IR 05000454/1989001
| ML20235U813 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 02/28/1989 |
| From: | Hinds J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20235U808 | List: |
| References | |
| 50-454-89-01, 50-454-89-1, 50-455-89-01, 50-455-89-1, NUDOCS 8903090381 | |
| Download: ML20235U813 (14) | |
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U.'S. NUCLEAR REGULATORY COMMISSION
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REGION III
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Report Nos. 50-454/89001(DRP);50-455/89001(DRP)
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Docket Nos.- 50-454; 50-455-License Nos. NPF-37; NPF-66
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i Licensee: Commonwealth Edison Company Post-Office Box 767
p Chicago, IL 60690 i
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Facility Name:
Byron Station, Units 1 and 2 Inspection At: Byron Station, Byron', Illinois ~
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Inspection Conducted: January 1 - February 16, 1989 Inspectors:
P. G. ' Broc.hman N. V. Gilles
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o Approved B.
J.
. Hind [,
ef FEB 2 81989 l
ctor Projects Section 1A Date i
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Inspection Summary-Inspection from-January 1 - February'16, 1989 (Report Nos. 50-454/89001(DRP);
50-455/89001(DRP))
Areas Inspected:
1. Routine, unannounced safety inspection by the resident
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inspectors of licensee action on previous inspection findings; operational i
safety; event follow-up; refueling and spent fuel pit activities;
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. maintenance / surveillance; licensee actions in response to suspected drug
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use; 1icensee's implementation of strike plans; licensee event reports; TMI
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action. items;. headquarters requests; management changes; and meetings.
2.'SIMS issue status for Units 1 and 2: Closed I.C.7.1; Closed.I.C.7.2.
Results:. Of the 10 areas inspected, no violations or deviations were identified in 9 areas; 1 violation'was identified in the remaining area;
-(failure to perform Technical Specification required surveillance within the specified time limit - paragraph 6.a) however, in accordance with 10 CFR Part 2,' Appendix C,Section V.G.1, a Notice of Violation was not issued. One
unresolved item concerning inadequate control of maintenance activities on Limitorque valves was identified.
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8903090381 890229~50\\ "@
PDR ADOCK 05000454 G
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- e DETAILS
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LPersons Contacted'
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Commo'nuealth' Edison Company-
- R. Pleniewicz, Station Manager.
- G. Schwartz,. Production Superintendent
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- R. Ward,. Technical Superintendent
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- J.,Kudalis, Director of Services.
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-D..Winchester, Quality Assurance Superintendent-
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- T. Tulon,: Assistant' Superintendent, Maintenance T. Higgins, Assistant Superintendent, Operating-
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L. Sues, Assistant Superintendent, Technical Services D. St.. Clair,. Assistant Superintendent, Work Planning J. Schrock, Operating. Engineer, Unit 1 D. Brindle, Operating Engineer, Unit 2 T. Didier, Operating Engineer, Rad-Waste
- M.' Snow, Regulatory Assurance Supervisor
- R. Flahive, Technical Staff Supervisor S. Barret, Health Physics Supervisor S. Wilson,. Chemistry Supervisor P. O'Neil,' Quality Control Supervisor R. Lucas, Security Supervisor
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A. Chernick, Training Supervisor
- W. Pirnat, Regulatory Assurance Staff
- E. Zittle, Regulatory Assurance Staff
- W. Dean, Onsite Nuclear Safety The 1nspector also contacted and interviewed other licensee and contractor personnel during the course of this inspection.
- Denotes those present during the exit interview on February 16,.
1989.
2.
Action of Previous-Inspection Findinjs (92701)
a.
(Closed) Unresolved Item (454/87039-02(DRP); 455/87036-02(DRP)):
Valve 00G066 foured in wrong position rendering hydrogen recombiner inoperable. The Byron Safety Evaluation Report (SER), Supplement 5, identified that the licensee committed to administrative controls to maintain the hydrogen recombiner discharge valves open.
This same discrepancy was also identified at Braidwood, and a Notice of Deviation was issued to the licensee.
Inspection Reports No.
456/87038; 457/87036. The inspector reviewed the licensee's response to the Deviation and verified that the corrective actions outlined in the Braidwood response have also been instituted at Byron, including the addition of valve 00G066 to the valve line-up, BOP OG-M2. Based on these actions, this item is considered closed.
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bpenItemslistedbelowhavebeenclosedduringthisinspection period based on a directive by the Division Director, Division of~
Reactor Safety, Region III as transmitted by memo from W. D. Shafer dated February 8:'1989.
The NRC's decision to close these items is based on the length of time the item has been in existence and the recognition of limited safety significance.
(Closed) Unresolved Item (454/85055-03(DRS)); Unresolved Item (454/86031-01; 455/86017-01(DRS)); Unresolved Item (454/86031-02; 455/86017-04(DRS)); Unresolved Item (454/86031-04(DRS)); Unresolved Item (454/86031-05(DRS)); Unresolved Item (454/86031-06; 455/86017-05(DRS)); Unresolved Item -(454/86031-07(DRS)); Unresolved Item (454/86031-08; 455/86017-08(DRS))- Unresolved Item (454/86031-09(DRS)); Unresolved Item (454/86031-11; 455/86017-11(DRS)); Unresolved Item (454/86031-12; 455/86017-12(DRS);UnresolvedItem{454/86031-13; 455/86017-13(DRS ; Unresolved It w,454/86031-14; 455/86017-14(DRS
- UnresolvedItem(454/86031-15; 455/86017-15(DRS
- Open Item (454/87014-01(DRS)); SER Item (454/87014-04(DRS));OpenItem(454/87025-01;455/87023-01(DRS));
Open Item (454/87025-02; 455/87023-02(DRS); Violation
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(454/88888-88(DRS)); Unresolved Item (455/86017-02(DRS)); Unresolved Item (455/86017-03(DRS)); Unresolved Item (455/86017-07(DRS));
Unresolved Item (455/86017-09(DRS)); Unresolved Item (455/86034 03(DRS)); Open Item (455/87015-01(DRS)).
3.
Plant Operations Unit 1 operated at power levels up to.100% until 9:56 a.m. on January 31, 1989, when the unit was manually tripped due to the IC feedwater regulating valve failing open (see paragraph 3.b.2).
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j unit was taken critical at 3:19 a.m. on February 1 and synchronized to the grid at 8:26 a.m. the same day. The unit operated at power levels up to 100% for the remainder of the report period.
Unit. 2 operated at power levels up to 35% until 12:21 a.m. on January 7, 1989, when the unit was taken off line for a scheduled 62-day refueling-outage. The unit remained shutdown for the rest of the report period.
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a.
Operational Safety (71707)
l The inspectors observed control room operation, reviewed applicable I
logs and conducted discussions with control room operators during January and February 1989.
During these discussions and observations, the inspectors ascertained that the operators were alert, cognizant of plant conditions, and attentive to changes in those conditions, and that they took prompt action when appropriate.
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The inspectors verified the operability of selected emergency l
systems, reviewed tagout records, and verified the proper return to
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service of affected components. Tours of the auxiliary, j
fuel-handling, rad-waste, turbine, and Unit 2 containment buildings were conducted to observe plant equipment conditions, including
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potential ' fire hazards, fluid leaks, and excessive vibrations, and
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'to verify that' maintenance requests had been initiated for equipment
.g in need of maintenance.
The inspectors verified by-observation and direct interviews that the physical security plan is being implemented in recordance with the station security plan.
The inspectors observed plant housekeeping / cleanliness con'ditions
.and verified implementation of radiation-protection controls. The-inspectors also witnessed portions of the radioactive waste system
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controls associated with rad-waste shipments and barreling.
The observed facility operations were verified to be in cccordance with the requirements established under Technical Specifications,.
10 CFR, and administrative procedures.
b.
Onsite Event Follow-up (93702)
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The' inspectors performed onsite follow-up activities for events which occurred during January and February 1989. These follow-ups-included reviews of operating logs, procedures, Deviation Reports,
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Licensee.EventReports,(whereavailable),andinterviewswith-licensee personnel.
For each event, the inspector developed a
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chronology, reviewed the functioning of safety systems required by plant conditions, and reviewed licensee actions to verify e
consistency with procedures, license conditions, and the nature
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of the event. Additionally, the inspector verified' that the licensee's investigation had identified the root causes of equipment malfunctions and/or personnel errors and that the licensee had.taken appropriate corrective actions prior to restarting the unit. Details of the events and the licensee's corrective actions developed through inspector follow-up are provided.in paragraphs (1) through (3) below:
(1) Unit 2 - Hydrogen Burn in 2A Safety Injection Accumulator At 5:00 p.m. (CST) on January 16, 1989, with Unit 2 in Mode 6, the licensee received a report of a fire in the 2A safety injection accumulator.
Investigation' revealed thct a Radiatica L
Protection Technician (RPT) had been attempting to collect an air sample from inside the accumulator tank using an electro-mechanical sampler. When he lowered the air sampler through the ooen manway into the tank, the accumulator's atmosphere a
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ignited and a rush-of warm gas and a small cloud exited the i
manway for approximately five seconds, accompanied by considerable noise and vibration. The RPT was unharmed except for a ringing in the ears for several hours following the event.
The licensee analyzed a grab samp7e for combustible constituents which had originally been collected from the 2A
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accumulator at 1:40 p.m., to determine the isotopic content of the accumulator's atmosphere for ALARA purposes. L'arly in the
, day, two contractors working on the 2A accumulator manway had l
alarmed a whole body frisker when they exited containment and the licensee was trying to determine the source of the noble gases in the 2A accumulator. The grab sample which the licensee analyzed was found to contain 7.6% hydrogen and 9.6%
oxygen. Subsequent calculations performed by Westinghouse determined that these concentrations were of sufficient magnitude to be flammable, but not explosive. The licensee's investigation determined that the source of the hydrogen was the waste gas system. One of the components of the waste gas system is the vent header. The vent header is regulated to 0.5 psig by a pressure regulator, supplied by one of the gas decay tanks, to provide cover gas for various tanks (including the reactor coolant drain collecting tar.k (RCDT)).
This cover gas flows into these tanks when liquid level is being lowered to prevent a vacuum from being created and structural collapse of the tank from occurring. With the drain valve from the accumulator to the RCDT open and the accumulator manway removed, a pressure differential existed between the waste gas system vent header and containment atmosphere.
This differential caused cover gas to flow from the vent header to the accumulator. The cover gas consists primarily of hydrogen, nitrogen, and isotopes of xenon and krypton.
Isotopic enalysis-of a grab sample indicated that its composition was very similar to the gas decay tank that was being used to supply cover gas.
Following the incident, the licensee diluted the 2A accumulator atmosphere using service air and performed a visual examination of the interior and exterior cf the 2A accumulator. No evidence of damage was discovered. Westinghouse performed calculations based on the hydrogen / oxygen content of the accumulator prior to the burn and determined that the peak pressure that could have been experienced by the accumulator was approximately 235 psig. The estimated peak pressure equivalent to the dynamic shock on the accumulator was approximately 470 psig, well below the accumulator's design pressure of 700 psig. TLe licensee performed visual inspections of all instrumentation attached to the 2A ac.cumulator and found no physical evidence of damage.
Calibration checks were also performed on all associated instrumentation and no appreciable deviations from previous calibrations were found.
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The licensee revised the standardized out-of-service, which was used to remove the 2A Accumulator from service, to require isolation from the RCDT following the draining operation.
In addition, the licensee will implement controls to require an analysis for atmospheric combustibility prior to collecting
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I electro-mechanical air samples in volumes known to contain noble gases.
At the time of the event, discussions were held between the Shift Engineer, Unit 2 Operating Engineer, and Station Health Physicist as to the deportability of this event in accordance with 10 CFR 50.72.
Based on the report from the RPT that the nature of the event was loud noise and vibration for a sustained time period rather than an instantaneous " bang", it was concluded that the event was not an explosion but a fire.
Byron Emergency Procedure BZP 200-1, " Byron Emergency Action Levels," specifies that an explosion be given an emergency classification of Unusual Event. However, a fire is classified as an Unusual Event only if it cannot be extinguished within 10 minutes of arrival of the onsite fire brigade. Since they had.
classified the event as a fire, which was self-extinguished in less than a minute, they concluded that this event was not reportable under 10 CFR 50.72. The inspectors have reviewed management's evaluation and agree that it is consistent with the licensee's approved emergency plan.
(2) Unit 1 - Manual Reactor Trip Due to Feedwater Regulating Valve Failing Open At approximately 9:55 a.m. (CST) on January 31, 1989, with the unit at 99% power, the Reactor Operator (RO) received a control room alarm for steam generator IC steam flow /
feedwater flow mismatch. Upon investigation he found that the Feedwater Regulating Valve (FRV) for the 1C steam generator had failed open.
He took manual control of the valve and attempted to close it, but the valve did not respond. At approximately 9:56 a.m., with level in the IC steam generator rapidly approaching the high-high steam generator water level turbine trip setpoint (P-14), the Shift Engineer ordered the R0 to manually trip the unit. All systems responded normally following the trip, with the exception of one of the intermediate range nuclear instrumentation channels which did not initially clear the P-6 setpoint (source range permissive)
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instruments. This was due to the instrument being slightly l
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out of calibration. The unit was stabilized in Mode 3.
At the time of the trip), stroke testing of the Main Steam Isolation Valves (MSIVs was in progress. The 1C MSIV was being tested when the R0 received the first alarm. The I
licensee believes the MSIV testing initiated a small feedwater
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oscillation due to the control system's response to changes in steam flow in the IC steam line. The licensee's inspection of i
the IC FRV revealed that a machine screw and lock nut in the l
valve position feedback linkage had come out of the linkage, l
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causing the controller to think the valve was fully closed.
As the controller believed the valve was stut, it generated a full open signal and the valve went fully open.
The licensee made repairs to the IC FRV and inspected the other FRVs to verify no similar problems existed. The unit was taken critical at 3:19 a.m. on February 1 and synchronized to the grid at 8:26 a.m. the same day.
.(3) Unit 2 - Inadvertent Safety Injection and Failure of 2B Diesel Generator Output Breaker to Close At 12:40 p.m. (CST) on February 11, 1989, with the unit in Mode 6 with the reactor vessel head off and water in the refueling cavity more than 23 feet above the. reactor vessel, a safety injection initiation signal was received. -At the time of the initiation, a load sequencing test of the 2E, diesel generator was in progress. Also ongoing at that time was work on containment pressure channel 935 by an instrument mechanic who had placed the channel in test. Due to instrument inverter 214 being out of service, instrument bus 214 was being powered from a sola transformer fed off of 4.16 KV bus 242. When bus 242 was deenergized to simulate an undervoltage condition for the diesel generator test, power to instrument bus 214 was lost, tripping containment pressure channel 934. This satisfied the 2 out of 3 logic for a high containment pressure safety injection signal. All train A equipment which was aligned for operation in Mode 6 responded as designed, ircluding the 2A centrifugal charging pump, which injected about 120 gallons of water into the Reactor Coolant System (RCS). All train A equipment was secured and realigned to its normal configuration and the safety injection signal was reset. Because of problems with the 28 diesel generator output breaker, train B equipment did not actuate. The 28 diesel generator started, but its output breaker did not close and sequence loac's onto bus 242 -
due to dirty contacts in an undervoltage relay.
The licensee cleaned the contacts and successfully performed the diesel generator sequencing test later the same day, after containment pressure channel 935 was returned to service.
The licensee is evaluating the need for some type cf preventive maintenance on these relays in the future.
The licensee is also reviewing controls to prevent unrelated work activities from causing unanticipated results during surveillance tests, as occurred during this event.
The inspectors will review these events in a subsequent report after the LERs are issued.
c.
Refueling end Spent Fuel Pool Activities (60710 & 86700)
Refueling activities during the Unit 2, Cycle 2, fuel reload were observed / reviewed to ascertain that they were conducted in
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accordance with approved procedures and in. compliance with the Technical Specifications.
The following areas wei
- onsidered/ monitored during this review:
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.tne periodic testing al 7erability of refueling equipment and systems were performed v r procedura11 requirements; fuel handling operations, including fuel assembly reinstallation, transfer of burnable poison assemblies and rod control cluster assemblies,-
ultrasonic examination of. spent fuel assemblies and reconstitution
.of damaged fuel assemblies were performed.in accordance with
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approved procedures and Technical Specifications; plant conditions
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were maintained as required to support refueling; good housekeeping, loose object control, and appropriate cleanliness zones were-established and enforced, and the required radiological controls and practices were established and' observed; and the fuel handling
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activities were performed by qualified personnel.
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The inspectors verified by observation and direct interviews that fuel handling and control room personnel were properly briefed on scheduled refueling activities and that these activities were correctly performed; that source range nuclear instruments, including audible monitors, were operable during reloading operations; that fuel' material control requirements were performed; that refueling cavity and spent fuel pool water levels were maintained in accordance with Technical Specifications; that boron concentrations were established and verified as required; and that operation of the spent fuel poc1 bridge crane, fuel handling building (FHB) crane, spent fuel pool system, and FHB ventilation and radiation monitoring systems was as required by Technical Specifications.
No violations or deviations were identified.
-4.
Maintenance / Surveillance (61726 & 62703)
Station maintenance and surveillance activities of the safety-related systems and components listed below were observed or. reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides, and industry codes or standards, and in conformance with Technical Specifications.
Unit 2 train A manual safety injection initiation and manual phase A initiation surveillance Installation of Unit 2 temporary tygon level indication system 2A Diesel Generator LOCA sequencer test Fit up and welding of nitrogen supply system to MSIVs Welding of access gallery for MSIVs Eddy current examination of steam generator U-tubes s
Ultrasonic examination of spent fuel assemblies Reconstitution of spent fuel assemblies
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Removal of Limitorque operator for valve 2CV8355D j
Valve signature for Limitorque valve 20094128 Unit 2 electrical penetration fire seal repair
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The following items were considered during this review:
the limiting conditions for operation were met while affected components or systems were removed from and restored to service; approvals were obtained prior to initiating work or testing; quality control records were maintained; parts and materials used were properly certified; radiological and fire prevention controls were accomplished in accordance with approved procedures; maintenance and testing were accomplished by qualified personnel; test instrumentation was within its calibration interval; functional testing and/or calibrations were performed prior to returning components or systems to service; test results conformed with Technical Specifications and procedural requirements and were reviewed by personnel other than the individual directing the test; any deficiencies identified during the testing were properly documented, reviewed, and resolved by appropriate management personnel; work requests were reviewed to determine the status of outstanding jobs and to assure that priority was assigned to safety-related equipment maintenance which may affect system performance.
During this inspection, the inspectors reviewed Deviation Report (DVR)
6-2-89-013, which concerned a water leak from valve 2CV8355D (RCP 2D Seal Injection Isolation Valve). The valve was tagged out of service as an isolation point for draining the 2D reactor coolant loop.
Projects and Construction Services (PACS) had been assigned the job of overhauling the Limitorque operator for valve 2CV8355D. The individual who removed the Limitorque operator from 2CV8355D saw the Out-of-Service (005) card on the operator and simply removed the operator and placed the 00S card back on the packing nut of the valve. Tne licensee believes that, when the valve operator was removed, fluid pressure lifted the valve off of its seat and caused the leak.
Upon discovery, the leak was isolated by closing valve 2CV8369D (2D RCP Seal Injection Manual Flow Control Valve).
This valve was added to the 00S for the Limitorque work on 2CV8355D as a manual isolation point. The licensee informed the inspectors that PACS was using the same 00S procedures to perform work on Limitorque valves as the station Maintenance Department uses and that P"* workers were informed that they were to either manually isolate valves or block them in the desired position before working on the valve or removing the operator.
Within the past two years, there have been two previous instances where i
the improper control of work on a Limitorque valve has caused unanticipated results. The first case occurred in April 1987, when a contractor maintenance crew working on the valve operator for valve ICC9412A (CC to RH Heat Exchanger 1A Isolation Valve) stroked the valve partially open, causing the Component Cooling Water (CC) surge tank to I
drain to the Residual Heat Removal (RH) heat exchanger, thereby rendering both trains of the CC system inoperable. One concern that arose from this incident was that clarification was needed of the licensee's policy on performing work on components which are being used as physical isolation points for other work activities.
A second incident occurred in October 1988, during the Unit I refueling outage. Mechanical maintenance personnel were removing the valve actuator en 1S188128 (RH pump 1B suction from RWST isolation valve) in
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order to change the gear box grease. During this evolution, the mechanics inadvertently opened the valve and provided a flow path'from the Refueling Water Storage Tank (RWST) to the Reactor Coolant. System
(RCS) and transferred approximately 10,000~ gallons of water from the RWST. Corrective' actions for this incident included making changes to l
maintenance procedures tu require locking the valve stem in place when working on any valves which cannot be isolated from system pressure or fluid thrust.
Following this incident, the inspectors stressed to licensee management that their system of maintenance controls needed to be structured so that.it could tolerate the possibility of personnel
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error, i
The inspectors are concerned not only that contracter personnel violated procedures when removing the Limitorque operator from valve 2CV8355D during this most recent incident, but that the licensee still has not_
established adequate controls to prevent unanticipated valve motion
during maintenance on Limitorque valves.
The licensee informed the i
inspectors that the Operations Department reviewed a listing of Limitorque valves which were to be worked on during this outage and made cognitive decisions as to which valves needed to be blocked open before-work began and which did not.
It was decided that valve 2CV8355D did not need to be blocked cper. because it could be manually isolated.
However, it. is unclear as to why manual isolation points were not added to the 00S for Limitorque the work.
Resolution as to the root cause, and contributing causes, of this incident will be tracked as an unresolved item (455/89001-01(DRP)).
5.
Security r_
a.
Review of Licensee Actions in Response to Suspected Drug Use (99024)
On January 12, 1989, the inspector was notified that an anonymous allegation had been received by the licensee concerning use of controlled substances by two individuals. One of the individuals performed non-licensed, non-safety-related duties and_the other was a licensed individual.
They both submitted to drug screening tests and the results for both tests were negative. The allegation vas not substantiated and the individuals were returned to their duties.
b.
Licensee's Implementation of Plans for Coping with a Strike by the Security Guard Force (92710)
At 5:00 a.m. on February 2, 1989, the bargaining unit members of the licensee's contract guard force walked off the job. The licensee had been anticipating this action and had a contingency plan in place, which they implemented at the time of the strike.
The inspectors verified the implementation of the contingency plan, assessed the strike's impact on other areas of plant operation, and communicated these observations the regional management.
Additional inspection was performed by a regional security specialist and is documented in Inspection Report No. 454/89003; 455/89005(DRSS).
The guard force voted to end the strike and returned to work on February 13.
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Novi51ationsordeviationswereidentified.
6.
Safety' Assessment / Quality Verification
.a.
Licensee Event Report.(LER) Follow-up (90712 &.92700)
.(Closed)LERs(454/86010-1L',454/86011-IL,454/86017-1L, 454/87019-2L,454/88009-1L,454/89001-LL,,455/87009-1L, U
455/87011-1L,455/88012-LL): Through. direct observation,-
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discussions with licensee personnel, and review of records, the following LERs were reviewed to determine that'the deportability requirements were fulfilled, immediate corrective action was
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- been accomplished in accordance with Technical Specifications.
-LER No.
Title Unit 1 454/86010-01 Control room ventilation actuation due to loss of radiation monitor sample pump.
454/86011-01 Control room ventilation actuation due to high vacuum on radiation monitor.
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454/86017-01 Both trains of control room ventilation inoperable due. to equipment problems..
454/87019-02 Safety injection and reactor trip due to failed main turbine throttle valve.
454/88009-01 Fuel handling building booster fan actuation due to high radiation caused by radioactive. particle.
454/89001 Technical Specification surveillance.
performed late due to personnel error.
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Unit 2 455/87009-01 Manual reactor trip in response to feedwater pump trip.
455/87011-01 Reactor trip on overtemperature delta T during 30% load rejection test.
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455/88012 Reactor trip on low reactor coolant loop flow caused by cleaning of flow transmitter vent valve.
With regard to LER 454/89001, this LER describes an event in which a Technical Specification surveillance was performed late on two different occasions due to personnel errors on the part of the
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engineers involved. Technical Specification 4.2.2 specifies surveillance requirements for determining if the heat flux hot l
channel factor (FQ(z)) is within its Technical Specification limit.
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On November 12, 1988, and again on November 17, 15'88, engineers incorrectly determined the condition requiring the next
determination of FQ(z).
In both of these cases, a supervisory review performed by the Station Nuclear Engineer incorrectly approved the completed surveillance. On January 13, 1989, another engineer, 1n conjunction with the Station Nuclear Engineer, discovered the failure to satisfy the time requirement of Technical Specification 4.2.2 while developing a revision to IBVS 2.2.2-1,-
which is the surveillance procedure which implements the requirements of this Technical Specification. On the first occasion, the surveillance was performed approximately 53 hours6.134259e-4 days <br />0.0147 hours <br />8.763227e-5 weeks <br />2.01665e-5 months <br />
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late and on the second occasion the surveillance was performed i
approximately 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> late. The failure to perform 1BVS 2.2.2-1 within the specified time interval is a violation of Technical Specification 4.2.2 (454/89001-01(DRP)). However, this is a licensee identified item, and in accordance with of 10 CFR Part 2, Appendix C, Section V.G.1 a notice of violation was not issued.
In both of these instances, it was verified that FQ(z) satisfied the Technical Specification Limiting Condition for Operation, and, therefore, implementation of the Action Requirements was not required.
The licensee determined that the root cause of this event was an improper surveillance procedure format. A contributing cause was the cognitive errors by the engineers performing IBVS 2.2.2-1, and inadequate reviews performed by the Station Nuclear Engineer.
The licensee's corrective actions included holding a Personnel Error
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Board, discussing the event with all Technical Staff personnel,
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revising BVS 2.2.2-1 surveillance procedures, reviewing all Technical Staff Technical Specification surveillance procedures to I
ensure that similar problems do not exist, reviewing all past performances of BVS 2.2.2-1 for Units 1 and 2, and addressing personnel performance deficiencies on an individual bases.
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b.
TMI Action Item Follow-up (25565)
(1)
(Closed) TMI Action Item I.C.7.1:
NSSS vendor review of procedures - low power test program.
This item is also identified as SIMS issue I.C.7.1.
The inspector verified that the licensee obtained reactor vendor review of low power test procedures as further verification of the adequacy of the l
procedures.
Based on these actions, this item is considered l
closed.
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(2)
(Closed) TMI Action Item I.C.7.2:
NSSS vendor review of
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precedures - power ascension and emergency procedures.
This item is also identified as SIMS issue I.C.7.2.
The inspector verified that the licensee obtained reactor vendor review of
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. power ascension and emergency procedures as further..
verification'of the adequacy of'the~ procedures.
Based on.'these acti)ns,-this item is considered-closed.'
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c.
' Followup on Headquarters Requests (25565)
(Close'd)TIl2515/65: TMI. Action Plan Requirement Followup. All inspection requirements-for closure of TMI Action Items are completed for Byron Units 1 and 2.
Therefore, this TI is considered
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closed.
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One licensee identified.v'olation was identified as discussed in paragraph' a above, no other violations or deviations were identified._
d 7.
Management Changes'.
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On Febreary 7, 1989',.the licensee-informed the resident inspectors of several management changes which were taking' place at Byron.
_l T. P. -Joyce, former Production Superintendent at Byrod is now the
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Station Manager for Zion.
G. K. Schwartz, former Assistant
. Superintendent of Maintenance is now the Production Superintendent.
R.-C. Ward, former Services Superintendent, is now'the Technical Superintendent.
J. A. Kudalis, former Senior Financial Coordinator,
.is now the. Services Director.
T. J. Tulen, former. Assistant Super-
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-intendent of Operations, ir now the Assistant Superintendent of-Maintenance.
T. K. Higgins, former Unit 0 Operating Engineer, is now
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the Assistant Superintendent.of Operations.
8.
Unresolved Items I
Unresolved items are matters about which more information is required
~ in order to ascertain whether they are acceptable items, violations, or
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deviations. An unresolved item disclosed during the inspection is discussed in paragraph 4.
1 9.
Meetings l
a.
SALP Presentation to Licensee (30702)
On January 27, 1989, Messrs. A. B. Davis, Region III Administrator, i
B. Clayton, Acting Chief, Reactor Projects Branch 1, J. M.. Hinds, Jr., Chief, Reactor Projects Section 1A, Dan Muller,
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Project. Director III-2, NRR and the NRC resident inspectors toured the Byron. plant and met publicly with licensee managers to present l
the results of the Systematic Assessment of Licensee Performance
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(SALP) 8 Report at Byron Station.
b.
Meeting with Local Public Officials (94600)
On January 27, 1989, Messrs. A. B. Davis, Region III Administrator, B. Clayton, Acting Chief, Reactor Projects Branch 1, J. M. Hinds,
Jr., Chief, Reactor Projects Section 1A, and the NRC resident inspectors met publicly at the Byron Cultural Center with local
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public officials from the area surrounding Byron Station. The meeting was held to present the findings of the SALP 8 Report.
c.
ExitInterview(30705)
The inspectors met with'the licensee representatives denoted in paragraph-1 at the conclusion of the inspection on February 16,
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1989. The inspectors summarized the purpose and scope of the inspection and the findings.
The inspectors also discussed the likely informational content of the inspection report, with regard to documents or processes reviewed by the inspectors during the inspection. The licensee did not identify any such documents or.
processes as proprietary, i
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