IR 05000458/1989047
| ML20006E294 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 02/08/1990 |
| From: | Constable G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20006E292 | List: |
| References | |
| 50-458-89-47, NUDOCS 9002220537 | |
| Download: ML20006E294 (12) | |
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.r APPENDIX
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U.S. NUCLEAR REGULATORY COMISSION
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REGION IV
NRC Inspection Report:
50-458/89-47 Operating License:
NPF-47 Docket: 50-458
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Licensee: GulfStatesUtilitiesCompany(GSU)
L P.O. Box 220 L
St. Francisv111e, Louisiana 70775 b"
Facility Name:. RiverBendStation(RBS)
Inspection At:
RBS, St. Francisville, Louisiana
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. Inspection Conducted: December 1-31, 1989
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Inspectors:
E. J. Ford, Senior Resident Inspector l'
W. B. Jones, Resident Inspector L
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Approved:
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G. monstable, cnter, Project section C Date Division of Reactor Projects Inspection Summary Inspection Conducted December 1-31. 1989 (Report 50-458/89-47)
Areas Inspected:
Routine, unannounced inspection of event followup, operational safety verification, maintenance observation, facility review committee, engineered safety system walkdown, surveillance observation, verification of containraent integrity, BWR anticipated transient without scram / recirculation pump trip, and fitness for duty.
Results: Additional examples of incomplete maintenance job plans and steps marked NA, without explanation, were identified. Similar violations were in
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NRC Inspection Reports 50-458/89-04and50-458/89-41(paragraph 5).
The reactor operators and support personnel responded well to the reactor scram on December 1,1989. Actions taken by the plant staff ensured the reactor
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Excellent engineering support was noted for the investigation of the two main
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steam line isolation valves which failed to remain closed.
Proposed corrective actions were thorough and technically sound (paragraph 3 b).
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DETAILS 1.
Persons Contacted
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- J. E. Booker, Manager, Oversight
E. M. Cargill, Director, Radiation Programs j
J. W. Cook, Lead Environmental Analyst, Nuclear Licensing
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- W. J. Curran Site Representative. Cajun Electric Power Company
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- J. C. Deddens, Senior Vice President, River Bend Nuclear Group
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D. R. Derbonne, Assistant Plant Manager, Maintenance L. A. England, Director Nuclear Licensing l
A. O. Fredieu. Supervisor, Operations i
P. E. Freeh111. Assistant Plant Manager, Outages
- K. J. Giadrosich, Supervisor, Quality Engineering
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- P. D. Grsham, Executive Assistant
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- J. R. Hamilton, Director, Design Engineering
G. K. Henry, Director, Quality Assurance Operations D. E. Jernigan, General Maintenance, Supervisor
G. R. Kimmell, Director, Quality Services
- D. N. Lorfing Supervisor, Nuclear Licensing
- C, L. Miller, Senior Compliance Analyst
- W. H. Odell, Manager, Administration
- T. F. Plunkett, Plant Manager
M. F. Sankovich, Manager, Engineering
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J. P. Schippert, Assistant Plant Manager, Operations and Radwaste
- K. E. Suhrke, Manager, Project Management
R. J. Vachon, Senior Compliance Analyst
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J. Venable. Assistant Operations Supervisor
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R. G. West Assistant Plant Manager Technical Services t
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.The NRC also interviewed additional licensee personnel during the l
inspection period.
- Denotes those persons that attended the exit interview conducted on January 18, 1990.
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Plant Status
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On December 1,1989, the plant experienced a main generator load rejection
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with reactor scram from 97 percent thermal power. The event resulted when protective relaying failed to clear a fault on a 230 kV powerline (Line No. 715) from Cajun Electric Power Company to the Fancy Point Substation
(paragraph 3.a). The licensee subsequently entered into a planned maintenance outage scheduled to begin December 2,1989. During the outage, the licensee replaced the "A" reactor recirculation pump seal package, repaired the "A" moisture separator reheater steam leak, and repaired the "A" reactor recirculation flow control system.
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-3-e After entering cold shutdown (Operational Condition 4), the licensee slow
closedalleightmainsteamisolationvalves(MSIVs). When the test
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switch was released, two outboard MSIVs failed to stay closed, as
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expected, and returned to the open position. The licensee subsequently
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replaced the eight ASCO solenoid valves after thoroughly cleaning each of
the replacement solenoid valves (paragraph 3.b).
On December 6,1989, the licensee returned to full power operation
(Operational Condition 1) and operated at near 100 percent power for the
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remainder of the inspection period.
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3.
Followup of Events (93702)
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During this inspection period, the inspectors reviewed licensee condition
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reports (CRs) and 10 CFR 50.72 reports and held discussions with various
plant personnel to ascertain the sequence, cause, and corrective actions
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taken for plant events. Discussion of selected events is given below:
a.
Reactor Scram
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On December 1,1989, the plant experienced a main generator load rejection from 97 percent thermal power. The main turbine control i
valve fast closures initiated a reactor scram as expected when i
reactor power is greater than 40 percent.
Nine main steam safety
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relief valves along with the turbine bypass valves opened I
concurrently to control the pressure transient. All the safety i
relief valves closed as expected and vessel pressure was subsequently controlled using the turbine bypass valves.
The event was initiated by a static line that broke near the power
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pole and fell across the "B" phase of the 230 kV power line (Line No. 715) leading to the Fancy Point Substation from Cajun Electric Power Company. Once the static line contacted the "B" phase, a phase
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to ground fault occurred. The Zone 1 directional distance ground
relay failed to operate properly to clear the ground fault. The
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Zone 2 directional distance ground relay operated to clear the affected breaker (Breaker 20745).
Because Breaker 20745 failed to operate in sufficient time upon receiving the trip signal, the main generator protective relays - 64M operated to clear the generator from the fault.
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The licensee subsequently verified that the Zone 1 directional distance ground relay had failed. The licensee has concluded that
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the relay failure was an isolated case based on satisfactory l
performance during 20 years of operation with this type of relay and satisfactory testing of the three other relays. These relays are presently tested every 2 years with the failed Zone 1 relay last tested on July 26, 1989. Breaker 20745 was subsequently tested on
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December 1.1989, and both trip coils opened within two cycles as
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L expected. This breaker had also cleared line faults on July 18, 1989, and again on November 8, 1989. Speed shots (timed operability
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tests) are perfonned on the 230 kV breakers at Fancy Point Substation
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every 4 years. Breaker 20745 was next scheduled for a speed shot in March 1990. The licensee has not been able to determine why the i
breaker failed to open within sufficient time to prevent the main generator protective relays from operating.
The licensee is
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reviewing the need for additional testing of both the relays and
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230 kV breakers, j
Inunediately following the generator trip, the nonsafety-related
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4160 Volt Switchgears, INNS-SWG1A and INNS-SWG1B, failed to fast transfer to the preferred station transformers and INNS-SWG1A failed
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to slow transfer until 6 minutes following the loss of normal station l
transformers. The licensee's investigation of this event identified
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that the preferred transformers secondary voltages had been depressed
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by the ground fault which caused the 59R under voltage relay to drop out and pick up the 59Rx relay. The 59Rx relay subsequently
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prevented the fast transfer scheme. When the fault was cleared, the
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59R relay reset for INNS-SWGIB, which dropped out the 59Rx relay and allowed the slow transfer to occur. However, the 59R relay failed to
reset for Switchgear INNS-SWGIA until 6 minutes later. This was
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caused by corrosion on the contacts and insufficient torque on the i
contact arm. The loss of power to INNS-SWGIA resulted in the loss of
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power to Division III Emergency Bus 1 ENS *SWG10. The Division III i
diesel generator subsequently started to power the emergency bus.
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Tha. unexpected restoration of power to INNS-SWG1A did not affect
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1 ENS *SWGIC because the emergency bus had isolated from the nonemergency bus on the loss of power as expected. The licensee has
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initiated a modification request to replace the 59R relay with a
solid state relay similar to that used in the safety-related buses.
Until this modification is implemented, the licensee will remain on
the preferred transformers to power INNS-SWG1A and INNS-SWG1B during
power operations. The licensee performed a probabilistic risk assessment of this electrical configuration to ensure the' risk of an accident was not increased.
f As a result of the main turbine control valves fast closing on the
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generator load rejection, nine safety relief valves and the bypass valves opened to control reactor pressure. The peak reactor vessel
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pressure recorded was 1126.8 psig. This pressure caused the anticipated transient without scram (ATWS)/ recirculation pump trip (RPT) logic to actuate and trip the two recirculation pumps.
Immediately following the ATWS/RPT actuation, the high pressure
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signal cleared, Ltd the recirculation pumps picked up on the low
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frequency motor generator sets. The licensee subsequently reviewed the plant's response to the generator load rejection with bypass valves to the same event described in Chapter 15.2.2 of the Updated
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Safety Analysis Report (USAR). The USAR analysis gives a maximum reactor vessel steam dome pressure of 1191 psig for the above event.
This places the observed plant response well within the USAR analysis. The licensee also contacted GE to verify that the ATWS/RPT
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should not be a seal-in trip logic. GE responded that a seal-in
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I ATWS/RPT lo ic is not required and that similar plant designs have the same lo ic setup. The plant staff has initiated Engineering
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Evaluation and Assistance Request (EEAR) 89-R382 to detemine if the
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ATWS trip setpoint can be increased to prevent the ATWS/RPT during a
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normal turbine or generator trip.
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On December 1,1989, with the reactor in cold shutdown, two of four
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outboard main steam isolation valves (MSIVs) (B21*F028A&D) failed to
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remain closed following slow closure and placement of the control
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switch to.the close position. The licensee had " slow closed" the MSIVs in accordance with the valve lineup requested for the planned
maintenance outage. The licensee's initial investigation revealed i
that, although the coils on the ASCO Model NP 8323, dual coil l
solenoid operated valves (SOVs) were deenergized as a result of l
placing the MSIV control switches to close, the SOVs failed to reposition to vent the control (instrunent) air from the MSIV
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operators. Thus, when the test switch was released, control air was
again allowed to flow to the SOVs which reopened their respective MSIVs.
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s The inspector observed the disassembly of one of the two SOVs. A
discolored ring of what appeared to be heat affected lubricant
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residue was observed on the faces of the plug nut assembly and core.
It was determined that, w in the 50V was energized, the two faces remained in contact due to the stickiness of the residue, thus i
blocking the exhaust port.
If sticking occurs, the MSIVs would not remain closed after a close signal was received.
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During September 1988, the licensee identified a similar failure of two inboard MSIVs. All eight of the MSIV SOVs were replaced in
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October 1988 following the removal of the Dow Corning DC-550 L
lubricant, which was determined to be the cause of the failure. The
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L recently observed discolored rings appears to be a residue of the
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same lubricant left from the cleaning process. Following the latest i
event, the licensee revised the cleaning process to include an
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ultrasonic, acetone bath for the metallic components, and an acetone
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wipe of the elastomers. This revised cleaning process was performed
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Each MSIV was subsequently tested satisfactorily. The licensee has revised the MSIV testing frequency
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to include an approximately monthly slow close test of the MSIVs.
Additiondl review of this event is documented in paragraph 3 of NRC Inspection Report 50-458/89-45.
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Chevron Harmony 68
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On December 16, 1989, a maintenance employee observed that the viscosity of oil stored in three onsite bulk oil storage drums appeared lower than previously observed. A hold on the use of this
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oil was subsequently initiated. A viscosity analysis of three drums of oil labeled as Hannony 68 was found to be 185 sus 190 sus, and
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182 sus respectively at 100'F. The viscosity of new Harmony 68
should be greater than 300 sus at 100*F. On December 19, 1989, an
additional sample was taken from each of the bulk storage tanks
labeled as Harmony 68. The analysis results indicated 182 sus,
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192 sus, and 260 sus respectively. At this time, CR 89-1304 was I
initiated to investigate the mason for the low viscosity indications.
l On December 28, 1989, the licensee determined that the low viscosity i
oil, labeled as Harmony 68, had been received in that condition from
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an offsite source. The licensee immediately reviewed the lubrication
m6nual, which is a controlled document, to determine which equipment
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utilizes the Harmony 68 oil. The licensee subsequently identified 45 i
safety-related components which utilized Harmony 68 oil (Chevron
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Industrial Oil R&O 68). Thirty-four of the items presented a
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possible safety concern if the equipment could not operate with the
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lower viscosity oil. The remaining 11 safety-related components were
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Items such as security doors which did not elicit further scrutiny.
On December 29, 1989, the licensee detennined the Block 10
(investigation, analysis, and corrective action) response for CR 89-1304. The licensee reviewed the vendor manuals for each of the
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34 safety-related components. The allowable viscosity range for eat.h component was determined.
In cases where the lower viscosity was not
acceptable, the components were flushed and the oil replaced with
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acceptable Harmony 68. The oil flushed from the components was
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subsequently analyzed by an independent laboratory to determine if any degradation to the component had occurred. None of the analysis
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indicated that abnormal wear had occurred.
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The licensee has determined that the oil received was actually Harmony 46. The mislabeling of the oil drums appears to have
occurred at the vendors facility. The licensee has revised the j
receipt inspection program to verify the viscosity of oil received in
addition to the certificate of compliance provided by the vendor. An
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INPO notepad entry has been made by the licensee regarding this event.
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No violations or deviations were identified.
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4.
Operational Safety Verification (71707)
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The inspectors observed operational activities throughout the inspection
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period and closely monitomd operational events. Control room conduct and
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activities were observed to be controlled. Proper control room staffing j
was maintained and access to the control room was controlled in accordance with administrative requirements. Selected shift turnover meetings were l
observed, and it was found that detailed infonnation concerning plant
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status was being covered. Several control board walkdowns were conducted by the inspectors.
In all cases, the responsible operators were cognizant i
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as to why an alarm was lit and the reason for each plant configuration.
Operational conditions and events identified through discussion with the L
reactor operators and review of the shift turnover logs were identified in the main control room log.
Inoperable equipment identified during the main control board walkdowns were identified by the applicable limiting condition for operation (LCO).
Walkdowns of the "A" and "B" residual heat removal, low pressure core spray, and high pressure core spray systems were conducted. Major flowpaths were verified to be in the required standby position. The associated power supply for each major flow path valve and pump was observed to be available.
No conditions were noted which would indicate the associated system would not perform its intended safety function.
The inspectors verified that selected ectivities of the licensee's radiological programs were implemented in conformance with facility policies, procedures, and regulatory requirements. Radiological and/or contaminated areas were properly posted and controlled.
Radiation work permits (RWps) contained appropriate information to ensure that work could be performed in a safe and controlled manner. The inspectors observed that the radiation protection staff questioned plant personnel, as they entered the radiation controlled area, to ensure that they were fully cognizant of their RWP requirements and limitations.
On December 1,1989, the plant experienced a main generator load rejection and subsequent reactor scram from 97 percent thermal power. The inspector observed the operators actions approximately 45 minutes after the event.
It was noted that procedures were being followed appropriately to place the plant into cold shutdown for the planned maintenance outage. Good communication between the reactor operators and control room supervisory personnel was observed by the inspectors.
On December 19, 1989, at approximately 12:45 p.m., the inspector observed the conduct of a test of the station security batteries. The purpose of the test, was to prove the capability of the security power supply system (IHS) to respond properly to a loss of nornel power. This was accomplished by simulating a loss of normal AC power and verifying that the batteries continued to supply the inverter. The procedure also verified the capability of the batteries to supply security loads without causing any alanns (other than those anticipated because of the loss of normal power). This was accomplished by simulating a loss of power to the battery charger for the duration of the test.
During the morning tour of the main control room, the inspector noted that the control operating foreman verbally briefed his operating crew on the test and what annunciators to expect. Later, the inspector discussed various facets of the upcoming test with a senior controls engineer, an electrical foreman, the electrical maintenance supervisor, two licensing engineers, a quality assurance (QA) engineer, a security systems coordinator, and the supervisor of nuclear security.
During these discussions electrical drawings were examined.
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The inspector witnessed activities in the secondary alarm station (SAS),
the IHS inverter room, the IHS battery room, and the central alarm
. station (CAS) and discussed the system responses in the main control room
with the assigned QA engineer. The inspector noted that the SAS received
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no unexpected faults or alarms as a result of comencing the test on battery power. The inspector went to the CAS for the conclusion of the test and the return to normal power. Again, there were no faults or
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alanns associated with the change in system power. The inspector observed
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the proper recording of data by personnel in the inverter and battery
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rooms and determined that required test equipment was utilized and within calibration due dates.
The inspector requested the licensee to cause alanns on at least four
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vital area doors and four perimeter zones.
o Subsequent to the test, the inspector reviewed the raw data (prior to a review by licensee supervisory personnel) and found no discrepancies, e
No violations or deviations were identified.
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5.
Maintenance Observation (62703)
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During the inspection period, the inspector observed corrective
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maintenance activities on two main steam isolation valve (MSIV) solenoid operated valves. (SOVs) and on the "A" reactor recirculation flow control system.
In addition, the maintenance work package for work performed on the Division I diesel generator, in November 1989, was reviewed.
L Maintenance Work Orders (MW0s) 132011 and 132013 were initiated on December 2,1989, to replace the SOVs on MSIVs IB21*A0V028B and IB21*A0V022A respectively.
Paragraph 3.b of this report discussed the failure of two MSIVs to close. The maintenance activities consisted of removal of the installed S0Vs for inspection, and the subsequent cleaning and installation of eight new S0Vs. Modification Request (MR) 89-0242 was initiated to revise the cleaning process for removal of the lubrication in the valve. The improved cleaning method included an ultrasonic, acetone
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bath for the metal parts and an acetone wipe for the elastomers.. The
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entire cleaning process and subsequent bench testing of the two valves was observed by 'a quality control inspector.
Following the satisfactory bench
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l tests to ensure the SOVs would reposition when deenergized to vent the
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control air, the S0Vs were installed on their respective MSIVs. The MSIVs L
were subsequently fast closed in accordance with STP-109-3302, "MSIV Full Stroke / Partial Stroke Operability Test," and demonstrated acceptable performance.
MWO R130065 was initiated to troubleshoot and repair the "A" reactor recirculation flow control valve control system. The licensee had been experiencing periodic, unplanned, reactor recirculation flow changes in the "A" loop.
Previous troubleshooting of this condition had been performed utilizing MWO R056469. The licensee concluded from this l~
troubleshooting activity that the "A" recirculation flow control valve
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linear velocity differential transmitter (LVDT), the associated shear pin, j
and a controller circuit board should be replaced. The licensee.
subsequently replaced the above components during the December 1-6, 1989, planned maintenance outage.
In addition, the licensee identified that a i
multi-conductor cable to the LVDT was damaged and was subsequently-.
replaced. The reactor recirculation flow control valves were functionally
tested in accordance with STP-053-0601, " Recirculation Flow Control Valve
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Operability Test," prior to being declared operational.
Quality Assurance Surveillance QS-89-12-15 was conducted for the
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maintenance activity authorized by MWO R130065. As a result of this
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surveillance, Quality Assurance Finding Report (QAFR) 0-89-12-002 was
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initiated. The QAFR identified steps marked NA within the work
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instructions without explanation and the acquisition of baseline data on
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the "A" recirculation flow control valve. This was performed by field i
engineering and maintenance personnel without proper work instructions.
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l The response to this QAFR is due by January 31, 1990.
The inspector also reviewed the work documentation for MWO R132854. This t
MWO was initiated on November 14, 1989, to troubleshoot and repair the Division I diesel generator following an automatic shutdown of the diesel engine 10 seconds into the surveillance. The inspector's observation of this maintenance activity is documented in NRC Inspection Report 50-458/89-40, paragraph 5.
The inspector noted during the review of the MWO package that work plan steps had been marked NA without an explanation. ' Specific work instructions were not provided, and the replacement of the pneumatic logic board was not documented as work performed..
p The inspector also reviewed the preventive maintenance program for the emergency diesel generator air starting dryers. The licensee performed an l
inspection of the air dryers on a 6-month frequency. This preventive
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maintenance (PM) task is identified as Task No. ME03127.02. This PM
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l-references Corrective Maintenance Procedure CMP-9108, " Emergency Diesel
i Starting Air Dryers," for replacing the dryer desiccant, prefilter trap, I :
and after filter elements. Neither the PM or CMP provides acceptance
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criteria as to when the desiccant should be replaced. The licensee
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provides a generic training class on air compressors. The Lesson
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Plan MT-064-2, " Reciprocating Air Compressors," is oriented towards the
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station air compressors. The diesel generator starting air compressors L
and dryer skid is fundamentally different than the station air system.
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The licensee is presently revising the PM task to include acceptance
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criteria for the desiccant replacemeat. Changes to the compressed aTr
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training program are also being reviewed by the licensee. The NRC staff L
will review the adequacy of this training program during a subsequent l
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inspection.
a The inspector considers the maintenance activity inadequacies identified by the licensee and the inspector in MW0s R130065 and R132854 respectively, to be similar to those previously identified in NRC T
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l Inspection Reports 50-458/89-04 and 50-458/89-41.
At the time of the
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above discrepancies, the licensee had not responded to the violations
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identified in the above two reports. The NRC staff will review the licensee's corrective actions during a subsequent inspection.
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. Facility Review Comittee (40700)
The inspector attended the facility review committee (FRC) meeting held on
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December 4-5, 1989. The meeting was documented as89-157 and a quorum was established as required by Administrative Procedure ADM-002, " Charter of FRC." The meeting was held to discuss the events associated with the
. December 1,1989, reactor scram, to verify that the reactor plant responded as expected to the scram, and to review the MSIV S0V failures. The r
inspector found that the committee critically evaluated each item on the agenda.
Each item identified as requiring additional action was uniquely
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identified as an action item in the FRC meeting notes. FRC Action Item 89-157-01 was initiated to evaluate the frequency for MSIV. testing until further 50V inspections can be performed.
This action item was closed during FRC Meeting 89-162 based on MSIV closure testing to be performed approximately monthly.
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No violations or deviation were identified.
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7.
Engineered Safety System Walkdown (71710)
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During this inspection period, the inspector performed a walkdown of the high pressure core spray (HPCS) system. This system is required to be operational during Operational Conditions 1, 2, and 3 with the capability of taking suction from the condensate storage tank and transferring the
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The inspector verified the workability of the system operating procedure and its lineup attachments using p'lant drawings.
Procedure SOP-0030,
"High Pressure Core Spray (Sys 203)," and the attachments for valve, electrical, and control board lineups were compared with PID-27-4A,
" Engineering P&I Diagram, System 203, HPCS System," Revision 15, and FSK-27-4A " Flow Diagram, High Pressure Core Spray." Additionally, the system design requirements document, "SDRD-P27, High/ Low Pressure Core Spray Systems," Revision 0, was reviewed to ' assure pertinent information had been factored into the system operating procedure.
The system walkdown revealed the following:
P System valves located on the major flowpaths were properly aligned.
Associated instrumentation was properly aligned.
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No abnormal control room instrumentation readings or alarms were
present which would prevent the systems from responding if required.
Accessible hangers and snubbers were intact.
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The electrica1'switchgear was properly aligned.
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8.
Surveillance Observation (61726)
The inspector observed the performance of Surveillance Test Procedure STP-053-0601, " Recirculation Flow Control Valve Operability Test," Revision 3. on December 5,1989. This surveillance test demonstrated the operability of Reactor Recirculation Flow Control Valves 1B33-HVYF060 A and B.
River Bend Technical Specification 3/4.4.1.1.
requires that the average rate of control valve movement be less than or equal to 11 percent of stroke per second opening and closing. Each valve Was demonstrated to meet this Technical Specification requirement. A quality assurance engineer noted that the connections for inputting the
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L flow control valve step changes were different than those described in_ the
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STP. The inspector independently verified along with the licensee that the connections were electrically equivalent. The shift supervisor subsequently approved the surveillance test with coments. CR 89-1261 was initiated to document the procedural violation.
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9.
Verification of Containment Integrity (61715)
The' licensee has established the procedural controls for entry into
Operational Condition 3 or 2 from cold shutdown in General Operating Procedure G0P-001, " Plant Startup." Attachment 6 to G0P-001 specifies the required position for each containment isolation valve.
Specific signoff steps are provided for this verification. On December 6, 1989, the inspector noted that the licensee had completed the prerequisites as identified in GOP-001 prior to entering Operational Condition 2.
Selected containment penetrations were verified to be properly aligned and the penetration valve leakage control system was operational.
Prior to completing the containment closeout, the licensee verified that the-containment air locks were tested and satisfied the Technical Specification requirements.
Licensee Event Report LER 89-0039, " Missed STP on Upper Containment Airlock Due to Personnel Error," was issued in December 1989 which
identified that the upper containment airlock was inoperable between February 5 and March 15, 1989. This occurrence will be investigated by
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the inspector and the results documented in a subsequent inspection L
report.
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No violations or deviations were identified.
L 10. BWR Anticipated Transient Without Scram (ATWS) / Recirculation Pump
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' Trip (m )
(Sitze)
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The licensee has installed an ATWS/RPT for both high reactor pressure or low reactor vessel water level. This modification was completed in Decerr6er 1987 during the first refueling outage. NRC Inspection
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i e
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,
"
Report 50-458/89-02, paragraph 4, docunents the licensee's compliance with
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,
the ATWS rule,10 CFR 50.62 and the quality assurance program as stated in a
Generic Letter 85-06, " Quality Assurance Guidance for ATWS Equipment That
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Is Not Safety-Related."
'11. ' Fitness for Duty (255104)
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On December 20, 1989, the inspector observed the licensee's presentations i
on fitness-for-duty policy awareness training and training for escorts.
The training consisted of the licensee's policies concerning onsite and c.
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offsite use, and sale or possession of illegal drugs. The discussion also covered use and abuse of prescription drugs and alcohol. Means of identifying personnel using drugs or abusing alcohol was covered during escort training.
In general, the inspector observed that the licensee generally covered the attributes identified in Temporary Instruction 2515/104, " Fitness for Duty:
Inspection of Initial Training Programs," Appendixes "A" and "C."
The inspector will observe the 16-hour
fitness-for-duty training for supervisors during the first calendar quarter of 1990.
No violations or deviations were identified.
- 12.
Exit (30703)
r An exit interview was conducted with licensee representatives identified in paragraph 1 on January 18, 1989. During this interview, the inspectors reviewed the scope and findings of the report.
The licensee did not identify as proprietary any information provided to. or reviewed by, the inspectors.
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