IR 05000338/1996010
| ML20149M586 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 12/02/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20149M576 | List: |
| References | |
| 50-338-96-10, 50-339-96-10, NUDOCS 9612170427 | |
| Download: ML20149M586 (37) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50 338, 50 339 License Nos:
NPF 4, NPF-7 Report Nos:
50 338/96 10, 50 339/96-10 Licensee:
Virginia Electric and Power Company (VEPCO)
Facility:
North Anna Power Station Units 1 & 2 Location:
1022 Haley Drive Mineral, Virginia 23117 Dates:
September 22 through November 2, 1996 Inspectors:
R. McWhorter, Senior Resident Inspector R. Gibbs, Resident Inspector D. Taylor, Resident Inspector D. Jones, Senior Radiation Specialist (Sections R1.2, R1.3, R1.4 and R7.2)
C. Payne, Reactor Engineer (Section 04.1)
E. Testa. Senior Radiation Specialist (Sections R1.1, R2.1, R2.2, R7.1 and R8.1)
Approved by:
G. Belisle, Chief, Reactor Projects Branch 5 Division of Reactor Projects ENCLOSURE 2
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9612170427 961202 PDR ADOCK 05000338 G
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EXECUTIVE SUMMARY North Anna Power Station. Units 1 & 2 NRC Inspection Report Nos. 50 338/96 10, 50 339/96 10 This integrated inspection included aspects of licensee operations engineering, maintenance, and plant support. The report covers a 6 week period of resident ins)ection.
In addition, it includes the results of announced inspections )y three regional specialists.
Operations Daily operations were generally conducted in accordance with regulatory e
requirements and plant procedures (Section 01.1).
Unit 2 startup and generator synchronization operations following
refueling outage were well controlled and conservative.
Procedural adherence, crew communications, and supervisory oversight were effective
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(Section 01.2).
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An unplanned Unit 2 shutdown was required to repair a high pressure
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turbine steam leak. Shutdown, repair and startup activities overall were properly performed with conservative decisions made by management to control unit status.
During reactor shutdown evolutions, operating crew performance fell below the licensee's high standards when the crew was required to respond to more than one problem at a time (Section 01.3).
Unit 1 tripped from full power due to a main generator protective system
failure.
Safety system and operator response to the trip was good.
Station Nuclear Safety and Operating Committee reviews prior to restart were appropriate, and the unit restart was carefully controlled. Crew performance during turbine startup and generator synchronization was exemplary (Section 01.4).
A non-cited violation was identified for a failure to follow procedures
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for system tag outs which resulted in spilling slightly contaminated water onto the ground from the quench spray system (Section 01.5).
The licensee met commitments related to the Unit 2 refueling outage
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(Section 02.1).
Five notifications required by 10 CFR 50.72 were made by the licensee.
- One was subsequently withdrawn (Section 02.2).
Control room activities were adequately controlled by the operators, but
monitoring of plant parameters and crew communications needed improvement (Section 04.1).
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Maintenance Three major maintenance work items required rework during or following
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the Unit 2 refueling outage (Section M1).
A violation with three examples was identified for failure to implement
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Maintenance Rule program requirements for root cause evaluations. A weakness was identified for a failure to update Maintenance Rule performance criteria in a timely manner (Section H2.1).
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A weakness was identified for a lack of understanding by various
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licensee departments concerning Maintenance Rule related programs for controlling on line maintenance for multiple risk important components (Section M2.2).
Two previous violations and two Licensee Event Reports (LERs) were
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closed.
One LER did not clearly state >ossible root causes and corrective actions'for a feedwater chec( valve failure. A non cited violation was identified for an inadequate waste gas decay tank oxygen analyzer surveillance test (Section M8).
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A proposal to remove seismic qualification requirements for containment e
radiation monitors was found to contain an unreviewed safety question.
An alternative course of action was taken to prepare a Justification for Continued Operation to address the problem temporarily (Section E2.1).
One previous violation was closed (Section E8.1).
- Plant Sucoort
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The As Low As Reasonably Achievable (ALARA) program was aggressively
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implemented and was using lessons learned from previous outages and industry experience to reduce station radiation exposure. The ALARA program was considered a program strength (Section R1.1).
The licensee had implemented and maintained an effective program to
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monitor and control liquid and gaseous radioactive effluents. The projected offsite doses resulting from those effluents were well within the limits specified in the Technical Specifications and the Offsite
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Dose Calculation Manual. The licensee's performance regarding the i
reduction of the amounts of activity released and the reduction of the
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radiation doses from those releases was deemed to be a program strength (Section R1.2).
The licensee had complied with the sampling, analytical and reporting
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program requirements, and the radiological environmental monitoring l
program was effectively implemented. The environmental sampling equipment was well maintained. The licensee's overall performance in
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the Environmental Protection Agency cross check arogram demonstrated
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analysis of environmental samples (Sections R1.3 and R7.2).
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i The surveillance requirements for demonstrating operability of the
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l meteorological monitoring instrumentation were met (Section R1'.4).
All effluent and radiation monitors reviewed were found to be
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operational, calibrated and in good material condition. An Inspection
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Follow up Item was opened to review documentation for Health Physics conversion factors (Section R2.1).
The licensee was controlling contaminated and radioactive material very
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well in work areas.
Radiological postings and labels were ap3ropriate j
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for the radiological hazard. Radioactive particles detected )y the licensee indicate storage of anti contamination clothing in clean areas can lead to loss of control of radioactive material. Housekeeping in areas toured by the inspectors was judged acceptable (Section R2.2).
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The licensee's program for identifying and correcting deficiencies or
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weaknesses related to the control of radiation or radioactive material
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was aggressive in identifying, assigning responsibilities and tracking i
i to resolution corrective actions. The requirements of 10 CFR 20.1101(c)
for periodic review of the Radiological Protection Program Content and
Implementation were met by the Nuclear Oversight Audit Report 96 05
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(Section R7.1).
A violation was identified for exceeding 10 CFR 61.56 requirements for e
maximum liquid content in a solid waste shipment. One Unresolved Item
was closed (Section R8.1).
A site vehicle gate was not manned at all times. However, no NRC
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requirements were identified for such manning (Section S1.1).
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Report Details
Summary of Plant Status Unit 1 operated at or near full power until October 24 when the unit tripped from full power due to a fault protection system actuation on the main generator. The unit was returned to commercial service on October 25 and reached full power on October 26. The unit remained at or near full power for the remainder of the inspection period.
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d Unit 2 began the inspection period with the reactor de-fueled for a planned refueling outage.
Fuel on load began on September 22, and was completed on September 26. On October 6, a unit heat up began. The heatup was interrupted
by problems with a Reactor Coolant Pump (RCP) seal, and the unit raturned to
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i cold shutdown on October 7.
On October ll, unit heatup began again, and the a
reactor was started on October 12. The unit returned to commercial service on
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October 13 and returned to full power on October 16. On October 21, the unit was shutdown from full power to repair a steam leak on the high pressure turbine exhaust equalization line. The unit returned to commercial service on October 25 and reached full power on October 26. The unit remained at or near full power for the remainder of the inspection period.
l I. Operations
01 Conduct of Operations
01.1 Daily Plant Status Reviews (71707)
The inspectors conducted frequent control room tours to verify proper staffing, operator attentiveness, and adherence to approved procedures.
The inspectors attended daily plant status meetings to maintain awareness of overall facility operations and reviewed operator logs to verify operational safety and compliance with Technical Specifications (TS).
Instrumentation and safety system lineups were aeriodically
reviewed from control room indications to assess opera)ility.
Frequent plant tours were conducted to observe equipment status and housekeeping.
Deviations Reports (DRs) were reviewed to assure that potential safety concerns were properly reported and resolved. The inspectors found that daily operations were generally conducted in accordance with regulatory requirements and plant procedures.
01.2 Unit 2 Return to Service Followino Refuelina Outaae a.
Inspection Scope (40500. 71707)
On October 12 and 13, the inspectors observed preparations and operations associated with reactor startup and unit synchronization for Unit 2 following refueling activities.
b.
Observations and Findinos The inspectors attended the reactor criticality brief and observed good discussions on management expectations for the evolution.
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particular, there was clear communication between the unit Senior Reactor Operator (SRO) and the Reactor Operator (RO) regarding responsibilities associated with reactivity management. The inspectors observed that all necessary personnel were in attendance and that the brief was effective. The inspectors reviewed the startup and unit
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synchronization procedures and verified that they were properly executed. The inspectors also performed an independent control board
walkdown of safety systems and found no discrepancies.
i The inspectors observed that there were very good three way communications among the operating crew, particularly during more
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complex evolutions such as the transfer of feedwater control to the main feedwater regulating valves and synchronization of the main generator.
Additionally, the inspectors noted that there was effective communication between the balance of plant operator and the R0: each
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informed the other when manipulations were done to change reactivity.
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The inspectors observed that the operating crew composition during the
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startup and synchronization was augmented to consist of the Shift
Supervisor (SS), three SR0s, and three R0s.
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Conclusions i
The inspectors concluded that Unit 2 startup and synchronization operations were well controlled and conservative.
Procedural adherence, crew communications, and supervisory oversight were effective.
01.3 Unit 2 Shutdown for Steam Leak Repair and Startuo
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a.
Insoection Scope (71707)
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On October 21, the inspectors observed an unalanned Unit 2 shutdown to
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repair a steam leak on the high pressure turaine exhaust equalization
line. On October 24 and 25, the inspectors observed preparations and operations associated with unit restart following the shutdown.
b.
Observations and Findinas
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The inspectors observed that although the shutdown was unexpected, the unit power reduction and shutdown were preformed in a controlled manner
and in accordance with normal operating procedures.
Plant operations
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went well until the turbine was removed from service at about 15 percent reactor power. At that point, operators experienced difficulties
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controlling Reactor Coolant System (RCS) temperature at low power
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levels. The temperature control aroblems were due, in part, to distractions from problems with t1e Intermediate Range Nuclear Instruments (IRNIs). Both channels of IRNIs were indicating high relative to the Power Range Nuclear Instruments (PRNIs). This situation caused concern for the operators because there was a risk that the IRNIs
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would not go below their high flux reactor trip setpoints before the reactor trip block signal (P 10: supplied from the PRNIs) automatically cleared. After a) proximately one half hour of difficulties controlling RCS temperature w111e the crew discussed the IRNI problem, the i
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Operations Superintendent directed the shift to continue the shutdown and take the IRNI automatic trip if the block signal did not clear. The
crew then successfully reduced power and the IRNI trip cleared prior to i
the block clearing, as designed.
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The shutdown then continued to the point of inserting a manual reactor i
trip in accordance with procedures.
Following the manual trip, four individual rod position instruments indicated between 10 and 12 steps.
l This required operators to commence emergency boration in accordance
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I with plant abnormal procedures. While dealing with this problem, the inspectors observed that operators were not attentive to the automatic energization of the Source Range Nuclear Instruments (SRNIs). After the SRNIs automatically energized, several minutes passed before the SRNIs were aligned to their chart recorder by the SS. This was the first
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indication that any crew member had noted the SRNI energization.
During the shutdown evolutions, the inspectors observed that the SS
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entered the Operator at the Controls (0ATC) work area repeatedly. The inspectors noted that this was not as desired by Operations Standards for complex evolutions which described the SS's responsibilities for broad oversight and stated that SS entry into the 0ATC work area should i-be kept to a minimum.
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Following unit shutdown, the inspectors observed that the licensee successfully repaired the steam leak and other minor equipment problems.
The inspectors also verified that the licensee completed rod drop time testing following the trip as discussed in NRC Bulletin 96 01, Control
Rod Insertion Problems. These tests also confirmed that the high rod position indications following the trip were due to indication
inaccuracies and not due to actual rod problems.
j The inspectors observed the reactor restart and subsequent power increase to approximately ten percent. No problems were noted during the Unit 2 restart.
l The inspectors noted that the licensee chose to shutdown the reactor rather than leave the reactor at low power with the main steam trip i
valves shut during repairs. Also, the inspectors noted that restart of Unit 2 was delayed several hours until a Unit 1 restart was completed.
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The inspectors found that these actions were appropriate and
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conservative decisions were made to ensure positive operator control
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over the plant at all times.
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Conclusions An unplanned Unit 2 shutdown was required to repair a turbine steam leak. Shutdown and repair activities overall were properly performed with conservative decisions made by management to control unit status.
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During reactor shutdown evolutions, o)erating crew performance fell
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below the licensee's high standards w1en the crew was required to respond to more than one problem at a time.
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01.4 Unit 1 Reactor Trio and Restart a.
Inspection Scooe (71707. 93702)
On October 24, the licensee notified the inspectors concerning a Unit 1 reactor trip from full power. The inspectors reviewed control room conditions and operations following the trip. Additionally, the inspectors attended the licensee's post trip review and reviewed trip data to independently verify that safety system and operator performance was as expected throughout the event.
On October 24 and 25, the inspectors observed preparations and operations associated with unit restart following the trip.
b.
Observations and Findinas The inspectors found that the reactor tripped from full power following a main generator trip. The main generator trip was caused by an actuation of the generator protective system. A review of trip data found that the trip signal was valid, and the inspectors verified that all safety systems performed as designed for plant conditions during the trip.
The inspectors observed the post trip Station Nuclear Safety and 0)erating Committee (SNS0C) meeting which reviewed startup readiness.
T1e SNSOC discussed and dispositioned several equipment problems prior to startup. The tria's cause was corrected by replacing a faulty main generator negative plase sequence relay. Additionally, the licensee corrected other minor problems and completed a weld overlay on the high pressure turbine ecualizing line to prevent problems similar to that which occurred on lnit 2 on October 21 (Section 01.3). The SNS0C also gave attention to the unique fact that both units would be restarted on the same day. The SNSOC reviews included discussions concerning the sequence of events for the dual unit startup. The inspectors also verified that the licensee completed rod drop time testing following the trip as discussed in NRC Bulletin 96-01.
The inspectors observed the pre-brief for reactor startup and noted an appropriate level of sensitivity to reactivity management during xenon burnout and individual responsibilities for startup. The inspectors then observed startup preparations, reactor startup, and power increase to place the unit in commercial service. The inspectors found that the approach to criticality and subsequent increase in power were carefully controlled. Throughout the evolutions, appropriate supervision was present, o)erator manipulations were focused, and communications were formal. W1en starting up the main turbine and synchronizing the main generator, crew communications and command and control were noted to be exem)lary. Although the level of operations and maintenance activities in t1e control room was high because of the dual unit startup, the inspectors found that the activity did not have a significant impact on the startu. _ - _.
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Conclusions The inspectors concluded that safety system and operator response to the
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Unit 1 reactor tri) was good.
SNSOC reviews prior to restart were
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appropriate, and t1e unit restart was carefully controlled. Crew performance during main turbine startuo and main generator synchronization was exemplary.
01.5 Quench Soray (0S) System Tao out Error i
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Insoection Scope (71707)
The inspectors reviewed an event occurring on September 17 when a) proximately 25 gallons of slightly contaminated water drained out of t1e QS system onto the ground when tne system was opened for maintenance.
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Observations and Findinas The event was identified by the licensee and documented in DR N 96-1918.
The inspectors reviewed the DR, the DR response, and discussed the event with Operations managers. The inspectors found that the water was
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s)illed when valve 2-QS 28 was disassembled by maintenance technicians.
T1e maintenance activity had been authorized by operators who had earlier completed tagging the system for maintenance. On September 16, operators were directed to drain the QS system for maintenance on various components including 2 0S 28. The draining evolution was completed, and boundary tags were hung prior to releasing the system for maintenance.
The draining evolution required manipulation of several valves and the use of various hoses to ensure that water from the system l
was properly captured and routed to the radioactive drain system. The status of the system drain valves was controlled by the tag-out sheet as
"N" (positioned, but not tagged) items. One system drain valve, j
2 0S 119, was listed as an "N" item and was to be left open, but not
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tagged. After the water was released when 2-QS 28 was disassembled, i
operators investigated the system lineup and found that valve 2 0S 119 was shut. When 2-QS 119 was opened, a large quantity of water was
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drained from the system indicating that the system had probably not been fully drained before the valve was shut.
The licensee continued to investigate the event and found that valve 2 0S-119 was correctly listed on the tag out record which required the valve to be left open after the draining evolution and to be independently verified as open. Both the initial positioning block and Independent Verification (IV) blocks were signed by operators to indicate that the valve was open. During subsequent interviews, the operators stated that they believed that they had correctly positioned and performed an IV for the valve. However, based on finding the valve shut and water in the system, the licensee concluded that the operators had erred and left the valve in the incorrect position. Action was taken in accordance with the licensee's disciplinary programs.
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TS 6.8.1 required the licensee to establish and implement procedures including, by reference to NRC Regulatory Guide 1.33, Quality Assurance Program Requirements (Operations), procedures governing equipment control (e.g., locking and tagging). The licensee implemented this requirement in part by 0 PAP 0010, Tag outs, Revision 6.
Procedure OPAP 0010, Section 6.4.4, required that operators performing tag-outs align and verify the alignment of components listed on the tagging record. Contrary to this requirement, on September 16, operators did not correctly align or verify the alignment of valve 2 0S 119 in accordance with a tagging record. This is the first example of a violation for a failure to follow procedures for system tag outs. This licensee identified and corrected violation is being treated as an Non Cited Violation (NCV), consistent with Section VII.B.1 of the NRC Enforcement Policy (50 338, 339/96010-01).
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Conclusions A non cited violation was identified for a failure to follow procedures for system tag outs which resulted in spilling slightly contaminated water onto the ground from the QS system.
Operational Status of Facilities and Equipment 02.1 Outaae related Commitment Review (71707)
Prior to startup following the Unit 2 refueling outage, the inspectors verified that licensee commitments made for outage related activities were completed.
During the previous inspection period, the inspectors verified that licensee commitments related to NRC Bulletin 96 01 were completed (NRC Inspection Report Nos. 50 338, 339/96 09). During this inspection period, the inspectors verified that the licensee completed corrective actions for violations concerning containment blowout panels (Section E8.1), a Motor operated Valve (MOV) overthrust 3roblem (Section M8.1), and RCS flow instrumentation support pro)lems (Section H8.2). Additionally, the inspectors verified that the licensee completed modifications on the Unit 2 turbine-driven auxiliary feedwater pump governor valve linkage and stem. The inspectors concluded that the licensee met commitments related to the Unit 2 refueling outage.
02.2 NRC Notifications a.
Insoection Scope (71707)
The inspectors reviewed the following licensee notifications to the NRC to ascertain if the required reports were adequate, timely and proper for the events.
b.
Observations and Findinas On September 26, the NRC was notified as required by 10 CFR 50.72 concerning the identification of a condition which could have arevented the fulfillment of the safety function of a system needed to slut down
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During seismic design basis reviews, licensee's engineers identified that a component cooling waster surge tank was not seismically qualified when the tank level was above 75 percent. The inspectors found that the licensee's reporting actions were appropriate.
The inspectors will review the issue further after LER issuance.
On September 27, the NRC was notified concerning an engineered safety feature actuation. The actuation was an automatic Unit 2 containment purge and exhaust isolation initiated from a high high radiation signal on the manipulator crane Radiation Monitor (RM). The actuation signal occurred during the reactor head set following refueling as the head swung close to the radiation monitor. After further review, the licensee concluded that this notification was not required by 10 CFR 50.72 and retracted it on October 15. The inspectors reviewed the licensee's reporting actions and found that they were appropriate.
On October 3, the NRC was notified as required by 10 CFR 50.72 concerning the identification of a condition which could have arevented the fulfillment of.the safety function of a system needed to slut down the reactor and mitigate the consequences of an accident. During investigations of a charging pump trip, licensee's engineers identified that a single failure on an opposite train could render the swing charging pump inoperable. The inspectors found that the licensee's i
reporting actions were appropriate. The inspectors will review the issue further after LER issuance.
On October 16, the NRC was notified as required by 10 CFR 50.72 concerning a loss of emergency assessment capability lasting greater than one hour. At 11:35 p.m. on October 15 a portion of the Unit 2
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Safety Parameter Display System (SPDS) failed and could not be restored within one hour. Maintenance personnel successfully returned the SPDS computer to operation at 11:45 a.m. on October 16. The inspectors monitored the licensee's corrective actions and found them to be appropriate.
On October 24, the NRC was notified as required by 10 CFR 50.72 concerning reactor protection system and engineered safety feature actuations generated when Unit 1 tripped from full power. The inspectors found that the licensee's reporting actions were appropriate.
Additional inspection activities and findings are discussed in Section 01.4.
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Conclusions Five notifications required by 10 CFR 50.72 were made by the licensee.
One was subsequently retracte.
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Operator Knowledge and Performance 04.1 Observation of Operator Performan_ce a.
Inspection ScoDe (71707)
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During the period October 28 November 1, 1996, the inspectors reviewed and observed operators conducting activities in the main control room and in the plant.
Specific areas of review included Operations administrative procedures, shift turnover activities, licensed operator response to normal and abnormal plant conditions, operator attentiveness to plant status, communications, and command and control of shift operations.
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b.
Observations and Findinas The inspectors observed three shift turnover meetings in the Operations Annex and three in the main control room.
In general, these meetings were in compliance with operations administrative procedure OPAP 0005, Shift Relief and Turnover, Revision 4, and operations standard OPS 046 Turnovers and Shift Briefs, dated August 30, 1996. The inspectors noted that two of the annex meetings were interrupted by personnel entering the area contrary to the posted " quiet" hours on the door. The inspectors also noted that two control room briefings were similarly interru)ted.
One of the three turnover meetings began 15 minutes late while t1e SS checked the status of Service Water (SW) piping modifications. This contributed to one of the control room interruptions, but not to any of the others.
The inspectors observed the activities of four different crews of operators over parts of seven shifts. The inspectors noted that the R0s regularly sat with their backs to the control panels while performing paperwork.
More recently licensed operators would scan their panels more frequently during this time than other operators. For example, one Unit 2 R0 sat turned from his panels for eight minutes before checking on the status of the plant.
In contrast, the companion Unit 1 R0 scanned his panels about every two minutes.
No adverse conditions were observed as a consequence of this practice. However, early trend determination of important plant parameters, as specified in OPAP-0006, Shift Operating Practices, Revision 2, was defeated unless operators closely monitored their indications.
The inspectors observed operator response to control room annunciators and found that the operators routinely announced both expected and unexpected alarms to the Unit SR0 as well as checked the Annunciator Procedure for potential causes and actions to be taken. These actions complied with operations standard OPS 034, Communication of Annunciators and Annunciator Response (AR) Usage, dated July 19, 1996.
However, during a response on Unit 2 to annunciator J-F2, " Containment Partial Pressure (+0.1 psi)." the inspectors questioned the actions taken by the operators. These actions involved increasing the alarm setpoint until
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the annunciator cleared. Both the Unit SR0 and the operator agreed that the response procedure did not specify the action that they had taken.
Each contended that the procedure was deficient in this respect and indicated they would submit a procedure change request to correct the error.
l The inspectors observed back panel operator and crew response to a failure of radiation monitor 1 VG RM-104 on Unit 1.
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was prompt and adequate. After shift relief, the inspectors questioned the relief Unit SR0 regarding the applicability of TSs for this situation. The operator demonstrated unfamiliarity with the TS in question (TS 3.3.3) and eventually made the incorrect determination that a TS Limiting Condition for Operation (LCO) had been entered when the radiation monitor originally failed. Subsequent supervisory review determined that the operator had misapplied the TS and, in fact, an LC0 had not been entered. The inspectors noted that the terminology listed in TS 3.3.3 was not consistent with the actual equipment nomenclature and could be easily misinterpreted by an inexperienced or unknowledgeable operator.
Crew communications were acceptable, though not always in accordance with VPAP 1407, Verbal Communications, Revision 2.
The inspectors observed occasions where the control room operators exhibited excellent three way communications with proper terminology used and verbatim repeat back. On other occasions, the control room operator's message was transmitted, received and understood, but was technically poor when compared to the standards of VPAP 1407. The inspectors noted that often the plant operator in the field demonstrated more technically correct communications than some operators in the control room.
The inspectors observed several examples where the control room operator would communicate a vague, non-saecific command to a plant operator, the plant operator would translate t1e message, and then " repeat back" a concise, s)ecific interpretation of the order that accomplished the purpose of t1e command.
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Conclusions The inspectors concluded that control room activities were adequately controlled by the operators but that monitoring of plant parameters and crew communications were areas needing improvement.
II. Maintenance M1 Conduct of Maintenance (62707)
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During the week of October 14, the inspectors reviewed maintenance activities during the Unit 2 refueling outage ending October 13 to ascertain the amount of work items requiring rework during or following the outage.
The inspectors found that the following major Unit 2 outage related work items required rework during or following the refueling outage:
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A RCP flywheel installed with impro>er orientation
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C RCP seals exhibited excessive leacage after RCS pressurization
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B main steam atmospheric relief valve leaked after repeated repair
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attempts and still leaked at the inspection period's end
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l The inspectors concluded that three major maintenance work items required rework during or following the Unit 2 refueling outage.
M2 Maintenance and Material Condition of Facilities and Equipment H2.1 Review of Maintenance Activities Under 10 CFR 50.65
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a.
Inspection Scoce (62707)
During the week of October 7, the inspectors reviewed the licensee's
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implementation of 10 CFR 50.65 (Maintenance Rule) for maintenance activities associated with selected plant Structures, Systems, or
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Components (SSCs). The following SSCs with recent failures were reviewed and assessed against the requirements of 10 CFR 50.65 and VPAP 0815 Maintenance Rule Pilot Program, Revision 1:
1) Unit 1 Charging /High Head Safety Injection (HHSI) pump, 1 CH-P-1A: 2) Unit 2 Instrument Air (IA) system: 3) Unit 1 SW system: and 4) Boron Recovery System.
On October 8, the inspectors met with licensee Maintenance Rule implementation personnel to discuss how the specific equipment problems were evaluated.
b.
Observations and Findinas Unit 1 Charaina/HHSI Pumo. 1 CH P 1A The inspectors reviewed an event on July 18, 1996, when 1-CH P 1A developed an outboard seal leak shortly after starting (DR N-96-1295).
The leak was estimated at approximately 0.5 gpm and resulted in the pump being declared inoperable because excessive seal leakage resulted in total Emergency Core Cooling System leakage in excess of that analyzed in the Updated Final Safety Analysis Report (UFSAR). On August 7, 1996, it was determined by the licensee that this event caused the Maintenance Rule unreliability performance criteria of one percent to be exceeded (DR N 96-1417). When reviewing corrective actions for the first DR, the inspectors noted that the Station Nuclear Safety (SNS) identified a history of outboard seal leakage problems. These problems were documented in a memorandum from SNS dated July 23, 1996, which concluded that the problem required a Level 1 Root Cause Evaluation (RCE). The following examples were noted in the memorandum-1) On February 11, 1996, a 1 gpm leak was identified while performing a Safety Injection functional test: 2) On March 5, 1996, an approxiaately 60 drops per second leak was identified: 3) On June 6,1996, an unquantified seal leak was identified while returning the pump to service after preventive maintenance on the seal coolers (no maintenance was performed on the fluid side of the pump).
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During the October 8 meeting, the inspectors inquired concerning the RCE's status.
Licensee engineers replied that personnel to perform the RCE had been selected, but minimal work had been done. The inspectors later also discussed the RCE's status with an RCE team member.
The inspectors found that several meetings had been held to discuss the seal failures and that initial data had been gathered. However, the member also confirmed that the effort to date was minimal and that no action i
had been taken since approximately one week before the Unit 2 refueling outage began (approximately 40 days earlier). The inspectors also noted that the Station Manager's system for tracking open short term projects showed the RCE status as five percent complete.
i Also during the October 8 meeting, the inspectors questioned the previous seal failures as to whether they were evaluated as functional failures and whether they were Maintenance Preventable Functional Failures (MPFFs). After research, the site Maintenance Rule Coordinator responded that two of the previous failures were functional failures and should have been captured during the historical review to initiate i
evaluations to determine if they were MPFFs.
In summary, the inspectors found that timely action for identifying the cause of the seal failures had not been initiated.
Specifically, i
previous 1-CH P 1A seal failures were not properly evaluated to ascertain if MPFFs had occurred.
Additionally, two and one half months
had passed since the July 18 failure without completing significant progress in determining the root cause to support evaluating whether the seal failure was an MPFF.
10 CFR 50.65(a)(1) requires, in part, that licensees shall monitor the performance or condition of SSCs against licensee-established goals, in a manner sufficient to provide reasonable assurance that such SSCs within the scope of the rule are capable of fulfilling their intended functions. When the performance or condition of an SSC does not meet established goals, appropriate corrective action shall be taken.
10 CFR 50.65(a)(2) requires, in part, that monitoring as specified in paragraph (a)(1) is not required where it has been demonstrated that the performance or condition of an SSC is being effectively controlled through the performance of appropriate preventive maintenance, such that the SSC remains capable of performing its intended function. VPAP 0815, Maintenance Rule Program, Revision 2, Section 6.1.4.a.2, implements these 10 CFR 50.65 requirements and states, in aart, that if functional failures are identified, a Category 1 or 2 RCE 3e performed to support determinations if the functional failure was an MPFF.
Contrary to the above requirements, as of October 8, an RCE and associated MPFF determination had not been completed for several pump 1-CH P-1A seal failures occurring between February 11 and July 18, 1996.
This is considered the first example of a violation of Maintenance Rule requirements (50 338, 339/96010 02).
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Unit 2 Instrument Air (IA) system
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The inspectors reviewed an event on September 21 and an earlier event on
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August 1, 1996, when air tubing on the Unit 2 IA dryer blowdown severed causing a decrease in IA pressure (DRs N 96-1391 and N 96 2008). The IA i
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i system's maintenance rule function was defined to maintain IA pressure
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> 90 psig.
For both the August 1 and September 21 reduction of IA
l pressure events, the pressure dropped below 90 psig, and the criteria
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for a functional failure was met.
f The inspectors found that VPAP-0815 requirements were not fully I
implemented in the responses to the August 1 DR.
Specifically, the initial assignment of actions by SNS did not include a requirement for a
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Category 1 or 2 RCE or performance of an MPFF evaluation for the functional failure. This error was identified by corporate personnel
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who initiated action to perform the evaluation to determine if an MPFF occurred. When reviewing the documentation, the inspectors noted that the MPFF evaluation form had been completed indicating that the
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functional failure was not an MPFF. The form also indicated that a RCE i
was not required. Determining that an J FF had not occurred without i
performing a Category 1 or 2 RCE for DR N 96 1391 was contrary to
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VPAP 0815 requirements as stated above. This was identified as the
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second example of a violation of Maintenance Rule requirements
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(50 338, 339/96010 02).
The inspectors noted that although a Category 1 or 2 RCE was not
initiated following the first failure, the copper air line was sent to
the licensee's metallurgical lab for further evaluation. Also, after j
the second failure, corrective actions were taken to replace the copper j
lines with stainless steel, a
Boron Recovery System
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The inspectors reviewed DR N 96-1770, dated September 10, 1996, which documented an event where airflow from the C Boron Recovery Tank (BRT)
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vent was identified and characterized as an unmonitored release from the
plant.
Samples were taken to quantify the release, and the release was
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found to be minimal. Concerning Maintenance Rule implementation, the
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inspectors found that the Boron Recovery System was listed as a non risk
significant system monitored by plant level performance criteria. One of the plant level performance criteria for non risk significant systems was that no unmonitored radioactive effluent release occur.
However,
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the corrective action assignments for the DR did not identify that the
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criteria had been exceeded and did not direct that a Category 1 or 2 RCE be performed to help determine if an MPFF had occurred. As a result, a Category 3 (lower level) RCE was performed, and the status with regards to the Maintenance Rule was not determined. The inspectors concluded
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that the licensee failed to implement the requirements of VPAP 0815 as stated above for performing a Category 1 or 2 RCE to determine if an i
MPFF had occurred. This was identified as the third example of a violation of Maintenance Rule requirements (50 338, 339/96010 02).
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- Unit 1 Service Water System
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The inspectors reviewed DR 96-1054, dated May 22, 1996, which documented that the A SW train had exceeded its performance criteria
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(unavailability < 150 hours0.00174 days <br />0.0417 hours <br />2.480159e-4 weeks <br />5.7075e-5 months <br />) for the previous 12 months. The total l
unavailability for the 12 month period ending May 1996 was 210 hours0.00243 days <br />0.0583 hours <br />3.472222e-4 weeks <br />7.9905e-5 months <br />.
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The insgctors found that the response to the DR noted that the
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unavailability hours were primarily caused by SW piping upgrades (58 hours6.712963e-4 days <br />0.0161 hours <br />9.589947e-5 weeks <br />2.2069e-5 months <br />) and screen wash intake structural work (110 hours0.00127 days <br />0.0306 hours <br />1.818783e-4 weeks <br />4.1855e-5 months <br />). The
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licensee considered this acceptable and had analyzed that the risk l
involved with the unavailability was low. The licensee also indicated i
that preliminary analysis showed that an unavailability of 5 percent, or
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438 hours0.00507 days <br />0.122 hours <br />7.242063e-4 weeks <br />1.66659e-4 months <br />, would be acceptable. The licensee planned to change the l
performance criteria to reflect this analysis, but the inspectors found
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that as of October 8, the
>erformance criteria had not been changed.
The ins)ectors concluded t1at the licensee had taken a reasonable approac1 in evaluating the rick of increased unavailability, but considered the failure to u>date the performance criteria in a timely
manner to be a weakness. T1e inspectors discussed this finding with
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licensee managers and were informed that performance criteria updates i
would be completed by mid November.
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c.
Conclusions One violation with three examples was identified for failures to implement Maintenance Rule program requirements for root cause evaluations. A weakness was identified for a failure to u Maintenance Rule performance criteria in a timely manner. pdate M2.2 On line Maintenance Activities Review a.
Inspection Scope (62707)
During daily control room observations on October 9, the inspectors observed that two safety related components (SW Pump 1 SW P-1A and Casing Cooling Pump 1 RS P-3A) were simultaneously unavailable. The j
inspectors reviewed the licensee's maintenance activities to ascertain the effectiveness of the licensee *s programs to assess the effects of total equipment out of-service as required by the Maintenance Rule
)
[10 CFR 50.65(a)(3)].
b.
Observations and Findinas The inspectors found that on October 8, 1 SW P-1A was removed from service under tag out N 1 96 SW 0047 to perform intake bay maintenance.
The > ump was returned to service (i.e., functional, but not operable) on Octo)er 9 at 6:20 a.m.
Also on October 9, 1-RS P 3A was removed from service at 5:30 a.m. under tag out N-1-96 RS-0030 to perform an oil change. The inspectors observed that TS did not prohibit taking these l
two pieces of equipment out of service simultaneously.
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The inspectors reviewed the risk information available for the systems involved. The inspectors found that the simultaneous unavailability was not risk significant. This fact combined with the short time the two components were simultaneously unavailable led the inspectors to determine that having the two components out of service simultaneously was not significant.
The inspectors then discussed control for this simultaneous i
unavailability with planning, operations and supervisory personnel. The inspectors found that the simultaneous unavailability had not been
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anticipated as a part of the work planning and approval process. This
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occurred because the work associated with 1 SW P 1A was delayed and was not completed on schedule. Operations and planning personnel failed to recognize the possible impact of the delay and went ahead with the
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tag out on 1 RS P 3A as scheduled on the licensee's Plan of the Day.
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The inspectors noted that the licensee's programs were intended to provide additional reviews and approvals to ensure that the risk and possible safety impact was assessed in advance when more than one risk important component was made unavailable. During the reviews, the inspectors found numerous members of the licensee's maintenance, planning, operations and management organizations were unfamiliar with the licensee's Maintenance Rule related programs (described in VPAP 2001, Station Planning and Scheduling, Revision 2) for controlling on line maintenance for multiple risk im)ortant components. The inspectors considered that this lack of (nowledge was a weakness.
c.
Conclusions The inspectors concluded that various licensee departments did not understand the licensee's Maintenance Rule related programs for controlling on line maintenance for multiple risk important components, and this was considered a weakness.
M8 Miscellaneous Maintenance Issues (92700, 92902)
i M8.1 (Closed) VIO 50 339/95015 02: Two MOVs Modified Without Proper Design Change Review.
This violation concerned an event where two charging Jump discharge valves, 2 CH MOV-2286B and 2-CH MOV 22878, were overt 1 rusted during
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maintenance. The event was caused by an incorrect rewiring of the
valves' motor operators by maintenance technicians. As corrective i
action, the licensee modified drawing control programs, reviewed human performance lessons learned with station personnel, and modified areventive maintenance procedures.
Since the valve internals could not ye inspected for damage with the unit on line, the licensee completed a Justification for Continued Operation (JCO), JC0 95-02, prior to
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returning the associated charging pump to service. The JC0 included actions to ensure continued valve integrity by examining the valve bodies and operators for damage, and to " VOTES" test the valves following any cycling. The inspectors verified that these actions were
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completed prior to the valves' return to service (NRC Inspection Reports Nos. 50 338, 339/95015 and 95016).
During this inspection period, the inspectors reviewed the licensee's actions to r.omplete valve internals inspections during the Unit 2
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refueling outage.
The JC0 stated that during the next outage of sufficient length, the valves would be opened and internally inspected.
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The JC0 described these inspections as including visual and Liquid l
Penetrant (LP) tests for the valve seat and wedge. The inspectors found l
that the seat and wedge inspections were completed satisfactorily for
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2 CH M0V 22868. However, on September 23, DR N 96 2035 reported that when 2 CH M0V 2287B was disassembled, an LP test was not completed for the seat due to an oversight in the maintenance work package. After
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l identifying this problem, the licensee initially planned to delete the LP ins wction requirement for the seat on 2 CH M0V 2287B. However, after seing reminded by the inspectors of commitments made in response to the violation which specifically stated that the inspections described in the JC0 would be completed, the licensee re opened the valve and completed the LP inspection.
For both valves, tests found that the seats were satisfactory, but minute cracking was found on the wedges which required their replacement. The inspectors concluded that the licensee's response dated October 12, 1995, and corrective actions were appropriate and had been adequately implemented.
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l M8.2 (Closed) VIO 50 338/96003 02: A RCS Loop Flow Transmitter Tubing Frame Support Found Partially Disassembled.
This violation concerned the discovery by NRC inspectors that the tubing j
for an RCS loop flow transmitter was not fully assembled. The violation was caused by inadequate control over the safety-related instrument tubing during past maintenance or modification activities. As corrective action, the licensee repaired the specific tubing supports j
and performed additional inspections to find and correct any similar problems. The inspectors verified that these inspections were completed during the March 1996 Unit 1 outage and during the Unit 2 outage ending in this inspection period. The inspectors reviewed the licensee's inspection results and independently observed material conditions for numerous additional containment hangars and supports. The inspectors
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did not identify any other significant deficiencies. The inspectors observed that the licensee's inspections were effective in identifying and correcting numerous minor deficiencies. Additionally, the licensee
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improved maintenance and modification procedures to clarify requirements
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for verifying proper re assembly of interferences. The inspectors concluded that the licensee's response dated June 3, 1996, and corrective actions were appropriate and had been adequately implemented.
M8.3 (Closed) LER 50 339/96002:
Feedwater Check Valve Excessive Leakage.
a.
Insoection Scope
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The inspectors reviewed the subject LER to determine if reporting l
requirements were met and if the problem's cause and corrective actions
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were appropriately identified.
b.
Observations and Findinas This LER re?orted failures of two of three installed Unit 2 Main Feedwater (iFW) check valves to pass leakage tests following shutdown for refueling.
Valve 2-FW 94 had leakage slightly higher than test acceptance criteria, and valve 2 FW 62 had significant leakage beyond the test method's ability to quantify. As corrective action, the licensee removed all three Unit 2 MFW check valves and had them refurbished by the manufacturer. All three valves then were satisfactorily retested, and the inspectors verified that this was completed prior to Unit 2 restart following refueling.
During LER review, the inspectors found that statements in the LER were unclear on the problem's cause and corrective actions and discussed these questions with licensee management. The LER stated that the cause was, "a lack of com)lete disc to seat contact." The inspectors expressed concern tlat this causal identification appeared superficial.
Saecifically, the cause in the LER did not provide information as to w1at caused the lack of disc to seat contact. Additionally, the LER stated that no new actions would be taken to prevent recurrence because current test methods were adequate to detect increasing leakage and prompt repairs before future failures.
Licensee management informed the inspectors that they believed the problem to probably result from component aging. Since the continued use of the improved testing method would detect and trend increasing leakage, maintenance would be performed before aging would result in future failures. The inspectors considered that this appeared reasonable, but noted that aging as a cause was not mentioned anywhere in the LER.
Additionally, the LER stated that during refurbishment, the manufacturer identified a 3rior maintenance error in assembling 2 FW 62. The LER stated that t11s may have contributed to the problem, but noted that the valve had successfully been tested twice since last disassembly. The inspectors noted that although this was stated to possibly contribute to the problem, no corrective actions or actions to prevent recurrence were listed in the LER to address this issue.
However, the inspectors noted that the testing now performed by the licensee would be adequate to detect any similar problem in the future.
Finally, the inspectors noted that the LER stated
"a Category II RCE was completed." However, the inspectors found that this statement was inaccurate. When the inspectors asked to review the RCE, the inspectors were informed that the RCE had not been yet fully accepted by the SNSOC.
An initial RCE had concluded that the problem was caused by the maintenance error during assembly, but this had been rejected by the SNSOC because it was not supported by the fact that the valve had passed two tests since last being disassembled. At the inspection period's end, the RCE had not yet been returned to SNSOC for final review and approva _
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The inspectors found that regardless of the cause, the valves'
refurbishment and the licensee's current testing techniques were reasonable to correct the problem and detect future problems.
However, the inspectors considered that the LER was unclear in stating possible
causes and applicable corrective actions. Specifically, the cause
i statement in the LER was superficial, and no corrective actions were listed which directly addressed maintenance errors discussed in the LER.
c.
Conclusion The inspectors concluded that the licensee had adequately ensured that
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i recurrence of the problem would be prevented by future routine testing.
However, the LER did not clearly state possible causes and corrective
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actions for the feedwater check valve failure.
M8.4 (Closed) LER 50 338. 339/96007:
Failure to Functional Check Waste Gas
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Decay Tank Hydrogen /0xygen Analyzer Alarm.
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This LER reported the identification on September 24, 1996, that a monthly surveillance test required by TS 4.3.3.11 failed to include a
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functional test of one alarm circuit. The surveillance test, i
1/2 PT 45.9.3, Waste Gas Decay Tank Outlet Oxygen Functional Test (0 GW 102), Revision 6, was designed to meet TS requirements to perform i
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a monthly channel functional test for the oxygen monitor on the waste
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gas holdup system explosive gas monitoring system. The licensee identified that the test did not fully meet the TS definition for a
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channel functional test because it did not test all alarms associated
with the sy a em.
Specifically, the test did not verify that the greater than two percent oxygen alarm was received in the control room. The licensee declared the equipment inoperable, modified the procedure, and
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successfully completed the test including the alarm test later the same
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date. A review of past records found that the requirement had been overlooked following modifications to the system in 1990.
It was also found that the quarterly surveillance test had adequately and successfully tested the alarm since its installation. The inspectors verified that the licensee had successfully modified the monthly surveillance test to incorporate testing the alarm.
TS Surveillance Requirement 4.3.3.11 requires that a monthly channel functional test be performed for the oxygen monitor on the waste gas holdup system explosive gas monitoring system. TS Definition 1.5 i
defines a channel functional test to include all alarm functions.
j Contrary to these requirements, from April 3, 1990, until September 24,
1996, a monthly channel functional test including a two percent oxygen
alarm was not completed for the waste gas holdup system explosive gas monitoring system. This is identified as a violation for an inadequate surveillance test. This licensee-identified and corrected violation is being treated as an NCV, consistent with Section VII.B.I of the NRC Enforcement Policy (NCV 50 338. 339/96010-03).
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III. Enaineerina E2 Engineering Support of Facilities and Equipment E2.1 Review of Proposed Modification to Containment RMs a.
Insoection Scope (37551)
During the week of October 7. the inspectors reviewed a proposed modification to containment RMs to remove the requirement for seismic qualification.
b.
Observations and Findinas On October 7, the inspectors found that the licensee proposed to delete the requirements for seismic qualification for the containment gaseous and particulate RMs. The seismic qualifications for these monitors had twice been identified as deficient by the licensee (LER 50 338, 339/96004 00 and 01) and various corrective actions were initiated to i
correct the deficiencies.
Parts of these activities were previously i
reviewed by the inspectors and discussed in NRC Inspection Report Nos. 50 338, 339/96007. Additional corrective actions for deficiencies
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included modifying the IA supplies to Containment Isolation Valves (CIVs) for the system.
Prior to restarting Unit 2 following refueling outage, the licensee completed these modifications on Unit 2.
Additionally, the licensee completed modifications to the CIVs on Unit 1 with the exception of the inside CIV for the RM supply line, 1 TV RM 100C. Due to the subatmospheric aressure, high temperature, and i
cramped work area conditions present at t1e valve, the licensee concluded that performing the modification on 1-TV-RM-100C was an unacceptable risk to the safety of personnel performing the l
modification.
The licensee then proposed to process a change to the system under 10 CFR 50.59 to delete the requirement for the system to be seismically qualified. The inspectors expressed concern to licensee management that the change appeared to be an unreviewed safety question which could not be done under 10 CFR 50.59 without NRC review and ap3roval. The inspectors based this conclusion on a review of UFSA1, TS 3.4.6.1 bases, NRC Regulatory Guide 1.45 Reactor Coolant Pressure Boundary Leakage Detection Systems, dated May 1973, the NRC Standard Review Plan (NUREG 0800), and the original license Safety Evaluation Report dated June 1976. All the documents were consistent in that NRC license approvals were based upon the system being qualified to detect leakage following seismic events not requiring a plant shutdown.
Licensee management responded to the inspectors' concerns by explaining that the change would include requirements to shutdown the unit following a seismic event if the radiation monitors were not operable.
The inspectors agreed that initiating a plant shutdown if the monitors were inoperable
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was consistent with the monitor's purpose. However, the inspectors
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continued to disagree that the licensee could delete the system's i
seismic qualification requirement without NRC review and approval.
The licensee further reviewed the issue and chose to initiate an alternative course of action.
Instead of attempting to delete the
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requirement for seismic qualification, the licensee chose to )repare a i
Justification for Continued Operation (JC0) for the valve. T1e JC0 l
(1-96 01) provided that the system could remain operable without
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modification to the valve. The JC0's position was based on the fact that the safety function of the monitors was defined to be shutting down the unit following a seismic event resulting in RCS leakage, and could be maintained by modifying procedures to require checking the monitors'
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l status following a seismic event and shutting down the unit if the monitors were inoperable.
The inspectors reviewed the JC0 and found I
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that it met NRC guidance for continued operability evaluations. At the
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inspection period's end, the licensee planned to obtain NRC approval, if i
required, and change the TS bases to remove the requirement for seismic l
qualification at a later date.
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Conclusions The inspectors concluded that a licensee proposal to remove recuirements
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for seismic qualification for containment RMs was an unreviewec safety question requiring NRC review. The licensee chose to take an alternative course of action, and a JC0 was prepared to address the issue temporarily.
E7 Quality Assurance in Engineering Activities E7.1 Review of UFSAR Commitments l
A recent discovery of a licensee o>erating their facility in a manner contrary to the UFSAR description lighlighted the need for a special focused review that compared plant practices, procedures and/or parameters to the UFSAR descriptions. While performing the inspections discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameters.
E8 Miscellaneous Engineering Issues (92903)
E8.1 (Closed) VIO 50 338. 339/96001-02: Unreviewed Modifications to Containment Blowout Panels.
This violation concerned the identification by NRC inspectors on February 13, 1996, that containment Steam Generator (SG) and reactor coolant system loop cubicles and the incore instrument tunnel blowout panels had been modified such that their configurations did not meet design basis descriptions.
Initial corrective actions for the problem
were previously reviewed by the inspectors shortly following initial
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identification (NRC Inspection Report Nos. 50 338, 339/96001). During
this inspection period, the inspectors verified that the licensee
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completed necessary modifications to the Unit 2 blowout panels.
During field observations, the ins)ectors found that one SG cubicle door blowout panel contained eig1t screws instead of six as described in the UFSAR. The inspectors discussed this finding with licensee engineers and found that the door had been added by a 1985 design change which
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contained a safety evaluation for the configuration. The change was being tracked by the licensee for future UFSAR update. Additionally, modifications were completed to incore instrument tunnel blowout panels
to restore their configuration, and inservice inspections were initiated for' the panels. The inspectors concluded that the licensee's response dated April 15, 1996, and corrective actions were appropriate and had been adequately implemented.
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IV. P1 ant Support
R1 Radiological Protection and Chemistry (RP&C) Controls RI.1 Radioloaical Protection FAs Low As Reasonably Achievable (ALARA)
Proaraml a.
Inspection Scope (83750l The inspectors reviewed the licensee's ALARA program and its implementation during the Unit 1 Refueling Outage February 11, 1996 to March 11, 1996, and the Unit 2 Refueling Outage scheduled to be completed October 4, 1996. The outage was extended by unanticipated additional Reactor Coolant Pump Seal work during the period of inspection.
j b.
Observations and Findinas The activities of the Unit 1 Refueling work were documented in 1996 Unit One Refueling Outage ALARA Report dated May 14, 1996. The report stated that the outage was completed in 29.9 days versus 34 planned and 184.263 person rem (98 percent of the goal). Areas highlighted for exposure reduction improvement were:
insulation removal and replacement, scaffolding and decontamination. These activities accounted for more than 34 person rem (20 percent) of the outage.
Better integration of support activities into work plans and more detailed walkdowns of job sites were expected to help reduce exposures. The Unit 2 Outage person rem goal was set at 149.518. As of October 10, 1996, the Unit 2 outage dose was 116.910. Significant dose reductions were realized during the Unit 2 Refueling Outage in insulation replacement (39 percent of goal), walkdowns (50 percent of goal), and routine decontamination (81 percent of the goal). These reductions were lessons learned improvements even though there were some workscope reductions in the outage. ALARA Awareness Update boards at four locations around the station and pre job briefings and post job debriefings kept the workers informed of their ALARA performanc _
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The Outage ALARA Guide detailed the Generic Exposure Reduction Techniques as well as specific reduction techniques for the containment and major tasks. The guide >rovided a hel aful handbook and reference.
The licensee included color (eyed maps to 1elp workers to quickly identify the various area dose levels.
These color keyed maps were strategically placed in plant areas to assist workers in finding low
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dose areas.
l Total Effective Dose Equivalent ALARA Evaluations for respirator use for
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removal and replacement of insulation and SG Primary Inspections were l
reviewed and found acceptable. Tours of the C RCP seal work area by the
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inspectors did not identify any exposure problems.
Shield packages were l
appropriately positioned to provide worker protection.
c.
Conclusions The ALARA program was aggressively implemented and was using lessons learned from previous outages and industry experience to reduce station radiation exposure. The ALARA program was considered a program strength.
R1.2 Radioactive Effluent Control Proaram a.
Inspection Scope (84750)
The inspectors reviewed the overall results of the radioactive effluent control program as documented in the Annual Radioactive Effluent Release Report for 1995. The amounts of radioactivity released and the resulting radiation doses for the years 1992 through 1995 were also tabulated from the annual reports to evaluate long term performance of
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the effluent control program relative to the design objectives in 10 CFR 60, Appendix I, for radiation doses from plant effluents.
b.
Observations and Findinas The data presented in Table 1 below were compiled from the licensee's effluent release reports for the years 1992 through 1995. The inspectors reviewed the report for the year 1995 and discussed its content and the data presented in Table 1 with the licensee.
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TABLE 1 j
NORTH ANNA RADI0 ACTIVE EFFLUENT RELEASES LIQUID EFFLUENTS
Year F&AP H
D&EG T.B. DOSE ORGAN DOSE
[3 mrem]
[10 mrem]
1992 0.50 929 4.82E 1 0.66 (11%)
0.84 (4.2%)
1993 0.48 693 5.86E-2 0.44 (7.3%) 0.54 (2.7%)
1994 0.54 1239 5.99E 4 0.40 (6.6%) 0.42 (2.1%)
1995 0.35 976 6.90E 4 0.28 (4.7%) 0.29 (1.4%)
GASE0US EF FLUENTS
Year F&AP Iodines Part.
ti Air Doses Oraan Dose
[y 10 mrad]
[15 mrem]
[# 20 mrad]
1992 1226 1.34E-2 1.00E 4
y 8.8E-2 (0.4%)
0.6 (2.1%)
- 1.9E 1 (0.4%)
1993 250 2.44E-3 4.60E 4
y 3.6E 2 (0.2%)
0.1 (0.4%)
- 4.8E 2 (0.1%)
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1994 43 3.92E 4 7.06E 5 117 y 4.0E 2 (0.2%)
0.02 (0.08)
- 1.6E 2 (0.04%)
1995 36 2.34E 4 7.60E 5 202 y 2.3E 2 (0.1%)
0.02 (0.07%)
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- 1.1E 2 (0.03%)
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[H Fission and Au.ivation Products (Curies released)
&AP Tritium D&EG Dissolved and Entrained Gases T.B.
Total Body
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Limits / Unit ()
% of Limits / Unit Part. Particulates y
Gamma
Beta
As indicated in the table there was a significant decrease in the amount of activity released as fission and activation products in gaseous effluents. i.e., from 1226 Curies (C1) in 1992 to 36 Ci in 1995.
Concurrently, the organ doses c!ecreased from 2 3ercent of the per unit limit to less than 0.1 percent of the limit. T1e licensee indicated that this reduction was a result of having replaced leaking fuel J
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elements. The inspectors noted that the amount of activity released as F&AP in liquid effluents was consistently about 0.5 Ci per year, but the
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total body dose decreased from 113ercent of the per unit limit to less than 5 percent of the limit.
Furt1er examination of the data in the i
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effluent release reports revealed that the amount of Cs 137 released in i
liquid effluents during 1995 was approximately six percent of the amount
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released during 1992. The licensee indicated that this was achieved as a result of their aggressive radioactive waste minimization program and
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the enhanced radioactive waste filtration program. The inspectors concluded that the licensee's performance regarding the reduction of the amounts of activity released and the reduction of the radiation doses
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was a program strength. Overall, for the year 1995, the annual total body and organ doses from licuid effluents were less than five percent of their limits. The air anc organ doses from gaseous effluents were
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less than 0.2 percent of their limits. The effluent release report
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indicated that during 1995 there were no unalanned releases, as defined by the criteria delineated in the Off site Jose Calculation Manual (0DCM), and no effluent monitors inoperable for more than 30 days, i
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Conclusions
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Based on the above reviews, the inspectors concluded that the licensee
had implemented and maintained an effective program to monitor and
control liquid and gaseous radioactive effluents. The
)rojected offsite doses resulting from those effluents were well within t1e limits specified in the TSs and ODCH. The licensee's performance regarding the
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reduction of the amounts of activicy released and the reduction of the radiation doses from those releases was deemed to be a program strength, l
R1.3 Radioloaical Environmental Monitorina Procram a.
Insoection Scooe (84750)
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The inspectors reviewed the overall results of the radiological environmental monitoring program as documented in the Annual Radiological Environmental Operating Report for 1995. Those results were compared to the program requirements delineated in the ODCM.
b.
Observations and Findinas The inspectors noted that, in accordance with the TS and ODCM, the report included a description of the program, a summary and discussion of the results for each exposure pathway, analysis of trends during the operational years as compared to the preoperational years, and an assessment of the impact on the environment based on program results.
The report also included a tabulation of the summarized analytical results for the samples ccllected during 1995.
From a review of this data the inspectors determined for selected exposure pathways that the i
sampling and analysis frequencies specified in the ODCM had been met.
As indicated in the report conclusions, the analytical results were as expected for normal environmental samples.
Very low concentrations of man made isotopes were occasionally detected in the samples but were of
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no dose consequence.
It was further concluded that during 1995, as in
>revious years, there were no adverse environmental effects or health lazards as a result of plant operations,
The inspectors also observed the licensee's collection of samples from six air sampling stations. The inspectors noted that the sampling equipment was operable and in good working order, the sampling stations were located as indicated in the ODCM, and good sampling techniques were employed by licensee personnel in collection of the samples.
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c.
Conclusions
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Based on the above reviews and observations, the inspectors concluded that the licensee had complied with the sampling, analytical and reporting program requirements, the sampling equipment was being well
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was effectively implemented.
R1.4 Meteoroloaical Monitorina Proaram
a.
Inspection Scope (84750)
The inspectors reviewed the licensee's procedures and records for the surveillances performed to demonstrate operability of the meteorological monitoring instrumentation as required by TS.
b.
Observations and Findinas
The inspectors reviewed 11 of the licensee's procedures for the l
performance of daily channel checks and semiannual channel calibrations
and determined that they were consistent with the requirements of TS i
3/4.3.3.4 for demonstrating that the meteorological monitoring
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instruments were operable. The inspectors reviewed the records for the most recent instrument calibrations for wind speed, wind direction, and
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air temperature which were performed during September 1996. Those
records indicated that the calibrations were current and had been
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performed in accordance with the applicable procedures.
During a tour
of the Control Room, licensee personnel demonstrated for the inspectors that the required meteorological monitoring instrumentation was operable
by displaying on a computer screen the current meteorological parameters. The inspectors also reviewed the daily surveillance log, i.e., the Back Board Log, and determined that the daily channel check had been performed.
c.
Conclusions
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Based on the above reviews and observations, the inspectors concluded that the surveillanca requirements for demonstrating operability of the i
meteorological monitoring instrumentation were met.
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j R2 Status of RP&C Facilities and Equipment i
R2.1 Status of Radiation Protection Facilities and Eauipment a.
Inspection Scope (83750)
The inspectors reviewed selected effluent monitors, radiation monitors, whole body friskers, hand held friskers, and survey instruments to observe their operational status, calibration and material condition.
The Stand Up and Bed Whole Body Counter calibrations and the 1995 Whole Body Counter Confirmatory Measurements report were reviewed.
b.
Observations and Findinas The effluent monitors selected by the inspectors were found to be operational and their material condition acceptable. Selected radiation survey and frisking instruments were found operational and within calibration dates. The whole body counters were calibrated as required by station procedures. The report detailing the 1995 Whole Body Counter Confirmatory Measurements concluded that the whole body counter was accurately measuring the calibration sources.
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The inspectors reviewed procedure HP 1061.020, Personnel Contamination Monitoring and Decontamination, Revision 1.
This procedure was used as a screening procedure for contamination monitoring and decontamination requirements.
Section 6.1.5 described conversion factors for converting instrument (R0 2 or equivalent) millirem / hour readings to disintegrations per minute (dpm). The technical basis for these and other Health Physics conversion factors were in the process of being
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documented in the 0)erations Support Cor) orate Procedure. The licensee was informed that t1e documentation of t1e technical basis for these conversion factors will be tracked as an Inspection Follow-up Item (IFI)
(50 338, 339/96010 04),
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Conclusions i
All monitors reviewed were found to be operational, calibrated and in good material condition. One IFI was identified and will be tracked involving the completion of documentation of the Health Physics (HP)
conversion factors.
R2.2 Tours of Licensee Radiolooical Control Areas a.
Inspection Scope (83750)
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During tours of the licensee facilities, the inspectors selectively verified that radiological postings and labels were appropriate for the l
radiological hazard.
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b.
Observations and Findinas The inspectors observed good control of contaminated and radioactive material and housekeeping in work areas within the Unit 2 containment, auxiliary building, decontamination building, waste solids area, new decontamination building, outside yard storage, and fuel handling i
building.
The inspectors observed health physics technicians in the new decontamination building hand frisking rugs that had been on the floor in the mens' clean change area and HP briefing room.
Multiple radioactive particles were found embedded in the rug pile. The particles were identified using a calibrated RM-14 frisker (Serial Nos. 2061, 2019 and 2040).
Particle measurements ranged from about 2,000 dpm to 18,000 dpm. The inspectors requested supplemental floor surveys in the clean area surrounding the change room and in the halls outside of the change area and the rugs and chairs in the control room.
No additional contamination was found.
Surveys of large area wipes of the floor did not identify any contamination. The vacuum used to clean the HP briefing room was surveyed and low levels of contamination were found in the bag.
The vacuum cleaner bag measured about 150,000 dpm.
This was evaluated to be less than Appendix C limits and thus met the exemption to labeling requirements in 10 CFR 20.1905. The inspectors reviewed selected historical surveys of the areas and did not find any documented surveys showing radioactive particles in the clean areas.
The licensee believes that the particles resulted from a mechanical / electrostatic transfer from protective clothing. The protective clothing had been checked using a laundry monitor set at 50,000 dpm rejection limit. Operational checks by the inspectors verified the laundry monitor alarm operability. The monitor was source checked prior to use.
c.
Conclusions The licensee was controlling contaminated and radioactive material in work areas.
Housekeeping in areas toured by the inspectors was judged acceptable. Radiological postings and labels were ap3ropriate for the radiological hazard. Radioactive particles detected )y the licensee indicate storage of anti contamination clothing in clean areas can lead to loss of control of radioactive material.
R7 Quality Assurance in Radiological Protection and Chemistry Activities R7.1 Audits and Aooraisals a.
Insoection Scope (83750)
The inspectors reviewed the licensee's program for identifying and correcting deficiencies or weaknesses related to the control of
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radiation or radioactive material. The licensee's documentation for the 10 CFR 20.1101(c) requirement for the periodic review of the Radiological Protection Program Content and Implementation was reviewed.
b.
Observations and Findinas The inspectors selectively reviewed the DRs related to the control of radiation or radioactive material. The inspectors reviewed the Nuclear Oversiaht Audit ReDort 96 05 dated July 3,1996.
The audit was aerformed to verify that the licensee effectively translated the ladiological Protection Plan into programs that satisfy regulatory and licensing requirements, and promoted a safe radiological work environment. The inspectors also reviewed the July 17, 1996, report titled Radiation Protection DeDartment Self-Assessment Report for the Second Quarter. 1996, and Radiation Protection Department Proficiency Summary Reoort, dated September 1996.
c.
Conclusions The licensee's program for identifying and correcting deficiencies or weaknesses related to the control of radiation or radioactive material was aggressive in identifying, assigning responsibilities, and tracking to resolution corrective actions. The requirements of 10 CFR 20.1101(c)
for the periodic review of the Radiological Protection Program Content and Implementation were being met by the Nuclear Oversight Audit Report 96 05. The self assessment report and the proficiency summary report are additional examples that demonstrate the aggressive identification program.
R7.2 Environmental Protection Aaency (EPA) Interlaboratory Comoarison Proaram Participation a.
Insoection Scope (84750)
The inspectors reviewed the results of the licensee's participation in the EPA's Interlaboratory Comparison Program as documented in the Annual Radiological Environmental Operating Report for 1995.
Participation in that program was required by TS to ersure that independent checks on the precision and accuracy of the environmental monitoring program measurements were performed. The licensee's results were compared to the EPA's analytical control limits, b.
Observations and Findinas The inspectors noted that the report included descriptions of the various types of samples analyzed and the analyses performed, and an evaluation of the analytical results. The EPA provided 17 samples of various environmental media, and a total of 44 analyses were performed.
Statistical evaluation of the program data indicated that two of the licensee's analytical results exceeded the EPA warning limits but not the action limits. The licensee investigated both of these occurrences and documented the results in the report.
For one of the analyses,
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I 131 in water, the analytical instrument was recalibrated, and good agreement was achieved.
For the other analysis, gross alpha in water, the warning limit was only slightly exceeded. During the year, four more of these type of analyses had been performed, two before and two
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after this occurrence, and those analyses were within the warning
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limits. The licensee determined that further corrective action was not i
warranted, l
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Conclusions I
Based on the licensee's overall erformance in the EPA cross-check program, the inspectors concluded that an effective quality assurance program had been maintained for analysis of environmental samples.
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R8 Miscellaneous RP&C Issues i
R8.1 (Closed) Unresolved Item (URI) 50 338. 339/96007 03:
Failure to Meet
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State of South Carolina Radioactive Material License and
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a.
Insoection Scope (86750. TI 2515/133)
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NRC Inspection Report No. 50 338, 339/96007, issued Seatember 9, 1996,
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identified URI 50-338, 339/96007-03, which discussed t1e May 17, 1996, notification from South Carolina Barnwell Low-Level Waste Facility that radioactive waste shipment No. 0596 5939 (96 0004), classified as, i
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" Radioactive Material. LSA, n.o.s., 7 " described as, " solid oxides
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deposited on spent resin," and packaged in a poly High Integrity i
Centainer (HIC), was found to contain approximately 29.85 gallons
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(2.5 percent) of liquid, greater than one percent.
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b.
Observations and Findinas
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The inspectors reviewed the information concerning the May 17, 1996 notification from South Carolina Barnwell Low Level Waste Facility that radioactive waste shipment No. 0596 5939 (96 0004), classified as,
" Radioactive Material, LSA, n.o s deposited on spent resin," and hac.,
7," described as, " solid oxides kaged in a poly HIC, was found to
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contain approximately 29.85 gallons (2.5 percent) of liquid. This was contrary to the requirements of South Carolina Radioactive Material License 097, Amendment 46. Condition 32 (C) which prohibits liquids in excess of one percent of total waste volume. The State of South Carolina assessed a civil penalty of one thousand dollars ($1000) in a
May 22, 1996, letter to the licensee. The fine was paid by the licensee on June 12, 1996, which was prior to the June 18, 1996, due date. The i
inspectors reviewed the May 21, 1996, licensee response to the state explaining the corrective actions taken to prevent recurrence. The
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licensee was informed that this event was a violation of 10 CFR 61.56(a)(3) (EA 96 322 01014).
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c.
Conclusions A violation was identified for exceeding 10 CFR 61.56 requirements for maximum liquid content in a solid waste shipment. One URI was closed.
S1 Conduct of Security and Safeguards Activities S1.1 Vehicle Gate Mannino Review (71750)
a.
Inspection Scope The inspectors reviewed the licensee's site vehicle gate manning practices to determine if NRC requirements for security manning at the site were met.
b.
Observations and Findinas The inspectors reviewed the licensee's changes to policies for manning the main site vehicle access gate located on State Route 700 next to the North Anna Nuclear Information Center (NANIC). The gate was commonly j
referred to as the NANIC gate.
For the past several years, the gate had been continuously manned.
In the spring of 1996, the inspectors were briefed by the licensee concerning a planned change to this policy.
Licensee managers informed the inspectors that a reduction in manning at
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the NANIC gate was planned to reduce personnel costs. The policy was being changed to man the NANIC gate only during daylight hours during the summer months and during refueling outages.
During the most recent outage occurring in September October 1996, the ins)ectors observed that the NANIC gate was unoccupied on several occasions aetween 6:00 p.m. and 6:00 a.m.
The inspectors also observed that the NANIC gate was not manned at all since the outage was completed on October 13 until the inspection period's end.
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The inspectors reviewed the licensee's Security Plan and did not find any requirements for manning the NANIC gate.
In general, the site Security Plan had no specific requirements for security outside the protected area, which was consistent with NRC regulations. The
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inspectors also reviewed Security Plan sections associated with the Independent Spent Fuel Storage Installation (ISFSI) planned for construction at North Anna in 1997. The inspectors found that the Security Plan requirements for the ISFSI also had no specific requirements for security outside the ISFSI protected area, which was consistent with NRC regulations.
The inspectors noted that the licensee was discussing this issue with local officials of Louisa County. The local officials, who were reviewing the licensee's application for a land use permit for the ISFSI, requested that as a condition for allowing ISFSI construction, the NANIC gate be manned at all times. The licensee was considering the local officials' request at the inspection period's en =.
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Conclusions The inspectors concluded that the licensee was not currently manning the NANIC gate full time. However, no NRC requirements were identified to
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require such manning.
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VI. Manaaement Meetinas l
X1 Exit Meeting Summary The inspectors ) resented the inspection results to members of licensee
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i management at t1e conclusion of the inspection on November 12 and December 2, 1996. The licensee acknowledged the findings presented.
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The inspectors asked the-licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was
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identified.
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s PARTIAL LIST OF PERSONS CONTACTED Licensee W. Anthes, Superintendent, Outage and Planning B. Foster, Superintendent, Station Engineering C. Funderburk, Former Superintendent, Outage and Planning E. Grecheck, Assistant Station Manager, Operations and Maintenance J. Hayes, Superintendent, Operations D. Heacock. Assistant Station Manager, Nuclear Safety and Licensing H. Kansler Vice President, Nuclear Operations P. Kemp, Supervisor, Licensing
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T. Maddy, Superintendent, Security i
W. Matthews, Station Manager i
M. McCarthy, Director, Nuclear Oversight D. Roberts, Supervisor, Station Nuclear Safety
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H. Royal, Superintendent, Nuclear Training D. Schappell, Superintendent, Site Services R. Shears, Superintendent Maintenance J. Smith, Former Superintendent, Station Engineering
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A. Stafford, Superintendent, Radiological Protection j
NRC
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K. Barr, Branch Chief, Plant Support INSPECTION PROCEDURES USED
IP 37551:
Onsite Engineering IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving and Preventing Problems IP 62707:
Maintenance Observ3tions IP 71707:
Plant Operations IP 71750:
Plant Support Activities
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IP 83750:
Occupational Radiation Exposure IP 84750:
Radioactive Waste Treatment and Effluent and Environmental
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Monitoring IP 86750:
Solid Radioactive Waste Management and Transportation of Radioactive Materials i
IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92902:
Followup - Maintenance IP 92903:
Followup - Engineering IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors TI 2515/133:
Implementation of Revised 49 CFR Parts 100 179 and 10 CFR Part 71 ITEMS OPENED AND CLOSED
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j Opened
50 338, 339/96010 01 NCV Failure to Follow Procedures for System Tag outs
(Section 01.5)
50 338, 339/96010 02 VIO Three Failures to Implement Maintenance Rule i
Requirements for Cause Evaluations l
(Section H2.1)
50 338, 339/96010 03 NCV Inadequate Surveillance for Waste Gas Oxygen Alarm (Section M8.4)
50 338, 339/96010 04 IFI Documentation of the Technical Basis for HP Conversion Factors (Section R2.1)
EA 96 322 01014 VIO Failure to Meet State of South Carolina Radioactive Material License and 10 CFR 61.56(a)(3) (Section R8.1)
Closed 50 339/95015 02 VIO Two MOVs Modified Without Proper Design Change Review (Section M8.1)
50 338, 339/96001 02 VIO Unreviewed Modifications to Containment Blowout Panels (Section E8.1)
50 339/96002 LER Feedwater Check Valve Excessive Leakage (Section M8.3)
50-338/96003-02 VIO A RCS Loop Flow Transmitter Tubing Frame Support Found Partially Disassembled (Section M8.2)
50 338, 339/96007 LER Failure to Functional Check Waste Gas Decay Tank Hydrogen /0xygen Analyzer Alarm (Section M8.4)
50 338, 339/96007-03 URI Failure to Meet State of South Carolina Radioactive Material License and 10 CFR 61.56(a)(3) (Section R8.1) (EA 96-322)
50-338, 339/96010 01 NCV Two Failures to Follow Procedures for System Tag-outs (Sections 01.5 and 04.2)
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50-338, 339/96010 03 NCV Inadequate Surveillance for Waste Gas Oxygen Alarm (Section M8.4)
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