IR 05000445/1999007
| ML20206S591 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 05/11/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20206S589 | List: |
| References | |
| 50-445-99-07, 50-445-99-7, 50-446-99-07, 50-446-99-7, NUDOCS 9905210166 | |
| Download: ML20206S591 (20) | |
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ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.:
50-445 50-446 License Nos.:
NPF-87 NPF-89 Report No.:
50-445/99-07 50-446/99-07 Licansee:
TU Electric Facility:
Comanche Peak Steam Electric Station, Units 1 and 2 Location:
March 7 through April 17,1999 Inspectors:
Anthony T. Gody, Senior Resident inspector Scott C. Schwind, Resident inspector Wayne Sifre, Resident inspector Don Allen, Project Engineer Clifford Clark, Reactor Engineer
Approved By:
Joseph I. Tapia, Chief, Project Branch A Division of Reactor Projects ATTACHMENT: Supplemental Information 9905210166 990511 i
PDR ADOCK 05000445 I
G PDR
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EXECUTIVE SUMMARY Comanche Peak Steam Electric Station, Units 1 and 2 NRC Inspection Report No. 50-445/99-07; 50-446/99-07 This inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 6-week period of resident inspection.
Ooerations The conduct of operations reflected a conservative decision-making policy. Both units
were operated by knowledgeable operators using good self-verification and peer-checking techniques and communications. The shutdown for the fourth Unit 2 refueling outage was well controlled and, in contrast with past shutdowns for refueling outages, did not end in a reactor trip. The Unit 2 solid plant cooldown from 350"F to Mode 5 (less than 200"F) allowed better control of pressurizer surge line cooldown rates and was conducted without error. This was the first time operators conducted this procedure, and the lack of errors was attributed to effective self-and peer-verification and training (Sections O1.1, O1.2, and O1.3).
Midloop activities were conducted in accordance with procedures and were uneventful.
- Pre-evolution briefings were comprehensive. Management demonstrated conservative decision-making when the reactor coolant system draindown was delayed until after shift turnover. This minimized the time spent in a reduced inventory condition.
(Section 01.4).
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Operators responded to repeated failures of the Steam Generator 1-02 feedwater
regulating valve control system in a consistent manner that minimized the plant transients. Af ter f aulty control cards were replaced, no further failures occurred (Section O2.1).
Maintenance Maintenance activities were conducted in accordance with approved procedures and
good work practices. Effective communication between work organizations was observed. Personnel protective equipment was used appropriately and effective personnel safety practices were observed. Maintenance workers were careful to exclude foreign material from systems. Some minor problems were noted with the storage of nonplant equipment and foreign material exclusion, but all were corrected immediately by the licensee (Section M1.2).
Surveillance activities were generally conducted in accordance with approved
procedures and were well coordinated. Good self-checking and peer-verification was noted. Communications between personnel conducting surveillances were clear and included formal repeat backs (Section M1.3).
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-2-Although emergency core cooling flow balancing was acceptable, a minor problem
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involving the licensee not verifying the minimum throttle valve gap size prior to ordering the throttle valves locked and marked was identified by the inspector. Af ter checking throttle valve gap size, at least one throttle valve had to be unlocked and readjusted.
The flow balancing was reperformed with no problems (Section M1.3).
Enaineerina The licensee review of the auxiliary feedwater system was performed in such a way that
an adequate degree of confidence exists that deficient surveillance procedures for testing of system safety-related logic circuits have been properly identified and the surveillance procedures have been adequately revised (Section E8.1).
Based on a sample of Generic Letter 96-01 deficiencies identified by other licensees,
the licensee's Industry Operating Experience Report Review Program adequately addressed these deficiencies (Section E8.1).
Plant Support Licensee management demonstrated conservative decision-making when they
preapproved various radiation worker limitations and temporary shielding that increased the duration of the outage but minimized radiation worker dose. Overall, radiation protection personnel conducted effective radiation and contamination surveys. The p'anned dose for the Unit 2 refueling outage was 190 person-rem. Actual dose received was 101.7 person-rem, which was approximately 40 person-rem less than the last Unit 2 refueling outage (Section R1.2).
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Report Details Summarv of Plant Status Unit 1 remained at approximately 100 percent power for the entire inspection period. Unit 2 began the inspection period at 100 percent power and was shut down on March 19,1999, for its fourth refueling outage. Unit 2 remained in the refueling outage until the end of the report period.
1. Operations
Conduct of Operations 01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations reflected a conservative decision-making policy; noteworthy observations are detailed in the sections below.
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Through daily observations of control room activities, the inspectors concluded that both units were operated by knowledgeable operators using good self-verification techniques and communications.
01.2 Unit 2 Shutdown a.
Inspection Scoce (71707)
The inspectors observed the Unit 2 shutdown for the fourth refueling outage and conducted plant tours, b.
Observations and Findinas Operators compensated well for minor heater drain and condensate system problems during the shutdown when portions of these systems had to be operated manually. The inspector noted that this was the first successful controlled shutdown on Unit 2 for a refueling outage in that the shutdown was completed without a significant transient or trip, in the past, controlled Unit 2 shutdowns had been terminated by tripping the reactor when rod control or steam plant system failures occurred.
The inspectors observed operators communicate effectively. Changing conditions were anticipated and properly communicated. During low power operations, the reactor operator was particularly effective in communicating needed main turbine power changes. Annunciators were quickly acknowledged and announced. When the alarm was not expected for the shutdown, the alarm manual was referenced. Where practical, operators used effective peer-checking. When peer-checking was not practical, operators used good self-verification technique.
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-2-01.3 Unit 2 Reactor Coolant System Cooldown a.
Inspection Scope (71707)
The inspectors observed control room operators cool down the Unit 2 reactor coolant system to Mode 5 (less than 200*F).
b.
Observations and Findinas During the Unit 2 shutdown, operators used new procedures to bring the reactor coolant system solid at 350*F. The solid plant cool down from 350*F to Mode 5 (less than 200*F) allowed operators to more effectively control pressurizer surge line cooldown
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rates and minimize thermal stress. Operators conducted the cooldown in accordance with the procedure and did not exceed limitations. Operators continued to demonstrate good communications and effective self-and peer-verification, resulting in no personnel errors during the cooldown. Effective training had been conducted on the solid plant cooldown prior to the outage.
When the reactor coolant system was at approximately 285*F, operators broke condenser vacuum and continued the plant cooldown to Mode 5 using the steam generator atmospheric relief valves. The inspectors observed good command and control by the unit supervisor and conservative plant operations. The cooldown rate was maintained within prescribed limits.
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Conclusions The inspectors observed good command and control by control room supervision and good communications by operators during the Unit 2 reactor coolant system cooldown to less than 200*F. Cooldown with the pressurizer solid proved easier to control than past cooldowns and minimized the potential for excessive thermal stress on welded components.
01.4 Midlooo Operations a.
Insoection Scope (71707)
The inspectors performed continuous control room observations while the licensee drained the Unit 2 reactor coolant system to a midloop condition in order to remove j
nozzle dams from the remaining two steam generators.
b.
Observations and Findinas l
The control room preevolution briefings for the draindown to the midloop level and the L
subsequent vacuum fill of the reactor coolant system were comprehensive.
The licensee postponed the reactor coolant system draindown to midloop until after shift turnover, which allowed them to have personnel staged on the steam generator platforms ready to remove the nozzle dams when midloop level was achieved. This
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a-3-minimized the time spent in midloop and reflected a conservative decision-making policy which was not affected by outage schedule pressures. The draindown evolution was well controlled and uneventful. The steam generator nozzle dams were removed, and l
steam generator and pressurizer manways were installed in approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />.
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After installation of all reactor coolant system manways, operators commenced drawing a vacuum on the reactor coolant system in preparation for refilling it. While drawing the vacuum, all level instruments tracked well except for the newly installed Mansell reactor levelinstrument. The licensee believed that there may have been a loop seal between j
the reactor head vent nozzle and the pressure transducer for this instrument. Operators only used the Mansell system for trending reactor coolant system level. The wide-range
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l instrument was used to track level. Overall, the vacuum fill evolution was well
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controlled. Operators used good communications and self-checking techniques. They were also sensitive to performance of the residual heat removal (RHR) system, especially while drawing the vacuum.
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Conclusions Midloop activities were conducted in accordance with procedures and were uneventful.
Preevolution briefings were comprehensive. Level instrumentation operated as designed. Management demonstrated conservative decision-making when the draindown was postponed until after shift turnover. This minimized the time in a reduced inventory condition.
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Operation Status of Facilities and Equipment O2.1 Unit 2 Shutdown Coolina Systems a.
Insoection Scoce (71707)
The inspector performed periodic walkdowns of the Unit 2 shutdown cooling systems while the plant was in Modes 4 and 5.
b.
Observations and Findinas The inspector walked down accessible portions of the Unit 2, Train A auxiliary i
feedwater (AFW) system, RHR syst'em, component cooling water system, and service water system. At the time, Unit 2 operators were cooling the plant from Mode 4 to Mode 5 using the steam generator atmospheric relief valves and motor-driven AFW Pump 2-01. !n addition, RHR Pump 2-01 and RHR Heat Exchanger 2-01 were in service. The inspector observed the start of motor-driven AFW Pump 2-01. A plant
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equipment operator was also present during pump start and was very attentive to the equipment condition. Although both pump bearing oilers were above the minimum allowable levels, he added oil to both bearing oilers because they were slightly lower than normal. This demonstrated ownership of plant equipment.
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-4-Periodic walkdowns of the spent fuel pool cooling and the RHR systems during the outage revealed that they were operating properly with no notable leakage. Plant material condition was good.
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Conclusions Systems required to support decay heat removal and plant cooldown were in good material condition and properly aligned. Plant equipment operators were attentive to the status of plant equipment.
02.2 Operational Status of Facilities and Eauiomenj a.
Insoection Scoce (71707)
The inspectors conducted frequent tours of the following areas of the plant:
Units 1 and 2 safeguards buildings Units 1 and 2 auxiliary buildings Units 1 and 2 electrical control buildings Unit 2 containment building Unit 2 containment sumps Units 1 and 2 turbine buildings 345kV Switchyard b.
Observations and Findinos
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Overall, the inspectors noted that plant equipment was in good material condition and in its proper standby or operating condition. Extensive scaffolding was erected in support of the outage, but did not interfere with safety-related equipment. Outage equipment and supplies were staged to support specific activities, but did not interfere with access i
or other activities. Specific observations are discussed below.
The inspectors walked down all Train A engineered safety features equipment while the Train B diesel generator was out of service for inspection. Included in the Train A walkdown were emergency core cooling systems, the diesel generator, and Class 1 E switchgear. All systems were appropriately aligned for either standby operation or shutdown cooling operation. In addition, the licensee appropriately cordoned off areas containing Train A equipment and labeled these areas to remind personnel that Train A was required for shutdown cooling.
The inspectors walked down the 345 kV switchyard during work on Breaker 8020 (one of the Unit 2 main generator output breakers). This work was conducted while the Unit 2 reactor coolant system was in a reduced inventory condition (reactor vessel level was at approximately 120 inches above the core plate) and the Train B diesel generator was out of service. Access to the switchyard and the work area around the breaker and the ring bus was well controlled. Disconnects for both main generator output breakers were opened. While work continued on Breaker 8020, the inspectors noticed a boom truck in the switchyard with the boom extended in order to work on the bushings on the tower
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boom was not in the vicinity of any other energized line or bus. At the time, the outage risk assessment was in an orange condition; however, the defense-in-depth strategies in effect (DID-1, " Loss of Shutdown Cooling") did not prohibit any specific type of switchyard activity until reactor vessel level was 80 inches above the core plate. There was no activity in the 138 kV switchyard at the time.
During outage conditions that relied on Train B for decay heat removal, caution signs were posted around various Train B equipment stating " Defense-in-Depth, Prior to working on this equipment contact Outage Control Center." No work was being performed on this equipment. These signs provided additional control of the configuration of important equipment during a period of high maintenance activity.
The inspectors walked down accessible portions of the Mansell level indication system.
The inspectors noted that despite several extremely long instrument tubing runs, the tubes were sloped and supported well with no loop seals.
The inspector performed a containment sump close-out inspection with licensee personnel. The sumps were clean of debris, and no major work had been performed in them this outage. The plant equipment operator assigned to perform the inspection was very thorough.
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Conclusions The inspectors observed that the plant material condition continued to be good.
Scaffolding and outage supplies were erected and staged as not to interfere with other activities. Caution signs posted around operable equipment to prevent unauthorized work during a period of high maintenance activity was a good practice.
O2 Operational Status of Facilities and Equipment O2.1 Failure of Unit 1 Feedwater Reaulatina Valve FCV 520 a.
Inspection Scope (71707)
The inspectors observed operators respond to failure of the feedwater regulating valve for Steam Generator 1-02 in Unit 1.
b.
Observations and Findinas On March 17,1999, feedwater regulating Valve FCV 520 on Unit 1, Steam Generator 1-02 began to drift shut. The control room received a low-low steam generator water level alarm and steam flow / feed flow mismatch alarm, at which point l
they took manual control of the valve and restored level in Steam Generator 1-02.
Troubleshooting efforts were unable to identify the root cause as the failure was intermittent. After the fault cleared, FCV 520 was returned to automatic and monitoring instruments were connected in the level control cabinet. The valve remained in
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automatic with no failures for 10 days. On March 26, the valve began to drift shut again.
During this occurrence, operators were able to take manual control of the valve and
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restore its position prior to receiving any steam generator level alarms. The monitoring
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equipment staged at the level control cabinet irdicated a bad auto control card, which was replaced, and the valve was returned to automatic. Later the same day, the valve failed again. Operators again responded before a significant plant transient occurred by placing FCV 520 in manual and restoring steam generator level to normal. The auto control card was again replaced, FCV 520 was returned to normal, and no further failures occurred.
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Conclusions Operators responded well to repeated failures of FCV 520 to operate in automatic.
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This was an isolated failure.
II. Maintenance M1 Conduct of Maintenance M1.1 General Comments (61726. 62707)
Using Inspection Procedures 61726 and 62707, the inspectors conducted frequent reviews of ongoing maintenance and surveillance activities. In general, the conduct of maintenance and surveillance activities reflected a policy of procedure adherence and quality; noteworthy observations are detailed in the sections below. Through daily observations of maintenance and surveillance activities, the inspectors concluded that maintenance and surveillance activities were conducted by knowledgeable personnel using good self-and peer-verification techniques and communications.
M1.2 Maintenance Observations a.
inspection Scope (62707)
The inspectors conducted periodic observations on the following activities:
Unit 2 high pressure turbine maintenance Unit 2 containment equipment hatch removal Unit 2 emergency diesel generator maintenance Unit 2 main turbine inspection / rotor replacement Unit 2 reactor vessel head removal Unit 2 safety injection accumulator motor-operated valve testing Unit 2 emergency core cooling system throttle valve replacement Unit 2 reactor coolant pump motor replacement Unit 2 containment cooler installation Unit 2 Mansell level instrument installation
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Observations and Findinos Overall, the inspectors found that maintenance activities were conducted in accordance with approved procedures and good work practices. Effective communication between work organizations was observed. Personnel protective equipment was used appropriately, and effective personnel safety practices were observed. Maintenance workers were careful to exclude foreign material from systems. Some minor problems were noted with the storage of nonplant equipment and foreign material exclusion, but all were corrected immediately by the licensee. Specific details are noted below.
The inspectors observed portions of the cylinder liner inspections performed on the Unit 2 Train B diesel generator. Four cylinders were disassembled and inspected during the outage. The inspectors noted that the foreign material exclusion covers on two of the cylinders were sliding off and could potentially allow debris to enter those cylinders.
j This was brought to the attention of the licensee and was immediately corrected.
The inspectors observed disassembly of the Unit 2 main turbine. The inspector noted small debris (nails, wire, insulation debris, etc.) around the flange on the lower high pressure turbine casing which could be knocked or blown into the condenser. The inspectors discussed this with the licensee, and it was corrected The inspectors observed the Unit 2 reactor vessel head lift. The evolution was slow and well controlled. During the lift, a reactor vessellevel indication system probe on the
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north side of the head was caught in its vessel head penetration. The lift was stopped, l
and the problem was corrected prior to resuming the lift.
The inspector observed the safety injection accumulator discharge motor-operated valve tests for Accumulators 1,3, and 4 from containment and the control room. Although the accumulators were pressurized to 50 psig, there was enough nitrogen dissolved in the s
water that, as it was injected into the reactor coolant, bubbles were visible from above the reactor vessel. Since the Train A RHR pump was in service filling the refueling cavity from the refueling water storage tank during the test, the bubbles would have had no adverse affect on the pump. Train B RHR was originally in service for shutdown cooling; however, the operators anticipated gas coming out of solution and temporarily secured the pump during the accumulator injections to prevent gas binding. The inspector observed control room operators test the safety injection Accumulator 4 motor-operated valve. Operators attempted to open the valve from the control room, but a plant equipment operator stationed by the valve in containment reported that the valve did not move. There was also no indication of valve movement in the control room and the *MOV trouble" annunciator alarmed. The plant equipment operator reported smoke j
from the actuator motor, and an operator was immediately dispatched to the motor I
control center to open the breaker for the valve.
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Conclusions The conduct of maintenance activities was good. Personnelinvolved in maintenance adhered to approved work procedures and good work practices. Foreign material exclusion controls were generally good, with some minor exceptions noted.
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Insoection Scoce (61726)
j The inspectors observed all or portions of the following surveillances:
Emergency Core Cooling System Flow Balancing
Loss of Offsite Power Test, Train A
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Safety injection with Loss of Offsite Power Test, Train A
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Observations and Findinas The inspectors concluded that each of these surveillance activities was performed satisfactorily. The activities were well coordinated with the other operators and technicians supporting the tests. The loss of offsite power tests were performed with the reactor vessel level above the level for reduced inventory, and a dedicated operator was assigned to monitor and control reactor vessel level and associated systems. The dedicated operator was aware of the tests but not distracted by them and responded correctly to resulting changes in systems flows and temperatures. These procedures had been recently converted from engineering procedures to operations surveillance procedures, and this was the first time they were used. The tests were performed without problem or procedure changes. Good self-checking and peer-checking was observed during control switch manipulations. Communications between the operator performing the test and other support personnel were clear and included formal repeat backs. Between the diesel starts associated with the tests, sufficient time elapsed to require a " water roll" of the diesel to check for condensation in the cylinders. The operators were cognizant of the requirements, and the water roll was performed as required.
The inspector noted that the lead test engineer for the emergency core cooling flow balancing involved himself in both calculations and data entry, as well as leading the surveillance test. This may have contributed to a minor error involving an order to mark and lock throttle valves prior to verification of proper gap size. After the inspector questioned the lead engineer on how they verified minimum gap size, the lead engineer stopped the marking and locking effort and redirected personnel in the field to measure throttle valve gap size. Three of the four throttle valves had already been marked and locked. At least one of the valves did not meet the minimum gap size requirements, and the flow balance test had to be reperformed once the minimum gap size was achieved.
Reperforming the flow balance for those throttle valves posed no significant impact to the surveillance test other than slightly increasing dose to workers in the field, c.
Conclusions The loss of offsite power and safety injection with loss of offsite power surveillances were performed satisfactorily. The activities were well coordinated with the other operators and technicians supporting the tests. Good self-and peer-checking were observed during control switch manipulations. Communications between the operator performing the tests and other support personnel were clear and included formal repeat-back.g.
Emergency core cooling flow balancing was acceptable. A minor problem involving the licensee not verifying the minimum throttle valve gap size prior to ordering the throttle i
valves locked and marked was identified by the inspector. After checking minimum gap size, at least one throttle valve had to be unlocked and readjusted. The flow balancing was performed again without any significant problems.
Ill. Enaineerina E1 Conduct of Engineering E1.1 General Observations (71707. 37551)
Using inspection Procedure 71707 and 37551, the inspectors conducted frequent reviews of ongoing engineering support to plant operations and the Unit 2 refueling outage. In general, engineering activities served to maintain the plant design and licensing bases, evaluations were clear and concise, the threshold for reporting issues to the NRC was appropriate, and system engineering involvement in day-to-day activities was evident. Noteworthy observations are detailed in the sections below.
E1.2 Desian Modifications a.
Inspection Scope (37551)
The inspector conducted a review of a design change involving the installation of a new reactor coolant system midloop level indication system.
b.
Observations and Findinas The inspector noted that the design change had been reviewed by the appropriate engineering and nonengineering organizations. Planning for installation of the modification appropriately included a review to maintain radiation dose as low as reasonably achievable (ALARA). The safety evaluation screen appropriately concluded that the design change modified the facility as described in the Final Safety Analysis Report and included a safety evaluation. The safety evaluation concluded that the design change did not involve an unreviewed safety question as described in 10 CFR 50.59, " Safety Evaluations." The inspector found that sufficient details were contained in the design modification to provide assurance that the conclusions of the safety evaluation were accurate.
E8 Miscellaneous Engineering issues E8.1 (Closed) Temocrary Instruction 2515/139. " Inspection of Licensee's Implementation of Generic Letter 96-01 Testina of Safetv-Related Loaic Circuits."
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Inspection Scope (Tl 2515/139)
The inspector reviewed the licensee's verification of the adequacy of programs, procedures, training, and supporting documentation associated with the surveillance testing of safety-related logic circuits required by Technical Specification.
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Observations and Findinas Generic Letter 96-01 was issued January 10,1996. Generic Letter 96-01 requested that licensees review electrical schematic drawings and logic diagrams for the reactor protection system, emergency diesel generator load shedding and sequencing, and actuation logic for the engineered safety features systems against plant surveillance test procedures to ensure that Technical Specification required surveillance were being properly performed.
The inspector noted that Unresolved item 50-445(446)/9802-01, which addressed Licensee Event Report (LER) 50-445/97004-00 through 06," Inadequate Surveillance i
Testing identified During the Licensee's Review of NRC Generic Letter 96-01, ' Testing of Safety-Related Logic Circuits,'" was closed in Section E8.1 of NRC Inspection Report 50-445/98-06;50-446/98-06. During closure of the unresolved item, the inspectors documented that the licensee identified that Technical Specification required j
surveillance tests had failed to include or adequately test over 500 safety-related relay
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The inspector, after reviewing the above information, held discussions with the system engineers who performed the licensee's Generic Letter 96-01 review of the AFW system to determine what licensee review actions were implemented. The inspector performed an inspection of the Unit 1, Train A, AFW system to independently confirm that the logic circuitry, including parallel logic, interlocks, bypasses and inhibit circuits, were adequately covered in the AFW system surveillance procedures. The inspector also inspected the licensee's program to review Generic Letter 96-01 deficiencies identified at other facilities.
The inspector reviewed the AFW system design documerits and drawings listed in the attachment to this report and selected components and associated logic circuits for review. The inspector reviewed the surveillance procedures identified in the attachment to this report, which implemented testing of the AFW system safety-related logic circuits.
The inspector independently confirmed that the AFW system safety-related logic circuits, including parallel logic, interlocks, bypasses and inhibit circuits, were adequately addressed in the reviewed surveillance procedures.
The inspector reviewed Procedure NOA 2.30," Industry Operating Experience Report Review Program,' Revision 5, and held discussions with licensee personnel involved in implementation of the program. The inspector reviewed the licensee program records listed in the attachment to this report and associated documents to ensure a sample selection of Generic Letter 96-01 related deficiencies identified at other facilities had been properly identified, integrated, and processed in the licensee's program. The inspector verified that this had been accomplished.
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The inspector concluded that the licensee's review of the AFW system was performed in l
such a way that an adequate degree of confidence exists that deficient surveillance l
procedures have been properly identified and they have been adequately revised for
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testing of system safety-related logic circuits. The inspector reviewed a sample of l
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IV. Plant Support R1 Radiological Protection and Chemistry Controls R1.1 General Comments (71750)
Using inspection Procedure 71750, the inspectors conducted reviews of various activities such as maintenance, surveillance, irradiated fuel assembly movement, core alterations, and plant operations. In general, the conduct of radiation workers reflected i
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knowledge of radiation work permit requirements, contamination control techniques, and a general sensitivity towards maintaining dose ALARA.
R1.2 Radioloaical Dose Control a.
inspection Scope (71750)
The inspectors toured various portions of Unit 2 during the refueling outage to determine how effective the licensee maintained dose ALARA, particularly when plant conditions were changing such as during a planned crud burst, through radiological postings, and limiting radiation worker access to radiation areas.
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The inspector noted that all levels of site personnel were involved in minimizing radiation worker dose. Management demonstrated conservative decision-making when they preapproved various radiation worker access limitations and temporary chielding l
installations that increased the length of the outage but clearly minimized the dose to the l
worker. Radiation protection personnel conducted effective radiation surveys with very few exceptions. None of the exceptions were significant or resulted in an increased dose to the radiation worker.
The inspector noted that the appropriate areas within the Unit 2 safeguards building had been properly posted as high radiation areas after the RHR system was placed into service. These postings included the Train A RHR heat exchanger, emergency core cooling system valve, RHR pump, and containment spray pump rooms.
Radiation worker access to the reactor coolant system loop rooms was appropriately limited to maintain dose ALARA during crud burst operations.
The planned dose for the Unit 2 refueling outage was 190 person-rem. Actual dose received was 101.7 person-rem, which was approximately 40 person-rem less than the last Unit 2 refueling outage. Although the planned dose was not particularly challenging, the licensee was very effective in maintaining dose ALAR c.
Conclusions i
i The licensee maintained dose to radiation workers ALARA during the Unit 2 fourth refueling outage through effective management, oversight, postings, shielding, and access limitations.
R1.3 Samolina and Chemistry a.
inspection Scoce (71750)
The inspectors observed the licensee conduct reactor coolant sampling, b.
Observations and Findinos inspectors observed chemistry personnel sample reactor coolant and prepare the sample for analysis during the Unit 2 shutdown. Samples were appropriately obtained in accordance with procedures, and chemistry personnel were observed using appropriate chemistry, radiological, and personnel practices during the performance of these tasks.
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Conclusions Personnel observed sampling the reactor coolant system obtained the required samples in accordance with procedures and in compliance with requirements.
R4 Staff Knowledge and Performance R4.1 Radiation Worker Knowledae a,
Insoection Scoce (71750)
The inspectors observed radiation workers conduct activities such as maintenance, surveillance, irradiated fuel assembly movement, core alterations, inspections, and plant operations within radiologically controlled areas of the plant. In addition, the inspectors verbally tested a number of radiation workers on their assigned radiation work permit requirements, b.
Observations and Findinas The inspectors observed radiation workers use good contamination control techniques.
l Dosimetry was worn in appropriate locations for the work being conducted, and low-dose waiting areas were used effectively. Radiation workers were appropriately cautious of changing radiological conditions, were observed to quickly raise radiological issues to radiation protection personnel, and were sensitive to maintaining dose ALARA.
The inspectors observed one isolated instance of a group of contract radiation workers I
not appropriately responding to an airborne contamination alarm. In response to the inspector's concern, licensee management appropriately reinstructed contract radiation
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workers on how to respond to an airborne contamination alarm. No subsequent examples were noted.
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Conclusions Radiation workers were knowledgeable of their radiation work permit requirements and
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I maintained dose ALARA.
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S1 Conduct of Security and Safeguards Activities l
S1.1 General a.
Inspection Scoce (71750)
The inspectors conducted frequent reviews of various security-related activities such as personnel access control, package receipt inspection, weapon control, attentiveness, and security system maintenance.
b.
Observations and Findinas The conduct of security officers reflected a thorough knowledge of the plant security plan, knowledge of security system operation, a high level of attentiveness, and a willingness to enforce, and knowledge of, general employee training expectations associated with radiation work permit requirements.
F4 Fire Protection Staff Knowledge and Performance F4.1 Fire Drills a.
Inspection Scope (71750)
The inspector questioned a fire watch on the meaning of a flashing blue light in a high noise area.
b.
Observations and Findinas On April 8,1999, while observing outage activities in the Unit 2 turbine building, a fire drill was performed which included sounding the fire alarms. In high noise areas, a flashing blue light accompanied the fire alarm to alert individuals who could potentially not hear the alarm. A fire watch, monitoring a welding activity, was unaware of the
. purpose of the flashing blue light. There were no signs in the vicinity of the blue light to indicate its function. The inspector informed the licensee of this isolated finding. The licensee stated that the inspector's observation would be shared with other personnel.
No other similar observation of this knowledge deficiency was note,
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V. Manaaement Meetinas X1 Exit Meeting Summary The inspector presented the results of the inspection to members of licensee management on April 20,1999. The licensee acknowledged the findings presented. No proprietary information was identified.
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ATTACHMENT SUPPLEMENTAL INFORMATION PARTIAL LIST OF PERSONS CONTACTED Licensee
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C. L. Terry, Senior Vice President and Principal Nuclear Officer
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M. R. Blevins, Vice President, Nuclear Operations J.J. Kelly, Vice President, Nuclear Engineering and Support J.R. Curtis, Radiation Protection Manager R. Flores, System Engineering Manager D.L. Walling, Plant Modification Manager D. Kross, Outage Manager D.L. Davis, Nuclear Overview Manager INSPECTION PROCEDURES USED IP 37551 Onsite Engineering IP 61726 Surveillance Observations IP 62707 Maintenance Observations IP 71707 Plant Operations IP 71750 Plant Support Activities
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Tl 2515/139 Inspection of Licensee's Implementation of Generic Letter 96-01 Testing of Safety-Related Logic Circuits ITEMS OPENED. CLOSED. AND DISCUSSED Opened None Closed Tl Temporary Instruction 2515/139," Inspection of Licensee's implementation of Generic Letter 96-01 Testing of Safety Related Logic Circuits." (Section E8.1)
Discussed None
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-2-DOCUMENTS REVIEWED
Procedures l
DBD-ME-206, " Auxiliary Feedwater System," Revision 9 (Section 6.0)
NOA 2.30, " Industry Operating Experience Report Review Program," Revision 5 OPT-450A, " Train A Safeguards Slave Relay K640 Actuation Test," Procedure Change No. OPT-450A-R6-1 OPT-451 A," Train A Safeguards Slave Relay K641 Actuation Test," Procedure Change No. OPT-451 A R6-1 OPT 463A," Train A Safeguards Slave Relay K601 Actuation Test," Procedure Change No. OPT-463A-R6-2 i
OPT-468A," Train A Safeguards Slave Relay K610 Actuation Test," Procedure Change
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No. OPT-468A-R6-1 OPT-511 A, "Feedwater Section XI Isolation Valves," Procedure Change No. OPT-511 A-R8-3
PPT-SI-7408A, " Train A Diesel Generator 24 Hour Load Test," Revision 2 PPT-St-7410A, " Safety injection in Conjunction with Loss of Offsite Power Train A," Revision 2 PPT-St-7414A," Safety injection without Loss of Offsite Power Train A," Revision 2 Other Documents Comanche Peak Steam Electric Station Response to Generic Letter 96-01," Testing of Safety-Related Logic Circuits," dated May 19,1998 Operation Notification Evaluation (ONE) Form 98-641 Operations Notification Evaluation (ONE)- Plant incident Report (PIR)
97-000641-00-00 97-001091-00-00 97-001465-00-00 98-000182-00-00 98-000184-00-00 98-000247-00-00 98-000290-00-00 98-000296-00-00 98-000306-00-00
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-3-98-000366-00-00 98-000578-00-00 98-000641-00-00 Drawinas 2462-1004, Sheets 1 & 2 " Internals Wiring Diagram Solid State Safeguard Sequencer,"
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Revision CP-2 8760D60, Sheets 19,20, & 26, " Solid State Protection System Interconnection Diagram Unit 1 and Unit 2," Revision CP-1 E1-0031, Sheet 37, "6.9 KV Switchgear Bus 1EA1 Auxiliary Feedwater Pump 11 TAG CP1-AFAPMD-01 Beaker 1 APMD1 Schematic Diagram," Revision CP-6 E1-0037, Sheet 15, " Motor Operated Valve 1-HV-2484 Condensate Storage Tank to Condensate System Make-Up Rejection Isolation Valve," Revision CP-5 E10037, Sheet 19, " Auxiliary Relays 1 HX/2450A, B, C, and 1-HX/2451 A, B, C",
Revision CP-5
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E1-0037, Sheet 32, " Solenoid Operated Valve 1-HV-2452-1 Turbine Driven Auxiliary Feedwater Pump Main Steam Header 1 isolation Valve Schematic Diagram," Revision CP-7 E1-0038, Sheet 64, " Solenoid Operated Valve 1-FV-2181 Feedwater Loop 1 to Steam Generator 1 Feedwater Split Flow Bypass Valve," Revision CP-5 E1-0070, Sheet 25, " Auxiliary Relays 1-KXA/71 A,1-KA/71 A1,1-KXA/87A,1-KXA/131 A, and 1-KXA/1318," Revision CP-6
- Industry Ooeratina Experience Report Assianment/Trackina Sheets (and Packaaes) for lofgr. ation Notices f rm 88-33 91-13 92-40 93-15 93-38 95-15 l
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