IR 05000309/1997005
| ML20210L092 | |
| Person / Time | |
|---|---|
| Site: | Maine Yankee |
| Issue date: | 07/11/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20210L065 | List: |
| References | |
| 50-309-97-05, 50-309-97-5, NUDOCS 9708200219 | |
| Download: ML20210L092 (43) | |
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. U S,-NUCLEAR REGULATORY COMMISSION
REGION I
- Docket No:-
_50 309-
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License No:
DPR 36
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Report No:
50 309/97 05 Licensee:
Maine Yankee Atomic Power Company (MYAPC)
Facility:
Maine Yankee Atomic Power Station
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Location:
Bailey Point Wiscasset, Maine
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Dates:
April 27,1997 - June 8,1997 Inspectors:
Jimi Yerokun, Senior Resident inspector Division of Reactor Projects i
Richard Rasmussen, Resident inspector Division of Reactor Projects Cheryl Beardslee, inspector
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Nuclear Reactor Regulation (NRR)
Douglas Dempsey, Reactor Engineer Division of Reactor Safety
' Approved by:
- Curtis J. Cowgill,111, Chief, Projects Branch No. 5
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Division of Reactor Projects
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9708200219 970711 PDR ADOCK 05000309 e
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EXECUTIVE SUMMARY
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Maine Yankee Atomic Power Company NRC Inspection Report 50 309/97-05 This integrated inspaction included aspects of licensee operations,' engineering,
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maintenance, and plant support. The report covers a 6 week period of resident inspection; in addition, it includes the results of announced inspections by a regional inspector of Inservice Testing and a headquarters inspector of Steam Generator inspection activities.
QacIJtioris
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A sequence of events during core offload revealed significant weaknesses in several areas-of Maine Yankee performance, Specifically, work control, testing, and problern identification and resolution were the most significant. Three events occurred during refueling operations that revealed inadequacies in the checkout performed to verify fuel
- handling crmes were ready to move fuel. As a result, the inspectors identified two Lviolations of Technical Specifications and 10 CFR Appendix B, Criterion XVI. (Section 01.2)
i Engineering design and evaluation of the alternate cooling to the spent fuel pool heat exchanger was thorough and adequately addressed the key safety functions of the system. However, the implementation of the modification through the installation and operating procedures war, not rigorous and roquired several changes to adequately implement the modification, (Section 02.1)
Maine Yankee appropriately and effectively implemented the design change request PORC subcommittee. The reviews performed by the subcommittee were thorough and focused on safety. (Section 07.1)
Maintenance
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- An inspection of the inservice testing (IST) confirmed the root causes from Maine Yankee's recent self assessment of the IST program, particularly with respect to weak -
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understanding of the Code requirements and the associated regulatory expectations.
Program documents and procedures were found to be inconsistent with technical specifications, and substantial scope problems were just being addressed at the time of the inspection. Violations of Code requirements pertaining to pump _ testing and implementation of alternative test limits and methods without obtaining NRC approval.
(Sections M1.2, M1.3, M3)
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- The steam generator tube inspection program and procedures were good, in addition, the personnel managing and implementing the program were knowledgeable and followed procedures. The licensee made the decision to perform additional steam generator secondary side inspections based on industry operating experience was indicative of good safety focus. (Section M1.5)
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An electrical supervisor displayed excellent technical kncwledge and a good safety perspective in finding a test discrepancy and recommending to operations that the EDG be declared inoperable. The response to weaknesses in documentation of the test difficulties
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during the May 15th test were considered appropriate. (Section M4.1)
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Enaineerina The development of the system engineering department and implementation of the system readiness reviews was a positive effort. The experience level of the system engineers
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attributed to tha quality of the system readiness reviews. (Section E2.1)
The steam generator inspection project was managed safely by technically competent
individuals. The approach taken regarding inspection scope and expansions, in situ testing -
and tube pulls reflected sound engineering judgement indicative of an excellent safety.
focus. The number of degraded tubes identified was not substantial enough to raise any concerns with the Reactor Coolant system flow. (Section E2.2)
Plant Suncort
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Maine Yankee's efforts at addressing the Fire Barrier Penetration Seals continued to progress well. The project was managed by technically competent individuals who demonstrated good safety perspective. (Section F2.1)
Maine Yankee reacted properly to ensure fire protection safety when it.was identified that an individual assigned to perform fire watches had not performed as expected and had
f alsified fire watch logs to indicate that he had been in the various areas as required when he, in fact, had not been. Security personnel showed good awareness and questioning attitude by identifying this discrepancy. (Section F4.1)
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-TA8LE OF CONTENTS T A 8 L E O F C O NT E NT S..............................................
iv 1. O p e r a t i o n s -.....................................................
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Conduct of Operations...................................
01.1 G eneral Comme nt s.................................
01.2 Re f ueling Activitie s.................................
'l 02-Operational Status of Facilities and Equipment...........,........ 5
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O2.1 Implementation of Alternate Spent Fuel Pool Cooling
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07-Quality Assurance in Operations
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07.1 Observations of PORC Subcommittee Activities.............
08 Miscellaneous Operations issues............................
08.1 10 CFR 70.24, Criticality Accident Monitoring..............
08.2 Closed, VIO 95 24-01 (EA 95 282 01014), VIO 95 24 02 (EA 95 282 02014) and VIO 95 24-03 (EA 95 282 03014)
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II. M a int e n a n c e..................................................
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M1 Conduct of Maintenance..................................
M 1.1 G eneral Comme nts.................................
M1.2 Inservice Test Program Review
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M1.3 Inservice Test Program Scope........................
M1.4 Steam Generator Tube / Sleeve Eddy Current Examination
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M1.5 Steam Generator Secondary Side Component Non Destructive E x a mina tio n.....................................
M3 Maintenance Procedures and Documentation...................
M3.1 Testing of Safety / Relief Valves
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M 3. 2 Pum p Te sting....................................
M 3.3 - Valve Te sting....................................
M4 Maintenance Staff Knowledge and Performance 26-
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M4.1 Diesel Generator Systems Testing
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M8 Miscellaneous Maintenance issues........,,................
M8.1 (Closed) Unresolved item 50 309/96 16-06, Adequacy of the I ST p rog ram....................................
111. E n g in e e r i n g..................................................
El Conduct of Engineering..................................
-E1.1 G e neral Comme nts................................
E2 Engineering Support of Facilities and Equipment.................
E2.1 Engineering System Assessments
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- E2.2 Steam Generator Inspection.........,...............
IV. Pl a n t S u p p o rt................................................
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S1 Conduct of Security and Safeguards Activities
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S1.1 G e neral Comments -................................
F2-Status of Fire Protection Facilities and Equipment
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F2.1 Fire Protection Penetration Seals Project lUpdad URI 50
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309/96-08 05) (Closed URI 50 309/9 5 15 02) -............
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F4 Fire Protection Staff Knowledge.and Performance..............
F4.1 - Falsification of Fire Watch Logs............,..........
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V. M an ageme nt Meeting s.......................................... -
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. Exit Me eting Summ ary -..................................
PARTI AL LIST OF PERSONS CONTACTED..............................
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INSPECTION PROCEDURES USED -....................................
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ITEMS OPENED,' CLOSED, AND DISCUSSED............................. =35 LIST OF ACRONYMS USED
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Reoort Details Summarv of Plant Status Maine Yankee began this inspection period in the refueling mode with significant work ongoing. Steam generator inspections, core offload, cable separation and fire penetrations were the primary areas of focus. On May 27,1997, the plant owners announced their plans to curtail spending on the plant and put it in preservation mode pending sale or a future decision to enter decommissioning. Contractors were cut from the work force and work on the site was reprioritized to support establishing those items necessary for
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optimizing shutdown safety using the remaining Maine Yankee staff.
l. Opera 1Lqog
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Conduct of Operations 01.1 General Comments (7170_7)
Using Inspection procedure 71707, the inspectors conducted reviews of ongoing plant operations. Operators performed activities in accordance with approved procedures and demonstrated a good safety perspective. However, some instances of weak performance were noted. For example, in dealing with problems that occurred with the refueling machines and in implementing the temporary modification to the spent fuel pool heat exchanger.
01.2 Refuelina Activities a.
Insoection Scone (71707. 60705. 607101
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During the period, Maine Yankee commenced moving fuel from the reactor core to the spent fuel pool in accordance with the cycle 15-16 refueling outage plan.
Maine Yankee experienced several problems and identified deficiencies with some of their refueling equipment checkout procedures. The inspectors reviewed the details of these events and the implementation of corrective actions, b.
Observations and Findinas in preparation for core offloading, the inspectors reviewed Maine Yankee's procedures and administrative requirements for controls of refueling activities. The reviews included Technical Specification Section 3.13, Refueling and Fuel Consolidation Operations; refueling procedures, and discussions with operations department managers and supervisors.
The inspectors ascertained that there were clear definitions of lines of supervision, shif t manning requirements, training and qualification of key personnel,
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communication requirements, and radiological monitoring and control requirements.
The requirements for equipment check out, dry runs of critical operations, and fuel handling were also clearly established. Personnel understood their responsibilities and the requirements and procedures for moving fuel. There was good management involvement in the activities.
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The inspectors reviewed the status of equipment needed to support core off-loading - The refueling reactor coolant system (RCS) boron concentration was 1,803 ppm (Tech. Specs requires minimum of 1,750 ppm). The Containment Purge and Vent valves' switches were in the " refueling" position and operable to high
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radiation signal as required. The containment equipment hatch roll up door was in place, and the personnel airlocks were open with established contingency plans for
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closure per the outage risk plans (17 2, Operations at Cold Shutdown Attachment
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B). All four wide range log monitors were operable and in service. The "B" train of
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RHR was in service. Tne cavity level was slightly above 44 feet, corresponding to
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about 36 feet above the core (minimum of 23 feet ah re core is required).
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On May 17,1997, core offload started. The inspectors observed defueling from the refueling bridges in the containment and the spent fuel pool. Foreign Material Exclusion (FME) and Radiological Control oversight was excellent. Communication was properly established and working properly. Lighting in the cavity and spent
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fuel pool was good. After movement of approximately 40 fuel assemblies, Maine Yankee experienced two problems which resulted in the stoppage of core offload.
The first problem occurred whik the operators in containment were trying to lower fuel bundle #D5 in the upender (North). The underload interlock tripped at about 36
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inches from the bottom indicating that there was some restriction to the bundle going all the way into the upender. The bundle was retracted and the upender inspected for blockage and it was also cycled down and up. Another attempt to insert the bundle in the upender gave the same result. The refueling machine, with
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the fuel bundle, wac returned to the reactor vessel area and alignment checked, it
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was found to be off by.21 inches in the North / South direction. Af ter discussion between the bridge and the control room personnel, it was decided that the
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machine be shifted North.21 inches to correct the alignment. The adjustment was
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made, but on trying to lower the bundle, it was evident that the alignment was still improper. The underload trip came early and the operator saw through the bridge
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camera that the machine was even further misaligned. So, they decided to adjust back to the original misaligned position and then adjust South.21 inches. The bundle was then successfully lowered into the upender, s
Although no damage resulted from the mis adjustment, the inspector considered the oversight of the evolution weak because the evolution was not stopped when the error was discoverdto understand why the error occurred and to verify that the roadjustment in the opposita direction was appropriate.
Preliminarily, the licenseo concluded that the frequency requirements for conducting
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fuel handling equipment alignment checks were not stated clearly in the procedures.
Operations management indicated that procedure 101, Core Reloading, would be enhanced to require alignment checks at fixed times each shift (at the beginning of-each shif t) and that turnover briefings would be improved.
The second problem occurred during the period when adjustments to the refueling machine were ongoing. Maine Yankee had taken the opportunity to repair some lights in the spent fuel pool. This activity moved some temporary power cables (480 volts) which resulted in a power cable to a temporary spent fuel pool
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purification unit being damaged by a wheel guard as the SFP crane (CR 9) bridge
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was being used to move fuel. The wheel guard cut the cable and caused a short.
Preliminarily the licensee concluded that inadequate inspection by the spent fuel pool team leader prior to moving the bridge; improper identification of cable atound the spent fuel pool; and, inadequate cleanup by maintenance workers contributed to the problem.
This second event was similar to an event that occurred on March 4,1997, during which CR 9 contacted a safety rail stanchion that was moved during maintenance.
Although this previous issue was entered into the learning bank as a level 2, the evaluation had not been completed at the time of the power cable event.
As a result of the above events, all refueling activities were stopped to review the issues and implement appropriate correctivo actions. Maine Yankee participated in a conference call with the NRC to discuss the events and corrective actions.
Corrective actions included verification that the fuel bundle in the upender was not damaged, personnel actions, briefing of personnel, walkdowns in the spent fuel pool, and checks that the cable short did not damage the electronics of spent fuel pool crane (CR 9). The following changes were also made: development of an additional requirement for maintenance personnel to walkdown areas during closeout of any activities around the Spent Fuel Pool and the Cavity; change of procedures 13 2, Fuel Handling in the Spent Fuel Pool, and 13-4, Refueling Machine Operation, to require reverification of certain prerequisites after maintenance in area; and improvement in FME controls of cords / lines that have the potential to interact with rails.
On May 19,1997, Maine Yankee determined that one of the tests prescribed by the system engineer to test the CR 9 electronics failed. The failed test was an interlock to stop bridge or trolley movement if hoist movement was initiated.
However, the cause and time of the interlock failure was not known because the procedure used to verify the proper operation of the cranes prior to refueling did not include these checks. Maine Yankee technical specifications are not specific with regard to what features or interlocks are required to be tested, however the technical specifications do require a thorough checkout of the cranes prior to moving fuel.
As a result of this problem Maine Yankee researched the CR 9 and refueling machine design basis to determine what interlocks and functions should exist and
- to verify that these interlocks and functions were tested as required by technical specifications. Maine Yankee returned the CR-9 interlocks to the original design configuration. No deficiencies were identified in the refueling machine.
On May 23,1997, the fuel pool crane was returned to operations to perform their pre-use checkout as revised. Although the crane passed all of the interlock checks specified in the procedure, the checkout was aborted because operators identified a problem with the trolley speed (no slow speed), and intermittent operation of bridge speeds. Moro troubleshooting identified a loose connection affecting the speeds.
Af ter repairs, the crane was retested per the maintenance work order and fuel movement was resumed late on May 24th. Procedural enhancements were made
. to include bridge and trolley speed checks as a part of the crane checkout
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- On May 25,1997, at approximately 1100 hrs, a radiation control technician identified that the north spent fuel pool crane stops were not placed such that a
oundle would be prevented from striking the north wall. Again fuel movement was stopped and operators developed immediate corrective actions which included testoration of the stops to the required location. Procedure 13-2, Fuel Handling in the Spent Fuel Pool, contained a prerequisite to check the stops, however the wording was unclear and did not give a purpose for the stops. Procedure 31 10,
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Refueling System Interlock Test, which Maine Yankee developed to assure the
- requirements of the technical specification required crane checkouts did not check
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On May 26,1997, fuel movement was stopped again due to problems identified with indicating lights on the fuel transfer machine. The transfer machine has two indicating lights, a blue light and a green light, The lights represent the appropriate scale on the cable load indicator to be road The cable load indicator has a separate scale for each direction of travel. The load indicator is used to monitor the safe travel of the fuel bundle and carriage through the fuel transfer canal. Procedure 13 3, Transfer Machine and Upender Operation, specified the expected sequence of
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indicating lights on the machine. During operation, operators noted that the lights did_not match the procedure. However, procedure 31-10, Refueling System
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refueling, was not detailed enough to identify the indicating light f ailure.
Investigation by Maine Yankee found that this question was first raised on May 17, 1997. The problem was resolved by swapping the position of the two light bulbs.
However, a detailed retest was not performed and the real problem was not fixed.
The actual problem turned out to be a f ailed relay in the indicating light circuit. A safety evaluation was performed by Maine. Yankee which concluded that although the indicating lights were not operating properly, the error was conservative in that
- the higher reading scale was used to monitor the movement of fuel through the transfer canal. This would not have been the case if fuel had been moved from the spent fuel pool to the core during this period, in response to these of events Maine Yankee completed the evaluations for the individual events and performed an aggregate assessment of all of the events.
Additionally, this evaluation included the crane problems cited in inspection report 9614 and violations experienced during the 1995 refueling outage which were documented in inspectlon report 95 24. The evaluation identified a number of
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causal factors which included inadequate work control, inadequate testing, non-conservative decision making, not identifying problems to _ management and not
- ins olving engineering. Maine Yankee developed short term corrective actions to resolve these issues prior to moving fuel and long term actions for future evaluation. The inspectors monitored the implementation of the short term actions and considered them adequate to resume fuel movement. However, as of the end of the inspection period fuel movement did not occur due to unrelated mechanical -
difficulties with a power cord take-up reel for the spent fuel pool cran._
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Conclusions The sequence of events revealed weaknesses in several areas of Maine Yankee performance. Specifically, work control, testing, and problem identification and resolution were the most significant. Proper testing of refueling cranes is a requirement of technical specification 3.13, Refueling and Fuel Consolidation Operations. One of the requirements is that prior to each refueling, a complote checkout shall be conducted on fuel handling cranes that will be used to handle irradiated fuel assemblies, From the period of May 19,1997, through May 26, 1997, three events occurred during refueling operations that identified inadequacies in the checkout performed to verify fuel handling cranes were ready to move fuel.
These inadequacies constitute a violation of NRC requirements. (VIO 50 309/97-05-01)
Additionally, the events which resulted in the spent fuel pool crane running over an electrical cable on may 18,1997, were nearly identical tu those which resulted in
the spent fuel pool crane running into a hand rail stanchion on March 4,1997.
Although the March 4, event was entered into the learning process, actions to prevent recurrence were inadequate and the issue evaluation report was not completed until after the electrical cable event. 10 CFR 50, Appendix B, Criteria XVI Corrective Actions, requires in part, that in the case of significant conditions adverse to quality, measures shall assure the cause of the condition is determined and corrective action is taken to preclude repetition. The f ailure to take adequate
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corrective actions is a violation of NRC requirements. (VIO 50 309/97-05-02)
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Operational Status of Facilities and Equipment O 2.1 Imolementation of Alternate Soent Fuel Pool Coolino a.
Inspection Scooe (71707)
As part of the outage work, Maine Yankee removed the primary component cooling
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(PCC) system from service, in order to facilitate removal of PCC, an alternate cooling source was required for the spent fuel pool (SFP) heat exchanger. Maine
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Yankee implemented a temporary modification which used the secondary component cooling (SCC) system to cool the SFP heat exchanger. The inspector reviewed the design, engineering and implementation of the temporary SCC to the SFP heat exchanger.
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Observations and Findinns
Alternate cooling to the SFP heat exchanger was provided by routing temporary SCC hoses from the main generator hydrogen coolers SCC piping to the SFP heat exchanger. The hoses tied into the SCC system outside of the SCC safety related
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boundary and wrapped around the outside of the turbine building to get to the SFP heat exchanger. Engineering performed a detailed technical evaluation and 10 CFR 50.59 evaluation for the temporary modification. The inspector performed a j
detailed review of these documents and found no discrepancies, i
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l The installation of the hoses was performed by a maintenance work request and the testing a. d operation of the hoses were addressed in operations procedure 41-49, Alternate Cooling to SFP Heat Exchanger. However, the inspector noted that the coordination between the procedures was poor. The fill, vent and testing was l
covered in both procedures which lead to confusion as to which procedure was being used to accomplish these tasks.
Another weakness in the implementation of the temporary cooling modification was the coordination with other procedures. The abnormal operating procedure, AOP 2-52, Loss of Fuel Pool Cooling, and/or Level, contained steps that no longer worked with the temporary modification installed. These steps referred to actions to take on the PCC system to deal with an abnormality in the SFP. However, portions of the temporary modification were installed, and the alternate cooling operating procedure was issued without modifying the AOP. The AOP was subsequently modified.
The operations procedure required an inspection of the temporary hoses once per shift. However, no periodic inspections were required for the temporary fire hoses and fittings that were staged as a backup to the alternate system. Due to the inspectors concerns of the backup hoses being moved, damaged or obscured due to the large volume of outage work in the area, operations added an inspection of the staged fore hoses to the shiftly checks, c.
Qgnelusions The inspector concluded that the engineering design and evaluation of the alternate cooling to the spent fuel pool heat exchanger was technically sound and adequately addressed the key safety functions of the system. However, the implementation of the modification through the installation and operating procedures was not rigorous and required several changes to adequately implement the modification.
Quality Assurance in Operations 07.1 Observations of PORC Subcommittee Activities
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Insoection Scone (71707)
As a result of the large volume of plant modifications planned for the current outage, a plant operating review committee (PORC) subcommittee was established to accomplish the reviews. The inspectors reviewed the makeup and activities of the subcommittec.
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Observations an_s! Findinas Maine Yankee technical specifications allow the establishment of PORC subcommittees to perform reviews as assigned. To facilitate the large volume of plant modifications, PORC established a design change request subcommittee. The membership in the committee met the technical specification requiremants and included representatives with expertise in all of the appropriate discipline _ - _.
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The inspectors attended several subcommittee meetings. At the meetings the subcommittee members raet with engineers and engineering management to
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discuss details of the design change roquests. The subcommittee members were prepared for the meetings and asked detailed questions related to their areas of expertise. Comments and q Jestions were resolved prior to the committee voting on
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the acceptance of each package. The results of the subcommittee reviews were presented to PORC for final ar.oroval.
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Conclusiong The inspector concluded that Maine Yankee appropriately and effectively implemonted the design change reouest PORC subcommittee. The reviews performed by the subcornmittee we'e thorough and focused on safety..
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Miscellaneous Operations issues 08.1 10 CFR 70.24. Criticality Accident Manitorina a.
Insnection Scoce (92901)
As a followup on recent industry experienco, the inspeaors reviewed Maine Yankee's status relative to the requirements of 10 CFR 70.24, Criticality Accident Requirements.
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Observations and Findinas 10 CFR 70.24 requires that each licensee authonted to possess special nuclear material (SNM) maintain in the area in which the f NM is handled, used or stored, a monitoring syt. tem. The requirements for the monit ring system are described in 10 a
CFR 70.24 (a)(1) or (a)(2). Paragraph (a)(2) was applicable to Maine Yankee, which was licensed prior to December 6,1974. The basic lequirements were that the criticality monitoring alarm system shall consist of garoma or neutron sensitive radiation detectors, with a clearly audible alarm signal. The detectors must be able to detect a criticality which generates radiation levels of 300 Rem per hour one foot from the source with preset alarm setpoints between 5 aad 20 mrem per hour and be located no further than 120 feet from the SNM.
An exemption from 10 CFR 70.24 was granted to Maine Yankee in the original SNM license (SNM-1258) dated August 9,1971 (Item 10 of ?.icense). But this exemption was not carried over into the operating license.
A review of Maine. Yankee's setup revealed that there was no dtdicated detector t.round the new fuel vault able to detect a criticality which generates radiation-levels of 300 Rem per hour one foot from the source and initiate a clearly audible alarm signal at preset alarm setpoints between 5 and 20 mrem per hour and at a
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To immediately rectify the situation, Maine Yankee did the following:
Changed the alarm setpoint of the Spent Fuel Pool monitor (RM 6107),
located within 120 feet of the new fuel vault, which alarms locally and in
the Control to between 5 and 20 Mrem /hr.
Relocated one of the two local radiation detectors installed in the new fuel
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vault to the fuel handling floor. Both detectors are, set to alarm locally at about 10 mrem / hour.
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Revised radiation control procedures to include more guidance and enhanced
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personnel training on responding to the alarms.
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Developed Emergency Plan instructions to address the required drill frequency, drill population, drill methodology and responsibilities and conducted a drill and briefed workers before the drill.
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The actions were completed in the end of February,1997. Additionally, Maine
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Yankee submitted a request for an exemption from 10 CFR Part 70.24, in a letter to the NRC dated December 19,1996.
This item remains unresolved pending further NRC review of the licensee's actions.
(URl 50 309/97 05 07)
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Conclusions The NRC found that Maine Yankee was not fully meeting the requirements of 10 CFR 70.24. However, when the issue was raised, the licensee took prompt and
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offective actions. Maine Yankee subsequently submitted a request to the NRC to be exempted from the requirements of 10 CFR 70.24.
L 08.2 Closed VIO 95-24-01 (EA 95-282 01014), VIO 95 24-02 (EA 95 282 02014) and l
VIO 95 24 03 (EA 95-282 03014)
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a, insoection Scone (929011 On March 5,1997, the NRC issued a Notice of Violation to Maine Yankee pertaining to issues identified during an NRC inspection conducted on November 6-9,-1995. The violations involved inadequacies observed during the 1995 refueling activities. The inspectors reviewed Maine Yankee's response to the Notice of Violation and observed activities involving fuel movement to determine if the root causes of the problems had been properly identified and if appropriate corrective actions had been implemented.
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b.
Obseryations and Findinos During the beginning of the 1995 refueling, Maine Yankee experienced a series of fuet handling and operational events in October and November of 1995. The more significant events involved: (1) A spill of about 800 gallons of radioactive water in the Containment Spray Building: (2) Presence of foreign materialin the refueling cavity; (3) Unplanned partiallifting of Control Element Assemblies (CEA); (4) Fuel assembly interaction with another assembly in the opender; and (5) Containment Purge Valve Switch mispositioning. An NRC specialinspection team reviewed the circumstances surrounding these issues and the findings were documented in NRC inspection report 50-309/95-24, dated December 20,1995.
In response to the violations, Maine Yankee discussed their immediate and planned long term corrective and preventive actions to address the problems. These items were transmitted to the NRC in a letter dated April 4,1996.
During the 1997 core off loading, the inspectors reviewed Maine Yankee's procedures, observed various activities, and held discussions with plant personnel to determine if the corrective actions taken to address the previous refueling errors were effective. There were good procedure controls and implementation.
Operators maintained good configuration control. The Foreign Material Exclusion (FME) program was being implemented properly. The inspector reviewed the refueling procedures and noted that there were appropriate enhancements implemented to ensure that errors similar to those that occurred during the last refueling would not recur. However, a minor discrepancy was identified in procedure 101, Core Reloading, regarding the requirement to conduct a refueling machine alignment check every shift. There was no specificity in the procedure as to the time during the shift when it was to be done, thereby making it possible to do at the beginning of a shift and next at the end of the next shift. This potential inconsistency was immediately corrected by the licensee, c.
Conclusiop_1 Maine Yankee properly implemented corrective and preventive measures to deal with the refueling mishaps that occurred during the 1995 refueling outage. The violations associated with those mishaps, 50-309/95-24-01, 50 309/95 24-02, and 50-309/95 24-03 are closed, ll. Maintenance M1 Conduct of Maintenance M 1.1 General Comments Maintenance activities were well controlled and conducted in accordance with approved work orders. There was good supervisory, radiological and Quality Assurance oversight of activities. The following maintenance and surveillance items were specifically observed. No discrepancies were noted.
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WO 96 01277 00 Overhaul MOV 6016 WO 97-00869 00 FB Penetration Seals, Rx. MCC Room WO 97 00869 07 Fire Barrier Fire Suppression, Rx. MCC Room FB Pen # FBP 51-07).
WO 97-00574-01 Repair valve WP-F-51 Actuntor M1.2 Inservice Test Proaram Review a.
Insnection Scoce (73756. T! 2515-110)
The inspectors evaluated the effectiveness of Maine Yankee Atomic Power Company's (MY) inservice test program for safety related pumps and valves. At
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the time of the inspection, the licensee had completed a self assessment of its inservice test progran.1, and was in the process of addressing the findings. The inspectors focused primarily on components in the emergency and auxiliary feedwater (EFW/AFW), high and low pressure safety injection (HPSI/LPSI),
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emergency diesel generator, containment isolation, and containment spray systems.
These risk-significant systems are needed to prevent or to mitigate the dominant core damage frequency events identified in the Maine Yankee Individual Plant Examination.
The purposes of inservice testing (IST) are to assess the operational readiness of pumps and valves, to detect degradation that might affect component operability, and to maintain safety margins with provisions for increased surveillance and corrective action. The requirements for IST are contained in Maine Yankee Technical Specification (TS) 4.7, which requires testing in accordance with 10 CFR 50.55a, " Codes and Standards," and Section XI of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (the Code). The inspectors reviewed administrative and surveillance procedures, engineering evaluations, and test results encompassing the previous two operating cycles at MY, b-Observations and Findinns Maine Yankee currently is implementing the third 10-year interval of the IST program. Testing is performed pursuant to Section XI of the Code (1986 Edition).
As allowed by 10 CFR 50.55a(f)(4)(iv), the MY IST program adopts ASME/ ANSI OMa-1988, " Inservice Testing of Pumps and Valves in Light-Water Reactor Power Plants," Part 6 (OM-6) for pumps, and ASME/ ANSI OM 1,1981 for pressure relief devices. MY conducted power operated valve testing in accordance with relief request VRR 1 which combined portions of Article IWV 3417 of the Code and Part 10 (OM 10) of ASME/ ANSI OMa 1988. Other valves were tested pursuant to the 1986 Code Edition. The licensee's implementation of relief request VRR 1 is discussed in Section M3.3 of this report.
The IST program description and surveillance procedures contained several statements that were quoted directly from the Code, but were inconsistent with the MY technical specifications, as well as the NRC interpretations and positions
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discussed in NUREG 1482, Guidelines for Inservice Testing at Nuclear Power Plants, and Generic Letter (GL) 89 04, Guidance on Developing acceptable Inservice Testing Programs. While no noncompliances attributable to the statements were identified, the inspectors were concerned that the procedures as written, could result in violations of the Code or of the MY technical specifications. The licensee acknowledged the NRC concern and agreed to review the procedures. Examples of the statements are discussed below:
e Paragraph 2.3.3.b of the IST program description, and procedures 31-2,4, ECCS Routino Testing HPSI Pump and Valve Test, step 2.0 and 3.17.6.6, Inservice Testing of Safeguards Pumps, step 2.3, stated that IST of certain pumps may bt. performed within one week of returning to normal operation.
This is consistent with paragraph 5.4 of OM 6 which states that " Pumps which can only be tested during plant operation shall be tested within one week following plant startup." However, as discussed in NUREG 1482, Guidelines for Inservice Testing At Nuclear Power Plants, and GL 87-09, the technical specification requirement that surveillance activities be performed before entry into an operational mode takes precedence over the Code provision. The inspectors found that the licensee's surveillance procedures could conflict with the requirements of TS 3.0.B, Entry into a Higher Operating Condition.
- Articles IWV 3417(b) and IVW-3523 of the Code state that when corrective action is required as a result of tests made during cold shutdown, the condition shall be corrected before startup. However, in paragraph 3.4.6 of the IST program description, the licensee took exception to the Code requirements: viz. "At Maine Yankee, this will only apply to valves that can only be tested at cold shutdown. For valves than can be tested quarterly at power the plant may return to power and the valve's test frequency increased or the valve repaired and tested as applicable." The inspectors noted that the licensee's position was inconsistent with Article IWV 3416, which requires valves located in inoperable systems, or systems not required to be operable, to be exercised within 30 days prior to return of the system to operable status. The liccnsee did not submit a relief request to the NRC for the exception, e
Paragraph 6.4 of surveillance procedure 3.17.8.2, IST Valve Tests for Work Orders, repeats the statement in Article IWV-3417(b) that providas 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to correct a condition in which a valve fails to exhibit the required change of stem or disk position or exceeds its specified limiting value of full stroke time prior to declaring the valve inoperable. The procedure cautions, however, that this flexibility may not be permitted if an FSAR time limit has been exceeded. The inspectors considered the licensee's position to be contrary to the TS and Position 8 of GL 89-04. As discussed in NUREG 1482, the TS definition of * Operable" does not grant a grace period before declaring a component not capable of performing its specified function inoperable. The licensee's retention of the grace period conflicted with the TS :
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Conclusi na Q
The IST program document and surveillance procedures contained guidance that conflicted with more restrictive technical specification requirements, and NRC positions and interpretations discussed in NUREG 1482 and GL 89 04. The licensee agreed to review the surveillance procedures in light of the inspectors'
observations.
M1.3 Inservice Test Prooram Scope a.
Inspection Scone The inspectors used MY's IST program submittals, the Final Safety Analysis Report (FSAR) and technical specifications, design basis documents, system drawings, and surveillance procedures to verify that the pumps and valves in the selected systems that perform a safety function were included in the IST program, b.
QDservations and Findinas The inspectors identified 41 power-operated, check, and manual valves that fell within the scope staternent of Article IWV 1100 and were not included in the MY IST prograrn. Also, as discussed in Section M3.1 of this report, most of the Code Class 2 and 3 pressure relief valves were not included in the program. Most of the components that were independently identified by the inspectccs had also been identified by the licensee. Some examples found by the inspectors of the excluded valves are discussed below:
e Normally closed manual valves HSI 331 and HS!-332 are described in the FSAR as being operated by means of reach rods located in the Emergency Feedwater pump room during the hot leg recirculation phase of a loss of coolant eccident. In addition, valves HSI 41 and HSI-42 are throttled during the recirculation phase.
- Normally closed manual valves EFW 23, EFW-24, and EFW-25 are Code Class 3 boundary valves that isolate the EFW/AFW systems from nonsafety-related piping leading to the first-point feedwater heaters. The valves are opened, and valves EFW 17, EFW-20. and EFW 316 are closed, to align the EFW/AFW pumps to the feedwater heatecs in the even' of an EFW pump manifold rupture during operation in the hot standby condition. This safety function is described in Section 10.2,3 of the FSAR, and in an NRC Safety Evaluation Report dated March 18,1983, that approved MY's return to normal operation following a main feedwater line break event.
- Valves EFW 115, EFW-215, and EFW-315 are check valves in the main feedwater line inside the primary containment. The check valves were installed per Engineering Design Change Request (EDCR) 86-44) to foreclose the possibility of water hammer damage to (and potential rupture of) the main feedwater piping as described in NRC Information Notice 86-01, Failure
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of Main Feedwater Check Valves Causes Loss of Feedwater System l
Integrity.
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e Manual v6lves EFW 3, EFW 307 EFW 42, EFW 315 are used to align EFW
pumps P 25A and P 25C to the primary water storage tank (PWST) and to
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Isolate _the normal supply from the demineralized water storage tank fDWST)
)
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In the event of a main steamline pipe break in the main steam valve house
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that ruptures the eight inch common AFW/EFW pump suction line from the
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DWST.
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F e
Manual valve EFW 5 cross connects the EFW system with the diesel driven l
fire pump. This alignment is needed to attain cold shutdown per 10 CFR 50, i
Appendix R.
l e
- Normally open manualisolation valve CH 109 is closed to vthe in a flow l
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restricting orifice in the charging system. This function is required by TS 3.4.D to provida reactor coolant system low temperature overpressure protection from inadvertent HPSI pump injection, and is descriNd in
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Section 4.2.5.4 of the FSAR.
The inspectors noted that the licensee recently had completed a comprehensive, preliminary review of the IST program in response to NRC findings documented in inspection Report 50 309/9616 and reported by the licensee in Licensee Event Report (LER) 96 28. In all, the licensee identified several components in each of the
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safety related systems at Maine Yankee that were not included within the scope of
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the IST program, or if included, were not tested adequately. The licensee was preparing an additional LER to document its finding in accordance with 10 CFR
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50.73, and was implementing comprehensive corrective actions during the inspection pursuant to the Maine Yankee Restart Readiness Plan. This licensee-identified and corrected violation is being treated as a Non Cited Violation,
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consistent with Section Vll B.1 of the NRC Enforcement Pollev.
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e c.
Conclusions IST program scope problems constituted a violation of 10 CFR 50.55ati), which requir6s inservice testing of ASME Code Class components as defined in Article
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IWV 1100 of the Code.' The licensee had developed and was implementing a comntehensive plan to correct the deficiencies.
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M1.4 S. team Generator Tube / Sleeve Eddy Curr Eymination a.
insoection Scope 173753)
The inspector reviewed procedures and documents related to eddy current (EC)
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examination of steam generator tubing and sleeving. The inspector also reviewed the scope and results of ongoing eddy current inspections and observed EC examination personnel perform calibration checks, data acquisition, data analysis and resolution analysis. -
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b.
Qhavations and Findinas The inspector found the steam generator eddy current analysis procedure to be acceptabic, approved by the EC vendor and licensee personnel, and in accordance with ASME Code and Technical Specification requirements. The EC analysis proceduro provided clear guidance to primary and secondary analysts on requirements for identification and recording of indications. The procedure also delineated clear criteria for the type of indications that require further inspection in order to be appropriately dispositioned. Examination data and documentation were also ;n accordance with the EC analysis procedure and ASME Code.
i EC data acquisition personnel followed appropriate precedures, controlled critical parameters, and performed calibration checks as required. EC analysts (primary, secondary and resolution) performed analysis in accordance with the EC analysis procedure. They properly identified and recorded indications, compared them to procedural acceptance requirements, and where applicable, processed and re-examined the indication. Inspection sotups were in accordance with EC method qualification parameters.
The scope of the EC inspections, with both the bobbin coil and plus point coil probes, exceeded Technical Specification requirements and f actored in industry operating experience. All indications identified with bobbin coil were inspected with the plus point probo for additional characterization of the indication.
To enhance the quality of the oversight of the primary, secondary and resolution analysts, the licenseo required the senior analyst to independently review a sample of indications that were dispositioned by the resolution analyst and a sample of tubes that the primary and secondary analyst determined to have no detectable degradation. The results of the independent review were provided to the applicable
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analysts to improve the overall analysis process.
M1.5 Steam Generator Secondary Side Comnonent Npn Destruci!ye Examination a.
lDingetion Scope (73753)
The inspector reviewed the proceduro, scopo and prol.minary results of the non-destructivo examination (NDE) of steam generator secondary sido components.
These examinations were scheduled based on United States and foreign industry experience and Maine Yankee previous inspection results, b.
Observations and Findinna The procedure used for the visualinspection of the secondary side of the steam generator contained a list of the areas required to be inspected. During this refueling outage, additions were made to that list based on operating experience at other plants.
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At the time of this inspection, the visualinspections were complete on steam generators #1 and #2 ftho two scheduled for inspection this outage). Steam generators #1 and #2 were previously inspected in 1993 and 1982 respectively.
The inspections were performed in areas where degradation was previously identified (to look for growth) and in areas not previously inspected.
The visualinspections identified, in part, that there was some erosion on the outer periphery of the #8 partial eggerate, and some cracking of the #7 and #9 partial drilled support plate. In all cases, the erosion and cracking did not extend more than one or two tubes into the tube bundle. The licensee determined that there was no change in the indications that were identified during the previous inspection. The licensee submitted the inspection results to an engineering contractor to evaluate the effect on operation and corrective actions, if required.
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c.
Conclusion.1 The inspector found the steam generator tube inspection program and procedures to be good. In addition, the personnel managing and implementing the program were knowledgeable and followed procedures. The licensee made the decision to perform additional steam generator secondary sido inspections based on industry operating experience.
M3 Maintenance Procedures and Documentation M3.1 Testina of Safetv/ Relief Valves a.
losnection Scona The IST program invoked OM 1 1981 requirements for testing safety / relief valves.
The inspectors reviewed licensee and vendor procedures against the scope, test methodology, and corrective action requirements contained in OM-1. The inspectors also evaluated the licensee's internal responses to recent NHC Information Notices concerning safety-related relief valves.
b.
Observations and Findinna The licensee categorized pressurizer Power Operated Relief Valves (PORV) PR S 14 and PR S 15 as Category C valves in its IST program, and tested the valves in accordance with Article IVW 3512 and Section 7.3.1.2 of OM 1. The tests involved a visual examination, seat tightness determination, determination of operability of pressure sensing and valve actuation equipment, and verification of the operation and electrical characteristics of the valve position indicators.
Calibration of the pressure sensor and verification of solenoid operated pilot valve actuation was performed per TS Table 4.13, and valve position indication was verified once per cycle during plant shutdown.
The licensee's program did not call for periodically exercising the PORVs as Category B valves per Article IWV 3410. Information Notice (IN) 89-32, Surveillance Testing of Low Temperature Overpressure Protection (LTOP) Systems, reported that some licensee's did not translate the PORV strol:e times assumed in
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17 their LTOP analyses into IST surveillance requirements. The inspectors reviewed the licensee's internal response to the Notica, in Operational Assessment Action
I Request No. 02 02 04, dated April 28,1989, the licensee concluded that the
PORVs were exempt from the stroke time requirements of the Code per Article
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j IWV 1200(b), which exempts external control and protection systems. Operational Assessment Action Request 02 02 03, dated January 12,1989, stated that the
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exercise requirement of Article IWV 3400 was met by the 18 month manual
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actuation of PORV control circuitry during performed during plant shutdown per
procedure OP 17, Plant Cooldown. Also, as a "f ast acting" valve, stroke time
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testing was not considered to be necessary. The inspectors found she licensee's position to be incorrect technically, because the 18 month test actuated only the PORV pilot valve, rather than the main disk. Section 4.4.1 of NUREG 1482 states
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that PORVs are considered to be Category B valves and must be exercised in c
accordance with Article IWV 3410 at least once per operating cycle,
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in March 1995, valve PR S 14 was tested at Wyle Laboratories using Wyle Test Procedure 1011, Test Procedure for Operability and Leakage Testing of Dresser
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Pilot Operated Relief Valves. The inspectors reviewed the procedure and the test results docurnented in Test Report No. 44617 0, dated May 9,1995. Step 6.1.4.3 of the procedure required valve response time to be measured and recorded, and the response time was recorded as 70 milliseconds at 2385 pounds per square inch gage (psig). This sat!sfisc' the 1.0 second response time assumed in the licensee's LTOP analysis. The licensee stated that it would modify the IST program and add the response time test to future purchase orders to ensure that stroke timing was performed.
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a The inspectors reviewed Wyle Laboatories Procedure No.1028, Testing of Model 31700 Safety Valves at Elevated Temperature, and Test Reports for the
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pressurizer Code safety valves, and Crosby Valve and Gage Company procedures and test reports for the steam generator Code stfety valves. The procedures and -
test reports conformed in all major respects with the requirements of OM 1 1981.
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The licensee properly evaluated system operability when "as found" tests f ailed to meet leakage rate or setpoint acceptance criteria.
The inspectors noted that the safety valve settings documented in the FSAR were correct, while the settings stated in the TS bases were not. The basis for TS 2.3, RCS Pressure Safety Limit, stated that the pressurizer safety valves were set at 2485 psig and the steam generator safety valves were set at 985 psig, in actuality, pressu;17er valves PR S 12 and PR S 13 are set at 2510 psig and 2535 psig, respectively, and only three of the 18 main steam valves are set at 985 psig.
Residual heat removal system (RHR) LTOP relief valves RH S 25 and RH S 25 were tested using instructions contained o, a preventive maintenance card and in job-specific work orders. The inspector reviewed work orders 9103239 00 and 92-05053. Both valves lifted prematurely (outside of the plus or minus 3% of setpoint permitted by the Code), and valve RH S 24 failed to reseat. The licensee
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performed a failed valve surveillance evaluation for valve RH S 24 that discussed the cause (debris in the valve) of the f ailure and the ability of the valve to have prevented overpressurization of the RHR system. The licensee's evaluation did not consider actions to prevent recurrence, such as more frequent testing and/or i
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maintenance procedure enhancements, or consider the potential consequences of the failure of valve RH S 24 to resent during shutdown cooling. The licensee also did not perform a similar evaluation for valve RH S 25 despite the fact that the licenseo found the valve body full of rust, excessive "neverseize" on the adjusting screw and spring washers, and pipe dope on the disk and guide areas.
As noted in Section M1.3 of this report, except for the steam generator safety and, RHR LTOP relief valves, and six relief valves in the primary component cooling water system, the licensee did not include Code Class 2 and 3 relief valves within the IST prograrn scope. Paragraph 4.1.1 of the IST Program Description limited the program scope to those valves "...which are required to perform a specific function in shutting down a reactor or in mitigating the consequences of an accident." This statement conformed to the 1983 Edition of the Code. However, as discussed in Section 4.3.1 of NUREG 1482, the 1986 Code Edition added to scope Article IWV 1100 the words "...or in providing overpressure protection", as defined in OM 1 1981. Section 1.1 of OM 1 1981 requires "... periodic performance testing and monitoring of pressure relief devices utilized in nuclear power plant systems which are required to perform a specific function in shutting down the reactor or in mitigating the consequences of an accident." Thus, relief valves that protect safety Code class safety systems were added to the program by the new Code Edition, The inspector attributed the licensee's misinterpretation of the scope statement to lack of attention to detail and unfamiliarity with NRC guidance in this area.
Though not included in the IST program, the licensee periodically tested and refurbished Class 2 and 3 relief valves under its preventive maintenance program.
The licensee utilized contractor services for this activity, and the plant operations review committee reviewed and approved the contractors' procedures. The inspector reviewed Newport News Industrial procedure SI FP 9, Repair of ASME Section I, Section Vil Division 1, and Non Code Pressure Relief Valves, SEVCO Quality Control Manual for Repair of National Board Certified Pressure Relief Valves, and licensee work orders for 12 relief valves in the AFW/EFW, HPSI, LPSI, containment spray and emergency diesel generator air start systems. While technically acceptable and conforming generally with the intent of OM 1, the procedures and work orders lacked the specificity needed to ensure literal compliance with the provisions of OM 1 concerning temperature stabilization, hold times, alternate media correlations, number of consecutive lif ts, leakage test pressures, and corrective action, in the aggregate, the deficiencies could have affected the pressure eettings and leak tightness of the valves. However, the inspectors did not consider that the differences significant enough to challenge the current functionality of the valves. During the inspection the licensee withdrew the contractor procedures pending revisions to incorporate the specific OM 1 requirements.
The inspactors reviewed the licensee's responses to IN 96-02, Inoperability of Power-Opuated Relief Valves Masked By Downstream Indications During Testing, and IN 90-03, Main Steam Safety Valve Setpoint Variation As A Result Of Thermal Effects. Both ins discussed problems with valves identical to those at MY. The licensee recognized the importance of establishing proper ambient conditions during
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I testing of the main steam and pressurizer relief valves, and placed the appropriate ambient temperature requirements in vendor purchase orders. Regarding IN 90 02, i
licensee personnel contacted the licensee involved and verified that the problems discussed in the IN did not apply at MY. The inspector discussed this issue with
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the IST coordinator and agreed with the licensee's assessment.
c.
Conclusions l
Misinterpretation of ASME Code scope requirements resulted in excluding most Class 2 and 3 relief valves from the IST program. While preventive maintenance practices did not conform to explicit Code requirements in all respects, there was reasonable assurance of current relief valve functionality. The licensee agreed to
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evaluate the need to add the relief valves to the IST program, and to review its procedures for conformance with OM 1. Also, the licensee was responsive to industry experience documented in NRC Information Notices.
M3.2 Pumn Testina a.
insnection Scone The inspectors reviewed surveillance procedures and performance records against OM 0 requirements for test periodicity, quantities measured, and allowable ranges.
The review included pumps in the high and low pressure safety injection, containment spray, service water, and emergency feedwater systems, b.
Qhservations and Findinas in most cases, quarterly inservice pump tests were conducted through minimum flow recirculation lines. The licensee supplemented these tests each refueling outage with full flow tests. Reference flow rate values were specified in procedure 317 0.6, inservice Testing of Safeguards Pumps, and the flow rates were set
...as close to the reference flow as possible." The containment spray pump
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minimum recirculation flow rate was fixed, and service water pump flow depended on system loads, and was not adjusted. The Alert and Required Action Ranges specified in Table 3b of OM-0 were established in the surveillance procedures.
The inspectors noted that the reference value ranges specified in the licensee's surveillance procedures also corresponded to the acceptance ranges contained in Table 3b. Section 4.3 of OM-6 requires reference values to be established at points of operation that are "readily dupliceted during subsequent tests. Section 5.2(b)
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requires that the resistance of the system shall be varied until the flow rate equals the reference value. As discussed in Sectiori 5.3 of NUREG 1482, the Code does not consider the possibi!hy that flow rate or differential pressure may not be controllable to an exact referenca value. However, the Code does not intend that the reference va'ue have an acceptance range as stated in Table 3b. The NRC's guidelines and recommendations (in Section 5.3 of NUREG 1482) to ensure consistent and repeatable test results, are that a total tolerance of plus or minus two percent of the reference value, including instrument accuracy and precision, is
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permitted without approval from the NRC. The inspectnrs did not identify any tests in which actual reference values exceed 9d the allowable four percent band.
The inspectors identified problems involving pump vibration testing. Paragraphs 4.3 and 4.4 of OM 6 require that reference values be established during preservice testing, af ter the first inservice test, or when maintenance may effect existing pump reference values. The inspectors found that a substantial majority of the vibration reference values contained in MY's pump surveillance procedures exceeded values that would be based on actual vibration data. The licensee was unable to document the bases for the vibration reference values established in its procedures. The inspectors noted that the current reference values could result in nonconservative alert and required action range limits because the multipliers could not be traced back to reference values established in accordance with Code requirements. For example, the inspectors reviewed technical evaluation TE 206-92 that documented the establishment of new hydraulic reference values following a roajor refurbishment of service water pump P 29D on April 8,1992. The licensee i
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was unable to provide documentation that new vibration reference values were
established or that the old reference values were re verified following the
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maintenance. This is a violation of paragraph 4.4 of OM-6. (VIO 50 309/97 05-03)
i Table 3a of OM-6 requires that pump vibration alert criteria be established within a range of greater than (>) 2.5Vr to 6.0Vr (where Vr is the vibration reference value
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for a specific bearing and direction; e.g. inboard horizontal) or >0.325 inches per second (ips). The required action range limit is specified at either > 6.0Vr or 0.70 ips. The more conservative of the Code requirements must be applied when establishing the alert and required action range limits for pump testing. However, the licensee established the alert range and required action ranges at the maximum limits of >0.325 ips and 0.70 ips, respectively, without regard to the actual vibration reference values (Vr). This practice was inconsistent with Code requirements, and could have resulted in f ailure to identify and assess degrading pump performance promptly.
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The inspectors noted that correct vibration reference value limits had been established during the previous 10 year IST Interval. The licensee acknowledged that the current reference values limits were less conservative, but stated that the values were consistent with its interpretation of the Code requirements. The inspectors also were informed that the issue had been identified and documented in
- the corrective action program on March 12,1997. However, the licensee only
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prioritized the matter on a routine followup basis, and no procedures were changed or pump operability evaluations were performed. - By the end of the inspection the licensee had not developed a plan to correct the deficiency. The inspectors reviewed the vibration data for several of the pumps currently required to be operable and identified none that were operating in the correct alert or required
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action ranges. Nonetheless, failure to establish appropriate purnp vibration
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- acceptance criteria is a violation of 10 CFR 50, Appendix B, Criterion XI, Test Control, which requires testing to be performed in accordance with test procedures that incorporate the requirements and acceptance limits contained in applicable
- design documents. (VIO 50 309/97-05-04)
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Table 3a of OM 0 establishes an absolute pump vibration alert limit of >0.325 ips.
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The inspectors identified that in June 1996, the licensee implemented a now alert limit for containment spray pump P 01S that exceeded the Code limit. The inspectors established that the licensee had not been aware that NRC approval was required prior to implementing the new limit. The licensee's implementation of a vibration limit in excess of that permitted by the Code was the first of two examples of a violation of 10 CFR 50.55a(a)(3), which requires alternatives to Code requirements to be approved by the NRC. (VIO 50 309/97 05 05)
c.
Conclusions Supplemental tests of safety-related pumps under full accident flow conditions during refueling outages were considered to be a program strength. The hydraulic reference specified in surveillance procedures were not consistent with Code requirements, and vibration reference values were not established conservatively.
Violations of Code requirements were identified pertaining to post maintenance verification of vibration reference values, vibration acceptance criteria, and implementation of an alternative test limit without obtaining NRC approval.
M3.3 Valve Testina a.
Insnection Scoco The inspectors reviewed surveillance procedures and test frequencies, methods, and acceptance criteria for several types of valves in the IST program, in addition, the inspectors reviewed the licensee's treatment of reactor coolant system pressure isolation valves, b.
Observations and Findinag Relief Reauest VRR 1 The third 10 year IST program interval (using the 1986 Edition of the Code) started on December 28,1992, in relief request VRR 1, the licensee proposed to establish the fixed reference value method of evaluating valve stroke time specified in the 1989 Edition of the Code (OM 10), in lieu of comparing the previous test value as specified in Article IWV 3417. However, the licensee continued to use the stroke time " alert" limits and corrective action requirements of Atticle IWV 3417 instead of the provisions of OM 10. The inspectors found that the licensee implemented relief request VRR 1 at the beginning of the third program interval and prior to receiving NRC approval. The licensee stated that this action was based on NRC approval of a similar relief request during the previous 10 year interval.
The inspectors noted that previously approve plant specific relief requests expire at the end of an IST program interval, and must be resubmitted and approved in subsequent intervals. The inspectors also observed that the NRC had approved the second interval relief request before OM 10 had been adopted by rulemaking.
Thus, at that time, the NRC concluded that the licensee's proposed alternative was
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superior to existing Code requirements. Through rulemaking on September 8, 1992, the NRC approved the 1989 Edition of the ASME Code, which included OM 10. On June 17,1994, the NRC issued the safety evaluation report (SER) for MY's third 10 year interval program. Pursuant to 10 CFR 50.55a(f)(4)(iv), the NRC approved relief request VRR 1 provided that all of the related stroke time limit, corrective action, and documentation requirements of OM 10 also were implemented. The SER gave the licensee one year or to the end of the next refueling outage to implement those provisions. Notwithstanding, the licensee continued to implement the provisions of VRR 1 after the 1995 refueling outage ended in January 1990. On February 23,1990, the licensee requested the NRC to reconsider its position en VRR 1 on the basis of impracticality per 50.55atf)(5)(iv).
This request was being evaluated by the NRC at the time of the inspection.
10 CFR 50.55a requires IST of components in accordance with the requirements of the Code to the extent practical within the limits of design, geometry, and materials of construction. Where a test requirement is determined by a licensee to be impractical, the basis of the determination must be demonstrated to the satisfaction of the NRC. Because of impracticality, a licenseo may test applicable components by the method proposed in a relief request until an NRC evaluation is completed.
However, compliance with the valve exercise requirements of the 1980 Code Edition was not impractical, and relief request VRR 1 constituted an alternative to those Code requirements. The inspectors concluded that the licensee's implementatic,a of relief request VRR 1 prior to receiving NRC concurrence was the second example of a violation of 10 CFR 50.55ala)(3h (VIO 50 309/97 05 05)
Power Ocerated Valve Exercise Tests The licensoo specified limiting values for full stroke time in IST procedures as required by Article IWV 3413(ah The inspectors reviewed memorandum TAG 92040, Required Stroke Times For Safeguards Valves, cated October 30, 1992, and concluded that the stroke time limits were derived from accident analysis assumptions and technically valid information contained in the FSAR and other design basis documents.
Article IWV 3417(b) of the Code requires corrective action to be initiated immediately if a valve exceeds its specified limiting value of full stroke time, if the condition cannot be corrected, the valve must be declared inoperable, and a retest showing acceptable operation must be performed before returning the valve to service following the required corrective action, in contrast, Section 4.2.1.9(a) of OM 10 requires the valve to be declared inoperable before initiating corrective action. In addition, OM 10 states that valves declared inoperable may be repaired, replaced, or the data may be analyzed to determine the cause of the deviation and the valve shown to be operating acceptably. Valve operability based on analysis must have the results of the analysis recorded in the record of tests.
Paragraph 6.4.1 of MY procedure 3.17.8.2, IST Valve Tests for Work Orders, stated that if a valve cycles in its inoperable range (i.e. exceeds the limiting value of
' full stroke time), restroke the valve with an auxiliary operator present to verify the
condition. If the condition persists, and the f ailure is positively identified, declare the valve inoperable. Additional guidance was provided in other surveillance procedures. For example, paragraph 6.2.5(b) of procedure 312.3, ECCS Routine Testing Valve Testing and Position Verification, stated that a valve that fails the inoperable criteria may be cycled up to three times, in January 1994, flow control valve EFW 201 exceeded the limiting value of full stroke time, and the valve was deciated inoperable. Following the direction contained in an engineering evaluation, the valve was exercised three additional times, during which it stroked in the " alert" range. The licensee increased the test frequency from quarterly to once per month and declared the valve operable.
During the next three months, the valve stroked within the normal range. However, on the fourth month, it again exceeded the " alert" limit, and monthly exercising was continued. The licensee's corrective action thus was limited to increasing the exercise frequency, and the cause of the deviation was not analyzed or recorded in the record of tests. The inspectors did not consider that the licensee's actions met the intent of Article IWV.3417(b).
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For valves that oxceed reference value limits, Article IWV 3417(a) requires the test frequency to be increased to once each month until corrective action is taken, at which time the original test frequency shall be resumed. Any abnormality or erratic action shall be reported. Paragraph 6.4.1 of procedure 3.17.8.2 directed that the valve be stroked again with an auxiliary operator stationed at the valve, if the condition persists and repairs are not practical, the valve is considered to be acceptable, an engineering evaluation is performed, and corrective action consisting either of repair or retest during the following months is implemented. Additional guidance was contained in sub tier surveillance procedures. For example, paragraph 2.0 of procedure 3120.2, Containment Isolation Valve Testing At Cold Shutdown, stated that if initial measurement is in the alert range, corrective action
such as stroking the valve shall be taken prior to writing a work order. If corrective action has restored the failed parameter then the valve may be retested. Paragraph 4.4 of procedure 312.3, ECCS Routine Testing Valve Testing and Position Verification, stated that valves that stroke in the alert range are still operable, but the surveillance frequency must be increased from quarterly to monthly.
The inspectors reviewed test data from previous operating cycles to assess the licensee's implementation of corrective actions for valve performance problems:
Valve LM A 55 exceeded the reference value limit in July 1994 during performance of procedure 3120.1, Containment Isolation Valve Testing At Power. The licensee increased the test frequency to monthly, and the reference value limit continued to be exceeded for the next two months.
During the subsequent two months the valve stroked within the normal-range. Following the 1996 refueling outage, the valve again stroked acceptably and the test frequency was restored to the normal quarterly periodicity. The licensee did not perform a causal analysis for the three successive failures, or justify the return to the quarterly frequency on a technical basis.
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On January 6,1997, seal water supply valve SL P 3 stroked greater than its j
" alert" limit during performance of procedure 3120.2, Containment
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Isolation Testing At Cold Shutdown. A degraded valve evaluation was
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performed that directed the valve to be stroked three additional times to j
determine if it returned to the normal range. The three strokes were within
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specification, and no work order was initiated to repair the valve. In
memorandum TES 97 011, dated February 17,1997, the licensee noted
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that the valve had a "very erratic" stroke time history, speculated that the cause was stem packing dryout, and concluded that an evaluation was i
needed to decide if further work was required prior to starting up from the i
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current outage, e
Since at least April 1992, charging system valves CH A 32 and CH A 33
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have stroked in and out of the " alert" range during monthly exercise tests.
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For example, valve CH A 33 was exercised 60 times in 44 months,
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exceeding the reference value limit on 42 occasions. Where multiple strokes were performed during a single monthly test, some met the criteria and others did not. On other occasions, retests performed after corrective maintenance f ailed, but the licensee nonetheless considered the valves'
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j performance to be acceptable. Various possible causes, such as varying test
conditions and incorrect reference values, were postulated in engineering memoranda, but no causes for the deviations were identified and no definitive corrective actions were taken.
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The inspectors concluded that the licensee's actions did not violate the literal requirements of Article IWV 3417, but that the practices did not meet the intent of
the Code. The inspectors viewed valve exercising at an increased frequency to be intended to provide reasonable assurance of operability between surveillance
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intervals; and, to ensure that further degradation will be detected and corrected prior to failure. The inspectors also considered that the licensee's provisions for
additional valve exercising during IST could be construed as preconditioning of the
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valves. While the Code does not explicitly require testing in the "as found"
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condition, most IST is performed in a manner that represents the standby condition of a component. As a result, the inspectors found that the licensee's procedures
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and practices appeared to discourage prompt identification and correction of t
potential valve performanco problems.
The inspectors noted that the licensee intended to implement fully the power-i operated valve test provisions of OM 10 by the end of the next refueling outage. In so doing, the practices discussed above would be discontinued.
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Check Valve Testino The inspectors found that the check valves in the selected systems were
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categorized properly _in the licensee's program as Category A or A/C valves. With
- one potential exception, full flow testing of check valves was performed under
- verified accident flow conditions contained h the FSAR or other design documents, and as specified in Position 1 of GL 89 04, Guidance On Developing Acceptable
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Inservice Testing Programs. - Quarterly partial flow tests were followed up during cold shutdowns or refueling outages with full flow tests or disassembly and inspection. The Irispectors noted that the periodic test of containment spray pump casing vent header check valve CS 54 may not be conducted under accident flow conditions. The licensee agreed to evaluated the test and modify the procedure as necessary,,
The licensee tested check valves in the reverse direction primarily through leakage checks. The inspectors found the licensee's procedures and methods to be acceptable. The licensee's grouping of check valves for disassembly and inspection where exercise requirements were impractical to implement rnet the guidance contained in Position 2 of OL 89 04 for group sire, periodicity, and sample expansion. The inspectors verified that partial stroke exercising following re-assembly was performed where possible.
One instance was identified that appeared to precondition the check valves under test. Procedure 3.17.8.6 tested valves EFW 345 and EFW 340 for gross leakage on a quarterly basis. The four inch valves are located in the water treatment makeup line to the DWST, and constitute the Class 3 seismic boundary. The acceptance criteria of the procedure stated that the valves were acceptable if measured leakage was less than five gallons per minute (gpm) at 170 psig. If leakage exceeded that amount, acceptable performance could be demonstrated by less than five gptn leakage at 15 psig. Since the normal back pressure on the valves due to the static head of the DWST is approximately 15 psig, the inspectors questioned the basis of the 170 psig test. The licensee explained that the initial source of test pressure source is the discharge of the primary makeup pumps, agreed that the lineup did not simulate normal condiflons at the valves, and stated that the procedure would be revised.
Solenold Onerated Valve Ppsition Indication Verificatl9.D Article IWV 3300 requires that valves with remote position indicators shall be observed at least once every two years to verify that valve operation is adequately indicated. Positive verification of remote valvo position indicators is important since they are used during periodic volve exerciso tests to assess valve performance.
Solenold operated charging pump suction vent valves CH 119 S, CH 120 S, CH-121 S, and CH 122 S are normally open and have a safety function to close on receipt of a safety injection actuation signal. The valves were exercised on a quarterly basis per procedure 3120.3, IST Valve Testlog at Power by operating switches on the engineered safeguards feature panels in the control room and observing individual valve position indicating lamps at a local electrical panel. The inspectors found that the valves were not included in procedure 3.1.7, Valve Position Indicator Check, and that the licensee did not verify the accuracy of the position indicators. The inspectors also learned that the licensee recently had identified the condition during its review of the IST program, and that the position indicator verifications would be added to the surveillance procedure. This licensee-identified and corrected violation is being treated as a Non Cited Violation consistent with Section Vll.B.1 of the NRC Enforcement Polie _ _ _ _ _. _
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l Reactor Coolant Pressgtg isolation Valve Testino l
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i The operational and functional requirements of the pressure isolation valves at MY
i-are contained in Technical Specifications (TS) 3.19.A.4 and 4.6.A.2.f. The TS
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imposes maximum leakage rate limits on the check valves located between the
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reactor coolant system and the low pressure safety injection system in order to
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ensure that the leakage rate will not exceed the pressure relief capacity of the LPSI i
relief valves. Overpressurization and rupture of LPSI system piping would result in
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a loss of coolant accident outside of the primary containment.
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The pressure isolation valves were classified properly in the IST program as
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Category A/C valves, and leakage rates were tested every two years in accordance
with Article IWV 3420. Inboard check valve pairs HSI 17(27,37) and HSI 61(62,
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63) are tested using procedure 3.17.3.2, LPSI Penetration Testing, Barrier "a", and-
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outboard check valves LSI 21(22,23) are tested by procedure 3.17.3.1, LPSI
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Penetration Testing, Barrier "b". Procedure 3.17.3.1 used a hydiostatic test pump to pressurire the check valves to 745 to 2235 pounds per square inch (differential),
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and valve leakage was measured with an ultrasonic instrument. For applied pressure less than the maximum functional differential pressure (2235 psid), the measured leakage rate was adjusted by the ratio of the maximum functional
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differential pressure to the test differential pressure. This method is technically
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incorrect and does satisfy Article IWV 3423(e), which requires measured leakage to
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be adjusted by the square root of the differential pressure ratio. Since the licensee's method overestimated valve leakage rates, no adverse safety
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consequences ensued. This failure constitutes a violation of minor significance and
is being treated as a Non Cited Violation consistent with Section IV of the BflQ
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Enforcement Poliev.
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Conclusions
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Several concerns involving weak performance were observed. Implementation of an alternative method of testing power operated valves prior to obtaining NRC approval was identified as a violation of 10 CFR 50.55a, which was a second
example of this type of violation during this inspection. Corrective actions for
valvet that did not meet stroke time reference value limits complied with literal
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requirements, but did not adequately address causes; and, did not meet the intent
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of the Code. =IST of check valves and verification of remote valve position indicators generally were acceptable. The method of adjusting measured primary isolation valve leakage rate for less than optimal test pressure was technically
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incorrect, but produced acceptably conservative results.
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M4 Maintenance Staff Knowledge and Performance
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M4.1 Diese,I Generator Systems Testina a.
Insoection Scoce (61726)
On May 16,1997, emergency diesel generator (EDG) 1B was declared inoperable based on a supervisors review of a previously completed test procedure. The inspector reviewed the circumstances surrounding the event and observed the performance of testing, b.
Observations and Findinas On May 15,1997, the Diesel Generator Redundant Systems Check and Diesel Overspeed Trip Test,61781, was performed for EDG 18. The procedure is normally performed every six months and was also being performed as part of
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restoring EDG 1B following the system outage window. At the completion of testing the test was declared satisfactory and EDG 1B was returned to operable by
operations.
The following day the electrical maintenance supervisor was performing a supervisory review of the completed test and identified a potential deficiency.
Operations was informed and the diesel was declared inoperable pending further testing. At this time the other EDG remained operable for technical specification
power requirements.
Part of the test used a multi channel strip chart recorder to time the sequence of the air start motors and governor booster pumps. During the supervisor's review of the strip chart, he noted that one of the governor booster pumps did not start as required.
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Electrical maintenance re-performed the test and the equipment functioned normally. Further investigation by Malne Yankee determined that the previous crew experienced difficulties with the cht.rt recorder and used an alternate method of volt meters to verify the function. The test procedure gave an option as to the method to be used and did not require documentation of the method. The EDG was subsequently declared operable.
As a result of the confusion caused by the lack of procedural documentation, the electrical supervisor was revising the procedure to require the use of the strip chart recorder for future testing. Briefing of electrical maintenance personnel on the expected standards of documentation was also conducted.
During the observance of the test, the inspector noted a test switch which was l
called out by the procedure as "27Y portable test device". The test device was used by.the electricians, however there was no marking or label to designate the switch as the 27Y device. The switch was simply a double pole single throw switch with four leads mounted in an electrical box. Af ter following up with the-
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supervisor as to the origin of the test device the inspector was told that the device was field built anJ maintained without any procedure or documentation.
The electrical supervisor explained that the test switch name had recently been added to the procedure as an improvement. The supervis,or was including a drawing of the test device in the procadure and labeling the test device as future improvements.
c.
Conclusions The inspector concluded that the electrical supervisor displayed excellent technical knowledge and a good safety perspective in both finding the discrepancy, and in recommending to operations that the EDG be declared inoperable. The response to weaknesses in documentation of the test difficulties during the May 15th test were considered appropriate.
M8 Miscellaneous Maintenance issues (92902)
M8.1 (Closed) Unresolved item 50 309/96 16 06. Adeauncv of the IST oroaram.
=!n responso to an NRC finding that check valves were not being tested properly, the licensee undortook an in-depth review of program scope and test methodologies that identified additional deficiencies. MY evaluations PED RC 97 03 and PED RC-97-04 documented the root causes of the discrepancies, including: (1) lack of effective management oversight, (2) inadequate training in Codes and Standards, (3) non participation in NRC and industry forums regarding IST, and (3) Inattention to detail. The findings discussed in this report confirmed the licensee's conclusions.
As part of the Restart Readiness Plan, the licensee completed an extent of condition review of IST program scope and tcst methods, and began creating a comprehensive basis document for each Code Class component. Outside experts were hired to assist in this effort. The licensee also planned to develop and provide training to all personnelinvolved in IST, and to hire additional personnel experienced in industry codes and IST.
The inrpectors concluded that the licensee adequately addressed the concerns associated with this item. Additional licensee corrective actions for the noncompliances and IST program discrepancies identified during this inspection will be tracked under the items opened in this report.
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t til. Enaineerina i
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E1 Conduct of Engineering j
E1.1 General Comments (37551)
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Engineering personnel provided good support to plant activities. Ongoing projects, such as steam generator eddy current testing, fire penetration seals upgrade, and development and implementation of major modificat!ons, were well controlled and implemented.
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E2 Engineering Support of Facilities and Equipment E2.1 Enaineer!na System Assessments
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a, Insoection Scone (71707. 375511 The inspector perfortned a detailed review of the Plant Readiness Assessments being performed by Maine Yankee as outlined in the Restart Readiness Plan.
b.
-Observations and Findinas
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The Maine Yankee Restart Readiness Plan outlined expectations for the conduct of l
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system readiness assessments. To implement these assessments, Maine Yb.ikee i
established a system enginn.ing department which was staffed with half Maine Yankee engineers and half contract engineers. Although the group was new, the
- group had considerable experience both within Maine Yankee and with other
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utilities.
Procedure 17 239, System Engineers Guide, was developed to provide details for the performance of the system assessments. The assessments included reviewing
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open items, understanding the scope of planned and differed work, and performing system walkdowns.
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The inspector accompanied two of the system engineers during their plant walkdowns. The systems performed were residual heat removal (RHR), low pressure safety injection (LPSI) and safe shutdown. The walkdowns were a field verification of the material condition of the systems. However, the walkdowns
'
were not a detailed comparison of the design to the field configuration. The walkdowns were done in the midst of the outage, therefore work activities were ongoing with the systems. Discrepancies identified were entered into the work control system or learning bank process as appropriate. Maine Yankee planned a
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final system walkdown at the completion of the outage work.
The findings from the walkdowns were a broad spectrum of issues including seismic concerns, environmental qualification issues, insulation, instrumentation concerns, and system operation issues.
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c.
Conclusions
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The development of the system engineering department and implementation of the
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system readiness reviews was a positive effort. The experience level of the system
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- engineers t.ttributed to the quality of the system readiness reviews.
.)
E2.2 Steam Generator Insund!nD
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a, knoection Scorn j
The inspector reviewed the results of steam generator tube inspection activities,
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I b.
Observallons and Findinas At the end of the inspection period, steam generator inspection activities were almost completed.- All tubes were inspected using the Bobbin Coil Probe (BCP), and selected tubes and locations were inspected using the Plus Point Probe (PPP), Out of the approximately 19,168 acquired data points in steam generator l's 5,445 i
tubes, a total of 183 tubes were identified as defective. In S/G 2's 5,491 tubes,
with 15,889 acquired data,130 tubes were identified as degraded. In S/G 3's
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5,493 tubes, with 16,114 acquired data,131 tubes were identified as degraded.
a On May 9,1997, tht licensee notified the NRC, in accordance with 10 CFR 50.72,
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that the total number of defective tubes identified in all three steam generators was l
greater than the Technical Specification 4.10 limit. - As a result of Eddy Current
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Testing, greater than 1% of the select ed sample (165 of 16,429) were defective in
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that the contained imperfections whiro exceeded the plugging limit depth of 40%
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of the normal wall thickness. ThG S required followup action was an expansion of
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the sample size. However, Maine Yankee had already scheduled to inspect 100%
of all three steam generators using the " Bobbin" method.
In s;tu pressure tests at greater than or equal to (>_.) 5,300 lbs (6,000 to 6,500)-
were conducted on a total of 37 tubes in all three steam generators. All tubes were able to withstand pressures above the test pressure except for a tube in S/G 3 that developed a leak at about 3,100 lbs. The tube had a defect (axial crack)
identified in the #1 Egg Crate region at 63% through wall at 1.92 inches. Five
other tubes, although passing the test, leaked above 5,300 lbs.
On May 21,1997, the licensee again notified the NRC, in eccordance with the
requirements of 10 CFR 50.72, of an event found while the reactor was shutdown,
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that had it been found while the reactor was in operation would have resulted in a principal safety barrier being seriously degraded. The event involved the results of Steam Generator #3 in S!tu Hydro Testing determining that one tube would not
, meet Regulatory Guide 1.121 requirements of withstanding three (3) times normal operating differential pressure. The tube failed at 3,100 Psid which was below the
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Reg, Guide 1.121 three times operating pressure differential pressure limit of 5,300 Psid.,
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Following the eddy current inspections, various lengths of three tubes were pulled from S/G 2 for metallurgical analysis of the detected flaws. All pulled sections included the sleeved regions. The results of the analysis were not available at the end of this inspection.
Following the inspections, the holes from the pulled tubes and the tubes ruptured during testing were plugged and the secondary side of the steam generators were placed in wet layup. The tubes with indications that require repair prior to operation were left as is pending decisions on future plant operation. Resolution of the steam generator tube integrity is an item in the NRC Restart Action Plan, c.
Conclusion The project was managed safely by technically competent individuals. The approach taken regarding inspection scope and expansions, in situ testing and tube
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pulls reflected sound engineering judgement indicative of an excellent safety focus.
The number of degraded tubes identified was not substantial enough to raise any concerns with the Reactor Coolant system flow.
j IV. Plant Suppntt S1 Conduct of Security and Safeguards Activities S 1.1 General Comments 171750)
Security personnel demonstrated a good questioning attitude when a security officer identified that a required fire round was not being conducted well.
F2 Status of Fire Protection Facilities and Equipment F2.1 Fire Protection Penetration Seals Prolect (Uodate URI 50-309/96-08 05) (Closed URI 50 300/95 15-02)
a.
leapaction Scone (717501 The inspector reviewed activities associated with the Fire Protection Barrier Seal Project. The reviews included discussion with project personnel, review of personnel training, and observation of work activities, b.
Qhservations and Findinag The project was managed by technically competent individuals. Repair efforts were coordinated well with plant personnel. A scope of repairs required prior to plant startup was laid out as follows: Maine Control Room Envelope (ensuring that Maine Control Room can be maintained under a positive pressure and prevent intrusion of carbon dioxide from the cable vault system); High Energy Line Break Seals; Inside Containment Penetration Room; and the Cable Vault. The total repair effort
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represents approximately 500 of the 2000 fire seats that will be cleaned out,
l inspected and reinstalled.
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The inspector observed installation of elastomer in a penetration in the Reactor MCC Room (WO #97 00869 00, FB Penetration Seals, Rx. MCC Room. Remove
and WO # 97 00869 07, Fire Barrier Fire Suppression, Rx. MCC Room FB Pen #
l FBP 5107). The inspector also observed work activities on penetrations 5123,
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and 5126 in the same area.
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In NRC inspection report 50 309/951E the inspectors documented their reviews of
the fire barrier program and the inadequacies associated with the penetration seals.
I The issue was left unresolved (URI 50 309/95 15 02) pending NRC review and
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acceptability of documented qualification and test reports performed in accordance with ASTM Test E 119 as committed to by the licensee. Following further reviews,
this same item was again identified in NRC inspection Report 50 309/96 08 as
,
i unresolved (URI 50 309/96 08 05). NHC's reviews and determination of further
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actions in this area will be tracked as URI 50 309/96 08 05, therefore item 50-309/95 15 02 is closed, i
Personnel Trainina and Qualificatiort
.
The inspector reviewed training and qualification program for those involved in the
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removal and installation of the Fire Penetration Seals. Training was controlled by i
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Maine Yankee's Fire Protection Lesson Plan, Lesson # FP L 6.1, Fire Barrier
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Penetration Sealing. The Fire Barrier Seal Certification Course included formal classroom and hands on training with followup examination, and field observation.
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The training addressed the proper use of the various types of sealing materials
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being used at Maine Yankee. They were: Dow Corning 3 6548 Silicone RTV Foam,
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Elastomer, Cerofiber (and/or Cerawool), and Caulk. The inspector reviewed
cortification records for some members of the project and verified that they had
<
i been certified in accordance with the approved training program. The training process and contents appeared appropriate. Records were maintained well. The inspector had no concerns in this area.
t c.
Conclusions Maine Yankee's efforts at addressing the Fire Barrier Penetration Seals continued to progress well.
F4 Fire Protection Staff Knowledge and Performance
' F4.1 Falsification of Fire Watch loas (URI 50 309/97 05 07)
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a, inspection Scoos (717501 The inspector reviewed the circumstances surrounding the falsification of fire watch logs by a temporary Maine Yankee _ employee. The individual, who was assigned to conduct fire watches, had signed off on some area logs without actually making the required periodic rounds.
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Observations and Findinas l
On May 28,1997, Maine Yankee security personnel identified that an employee
designated to conduct fire watches in various areas of the plant had not been conducting the watches. This was determined when a security officer advised i
security supervision that the individual had not been seen on rounds for some time.
Reviews of fire watch patrollogs and individual security key card records revealed
,
that at some times, the individual was not actually in some areas contrary to his
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signature in the logs for those areas.
!-
The individualinvolved started working at Maine Yankee on May 9,1997, and following the event was terminated on June 2,1997. The licensee reviewed the
,
computer logs for the individual's entries into the fire watch areas to determine the
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extent of his document falsification. Preliminary investigation revealed that the areas of the plant involved were the AFW Pump area, and the Information Center, i
As immediate corrective actions plant support management instituted a review of
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fire watch records to verify that there were no obvious problems. They also conducted periodic checks of the fire watch areas to verify that personnel were conducting the required watches. The requirements and significance of conducting
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the fire watches was re iterated to allindividuals involved in fire watches. Maine Yankee expanded their scope of reviews to include all personnelinvolved with performing fire watches, in order to determine the extent of this discrepancy.
Another individual was identified with a similar discrepancy.
At the end of this inspection period, Maine Yankee was still reviewing the issue and had not determined the root causes of the problem. The inspector was satisfied
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that the licensee had taken a good approach to deal with the problem. However,
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the NRC's reviews in this matter are still ongoing, therefore, this issue remains open pending completion of that review. (URI 50 309/97 05 06)
c.
Conclusions
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Maine Yankee reacted properly to ensure fire protection safety when it was identified that an individual assigned to perform fire watches had not performed as
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expected and had f alsified fire watch logs to indicate that he had been in the
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various areas as required when he, in fact, had not been. Security personnel showed good awareness and questioning attitude by identifying,this discrepancy.
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V. Manaaement Meetinan X1 Exit Meeting Summary A recent discovery of a licensee operating its f acility in a manner contrary to the UFSAR description highlighted the need for a special focused review that compares plant practices, procedures, and parameters to the UFSAR description. While performing the inspection of the MY IST program, the inspectors reviewed the applicable portions of the
MY FSAR that pertained to the areas inspected, inconsistencies were noted by the L
inspectors between the wording of the FSAR and plant IST practices and procedures.
These are documented in Section M1.3. A conflict between the plant configuration and the TS bases for the pressurizer Code safety valve setpoint was found and is documented
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in Section M3.1.
The preliminary results of an inspection of the Maine Yankee inservice Test Program that was conducted on April 14 25, 1997, were discussed with licensee managers at an exit
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meeting on April 25,1997. The licensee acknowledged the findings presented.
The inspectors presented the inspection results to members of the licensee on June 12, 1997. The licensee acknowledged the findings presented. The inspectors asked the
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licensee whether any material examined during tho inspection should be considered proprietary. No proprietary inforrnation was identified.
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. PARTIAL LIST OF PERSONS CONTACTED l
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i R. Blackmore, Plant Manager i
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G. Leitch, VP, Operations i
R. Fraser, VP, Engineering
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M. Meisner, VP, Nuclear Safety and Regulatory Aff airs-i B. Plummer, Operations Manager
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J Sauger, Maintenance Manager W. Odell. Technical Support Manager i
E Soule, Systems Engineering Manager i
W. Ball, Assistant Manager, Operations Support G. Zinke, Quality Programs Manager
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J. Hebert, Regulatory Affairs Manager
D.:Keuter,' Restart Manager -
10. Baker, Project Manager Entergy
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Other
P Dostle, Maine, Nuclear Safety inspector
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NBA.
J. Colact.'no NRR/MEB J
r INSPECTION PROCEDURES USED IP 37551:
Onsite Engineering
IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP 60705:
Preparation for Refueling IP 60710:
Refueling IP 61726:
Surveillance Observation
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IP 62707:
Maintenance Observation IP 71707; Plant Operations
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IP 71750:
Plant Support IP 73753:
-Inservice inspection IP 73756:.
IST of Pumps and Valves
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IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor i
Facilities IP 92901:
Followup Operations
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IP 92902:-
Followup Maintenance IP 92903:
Followup - Engineering
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. IP 92904:
Followup + Plant Support l
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ITEMS OPENED, CLOSED, AND DISCUSSED ltems Onened:
50 309/97 05 01 VIO Inadequate checkout of SFP crane (TS 3.13) pilor to fuel handling (01.2)
50 309/97 05 02 VIO Inadequate corrective action for SFP Crano/ Bridge interaction with objects (01.2)
50 300/97 05 03 VIO Failure to reestablish pump baseline values IM3.2)
50 309/97 05 04 VIO Test control incorrect acceptance criteria (M3.2)
50 300/97 05 05 VIO Implementation of Code alternative without NRC approval (M3.2 and M3.3)
50 309/97 05 05 URI Falsification of fire watch logs (F4.1)
50 309/97-05 07 URI Criticality monitoring requirements per 10 CFR 70.24 (08.1)
ltems Closed:
50 309/95 15 02 URI Fire barrier penetration seats (F2.1)
50 309/96 10-06 URI Adequacy of IST program (M8.1)
50 309/95 24 01 VIO Tech Specs 3.13.D.3, containment purge and vent valves (M8.2)
50 309/95 24 02 VIO Tech Specs 5.8.2, spill of 800 gallons in spray building (M8.2)
50-309/95 24 03 VIO Tech Specs 5.8.2, refueling mishaps of 1995 (M8.2)
Jtems Discussed;
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50 309/96 08 05 URI Fire penetration seals project (F2.1)
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LIST OF ACRONYMS USED
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ALARA As Lt.w As la Reasonably Achievable ANSI American National Standards Institute
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AOP Abnormal Operating Procedure ASME_
American Society of Mechtenical Engineers i
CFR
. Code of Federal Regulations l
CRO Control Room Operator DWST Domineralized water storage tank
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ECCS Emergency core cooling system (s)
EDCR Engineering design change request EDO Emergency Diesel Generator
EFW Emergency feedwater ESF Engineered Safety Feature
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FSAR Final Safety Analysis Report
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FSAR Final Safety Analysis Report GL Generic Letter
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GPM Gallons per Minute
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HPSI High pressure safety injection
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I IFl Inspection Follow Up Item lFS Inspection Follow Up System IMC Inspection Manual Chapter IN(s)
Information Notice (s)
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IP-Inspection Procedure Ips inches per second i
ISI In-Service inspection -
lST-Inservice Test-JCO Justification for Operations-LER Licensee Event Report
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LP Learning Process LPSI Low pressure safety _ injection
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-LPT=
' Learning Process Team
- LTOP Low temperature overpressure protection
' MYAPS -
Maine Yankee Atomic Power Station MYLP Maine Yarskee Learning Process MYTTS
_ Maine Yankee Task Tracking System NCV'
Non-Cited Violation NOV-Notice of Violation NPSH Net Positive Suction Head
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NRC-Nuclear Regulatory Commission
- NRR-Office of Nuclear Reactor Regulation
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PCCW-Primary Component Cooling Water
~PM Preventative Maintenance t
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PORV(s)
Power operated relief valve (s)
PRA Probability Risk Assessment PRCE Plant Root Cour,e Evaluation PSS Plant Shif t Supervisor PWST Primary water storage tank OA Quality Assurance RCS Reactor Coolant system RHR Residual Heat Removal RMS Radiation Monitoring System RP Radiation Protection RWST Refueling Water Storage Tank SCCW Secondary Component Cooling Water SER Safety Evaluation Report TE Technical Evaluation TS Technical Specification UT Ultrasonic Vr Vibration reference value WO Work Order YNSD Yankee Nuclear Services Department
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