition of Facilities and Equipment......... 21 -
M2.1 Main Steam isolation (MSIV) Solenoid Valve (SV) 3 MSS *SV27A1 A Piston Cracking...................................................... 21 '
j U3. Ill Engineering.......................................................... 23 U3 E1 Conduct of Engineering................................................ 23 E1.1 ! Blown Fuse on Safety Related 4160 V Bus 34D...................... 23 U3 E2 Engineering Support of Facilities and Equipment............................ 25
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E2.1 Waste Test Tank Leakage - Radiological Review and Design Follow-up...
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l il Plant Support............................................................. 28
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R1 Radiological Protection and Chemistry Controls............................. 28 R1.1 Radioactive Waste (Radwaste) Program............................. 28
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R3;. Radiological Protection and Chemistry Procedures and Documentation..........
R3.1 3 Radioactive Material Shipment Records and Procedures............... 30 R5
' Staff Training and Qualification in Radiological Protection and Chemistry.........
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- Quality Assurance in Radiological Protection and Chemistry Activities........... 31 S1 Conduct of Security and Safeguards Activities.............................. 32 S2 Status of Security Facilities tend Equipment................................ 33 L
S3 - Security and Safeguards Procedures and Documentation..................... 34
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TABLE OF CONTENTS (CONT'D)
PAQE
S4 Security and Safeguards Staff Knowledge and Performance................... 34 S6 Security Organization and Administration.................................. 35 S7 Quality Assurance in Security and Safeguards Activities...................... 35 IV.
Management Meetings.............................................. 36 X1 Exit Meeting Summary................................................ 36
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EXECUTIVE SUMMARY Millstone Nuclear Power Station Combined Inspection 245/98-06; 336/98-06; 423/98-06 Operations At Unit 3, licensed operator recovery actions, and overall control room activities, in
response to the unexpected main steam isolation valve (MSIV) closure and resultant automatic reactor trip were deliberate and well controlled. While the lifting and reseating of two main steam safety valves (MSSVs) was identified in a timely manner and reviewed for adequate system response, this information was not initially disseminated to all operators involved in recovery operations. Plant equipment performed as expected.
Licensee activities to investigate the cause of this event and implement corrective actions, in the form of a design modification to the MSIVs, were well detailed, planned, and executed. The licensee also evaluated causal factors for this event with respect to historical solenoid valve performance problems. NRC review of this assessment and j
these factors determined that the solenoid valve failure mechanism specifically related to q
the current event was different than that identified with previous MSIV solenoid j
concerns. However, both sets of problems appeared correctable with the implementation of the design modification, which installed upgraded solenoid valves fabricated with new material types. Certain issues involving continued MSIV stroke testing plans and LER follow-up, documenting further metallurgical studies, remain open
for additional NRC review and inspection. (Section U3 O2.1)
Maintenance Overall, the Unit 2 refueling was executed well with good management oversight. In e
addition, the inspectors noted a strong presence by Nuclear Oversight in the preparation for Mode 6, the fuel reload, to the final core verification following reload. Although fuel
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handling operations were generally well controlled, one incident occurred where the spent fuel pool area hoist operator raised a fuel assembly approximately 2 inches above the prescribed height and when recovering from this, the operator did not immediately stop when the fuel hoist did not respond as expected. Similarly, when two pieces of tape were found on top of fuel assemblies in the spent fuel pool, the licensee did not initially plan to assess the impact of undetected tape on the fuel and core components during power operations. (Section U2.M1.2)
e At Unit 2, the NRC found that the preparations for and performance of the integrated test of Facility 2 engineered safety features components were conducted well. The integrated test, in combination with individual component surveillance tests, satisfied the technical specification surveillance requirements for Facility 2 components. However, during the test restoration, the inspector discussed with operators the propriety r.,f using a valve lineup form to restore the shutdown cooling system valve alignment rather than
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an approved procedure that controlled the sequence of valve manipulations. The NRC
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systems was a general weakness in operations. This is a concern because a valve
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lineup form does not control the sequence of valve manipulations, which is often important for in-service systems. (Section U2.M1.3)
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e Overall, for the selected maintenance work items and maintenance field observations at Unit 3, the inspector identified acceptable work controls, equipment conditions, and l
coordination amongst the maintenance, operations, and engineering departments.
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(Section U3 M1.1)
l The preliminary failure mechanism of stress corrosion cracking for the Unit 3 main steam
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e isolation solenoid valves appears reasonable, although a formal root cause remains to l
be determined. The licensee's material reconciliation effort was thorough and of
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l sufficient depth to provide a basis for the installation of new MSIV solenoid valves.
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(Section U3 M2.1)
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Engineering i
The inspectors concluded that the licensee's decision-making process for the
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o identification of items to be completed after the restart of Unit 2 was cornervative and thorough. The process resulted in the not containing items that were appopriate for l
deferral. The inspectors did not identify any issues that, if not corrected pior to plant
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restart, would have resulted in a significant safety concem during plant operations. Unit 2 Significant items List 12 remains open pending NRC review of an additional update to
the deferred items list that the licensee is required to submit prior to restart. (Section U2.E1.1)
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The licensee's corrective actions for Unit 2 Significant items List (SIL) No. 42 were e
incomplete at the time of the inspection. This SIL item concerned the fact that the emergency diesel generators fuel oil supply tanks did not have the 7-day capacity l
specified in the final safety analysis report. Subsequently, the licensee issued changes l
to the associated surveillance procedures. Those changes were reviewed by the NRC l
and found to be appropriate, therefore, SIL No. 42 was closed. (Section U2.E8.1)
At Unit 2, the licensee's corrective actions were acceptable in addressing eel 50-336/96-e 201-25, which involved the failure of the licensee to track and implement corrective actions conceming dual-function isolation valves. eel 50-336/96 201-25 and Unit 2 L
Significant items List No. 30 are considered closed. (Section U2.E8.2)
At Unit 2, the licensee's corrective actions were acceptable in addressing Violation 50-e 336/98-216-02, which involved repsated incidents where the reactor coolant system heatup and cooldown rate limits epecified in technical specifications were exceeded.
Violation 50-336/98-216-02 and Unit 2 Significant items List No. 24 are considered closed. (Section U2.E8.3)
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<.. Following the failure of a potential transformer fuse in the Unit 3, "A" train 34D, 4KV bus,
=e4 operators took appropriate actions to declare the affected instrumentation inoperable and
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entered technical specification 3.3.2. The licensee initially determined that l
troubleshooting and repair could be performed on the affected instrumentation while in l
TS 3.3.2. The inspector discussed this determination with plant management,and after a subsequent discussion with NRR, the licensee decded not to perform the work using
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this TS. Thorough licensee discussion of the plant design and options for
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troubleshooting were observed. The normally scheduled monthly operability
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surveillance, performed at power, and troubleshooting on the affected instrumentation, l
performed in cold shutdown, were well controlled and completed without affecting
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- operable plant equipment. (Section U3 E1.1)
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. After discovery of a waste test tank leak, licensee corrective actions were appropriately
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taken to assess the impact and prevent recurrence of such an event. The inadvertent-i release of radioactive material to the environment did not violate license conditions and was evaluated to have low safety significance. However, weaknesses in the licensee's
reportability, engineering, preventive maintenance, and environmental programs were i
s :f-identified by this event. (Section U3 E2.1)
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. Unit i liquid and solid radwaste systems continue to need improvements in order' s be e
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functional. Currently, the "A" train of the floor drain system and the spent resin enk i
discharge system are not available. Onsite storage of radioactive wastes and reusable contaminated equipment were well managed and organized with a small backlog of I
radwaste remaining to be processed and shipped. The radwaste processing and l
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packaging program was effective. (Section Ill.R1.1)
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e All radioactive material shipments reviewed were determined to be in compliance with i
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the applicable provisions of Titles 10 and 49 CFR. The technical training program for
personnel involved in the transportation of radioactive materials was effective. The licensee provided an independent review of all radioactive material shipments from Millstone Station utilizing detailed checklists, which was effective. (Section Ill.R)
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e The security program was inspected during this period. The inspection consisted of
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l selective reviews of procedures and records, inspector observations, and interviews with 1-security personnel. No safety concems or violations were identified. The inspector i
determined that the security program was effectively implemented to protect against acts
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of radiological sabotage. (Section Ill.S)
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e The review of the licensee's audit program for security indicated that audits were comprehensive in scope and depth, that the audit findings were reported to the
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appropriate level of management, and that the program was being properly J-
administered. In addition, a review of the self-assessment program documentation in conjunction with the key performance indicators program indicated that the programs j
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(Section Ill.S7)
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Report Details
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Summarv of Unit 2 Status The unit was initially shut down on February 20,1996, to address containment sump screen concems and has remained shut down to address the problems outlined in the Restart Assessment Plan and a NRC Demand for Information [10 CFR 50.54(f)] letter requiring an assertion by the licensee that future operations are conducted in accordance with the regulations, the license, and the Final Safety Analysis Report.
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Unit 2 entered the inspection period with the reactor core off-loaded to the spent fuel pool.
During the inspection period, the licensee entered operational mode 6, refueling, on December 31,1998, and completed reloading the core into the reactor vessel on January 6,1999. At the completion of the inspection period, Unit 2 remained in operational mode 6 with reactor vessel component reassembly in progress.
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LL2.I Operations U2 01 Conduct of Operations 01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspector conducted frequent reviews of ongoing plant operations, including observations of operator evolutions in the control room; walkdowns of the main control boarda; tours of the Unit 2 radiologically controlled area i
and other buildings housing safety-related equipment; and observations of several l
management planning meetings and plant onsite review committee meetings.
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The inspector observed operational preparations, procedural adherence, and the control of shutdown risk during the following evolutions: the Facility 2 maintenance outage, the subsequent Facility 2 surveillance testing window, the transition to operation with Facility 2 systems and components protected, the transition to operational mode 6 (refueling),
refueling activities, and the beginning of reactor vessel reassembly. In general, the operators conducted the evolutions described above well. The inspectors noted continued sensitivity to special conditions and equipment outages that affected shutdown safety. The operators exhibited improving standards relative to procedural quality and adherence by their willingness to stop evolutions to correct inadequate procedures.
However, the inspector identified a performance weakness in that operators demonstrated a willingness to realign systems in an operational state to their baseline configuration using " valve lineup" forms, which did not provide adequate procedural controls. This issue is described in Section M1.2 of this report.
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U2.ll Maintenance U2 M1 Conduct of Maintenance M1.1 Overhaul of the "B" Service Water Pumo a.
Inspection Scoce (62707)
The inspectors observed a portion of the work activities associated with automated work order (AWO) M2-93-01594, ""B" SW Pump Mechanical Overhaul." The inspector reviewed the work order ard associated documents and interviewed licensee field personnel to evaluate the propriety of the maintenance activities and the functionality of systems and components with respect to technical specifications and other requirements.~
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Observations and Findings
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The inspector observed the disassembly of the service water pump, the inspection, and alignment activities. The inspectore found that the work was being performed in accordance with approved proosdures ::nd that the work order was present at the work site. A review of the work package found that it was complete with respect to work authorization, procedures, and inspection and retest requirements.
Interviews with the mainterance supervisor and maintenance engineer indicated that they had a good understanding of the ovenaul procedure and inspection requirements.
The inspection of the pump was thorough and the identified defects were appropriately addressed.
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Conclusions
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The inspectors concluded that the "B" service water pump overhaul was thorough and satisfied the objectives of the activity. The plant staff used the appropriate procedures and completed the work as outlined in the work packages. The work packages provided comprehensive information regarding the scope and performance of work activities.
M1.2 Refuelino Operations
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Inspection Scope (60705/60710)
The inspectors observed, in part, preparations and performance of reactor core reload activities at Unit 2. The inspector reviewed refueling procedures and surveillance test results, and interviewed licensee personnel to evaluate conformance with technical specification requirements during the transition into operational mode 6, refueling.
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Observahons and Findings l
The inspector reviewed the licensee's preparations for refueling and conducted a sample
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of surveillance test results to assess compliance with Technical Specification l
requirements for entry into operational mode 6, refueling. As documented in NRC
inspection Report 50-336/98-216, the NRC had reviewed early preparations for refueling
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and assessed system readiness for entry into operational mode 6. The inspector
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focus on.those surveillances having a periodicity more frequent than monthly. In
addition,'a complete review was performed of surveillance requirements for core
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alterations and movement of irradiated fuel. The inspector verified that the surveillance
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procedures executing these surveillance requirements were complete prior to entry into operational mode 6c The inspector found that the licensee's controls were effective in ensuring surveillance requirements were satisfied for entry into operational mode 6.
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The inspectors observed refueling operations from the control room, spent fuel pool l
area, and the refueling area inside containment. Overall, the refueling was executed well with good management oversight.- In addition, the inspectors noted a strong presence by Nuclear Oversight in the preparation for Mode 6, the fuel reload, to the final core verification following reload. Around the clock coverage was provided by Nuclear Oversight for activities in the control room as well as in the field. Their observations resulted in two condition reports being generated, each related to foreign material exclusion practices.
Although fuel handling onerations were generally well controlled, one incident occurred where the spent fuel pou area hoist operator raised a fuel assembly approximately 2 l
' inches'above the prescribed height for fuel movement. While raising a fuel assembly, the operator must monitor the position of the hoist, which is located directly in front of -
him, and must also monitor the load cell indication, which was located about 20 feet to the right of the hoist operator. The load cell is monitored to identify an unexpected increase in hoist tension that could indicate a problem with the lifting evolution. The operator stated that this configuration contributed to him raising the hoist 2 inches above its prescribed height.
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The fuel assembly had been raised high enough to engaged one of two safety features that prevent damage to the hoist by stopping any further upward movement of the hoist, but the operator was unaware that the safety feature had engaged. To restore the hoist, l
the operator lowered the fuel assembly to a point slightly lower than the prescribed height and then attempted to raise the fuel assembly to the correct position.. However, the operator found that the fuel assembly could be lowered, but could not be raised as he expected. When the hoist did not respond, the operator contacted the refueling licensed senior reactor operator and demonstrated the problem by once more lowering and attempting to raise the fuel assembly._ Operators discussed the problem with reactor m
. engineering who determined that the fuel assembly needed to be lowered furthe io reset l
the interlock for the upper limit of travel. Inspector assessment of operator performance
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l was that it was weak in that he raised the fuel assembly two inches too high and that he i
did not stop and notify management when the fuel assembly could not be raised as l
2 expected. The other operating crews were briefed on the event and management
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. expectations were reinforced.'
.The inspector also had concems regarding the licensee's disposition of two pieces of
tape that were noted on the top of two fuel assemblies in the spent fuel pool. The first
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concem was that they planned to move the fuel assemblies to the refueling pool before
removing the tape, creating the possibility of losing the tape in the transfer tube. The
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inspector discussed the concem with the Shift Manager, who directed that the tape to be
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removed prior to transporting the fuel assemblies.
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The inspector 'was also concemed that the licensee did not have a sound basis for i
- determining that no additional tape had become lodged in a fuel assembly because they
did not know the source of the tape or when the tape landed on the fuel assemblies.
- Following discussions with the inspector, the licensee performed an engineering
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evaluation (M2-EV-99-0006) to assess the various possible impacts of tape on the fuel and core components during power operations if tape were to be inadvertently
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introduced into the reactor during the fuel reload. The evaluation stated the tape would
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affect neither the operation nor the reliability of the nuclear fuel or components due to the inherent thermal and radiation produced degradation of the tape and organic-based nature of its products of decomposition. The inspector found the engineering evaluation
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to be acceptable.
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Conclusions Overall, the refueling was executed well with good management oversight. In addition, the inspectors noted a strong presence by Nuclear Oversight in the preparation for Mode
. 6, the fuel reload, to the final core verification following reload. Although fuel handling operations were generally well controlled, one incident occurred where the spent fuel pool area hoist operator raised a fuel assembly approximately 2 inches above the l
prescribed height and when recovering from this, the operator did not immediately stop l
when the fuel hoist did not respond as expected. Another concem was that when two l
pieces of tape were found on top of fuel. assemblies in the spent fuel pool, the licensee i
did not plan to assess the impact of undetected tape on the fuel and core components during power operations.
M1.3 Intearated Test of Facility 2 Enoineered Safety Features Components
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Inanadian S9e(61726)
The inspectors observed, in part, preparations for, performance of, and restoration from
I the integrated test of Facility 2 engineered safety features components. The inspector
._ reviewed the survelilance procedure and interviewed licensee field personnel to evaluate j
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the propriety of the activities and the functionality of systems and components with l
respect to technical specifications and other requirements.
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Observations and Findinas The inspector reviewed implernentation of procedure SP2613H, " Integrated Test of Facility 2 Components," which includes instructions for preparation for, performance of,
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and restoration from the test. The purpose of the test was to demonstrate, following a simulated loss of offsite power in conjunction with a safety injection actuation signal (SlAS), the proper performance of the following automatic functions in accordance with Technical Specification (TS) 4.8.1.1.2.c.5: (1) deenergization of and load shed from the emergency buses, (2) starting of the associated emergency diesel generator (EDG) from ambient conditions, (3) reenergization of the emergency bus ar.d the permanently
. connected loads from the associated EDG, and (4) sequenced reenergization of the automatically connected loads. The licensee also used this test to demonstrate the l
proper realignment and operation of various systems and components following a SIAS.
The inspector noted that procedure SP2613H placed certain components in abnormal
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alignments for the test. The "B" and "C" charging pumps were aligned such that they.
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would not be energized during the test by removing their thermal overload devices. The epare (idle) high pressure safety injection pump, service water pump, and reactor building closed cooling water pump were blocked from operation by placing their breakers in test. Other components, such as the pressurizer proportional heater bank breaker, cestain bus-tie bnsakers, and certain pumps, were aligned to monitor their response to the test signals without performing their design functions.
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The inspector found that the most of the abnormal alignments were consistent with the TS statement. Howeverl because TS 4.8.1.1.2.c.5 states that the EDG energizes the automatically connected loadsfand because the "B" and "C" charging pumps are automatically connected loads for the "B" EDG, the inspector evaluated the propriety of j
disabling these pumps during the test. The licensing basis for Millstone Unit 2 includes Criterion 18, " Inspection and Testing of Electric Power Systems," of the General Design
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Criteria. ; This criterion states that the electrical power systems shall be designed with the capability to test,."under conditions as close to design as practical, the full operation sequence that brings the systems into operation." Because the charging pumps are designed to inject a concentrated boric acid solution into the reactor coolant system at high pressure, their operation during shutdown conditions, which exist when the test is performed, may have adverse consequences or require impractical preparatory or recovery actions. Therefore, the inspector concluded that testing of the breaker
operation during the test combined with separate surveillance testing of the pump
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lThe operations personnel executed the test welle Communications between operators i were excellent. The operations shift on-duty for the test had been selected for this
. evolution in advance and had prepared for the test using the Unit 2 simulator. The
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inspector verified that selected equipment responded properly to the test signals.
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The inspector also observed the briefing preceding the restoration of the "B" low pressure safety injection (LPSi) pump to its shutdown cooling alignment following the test. Procedure SP2613H had placed the "B" LPSI pump in a minimum fDw, recirculation alignment with suction from the refueling water storage tank (RWST).
Previously, the "B" LPSI pump had been aligned for intermittent shutdown cooling operation with suction and discharge to the reactor coolant system in accordance with Section 4.8 of procedure OP2310, " Shutdown Cooling System." Step 4.11.26 of procedure SP2613H directed operators to restore shutdown cooling using procedure OP2310. However, the operations briefing discussed using the valve line-up form for the shutdown cooling system, OPS Form 2310-3, as a guide for realigning the "B" LPSI pump for shutdown cooling, and then using Section 4.8 of procedure OP2310 to verify valve alignment and start the shutdown cooling system flow.
The inspector was concemed about the potential to transfer water from the spent fuel pool in an uncontrolled manner by operating valves in an improper sequence. The valve line-up forms do not provide control of the sequence of valve operation. Therefore, if valve 2-SI-440 (LPSI pump suction isolation valve from the reactor coolant system) were to be opened before valve 2-SI-450 (isolation for the minimum flow recirculation line) and valve 2-SI-432 (LPSI pump suction isolation valve from the RWST) were closed, water could be inadvertently transferred from the spent fuel pool to the RWST via the refueling pool. At the conclusion of the briefing, the inspector discussed these concems with the on-shift Unit Supervisor, who then informed the inspector that Section 4.8 of procedure OP2310 would be used to realign the valves. Although no violation of NRC requirements occurred, the inspector found the operator's acceptance of using a valve lineup form to realign an in-service system was a general weakness in operations.
The inspector discussed the concern with the Unit 2 Operations Manager, who stated that valve lineup forms are often used to restore a system to its baseline configuration, which is the initial configuration assumed for many operating procedure sections. The inspector agrees that it is appropriate to perform a valve lineup to establish system alignment when the system configuration is unknown, such as restoring a systern after maintenance. However, for systems that are in service, operators should be aware of the current configuration.
Surveillance procedures often place systems in an unusual alignment, and system configuration is controlled by the surveillance procedure. Restoration instructions in the surveillance procedure should, therefore, reestablish the normal system alignment. In this instance, procedure OP2613H referenced procedure OP2310 to restore the normal shutdown cooling alignment. The licensee initiated a condition report to document that procedure OP2310 does not provide clear guidance for restoration of the shutdown cooling system valve alignment. The licensee stated that they would evaluate their existing procedural guidance on the use of valve lineup forms during the resolution of this condition report.
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The actual safety significance of an improper sequence of valve operations was low, if a
valve configuration that began to transfer water to the RWST was established, the water e
transfer would be self limiting because the water would fill the RWST and eliminate the i
l available driving head before the level reduction in the spent fuel pool would be sufficient j'
to create a safety concem. In addition, it is unlikely that the system would have been left j
' in an intermediate configuration that would allow the water transfer to continue for an i
extended period of time.
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Conclusions F
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The NRC found that the preparations for and performance of the integrated test of j
Facility 2 engineered safety features components were executed well. The integrated
test in combination with individual component surveillance tests, satisfied the technical
- i specification surveillance requirements for Facility 2 components. However, during the test restoration, the inspector noted the use of a valve lineup form to restore the i
shutdown cooling system valve alignment rather than an approved procedure that i
controlled the sequence of valve manipulations. The NRC concluded that operator
- acceptance of using valve lineup forms to realign in-service systems was a general weakness in operations. This is a concem because a valve lineup form does not control the sequence of valve manipulations, which is often important for in-service systems.
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U2 M8 Miscellaneous Maintenance issues
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- MB.1 -(Closed) LERs 50-336/96-038-00 and 97-012-00: Inadaausta Surveillance Procedures
Used to Verifv Emeroency Diesel Generator Operability: (Ooen) eel 50-336/97-02-12:
(Undate - Unit 2 Significant items List No. 8.61 i
a.
Insoectiori Scope (92700)
'l The inspectors reviewed the licensee's corrective actions for Licensee Event Reports
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(LERs) 50-336/96-038-00 and 97-012-00. These LERs were two of 17 LERs associated with Escalated Enforcement item (eel) 50-336/97-02-12 which involved numerous examples of inadequate surveillance procedures. Although enforcement discretion was
- exercised for this apparent violation, this eel, as well as Unit 2 Significant Items List No.
i 8.6, will be characterized as open until each of the 17 LERs have been dispositioned by i
the NRC.
b.
Observations and Findinas LER 50-336/96-038-00 described the licensee-identified condition where the emergency diesel generator (EDG) technical specification (TS) surveillance procedures failed to meet the requirements of TS 4.8.1.1.2.a.2. Specifically, procedure SP 2613A and B,
EDG Operability Tests, Facilities 1 and 2, respectively, require the EDGs to start from
' ambient conditions and accelerate to greater than or equal to both 90% of rated speed
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(810 rpm) and 97% of rated voltage (4035 volts) in s15 seconds. The procedure l
describes a " Ready to Load" (RTL) annunciator that actuates at the appropriate setpoints to verify TS compliance. However, the licensee identified that the RTL annunciator l
. would actuate when the EDG voltage was 96.9% of rated voltage for EDG "A", and 96.2% of rated voltage for EDG "B", versus the required 97%.
LER 50-336/97-12-00 described the licensee-identified condition where a lube oil pressure switch, which also provided an input to the RTL annunciator, could cause the
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l actuation of the RTL annunciator prior to the EDG reaching the required 90% of rated speed. As a result, the test method was considered to be non-conservative in meeting the requirements of TSs 4.8.1.1.2.a.2 and 4.8.1.1.2.c.8.c.
l The licensee's corrective actions included: (1) they appropriately declared the EDGs
inoperable when the initial condition was identified; (2) calibrated a relay that contributed
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to the 96.2% and 96.9% early RTL annunciator actuation; (3) successfully retested the EDGs and returned them to operable status; (4) revised the surveillance procedures, SP 2613A, " Diesel Generator Operability Tests, Facility 1," SP 2613B, " Diesel Generator Operability Tests, Facility 2," and SP 2604R, "SIAS Manual Push Button Test" to verify
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engine speed using indication versus the RTL light; and (5) following the submittal of the I
LERs, the licensee committed to, and subsequently completed, a 100% review of all TS surveillance procedures to verify compliance with TS requirements.
l c.
Conclusions l
The NRC concluded that licensee corrective actions have been adequate, and LERs 50-336/96-38-00 and 50-336/97-12-00 are considered closed.
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U2.lli Enaineerina i
U2 E1 Conduct of Engineering l
E1.1 Review of items to be Comoleted After Restart (Update - Unit 2 Sianificant items List No.12)
a.
Inspection Scope (37550)
In a letter dated April 16,1997, the NRC requested, in part, that the licensee provide the following information pursuant to 10 CFR 50.54(f) for each unit:
identification of cignificant items needed to be accomplished prior to restart;
e identification of items to be completed after restart; and
the process and rationale for selecting items for post restart.
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i The letter also requested updates approximately every 45 days for the first two items.
i On December 1,1998, the licensee provided the latest update to the list of Unit 2 items p
to be deferred until after instatt. The inspectors reviewed the information provided to
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assess: the content of the deferred items list, whether the deferrals were appropriate, and that they met the criteria for deferral as stated in the licensee letter of
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l January 9,- 1998.
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Observations and Findinas
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. Approximately 3000 items were included on the licensee's December 1,1998, deferred
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items list for Unit 2. Each inspector on the three person inspection team reviewed approximately one-third of the list. The inspectors reviewed the brief one line descriptions of all the items on the list, and selected items for further review based on the descriptions. In selecting the items for further review, inspectors considered the safety significance of the systems and the potential for system operability to be affected. They i
reviewed supporting documentation for approximately 200 items to determine if deferring the item was appropriate.
The inspectors found that the decision-making process for deferring items was conservative and thorough, and that the items placed on the deferred items list would not need to be completed prior to Unit 2 restart. The licensee had previously conducted a similar effort for Unit 3. Therefore, the licensee was able to incorporate lessons learned from the Unit 3 effort to enhance the deferral review process at Unit 2. For example, the
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' licensee developed a procedure to provide guidance to the reviewers, and the Plant Operations Review Committee reviewed all of the items on the deferred issues list.
' Also, the plant Outage Recovery Team reviews emergent automated work order (AWO)
l and corrective action assignments on a daily basis to determine if items are required for restart or can be deferred. Additionally, the system engineering group reviews deferred work on their systems for impact on operability or reliability, as part of the Readiness
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Review pro'.:ess. Generally, the licensee was able to provide a good basis for including j
the items on the deferred list. The specific findings are discussed below.
During the review, the inspectors requested additional information if the licensee's deferral rationale was not clearly supported. In one case, the licensee's response to the additional information request stated that the item was previously removed from the deferred list on December 4,1998, (the deferred items list presented to the inspectors was developed on December 1,1998). In another case, an item conceming response
- time testing for the containment high pressure trip logic had met the criteria for deferral, but was intended to be completed prior to restart for other valid reasons and assigned an appropriate date. In some cases, the licensee enhanced its deferral reason after -
reviewing the inspector's comments.
The inspectors identified two assignments relative to licensee identified conditions where
, the containment leak test program was contrary to 10 CFR 50, Appendix J requirements.
However, the assignments appeared to have administrative controls for completion prior to Mode 4, and the licensee confirmed that both items had been removed from the deferred items list. In addition, the inspectors identified an assignment that would correct
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a cable tray electrical separation deficiency. The inspector requested more detailed l
. Information on this assignment, but the licensee had previously removed this item from
the deferred items list. The three items addressed above were all previously screened j
and placed on the deferred items list, and upon further licensee review, were
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subsequently removed from the list for completion prior to startup. For all the deferred issues reviewed by the inspectors, the inspectors agreed with the licensee's deferral j
decisions after reviewing the additional information.
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- Conclusions l
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-l The inspectors concluded that the licensee's decision-making process for the
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identification of items to be completed after the restart of Unit 2 was conservative and i
thorough. The process resulted in the list containing items that were appropriate for deferral. The inspectors did not identify any issues that, if not corrected prior to plant
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restart, would have resulted in a significant safety concem during plant operations. Unit '
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j 2 Significant items List 12 remains open pending NRC review of an additional update to l
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the deferred items list that the licensee is required to submit prior to restart.
U2 E8 Miscellaneous Engineering issues l-E8.1. { Closed) Follow-uo item 50-336/94-201-90: Emeroency Diesel Generator Fuel Oil
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Supolv Tank Caoacity -(Closed) Unit 2 Sionificant items List item No. 42)
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Insoection Scope (92903)
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L The inspector reviewed the licensee's corrective actions to address inspection Follow-up Item (IFI) 50-336/94-201-90, Significant items List (SIL) item number 42, which
' concerned the fact that the emergency diesel generators (EDG) fuel oil supply tanks did.
c not have the 7-day capacity specified in the final safety analysis report (FSAR).
l-b.
Observations and Findinas in 1994, the licensee recalculated the length of time the EDGs would operate following a l
loss of coolant accident and a loss of normal power and found that the required volume l
in the fuel oil supply tank for each EDG would not support EDG operation for 7 days as L
required by FSAR Section 8.3, " Emergency Generators." To address this concern, the l
FSAR was revised in Amendment No. 212. The FSAR change was found acceptable
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based on two methods for refilling the fuel oil supply tanks that were described in the l
licensee's submittal.
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The inspectors confirmed that the licensee had adequately calculated the required amount of fuel required to be in the underground storage tank and had established conservative level setpoints for the storage tank, assuming the minimum technical
" + specification required 12,000 gallons of fuel oil in the day tank. The inspector also
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verified that the requirement for 19,563 gallons of fuel oil (77.1% level) to be stored in
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L tank T-47A had been added to the Technical Requirements Manual (TRM), Section 6.0.
p The licensee's submittal indicated that the fuel quantity in T-47A would be verified by a
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. surveillance. However, during this inspection, the licensee was not s'sle to demonstrate j
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that they had met this commitment. The licensee indicated that the sequired surveillance l
was in development. Following the inspection on site, the licensee sthmitted change request forms for procedures SP 2613A and SP 2613B, Diesel Generaer Operability Test, Facilities 1 and 2, respectively. These changes incorporated the requirement from the TRM to verify the quantity of fuel in the underground storage tank by either the lack
of a low-level alarm or by actual measurement with a dipstick.
The inspector also verified that the low level alarm for tank T-47A had been adjusted and an associated alarm response procedure (ARP) modified to ensure that the required fuel
. quantity is maintained. However, the inspector found that the ARP had not been revised to agree with the TRM to declare one EDG inoperable when the level in T-47A drops to
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67.1% (14,469 gallons.) The licensee produced Condition Report (CR) M2-98-3407, dated November 15,1998, where the licensee had already documented this same concern and indicated that the ARP would be revised prior to entering mode 4 operations, consistent with the TRM. The inspector found this acceptable.
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c.
Conclusions The licensee's corrective actions for Unit 2 SIL number 42 were incomplete at the time of the inspection. Subsequently, the licensee issued changes to the associated surveillance procedures. Those changes were reviewed and found to be appropriate, therefore, IFl 50-336/94-201-90 and SIL number 42 are considered closed.
E8.2 LQlgandLY.lQ_5Q-336/9B-207-10: Failure to Provide Comolete Information in Submittal on l
Emeroency Diesel Generator Fuel Oil a.
Inspection Scope (92903)
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The inspector reviewed the licensee's corrective actions to address Violation 50-336/98-
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207-10.
b.
' Observations and Findinos Violation 50-336/98-207-10 concerned the failure of the licensee to provide complete
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information in their September 3,1997, submittal regarding their capability to replenish the emergency diesel generator (EDG) fuel oil supply tanks via an offsite source. This
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submittal involved a proposed revision to the final safety analysis report (FSAR) to e' tess the concem that the emergency diesel generators (EDG) fuel oil supply tanks oid not have the 7-day capacity specified in the FSAR. The NRC considered the statement in the submittal that " replenishment of fuel oil could be accomplished via an offsite source," to be en incomplete because: (a) the fuel oil supply tanks did not have a formally established fill connection to fil' the tanks directly from a delivery truck; (b)
temporary equipment such as pumps and hoses had not been pre-staged for directly o
filling the fuel oil supply tanks; and (c) there were no procedures provided for directly filling the fuel oil supply tanks; and (d) there was no engineering evaluation to support the assertion that the tanks could be filled.
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To address the violation, the licensee plans to change Emergency Plan implementing Procedure 4400, " Event Assessment, Classification, and Reportability." Section 4.8 of this' procedure provides actions to be taken in the event of a loss of off-site power. The licensee plans to add the statement that any vehicle delivering diesel fuel to the site, for I
the purpose of filling the Unit 2 EDG supply tanks must have the a pump capacity of at least 10 gpm at 30 psig and an adequate length of hose (100 feet.) The flame arrestor (vent) connection may be used to fill the supply tanks. The inspector determined that the proposed procedure change adequately addresses the procedure and equipment concems discussed in the violation.
The inspector noted that the proposed change to procedure EPIP 4400 is being tracked by Action Request 98010177 and is' scheduled for completion prior to Mode 4. The inspector found this to be acceptable.
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Conclusions
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. The licensee's corrective actions to address Violation 50-336/98-207-10 found to be acceptable. This violation is considered closed.
E8.3 (Closed) eel 50-336/96-201-25: Failure to Effectivelv Track and imolement Corrective Actions Concomina Dual-Function Isolation Valves: (Closed - Unit 2 -Sinnificant items
List No. 30)
a:
Insoection Scone (92903)
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The inspector reviewed the remaining licensee corrective actions to address Escalated Enforcement item (EEI) 50-336/96-201-25, which involved the failure of the licensee to track and implement corrective actions conceming dual-function isolation valves. This
issue was previously inspected and detailed in NRC Inspection Report (IR) 50-336/97-202, which included various licensee corrective actions taken in response to eel 50-
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336/96-201-25 and other licensee actions to resolve the issue of inadequate testing of dual-function isolation valves.
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Observations and Findinos As documented in NRC IR 50-336/97-202, eel 50-336/96-201-25 involved an apparent violation for the licensee's failure to implement prompt corrective action to resolve a dual-
- function valve testing concem. The licensee oefines dual-function valves as those valves that have an isolation function at both containment design pressure and normal
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system operating pressure. Licensee corrective actions included: (1) revising or enhanciag corrective action and maintenance department procedures, which dealt with both the programmatic issues, as well as the specdic problem associated with dual-
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. function valves; (2) establishing corrective action program requirements and providing t-training to station personnel; and (3) testing 23 dual-function valves 11 were identified that potentially would not isolate against normal system pressure.
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The inspector verified the remaining corrective actions, including: (1) the licensee l
completed a review of all safety-related air operated valves (AOV) that could share
similar problems identified in the dual-function valves; all dual-function valves (of the 23 i
discussed above) identified in this AOV review had been previously tested satisfactorly;
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l (2) a new maintenance procedure was developed to ensure the proper setup and repair i
of a specific type of valve operator; (3) other maintenance procedures for AOV actuators l
were revised to ensure closing force problems associated with dual-function valves
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would be corrected; and (4) the 23 dual-function valves had been tested to meet the l
requirements of 10 CFR 50,' Appendix J, to verify they all have valve seating capability at l
containment design pressure.'
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Conclusions The licensee's corrective actions were acceptable in addressing eel 50-336/96-201-25, which involved the failure of the licensee to track and implement corrective actions i
conceming dual-function isolation valves. As a result, eel 50-336/96-201-25 and Unit 2 i
Significant items List No. 30 are considered closed.
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E8.4 (Closed) VIO 50-336/98-216-02: Reactor Coolant System Heatuo and Cooldown Rate Limits Exceeded: (Closed-Unit 2 Slanificant item List No. 24)
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Inspection Scope (92901)
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The inspector reviewed the licensee's corrective actions to address Violation 50-336/98-
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216-02 and Unit 2 Significant items List (SIL) No. 24, which involved repeated incidents where the reactor coolant system (RCS) heatup and cooldown rate limits specif' d in e
technical specifications were exceeded. As stated in NRC Inspection Report 50-336/98-216, the majority of the corrective actions to address the violation had already been
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completed and were found acceptable by the NRC. The violation and SIL No. 24 remained open pending completion of the corrective actions associated with the plant process computer software that the operators use in monitoring heatup and cooldown rates, b.
Observations and Findinas The corrective action of updating of the computer software was important because the reason that operators did not know they had been exceeding the RCS heatup limits was the computer had been calculating the heatup and cooldown rates in a non-conservative manner. The calculation should simply be the comparison of the current temperature to the temperature one hour ago. However, due to erratic temperature indication, the
- licensee had been using a " smoothing function" which took the average temperature of the last 30 minutes and compared this to average temperature from the previous hour.
However, the NRC found that the " smoothing function" value that operators monitored s was not sufficiently precise to prevent exceeding heatup and cooldown rate limits.
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v The inspector reviewed the licensee's new computer screen that operator's will monitor l
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and found that the heatup and cooldown rates are correctly calculated for the RCS loops,
the pressurizer, and the shutdown cooling system. In addition, operators have trained on
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the simulator using revised procedures that allow the simultaneous operation of the i
shutdown cooling system and the reactor coolant pumps. This addresses the problems with erratic temperature indications that operators used to experience during RCS l
heatups and cooldowns when the shutdown cooling system was placed in and out of l
service.
c.
Conclusions The licensee's corrective actions were acceptable in addressing Violation 50-336/98-216-02, which involved repeated incidents where the RCS heatup and cooldown rate limits specified in technical specifications were exceeded. Violation 50-336/98-216-02 and Unit 2 Significant items List No. 24 are considered closed.
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Report Details Summarv of Unit 3 Status
. Unit 3 began the inspection period in Mode 1 at full power. On December 11,1998, the unit tripped from 100% power, due to an automatic reactor protection system actuation signal generated by a low level in a steam generator, and caused by an unexpected main steam isolation valve (MSIV) closure. This issue is discussed in detail in later sections of this inspection report. On December 12, the plant was cooled to cold shutdown (Mode 5) conditions
to effect MSIV repales. After completion of the repair and modification activities, the unit was heated to hot standby (Mode 3) on December 24; and after post-modification testing of the MSIVs at normal operating pressure and temperature, the reactor was taken critical (Mode 2) on i
December 25. Over the next couple days, the reactor was retumed to Mode 3, taken critical j
again, and restored to Mode 3 conditions to troubleshoot problems with a nuclear instrument channel. While in Mode 3 on December 26, the operators manually tripped the reactor during the evolution of inserting all control rod shutdown banks, when a mismatch between indicated and demand rod positions was obserwd in the "D" shutdown bank.
l After repair to the nuclear instrument channel (i.e., an intermediate range monitor cable) and replacement of the control rod bank selector switch on the main control board, Unit 3 was again taken critical on December 30,1998 and full power was achieved on January 3,1999. The l
. reactor remained at approximately 100 percent power through the end of this inspection period.
On January 4,1999, a small leak in a waste test tank, located outside, but within the radiologically controlled area (RCA) of the unit, caused an unplanned release of some low-level radioactive water to Niantic Bay. This event was reported to both the NRC and the State of p
Connecticut and is discussed in later sections of this inspection report.
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U3.1 Operations U3 01 Conduct of Operations 01.1 GeneralComments(71707)
The inspector conducted frequent reviews of ongoing plant activities, including observations of operator evolutions in the control room; main control board walkdowns; i
and inspections within the RCA and other buildings housing safety-related equipment. In i
addition, several maintenance planning, operational focus, and plant operations review committee / event follow-up meetings were attended.
The inspector observed the performance cf slave relay testing, solid state protection system testing, reactor trip breaker testing, response and review of loose parts monitor alarms, and both routine (e.g., placing the spare component cooling pump in service in a
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safety flow train lineup) and nonroutine (e.g., charging nitrogen to the safety injection
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accumulators during plant heatup) activities. The proper use of procedures, appropriate l
entry into and exit from the limiting conditions for operation (LCOs) of the applicable technical specifications (TS), clear communications, and the use of double verification controls, where warranted, were noted.
- Coordination among departments (e.g., engineering revision of a temporary modification before operations took credit for new hypochlorite injection valve boundaries) and liaison with outside consultants (e.g., evaluation by Westinghouse of the validity of loose parts l
_ monitor alarms) were also in evidence.
The inspector routinely reviewed the condition reports (CRs) issued during this
- Inspection period, particularly noting the tracking of reactivity management CRs as a key performance indicator by licensee management. Other CR issues with programmatic-impact (e.g.~, post accident sample system surveillance discrepancies, radiological environmental monitoring program problems) were evaluated for immediate or fu'.ure inspection follow-up.
The inspector discussed the series of manual and automatic plant trips which have occurred over the past six months', and the Unit 3 " operational focus" enhancement strategy with the Unit Director; noted the use of an " aggregate impact" performance indicator to track and trend the reduction of operator burdens affecting the on-shift crews; i
and reviewed a Unit 3 self assessment of the vulnerabilities to safe, event-free and reliable operation. This document was prepared at the direction of the Vice President of
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Operations to identify those items to be included for consideration as required work prior L
to restart from the cold shutdown that commenced on December 12,1998 for main l
steam isolation valve repair activities.
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Additionally, the inspector examined the scheduler controls and Nuclear Oversight
- assessment activities related to the plant restart commencing on December 23; and subsequently reviewed an Event Review Team report for CR M3-98-5289, regarding an l
unplanned manual reactor trip from Mode 3 (reactor noncritical) conditions on
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December 26, due to a difference in the indicated and demand control rod positions on the "D" shutdown bank. Successful ascension to full reactor power was noted to be completed on January 3,1999.
U3 02 Operational Status of Facilities and Eqdpment O2.1 Automatic Reactor Trio Durina Main Steam isolation Valve Partial-stroke Testina a.
Inspection Scooe (71707. 93702) (Reference this (aport, Section M2.1, for engineering details)
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. On December 11,1998, the unit tripped from 100% power during the conduct of main i
steam isolation valve (MSIV) partial stroke testing. During such testing, each of the four MSIVs is slow-stroke closed 10%, using test circuitry that employs solenoid valves to charge and vent steam pressure from the pistons that control movement of the MSIVs.
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The inspector responded to the control room upon the station announcement of the reactor trip, witnessed the conduct of operator actions to cool down the plant to hot standby (Mode 3) conditions, observed several licensee meetings evaluating the fact-finding and decision-making processes, and subsequently reviewed licensee's activities to investigate and effect repairs and implement design modifications to the MSIVs with the plant in cold shutdown (Mode 5) conditions.
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Observations and Findinas j
Overview The reactor trip occurred as a result of a low-low steam generator (S/G) level in the "A" i
S/G, corresponding to the shrinkage in S/G water level caused by the "A" MSIV closure.
The "A" MSIV was the first of the four valves scheduled for partial-stroke testing on December 11. The start of the test ported steam through certain solenoid valves.
designed for testing of the MSIVs at power. However, with the technician's release of the test switch, the expected movement of one solenoid to the open position, which would have vented steam to reopen the MSIV, did not occur. This caused the "A" MS!V to continue past the 10% test-closure point to fully close the valve and isolate the "A" main steam line. With the resultant reactor trip, plant systems functioned norma;y. The lift and subsequent reseating of two main steam safety valves (MSSVs) on the "A" steam line were determined to be an expected and acceptable result of the full MSIV closure,
given the measured pressure spike and the required MSSV setpoints and tolerances.
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With the plant in hot standby (Mode 3), the licensee was able to open the closed MSIV and perform additional partial-stroke testing of this valve and the other three MSIVs,
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having decided to further cooldown the plant to cold shutdown (Mode 5) conditions and conduct other component maintenance activities in parallel with the MSIV troubleshooting. Subsequent inspection of the solenoid valve that had failed to vent identified a circumferential crack in the piston assembly. While this defect would not have prevented a MSIV from performing its safety function (i.e., fail-safe closed), it did adversely affect the parialt-stroking of the valves, and thus, the conduct of surveillance testing in accordance with the unit technical specifications (TS). The current Unit 3 TS require MSIV partial-stroke tests on a quarterly basis; however, the licensee was conducting this testing on a more frequent, graded periodicity because of previous
. problems with the solenoid valve reliability.
During the shutdown, the licensee removed and inspecterd all 32 solenoid valves (two trains of four each per MSIV), identifying additional piston material indications that required further evaluation. Licensee management then decided to immediately implement a solenoid valve assembly design modification that had been planned for the next refueling outage (RFO 6) currently planned to commence in May 1999. The field -
modifications to the MSIV solenoid valves were completed on December 22; the MSIVs returned to operations control; the MSIVs full-stroke tested after the plant was heated to Mode 4 conditions on December 23; and partial-stroke testing of the MSIVs completed, to post-modification test criteria, with the plant at normal operating pressure and temperature in Mode 3 on December 24.
Insoection Activities
' In addition to control room observations immediately following the reactor trip on December 11, the inspector witnessed other control room evolutions in support of MSIV repair, modification, and restoration activities. Inspections of the MSIV field work were conducted, to include review of foreign material exclusion (FME) controls, solenoid valve
~ tagging and parts coordination, visual examination of interior port conditions, observation of cable splicing activities, witness of local " dry-strokes" of the new solenoid valve installations, and final modification checks for environmental qualification (EQ)
i installation attributes. The inspector also attended several licensee planning sessions and plant operations review committee (PORC) meetings, involving discussions of the as-found solenoid valve conditions and failure mechanisms and the sequence of repair and restoration activities. The following documents were reviewed, to evaluate equipment conditions and plant response to this event and to answer specific inspector questions regarding the sequence of events and component operability:
e MSIV Action Plan, MP3-TS-98-401 (reference: CR M3-98-5093)
e Root Cause investigation Report - MSIV Solenoid Failure and MSIV Closure Resulting in Reactor Trip, dated 12/22/98 Engineering Record Correspondence,25212-ER-98-00, regarding main steam e
relief valve operation during the reactor trip
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Memorandum, dated 12/15/98, regarding the "A" S/G atmospheric relief valve operation and response during the MSIV closure transient and reactor trip event o
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e Project Plan for Engineering Work Request (EWR 95-107), MSIV Solenoid Coil
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Replacements and Elimination of Attenuator Circuits Design Change Record (DCR) M3-98053 for the MSIV Solenoid Design Upgrade i
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Summary of the MSIV partial-stroke testing provisions, including analysis of e
i regulatory guidance and technical specification requirements
With regard to the MSIV partial-stroke testing details, the licensee was conducting the
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partial-strokes at a graded periodicity (two week, four week, six weeks at the time of the j
reactor trip on December 11) to demonstrate solenoid valve reliability in accordance with j
the licensee's interpretation of maintenance rule requirements. The Unit 3 TS 4.7.1.5.1 J
requires that each MSIV shall be demonstrated operable, pursuant to TS 4.0.5, by i
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verifying a partial stroke in Mode 1. TS 4.0.5 references the applicability of the in-service i
. testing (IST) program and Section XI requirements of the applicable ASME Boiler and l
Pressure Vessel Code edition, setting the testing frequency at quarterly as a minimum.
The licensee is evaluating the current IST program provisions regarding the conduct of
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partial-stroke testing during plant power operations, i
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j Since the licensee successfully conducted full-stroke testing of the MSIV in Mode 4 prior
to the retuin to power in December, the next partial-stroke tests in accordance with TS
requirements need not be done until March 1999. However, if the licensee intends to invoke guidance suggesting no partial-stroke testing at power, it appears that a TS
,
revision would be required. The inspector discussed this position with the cognizant s
j system engineering and licensing personnel and intends to track licensee activities with i
respect to future partial-stroke testing options, plans, and licensing actions as an inspector follow-up item. (IFl 50-423/98-06-01) Another NRC opan inspection issue on
the MSIV solenoid valve performance is documented in Section U3 M2.1 of this inspection report. Additionally, on January 11,1999, the licensee issued licensee event report (LER)98-045 to document this reactor trip as a result of the MSIV closure event as an automatic actuation of an engineered safety feature. This LER will also receive further review during future NRC inspection activities.
c.
Conclusions Licensed operator recovery actions, and overall control room activities, in response to the unexpected MSIV closure and resultant automatic reactor trip were deliberate and well controlled. While the lifting and reseating of two MSSVs was identified in a timely manner and reviewed for adequate system response, this information was not initially disseminated to all operators involved in recovery operations. Plant equipment performed as expected. Licensee activities to investigate the cause of this event and implement corrective actions, in the form of a design modification to the MSIVs, were well detailed, planned, and executed. The licensee also evaluated causal factors for this
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event with respect to historical solenoid valve performance problems. NRC review of this assessment and these factors determined that the solenoid valve failure mechanism
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specifically related to the current event was different than that identified with previous MSIV solenoid concems. However, both sets of problems appeared correctable with the
implementation of the design modification, which installed upgraded solenoid valves fabricated with new material types. Certain issues involving continued MSIV stroke testing plans and LER follow-up, documenting further metallurgical studies, remain open i
for additional NRC review and inspection.
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i U3 08 Miscellaneous Operations issues (92700)
08.1_ (Closed) Violation 50-423/96-05-12: Failure to Audit the Technical Specifications
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r As documented in NRC inspection report (IR) 50-423/96-05, the NRC identified and issued a violation for the failure to audit TS Section 6.8.4.e within five years in
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accordance with TS 6.5.3.7, " Nuclear Safety Assessment Board (NSAB) Audit Program
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Responsibility," requirements. The licensee's response to this violation was previously i
reviewed in IR 50-423/97-82, dated June 11,1998. At that time, the inspector stated that
'although much of the corrective action for the violation had been accomplished, the
violation remained open pending the development of an effective scheduling tool to i
ensure that all technical specifications will be audited within the required five-year period.
During the current report period, the inspector reviewed the licensee's final closure
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package for this violation. The Audits and Evaluation (A&E) Group of the Nuclear Oversight Organization is responsible for maintaining the TS database, which is a tabular database that lists the technical specifications for each unit and the audit (s) that cover each TS. An A&E Group individual was recently assigned the responsibility of maintaining the database, creating reports, 74 making the appropriate audit
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assignments in order to implement the five-year Technical Specification Audit Plan. The inspector reviewed a database report that included: the TS section for each unit; the i
audit report number (s) for the TS sections that were audited during the five-year cycle-I
and the exit date for the audit. At any time during the five-year cycle, the report can be j
reviewed to determine which sections have been audited, and which sections remain J
open. By reviewing the audit schedule and TS database, audit assignments can be
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made for TS sections that have not yet been audited.
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The inspector reviewed the current TS database and audit assignment process and concluded that the corrective actions taken by the licensee in response to this violation i
were appropriate. This issue, VIO 50-423/96-05-12, is considered closed.
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U3.Il Maintenance U3 M1 Conduct of Maintenance M1.1 Maintenance Observations
. a.
Insoection Scope (62707)
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The inspector observed maintenance planning meetings, conducted field inspections of work in progress in the plant, and reviewed work control and other goveming technical documents and records to evaluate the overall performance of selected emergent and planned maintenance activities during this inspection period.
b.
Observations and Findinos i
The inspector conducted periodic reviews of the daily status of emergent work being added to the current work week schedule based upon its direct impact upon personnel safety or plant reliability; and also reviewed several items requiring investigation as
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potential emergent or planned work. The following work activities were either reviewed at the planning level, discussed with the cognizant work supervisor, or observed in progress in the field.
i e
action plan to isolate components cocled by the reactor plant component cooling (CCP) system, one at a time, to identify and repair CCP leakage; subsequently found in part of the auxiliary condensate sample coolers.
heat exchanger (3CCP*E1B) leak repairs, subsequently effected with the e
replacement of certain questionable plugs in the tube sheet.
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status of minor maintenance to two area radiation monitors (3RMS1Y32 & 3RMS-
R1YO1) located inside containment; both being repaired with one subsequently becoming inoperable as result of unrelated cable troubleshooting.
I restoration of the "A" reactor trip and bypass breakers after the conduct of e
required surveillance testing.
e isolation of an exciter cubicle rectifier bank to conduct troubleshooting of a generator field ground alarm.
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completed sealant injection to repair a smali body-to-bonnet leak on the main feedwater containment isolation valve, 3FWS*CTV418.
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l The inspector examined the affected equipment tagging controls, automated work order
(AWO) authorizations, and the establishment of appropriate foreign material exclusion (FME) areas for the work. The status of completed work was discussed with various maintenance personnel and the TS applicability and/or cperations impact of the work was spot-checked. The inspector noted engineering involvement, as appropriate, in the l
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troubleshooting or repair plan decisions. During a field inspection of one AWO job, the inspector identified a leaking pressure gauge ast ociated with a controller for a valve in the main steam system. This instrument was no.ed to provide a nonsafety-related function. The problem was brought to the attention of technical support personnel and the gauge was subsequently repaired.
c.
. Conclusions Overall, for the selected maintenance work items and maintenance field observations, the inspector identified acceptable work controls, equipment conditions, and coordination amongst the maintenance, operations, and engineering departments.
U3 M2 Maintenance and Material Condition of Facilities and Equipment M2.1 M_ain Steam isolation (MSIV) Solenoid Valve (SV) 3 MSS *SV27A1 A Piston Crackina a.
Inspection Scope (62707.929Q2) (Reference this report, Section O2.1 for operational details)
On December 10,1998 Northeast Utilities (NU) identified the malfuncticn of a main
- steam isolation valve (MSIV) solenoid valve during the performance of a stroke test of the main steam isolation valves. The malfunctioning solenoid valve resulted in the unplanned closure of the valve with a resultant reactor trip. The malfunctioning solenoid
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valve was disassembled and it was discovered to have a large circumferential crack in the main piston. The remaining thirty one solenoid valves, on the other MSIVs, were disassembled and inspected. Four other main pistons were found cracked. As a consequence of this discovery, the licensee arranged to replace all thirty two solenoid valves. The inspector examined the failed pistons, reviewed documentation of test results, and interviewed engineering personnel.
b.
Observations and Findinos The SV27A1 A valve is one of eight selenoid valves located on each of four main steam isolation valves. The Number 1 solenoid valves (1 A and 1B) allow venting of the upper piston chamber to open the MSIV, or maintain it in the open position. The failure of the
"A" solenoid valve was discovered when the piston in this valve failed to move during -
testing. Investigation of the component parts of the SV1 A valve after disassembly revealed that the main piston had a circumferential, through wall crack for 3/4 of the circumference. The inspector examined this pistoa and four additional cracked pistons
- from the 27A4A, 27C1 A, 27C2A and 27D1B valves.
The inspector reviewed the plan developed by NU to identify the mechanism and most probable cause of the failure of the piston. The approach developed was well organized and considerable progress was evident at the time of the inspection. The inspector noted significant resources were directed to this effort. Through discussions with personnel assigned to the materials investigation, the inspector determined they were technically qualified to pursue the failure analysis to conclusion.
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The inspector reviewed the work done by NU to date and found that a significant effort had been made to identify the base material and the thermal heat treatment (s)
performed by the manufacturer. Because the valves are not of domestic manufacture,
' this data has not been readily available. NU has determined that this material is most similar to a domestic designation of AISI 420 stainless steel. This material is a relatively high carbon content, hardenable grade of stainless steel. Replacement solenoid valves were installed using NU design change process DCR M3-98-053. The new material and thermal treatments of the main piston differ considerably from the original, and there are changes in the configuration of the piston. NU has performed a comparison of the material changes to the extent possible given the data available on both the old and the
- nov' pistons. The licensee has concluded that the material changes (pisten, pilot piston, springs, piston rod, alignment pins and pilot valve nut) will not have an adverse effect on the performance of the valve. However, the material change of the pilot valve nut has been appropriately identified as an open item (by NU) in the DCR process, as its service
life is not considered to be suitable for the life of the plant.
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The inspector visually examined and found that all of the main pistons exhibited some degree of pitting corrosion on the outside diameter of the body. Corrosive attack varied from light to severe however, all had suffered pitting attack. There was no pitting attack apparent on other surfaces of the piston. Cracking was readily apparent and could be easily seen with the unaided eye. Their orientation was diverse with some cracks axial, circumferential and in one instance, emanated from the three drilled vent holes just above the piston seating area.
The inspector reviewed photomicrographs of the crack location from the 27A1 A piston.
The crack was noted to be intergranular in orientation and crack surfaces were heavily oxidized. Scanning Electron Microscope photographs were taken of the cracked surface which provided further evidence that the crack was intergranular in nature.
Hardness test data taken by the licensee on the failed piston was reviewed by the inspector and found to range from HRC 44 to 50 which was in agreement with the design values provided by the manufacturer. The replacement pistons are provided with a l
considerable increase in surface hardness (to improve wear resistance of the piston)
- with r corresponding reduction in core hardness (for toughness and resistance to cracking).
There is very little data available regarding service history of the new materials.
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However, as a result of the materials evaluation performed, NU expects that the performance and overall service life of the solenoid piston will be enhanced.
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Conclusions-I A main steam isolation valve (MSIV) solenoid valve malfunctioned during the
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performance of a stroke test of the main steam isolation valves. The malfunctioning
. solenoid valve resulted in the unplanned closure of the valve with a resultant reactor trip.
The preliminary failure mechanism for the malfunctioning solenoid valve of stress corrosion cracking appears reasonable, although a formal root cause remains to be determined. The licensee's material reconciliation effort was thorough and of sufficient depth to provide a bam for the installation of new MSIV solenoid valves.
U3.lli Engineering
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U3 E1 Conduct of Engineering E1.1 Blown Fuse on Safety Related 4160 V Bus 34D a.
Inspection Scooe (71707. 92903)
' On November 24,1998, operators received alarms in the control room indicating that a potential transformer fuse blew on bus 34D, and the bus had under voltage relay trouble.
The inspector reviewed the Unit 3 technical specifications (TS) to determine whether the appropriate immediate actions were taken by operations personnel. In addition, the-inspector reviewed and discussed the subsequent plans for repairing the blown fuse with engineering and regulatory compliance personnel to determine whether the actions were allowed per the plant TS.
b.
' Observations and Findinos
- The safety related electrical distribution system consists of two separate 4160 V trains, Each of these trains has an under voltage and a degraded voltage protection scheme. In order to actuate the protection scheme on either train,2 out of 4 signals must come in for either under voltage or degraded voltage in this case,1 out of 4 channels were tripped
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in the under voltage and degraded voltage schemes.- Therefore, in this condition another 1 out of 3 channels would red to trip to disconnect the bus from the normal and reserve station transformers and start the emergency diesel generator.
The inspector verified operators appropriately entered TS 3.3.2, Engineered Safety Features Actuation System, Table 3.3-3, Action 20a. With the potential transformer fuse blown, the inoperable channel was considered tripped. In this configuration, the TS l allow operation for an indefinite period of time.
. in order for the licensee to restore the inoperable channel, another channel would need
? to be removed from service. The licensee initially determined that this action was allowed per the TS under; Action 20b, which allows the licensee to bypass the inoperable channel for up to four hours to perform surveillance testing on the other channels. The inspector' discussed the appropriateness of this interpretation of the TS with plant
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.24 management. The inspector, licensee, and NRC personnel from the office of NRR held a conference call to discuss the licensee's plan. After the discussion, the technical specification branch in NRR determined that this would be an inappropriate use of the licensee's specific TS. The licensee subsequently decided not to pursue the repair using this TS.
The inspector attended many licensee planning meetings held to discuss their options for repairing the fuse and troubleshooting the cause for the fuse failure. Engineering, operations, maintenance, licensing, and other departments provided thorough discussions of the repair options including availability of replacement parts, potential of separating power supplies to trains "A" and "B", performing the evolution as an infrequently performed test or evolution (iPTE) or special procedure (SPROC), and performing the repair online (using TS 3.0.3 or TS 3.3.2) or during cold shutdown.
The licensee wrote SPROC GTS 98-3-01, Trip Actuating Device Operational Test for 4KV Bus 34D Under voltage with Channel "A" Bypassed, to perform the monthiy operational test for the operable under voltage and degraded voltage channels with the inoperable channel bypassed. The inspector observed the pre-job brief and conduct of this test on December 7. The evolution was well controlled and performed by generation test services (GTS) personnel. Control room operators and the shift manager were aware of the test and prepared for the inadvertent loss of service water and reactor plant closed cooling water. The test was performed well, and all channels passed the test with no affect on other operating plant equipment.
As described earlier in this report, the plant automatically tripped on December 11 due to problems with an MSIV. Licensee management decided to place the plant in cold shutdown to effect repairs to the MSIVs and also to troubleshoot and repair the 34D bus.
The inspector observed a sample of the repair activities for the 34D bus work performed in accordance with AWO M3-98-17027, and confirmed that the job was performed in accordance with the AWO. The licensee concluded the potential transformer had also failed and replaced it as well as the blown fuse. The observed post maintenance test also passed and the "A" channel of 34D under voltage and degraded voltage instrumentation was retumed to operation. LCO 3.3.2 was appropriately exited following the repair.
c.
Conclusions '
Following the failure of a potential transformer fuse in the "A" train 34D 4KV bus, operators took appropriate actions to declare the affected instrumentation inoperable and enter technical specification 3.3.2. The licensee initially determined that troubleshooting and repair could be performed on the affected instrumentation while in TS 3.3.2. The
. inspector discussed this determination with plant management, and after subsequent discussion with NRR, the licensee decided not to perform the work using this TS.
. Thorough licensee discussion of the plant design and options for troubleshooting were observed. The normally scheduled monthly operability surveillance, performed at power, and troubleshooting on the affected instrumentation, performed in cold shutdown, were well controlled and completed without affecting operable plant equipment.
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l U3 E2 Engineering Support of Facilities and Equipment E2.1 Waste Test Tank Leakaos - Radioloaical Review and Desian Follow-uo
. a.
Inspection Scope (71750. 90712. 92903)
i During this inspection period, the license implemented a design change notice (DCN) for j
the installation of an asphalt berm surrounding the area of the waste test tanks and
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boron test tanks in order to prevent any accidental leakage of tank components from entering a nearby yard drain. Subsequently, during a period of heavy rain, a tank leak
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was discovered, but the installed berm did not perform its intended function of containing i
the leakage. Because of the potential for a radiological release via an unauthorized
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discharge path, the inspector conducted a follow-up of this event as it developed, reviewed the licensee's evaluation activities, and assessed the corrective action,
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reportability, and engineering performance. as were related to this event.
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b.
Observations and Findinas l
Seouence of Events l'
On January 4,1999, at approximately 2:00 am, a plant equipment operator (PEO) was l
. dispatched to the Unit 3 waste test tank (WTT) inside the RCA after a remote tank level j
indicator showed a drop in tank level. The PEO discovered a 1'- 2 gallon per minute leak from the heater loop piping of the "A" waste test tank. The heater loop piping was isolated and the leak was stopped. Radiological surveys of the asphalt areas in the '
j vicinity of the waste test tank were conducted; however, there was no initial indication of radiological contamination.
i Unit 3 began sampling and analyses to identify whether radioactivity had reached yard drains downstream of the leak in an attempt to identify the extent of migration, it any radioactive material was detected. At approximately 7:45 am, bypmduci myerial (Cobalt and Cesium) was identified in two storm drains adjacent to the waste test tank berm area, however, not at a level that would require reporting to outside agencies, and the
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licensee subsequently removed any silt and water from the manhole sumps.' At approximately 8:00 am, a sample was obtained from discharge point DSN-006 (the yard storm drain permitted discharge point into the Niantic Bay); however, the sample analyses yielded radioactive tritium at levels below the minimum detectable activity as prescribed by the Offsite Dose Calculation Manual. In addition,6.8 ppm boron was also
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identified in the sample. Based on these results, the licensee initially determined that this event was not reportable.
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A routine waste test tank discharge through the normal permitted discharge point i
' occurred at approximately 12:30 pm on January 4. Earlier that same day, the Shift -
l Manager had initiated a condition report (M3-99-0015) detailing the waste test tank leak.
l The Shift Manager determined that the event was "potentially reportable" and determined that a reportability determination was required. At approximately 12:00 pm, January 5, a Reportability Determination performed by the licensee's Environmental Services group msulted in the determination that this event should be reported to the Connecticut Department of Environmental Protection (CT DEP).
At approximately 4:00 - 4:15 pm, January 5, verbal notifications were made to the CT DEP, detailing the waste test tank discharge event. Specifically, that the preliminary results indicated approximately 840 gallons (4%) of the waste test tank could have l
drained to the berm area, which surrounds the waste test tank, drained into storm drains and out into the Niantic Bay. This amount was later revised in the formal written notification to the CT DEP (Oil & Chemical Spill Division and Bureau of Water Management), dated Janua,y 7,1999. The written notification indicated that
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approximately 1050 gallons (5%) of the Waste test tank had drained to the berm area.
l The notifications to the DEP were made due to procedural requirements contained within emergency plan implementing procedure (EPIP) 4400, " Event Assessment, Classification, and Reportability," and EPIP 4404, " Notifications and Communications."
However, the notifications were made beyond the time requirements specified in the EPIP. 'Also, at 4:15 pm on Janurry 5, report of this event in accordance with 10 CFR 50.72(b)(2)(vi) was made to the NRC, based upon the offsite notification to the state.
.
Inspection Activities'
Through on-site inspection by the resident inspector and in-office review of licensee sample results and dose calculations by NRC Region I specialists, the licensee's follow-
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up and corrective action activities for this event were reviewed. The inspectors noted that CR M3-99-0015 was provided Level 1 status, requiring the licensee to perform a root cause analysis of this event.
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From a radiological standpoint, the licensee estimated the whole body dose from this release to be 2.2E-7 millirem to the maximum exposed member of the public.
independent NRC in-office review of water sample data and calculation assumptions
,
determined that the licensee's exposure determination was based on conservative i
assumptions, and the result was corroborated by an independent calculation by the NRC. Compared to the public exposure limit of 100 millirem per year, the subject
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release was considered to be of very low significance. Though inadvertent and unmonitored, the release did not exceed any regulatory limits or license conditions. The i
licensee initiated actions to assure that this inadvertent release to the environment will be
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appropriately characterized in the next annual effluent release report as required by 10 l
CFR 50.36a(a)(2).
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The inspector Wo reviewed licensee cold weather protection controls, noting that the waste test h leakage originated from the freeze-thaw of a small-bore (%") line, resulting in the failure of an instrument gasket. The heat tracing, intended to keep this
line off the waste test tank from freezing, had failed. - It was not detected, because it was
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a dead-leg branch off the main heat tracing circuit. The heat tracing, the leaking
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instrument, and the waste test tank itself are all classified as nonsafety-related
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l components. The inspector verified through interviews with operations and maintenance l
management personnel that other cold-weather implications of this event, including the
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impact on other outdoor plant tanks, had been considered and that preventive j
maintenance activities with respect to heat tracing were being assessed for further. -
improvements.
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l Both the original design change, DCN DM3-00-1095-98, providing for initial installation of l
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the berm in December 1998, and the revised DCN (DM3-01-1095-98) issued in January 1999 were reviewed. The design upgrade provided a better seal at the joint i
i between the existing asphalt and the berm with the installation of a membrane material.
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The inspector examined some of the field work to install the membrane and noted that
- the new DCN required a test plan to ensure leak tightness of the completed work by filling the area with water and checking for leakage. No test plan had been specified for the original berm installation. The inspector also noted a note on the original berm installation sketch that implied all leak paths should have been suitably caulked. The
' licensee's interpretation of this note was the field sealant of the joint between the existing waste test tanks and boron test tanks concrete slabs, and not the need for sealant of the
cold joint between the asphalt pavement and the installed berm.
The inspector noted that because of the nonsafety nature of this work, neither DCN required quality assurance (QA) oversight. The deficiencies in the original design were discussed with engineering and technical support personnel, and acknowledged by
licensee management as an engineering effectiveness issue. As corrective action for i
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this event, the licensee implemented appropriate contingency actions (e.g., health physics support, berm pumping and containment capabilities) and worked the upgraded DCN installation as a continuous to effect corrective measures as timely as possible.
i Subsequently, the licensee issued another Level 1 CR (M3-99-0189) to evaluate the lack
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of adequate work planning and environmental preparations involved with the completed berm sealing job. Both Level 1 CRs, M3-99-0015 and 0189, remain open pending
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completion of the rout cause analyses.
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Conclusions.
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- After discovery of a waste test tank leak, licensee corrective actions were appropnately f
taken to assess the impact and prevent recurrence of such an event. The inadvertent release of radioactive material to the environment did not violate license conditions and
L was evaluated to have ice safety significance. However, weaknesses in the licensee's l
reportability, engineering, pre,m.tive maintenance, and environmental programs were L
self-identified by this event. The CRs initiated to track these concerns remain open, -
l having been provided Level 1 status for root cause analyses. Pending licensee completion of its reviews and corrective action activities, the overall occurrence,
handling, and licensee response to this event remain unreedved. (URI 50-423/98-06-02) -
111 Plant Suonort
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(Common to Unit 2 and Unit 3)
R1 Radiological Protection and Chemistry Controls R1.1 Badioactive Waste (Radwaste) Proaram a.
Inspection Scoce (86750)
The inspector reviewed the licensee's programs for the processing and packaging for
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shipment of radwaste and radioactive materials. The inspector reviewed licensee documents, interviewed personnel, and made direct observations of licensee activities.
I b.
Observations and Findinas j
Unit 1 i
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The liquid waste processing at Unit 1 currently consist of equipment and floor drain
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waste processing systems. The filter sludge tanks and waste evaporators were removed by May 1997. The inspector observed that only the B train of the floor drain system was fully operable due to "A" degraded valve and associated piping that was removed from the "A" train floor drain sample tank discharge piping. The Unit 1 Director indica 3d that this valve (LRF63) would be replaced and the "A" train restored to service. The basement of the Unit i radwaste building continues to be a contamination area.
Although the major sources of radiation have been removed with dose rates generally 1-3 mrem /hr; the filter sludge tank room, which is empty, is 40 mrem /hr gamma and 200 mrem /hr beta at a distance of 30 centimeters from the floor. This radiological condition was left over from the May 1997 radwaste equipment clean out project. The Unit 1
. _. Radiation Protection Manager inoicated that the contamination clean up of the radwaste
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g basement would be considered relative to As Low As is Reasonably Achievable
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(ALARA) goals.
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Also, at the time of this inspection, the Unit 1 spent resin tank discharge system was declared out of service. The method for pumping out spent resins for the last 15-20 years consisted of a hose placed into the tank through a hole cut in the top of the tank
. and utilized positive displacement pur.:ps for both sluicing out resins and dewatering resins into a polyethlene liner. The radwaste primary equipment operator (PEO)
determined that the hoses and hose fittings were not pressure rated high enough for the
. system configuration and declared the resin discharge pump and hose system inoperable.
Unit 2 The radwaste processing program at Unit 2 continued to be effectively implemented. No discrepancies with the processing ofliquid-to-solid radwaste were observed. In general, the radwaste systems were being operated in accordance with the Unit Final Safety Analysis Report (FSAR).
Unit 3 The originally installed solid radwaste processing system, consisting of a radwaste liquid evaporator, was last used in 1988. From in-plant observations, the waste inlet and steam supply valves to this equipment were closed, however, the valves were not tagged out of service. The radwaste system engineer indicated that a design change had been initiated to cap and isolate the abandoned radwaste equipment. The radwaste PEO reviewed this design change (DCR No. M3-97022), which provided a complete list of valves requiring closure. Utilizing this list, Red (do not operate) tags were hung. The Unit 3 radwaste system engineer indicated that the abandoned radweste evaporator and associated equipment were identified and captured on the unresolved item report no.
1058, with the work to cap, isolate, and institute drawing and UFSAR changes to begin in late 1999.
On Site Radioactive Waste Storaos The Millstone site has several common areas used for the processing and packaging of solid radwaste for offsite shipment. - The areas that were inspected included: The Unit 2 mixed waste storage area, the Unit 2 radwaste filter liner collection area, the Unit 1 solid
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waste storage area, the Millstone radwaste reduction facility and warehouse no. 9.
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The licensee provided a controlled environment for steam cleaning of contaminated
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equipment in the Unit i solid waste storage area. Very little backlog of materials was L
observed. The Unit 2 mixed waste storage area was kept locked and the waste l
containers were appropriately sealed and accurately inventoried. Over eighty
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containers, mostly 55 gallon drums, of mixed waste were being stored. The Unit 2 radwaste filter collection area was in a locked location with a containment building
. installed above the collection liners that effec'.ively limited intemal exposures to personnel. An accurate waste filter inventory was maintained and storage was minimized to less than one polyethlene liner shipment. The Millstone radwaste reduction facility carefully segregated each unit's dry wastes for compaction. Sorting hood and
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compactor ventilation systems included high efficiency particulate air (HEPA) filters. All other contaminated waste in this facility was appropriately handled in sealed containers.
In back of the facility there were over 20 sea vans worth of backlogged contaminated waste articles waiting to be processed and shipped offsite.
At the time of the inspection, warehouse no. 9 was appropriately managed with an
organized contaminated toolissue depot, and stock of reusable contaminated equipment stored in sealed containers that were accurately listed on an inventory list. The fenced in yard area in front of warehouse no. 9 contained 3 polyethlene liners and 7 or 8 sea vans of backlogged contaminated waste articles waiting to be processed and shipped offsite.
All the areas reviewed were well controlled by radiation protection personnel and did not present any significant radiologica' exposure to personnel.
c.
Conclusions Unit i liquid and solid radwaste systems continue to need improvements in order to be functional. Currently, the "A" train of the floor drain system and the spent resin tank discharge system are not available. Onsite storage of radioactive wastes and reusable contaminated equipment was well managed and organized with a small backlog of radwaste remaining to be processed and shipped. The radwaste processing and packaging program was very effective.
R3 Radiological Protection and Chemistry Procedures and Documentation R3.1 Radioactive Material Shioment Records and Procedures a.
Scope (86750)
A review of randomly selected 1998 radioactive material shipments was conducted by the inspector. Shipments selected originated in each of the three units, and included radwaste for disposal in Utah and South Carolina, contaminated laundry, laboratory samples and contaminated equipment. In addition, procedures associated with the i
selected shipments were reviewed as follows:
Procedure no. RW46005, Rev.1, " Shipment of Radioactive Material-Surface Contaminated Object" Procedure no. RW46004, Rev. 5, " Shipment of Radioactive Material-Low Specific Activity" Procedure no. RW46054, Rev.1, " Vectra Resin Drying System" Procedure no. RW46053, Rev. 3, " Packing Radioactive Waste Filters"
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b.
Observations and Findinas l
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. All shipping records were accurate with respect to procedural requirements. During the loading of Unit i spent resin into shipping liners, the use of the inline isolok resin intermittent sampler was not procedurally defined and the manager of waste services indicated that procedure RW46054 would be moditied to ensure samples'of high dose j
rate resin are obtained to provide proper waste classification. The licensee was
determined to be in full compliance with all applicable regulations contained in 10 CFR Parts 20,61 and 71 and 49 CFR.
c.
Conclusions
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All radioactive material shipments reviewed were determined to be in compliance with the applicable provisions of Titles 10 and 49 CFR.
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R5 StafiTraining and Qualification in Radiological Protection and Chemistry a.
Inspection Scooe (86750) and Tl 2515/133
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The inspector reviewed the licensee's program for the training of radioactive material
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l shippers in accordance with NRC IE Bulletin 79-19 and 49 CFR 172.700.
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b.
Observations and Findinas
The inspector reviewed training records for the four Millstone authorized radioactive
. material shippers and verified that each had completed a course covering the applicable
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shipping regulations within the past three years as required.
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Conclusions The technical training program for personnel involved in the transportation of radioactive j
materials was being implemented. Training was provided as required by 49 CFR.
I R7 Quality Assurance in Radiological Protection and Chemistry Activities a.
In*Dection Scooe (86750)
. The inspector reviewed the licensee's program for the assurance of quality in waste processing and transportation of radioactive materials. The program evaluation was based on a review of surveillances conducted of licensee radioactive shipment activities.
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' Observations and Findinas The inspector reviewed the licensee's documentation of quality surveillance reviews of radioactive material shipments performed by the Waste Services Group.
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Quality surveillances are conducted on all packages of radioactive material shipped from i
Millstone Station. De%iled check lists have been developed for the various types of
. radioactive material shipments made, and the completed documents are incorporated i
into the shipment record packages.
f c.
Conclusions i
The licensee provided an independent review of all radioactive material shipments from
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- Millstone Station utilizing detailed checklists, which was effective.
Conduct of Security and Safeguards Activities f
a.
Inspection Scope (817QQ)
The purpose of the inspection was to determine whether the conduct of security and j
safeguards activities met the licensee's commitments in the NRC-approved security plan
-(the Plan) and NRC regulatory requirements. The security program was inspected during the period of December 8-11,1998. Areas inspected included: alarm stations communications; protected area (PA) access control of personnel, packages, and vehicles.
b.
Observations and Findinas Alarm Stations. On December 9 and 10,1998, the inspector observed operations of the Central Alarm Stution (CAS) and the Secondary Alarm Station Center (SAS) and verified that the alarm stations were equipped with appropriate alarms, surveillance and communications capabilities. Interviews with the alarm station operators found them very knowledgeable of their duties and responsibilities. The inspector also verified, through observations and interviews, that the alarm stations were continuously manned, independent and diverse so that no single act could remove the plants capability for detecting a threat and calling for assistance, and the alarm stations did not contain any-l operational activities that could interfere with the execution of the detection, assessment and response functions.
i Communications. The inspector verified, by document reviews and discussions with alarm station operators, that the alarm stations were capable of maintaining continuous intercommunications, communications with each security force member (SFM) on duty, and were exercising communication methods with the locallaw enforcement agencies as committed to in the Plan.
i PA Access Control of Personnel. Hand-Carried Packaoes and Material. On December 9,1998, the inspector observed personnel and package search activities at the personnel access portals, during peak activity periods. The inspector determined, that positive controls were in place to ensure only authorized individuals were granted access to the PA and that all personnel and hand carried items entering the PA were properly searched.
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PA Access Control of Vehicles. On December 10,1998, the inspector observed vehicle e
access control activities at the main vehicle access control entry point. The activities observed included Security force member's verification of vehicle authorization and I
escort requirements and the performance of three vehicle searches prior to granting PA
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access. The inspector concluded that vehicles were being controlled and maintained in
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accordance with the Plan and applicable procedures.
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Conclusions t
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The licensee was conducting its security and safeguards activities in a manner that
l protected public health and safety and that this portion of the program, as implemented,
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met the licensee's commitments and NRC requirements.
S2 Status of Security Facilities and Equipment
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a.
Insoection Scoos (81700)
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j Areas inspected were: PA assessment aids and PA detection aids.
b.
Observations and Findinas '
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PA Assessment Aids. On December 9,1998, the inspector evaluated the effectiveness of the assessment aids, by observing on closed circuit television, a security force member conducting a walkdown of the PA. The assessment aids, in general, had good
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picture quality and good zone overlap. Additionally, to ensure Plan commitments are
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satisfied, the licensee has procedures in place requiring the implementation of
compensatory measures in the event the alarm station operator is unable to properly i
l assess the cause of an alarm.
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PA Detection Aids. During the assessment aids PA walkdown observation, conducted on December 9,1998, the security force member conducted random performance
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j testing of the detection aids. The appropriate alarm was generated in all cases. The
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inspector determined that the equipment was functional and effective and met the i
requirements of the plan.
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c.
Conclusions
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The licensee's security facilities and equipment were determined to be well maintained and reliable and were able to meet the licensee's commitments and NRC requirements.
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S3 Security and Safeguards Procedures and Documentation a.
Insoection Scope (81700)
Areas inspected were: implementing procedures and security event logs.
b.
Observations and Findinas.
Security Proaram Procedures. The inspector verified that the procedures were i
consistent with the plan commitments, and were properly implemented. The verification
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was accomplished by reviewing selected implementing procedures associated with PA access control of personnel, and PA access control of vehicles.
Security Event Loos. The inspector reviewed the Security Event Logs for the previous nine months. Based on this review, and discussion with security management, it was
determined that the licensee appropriately analyzed, tracked, resolved and documented safeguards events dat the licensee determined did not require a report to the NRC
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within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
c.
Conclusions Security and safeguards procedures and documentation were being properly implemented. Event Logs were being properly maintained and effectively used to analyze, track, and resolve safeguards events.
S4 Security and Safeguards Staff Knowledge and Performance a.
Inspection Scope (81700)
)
Area inspected was: security staff requisite knowledge.
b.
Observations and Findinas
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Security Force Reauisite Knowledae. The inspector observed a number of security force member's in the performance of their routine duties. These observations included alarm station operations, personnel and package searches and vehicle searches. The
. inspector determined that the security force members were very knowledgeable of their responsibilities and duties, and could effectively carry out their assignments.
c.
Conclusions The Security force members adequately demonstrated that they had the requisite l_
. knowledge necessary to effectively implement the duties and responsibilities associated j
with their position.
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I t86 Security Organization and Administration I
a.
Insoection Scoos (81700)
Areas inspected were: management support, effectiveness and staffing levels.
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b.
Observations and Findinas Manaaement Support. The inspector reviewed various program enhancements made
'since the last program inspection which was conducted in February,1998. These
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' enhancements included the allocation of resources for a complete replacement of the E-field, attendance of the entire training staff at corporate train-the-trainer training, and '
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acquisition of a large offsite facility used exclusively for the conduct of training.
Manaaement Effectiveness. The inspector reviewed the management organizational.
structure and reporting chain and noted that the Manager, Nuclear Security's position in the organizational structure provides a means for making senior management aware of programmatic needs, i
Staffina Levels.- The inspector verified that the total number of trained security force members immediately available on shift met the requirements specified in the plan.
c.
Conclusions The level of management support was adequate to ensure effective implementation of the security program, and was evidenced by adequate staffing levels and the allocations of resources to support programmatic needs.
j S7 Quality Assurance in Security and Safeguards Activities
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a.
Insoection Scooe (817QQ)
i Areas inspected were: audits, problem analyses, corre::tive actions and effectiveness of
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management controls.
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b.
Observations and Findinas The inspector revkewed the 1998 QA audit of security program conducted
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September 14-25,1998, (Audit No. MP-98-and the 1998 QA audit of the fitness-for-
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' duty (FFD) program, conducted may 4-15, k,, (Audit No. MP-98-A07). The audits were found to have been conducted in aco ance with the plan and FFD rule. To enhance the effectiveness of the audits, bo.n audit teams included independent technical l
specialists.
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- The security audit identified no findings,5 deficiencies. One deficiency was related to a lighting deficiency, and four deficiencies were related to administrative issues associated l~
with procedures and procedure controls. The FFD audit identified three deficiencies.
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The deficiencies were associated with the MRO signature on chain-of-custody forms, document control of one copy of the FFD Manual and the lack of reporting of negative j~
_ test results into the database as required by the FFD Manual.
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i The inspector determined that the. deficiencies were not indicative of programmatic
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weaknesses, and the corrective actions would enhance program effectiveness.
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Inspector's discussions with security management and FFD staff revealed that the -
l responses to the deficiencies were complete, and the corrective actions were effective.
Problem Analyses. The inspector reviewed data derived from the security department's self-assessment program. This data is tracked through key performance indicators.
Potential weaknesses were being identified, tracked and trended.
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. Corrective Actions, The inspector reviewed corrective actions implemented by the i
licensee in response to both the QA audits and the self-assessment program. The corrective actions were effective, evidenced by a reduction in personnel performance issues and loggable safeguards events.
Effectiveness of Manaaement Controls. The inspector observed that the licensee had programs in place for identifying, analyzing and resolving problems. They include the performance of annual QA audits, a departmental self-assessment program, a recently developed key performance indicators program and the use of industry data such as violations of regulatory requirements identified by the NRC at other facilities, as criterion for self-assessment.
c.
Conclusion The review of the licensee's audit program indicated that audits were comprehensive in scope and depth, that the audit findings were reported to the appropriate level of management, and that the program was being properly administered. In addition, a i
review of the self-assessment program documentation in conjunction with the key performance indicators program indicated that the programs were being effectively implemented to identify and resolve potential weaknesses.
IV. Manaaement Meetinas l
X1-Exit Meeting Summary L
L The inspectors presented the inspection results to members of licensee management at the
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. conclusion of the inspection. The licensee acknowledged the findings presented.
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INSPECTION PROCEDURES USED l
IP 37550i Engineering j
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IP 60705:
Preparation for Refueling I
IP 60710:
Refueling Activities
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- IP 61726:
Surveillance Observations
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. IP 62707:
Maintenance Observations
. lP 71707:
Plant Operations IP 71750:
- Plant Support Activities j
lP 81700:
- Physical Security Program for Power Reactors
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IP 83729:
Occupational Exposure During Extended Outages
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. lP 86750:
Solid Radiation Waste Management and Transportation of Radioactive Material
. IP 90712i In-Office Review of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92700 Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92901:
Follow-up Operations IP 92902:
Follow-up Maintenance.
IP 92903:
Follow-up Engineering llP 93702:'
Pr,.mpt Onsite Response to Events at Operating Power Reactors
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- TI 2515/133
- Implementation of Revised 49 CFR Parts 100-179 and 10 CFR Part 171
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ITEMS OPENED, CLOSED, AND DISCUSSED l
Ooened IFl 50-423/98-06-01 (Section U3.02.1)
MSIV Partial Stroke Testing URI 50-423/98-06-02 (Section U3.E2.1)
Waste Test Tank Leakage Closed i
IFl 50-336/94-201-90 (Section U2.E8.1)
VIO 50-336/98-207-10 (Section U2.E8.2)
eel 50-336/96-201-25 (Section U2.M8.3)
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VIO 50-336/98-216-02 (Section U2.E8.4) -
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VIO 50-423/96-05-12 (Section U3.08.1)
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Discussed eel 50-336/97-02-12 (Section U2.M8.1)
VIO 50-336/98-207-10 (Section U2.E8.3)
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. The followina LERs were also closed durina this insoection:
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LER 50-336/96-038-00 (Section U2.M8.1)
LER 50-336/97-012-00 (Section U2.M8.1).
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