ML14181A949
| ML14181A949 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 09/26/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14181A947 | List: |
| References | |
| 50-261-97-09, 50-261-97-9, NUDOCS 9710100035 | |
| Download: ML14181A949 (28) | |
See also: IR 05000261/1997009
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-261
License Nos:
Report No:
50-261/97-09
Licensee:
Carolina Power & Light (CP&L)
Facility:
H. B. Robinson Unit 2
Location:
3581 West Entrance Road
Hartsville, SC 29550
Dates:
July 20 - August 30, 1997
Inspectors:
B. Desai, Senior Resident Inspector
J. Zeiler, Resident Inspector
J. Wiseman, Region II Inspector
Approved by:
M. Shymlock, Chief, Projects Branch 4
Division of Reactor Projects
Enclosure 2
9710100035 970926
ADOCK 05000261
EXECUTIVE SUMMARY
H. B. Robinson Power Plant, Unit 2
NRC Inspection Report 50-261/97-09
This integrated inspection included aspects of licensee operations,
maintenance, engineering, and plant support. The report covers a six-week
period of resident inspection: in addition, it includes the results of an
inspection by a Region II based reactor safety inspector.
Operations
The conduct of operations was professional and safety-conscious.
Several items were identified by either the inspector or licensee that
indicated the need for greater attention to detail by operators
conducting routine rounds. Several major projects were continuing or
nearing completion which have improved plant material and cosmetic
conditions, enhanced equipment identification, and aided personnel
safety (Section 01.1).
The licensee issued a night order when the reactor coolant system hot
leg temperature indication, TE-413, was out of service. The night order
adequately addressed steps required by operators to confirm natural
circulation cooldown in lieu of the temporary loss of post-accident
temperature indication. TE-413 was subsequently returned to service
following replacement of the failed component (Section 01.2).
The inspector discovered that the B Emergency Diesel Generator (EDG)
output breaker control switch was mispositioned. This mispositioning
resulted in the B EDG being inoperable for an extended period of time.
The licensee's initial actions in response to the mispositioning were
appropriate and timely. At the end of the report period, the licensee
had not completed their investigation into the cause and risk
significance of the mispositioning. This issue was identified as an
Unresolved Item pending completion of the NRC's review of the licensee's
investigation (Section 01.3).
The inspector concluded that all three channels of Over Power Delta
Temperature (OPDT) were not calibrated in accordance with Technical
Specification (TS) 2.3.1.2.e, causing the three channels to be
inoperable. This constituted a failure to meet the minimum channel
operability requirement of TS Table 3.5-2, Item 6. This issue was
identified as a Violation (Section 08.1).
Maintenance
In general, routine maintenance activities were performed
satisfactorily. The inspector noted good controls of housekeeping and
good supervisor oversight of work activities while performing preventive
maintenance on a condenser vacuum pump. The inspector noted good
engineering support and management involvement in addressing a Steam
Generator Power-Operated Relief Valve setpoint indication drift problem.
In general, maintenance overhaul of the Dedicated Shutdown (DS) diesel
engine was performed satisfactorily, however, the inspector noted that
2
maintenance personnel were inexperienced resulting in strong reliance on
vendor support and potentially longer DS system outage time (Section
M1.1).
The waste gas analyzer continued to experience problems, indicating a
need for the licensee to adequately address the root cause. Rapid
response team support to address these problems was noteworthy (Section
M1.2).
The inspector concluded that the new Work Management Process procedure
appropriately detailed the changes that were recently updated. The
training plan associated with the new process was also considered good,
as it relied on numerous examples of what constitutes tool pouch work
(Section M1.3).
Engineering
A Non-Cited Violation (NCV) was identified for failure to meet the
requirements of 10 CFR 50.59 regarding an old design installation error
involving the failure to install a restricting orifice in the
containment airlock interlock (Section E8.1).
A NCV was identified for failure to meet the requirements of 10 CFR
50.71(e) regarding inaccuracies identified in the Updated Final Safety
Analysis Report (UFSAR) description of the spent fuel pool cooling
system (Section E8.2).
Plant Support
One instance was identified by the inspector where an untimely hourly
fire watch was performed during the implementation of fire protection
compensatory measures in the B EDG room. The problem resulted from
weaknesses in fire protection controls (Section F1.1).
The number of outstanding work requests related to the fire protection
systems was low and there was no backlog. Corrective maintenance on
degraded fire protection systems was being accomplished in a timely
manner. Appropriate Corrective Action Program assessments of fire
protection program implementation have been conducted (Section F2.1).
Appropriate surveillances and tests were being performed on the fire
protection features and systems. The surveillance and tests of the fire
protection systems and features met the requirements specified in the
UFSAR (Section F2.2).
The licensee has developed engineering evaluations in accordance with
the provisions of NRC Generic Letter 86-10 to justify variations of
in-plant installations from tested configurations for pyrocrete fire
barrier walls, penetration seals, fire doors, fire dampers
(Section F2.3).
3
The fire protection program implementing procedures met the intent of
the NRC guidelines and requirements. Implementation of the fire
protection and prevention procedures .and the general housekeeping for
control of combustibles within the plant were satisfactory
(Section.F3.1).
The performance by the fire brigade to a drill during this inspection
was good. The brigade exhibited good command and control, fire ground
tactics, and recovery operations. The actions by the fire brigade met
the established drill objectives (Section F5.1).
Licensee performance during several emergency preparedness drills
adequately demonstrated the capability of the emergency response
organization and facilities. Drill critiques were aggressive in
identifying areas for improvement (Section P1.1).
The inspectors concluded that radiation control and security practices
were proper (Section R1.1 and S1.1).
Summary of Plant Status
Robinson Unit 2 operated at full power for the entire report period. As of
the end of the report period, the unit had been continuously on-line for 313
days.
I. Operations
01
Conduct of Operations
01.1 General Comments (71707)
The inspectors conducted frequent control room tours to verify proper
staffing, operator attentiveness and communications, and adherence to
approved procedures. The inspectors attended daily operation turnovers,
management reviews, and plan-of-the-day meetings to maintain awareness
of overall plant operations. Operator logs were reviewed to verify
operational safety and compliance with Technical Specifications (TSs).
Instrumentation, computer indications, and safety system lineups were
periodically reviewed from the Control Room to assess operability.
Frequent plant tours were conducted to observe equipment status and
housekeeping. Condition Reports (CRs) were routinely reviewed to assure
that potential safety concerns and equipment problems were reported and
resolved.
In general, the conduct of operations was professional and safety
conscious. However, the inspector noted several items during this
report period that indicated the need for greater operator attention to
detail during the conduct of rounds. For example, during a routine
plant walkdown, the inspector discovered an emergency diesel generator
output breaker control switch mispositioned. This mispositioning, most
likely, had existed over numerous shifts. During another walkdown, the
inspector observed rainwater leaking through the roof of the Dedicated
Shutdown (DS) Diesel Generator cubicle wetting areas on the generator
side of the engine. The rainwater stains present indicated that this
condition had gone undetected and not corrected for a considerable
period of time. In addition, a Shift Technical Advisor (STA) identified
that the setpoints on the local positioners for the Steam Generator
Power-Operated Relief Valves (PORVs) had drifted significantly. While
the identification of this problem by the STA was good, and the setpoint
drift did not impact valve operability, the condition had existed for a
considerable time.
Good plant equipment material conditions and housekeeping continued to
be observed throughout the report period. The licensee was continuing
with or nearing completion of several major projects designed to improve
plant material and cosmetic conditions, provide easier and efficient
equipment identification, and promote greater personnel safety. These
projects included: painting equipment and plant structures, color-coding
safety equipment, installing new and improved equipment identification
tags, re-insulating piping, and re-surfacing heavily traveled areas,
2
both inside the auxiliary building and in and around the turbine
building.
01.2 Reactor Coolant System (RCS) Loop 1 Hot Leg Temperature Instrument
Failure
a. Inspection Scope (71707)
The inspector assessed the impact associated with the failure of the RCS
loop 1 hot leg wide range temperature element (TE-413). TE-413 failed
due to a problem with an electronic repeater module.
b. Observations and Findings
TE-413 provides indication of RCS loop 1 hot leg wide range temperature
in the control room, as well as locally in the charging pump room and at
the secondary control panel in the turbine building. TE-413 is powered
from the Appendix R/Safe-Shutdown power supply PP-50 and its use
includes confirmation of natural circulation in Dedicated Shutdown
Procedure (DSP), DSP-002, Hot shutdown using the Dedicated/Alternate
Shutdown System, as well as DSP-007, Cold Shutdown using the
Dedicated/Alternate Shutdown System. DSP-002 and -007 are utilized to
shutdown the plant from the secondary control panel following an event
that requires control room evacuation. While redundant RCS hot leg
temperature monitoring is available in the control room, TE-413 is the
only RCS hot leg temperature monitoring instrument available at the
secondary control panel. With TE-413 inoperable, the inspector
questioned the licensee if additional guidance was needed to confirm
natural circulation while in procedure DSP-002 and DSP-007.
The licensee assessed the condition and issued Night Order 97-031, which
provided guidance to the operators to utilize other available
information, e.g., RCS cold leg temperature and steam pressure.
c. Conclusions
The licensee issued a night order when TE-413 was out of service. The
night order adequately addressed steps required by operators to confirm
natural circulation cooldown.. TE-413 was subsequently returned to
service following replacement of the failed component.
01.3 Emergency Diesel Generator Output Breaker Control Switch Mispositioning
a. Inspection Scope (71707)
On August 20, 1997, the inspector discovered the B train Emergency
Diesel Generator (EDG) output breaker control switch in the TRIP
position rather than the NEUTRAL (i.e., normal) position. This
mispositioning rendered the B EDG inoperable. The inspector monitored
the licensee's investigation to determine the cause of the switch
mispositioning, plant risk significance, and corrective actions.
b. Observations and Findings
At approximately 11:15 a.m., on August 20, during a routine walkdown of
equipment readiness for operation in the B EDG room, the inspector
discovered the B EDG output breaker control switch, located on the
generator control panel, to be in (what appeared to be) the TRIP
position. The switch is normally in the neutral position, mid-way
between the TRIP and OPEN position indication. The inspector observed
no alarms present on the EDG control panel that indicated a problem with
the switch position. After verifying that a similar switch
configuration problem did not exist on the A EDG, the inspector alerted
operations personnel to the problem. The licensee immediately initiated
an operability determination to determine whether the as-found switch
position impacted operability of the EDG.
Following review of the output breaker control circuitry, licensee
engineering personnel determined that, with the switch in the TRIP
position, the B EDG output breaker would have immediately reopened
following closure on an E-2 Emergency Bus undervoltage condition. As a
result, the B EDG would have been incapable of automatically energizing
the E-2 Emergency Bus,.and was therefore, inoperable. At 3:44 p.m.,
plant management directed the switch to be returned to its normal
position. At that time, it was discovered that the switch was in the
TRIP and partial PULL OUT (i.e., pull-to-lock) position. In this
configuration, the EDG output breaker would have responded similarly to
the switch being held in the TRIP position.
The licensee determined that between 11:15 a.m. and 3:44 p.m., the plant
had been in the action requirements of TS 3.0 as a result of having the
A train Safety Injection (SI) Pump and Containment Spray (CS) Pump
inoperable concurrent with the B EDG inoperability. The A train SI and
CS pumps had previously been declared inoperable for scheduled
maintenance earlier that morning on HVH-6A, the safety-related A train
SI pump room cooler. HVH-6A is required to be operable to support
cooling the A ECCS pumps in the SI pump room and HVH-6B is necessary for
cooling B train ECCS pumps. Due to the potential for the B EDG to have
been inoperable greater than the outage time allowed by TS, the licensee
made a one-hour non-emergency report to the NRC in accordance with 10
CFR 50.72 for a condition outside design basis. Later that night, the B
EDG was started and operated to verify that the output breaker control
switch functioned properly. No problems were identified with either the
switch or EDG operation.
The output breaker control switch is a Westinghouse Type W-2. four
position, spring return to normal, T-handle switch. The four positions
include CLOSE, NEUTRAL, TRIP, and PULL-OUT. The NEUTRAL, i.e., normal
position, has the T-handle oriented vertically facing the 12 o-clock
position. When manipulated in the TRIP or CLOSE direction, the switch
spring returns to NEUTRAL upon release of the handle. By moving the
switch first to TRIP, then pulling the handle outward from the switch
face and moving it counter-clockwise, the switch can be placed in PULL
OUT.
4
The switch is manipulated quarterly during routine TS surveillance
testing. During this testing, the switch is turned to the CLOSE
position to connect the EDG to its E-2 Emergency Bus and later turned to
the TRIP position to disconnect from the emergency bus. The last time
this test was performed, as well as the last time the switch was known
to have been operated, was July 28, 1997.
The licensee initiated an Event Review Team to investigate the cause of
the switch mispositioning, the risk significance, and recommend
corrective actions. The team investigated three possible scenarios that
could have resulted in the switch being mispositioned. These scenarios
included (1)
the potential for the switch to have been left in the
partial PULL-OUT position when it was manipulated during the July 28,
1997 EDG testing, (2) the switch being inadvertently manipulated, e.g.,
bumped, and (3)
the switch being deliberately placed in the incorrect
position. At the end of the report period, the Event Review Team had
not completed its review of the incident. The inspector planned to
review the results of the licensee's evaluation upon completion. This
will be tracked as Unresolved Item (URI) 50-261/97-09-01:
Review
Licensee Evaluation of EDG Output Breaker Control Switch Mispositioning.
c. Conclusions
The inspector determined that the licensee's initial actions taken in
response to the discovery of the mispositioned B EDG output breaker
control switch were appropriate and timely. At the end of the report
period, the licensee had not completed their investigation into the
cause and risk significance of the mispositioning. This issue was
identified as an URI pending completion of the NRC's review of the
licensee's investigation.
07
Quality Assurance In Operations
07.1 Plant Nuclear Safety Committee and Nuclear Assessment Section Oversight
a. Inspection Scope (40500)
The inspector evaluated certain activities of the Plant Nuclear Safety
Committee (PNSC) and Nuclear Assessment Section (NAS) to determine
whether the onsite review functions were conducted in accordance with TS
and other regulatory requirements.
b. Observations and Findings
The inspector periodically attended PNSC meetings during the report
period. The presentations were thorough and the presenters readily
responded to all questions. The committee members asked probing
questions and were well prepared. The committee members displayed
understanding of the issues and potential risks. Further, the inspector
reviewed NAS audits and concluded that they were appropriately focused
to identify and enhance safety.
5
c. Conclusions
The inspector concluded that the onsite review functions of the PNSC
were conducted in accordance with TSs. The PNSC meetings attended by
the inspector were well coordinated and meetings topics were thoroughly
discussed and evaluated. NAS continued to provide strong oversight of
licensee activities.
08
Miscellaneous Operations Issues (92901)
08.1 (Closed) URI 50-261/97-08-01, Failure to Properly Calibrate the Low
Limit Value Affecting Reactor Trip Setpoint:
and,
(Closed) Licensee Event Report (LER) 50-261/97-07-00, Condition Outside
Design Basis Due to Inoperable OPDT Channels:
Background
This issue involved the identification by the licensee of non
conservative setting of the Over Power Delta Temperature (OPDT) reactor
trip setpoints affecting all three Limiting Safety System Settings
(LSSS) channels. The non-conservative setting only affected the OPDT
reactor trip setpoints at reactor power below 100 percent. The problem
was attributed to an inadequate calibration procedure that did not
specify appropriate low limit setpoints. The low limit is an adjustable
setpoint and is set during routine calibration of the loop at refueling
outage intervals. If no limits are specified on the calibration data
sheets, the limits are turned to the lowest setting so they do not
interfere with the calibration module. The licensee determined that the
condition had potentially existed since 1979 and was introduced during a
calibration data sheet revision.
Licensee corrective actions (planned and completed) included changes to
Loop Calibration Procedures (LP)-001, -002, and -003, OPDT Protection
Channels I, II, and III, respectively. The event was to be reviewed by
appropriate Maintenance and Operations personnel, and if determined
necessary, the Reactor Protection System (RPS) was to be revised to
determine which summators require high and low limits to be set. The
licensee submitted LER 50-261/97-07-00 on July 9, 1997, pursuant to 10
CFR 50.73 (a)(2)(i). The licensee had not identified any other
calibration procedures with similar errors.
Significance
The OPDT reactor trip setpoint, though an LSSS setting, is not taken
credit for in the accident analysis. Notwithstanding, the inspector
assessed the safety significance, including review of analysis performed
by Siemens Corporation (fuel supplier and core designer), as well as
discussed several potential scenarios with the reactor engineer. The
Siemens analysis performed a calculation assuming a rod withdrawal
6
accident starting at 100 percent and terminating at 118 percent combined
with a limiting axial flux difference of -20.0 and concluded that margin
existed to prevent reaching fuel centerline melt. This conservative
analysis enveloped the non-conservative trip setpoint that would
manifest only at power levels below 100 percent. Additionally, the
inspector confirmed through discussion with the reactor engineer, that
the local and average kilowatt/foot limits would not be exceeded for the
probable scenarios. Thus, the overall safety significance of the
condition was low. Additionally, the identification of the condition by
the Control Room Shift Supervisor (CRSS) was considered an example of
good attention to detail in the monitoring of control room indications.
However, the NRC is concerned about the length of time the condition had
existed since the periodic loop calibrations performed after 1979 failed
to identify the non-conservative setpoints as a result of not
appropriately prescribing the low limit values.
Conclusions
TS 2.3.1.2.e, LSSS, Protective Instrumentation, Core Protection,
requires that the OPDT reactor trip setpoint, for all three channels, be
calibrated commensurate with the formula specified. TS Table 3.5-2,
Item 6, requires that a total of three channels of OPDT be operable when
the reactor is critical.
The inspector concluded that all three channels of OPDT were not
calibrated in accordance with TS 2.3.1.2.e, causing the three channels
to be inoperable. This constituted a failure to meet the minimum
channel operability requirement of TS Table 3.5-2, Item 6. This issue
is identified as Violation (VIO) 50-261/97-09-02:
Failure to Properly
Calibrate OPDT Channels.
II.
Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a. Inspection Scope (61726 and 62707)
The inspector reviewed/observed all or portions of the following
maintenance related work requests/job orders (WRs/JOs) and/or
surveillances and reviewed the associated documentation:
WR/JO 97-ADBP1
RPS Relay Replacement (Rack 54)
WR/JO 97-ADBS1
RPS Relay Replacement (Rack 56)
WR/JO 97-ADBR1
RPS Relay Replacement (Rack 55)
WR/JO 97-ADFA1
Condenser Vacuum Pump A Packing Replacement
WR/JO AAICV-005
Condenser Vacuum Pump A Cooler Cleaning
WR/JO 917-ADXB1
Recalibrate Positioner on Secondary Control
Panel for B Steam Generator PORV Setpoint
Indication
7
WR/JO AARQ-001
Seven Year Dedicated Shutdown Diesel Generator
Inspection
OST 701-4
Inservice Inspection Valve Operations
Surveillance Test (OST)
b. Observations and Findings
The inspector observed that these activities were performed by personnel
who were experienced and knowledgeable of their assigned tasks.
Procedures were present at the work location and being followed.
Procedures provided sufficient detail and guidance for the intended
activities. Activities were properly authorized and coordinated with
operations prior to starting. Test and maintenance equipment in use was
calibrated, procedure prerequisites were met, and system restoration was
completed. Other specific observations and comments for the items
listed above included the following:
The maintenance supervisor for work related to condenser vacuum pump A
(WR/JOs 97-ADFA1 and AAICV-005) was observed frequently at the job
location and providing good oversight of work activities. Good control
of area housekeeping was maintained during the work, and upon completion
of work, the area was restored to its previous condition. Repacking of
the pump was necessitated as a result of excessive packing leakage. The
inspector noted that when the old packing rings were removed from the
outboard bearing, the four packing ring separation joints were found
aligned together. Normally, packing ring joints are offset to provide
less chance of packing leakage. The inspector noted that the procedure
did not provide guidance for installing packing rings since this
activity was considered skill of the craft. The maintenance supervisor
initiated a CR to address the mis-aligned packing rings and indicated
that corrective actions would address the need for additional training
and emphasis on correct packing ring installation.
The inspector noted good engineering support and involvement in
evaluating and developing detailed work instructions for the on-line
calibration of the positioner on the Secondary Control Panel for the B
Steam Generator PORV setpoint indication (WR/JO 97-ADXB1). This work
request, along with two others for Steam Generator PORVs A and C, were
implemented to correct a significant amount of drift identified in each
PORV's local indications of lift setpoint. The work activity was well
controlled and coordinated with operations to ensure that there was no
adverse impact on the plant. Since the setpoint drift was determined to
be a recurring problem, an Engineering Service Request was initiated to
investigate the need to replace the setpoint devices.
The inspector noted good vendor support of the seven year preventive
maintenance activity on the DS diesel engine (WR/JO AARQ-001). This
maintenance overhaul of the engine was conducted round the clock and a
vendor representative was present, both on day and night shift. The
inspector noted that maintenance personnel were not experienced in many
of the critical diesel inspections, work activities, etc., resulting in
strong reliance on the vendor and potentially longer DS system outage
8
time. Formal DS engine training and personnel training qualification
requirements were not established. However, the inspector did not
identify any areas where worker inexperience caused any adverse
maintenance quality impact. The licensee's post maintenance critique
identified actions to evaluate the need for formal training
qualifications for DS engine maintenance.
c. Conclusions
The inspector concluded that routine and corrective maintenance
activities were performed satisfactorily. The inspector noted good
controls of housekeeping and good supervisor oversight of work
activities while performing preventive maintenance on a condenser vacuum
pump. The inspector roted good engineering support and management
involvement in addressing a Steam Generator PORV setpoint indication
drift problem. In general, maintenance overhaul of the DS diesel engine
was performed satisfactorily, however, the inspector noted that
maintenance personnel were inexperienced resulting in strong reliance on
vendor support and potentially longer DS system outage time.
M1.2 Waste Gas Analyzer Problems
a. Inspection Scope (62707) (71500)
The inspector noted that the Waste Gas Analyzer continued to experience
problems in that it frequently alarmed, indicating greater than two
percent oxygen concentration in the gaseous waste disposal system.
Consequently, the inspector reviewed licensee actions related to
resolving this problem.
b. Observations and Findings
The waste gas analyzer is designed to automatically monitor oxygen and
hydrogen concentration in the waste disposal system and chemical and
volume control tanks. As discussed in Updated Final Safety Analysis
Report (UFSAR) Section 11.3.2.1, the waste disposal system is not
expected to have significant oxygen in any of the tanks. An alarm, with
a setpoint of two percent volume of oxygen, is provided to allow time to
take the required action before the combustible concentration limit is
reached. Due to problems, including oxygen inleakage, the inspector
noted that the waste gas analyzer frequently reached the two percent
alarm setpoint. Consequently, operators would remove the waste gas
analyzer from automatic sampling and place it in a manual mode, pending
resolution of the oxygen inleakage problem. Placing the waste gas
analyzer in the manual mode, resulted in the analyzer being inoperable,
and placed the unit in a 14 day reportable TS action statement per
TS 3.5.3, Table 3.5-7, Item 2, as well as requiring periodic manual
sampling of waste gas.
The inspector expressed concern to the licensee in view of the frequency
of the problems experienced with the gas analyzer. Additionally, the
inspector also noted that some of the details associated with the system
9
were not clearly understood by some members of the operating staff. The
licensee initiated several actions including, replacement of the
portions of tubing suspected of inleakage as well as promulgation of
additional guidance to the operators on operational details to minimize
reaching the alarm setpoint. Additionally, the licensee plans to
implement a modification to the alarm setpoint. The Rapid Response
Team's support associated with troubleshooting related to the system was
considered to be noteworthy. The inspector plans to review the
modification during future inspections.
The inspector also noted that the waste gas analyzer was not scoped in
the Maintenance Rule program. This issue will be further reviewed by an
upcoming NRC inspection of the licensee's Maintenance Rule program.
c. Conclusions
The waste gas analyzer continued to experience problems, indicating a
need for the licensee to adequately address the root cause. Rapid
Response Team support to address these problems was noteworthy.
M1.3 Work Control Process
a. Inspection Scope (62707) (92902)
The licensee implemented changes to the work control process. A
significant change included the addition of "tool pouch" type
maintenance. The work control process is described in Nuclear
Generation Group procedure ADM-NGGC-0104, Work Management Process.
b. Observations and Findings
The inspector reviewed procedure ADM-NGGC-0104 and discussed the process
with licensee management. The new process allows qualified individuals
to conduct corrective maintenance without a work order, written
instructions, post maintenance testing, or close-out documentation under
the tool pouch process. Tool pouch maintenance is allowed to be
conducted on safety-related equipment, provided it does not impact
system operation or availability.
The inspector reviewed the training and plans to monitor effectiveness
of this methodology during routine inspections.
c. Conclusions
The inspector concluded that the new Work Management Process procedure
appropriately detailed the changes that were recently updated. The
training plan associated with the new process was also considered good,
as it relied on numerous examples of what constitutes tool pouch work.
10
III. Engineering
E7
Quality Assurance in Engineering Activities
E7.1 Special UFSAR Review (37551)
A recent discovery of a licensee operating their facility in a manner
contrary to the UFSAR description highlighted the need for a special
focused review that compares plant practices, procedures and/or
parameters to the UFSAR descriptions. While performing the inspections
discussed in this report, the inspector reviewed the applicable portions.
of the UFSAR related to the areas inspected. The inspector verified
that for the select portions of the UFSAR reviewed, the UFSAR wording
was consistent with the observed plant practices, procedures and/or
parameters.
E8
Miscellaneous Engineering Issues (92903) (37551)
E8.1
(Closed) URI 50-261/96-04-02, Review Licensee Evaluation of UFSAR
Containment Personnel Airlock Discrepancy: This URI involved a UFSAR
discrepancy identified by the inspector associated with the containment
airlock interlock. Specifically, UFSAR Section 6.9.2.3 (Amendment 13)
stated that the Penetration Pressurization System (PPS) line that
supplies continuous air pressurization to the containment personnel
airlock seals contained a restricting orifice. The purpose of this
orifice was to assure that air consumption upon failure of the interlock
(e.g., air supply valve failed to close), would still be within the
capacity of the PPS, and would not result in loss of pressure to other
zones connected to the same PPS header. The inspector discovered that
this restricting orifice did not exist. The licensee confirmed that
this orifice, most likely, had never been installed.
The licensee initiated CR 96-00803 to address this issue. The licensee
determined that there was no safety benefit in having a restricting
orifice in this application. This was based primarily on existing
control room alarms and indications of PPS low header pressure and high
PPS header flowrates, as well as the existing capability to manually
isolate PPS to the airlock. In addition, should the interlock fail, the
PPS supply could be isolated by closing the airlock door. The inspector
reviewed CR 96-00803 and determined that the licensee had adequately
evaluated the impact of not having an orifice in this application. The
inspector also noted that during the October 1996 refueling outage (RFO
17), the licensee implemented modification Engineered Service Request
(ESR) 95-00888. This modification isolated continuous PPS air
pressurization of containment penetrations, including the containment
airlock. As a result of this modification, the airlock interlock no
longer served any function. The licensee deleted the UFSAR statement
referring to the restricting orifice with the issuance of Amendment 14
to the UFSAR, dated April 14, 1997. The inspector verified these
actions had been completed and determined that this adequately resolved
this issue.
11
The licensee indicated the reference to the restricting orifice had been
in the original plant FSAR. Since the plant had never met the
description of the airlock interlock in the FSAR, the inspector
considered this to be a defacto change from the FSAR. The inspector
determined the failure of the as-built containment airlock design to
match the description in the FSAR was a violation of the requirements of
The safety significance of this violation was considered to be low
.because the lack of a restricting orifice had no adverse impact on the
operation of the PPS system. Further, the issue did not involve an
unreviewed safety question. The licensee's UFSAR Review and Upgrade
Plan was presented to the NRC in a May 30, 1996 management meeting and
was docketed in a June 10, 1996 meeting summary issued by the NRC. The
meeting summary contains information related to the scope of the UFSAR
review and examples of identified discrepancies. The initial phase of
the UFSAR review was completed on June 30, 1997. The review of UFSAR
Section 6.9.2.3 had not been completed by the licensee when this issue
was identified. The inspector considered that this issue would have
probably been identified by the licensee's UFSAR review. Regardless,
the statement referring to the orifice would have been deleted as part
of the implementation of modification ESR 95-00888.
In accordance with the "General Statement of Policy and Procedures for
Enforcement Actions" (Enforcement Policy), NUREG-1600, this violation
normally would be categorized as a Severity Level IV violation.
However, as discussed in Section VII.B.3 of the Enforcement Policy, the
NRC may refrain from issuing a Notice of Violation (Notice) for a
violation that involves a past problem, such as an old engineering,
design, or installation deficiency, provided that certain criteria are
met. After review of this violation the NRC has concluded that while a
violation did occur, enforcement discretion is warranted in this case.
Therefore, to encourage licensee efforts to identify and correct UFSAR
discrepancies, no Notice is being issued in this case. The specific
bases for this decision were (1)
the licensee's UFSAR review program, as
described in the June 10, 1996 NRC meeting summary, would likely have
identified the violation in light of the defined scope, thoroughness and
schedule; (2)
there had been no prior notice where the licensee could
have reasonably identified the violation earlier; (3)
timely and
appropriate corrective action was completed to evaluate the lack of a
restricting orifice; (4)
timely and effective long-term corrective
actions were implemented to review and identify any similar design
deficiencies; (5)
the design deficiency was considered an old design
issue in that the restricting orifice had never been installed; and, (6)
the violation was not willful.
This issue will be documented as Non
Cited Violation (NCV) 50-261/97-09-03:
Failure to Meet 10 CFR 50.59
Requirements for UFSAR Description of Containment Airlock Interlock.
E8.2 (Closed) Inspector Followub Item (IFI) 50-261/96-08-02, Review Licensee
Actions to Resolve UFSAR Inconsistencies: This IFI involved examples
where the Spent Fuel Pool (SFP) Cooling System description in the UFSAR
12
did not adequately describe the true design. The examples identified
included the following:
UFSAR Section 9.1.3.1.2 (Amendment 7) stated the design basis for
the SFP cooling capacity was to provide cooling for a full core
off-load when only one-third core already existed in the SFP.
Contrary to this, the licensee routinely conducted full core off
loads with greater than one-third core already in the SFP.
UFSAR Sections 9.1.3.1.3 (Amendment 7) and 9.1.2.3.4 (Amendment 2)
were inconsistent with regard to maximum SFP water temperatures
for one-third and full core off-loads. Section 9.1.3.1.3
indicated these SFP temperatures would be 120oF and 150 0 F,
respectively. Section 9.1.2.3.4 indicated the temperatures would
be 132oF and 166 0F, respectively.
UFSAR Section 9.1.3.3.1 (Amendment 2) discussed an alternate means
of providing SFP cooling in the event of a failure of the SFP
cooling pump by connecting a temporary pump to emergency
connections. While the capability to connect a temporary pump
still existed, the wording had not been updated following the
permanent installation of a second SFP cooling pump.
The licensee initiated CR 95-02501 to address these inaccuracies in the
SFP description in the UFSAR. The root cause was determined to be the
inadequate implementation of UFSAR description updates in 1982 when the
SFP was re-analyzed and expanded to its current storage capacity. The
inspector previously reviewed the 1982 NRC Safety Evaluation Report
(SER) and related licensee supporting analysis for the SFP expansion
project and determined that SFP cooling system was capable of performing
its design function at the current SFP storage capacity. The inspector
reviewed the latest licensee update to the UFSAR (Amendment 14),
submitted in April 1996. The inspector verified that appropriate
corrections or enhancements in the description of the SFP system had
been implemented.
10 CFR 50.71(e) requires that the FSAR be revised to include the effects
of all changes in the facility. The inspector determined that UFSAR
Sections 9.1.2.3.4, 9.1.3.1.2, 9.1.3.1.3, and 9.1.3.3.1 had contained
information that predated the SFP expansion project of 1982 that was no
longer accurate and had not been revised in a timely manner.
In accordance with the General Statement of Policy and Procedures for
Enforcement Actions" (Enforcement Policy), NUREG-1600, this violation
normally would be categorized as a Severity Level IV violation.
However, as discussed in Section VII.B.3 of the Enforcement Policy, the
NRC may refrain from issuing a Notice of Violation (Notice) for a
violation that involves a past problem, such as an old engineering,
design, or installation deficiency, provided that certain criteria are
met. After review of this violation the NRC has concluded that while a
violation did occur, enforcement discretion is warranted in this case.
Therefore, to encourage licensee efforts to identify and correct UFSAR
13
discrepancies, no Notice is being issued in this case. The specific
bases for this decision (1) the licensee's UFSAR review program, as
described in the June 10, 1996 NRC meeting summary, would likely have
identified the UFSAR inaccuracies in light of the defined scope,
thoroughness and schedule: (2) there had been no prior notice where the
licensee could have reasonably identified the violation earlier:
(3) timely and appropriate corrective action was completed to evaluate
the inaccurate SFP descriptions; (4) timely and effective long-term
corrective actions were implemented to review and identify any similar
design deficiencies in the system; (5)
the design deficiency was
considered an old design issue in that the description of the SFP had
not been adequately updated following design changes in 1982; and, (6)
the violation was not willful. This issue will be documented as NCV 50
261/97-09-04:
Failure to Update UFSAR Description of the Spent Fuel
Pool System Following Design Changes.
IV. Plant Support
F1
Control of Fire Protection Activities
F1.1 Untimely Hourly Fire Watch Performance
a. Inspection Scope (71750)
The inspector observed one instance where an hourly fire watch for the B
EDG room was not conducted in a timely manner. The inspector reviewed
fire protection procedures governing the performance of hourly fire
watches.
b. Observations and Findings
At 2:20 p.m., on August 21, the inspector noticed that an hourly fire
watch log posted at the entrance to the B EDG room had not been signed
off by the fire watch attendant for the required 2:00 p.m. log entry.
At the time, the attendant was inside the EDG room discussing the repair
of a local fire alarm manual pull station box with maintenance
personnel.
The fire watch had been implemented due to the problem with
this pull station box. After alerting the attendant to the missing log
entry, the attendant immediately initialed for the 2:00 p.m. entry.
Based on subsequent discussions with the attendant, the inspector
learned that the individual had arrived in the room at 2:15 p.m. The
attendant indicated that the previous fire watch was conducted at 1:00
p.m. This resulted in an hour and fifteen minute period for this fire
watch. The attendant indicated that hourly fire watches could be
performed anytime during the hour and not necessarily at the same time
each successive hour. While it was reasonable to allow some flexibility
in the frequency, the inspector was concerned that this understanding
allowed too much flexibility and did not meet the intent of an hourly
The inspector reviewed Fire Protection (FP) procedure FP-004, Duties of
a Fire Watch, Revision 7, dated June 6. 1996. The procedure did not
14
provide a clear definition of an "hourly" fire watch. The Area Fire
Watch Hourly Inspection Log (Attachment 7.1 of FP-004) provided pre-set
spaces for initialing the completion of hourly fire watch inspections on
the hour for a 24-hour period. However, the procedure did not
specifically state that the fire watch had to be performed on the hour
or at the same time each hour. The inspector discussed the untimely
fire watch in the EDG room and weaknesses identified in FP-004 with the
operations manager. The licensee initiated CR 97-01774 to address these
items. The licensee indicated that the procedure would be revised to
clearly define and document the definition and requirements for an
hourly fire watch. The inspector considered this adequate to resolve
the concerns in this area. The inspector plans to review the licensee's
corrective actions upon completion.
c. Conclusions
The inspector identified one instance where an untimely hourly fire
watch was performed during the implementation of fire protection
compensatory measures for the B EDG room. The problem resulted from
weaknesses in fire protection controls. The inspector determined that
the licensee's planned corrective actions should prevent recurrence of
this type of incident.
F2
Status of Fire Protection Facilities and Equipment
F2.1 Operability of Fire Protection Facilities and Equipment
a. Inspection Scope (64704)
The inspector reviewed open maintenance work orders, Equipment
Inoperable Records (EIRs), fire protection related CRs, fire protection
technical aid logs on the facility fire protection systems, features to
assess performance trends or material condition problems with fire
protection/safe-shutdown systems, and equipment. Walkdown inspections
were conducted of the fire protection water supply systems, Appendix R
emergency lighting, the DS diesel system, and fire barriers in safety
related plant areas, to determine the material condition of these fire
protection features.
b. Observations and Findings
As of July 31, 1997, the total number of open WR/JOs related to the fire
protection and safe-shutdown systems and features was 26. These work
requestswere grouped as follows:
Fire Barrier Door, Dampers, and Penetration Seals
10
Fire Protection Water Systems (fire Pumps/sprinklers) 7
CO Systems (EDG & Cable Vaults)
0
Haion System (Cable Spreading & Switchgear Rooms)
0
Fire Brigade Equipment
2
Dedicated Shutdown Diesel Generator System
6
Emergency Lights
1
Fire Detection System
2
Total
26
15
All except two of these work requests were issued in 1996 or 1997. The
work requests issued prior to 1996 were minor DS diesel cubical
ventilation repairs which did not affect the operability of the DS
diesel systems.
As a result of the predictive maintenance program, the licensee
identified that vibration levels on the motor driven fire pump indicated
motor degradation and a need for motor refurbishment. Special motor
vibration monitoring tests (Report No. V-6175-97-07-1) were performed on
July 14-15, 1997. The testing indicated the presence of open or loose
rotor bars in the motor. The licensee indicated that the fire pump
motor is scheduled to be removed and refurbished (WR/JO 97-AEDJ1) during
the week of August 18, 1997.
The inspector determined that the number of outstanding work requests
related to the fire protection systems was low. There was not a backlog
of open work requests.
Fire Protection System Operability:
The inspector reviewed the fire protection portion of the Equipment
Inoperable Records and the plant fire protection Technical Aid Log for
the three month period of May-July, 1997. These records indicated that
the number of fire protection impairments was relatively small and
adequately monitored to limit their duration. The inspector determined
that the identified repair impairments had been restored to service
within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
The inspector conducted walkdown tours and inspected the fire protection
features to determine if the systems were operable and properly
maintained. The inspector toured the following plant fire zones/areas:
Fire doors to the Waste Evaporator Area (Fire Zone 38),
Fire barrier walls for the Component Cooling Water Surge Tank Room
(Fire Zone 36),
Unit 2 Service Water pumps and electric and diesel driven fire
pumps (Fire Zone 29),
Dedicated shutdown system indications in the 4160 VAC Switchgear
Room (Fire Zone 25E),
Dedicated Shutdown Diesel Generator (Fire Zone 25D),
Appendix R eight-hour emergency light units for the dedicated
safe-shutdown system (Fire Zone 25),
Halon 1301 and fire detection systems for the Emergency Switchgear
Room (Fire Zone 20), and,
.
Fire doors and fire detectors for the Battery Room (Fire Zone 16).
16
The inspector noted that the manual fire fighting equipment, automatic
fire detection systems, and fire zone/area walls, floors, and ceilings
of the fire zones, inspected were operational and were well maintained.
The inspector noted that the fire protection system engineer tracked
fire detection system spurious alarms and Electric Thermal Link (ETL)
fire damper resistance values for the CO2 and Halon fire suppression
systems to trend problems with detector sensitivity and automatic fire
damper operations. The inspector reviewed the system engineer trend
reports for 1997 and concluded that no adverse trends had been observed
for these systems during 1997.
Fire Protection Corrective Action Program:
The inspector reviewed a computer listing of the fire protection program
related Condition Reports issued during 1997. The number of CRs related
to the fire protection and safe-shutdown systems and features was
approximately 23. Discussions with operations fire protection personnel
indicated that while no adverse trends have been identified as part of
Corrective Action Program (CAP), the first quarter 1997 review of fire
protection program CRs had observed an increase in the number of errors
related to fire protection. This condition was identified in CR 97
01250 and was currently being reviewed by the licensee. The inspector
concluded that appropriate CAP assessments of the fire protection
program implementation had been performed.
c. Conclusions
The number of outstanding work requests related to the fire protection
.systems was low and there was no backlog. Corrective maintenance on
degraded fire protection systems was being accomplished in a timely
manner. Appropriate Corrective Action Program assessments of fire
protection program implementation had been performed.
F2.2 Surveillance of Fire Protection Features and Equipment
a. Inspection Scope (64704) (92904)
The inspector reviewed the following operations surveillance test
procedures and completed tests for various fire protection systems and
features to determine compliance with UFSAR Section 9.5.1.6, Inspection
and Testing Requirements:
OST-611, Revision 12, November 13, 1996, Low Voltage Fire
Detection and Actuation System, Zones 1&2, (Semi Annual),
OST-623, Revision 13, January 31, 1995, Fire Barrier Penetration
Seal Inspection, (18 Months),
OST-624, Revision 16, May 9, 1996, Fire Damper Inspection, (18
Months),
17
OST-625, Revision 18, November 11, 1996, Fire Door Inspection,
(Semi Annual),
OST-640, Revision 21, May 23, 1997, Self-Contained DC Emergency
Lighting System, (Semi Annual),
OST-918, Revision 5, April 9, 1996, Dedicated Shutdown
Instrumentation Check, (Monthly), and,
OST-922, Revision 9, November 21, 1995, Dedicated Shutdown
Equipment Identification Check, (Semi Annual).
b. Observations and Findings
The operability, surveillance and test requirements for the fire
protection systems and features had been removed from the Technical
Specifications and incorporated into the fire protection program as
described in UFSAR Section 9.5.1.6. These requirements met the
requirements for the fire protection features which were formerly in the
Technical Specifications. The completed surveillance tests of the fire
protection systems reviewed by the inspector were appropriately
completed and met the acceptance criteria. However, the inspector noted
that the test acceptance criteria and compensatory action requirements
of OST-640 for the 10 CFR Part 50, Appendix R, eight-hour DC emergency
light units for the dedicated safe-shutdown system were not addressed
within the.scope of administrative Fire Protection Procedure FPP-012,
Fire Protection Systems Minimum Equipment and Compensatory Actions. The
licensee stated that this issue was previously identified as a 1996 NAS
audit identified weakness and was being evaluated in the scope of
corrective actions for CRs 96-00733 and 96-00735 related to the problems
with the administrative and technical content of Fire Protection
Procedures not meeting management standards. NRC review of the status
of these issues is addressed in Section F3.1 of this report.
c. Conclusions
Appropriate surveillances and tests were being performed on fire
protection features and systems. The surveillance and tests of fire
protection systems and features met the requirements specified by UFSAR
Section 9.5.1.6.
F2.3 Design Basis for Fire Barrier Features and Components
a. Inspection Scope (64704)
Fire barriers include penetration seals, wraps, walls, structural member
fire resistant coatings, doors, dampers, etc. Fire barriers are used to
prevent the spread of fire and to protect redundant safe shutdown
equipment. Laboratory testing of fire barrier materials is done only on
a limited range of test.assemblies. However, in-plant installations can
vary from the tested configurations. Under the provisions of Generic
Letter (GL) 86-10, licensees are permitted to develop engineering
18
evaluations justifying such deviations. The inspector reviewed the
scope of the licensee's engineering evaluations associated with various
fire barrier features and components to confirm that the licensee had
established an adequate design basis for those fire barriers used to
separate safe shutdown functions.
b. Observations and Findings
In 1990, the licensee conducted a fire barrier inspection program which
identified fire barrier components which were not installed in
conformance with all NRC requirements for fire rated barriers. As a
result, the licensee generated a number of Engineering Evaluations (EEs)
to justify those deviations and address the adequacy of the installed
fire barriers for safety-related shutdown interior fire zones within the
plant. The EEs for the plant specific fire zones include EE 90-105
through EE 90-129. In addition, EE 90-104 listed fire doors and fire
dampers which do not conform to the respective National Fire Protection
Association requirements, as well as addressed generic deviations.
Nonconforming fire barrier penetration seal blockout designs were
addressed generically in EEs90-071 and 90-025.
During an NRC inspection (Inspection Report 50-261/96-12) conducted in
1996, configuration discrepancies were identified with the pyrocrete
fire barrier walls installed between fire zones 3 and 7, and between
fire zones 4 and 12. The licensee indicated that an engineering
evaluation that evaluated the wall configurations for acceptability of
the design in accordance with the provisions of GL 86-10 had been
developed for approval and identified in Engineering Service Request No.
97-00405. These engineering evaluations will be reviewed during future
NRC inspections.
c. Conclusions
The licensee has developed engineering evaluations in accordance with
the provisions of NRC GL 86-10 to justify variations of in-plant
installations from tested configurations for pyrocrete fire barrier
walls, penetration seals, fire doors, fire dampers.
F3
Fire Protection Procedures and Documentation
F3.1 Review of Fire Protection Program Procedures
a. Inspection Scope (64704)
The following Station Administration Procedures and Fire Protection
Procedures were reviewed for compliance with NRC requirements and
guidelines:
FP-001, Revision 29, Fire Emergency,
FP-002, Revision 5, Fire Report,
19
FP-003, Revision 9, Control of Transient Combustibles,
FP-009, Revision 6, Surveillance of Fire Protection Activities,
FP-010, Revision 6, Housekeeping Controls, and,
FP-012, Revision 4, Fire Protection Systems Minimum Equipment and
Compensatory Actions.
Plant tours were performed to determine procedure compliance.
b. Observations and Findings
The above procedures established the administrative guidance used to
implement the fire protection program at Robinson and included the
requirements for the control of combustibles, ignition sources and fire
brigade organization and training. The procedures met the intent of the
NRC requirements. Corrective actions of NAS audit weakness items R-FP
96-01, Weakness Nos. 1 ana 2, and CRs 96-00733 and 96-00735, addressing
the fire protection program administrative procedural problems, were not
yet completed. These items were scheduled for completion during the
fourth quarter 1997.
The inspector performed plant tours and noted that the control of
combustible and flammable materials, liquids and gases, and general
housekeeping were satisfactory.
c. Conclusions
The fire protection program implementing procedures met the intent of
NRC guidelines and requirements. Implementation of the fire protection
and prevention procedures and the general housekeeping for control of
combustibles within the plant were satisfactory.
F5
Fire Protection Staff Training and Qualification
F5.1 Fire Brigade Drill
a. Inspection Scope (64704)
The inspector witnessed a fire brigade drill and training for compliance
with the facility's fire protection program and NRC guidelines and
requirements.
b. Observations and Findings
On July 28, the inspector observed a fire brigade drill involving a
simulated fire at the outage radiation control access processing
building in the plant yard area. The fire brigade team leader and four
fire brigade members responded with the plant fire equipment carts in
full fire fighting turnout gear. An offensive fire attack was mounted
utilizing a 1 1/2-inch attack fire hose line from the first floor of the
20
building up the stairs to the second floor, followed by additional fire
hose line deployment practice in the yard area. A building search was
conducted by the brigade members and a practice search object was
successfully retrieved. The fire brigade team leader properly deployed
the fire brigade personnel, established a command post and effectively
used radio communications. The actions by the brigade met the
established drill objectives. A drill critique was conducted with the
fire brigade members following the drill to discuss the drill,
participants performance and recommendations for improvements. Several
areas of improvement were identified and were being addressed by the
fire protection and fire brigade training staffs.
c. Conclusions
During observation of a fire drill, the brigade exhibited good command
and control, fire ground tactics, and recovery operations. The ' tions
by the fire brigade met the established drill objectives.
P1
Conduct of Emergency Preparedness Activities
P1.1 Emergency Preparedness Drills (71750)
a. Inspection Scope
On July 29 and August 5, the inspector observed portions of the
licensee's emergency response drills conducted with Emergency Response
Organization Team "C" and "D", respectively. The drills were conducted
from the training simulator and included Technical Support Center (TSC),
Operations Support Center (OSC), Emergency Operations Facility (EOF),
and Joint Information Center activation with limited participation by
offsite organizations.
b. Observations and Findings
The inspector observed activities in the simulator control room, TSC,
and EOF. Activities were conducted in a professional manner and
personnel treated the exercises as if they were real.
The licensee
determined that all drill objectives were met. The inspector observed
the licensee's critique for the August 5 drill and noted that the
licensee was aggressive in identifying areas for improvement.
Strengths, deficiencies, and comments identified were appropriately
characterized, and where applicable, were entered into the corrective
action tracking program. The drill was also evaluated by NAS personnel
who provided meaningful comments on the effectiveness of the drills.
c. Conclusions
The licensee's performance during the two emergency preparedness drills
were adequate and drill critiques were aggressive in identifying areas
for improvement.
21
R1
Radiological Protection and Chemistry Controls
R1.1 General Comments (71750)
The inspector periodically toured the Radiological Control Area (RCA)
during the inspection period. Radiological control practices were
observed and discussed with radiological control personnel including RCA
entry and exit, survey postings, locked high radiation areas, and
radiological area material conditions. The inspector concluded that
radiation control practices were proper.
S1
Conduct of Security and Safeguards Activities
S1.1 General Comments (71750)
During the period, the inspector toured the protected area and noted
that the perimeter fence was intact and not compromised by erosion nor
disrepair. Isolation zones were maintained on both sides of the barrier
and were free of objects which could shield or conceal an individual.
The inspector periodically observed personnel, packages, and vehicles
entering the protected area and verified that necessary searches,
visitor escorting, and special purpose detectors were used as applicable
prior to entry. Lighting of the perimeter and of the protected area was
acceptable and met illumination requirements.
V. Management Meetings
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on September 10, 1997.
No proprietary information was identified.
22
PARTIAL LIST OF PERSONS CONTACTED
Licensee
J. Boska, Manager, Operations
H. Chernoff, Supervisor, Licensing/Regulatory Programs
T. Cleary, Manager, Maintenance
J. Clements, Manager, Site Support Services
D. Crook, Senior Specialist, Licensing/Regulatory Compliance
J. Keenan, Vice President, Robinson Nuclear Plant
R. Duncan, Manager, Robinson Engineering Support Services
R. Moore, Manager, Outage Management
J. Moyer, Manager, Robinson Plant
D. Stoddard, Manager, Operating Experience Assessment
R. Warden, Manager, Nuclear Assessment Section
T. Wilkerson, Manager, Regulatory Affairs
D. Young, Director, Site Operations
NRC
B. Desai, Senior Resident Inspector
J. Zeiler, Resident Inspector
M. Shymlock, Branch Chief, Region II
23
INSPECTION PROCEDURES USED
IP 37551:
Onsite Engineering
IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and
Preventing Problems
IP 61726:
Surveillance Observations
IP 62707:
Maintenance Observation
IP 64704:
IP 71500:
Balance of Plant Inspection
IP 71707:
Plant Operations
IP 71750:
Plant Support Activities
IP 92901:
Followup - Operations
IP 92902:
Followup - Maintenance
IP 92903:
Followup - Engineering
IP 92904:
Followup - Plant Support
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
!Me Item Number
Status
Description and Reference
50-261/97-09-01
Open
Review Licensee Evaluation of EDG Output
Breaker Control Switch Mispositioning
(Section 01.3)
50-261/97-09-02
Open
Failure to Properly Calibrate OPDT
Channels (Section 08.1)
50-261/97-09-03
Open
Failure to Meet 10 CFR 50.59 Requirements
for UFSAR Description of Containment
Airlock Interlock (Section E8.1)
50-261/97-09-04
Open
Failure to Update UFSAR Description of the
Spent Fuel Pool System Following Design
Changes (Section E8.2)
Closed
TNe Item Number
Status
Description and Reference
50-261/97-08-01
Closed
Failure to Properly Calibrate the Low
Limit Value Affecting Reactor Trip
Setpoint (Section 08.1)
LER
50-261/97-07-00
Closed
Condition Outside Design Basis Due to
Inoperable OPDT Channels (Section 08.1)
50-261/96-04-02
Closed
Review Licensee Evaluation of UFSAR
Containment Personnel Airlock Discrepancy
(Section E8.1)
24
50-261/97-09-03
Closed
Failure to Meet 10 CFR 50.59 Requirements
for UFSAR Description of Containment
Airlock Interlock (Section E8.1)
IFI
50-261/96-08-02
Closed
Review Licensee Actions to Resolve UFSAR
Inconsistencies (Section E8.2)
50-261/97-09-04
Closed
Failure to Update UFSAR Description of the
Spent Fuel Pool System Following Design
Changes (Section E8.2)