ML20059F441
| ML20059F441 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 01/07/1994 |
| From: | Harrell P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20059F439 | List: |
| References | |
| 50-458-93-25, NUDOCS 9401140030 | |
| Download: ML20059F441 (54) | |
See also: IR 05000458/1993025
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APPENDIX A
U.S. NUCLEAR REGULATORY 00lir11SSION
REGION IV
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Inspection Report: 50-458/93-25
Operating License: NPF-47
Licensee: Gulf States Utilities
P.O. Box 220 '
St. Francisville, Louisiana 70775-0220
Facility Name: River Bend Station :
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Inspection At: St. Francisville, Louisiana !
Inspection Conducted: October 25-29 and November 8-12, 1993
Team Leader: P. Harrell, Chief, Technical Support Staff, Division of Reactor '
Projects (DRP)
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Assistant Team Leader: P. Wagner, Team Leader, Division of
Reactor Safety (DRS) :
Team Members: L. Gundrum, Office for Analysis aid Evaluation of
Operational Data, Reactor Operations Analysis Branch
C. Johnson, Reactor Inspector, DRS
W. McNeill, Reactor Inspector, DRS
D. Graves, Senior Resident Inspector, Ccmanche Peak, DRP
W. Walker, Resident Inspector, Cooper Nu: lear Station, _ DRP 1
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Approved: \ l N
P. H. Harriell, Chief, Technical Support Staff Ddte
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DR 940107
ADOCK 05000458
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EXECUTIVE SUMMARY
RIVER BEND STATION
OPERATIONAL SAFETY TEAM INSPECTION
On October 25-29 and November 8-12, 1993, a team of seven NRC inspectors
performed an Operational Safety Team Inspection at the River Bend Station, ;
Unit 1, to ascertain that the facility was being operated in a safe manner.
The team reviewed the areas of opcrations, maintenance, management oversight, !
surveillance and testing, safety assessment, and engineering and technical !
support.
The team did not identify any safety significance findings that would preclude
continued plant operation. For those items identified by the team that
involved equipment and/or component operability concerns, the licensee quickly --
evaluated the concerns and took immediate actions to correct the issues. l
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During review of the operations area, the team noted a mixed performance by ,
the operations staff and the organizations that support the operation of the ,
facility. The conduct of the on-shift crews was good as demonstrated by good i
communications, shift turnovers, and response to_ annunciators. The
establishment of a work management center was identified as a positive
contributor to reducing the administrative burden on the control room staff.
During plant tours with operations personnel, the team noted that the
equipment operators performed all the checks required by procedure; however,
the operators demonstrated the lack of a questioning attitude. .The team _,
identified potential deficient or nonconforming conditions with housekeeping _
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and plant equipment that should have been identified by the operators. The
overall level of housekeeping was acceptable; however, the team identified an
excessive amount of loose and unattended material inside containment. As a
result of this observation, tours were performed by the licensee and a
significant amount of material was removed from containment.
The team noted a number of examples of where the licensee had worked around !
equipment and procedural deficiencies, rather than repair the equipment or !
revise the procedures. For example, there were approximately 106 deficiency
and operator aid /information tags on the main control boards. It was not l
apparent that management was proactive in addressing equipment and/or
procedural problems.
In the areas of maintenance and surveillance, the team noted that maintenance
personnel performed their activities well. The team identified a number of I
examples of repetitive problems with plant equipment, which indicated that the
actions taken by the licensee to repair equipment had been ineffective. This
was also an indication that the appropriate level of management attention to i'
adequately repair equipment to prevent repetitive failures was lacking.
During the review of surveillance. activities, the team noted a number of ,
instances where the testing could not be performed in accordance with the l
procedure, as written. The team concluded that the procedures were not being
revised due to the cumbersome procedure change process. Two of the
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surveillance tests witnessed by the team were also monitored by a quality
assurance auditor. The auditors performed well in identifying performance
errors by the technicians. The team identified, in discussions with l
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craftspersons, that the corrective action program was not generally being used i
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by maintenance personnel. These personnel stated that the process was
difficult to use since they did not understand how to obtain the information- ;
required on the condition report form. ,
The team identified that the engineering organization had a large backlog of
work, which included modification requests and drawing changes. During review :
of relatively old modification requests, the team noted that an operability ,
determination for a number of requests had not been performed at the time the
nonconforming condition was identified. As a result of this observation, the
licensee reviewed the open modification requests and identified conditions >
that required additional evaluations of equipment operability. The team
reviewed the status of the system engineering program and noted that
additional management attention was required. Management expectations for.
this organization were poorly defined and some engineers indicated that they
did not routinely utilize the corrective action program.
In the area of oversight of plant operations, it was noted that audits
performed by the quality assurance organization were effective in identifying t
areas with plant staff performance problems. However, responses to these
problems indicated that management was not proactive in addressing those
areas. ,
Overall, it appeared that the corrective action process was not being
effectively implemented by the licensee. As discussed above, the team
identified that the key groups of maintenance and system engineering personnel
were not actively participating in the generation of condition reports.
Although component and/or equipment deficiencies and nonconformances were
being identified by plant personnel, the team identified a number of equipment
problems where the actions taken by the licensee were ineffective in
identifying the root cause and preventing recurrence. The procedures used for -
the performance of surveillance testing generally could not be performed as
written.
The team also noted that recent organizational changes and the initiation of
the Near term Performance Improvement Plan had been undertaken to correct some
of the problem areas identified during this inspection. The effects of these
changes will be monitored during future inspections.
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TABLE OF CONTENTS
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EXECUTIVE SUMMARY .................................................. i
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1 INSPECTION SCOPE ................................................ I ;
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2 PLANT OPERATIONS ................................................ I
2.1 Operations Staffing ......................... . . . . - 1
2.2 Conduct of Operations ...... ............................... 2
2.2.1 Control Room Observations............................. 2
2.2.2 Observation of Equipment Operator Performance ....... 3 q
2.3 Work Management Center ..................................... 4 \
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2.4 Locked Valve List Discrepancies ............................ 5
2.5 Plant Tours .......................... ..................... 6 i
2.5.1 Control Room ........................................ 6
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2.5.2 Equipment Areas and Operating Spaces ................ 6
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2.5.2.1 Hou'sekeeping ...............................
2.5.2.2 Spare Breakers .............. .............. 7
2.5.2.3 Painter Walking.on Piping .................. 8
2.5.2.4 Emergency Lighting ......................... 8
2.5.3 Containment ......................................... 9
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2.6 Walidown of an Emergency Diesel Generator .................. 11 !
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2.7 Operations Department Problem Identification
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and Resolution .......................................... 12
2.7.1 Condition Reports ................................... 12 >
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2.7.2 Emergency Operating Procedure Discrepancy Sheets .... 13
2.7.3 Procedures .......................................... 15 !
2.7.4 System Deficiencies ................................. 16
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3 MAIN"ENANCE ..................................................... 17
3.1 Review and Observation of Maintenance Activities ........... 17
3.1.1 Containment Door Seal Failures ....................... 17
3.1.2 Radiation Monitors .................................. 18
3.1.3 Hydraulic Power Unit Pump ........................... 19
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3.1.4 Motor-Operated Valve Thermal Overload Heaters ....... 20
3.l.5 Electrical Breakers ................................. 21
3.2 Preventive Maintenance Program Review ...................... 22
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3.2.1 Program Implementation .............................. 22 j
3.2.2 Program Review ...................................... 23
3.3 Review of Surveillance Testing Performance ................. 24 .
3.3.1 Diesel Fire Pump .................................... 24 ;
3.3.2 Low Pressure Coolant Injection Pump ................. 25
3.3.3 Residual Heat Removal Valve ......................... 25 ;
3.3.4 Low Pressure Coolant Injection Pump ................. 26 ;
3.3.5 Radiation Monitor ................................... 26 ;
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3.4 Review of Surveillance Test Exceptions ..................... 27
3.5 Review of Surveillance Test Comment Control Forms .......... 28 ;
3.6 Implementation of the Condition Report Process ............. 28
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4 ENGINEERING ..................................................... 29'
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4.1 Review of Modification Requests ............................ 29
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4.1.1 Control Room Panel Labels ........................... 29
4.1.2 Control Room Panel Wiring Splices ................... 29-
4.1.3 Reactor Protection System Wiring Error .............. 30
4.1.4 Emergency Diesel Generator Elbow-Orifice Assembly ... 30:
4.1.5 Residual Heat Removal System Check Valves . . . . . . . . . . . 31
4.1.6 Licensee Review of Modification Requests ............. 31
4.2 Drawings ................................................... 32 ;
4.3 System Engineering ......................................... 33
4.4 Engineering Workload ....................................... 34
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5 CORRECTIVE ACTION PROGRAM .......... .......................... 34-
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5.' Review of the Condition Report Program ..................... 34
5.1.1 Procedures .......................................... 34
5.1.2 Implementation ...... ............................... 35 -
5.2 Review of Condition Reports ................................ 36
5.2.1 Elevated Drywell Temperatures ....................... 36
5.2.2 Emergency Diesel Generator Fuel Oil Storage ......... 37-
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5.3 Review of Quality Assurance Activities ..................... 38 {
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5.3.1 Audits and Quality Condition Reports ................ 38 :
5.3.2 Corrective Action Reports ........................... 39' !
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5.4 Review of Oversight Programs ............................... 39
5.4.1 Independent Safety Engineering Group ................ 39 i
5.4.2 Nuclear Review Board ... ............................ 40 i
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6 NEAR TERM PERFORMANCE IMPROVEMENT PLAN .......................... 41 l
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ATTACHMENTS
1. LIST OF ACRONYMS
2. EXIT MEETING
3. LIST OF INSPECTION FINDINGS ;
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DETAILS
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1 INSPECTION SCOPE
On October 25-29 and November 8-12, 1993, a team of seven inspectors conducted
an Operational Safety Team Inspection at the River Bend Station, Unit 1, to .
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assess the safe operation of the facility. This performance-based inspection
concentrated on the overall effectiveness of the licensee's support for plant '
operations. The inspection was conducted in accordance with the guidance of
Inspection Procedure 93802, " Operational Safety Inspectors Inspection (OSTI)," i
dated November 27, 1989. ;
2 PLANT OPERATIONS
The inspectors observed plant operations in the main control room and in the -
plant on a routine basis and conducted several tours with plant personnel.
The adequacy of procedures was reviewed to assess the overall effectiveness in
supporting plant operations. A system walkdown was conducted to verify that i
the configuration of the system met the appropriate design documentation. i
2.1 Operations Staffing ,
A review was performed to verify that the on-shift staffing of licensed
operators met the requirements specified in the Technical Specifications (TS). -
The staffing consisted of 24 licensed senior reactor operators (SRO) and 22 ,
licensed reactor operators (RO). Of this total, typically 10 SR0s and 15 R0s
were assigned to operating crews. Fourteen licenses (five R0s and nine SR0s) :
were assigned to support functions within the Operations department. The
remainder of the licensed personnel were distributed throughout various i
departments, such as training, maintenance, outages, and nuclear performance. ;
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The operating crews included sufficient staffing to fill the assigned shift
positions, but several crews had no extra personnel. One crew was operating ;
with one of the two R0s designated as fire brigade team leader. In the event
of a fire in the plant, this would leave only one RO in the control room to .
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perform control board manipulations. While this met the minimum TS
requirements, a fire in conjunction with a plant transient could potentially ,
tax the abilities of a single control board operator. The shift schedule for ;
November and December 1993 indicated that all crews were assigned.at least
three R0s. .
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On November 29, 1991, the NRC issued Information Notice 91-77, " Shift Staffing i
at Nuclear Power Plants," which discussed the.actiens that licensees may wish
to take to ensure that an appropriate number of personnel were available on '
each shift to respond to plant events. As indicated in the notice, the ,
appropriate level of staffing may exceed the minimum number of personnel
specified in the TS. As discussed above, it was not apparent that the '
licensee had considered the information provided in the notice in determining
the on-shift staffing levels. This issue will be tracked as an inspection ;
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followup item based on an NRC review of how the licensee addressed Information
Notice 91-77 (458/9325-01).
The shift technical advisors were nonlicensed individuals, who were assigned
to and rotated with the operating crews. The shift technical advisors were
actively involved in plant operations, including participation in review of
surveillance test data, control board walkdowns, shift briefings, and periodic
observations of operator performance in the control room and in the plant. ,
The shift technical advisors appeared to be effective in providing support to i
the operating crews.
A review of the use of overtime identified that at least 1 R0 and 8 SR0s had
worked in excess of 20 percent overtime, which was generally working
additional days in lieu of working greater than 12-hour shifts, since the
beginning of 1993. No instances were identified where overtime had been ,
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performed without proper authorization and documentation. Several operators
interviewed by the inspectors indicated that they did not feel the use of l
overtime was excessive. The inspectors observed, on two separate occasions, !
the Assistant Plant Manager, Operations, stressing the need to self-identify
any fatigue or fitness-for-duty concerns.
2.2 Conduct of Operations ,
2.2.1 Control Room Observations
Control room activities were conducted in a professional, business-like
manner. The at-the-controls area was well marked and access was controlled by !
operations personnel and was limited to individuals requiring access.
Personnel approaching the at-the-controls area for access were acre of the i
restrictions and adhered to the requirements.
Communications were observed to be formal, complete, and routinely repeated !
back. These observations included communications between operators in the :
control room, as well as between control room operators and equipment !
operators in the plant. Receipt of alarms was routinely announced by the l
control room operators and acknowledged by the control operating foreman. '
Annunciator response procedures were appropriately referenced when responding j
to an alarm. Shift turnovers were face-to-face communications and were I
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followed by a shift meeting in the control room. The turnovers were found to
be comprehensive and thorough. This quality of turnovers was typically what i
had been observed in the past by the resident inspectors. Turnover sheets and
document reviews were completed, as required.
Limiting conditions for operation (LCO) were well documented and tracked. A l
review of active and recently completed active and tracking LCO forms was j
performed. The review noted that the forms were complete and accurate. '
Appropriate entries were made in the control room log.
A selected sample of general operating, system operating, abnormal operating,
and emergency operating procedures in the at-the-controls area were reviewed
to verify that the latest revision was available. No problems were identified
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as a result of this review. General housekeeping in the control room was very l
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2.2.2 Observation of Equipment Operator Performance J
The inspectors accompanied equipment operators during tours of the plant. All
areas and equipment identified in Procedure OSP-0012, " Daily Log Report," were -
inspected by the operator. However, during the tours, several hardware and l
housekeeping deficiencies were identified by the inspectors instead of the
equipment operator. A free-standing step ladder was observed adjacent to
safety-related switchgear in the standby service water building and another
ladder was close to a bank of hydraulic control units inside containment. The i
ladders were neither restrained nor attended. The ladders were subsequently
removed by the equipment operator when prompted by the inspectors (see i
Section 2.5.2.1 for an additional discussion on the control of ladders). l
Additionally, the discharge pressure gages for the four standby service water
pumps were reading pressures of 0, 0, 35, and 100 psig for Pumps A through D,
respectively, with none of the pumps running. The operator did not question
or appear to notice any of the pressure indications until prompted by the
inspectors.
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During a tour, the inspectors noted that temporary plastic sheeting was
installed over the switchgear associated with the low frequency,
motor-generator sets for the reactor recirculation pumps. When questioned by i
the inspectors, the operator was aware that the sheeting installed over ;
Switchgear A was due to a roof leak, but was unaware of the reason' for the l
sheeting being installed over Switchgear B. The inspectors later determined
that the sheeting over Switchgear B was also installed because of a leaking .
roof. When this observation was brought to licensee management's attention, 1
expedited roof repairs were initiated to facilitate removal of the protection
sheeting. i
The inspectors observed a 2-inch drain hose connected to condensate storage
tank Valve ICNS-V3028 and routed to a sump near the tank. The operator was
not sure of its purpose or how long it had been installed. The inspectors i
determined that the hose had been connected to the tank by Prompt Modification :
Request 93-0014 to provide a temporary water supply / filtration system to the
tank. The modification request was canceled on June 16, 1993, and the system
restored under Maintenance Work Order (MWO) R16128. The MWO did not contain
instructions to remove the hose. After discussions with the inspectors, the
licensee removed the hose. The inspectors established that the presence of
the hose did not affect the operability of the system. This is an example of
a weakness in the licensee's program for restoring systems to an as-designed '
condition when a prompt modification request (i.e., temporary modification) is
closed.
Although the equipment operators completed the equipment checks and tours
required by Procedure OSP-0012, the lack of a proactive problem identification ,
and questioning attitude by the operators resulted in the failure to identify l
plant deficiencies that could potentially affect equipment and/or system j
operability.
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During a tour of containment, the inspectors observed that the contaminated i
area around the east bank of hydraulic control units did not have a stepoff ;
pad located adjacent to the area. When the equipment operator was asked how
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he would proceed to enter the area, he responded that he was not sure but
would not let the lack of a stepoff pad deter him from entering the area, if
necessary. The inspectors later determined that a stepoff pad was
intentionally not installed in order to minimize the possibility of the pad
coming loose, entering the suppression pool, and potentially clogging the i
emergency core cooling system (ECCS) strainers.
Recommended guidance on how to enter an area without a stepoff pad was
addressed in memoranda between radiation protection and engineering personnel.
The individuals involved with the memoranda stated that the appropriate
actions required for entry into these areas was addressed at morning
management meetings and each manager was to provide the information to the
personnel in their departments. Although no instances of inappropriate entry
or exit practices were observed, the equipment operator's response indicated
that the information had not been brought to the attention of all station
personnel.
It was later determined that personnel would be required to contact health
physics prior to entry, during nonemergency conditions, into a contaminated
area without a stepoff pad. At the time of entry, health physics technicians -
would provide information on how to enter and exit the area. The inspectors
verified that instructions were provided to all plant personnel, during
general employee training, to contact health physics whenever questions arose
regarding any radiological program requirements.
2.3 Work Management Center
The licensee recently implemented a work management center to provide a
central location, outside the control room, to manage and support plant work
activities. Although all MW0s requiring entry into an LCO action statement
. and clearances, required the approval and authorization of the duty shift
supervisor or control operating foreman, the establishment of a work
management center relieved some of the administrative burden from the control
room operators, especially the SR0s, and allowed the operating crew to be more
involved in and aware of control room and operational activities. .
The work management center was staffed with a shift supervisor and a control ;
operating foreman, both SR0 licensed, and two R0s. The center was operated
during regular work hours. Weekend and after-hours work control activities
were conducted in the control room. procedures for operation of the center
were not finalized at the time of this inspection, but the center was ,
operating under guidelines promulgated in Operations Policy 16, issued
October 28, 1993. The inspectors verified that the policy had received the
appropriate reviews and approval and provided the necessary requirements for
the operation of the center. *
Work control meetings were conducted twice daily to review the status of ,
ongoing maintenance tasks, emergent work, surveillances, and scheduling of ;
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work activities for the on-coming shift. These meetings were led by the work
management center supervisor and attended by representatives of various ,
licensee organizations.
The control room, typically the shift supervisor, was in constant visual and l
often audio contact with the operators in the work management center, when it i
was staffed, via a television link. The link was established to ensure that i
the control room maintained an awareness of the work activities authorized for :
implementation in the plant by the work management center. !
2.4 Locked Valve List Discrepancies
Certain valves installed in the plant were required to be locked in a specific !
position. The reason for a valve to be locked was typically traceable to a
Final Safety Analysis Report (FSAR) commitment, a controlled drawing j
requirement, or as specified by licensee management. Valves were either shown ;
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to be in the locked position by FSAR system drawing and/or text, piping and
instrumentation diagrams (P&ID), or on a procedure valve lineup list. The :
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Operations department maintained a consolidated list of locked valves and
indicated the reason (s) for the valve being locked as PID (for a P&ID
requirement), ADM (for an administrative requirement by licensee management),
or FSAR (for an FSAR requirement). Table PID-0-3A, contained in the station ;
drawings, also contained a list of locked valves specified on the P& ids.
During a review of the locked valve list, the inspectors identified a number .
of discrepancies between the reasons annotated on the Operations department .
locked valve list and the P&ID list. Discussions regarding the accuracy of
the locked valve lists prompted the licensee to perform a review of the lists.
The licensee's review identified the following discrepancies: !
- The FSAR and P&lDs identified a locked position for several valves, but l
Table PID-0-3A omitted the valves. The licensee verified that the '
valves were in the procedure lineup lists as locked and were physically
locked. The valves were G-33-VF034A, -VF005A, -VF005B, -VF043A,
-VF00 B, -VF057; MWS-V10, -V81, -V83; SFC-106; E51-V106; FPW-110;
LMS-V17; and SWP-V3295. ;
- Several valves in the makeup water system were indicated as locked on ,
FSAR Figure 9.2-3A and P&lD-9-15A. These valves were not on :
Table PID-0-3A, nor were the valves on the Operations department locked
valve list. They were not locked in position at the time of the
discovery of this problem, but were subsequently locked; however, none
of the valves were found out of the expected position. These valves
were MWS-V368, -V369, -V370, -V371, -V372, and -V373. A change was
initiated to Procedure 50P-0099, " Makeup Water System," to correct the
valve lineup list to reflect the appropriate locked valve positions.
Two valves (RHS-3018 and -3019) listed on Table PID-0-3A were not
installed in the plant. Drawing PID-27-78 also indicated that
Valve RHS-3019 was installed. The licensee physically verified that the
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valves were not installed and initiated a document change notice to
correct the discrepancies. Field Change Notice 6 to Modification i
Request (MR)- 88-0145 canceled the installation of the two valves and '
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should have precluded update of Drawing PID-27-7B and Table PID-0-3A to
reflect the installation of the valves.
This issue, and the issue identified in Section 4.2, will be tracked as
an inspection followup item pending review of the drawing change control'
process by the NRC (458/9325-02).
. Valve CNS-489 was installed in the plant and locked, but did not appear
on the Drawing PID-4-38. A document change notice was initiated to
correct this minor discrepancy.
Condition Report (CR) 93-0702 was generated to document and resolve the
discrepancies discussed above. Although no valves were found out of their
expected position, the failure to maintain documentation to accurately
identify plant valves and their locked position is the first example of an
apparent violation of Criterion V of Appendix B to 10 CFR Part 50
(458/9325-03).
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2.5 Plant Tours
2.5.1 Control Room
The licensee recently performed a review of outstanding MW0s and deficiencies
to identify and correct the items that had a potential significant
operational, nuclear safety, or personnel safety impact. A walkdown by the
inspectors, of the at-the-controls area, determined that the panels contained
approximately 80 deficiency tags and 26 operator aid /information tags.
Operator aid /information tags were used by the licensee to correct improper
labeling or to provide information useful in the normal operation of
equipment. While none of the tags reviewed appeared to have an impact on
personnel safety or system operability, the number of outstanding tags was
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considered to be excessive. This is an example of the licensee working around
system and/or procedural deficiencies instead of taking actions to correct the
deficiencies. This is considered to be a weakness.
2.5.2 Equipment Areas and Operating Spaces
The inspectors toured the plant to assess the material condition and
housekeeping status of equipment areas and operating. spaces. The inspectors
reviewed items such as age and wear of systems and components; adequacy of the
design of installed systems and components; and proper installation,
operation, and maintenance practices. -
2.5.2.1 Housekeeping and Material Condition
The observations of the inspectors in the operating spaces, not including !
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containment, are discussed below:
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- Loose articles such as ink pens and a protective clothing hood were
observed inside a contaminated area in a residual heat removal (RHR)
pump room.
- Debris was found floating in the spent fuel pool.
- In the basement of the cooling tower, a 3-inch pipe was supported by !
heavy gauge wire. t
- A folding chair was found laying on a duct in a ventilation room.
- Numerous minor deficiencies were identified in many operating spaces, ;
which included items such as panel covers loose, missing screws on
conduit supports, and missing screws in electrical junction boxes.
- An unsecured ladder was found in the west end of the Tunnel D. The
three unsecured and unattended ladders, which includes the two ladders
discussed in Section 2.2.2, found in nondesignated ladder storage areas
constituted an unanalyzed potential missile hazard. Although of minor
significance, the inspectors noted that the licensee had not provided
procedural guidance on how to properly store unattended ladders.
Licensee management stated that a policy for handling unattended ladders
would be established and provided to plant personnel.
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- In the Unit Cooler 9 room, the inspectors observed the storage of -l
plywood that was not treated with fire retardant. The licensee's i
procedure required that all wood used in buildings be treated with fire
retardant. The licensee removed the plywood when notified of the
location by the inspectors. This observation was considered an isolated
case since similar concerns were not identified during additional tours
by the inspectors.
The inspectors considered the overall housekeeping of the operating spaces to
need additional management attention. The above items are considered
examples, in addition to the examples identified in Section 2.2.2, of
operations personnel not displaying a proactive problem identification and
questioning attitude during routine tours of the facility.
2.5.2.2 Spare Breakers
The inspectors identified that breakers labeled as spare, located in various
safety- and nonsafety-related motor control centers and electrical
distribution panels throughout the plant, were in the ON position. This was
considered to be an abnormal condition, since spare breakers are generally
found in the OFF position. In discussions with the licensee regarding the
position of the spare breakers, it was established that the licensee had
previously identified approximately 170 breakers that were labeled as spare.
However, the licensee had not established whether or not these breakers
supplied any plant electrical loads. The licensee stated that the unknown
status of the spare breakers had existed since plant startup in 1985. The
licensee also stated that in the recent past, a spare breaker had been moved
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from the ON to the 0FF position and an inadvertent actuation of engineered ;
safeguards equipment had occurred. As a result of this actuation, the
licensee did not plan on opening any additional spare breakers.
.
A review of the licensee's actions determined that the licensee had been aware
of the problem since 1985 and had not initiated efforts to determine if the
spare breakers supplied electrical loads. In July 1993, the licensee compiled
a list of all spare breakers in the plant; however, actions had not been
initiated to identify if loads were supplied by the breakers. The failure to
take timely actions to resolve a nonconforming condition is the first example
of an apparent violation of Criterion XVI of Appendix B to 10 CFR Part 50
(458/9325-04).
After discussions with the inspectors regarding the labeling and control of ,
spare breakers in the plant, the licensee initiated efforts to determine, by
field walkdown of all spare breakers using the appropriate drawings, which
breakers were spare and which breakers actually supplied electrical loads. 4
Prior to the end of this inspection, the licensee established the status of
the spare breakers and implemented actions to either place the breaker in the-
0FF position or provide an appropriate label on the breakers.
2.5.2.3 Painter Walking on Piping :
During a tour of the plant, the inspectors noted that a painter was walking on
a 1-inch pipe. In response to the inspectors' observation, an engineering
calculation verified that the 1-inch piping had not been overstressed due to
the weight of the individual. .
Management stated that guidance had been provided to plant personnel that
piping should be greater than 2 inches in diameter for personnel to walk on -
it. The inspectors questioned the basis for the 2-inch criteria, and as a
result, the licensee initiated an engineering evaluation to establish the -
criteria. Based on the results of the evaluation, the licensee established
that the pipe should be 2.5 inches or greater for a 250 pound person to walk
on it. It appeared that the 2-inch criteria previously established by the
licensee was incorrect and was based on judgement rather than an engineering l
evaluation. !
The inspectors reviewed the material provided for general employee training
and noted that there was no information provided with respect to walking on
pipes. Licensee management stated that the general employee training material l
would be revised to include this criteria and would also include guidance
about not walking in cable trays or stepping on instrument tubing. This issue l
will be tracked as an inspection followup item to verify that the training !
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material was revised and implemented (458/9325-05).
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2.5.L.4 Emergency Lighting
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A tour of the emergency diesel generator (EDG) rooms resulted in the
identification of concerns related to emergency lighting. In the Division III I
EDG room, the emergency lights were pointed toward each other instead of being
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aimed to. provide general area lighting. During a review of the emergency
light installations in the other EDG rooms, it was noted that the lights did i
not appear to be aimed at the points where the operators would be required to i
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operate equipment if a loss of normal plant lighting occurred.
'
To address this concern, the licensee adjusted the lights in the Division III ,
EDG room. In addition, the licensee stated that a review of all' emergency
light installations in the facility would be performed to verify that the
lights were properly aimed. The licensee stated that this would be
accomplished by December 31, 1993. This issue will be tracked as an
inspection followup item to verify that the emergency lights have been
appropriately adjusted (458/9325-06).
2.5.3 Containment
The inspectors toured containment and identified the following deficiencies: ,
- An extensive amount of duct-type tape was used. -
- Health physics barrier-type tape was found at the suppression pool
level.
- Plastic streamers, used for identification of low clearance areas, were
installed at various locations.
- Fiberglass material (SilTemp), used as a fire-barrier wrap, was
installed on electrical cables and conduits throughout containment.
- Rope was found over the suppression pool.
- Paper (about 2 by 3 inches) was found in the suppression pool.
- A legal-sized page of paper was found under the equipment hatch door. t
- Trash bags (yellow health physics type) were found at various locations.
- Foam antisweat insulation was installed using cellophane-type tape.
Damage and cutting of the_ tape and insulation was noted. Loose
insulation was found on Radiation Monitor RMS*RE-ll2. During review of
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this item, the licensee identified that the tape was used for
installation of the insulation during plant construction. The tape was :
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used to hold the insulation in place while the adhesive, used to seal
the insulation joints, dried. The tape should have been removed after i
the installation of the insulation was completed; however, it was not.
- A cotton glove liner and smear paper was found in the valve yoke area of
a motor-operated valve (MOV).
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- Paint flakes were found on the piping near Valve G36-FVF-021.
- A plastic bag containing additional bags was found.
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The inspectors were concerned that the quantity of material identified in
containment could potentially enter the suppression pool during an accident
and clog the ECCS strainers. The licensee documented the concerns discussed
above on CR 93-0753. As a' followup action, three crews of operations -
,
personnel inspected the containment and removed materials, including the items
identified by the inspectors. According to licensee estimates, approximately .
10 gallons of material was removed from the swell area of the suppression
pool.
To address the issue of potential clogging of the ECCS strainers, the licensee
performed an immediate operability determination of the_ status of the material
inside containment. The determination was performed based on the material
remaining in containment after the operations crews had removed the material
found during their tours. The licensee's operability determination indicated
that all systems remained operable.
At the time this inspection ended, the licensee was in the process of making
an operability determination that assumed all of the material was inside
containment. This issue will be tracked as an unresolved item pending
completion of the operability determination by the licensee and a review of 4
the results by the NRC (458/9325-07).
.
During the tour of containment, the inspectors identified the following !
material condition deficiencies ,
- The conduit connection to Valve ICMS*SOV33B was not made up properly. ,
CR 93-0749 was written to document the concern of exposed wires on this
valve.
- The mounting of Radiation Monitor 1RMS*RE-16A and the~ wire connections
inside appeared questionable.
Lights on the fuel deck and a light above the cooling water supply line
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to the containment coolers were broken or burned out. *
- Emergency Light 1LAR-lR16-16-0-A-2 had a broken fixture. -
- Snubbers BX78F1 and GB09F, on the cooling water supply line to the
crntainment coolers, would not rotate. CR 93-0756 was written to ,
document the concerns with these snubbers. ,
- The packing for Valve 1HVN*TCV-122 was leaking.
- Fire protection material (lagging) on structural steel was not
completely covered, as fabric and wires were visible. ,
,
- One light fixture was broken and hanging by wires and another one was
tied back with a rope. The fixtures were located at the equipment
' hatch.
- Lagging on Relief Valve ISWP-RV-119 was not complete.
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The licensee, in response to the items identified above, performed an
operability determiration to verify all equipment could perform its intended
safety function. No operability concerns were identified by the licensee and
efforts to repair the equipment were initiated. Due to the nature and extent
of the items identified by the inspectcrs, it was apparent that licensee
personnel are not identifying nonconforming and deficient conditions during
tours of containment. This was a further example of the lack of a questioning
attitude and pant personnel not being proactive in identifying deficient or
nonconforming conditions.
2.6 Walkdown of an Emeroency Diesel Generator j
The inspectors performed a detailed walkdown of the Division II EDG. Valve -
positions were verified in the starting air, fuel oil, lube oil, Jacket water,
and service water support systems. The valve lineup list in
Procedure SOP-0053, " Standby Diesel Generator," Revision 8, was compared to
the associated P& ids to verify consistency. The valve lineup list contained
all the valves shown on the P& ids. One minor discrepancy was noted in that a
drain valve (Valve 30058) was closed and the P&ID indicated that its normal
position was open. The valve lineup list indicated that the valve should be :
'
closed. Discussions with the licensee determined that the P&ID was incorrect
and the correct position was closed, as indicated by the valve lineup list. A
change notice was initiated to correct the P&ID. The electrical lineup was
verified to be in accordance with Attachment 3B to Procedure SOP-0053. No
valves or electrical components were found out of their expected position.
Prior to this inspection, the licensee, as a result of their reviews, had
generated 17 MRs to upgrade various skid-mounted equipment P& ids to ensure
consistency between the installed configurations and the drawings. Although !
no discrepancies between the P&ID and procedure valve lineup list were
identified, other than the minor issue discussed above, the upgrade program
included the EDGs and was tentatively scheduled to be completed for all !
skid-mounted equipment by the end of March 1994. ,
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The general appearance of the EDG was poor. Oil leaks were visible and
various pieces of insulation were torn or missing. The paint on the diesel
and the associated support equipment and piping was flaking and/or worn.
While no inaccurate component labels were identified on the EDG or support
systems, the general quality of the permanently installed component tags and
labels was poor. The labels were small, susceptible to glare, and difficult
to read. The licensee had implemented a program to install improved labels i
and tags on components. The new labels and tags, where installed, were much
clearer and easier to read than the majority of the currently installed '
labels.
During the walkdown of the EDG, the inspectors noted that the emergency ;
shutdown button for the engine was unprotected (i.e., did not have a cover i
installed to prevent inadvertent tripping of the EDG) and in a particularly l
vulnerable location. Depressing the button when the EDG was operating in the '
emergency start mode would cause the EDG output breaker to open and initiate l
engine coastdown. When the engine reached 120 rpm, the button would
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automatically reset and reinitiation of the emergency start sequence would
begin. Therefore, depressing the button would result in a loss of power to a ,
vital bus for approximately 45 to 60 seconds, which could affect the
capability of the ECCS systems to remove decay heat from the core.
During discussions with the licensee, the inspectors established that the
emergency button had been inadvertently pushed on two previous occasions. On
both occasions, personnel were performing corrective maintenance on the EDG,
during operation of the diesel for surveillance testing, when the wrench they
were using slipped and caused the individual to inadvertently prass the '
emergency stop button, which shutdown the engine.
To address the vulnerability of the emergency stop button, the licensee issued
a CR in 1992 that required a sign be placed adjacent to the button to warn :
personnel that depressing the button could stop the diesel. The CR was closed ;
based on a label request form being initiated to create the signs. A sign was !
installed for the Division II EDG, but was not installed on the Division I
EDG. After discussion of this issue with the licensee, a cover was installed !
on both EDGs to prevent inadvertent depressing of the button. However, the
failure to implement timely actions to correct a nonconforming condition is l
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the second example of an apparent violation of Criterion XVI of Apperdix B to
10 CFR Part 50 (458/9325-04). .
The inspectors also toured the Division III EDG room. The licensee had
performed considerable efforts tc upgrade the appearance of the equipment 1
located in the room. The efforts included painting of the EDG and support
equipment, all interconnecting piping, all structural components, and the
walls, floor, and ceiling of the room. In addition, the licensee had
installed new, easy-to-read component labels and valve tags. The licensee <
referred to the room as the " showcase" area, which was a representation of how
the entire plant would look when the licensee completed the plant appearance
upgrade program in the near future. The inspectors noted that the ,
housekeeping and material condition in the room was excellent. !
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2.7 Operations Department Problem Identification and Resolution
2.7.1 Condition Reports j
The inspectors reviewed a sample of eleven CRs related to operations, )
including personnel errors, and the subsequent disposition of the CRs. A J
sample of the corrective actions were reviewed for completion and the !
inspectors noted that the root causes and corrective actions were generally l
appropriate for the conditions identified by the CRs. '
The recommended corrective actions included procedure changes, required
reading, training, and information memoranda. A review of several procedure
changes, training attendance records, and memoranda indicated that the
recommended corrective actions were appropriately completed. However, one
instance was identified where a recommended corrective action was implemented
but not continued.
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CR 93-0467, which documented a clearance tagging error, recommended placing a
check sheet into each MWO package requiring a clearance as a general reminder
to crafts personnel on what should be verified to ensure a clearance was
properly completed prior to starting work. The . inspectors reviewed several
MWO packages following release of the package to the field for work and noted
that no check sheets were included. Discussions with Operations management
and work group planners concluded that the check sheets had been placed in MWO
packages previously, but when the work management center was activated, the
practice was not continued. The use and inclusion of the check sheet in MWO
packages was subsequently reinitiated after discussions with the inspectors.
Interviews were conducted with equipment operators, R0s, SR0s, and a chemistry
technician to determine their perception of the CR process. Without
exception, the interviewees indicated that they would not hesitate to write a
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CR, if warranted. Several indicated that they would take the issue to their
supervisor for discussion and would prefer that the supervisor write the CR.
However, all stated that if they believed the condition should be documented
on a CR, even if the supervisor disagreed, that they would initiate the CR
themselves. The individuals indicated that they had been encouraged to j
identify adverse conditions and instructed that identification and elevation i
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of these identified conditions to management was the proper way to obtain
corrective action.
All interviewees were positive regarding the attention that degraded
conditions received when reported and indicated that this was a fairly recent
and welcome change, which started when the new Plant Manager arrived on site.
One individual stated that his general perception had previously been to not
bother reporting adverse conditions because nothing would be done about them
anyway. He also added that he had no specific knowledge of any known adverse
condition that went unreported.
I In discussions with operations personnel, it was indicated that a positive
change had occurred with regard to the emphasis that the new Plant Manager had
placed on correcting deficiencies and making the plant more efficient and
easier to operate.
2.7.2 Emergency Operating Procedure Discrepancy Sheets
)
During a plant walkdown, the inspectors observed that manual Valve 1E12*VF063C {
(the condensate transfer system supply valve to the RHR system for alternate i
reactor pressure vessel level control) was located approximately 20 feet in
the overhead, with no apparent access to the valve. The valve was required to
be operated during implementation of Enclosure 6 to Emergency Operating
Procedure (EOP) E0P-0001. There was no ladder of sufficient length in the
immediate area that could provide access to the valve, although a designated
ladder storage area was nearby.
Subsequent discussions with the licensee determined that the inaccessibility
of this valve had been previously identified on several occasions, and as a
result, a ladder had been prestaged in the designated ladder storage area. An l
MR had been initiated on March 18, 1990, when it was identified that the valve i
should have a chain operator installed to facilitate operation of the valve
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during accident conditions. The MR stated, during an accident condition, the '
area may be hazardous due to radiological conditions or other safety concerns,
such as a loss of lighting. A second MR was initiated on February 25, 1991,
requesting the installation of a chain operator on the valve. This MR
indicated that the use of a ladder.to access the valve for operation was ,
inconvenient during normal operations and could be hazardous during accident
conditions. This MR was subsequently placed in the system enhancement file i
(SEF 91-9040) for future consideration and/or implementation.
The safety enhancement file was established by the licensee to collect items t
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that were considered to be plant enhancements and not required to address
deficiencies with the operation or operability of components or systems. An
evaluation was performed by the licensee before an item was placed in the file
to ensure that the item was an enhancement and not a required modification.
It appeared that this item should not have been placed in the system
enhancement file. This issue will be tracked as an inspection followup item
pending review of the contents of the system enhancement file by the NRC >
(458/9325-08).
On May 23, 1991, as a result of. the licensee's review of E0Ps, an E0P -
discrepancy sheet documented that a ladder needed to be provided for access to
the valve. This represented the third time that documentation was initiated
to provide access to Valve IE12*VF063C and actions had not been completed to i
ensure that access to the valve was maintained. l
Following the inspectors' discussions with the licensee, a ladder was located ,
in the vicinity of the valve. With the location and orientation of the valve, j
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and the necessary orientation of the ladder, the inspectors assessed that the
operation of the valve appeared to be possible, but potentially physically {
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hazardous.
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The failure to provide timely corrective action to an identified nonconforming
condition is the third example of an apparent violation of Criterion XVI of
Appendix B to 10 CFR Part 50 (458/9325-04).
Several other E0P discrepancy sheets were reviewed for disposition. One of
the sheets indicated that the necessary injection equipment, for +
implementation of Enclosure 15 to E0P-0001, was not staged or specifically ;
designated for E0P use. To determine the current status of the equipment, the
inspectors reviewed Revision 5 of Enclosure 15 to verify that the material was ,
staged and designated for E0P use only. Some minor discrepancies were noted, ;
which included the dolly referenced in the procedure for-transport of the -
staged equipment was not in the equipment box and the air supply hose to .
operate the injection pump was in the equipment box, but was not referenced in ,
the procedure as being required. These minor observations were brought to the
licensee's attention for action. t
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On September 23, 1990, an E0P discrepancy sheet was generated to identify the :
need to have a wide-range suppression pool water level instrument installed.
The original meter display scale ranged from +4 to -18 feet from normal level. ,
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The instrument physically installed in the plant to measure level could only
measure to -14.75 feet below normal level. This condition was originally
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identified in CR 86-1434, dated September 17, 1986. MR 86-1844 was generated
in 1986 to address the discrepancy between actual instrument capability and
the control board indication. Neither the level transmitter nor the meter
scales had been changed, although an operator aid was installed to alert the
operators that the indicated level would not decrease below -14.75 feet.
During review of the status of the actions taken by the licensee to address
the level instrument indication, the inspectors noted that this issue was
previously identified by the NRC in July 1990. In NRC Inspection
Report 50-458/90-16, a deviation (458/9016-01) was issued because the
installed instrument could not indicate the range that was stated in the FSAR.
In a letter dated October 11, 1990, which provided the licensee's response to
Deviation 458/9016-01, it was stated that MR 86-1844 would be implemented by
the end of Cycle 4 (March 5,1992). The letter also stated that the
description of the range of the instrument in the FSAR would be updated.
Updating of the FSAR was completed by the licensee.
The modifications specified by MR 86-1644 had not yet been implemented. The
failure to implement timely actions to correct a nonconforming condition is
the fourth example of an apparent violation of Criterion XVI of Appendix B to
10 CFR Part 50 (458/9325-04).
2.7.3 Procedures
During the performance of surveillance testing, an operator racked out two
circuit breakers in accordance with Procedure 50P-0046, "4.16 KV System," '
. Revision 6, with Change Notice (CN) 93-0807 attached. The operetor used
Revision 6 to perform the evolution, instead of Revision 7 that was in effect i
at the time. The inspectors noted that there was no significant difference
between Revisions 6 (including the CN)'and 7.
When notified of the use of the wrong procedure revision by the inspectors,
the licensee documented the concern on CR 93-0645. The licensee found that
the distribution of procedures from the control room was changed from 4 to 11
copies; however, the clerk responsible for distribution was not informed of
the change. Further review by the licensee identified that this same problem
had occurred during the previous performance of this evolution, as documented
on CR 93-0556. The CR had been closed out on October 14, 1993, before the
identification of the second occurrence of this problem. The corrective
actions taken by the licensee did not prevent recurrence.
The failure to implement actions to correct a nonconforming condition is the
fifth example of an a; parent violation of Criterion XVI of Appendix B to 10
CFR Part 50 (458/9325-04).
In May 1993, the licensee made organizational changes that resulted in
authorities and responsibilities being reassigned to different organizations.
Specifically, the title of Manager-River Bend Oversight, referenced in
TS 6.2.3, was eliminated in the reorganization. At the time the changes were
made, a memorandum was issued to all plant personnel to explain the changes;
however, the memorandum did not discuss how the responsibilities and
authorities had been reassigned. The licensee stated that the appropriate
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procedure changes would be made by January 31, 1994, to reflect the new
organizational titles. i
During a review of procedures used to perform safety-related evolutions, it
was identified that some procedures contained more revision sheets than the ,
original procedure. The licensee had established an administrative :
requirement that any procedure would be revised when four procedure change
notices had accumulated against it. To avoid the task of revising a
procedure, when the fourth change was generated, the change included the '
previous three changes. Thus, when the fourth change was issued, it became'
the first active change against the procedure. By using this method, the
licensee's administrative requirement to incorporate changes by a specified
number of revisions was avoided. For example, one procedure was reviewed that i
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had approximately 150 revised pages attached to the original 120 page !
procedure. An excessive number of revised pages was generally typical for the d
procedures reviewed by the inspectors.
Although no examples were identified where the appropriate pages or steps of a :
procedure were not being used, the inspectors were concerned that the
cumbersome method of integrating a b rge number of revised pages into an ,
original document could result in the latest approved changes not being used
or confusion for the procedure user. The inspectors noted that plant
personnel did not utilize the procedure change process because the process was
cumbersome and time consuming. The licensee acknowledged that the revision
process used was cumbersome and stated that efforts had been initiated to ,
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change the method used for revising procedures. The current status of the
licensee's procedures was a concern to the inspectors.
The inspectors were informed that steps had been initiated to improve the !
condition and control of all procedures. The licensee had been converting l
procedures to a more automated system since May 1993. The licensee stated ,
that all procedures would be converted to a personal computer system by early 'j
1994. ;
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2.7.4 System Deficiencies l
The inspectors, during tours of the facility, identified concerns with plant
equipment. The concerns are discussed below-
!
- The reactor water cleanup system backwash panel contained an operator !
aid, which stated that the light bulbs could not be changed without ;
blowing fuses, and referenced CR 93-0802. Discussions with the system '
engineer indicated that, if a fuse were to blow, it could result in
repositioning of the valve associated with the light bulb being changed.
This was identified by the licensee as a work-around item. '
Additionally, MR 86-1138 was initiated in 1986 to rework the
conductivity recorder on the backwash panel and the HR had not been
implemented. This recorder provides input to an annunciator in the
control room, which caused an occasional distraction to the operators.
The MR had not been worked because it provided no trips or operator
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actions based on the annunciator. The insensitivity to "nnecessari; ,
operator distractions and the use of an operator aid on ti.9 reactor
water cleanup panel to describe system deficiencies was con & red a
weakness.
- The inspectors observed considerable chattering of the reactor plant
closed c:rling water system pump discharge check valves during a tour of
the plant. Discussions with the licensee determined that tiie c. heck
valves (ICCP-V25, -V37, and -V46) had a history of failures and required
frequent repairs. Since 1986, 16 MW0s had been generated against the
valves, requiring disassembly of the three valves 15 times. In six of
these cases, the valves were found to have excessively worn or failed
parts. Four CRs, dating back to February 1988, had been written to ;
address excessive vibration, acoustic emissions, and valve damage. This ,
issue was identified by the licensee as a problem on their tracking list
of long-standing equipment problems. MR 93-9007 was initiated, as a
result of CR 92-0900, to replace the current check valve design with a .
design less susceptible to failure in this particular application. The '!
inspectors noted that actions were underway to correct the condition of' >
check valve failures.
3 MAINTENANCE
The inspectors performed a review of the activities associated with the
maintenance of plant systems, equipment, and components. The reviews also
included surveillance testing of plant systems and equipment.
3.1 Review and Observation of Mainte m ce Activities
The inspectors reviewed the history of equipment problems and selected
equipment and associated components for review. The inspectors reviewed MW0s,
licensee event reports (LER), and CRs to evaluate the corrective actions taken
by the licensee to prevent recurrence.
3.1.1 Containment Door Seals
The inspectors reviewed numerous CRs generated by the licensee to document
failures of the containment door seals. Since plant startup in 1985, the
frequency of door seal failures ranged from a low of one failure in.1987 to a~
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high of ten failures so far in 1993. The average number of failures was about ,
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five per year since plant startup, which exceeded the one to two failures per l
year experienced at other plants with similar type seals.
The apparent cause for the high seal failure rate was excessive air pressure
supplied to the seals. Other plants with similar seals supply air pressure at j
less than 90 psig; whereas, at the River Bend Station, air pressure to the
seals was maintained at 110 to 120 psig. The manufacturer of the seals
recommended that air pressure be maintained at less than 90 psig. As a result
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of the elevated air pressure, many of the failures were a result of seal
blistering. Failures caused by seal blistering at other plants were
infrequent. >
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The licensee stated that the reason for maintaining pressure at 110 to
120 psig was based on Containment Seal Qualification Report QR-1056/1160-1,
dated June 21, 1985, which was generated by the seal vendor. The overall i
results of the qualification testing recommended that the internal pressure of
the inflatable seals should not exceed 125 psig during all operating and -
accident conditions. It was apparent from the report that the vendor did not
intend for 125 psig to be continuously applied to the seals. The licensee
apparently ignored the vendor's recommendations of maintaining the air
pressure less than 90 psig. Instead, the licensee misapplied the statements
"
provided in the vendor's report to justify using 110 to 120 psig.
'
The instrument air system pressure of 110 to 120 psig was routed directly to
the seals since the licensee had not installed pressure regulators to lower
pressure to 90 psig or less. Discussions with licensee personnel, who had
been involved in attempting to resolve the cause for the high number of '
failures, indicated that economics and lack of management attention to address '
the design of the air system were contributing factors of the repetitive seal
problems. Licensee personnel also stated that suggestions had been made in
the past to incorporate the use of regulators to limit the air pressure to ,
less than 90 psig; however, the suggestion was never implemented.
The inspectors were informed that MR 93-0071 was initiated in August 1993 to <
add pressure regulators to the air supply lines for the seals. Licensee i
personnel indicated that modifications to install the regulators would be
implemented during the next refueling outage. {
A review of the CRs related to the seal failures indicated that the causes
identified by the licensee included reasons such as indeterminate, defective
material, and excessive air supply pressure. The corrective actions !
implemented by the licensee were limited to repairing or replacing the i
defective seals.
Although corrective actions were taken by the licensee, the actions were not i
effective in correcting the root cause of the problem as evidenced by.the i
repetitive seal failures. The failure to implement appropriate actions to j
correct a nonconforming condition is the sixth example of an apparent
violation of Criterion XVI of Appendix B to 10 CFR Part 50 (458/9325-04). I
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3.1.2 Radiation Monitors .
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The inspectors reviewed CRs, LERs, and MW0s related to Radiation i
Monitors RMS*RE-11A and -11B. The monitors continuously sampled the l
atmosphere in the annulus between the reactor containment and the shield l
building. In the event that one of the monitors sensed a high radiation level j
in the annulus, an automatic transfer from the annulus pressure control system
to the standby gas treatment and annulus mixing systems would be initiated.
Each monitor required a pump to draw an air sample from the annulus. Low flow l
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conditions in the monitoring system were annunciated in the main control room.
This annunciator was important since the TS required that the standby gas
treatment and annulus mixing systems be initiated within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> if a radiation
monitor became inoperable. The signal for this annunciator originated from a
flow switch in the sample stream of the monitor. These flow switches had
experienced repetitive failures, as indicated by the numerous CRs, LERs, and
MW0s that had been generated. Review of the CRs indicated that correct.ve
actions implemented by the licensee were to simply replace the defect've
switch with a new switch. Many of the CRs reviewed indicated that the .oot
cause of the failure as a sticking flow switch.
CR 87-0606 was written because Radiation Monitor RMS*RE-11A was found to be f
inoperable. The corrective action was to revise the local / remote status
. lights on the monitor to be in parallel with the pump motor power supply -
(i.e., the annunciator would change status when motor was energized or *
deenergized). MR 87-0418 was initiated to implement the corrective actions
specified by CR 87-0606. Installation of the MR would have provided an :
alternate means, other than the flow switches, of indicating that the monitor
pump was not operating. It appeared that this MR was economical and simple,
but it was never implemented. Repeated failures of the flow switches
continued to occur.
'
The inspectors were informed by licensee personnel that the flow switches
installed in the system were possibly used in the wrong application. The
licensee was in the process of obtaining a new type of switch, and associated
,
computer software changes, at the end of this inspection period.
Corrective actions for the inoperable monitors were usually taken by the
licensee, but the actions were not effective in correcting the root cause of
the repetitive failures. Management involvement in addressing repetitive i
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failures of the radiation monitors was ineffective. The failure to correct
repetitive problems with the radiation monitors is the seventh example of an
apparent violation of Criterion XVI of Appendix B to 10 CFR Part 50
(458/9325-04).
3.1.3 Hydraulic Power Unit Pump
The inspectors observed maintenance personnel perform the disassembly of
hydraulic power unit (HPU) Pump 1RCS-P1A. The pump provided position control
for the reactor recirculation flow control valve hydraulic actuators.
During disassembly of the HPU pump, maintenance personnel observed excessive
corrosion and rust on the chain coupling. The inspectors questioned the
maintenance supervisor on whether preventive maintenance (PM) was performed on
the chain coupling. Further investigation by the supervisor revealed that the
vendor did not recommend a PM be performed on the chain coupling. Subsequent
to the inspectors' questions, a PM task was initiated to require inspection of
the chain coupling every 6 months. The lack of a PM for the coupling was _ also
documented on a feeder form included in the MWO package. This feeder form was
used to assist the planner in identifying additional PM requirements.
Maintenance personnel performed the work on the pump according to the
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procedures and work instructions. The maintenance supervisor was present
during the disassembly activities. The instructions were clear and sufficient
to perform the work.
The inspectors requested PM records for the filters associated with the HPU '
and compared the licensee's PM frequency with the vendor's recommendation.
The licensee was not able to locate the documentation to verify that this PM t
!
task had been performed for the period of March 14, 1986, through February 15,
1989. ;
The inspectors noted that the vendor recommended that the filters be changed
every 6 months or earlier. The licensee revised this 6 month requirement to -
-
every refueling outage, with no apparent justification. The inspectors
questioned the licensee's decision for deviating from the vendor's
recommendations and were informed that the maintenance discipline supervisor '
had the option to change PM frequencies for nonscfety-related equipment
without engineering approval.
3.1.4 Motor-0perated Valve Thermal Overload Heaters
On October 26, 1993, the inspectors observed two electrical maintenance i
technicians perform preplanning efforts on NWO R-154963, which required ;
replacement of the thermal overload heaters for MOV 1*HVN-MOV-22 (the
'
discharge valve for the containment cooling system). j
On August 19, 1992, during signature testing of MOVs, the licensee discovered )
that the thermal overload heater resistances on 13 MOVs were the wrong size
and needed to be changed, as specified in Design Specification 248, !
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Appendix F, " Motor Overload Heater Selection For Safety Class Motor-0perated
Valves With Overloads Bypassed." The licensee performed an evaluation, which i
documented that the 13 MOVs could still perform their intended safety l
'
function.
CR 92-0708 was initiated to document that the thermal overload resistance was
not taken into account in the voltage drop calculations. Even though the
thermal overload trip function was bypassed, the heater was connected in the
power supply circuit and would contribute to the voltage drop. Since the J
motor torque varied with the square of available voltage, the amount of
resistance in the circuit could affect the capability of an MOV to perform its ;
intended function. l
During discussions between the technicians and the inspectors, questions were !
raised as to why the MWO instructions did not agree with the MWO retest !
requirements. The maintenance planner informed the inspectors that I
discussions were held with electrical maintenance supervision and the rotest
requirements were changed without consulting the design engineer. It was
later determined that the design engineer considered the retest requirements
necessary.
On October 28, 1993, the licensee initiated MWO 161273 to retest the three
thermal overhead heaters that had been installed under MWO R-154957, for
Valve 1*CNS-MOV-130. The valve was retested satisfactorily using ,
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Procedure PHP .1020, " Preventive Maintenance of Thermal Overload Relays
Unitized and Molded Case Circuit Breakers," as required by the design ,
engineer. This was the only MWO that had already been completed without :
performing the required testing.
The inspectors reviewed Procedures ADM-023, " Conduct of Maintenance," and
ADH-028, " Maintenance Work Order," which specified that retest requirements
were determined by-the maintenance planner. The procedure referred the 4
'
planners to the Maintenance Policy Guidelines Manual for instructions _
, regarding retest requirements. CR 93-0665 was written, in response to the
questions raised by the inspectors, to evaluate the policy that allowed '
planners to change retest requirements without engineering concurrence and a
memorandum was issued, on October 29, 1993, to change Maintenance Policy
Guideline MPG-002-005, Revision 3, to ensure that, in the future, maintenance '
planners did not remove retest or postmaintenance testing requirements
specified in an MWO. The memorandum stated that the recommended retest or .
postmaintenance instructions could be altered only after receiving the
original requestor's concurrence. This issue will be tracked as an inspection
followup item pending NRC review of the control of postmaintenance activities .
(458/9325-09).
3.1.5 Electrical Breakers
On October 28, 1993, the licensee performed surveillance testing of the_ diesel i
fuel oil transfer pump per Procedure STP-309-0202. The pump failed to start i
automatically on a low fuel oil level in the day tank, as expected. On
October 29, the inspectors observed electrical maintenance personnel
troubleshoot the diesel fuel oil transfer pump breaker (EHS-MCC15B) under ;
MWO 59560. ,
The inspectors observed removal of the pump breaker. During removal of the i
breaker, the electrical technicians observed degradation of the black foam -
backing for the terminal strip stiffener brace, which was installed to hold i
the terminal blocks in place. The inspectors were informed by the technicians ;
that similar conditions had been observed in other breaker cubicles. The ,
inspectors requested the maintenance history on these types of breakers and
documentation to confirm that the degradation of the foam material had been _
previously identified. The licensee was not able to find any documentation !
that identified that the degradation af the foam material had previously been
generated. As discussed throughout this report, and as demonstrated by this
example, the inspectors concluded that the reluctance of maintenance personnel i
to use the CR system to be a significant weakness in the licensee's corrective !
action program.
The licensee informed the inspectors that the foam material had been added i
during plant construction to provide additional assurance that the terminal
block contacts would remain in place and functional. On October 29, 1993, the
electrical foreman initiated CR 93-0667 to document the degradation of the
foam material. An evaluation was conducted and the licensee determined that
the fuel oil transfer breaker was capable of performing its intended safety ,
function, in addition, the CR stated that breaker cubicles would be inspected 3
to determine the extent of foam degradation. ,
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The inspectors reviewed the licensee's actions to address the operability of
the breakers with the foam material installed and identified no problems with
the licensee's assessment.
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3.2 Preventive Maintenance Program Review l
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3.2.1 Program Implementation ;
The inspectors reviewed PM records of selected components to determine if the
required PM activities were being implemented. The PMs selected were:
a Change out of the cartridge filters for Radiation Monitors RMS*RE-11A
and 11B.
- Replacement of the hydraulic control unit (HCU) filters for the control
rod drive mechanisms.
- Oil changes for the reactor core isolation cooling (RCIC) pump bearings
and turbine. >
The inspectors requested the records documenting completion of the PMs. The '
inspectors were informed by licensee personnel that the records were not
easily retrievable. For example, the records for completion of the PM for
replacement of the HCU filters were missing for the period of March 1986 to
February 1989.
PM records for replacement of the filt'er cartridges for Radiation- ,
Monitors RMS*RE-llA and -118 were reviewed by the inspectors. No records to '
verify completion of the PM were found before 1987. The licensee informed the i
inspectors that blanket PMs were performed before 1987 on the filter
cartridges, which would account for the lack of specific PM records. No
problems were noted during review of the available records.
The inspectors reviewed the PM records for replacement of the filters in the
HCus. The licensee presented the records that were available; however, the
inspectors were informed that documentation of completion of the filter
replacement for all HCUs could not be found. The licensee believed that a .
contractor performed the work, but did not document the completion of the l
filter replacements. CR 93-0783 was initiated to document this record '
deficiency. The licensee did not provide, prior to the end of this
.
inspection, documented evidence that replacement of all the HCU filters had
been completed. This issue is considered an inspection followup item pending
the licensee providing the records for completion of the HCU filter ;
replacement and NRC review of the records (458/9325-10), i
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Review of the PMs for replacement or inspection of the lube oil strainers for
the EDGs indicated that the licensee was performing the PMs on an as-needed ,
basis. Operations personnel checked the differential pressure of the
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strainers during daily tours. When the pressure across the strainers exceeded
20 psid, operations notified maintenance to change or clean the strainers. No
concerns were identified during this review.
The inspectors raviewe.d records for the RCIC pump bearing and turbine oil
changes. The vendor recommended that the turbine oil be changed every
12 months, but the licensee increased the frequency to 18 months to coincide
.
with their planned outage frequency. The inspectors questioned the basis for '
the extension and the licensee was unable to provide an engineering evaluation
that addressed the change in PM frequency. The explanation provided was,
based on monthly oil analysis and trending of no oil degradation, it appeared
acceptable to extend the oil change frequency. 1
The inspectors also reviewed the PM records on the RCIC pump bearing oil ,
changes from 1987 to the present. The records were difficult to track since
some oil changes were accomplished under MW0s when unscheduled maintenance was
performed. Based on the review performed by the inspectors, it appeared that
the pump oil changes were completed on the licensee's schedule of every 12
months. However, the vendor manual for the RCIC pump stated that, under
average conditions, the oil in the pump bearings should be changed at the end '
of every 6 months of operation. The licensee could not provide documentation
to indicate an engineering evaluation had been performed to extend the
recommended oil change frequency from 6 to 12 months. The issue related to
the extension of PM frequencies without an engineering evaluation will be
tracked as an inspection followup item pending NRC review of the licensee's PM
program implementation (458/9325-11).
During review of the vendor manuals to determine vendor-recommended PM
frequencies, the inspectors noted that the vendor manuals were in extremely
poor condition. Pages were falling out of some the manuals, pen-and-ink i
changes were prevalent, and the usability of the manuals was questionable.
The condition of the vendor manuals was discussed with the licensee. The
licensee stated that a 2-year program had been established to upgrade the ;
vendor manuals. Completion of upgrades for high priority vendor manuals was
scheduled for April 1994.
3.2.2 Program Review .
Based on the concerns identified in the preceding section, the inspectors
discussed the PM program with the licensee to determine the present status of
the program. ,
in 1985 de licensee decided to input the construction phase cf the PM program ;
into' a statistical analysis system database and utilize the me program for
PM maintenance during plant operations. Guidance for performance of PM tasks
was obtained from vendor manuals; however, minini information or guidance was >
provided fo the maintenance technicians on the specific work instructions ,
required *.o complete the necessary PMs. In 1986 the licensee trinsferred the
PM database to the plant management systems database; however, due to lack of :
sufficient resources, an in-depth evaluation of the PM program and its :
effectiveness was not performed.
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In June 1991 the licensee initiated a program to evaluate each PM to determine
the need to perform the PM, review the frequency of the PM, develop complete
and accurate job plans for performing each PM, improve the scheduling and
tracking system to ensure that PMs were performed by the established due date,
and modify the program to allow for on-the-spot minor rework, as necessary to
complete the associated PM.
During discussions with the inspectors, the licensee stated that a PM Action
Plan had been implemented prior to the start of this inspection. The
objective of the plan was to implement a PM program that would result in the
conpletion of PMs on their established due dates. The program goals included:
. Evaluation of the PMs for the need to perform them on a specified
frequency.
. Creation of complete and accurate job plans for each PM to allow
technicians to perform the task with minimum additional resources.
- Development of changes to improve the scheduling and tracking system to
ensure PMs were performed by the established due date.
- Modify the PM program to allow for on-the-spot minor rework, as
necessary to complete the associated PM.
Many of the items in the PM Action Plan were completed. The licensee's
schedule was to complete the review of the instrumentation and control PMs by
December 1993, electrical PMs by December 1994, and mechanical PMs by
December 1995.
The licensee also implemented a System Reliability Program as an additional
method to recommend changes to the PM program. The reliability program
monitored the maintenance history of components and systems and recommended
changes to the PM program, if needed. It appeared that implementation of the
PM Action Plan, in conjunction with the System Reliability Program, would
resolve many of the concerns identified by the inspectors.
3.3 Review of Surveillance Testing Performance
'
3.3.1 Diesel Fire Pump
The inspectors observed testing of the diesel-driven fire pump, as specified ,
in Procedure STP-251-3205, " Diesel Fire Pump Operational Test." The
inspectors noted that the installed plant instrumentation was not included in
the measuring and test equipment program, but was used to record system ,
'
flowrates . The instrumentation included in the measuring and test equipment
program was routinely calibrated to ensure the accuracy of the reading 1.
Because the installed instrumentation was not calibrated in accordance with
the established frequencies of the test equipment program, it should rot have ,
been used to verify that system parameters complied with th.e requirements i
specified in the TS. l
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After the observation by the inspectors, the licensee documented the failure
to use an appropriately calibrated instrument on CR 93-0642. Further
investigation by the licensee found four similar instruments that had been
used to record fire protection system parameters.
The instruments in question were calibrated and found to be within established
tolerances., and as a result, validated the data that were reccrded during
performance of the test. The licensee reviewed past test records and verified
that no operability concerns existed with the previous testing that had been
performed on the fire protection system.
!
3.3.2 Low Pressure Coolant Injection Pump
The inspectors observed testing of low pressure coolant injection (LPCI)
Pump B, as specified in Procedure STP-204-4223, "ECCS-LPCI Pump B Discharge
Pressure-High Monthly CHFUNCT, 18 Month CHCAL, 18 Honth LSFT (E12-N0558, ;
E12-N655B)."
The performance of this surveillance test on the pump discharge pressure
transmitter was terminated when it was determined that air was trapped in the
test lines, which would have caused incorrect readings. The procedure did not
provide instructions for venting the pressure transmitter at the high points
to remove the air after the test equipment was connected. The test was
accomplished later in the day after an MWO was generated to provide
instructions for venting the transmitter. The licensee stated that an NWO had
been used in the past to provide instructions for venting the system whenever
this test was performed.
The licensee documented this problem on CR 93-0719 and determined that 79
additional procedures also failed to provide the appropriate venting
instructions. The licensee stated that each affected procedure would be !
revised, by adding a requirement to vent at the high point of the transmitter, !
prior to the next use of the procedure. The failure to provide an adequate
procedure for testing a safety-related system is the second example of an
apparent violation of Criterion V of Appendix B to 10 CFR Part 50 *
(458/9325-03).
3.3.3 Residual Heat Removal Valve
i
The inspectors observed testing of an RHR valve c as directed by
Procedure STP-204-6304, " Loop B RHR Valve Operability Test." During review of
the test procedure, the inspectors noted that the acceptance criteria for all '
inservice testing of valves was transmitted'to the control room in a document
entitled, " Report 20." This report was reviewed by the inspectors for . 7
accuracy and it was determined, by review of selected entries, that the TS and -i
the ASME Section XI acceptance limits were correct.
Report 2D was not maintained in the licensee's standard document control '
system. Revision 6A of Report 2D was approved on November 30, 1992. There
were five different dates of pen-and-ink changes that had not been
incorporated by Revision 6 and there were at least two pen-and-ink changes
made since Revision 6A was issued. No dates or initials were entered to
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identify who had made the changes and when the changes had been made, on all
pages except one. !
Related problems had been previously identified by the licensee on CRs 92-0650 i
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and 93-0564. The corrective actions specified on the CRs were to issue a new
procedure to establish the requirements for issue, review, approval, and
distribution of the inservice testing acceptance criteria. The new procedure i
was due to be issued by December 1993.
Review of completed testing procedures was performed prior to the end of this
inspection period due to time constraints; therefore, this issue will be
tracked as an unresolved item to ensure that the licensee had established i
appropriate controls for the acceptance criteria and the criteria were
appropriately specified in testing procedures (458/9325-12). ,
This surveillance test was also the subject of a quality assurance (QA) audit. l
The inspectors considered the audit to be a good review of the surveillance
activity. The auditor issued CR 93-0664 to document the problem involving the t
recording of pen-and-ink changes in an approved document.
'
3.3.4 Low Pressure Coolant Injection Pump
The surveillance testing specified in Procedure STP-204-6302, " Division II
LPCI (RHR) Pump and Valve Operability Test," was observed by the inspectors. ;
This surveillance test was terminated before completion. The testing
activities were observed by a QA auditor. The auditor identified several '
problems in the performance of this surveillance test, which were documented
on CRs 93-0666, -0667, and -0668. The auditor's concerns were that the
operator did not fully follow the procedure, did not implement satisfactory '
radiological practices, and the procedure was not adequate. The auditor
performed an excellent review of the surveillance test.
,
During performance of this test, the operator failed to secure the temporary
pressure gage to a structure, and as a result, the gage fell from a pipe and
became disconnected from the tubing used to attached the gage to the system
piping. When the gage became disconnected, process fluid was sprayed in the
area and contaminated a person observing the testing. The failure to provide
the appropriate instructions in a procedure for performance of safety-related ,
testing is the third example of an apparent violation of Criterion V of .
Appendix B to 10 CFR Part 50 (458/9325-03). ;
The licensee stated that a plan, to correct the procedure inadequacy of not
requiring test instrumentation be temporarily attached to a plant structure, .
would be performed by a comprehensive review and upgrade of all inservice
testing procedures. Training will be provided to Operations personnel on
securing instruments during testing.
.
3.3.5 Radiation Monitor
The inspectors witnessed the performance of testing of a radiation monitor, as
specified in Procedure STP-511-4514, "*RMS-Main Plant Exhaust Duct Noble Gas
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Activity Quarterly CHFUNCT (1RMS*RE125)." :
This surveillance test was terminated early because the procedure was [
inadequate, as written. The inspectors found problems such as a note at ;
Step 6.10 was not readable and not possible to follow and Step 7.1.5 required i
the individual conducting the test to perform 14 different operations within
30 seconds, which was not physically possible. Three of the 14 operations ;
were TS verification steps. The operator dispositioned these problems with
test comments until he reached Step 7.1.7.3, which required operation of
equipment that had not been previously identified as required to be used.
As a result of the observations made by the inspectors, the licensee ;
'
documented the procedure inadequacies in CR 93-0663. Further review by the
licensee determined that the same problems existed in 36 additional
procedures. A review of the completed tests found the same inadequacies in ,
the procedure used for the last six quarterly tests. The failure to provide
an appropriate procedure for the performance of a safety-related test is the ,
fourth example of an apparent violation of Criterion V of Appendix B to 10 CFR
Part 50 (458/9325-03).
3.4 Review of Surveillance Test Exceptions
The inspectors reviewed a sample of 17 surveillance tests that documented test
exceptions and unsatisfactory conditions that were identified during the
performance of the testing. The following observations were made as a result
of this review:
- Procedures STP-204-1200, "LPCI Pump Start Time Delay Monthly Channel ,
Function Test"; STP 209-3301, "RCIC Valve Operability"; and
STP-209-6310, "RCIC Pump Operability and Flow Test"; were missing a
cautionary note on the prohibition of the use of alligator-type clips. ,
The prohibition of alligator-type clips was implemented in response to
corrective action.s implemented in response to a violation identified in
NRC Inspection Report 50-458/89-11.
The licensee, as corrective action for the violation, issued a CN to an
administrative oncedure to address the prohibition of the use of :
'
alligator-type citps. The CN required the addition of a note to all
applicable eiera ical and instrument and control procedures, but did not
address operating procedures, which also specified the use of ,
alligator-type clips. The licensee issued CN 93-1062 to require adding,
this note to all applicable operating procedures.
The inspectors did not identify, during plant tours or the observation
of maintenance and surveillance activities, any plant personnel using L
alligator-type clips.
Pressure-High, Monthly CHFUNT, 18 Month CHCAL, 18 Month LSFT (E51-N055E,
E51-N655E)," Revision 7, with CN 93-0657; and STP-209-5201, "RCIC
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Isolation-RCIC Turbine Exhaust Diaphragm Pressure, High Monthly CHFUNCT,
18 Month CHCAL, 18 Month LSFT (E51-N055B, E51-N655B)," Revision 7A, with
CNs 93-0185, -0226, and -0947, were noted by the inspectors to contain
requirements to alarm Annunciator 2473, " Reactor Core Isolation Cooling
System Inoperative." Howevery the procedure did not contain
instructions for restoration of this alarm to a safe and stable
configuration after completion of the testing. The licensee issued
CR 93-0743 to correct the minor procedural inadequacies identified by
the inspectors.
3.5 Review of Surveillance Test Comment Control Forms
The inspectors reviewed the use of comment control forms, which were provided
by the licensee to make minor changes to procedures for such items as
typographical errors. The comments provided on the forms were to be used to
correct a procedure during its next revision. The inspectors reviewed the
files of comment control forms located in the instrument and control shop and
noted that the files contained numerous old comment forms.
Four comment control forms were reviewed in detail. The inspectors found a
form, dated January 29, 1990, that changed a TS verification step of
Procedure STP-511-4209, "RMS-Main Control Room Ventilation Radiation Monitor
Local Intake 18 Month CHCAL (RMS*RE13A)," Revision 4. The form changed the
established procedure requirement from verifying that the annunciator had
alarmed to verifying that the annunciator had not cleared. The comment
control form implemented an on-the-spot procedure change without obtaining
review and approval of the change.
The licensee documented the failure to' properly change a procedure, after
identification of the problem by the inspectors, on CR 93-0696. The licensee
implemented immediate corrective actions by prohibiting further use of comment
control forms. The failure to properly obtain approval of a procedure change
is the fifth example of an apparent violation of Criterion V of Appendix B to
10 CFR Part 50 (458/9325-03).
3.6 Implementation of the Condition Report Process
The licensee's CR program was established such that any individual involved in
plant activities could initiate a CR. During discussions with licensee
personnel, the inspectors noted that the general plant population was aware of
the CR process and initiated CRs, when required. However, the inspectors
noted that there was reluctance by maintenance personnel to initiate CRs. A
number of individuals stated that they did not know how the CR process
functioned or how to obtain the information required by the CR form. The
individuals interviewed stated that they were not aware of a nonconforming or
deficient that had not been reported. As a result of the observations made by
the inspectors, management stated that training would be initiated to ensure
that maintenance personnel fully understood the CR process and how to obtain
the information required to complete the form.
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4 ENGINEERING
- The inspectors reviewed the onsite engineering organization for organizational
structure and interfaces, work backlogs, technical quality of work activities, ;
and support for plant operations. ;
4.1 Review of Modification Recuests ,
The inspectors reviewed the listing of MRs and noted that there were 505 MRs
open as of September 8, 1993. The inspectors also noted that of this total,
242 items had been open for more than 5 years. The inspectors identified a
large number of open items related to correcting drawings, other documents,
and equipment labels to reflect the as-built condition of the plant.
4.1.1 Control Room Panel Labels
The licensee initiated MR 87-0192 in March 1987 to correct the identification
labels on the control rooni panel for the purge and exhaust fans and associated
dampers. The modification had not been implemented, but was placed in the
system enhancement file (SEF 93-004), which was an indication that the
licensee considered the correction of the labels to be an enhancement and not
a nonconforming condition that required timely correction. See Section 2.7.2 !
for a discussion of the licensee's system enhancement file process.
The inspectors performed a tour of the control room to observe the
installation of the labels. The inspectors noted an operator aid taped to the
control panel between the lights that provided the correct designations.
Since these amber lights served only to alert the operator of a misalignment
between the fan and its damper, the inspectors. determined that the incorrect l
labels did not significantly affect plant safety. However, the inspectors !
noted that this was another example of the licensee's apparent willingness to
live with problems, since this condition had existed for over 6 years.
The inspectors were later informed that the licensee had issued Revision 5 to
Procedure ADM-0037, " Equipment Identification and Labeling," on July 29, 1993,
to establish a simpler method for correcting labeling problems. The MR
process was considered by the licensee to be excessively cumbersome and a time
consuming method for making changes to plant labels.
4.1.2 Control Room Panel Wiring Splices
The licensee initiated MR 88-0189 in April 1988 to remove two wiring splices
installed in a control room panel. The licensee was unable to determine when ,
the soldered splices had been installed. The MR discussed.the licensee's FSAR I
commitment to IEEE Standard 420, "IEEE Trial-Use Guide for Class IE Control !
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Switchboatds for Nuclear Power Generating Stations," which prohibited the use
of wire splices inside control panels. This condition had not been corrected
at the time of this inspection.
The inspectors were informed that the two wires provided signals for a common
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alarm circuit for the standby service water system and would not have an ,
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affect on the proper operation of the system. The inspectors also noted that
CR 87-1525, which documented the problem, contained a discussicn of the
inspections conducted by the licensee to ensure that additional unauthorized
splices did not exist.
While the inspectors found the licensee's actions to evaluate the problem and
develop corrective actions to be acceptable, the implementation of the
corrective actions was unacceptable. Table 3.2-7 of the FSAR indicated that
the provisions of IEEE Standard 420 applied for low- and medium-voltage
switchgear. Section 4.6.1.2 of IEEE 420 stated that wire splices were not
allowed; therefore, the licensee had been in deviation of an FSAR commitment
for over 5 years. In addition, a decision on the reportability of the
condition was delayed until CR 93-0670 was initiated in. response to the
inspectors' questions. The licensee determined that the condition was not
reportable.
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The failure to implement timely actions to correct a nonconforming condition
is the eighth example of an apparent violation of Criterion XVI of Appendix B
to 10 CFR Part 50 (458/9325-04). :
4.1.3 Reactor Protection System Wiring Error .
The licensee initiated CR 88-0382 in May 1988 to document the existence of a-
problem with the reactor protection system (RPS) Channel 2, Bus A and B
wiring. The return lead for the scram relays on Bus A had been incorrectly
crossconnected to the return lead from the Bus B scram relays, rather than i
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returned to the Bus A neutral. A licensee inspection of the other RPS
actuation channels did not identify additional examples of this wiring error.
CR 88-0382 indicated that the root cause of the problem was that the
contractor, during plant construction, routed the return lead from the relays
incorrectly. The licensee initiated MR 88-0207 to correct this wiring error. :
When the inspectors questioned the consequences of the crossconnection, the
licensee initiated CR 93-0659, which recommended that an operability
evaluation be performed. The licensee's evaluation concluded that the
condition was acceptable for continued operation until such time as MR 88-0207
could be implemented. The inspectors determined that the configuration was a
reliability concern rather than a safety concern.
The inspectors reviewed the licensee's evaluation and the applicable ,
electrical drawings. The inspectors did not identify any credible failure
mechanism that would preclude completion of the RPS safety function. However,
the inspectors questioned the timeliness of the licensee's corrective actions
since this condition existed for over 5 years. The failure of the licensee to
remove the unauthorized crossconnection is another example of the lack of
proactive problem identification and a questioning attitude.
4.1.4 Emergency Diesel Generator Elbow-Orifice Assembly
The licensee initiated MR 89-0120 in May 1989 to replace the elbow-orifice
assembly on the Division I and II EDGs. The licensee was informed by the
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diesel manufacturer that the original assembly should be replaced because a
failure of the part had been reported. The manufacturer provided a service
information memorandum on this subject on October 8, 1985, but the licensee
had no record of receiving the information until parts were ordered in 1989.
The licensee considered the assembly replacement to be a low priority product
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improvement and did not perform an operability or unreviewed safety question i
evaluation until questioned by the inspectors. l
The licensee initiated CR 93-0651 to evaluate the effects of a failure of the '
elbow-orifice assembly on the operability of the EDGs. The inspectors
reviewed the licensee's evaluation and questioned some of the assumptions and
conclusions, and as a result, the licensee performed another evaluation. The
inspectors reviewed the second evaluation and determined that the licensee had
established an acceptable basis to consider the EDGs operable. However, the
inspectors considered the licensee's actions in response to this issue, which
was identified over 4 years ago, to be neither timely nor technically
rigorous. The failure to take prompt actions to evaluate a potentially
significant safety problem is the ninth example of an apparent violation of
Criterion XVI of Appendix B to 10 CFR Part 50 (458/9325-04).
4.1.5 Residual Heat Removal System Check Valves
The licensee initiated CR 90-0914 in October 1990 to document loose and
damaged internal parts in RHR system check valves. The check valves were
located in the RHR return line to the suppression pool. Since the check
valves were not required for any isolation function, the licensee decided that
removal of the internal components, to ensure that parts would not come loose
and restrict RHR system flow, was appropriate. CR 90-0914 was closed when
MR 91-0064 was initiated to remove the check valve internals. The inspectors
noted that the MR had not been implemented and questioned the postponement of
removing the check valve parts, which could potentially block the suppression
pool cooling flow path.
In response to the inspectors' questions, the licensee initiated CR 93-0653 to
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evaluate the operability of the RHR system. The licensee concluded that
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potential failures of the check valves would not prevent the suppression pool
cooling mode of operation from being established. The inspectors reviewed
drawings of the check valves and the downstream restricting orifices and
agreed with the licensee's conclusions. The inspectors were also informed
that the check valve internals were scheduled for removal during the next
refueling outage.
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4.1.6 Licensee Review of Modification Requests
As a result of the issues discussed above, which were identified during the
first week of this inspection, the licensee initiated a review of the open
MRs. The licensee reviewed 441 MRs and determined that 127 of the MRs had
been initiated as a result of deficiencies or degraded conditions. The
licensee initiated 22 new CRs to more thoroughly evaluate the conditions that
had not been resolved during implementation of the associated MR. Two issues
were identified by the licensee that required further evaluation and involved
completion of an operability determination.
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The licensee declared the motor-operated, suppression pool suction
Valve IE22*MOVF015 inoperable, on November 5,1993, because of a condition i
that had been identified in 1986. The licensee had initiated CR 86-0045 to l
document the unauthorized termination of three wires on a single terminal '
screw in an MOV. The condition was to be corrected through MR 86-0060, but
the MR had not been implemented. The licensee completed the reevaluation of
the condition, which was initially identified 7 years ago, and concluded that '
the valve was operable with the unauthorized configuration. The recommended
corrective action of the reevaluation was to implement MR 86-0060.
The licensee also initiated CR 93-0727 and performed a reevaluation of the
operability of two tornado dampers. The interference between the i
counterweights connected to the dampers and structural supports prevented full
closure of the dampers. This condition was originally documented in
CR 89-0070, issued in February 1989. The licensee initiated MR 89-0054 to i
trim the structural support for each damper to eliminate the interference and 1
allow full closure of the dampers. This MR was never implemented. The !
licensee's recent review determined that the failure of the dampers to fully
close would not result in a significant safety problem. The recommended
corrective action, included in CR 93-0727, was that MR 89-0054 should be ,
implemented as soon as possible. l
The inspectors reviewed the licensee's reevaluations for the M0V wiring l
termination and the tornado damper interference problems and found that the
reevaluations provided an adequate basis for the operability determination.
The inspectors noted, however, that these two issues, in addition to several
of the other issues discussed above, had been identified a number of years i
earlier and actions to address these nonconforming or deficient conditions has !
not been taken. l
4.2 Drawin_qs
The inspectors noted numerous problems with facility drawings. The review of
open MRs contained numerous entries to revise drawings to reflect the as-built
conditions of the facility. For example, the licensee reevaluated the
conditions of tornado dampers (discussed above) and utilized existing
drawings. During the licensee's walkdown of the tornado damper configuration,
drawing errors were discovered with the numbering of the dampers. The
drawings reflected the problem dampers as the inside dampers, but they were '
actually the outside dampers. While the inspectors did not consider this type '
of drawing error to represent an operability problem, the inspectors were
concerned that operation of the components could become a problem.
The inspectors discussed this concern with licensee personnel, who
acknowledged the problem. The licensee stated that an administrative limit
existed that required a drawing be revised when ten changes were issued ,
against a drawing. The inspectors were informed that there were over 10,000
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outstanding changes awaiting incorporation into 6,000 drawings. The licensee
stated that no drawings had ten or more changes issued against them. An
example of how not incorporating drawing changes affected the performance of .
engineering personnel, involved a portion of the main control boards. - Design !
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engineering stated that no additional modifications would be implemented to i
portions of the main control boards since so many drawing changes existed that
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the present status of the control board wiring could not be determined.
The inspectors were also informed that the licensee was initiating plans to go )
to an automated computer assisted drawing system and planned to revise the i
drawings to include all changes by July 1994. l
This issue, and the issue identified in Section 2.4, will be tracked as an ,
inspection followup item pending review of the licensee's program for the
control and incorporation of drawing changes (458/9325-02). ;
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4.3 System Engineering
During performance of this inspection, the inspectors had frequent discussions ..
with personnel in system engineering regarding the status of their assigned !
systems. As a result of these discussions, the following items were
identified: ,
e Management expectations for the performance of the system engineers was ;
poorly defined. For example, the inspectors noted that the system
engineers did not routinely observe maintenance and surveillance :
activities performed on their assigned systems. The procedure that !
provided guidance for the engineers did not address management's i
expectations with respect to the engineer's involvement in the these ;
activities. j
- The inspectors noted that the system engineers were hesitant about
initiating CRs because this represented an increased workload for them.
Since the system engineers were involved in monitoring the performance
of systems and equipment, the inspectors were concerned that
deficiencies were not being entered into the CR process. The inspectors
discussed this concern with several engineers and were assured that all
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deficiencies were being resolved, either by issuance of an MWO or a CR.
licensee management stated that discussions would be held with the
system engineers regarding each engineer's responsibility to use the CR-
process.
- Licensee procedures contained an administrative requirement that each
system engineer prepare a quarterly. report on the status of their. .
assigned systems. The purpose of the report was to identify items such
as any component and/or equipment issues that needed to be resolved,
repetitive failures of components and/or equipment, and recommended ,
modifications that would enhance the reliability of the system. The {
inspectors noted that reports for all systems were not being completed
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on a quarterly basis.
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- During discussions with the engineers concerning the emergency stop .
button installed on the Division I and 11 EDGs (see Section 2.6), the j
inspectors noted that the engineer's knowledge of system interrelations I
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appeared to be weak. For example, the engineer did not appear to be
aware of what would happen to the plant equipment, and the resulting
effects on the capability of decay heat removal, if the emergency stop
button was depressed when the EDG was operating in the emergency start
mode. s
The above issues were discussed with licensee management, who stated that the
concerns expressed by the inspectors, and other related issues, would be
addressed by a revision to the procedure that provided guidance to the system
engineers.
4.4 Engineering Workload
The inspectors conducted several meetings with engineering management !
personnel to discuss the level of engineering workload. The meetings were ,
held because the inspectors were concerned that the available engineering
resources were not sufficient to meet the apparent work requirements. The
basis of the concern was the large amount of work that had not been addressed
in the past, as discussed above; the need to provide continuing and ongoing
support for plant operations on a day-to-day basis; and the work that was
required to be completed in the future, such as the modifications to be
installed during the upcoming refueling outage in April 1994. The inspectors
were informed that the licensee had completed only 8 of 28 modification
packages for the next outage, which was only 4 months away.
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The inspectors were informed that there were approximately 60 design engineers
responsible for plant modifications and technical support for operation of the -
facility. The licensee stated that additional engineering resources were
available from other Entergy facilities and would be utilized on an as-needed
basis. The licensee also stated that additional contractor resources would be
used to assist in reducing the backlog of engineering work such as
incorporation of the 10,000 drawing changes.
5 CORRECTIVE ACTION PROGRAM
The inspection of this area included the CR program, the QA audit program, and '
the oversight programs. The inspection included the review of program
procedures and the implementation of the programs.
5.1 Review of the Condition Report Program ,
5.1.1 Procedures
Procedure RBNP-030, " Initiation and Processing of Condition Reports," '
Revision 2, with CN 030-2-1, was in effect at the beginning of this inspection-
period. Revision 3, which was in the process of being revised prior to this
inspection, was issued on November 11, 1993. Revision 3 revised the CR review
group's title and function, modified the definition of significant condition
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adverse to quality, instituted a Corrective Action Review Board (CARB), added
the responsibilities for reportability determinations, and added a requirement ,
to justify extensions of due dates for corrective action implementation.
The inspectors reviewed the procedure and noted that conditions involving
administrative, procedural, or operational errors had been added to the
definition of significant conditions adverse to quality. The inspectors found
this addition to be an improvement to the CR program.
The inspectors noted that Procedure RBNP-030 was revised to reflect the
changes in the QA organization; however, Procedures RBNP-052, " River Bend
Station Trending Program," and QAP-1.19, " Processing of QCRs," had not been
revised. Procedure RBNP-030 referenced functions performed by Operations QA
and QA Engineering supervisors / departments, which were eliminated by the ,
reorganization. The licensee stated that the appropriate procedure changes
would be made, by January 31, 1994, to reflect the reorganization of the QA
department.
The function of trending CRs was transferred to the Nuclear Safety Assessment
Group (NSAG), even though trending was previously a function of the QA
department. The trending function, which addressed the backlog of CRs and
other documents to provide'information of interest to management, performed by
NSAG did not constitute an approval process and did not appear to conflict i
with the independent function provided by the group.
5.1.2 Implementation
The licensee's program allowed a CR to be formally closed as long as the
corrective actions were to be completed on a document; such as an MWO, MR, :
engineering assistance request, quality condition report (QCR), etc. The
inspectors were concerned with this approach because the CR process required.
that corrective actions be completed within a specified time period, and if
the actions were not completed, authorization was required to extend the date
for implementation of the corrective actions. The use of documents other than
CRs did not provide a method for ensuring that the actions were completed by a
specified due date. Thus, the same level of oversight for the timely
completion of corrective actions for CRs was not applied to the other
documents used by the licensee for correcting deficient or nonconforming
conditions. For example, the inspectors noted that, at the time this
inspection was performed, 276 CRs were closed prior to 1991 based on the
issuance of MW0s. Of this total of 276 CRs,142 of the CRs had none of the
MW0s closed and 134 of the CRs had some, but not all, of their associated MWO
actions completed. This data indicated that the closure of MW0s to correct !
deficient or nonconforming conditions was not timely; whereas, the closure of l
CRs, with the exception discussed below, was generally timely. j
The issue of the use of documents that did not have a mechanism to verify j
timely completion of corrective actions of identified deficiencies will be l
tracked as an unresolved item pending an NRC review of the licensee's
corrective action process (458/9325-13).
In addition to the apparent problems discussed above with the use of
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documents, other than CRs, to implement corrective actions, the inspectors
were concerned about the accuracy of the performance indicator provided to
management that showed the number of open CRs. Of the total number of CRs ,
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opened since 1991, 70 CRs were closed based on the generation of 109 MW0s and
107 CRs were closed based on the generation of 120 MRs. The CR status report
issued to management on October 13, 1993, indicated that 335 CRs were open.
It appeared, from the above data, that the total number of open CRs was 787
(276 prior to 1991, 177 after 1991, and 335 on the status report), based on
the documents generated to close the CRs that still remained open. Because of
the method used by the licensee to close CRs, the total number of open CRs
provided as a performance indicator did not appear to accurately reflect the
total number of corrective action documents.
During a review of CRs, the inspectors noted that the completion dates "
specified on CRs had been exceeded but the corrective actions had not been
completed. The licensee's program required that a justification for an
extension of the scheduled date be provided to the Plant Manager, by the
responsible organization, prior to expiration of the due date. The status !
report of October 11, 1993, listed 15 CR dispositions overdue and-the status
report of October 26, listed 8 CR dispositions overdue.
Since the overdue status was being tracked by the licensee and apparent
actions were being implemented, this issue is considered a weakness in the
licensee's corrective action documentation process.
5.2 Review of Condition Reports
5.2.1 Elevated Drywell Temperatures
The inspectors reviewed CR 93-0413, initiated on July 15, 1993, which
documented that an access panel, in the reactor pressure vessel support skirt
insulation, was found missing and the reactor insulation access hatch on
Elevation 141 was found open. The missing segments of insulation inside the
primary shield wall, near the top of the vessel support skirt, opened a new
pathway for air flow between the vessel and the insulation, which interrupted
the normal skirt cooling ventilation path and affected the uniform cooling of
the vessel skirt. Prior to an unscheduled shutdown of the plant to repair a l
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reactor recirculation pump seal, the drywell temperature had been trending
upward and had reached an average temperature of 144oF, with one temperature
monitor reading 150 F. There was no operability concerns with respect to TS
requirements since TS 3.6.2.6 required the drywell average air temperatures
not exceed 145of.
Based on the evaluations of the high temperature conditions performed by the
licensee, one hydrogen ignitor and several electrical cables, located near the
ceiling, were replaced. Additional corrective actions were also taken, as
described in LER 93-019.
The inspectors reviewed the licensee's evaluation of the elevated temperatures
in the drywell for the potential for the degradation of protective coatings
(i.e., paint) and affects on the structural concrete around the vessel. The
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CR identified that the coatings were flaking and peeling in different areas of
the drywell. The licensee's final CR disposition stated that the coatings and
concrete were satisfactory for continued plant operation. The licensee's
justification for the use-as-is determination acknowledged that the coatings
had the potential to form solid debris during a design basis accident and
could potentially enter the suppression pool. The licensee's analysis
indicated that the probability of migration of the coatings toward the ECCS
strainers was extremely small due to the low water velocities in the
suppression pool.
The inspectors questioned the disposition of the CR and the corrective actions
taken by the licensee. The inspectors also questioned why the corrective
actions _taken for high temperature events in 1989 and 1990 were not sufficient
to prevent recurrence of the 1993 event. CR 93-0754 was generated by the
licensee to resolve these questions. The licensee completed an interim-
operability determination, within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the initiation of the CR, and
determined that all systems were operable. The licensee stated that an
independent review of the final operability assessment would be performed.
The independent review was not completed prior to the end of this inspection.
This issue will be tracked as an unresolved item pending a review by the NRC
of the effectiveness of the licensee's efforts to address the effects of the
high temperature condition inside the drywell (458/9325-14).
5.2.2 Emergency Diesel Generator Fuel Oil Storage
CR 93-0258 was initiated upon discovery inat the EDG day tank was below the
minimum level required by TS 3.8.1.1 and 3.8.1.2. The licensee evaluated the
configuration of the tank and, based on original specification information for
fuel consumption at rated load, determined that sufficient fuel oil was
present when the tank leval indicated 53 percent (370 gallons), which met the
TS requirement of 316.3 'illons. As a result of the initiation of the CR, the
licensee revised Procedure OSP-0012, " Daily Log Report," to specify the
minimum level required in the day tank.
Two aspects of CR 93-0258 were questioned by the inspectors. The licensee was
asked if the design fuel oil consumption was verified by test. According to
licensee personnel, the specific fuel oil consumption data had not been
determined. However, based on a review of available data, the fuel oil
consumption for full load had been appropriately established by the licensee.
The inspectors also asked why CR 93-0258 remained open when disposition _of the
documented problem was reviewed on July 9,1993, and the QA-review was
completed-on July 22. 1
The inspectors were informed that the CR had been returned to QA by the Plant
Manager because MR 93-0001, initiated to change the setpoints for the fuel oil
transfer pumps, was not statused in the close out section of the CR and
because the generic aspects of the problem had not been addressed. The Plant
Manager also questioned if other safety system parameters should be added to
Procedure OSP-0012.
At the end of this inspection period, the licensee was in the process of
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revising Procedure OSP-0012 to address the items identified by the Plant )
Manager. The licensee intended to issue six different procedures to replace - !
Procedure OSP-0012 in order to create a specific procedure for each of the six ,
different areas of the plant.
5.3 Review of Quality Assurance Activities .
5.3.1 Audits and Quality Condition Reports
The inspectors reviewed a 1991 audit of surveillance activities. The audit .
discussed CR 92-0085, which documented the successful completion of a !
surveillance test, even though the data required by.the procedure was not
obtained. The audit recommended a systematic review and correction of similar ;
performance problems with surveillance test procedures and management
reinforcement of standards and expectations related to the performance of the >
surveillance testing program. Another audit of the surveillance testing
program was performed in February 1993. The inspectors noted that the item
regarding the surveillance testing program, initially identified in 1991, was
not resolved and an extension for the completion of the corrective actions had
been authorized until April 2. The audit report stated that there was no :
adverse impact on plant operation as a result of this finding remaining open.
At the time this inspection was performed, this finding was still open. The
failure to implement timely corrective actionsEto address concerns with the
surveillance testing program is the tenth example of an apparent violation of
Criterion XVI of Appendix B to 10 CFR Part 50 (458/9325-04).
The inspectors reviewed Audit 93-09-I-CANC, which discussed the results of a
review of the corrective action and nonconformance control program. The audit
covered the period from August 30 through September 16, 1993. The report
stated, in part, that the results of this audit concluded the program was
ineffective and inadequate in that the program did not establish adequate ,
controls to identify and prevent recurring significant conditions from
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adversely impacting the safe operation of the facility. As a result of the ;
audit, 14 QCRs were issued, of which 10 were considered to be major findings.
The audit report stated that the root cause of the failure to prevent
recurring conditions was management's inability to establish procedural ,
measures that ensured these adverse quality trends were promptly identified
and corrected. At the end of this inspection, the licensee was formulating
the actions that would be taken to address these issues.
The inspectors reviewed a sample of QCRs to verify that the corrective actions
taken by the responsible organization appropriately addressed the identified
issue. During the review of QCRs, the inspectors noted that QCRs P-92-11-025 1
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and P-92-12-010 were not reviewed and signed by QA management. As a result of
this problem, QA personnel issued a CR and performed a review of QCRs that had ,
not received management review. Approximately 17 additional QCRs were
identified that required a final closeout review, which was subsequently
performed. ;
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5.3.2 Corrective Actien Reports *
During the review of Procedure QAP-1.8, " Processing Corrective Action Reports
(CAR) to Management," Revision 6, the inspectors noted that the procedure was
intended to provide a mechanism by which repetitive or significant conditions
could be brought into compliance. CARS were intended to be a progressive step
to correct problems prior to implementation of a stop work directive.
Procedure QAP-1.8 stated that a CAR may be issued for repetitive and ,
significant conditions adverse to nuclear safety where previous corrective
actions had not been effective. A CAR may also be issued when conditions :
requiring resolution, response, or corrective actions were not being completed
in a timely manner. The QA department was responsible for issuing, tracking,
verifying, and closing CARS. l
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The inspectors reviewed the status of the CARS that had been issued in the
past 3 years and determined that one CAR was issued in 1991 to document
hardware deficiencies in implementing the emergency operating procedures. All
corrective actions, except the implementation of MR 88-0070, which changed the
containment pressure indication from psig to psia, were completed. The
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inspectors noted that no CARS were initiated in 1992 and only two CARS were i
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initiated in 1993, one for control of safeguards information and one for
/r 'iciencies in the cheraical control program.
The inspectors identified that, for the past 3 years, there was a large number
of failures to follow procedures and personnel errors documented by CRs. The
data for personnel errors included, from August 1990 to July 1991: 98 CRs,
from August 1991 to July 1992: 60 CRs, and from August 1992 to July 1993: 31 l
CRs. The data for the lack of adherence to procedures included, from August !
1990 to July 1991: 105 CRs, from August 1991 to July 1992: 128 CRs, and from l
August 1992 to July 1993: 140 CRs. The above data were forwarded by QA to the
Plant Manager via a memoranda on a monthly basis for this 3 year period. The
licensee could not provide documentation that any actions were taken to ,
address the repetitive problems identified with the performance of the plant
staff. The failure to implement timely corrective actions to address
repetitive problems with the performance of the plant staff is the eleventh
example of an apparent violatiot of Criterion XVI of Appendix B to 10 CFR
Part 50 (458/9325-04).
5.4 Review of Oversight Programs
5.4.1 Independent Safety Engineering Group
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The function of the Independent Safety Engineering Group (ISEG), as defined in
TS 6.2.3, was to make detailed recommendations for revised procedures,
equipment modifications, maintenance activities, operations activities, or
other means of improving unit safety. The ISEG function was performed by the
NSAG. ,
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The inspectors reviewed operating experience reports, special analyses, ,
special reports, and trending reports issued by the NSAG. As discussed in an '
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NSAG report (Safety Analysis92-005), there were 97 open NSAG recommendations.
The report documented the backlog of open corrective action documents and ;
stated that the large number of documents remained unprioritized. A review of
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MW0s identified 100 to 130 components with multiple MW0s and identified that
CRs were not effectively used to identify and correct the underlying problems. ;
Based on a sample of 45 CRs, the report concluded that root cause
determinations and/or incomplete corrective action were responsible for t
multiple CRs written for the same problems. The inspectors considered this a ;
good analysis of the status of the corrective action program documents; >
however, no recommendations were provided to management on how to address the
excessive backlog of corrective action documents. Recommendations were !
directed toward the QA, Maintenance, Design Engineering, System Engineering, ;
Licensing, and Security organizations. The majority of the recommendations
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were to prioritize the backlog, reduce the backlog, and initiate timely
processing of documents.
During review of the implementation of the ISEG, the inspectors noted that
responses, from the responsible organizations, to the recommendations made by
the ISEG were not provided within the specified time frame. The licensee
identified in Audit 93-09-I-CANC, which was discussed above, that a written ,
response to 46 recommendations made by the ISEG was not received within 90 ,
days of calendar issuance. Based on this audit finding, the inspectors were
concerned that the ISEG was not performing its oversight function, as
described in the TS. This issue will be tracked as an inspection followup -
item pending an NRC review of the implementation of the ISEG function
(458/9325-15). .
5.4.2 Nuclear Review Board
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TS 6.5.3 defined the qualifications of the members and the review and audit
functions of the Nuclear Review Board (NRB). The members were identified in
the TS by plant position and the inspectors noted that there were several
members that were not fully qualified, as required by the applicable portions
of ANSI /ANS 3.1-1978. The licensee identified designated alternates to
fulfill NRB functions until all qualifications were completed by the
appropriate members.
Section 2.2.3 of the NRB Manual, Revision 7, stated that, in the absence of
the permanent member, the alternate member would assume all the duties and i
responsibilities of the replaced permanent member and the voting restrictions ,
of Section 2.2.5 would not apply. Section 2.2.5 defined a quorum as a
majority of the NRB members, including the Chairman or Vice Chairman, and no l
more than two alternate members.
The inspectors did not identify any instances of more than two alternates in a !
quorum; however, the inspectors noted that the manual, as written, was not
consistent with the requirements specified in TS 6.5.3. The manual allowed an
unlimited number of alternates to attend an NRB meeting as a voting member; ;
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whereas, the TS only allowed two alternate members in a fulfill the quorum
requirements. l
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The inspectors discussed the potential for violating the TS requirement with i
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licensee personnel. The licensee personnel disagreed with the interpretation l
made by the inspectors with respect to the use of alternates as voting
members. This issue will be tracked as an inspection followup item pending
review of the licensee's implementation of the TS requirements for the NRB
(458/9325-16).
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6 NEAR TERM PERFORMANCE IMPROVEMENT PLAN
The licensee issued the Near Term Performance Improvement Plan (NTPIP),
Revision 0, on November 1, 1993. The licensee initiated formulation of the 1
plan prior to the start of this inspection. The items contained in the plan
'
were identified as a result of an internal performance review that was
conducted by the licensee to identify the underlying causes of certain
significant performance issues. As a result of the review, issues were
identified that required management attention. These issues, and the
corresponding corrective actions, were issued as the NTPIP.
The NTPIP provided a plan, to be implemented over the next 6 months, to
implement actions to correct the identified weak areas. The plan discussed
actions that would be taken to address many, but not all, of the weaknesses
identified in this inspection report. The licensee stated that, upon receipt
of this inspection report, the plan would be revised to include the items that
were not in the plan.
The NTPIP was developed as an interim measure while the licensee compiled and
issued the business plan. The purpose of the business plan was to address a
broader range of issues over the long term, which would provide a mechanism
for ensuring the appropriate items were reviewed and effective corrective
actions implemented.
The NRC will review the NTPIP during future inspections to verify that the
plan contained the appropriate items and that the licensee was progressing
satisfactorily to address the completion of each item within the specified
date. In addition, public meetings will be held to brief NRC management on
the status of the completion of the plan.
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ATTACHMENT 1
i
LIST OF ACRONYMS
i
APP -
Apparent ,
CAR -
Corrective action report ;
CARB - Corrective Action Review Board t
CN -
Change notice !
CR -
Condition report l
t
DEV -
Deviation
DRP - Division of Reactor Projects
DRS -
Division of Reactor Safety
ECCS - Emergency core cooling system
EDG -
E0P -
Emergency operating procedure
FSAR - Final Safety Analysis Report ;
HCU -
Hydraulic control unit i
HPU -
Hydraulic power unit
IFI -
Inspection followup item
ISEG - Independent Safety Engineering Group
LC0 - Limiting condition for operation
LER -
Licensee event report
LPCI - Low pressure coolant injection
MOV -
Motor-operated valve
MR -
Modification request
MWO -
Maintenance work request
NSAG - Nuclear Safety Assessment Group
NTPIP - Near Term Performance Improvement Plan
P&ID - Piping and instrumentation diagram
PM -
Preventive maintenance
QA -
Quality assurance
QCR -
Quality condition report
RCIC - Reactor core isolation cooling
RHR -
R0 -- Reactor operator
RPS -
SR0 -
Senior reactor operator ,
TS -
Technical Specifications
URI -
Unresolved item
VIO -
Violation
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ATTACHMENT 2
EXIT MEETING
1 PERSONS CONTACTED
1.1 Licensee Personnel
J. Fisicaro, Mar.ager, Safety Assessment and Quality Verification
P. Freehill, Assistant Plant Manager, Outage Management
P. Graham, Vice President, Nuclear Integration
J. Hamilton, Manager, Engineering
H. Kaiser, Senior Vice President
J. McGaha, Vice President, RBNG
W. Odell, Director, Radiological Programs
J. Schippert, Assistant Plant Manager, System Engineering
M. Sellman, Plant Manager
F. Titus, Vice President, Engineering, Entergy
J. Venable, Operations Supervisor
1.2 NRC Personnel
J. Milhoan, Regional Administrator, Region IV
P. Gwynn, Deputy Director, DRP, Region IV
P. Harrell, Chief, Technical Support Staff, DRP, Region IV
P. Wagner, Team Leader, DRS, Region IV
J. Gagliardo, Chief, Project Section C, DRP, Region IV
W. Smith, Senior Resident Inspector, River Bend Station
C. Skinner, Resident Inspector, River Bend Station
S. Black, Project Director, Project Directorate IV-2, Office of Nuclear
Reactor Regulation (NRR)
E. Baker, Project Manager, River Bend Station, NRR
The personnel listed above attended the exit meeting. Additional personnel
from the licensee's staff and members of the media and the public also
attended the exit meeting. The inspectors contacted various licensee
personnel during the performance of this inspection.
2 EXIT MEETING
A public exit meeting was conducted on November 17, 1993. During this
meeting, the team leader reviewed the scope and findings of the inspection, as
discussed in this report. The licensee acknowledged the inspection findings
documented in this report. The licensee did not identify as proprietary any
information provided to, or reviewed by, the inspectors.
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ATTACHMENT 3
,
h
LIST OF INSPECTION FINDINGS-
.
Report
Number Type Section Topic
9325-01 IFI 2.1 NRC to review the licensee's determination ;
of appropriate levels of on-shift operator
staffing
9325-02 IFl 2.4 NRC to review the drawing change control I
4.2 process
9325-03 APP Examples of the failure to establish, ,
VIO implement, and maintain procedures, in
accordance with the requirements of .
Criterion V of Appendix B to 10 CFR ;
Part 50, are listed below:
2.4 Facility documentation not maintained to
accurately identify the valves required to !
be locked.
3.3.2 Surveillance procedure did not provide
instructions for properly venting a system ,
prior to initiating testing ;
3.3.4 Procedure did not provide instructions for
securing temporary testing equipment
r
3.3.5 Procedure for testing of a radiation
monitor could not be performed as written
3.5 A comment control form was used to change
a TS verification step
.
9325-04 APP Examples of the failure to identify and
VIO correct nonconforming and deficient
conditions, as required by Criterion XVI l
of Appendix B to 10 CFR Part 50, are >
listed below: ,
2.5.2.2 Timely actions were not taken to determine .
which spare breakers, if any, supplied
power to plant electrical loads
2.6 Timely actions were not taken to correct
the cause of the inadvertent tripping of *
an EDG due to depressing the emergency
stop button :
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2.7.2 Timely corrective actions were not taken
to provide access to an inaccessible ,
'
valve, which was required to be operated
by an E0P !
2.7.2 Failure to implement a commitment to
modify the suppression pool water level
indicator ,
,
2.7.3 Actions taken to prevent recurrence of a
nonconforming condition involving the use
of an incorrect revision of a procedure
were not effective ,
3.1.1 Actions were ineffective in correcting the
repetitive failure of the containment
airlock door seals
3.1.2 Actions were ineffective in correcting the
repetitive flow switch problems in
Radiation Monitors RMS*RE-11A.and -118 ,
t
4.1.2 Failure to implement timely actions to '
remove two unauthorized splices from a
control room cabinet
4.1.4 Failure to implement timely actions for !
evaluation of a potentially significant
EDG safety problem
5.3.1 Failure to implement timeiy actions to
address problems with the surveillance ,
testing program
Failure to implement timely actions to
5.3.2
address licensee identified concerns with i
'
repetitive personnel errors and repetitive
failure to follow procedures
,
9325-05 IFI 2.5.2.3 NRC to review general employee training
information to verify guidance for walking
on piping and structures had been included
9325-06 IFI 2.5.2.4 NRC review to verify that plant emergency *
lights have been properly adjusted
9325-07 URI 2.5.3 NRC to review the licensee's operability '
determination for the material found in
containment
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9':25-08 IFI 2.7.2 NRC to review the contents of the system l
enhancement file !
5
9325-09 IFI 3.1.4 NRC to review control of pastmaintenance
activities
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9325-10 IFI 3.2.1 NRC to review of PM records for ;
'
replacement of HCU filters
9325-11 IFI 3.2.1 NRC to review licensee's PM program with
respect to extension of PM frequencies ;
9325-12 URI 3.3.3 NRC to review of licensee's program for ;
controlling changes to the acceptance
criteria for the inservice testing program
and to verify that acceptance criteria
were appropriately specified in test
procedures
9325-13 URI 5.1.2. NRC to review the process used by the
licensee to close out a CR by generating
another document j
9325-14 URI 5.2.1 NRC to review the effectiveness of the
licensee's efforts to address the high
temperature condition in the drywell- !
9325-15 IFI 5.4.1 NRC to review the implementation of the
ISEG function .
9325-16 IFI 5.4.2 NRC to review the implementation of the f
!
NRB ,
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- APPENDIX B
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.30752 . Fedusel Ramster { Vol. 57. No.133 / Friday, inly 10.19B21:Noboes . ..
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amoneseus:Semb-====t= to:The i
Secretary of the c ======= U.S. l
Naciner Ragudatory em=====aa- l
Time-Veer Trtal Progress for
W= ' -DC2 555. ATIN:
Conesomas W N Docketmg sad SernoeSnach.
Comeneenese:Pomey Stasessent -
Hand dahver ccumnants to: One White i
amuscv: Nuclear Regulatory Fhat North.11555 Rocknile Pike,
c- Rockvdle.MD between R45 a.m. to 415
acnosc Pobey statement. p.m. Federes workdays. ,
i
Copies of n===mante may be erammad
sumament:The Nar4e=* Regtdatory at the NRC Pubbe Darnment Room.n20 l
ren===an (NRC)is issang tms pohey - L Street.NW. (lowerlevel). 1
Ftah'amant og gbg epiamentenart of a Wm.hmemn DC i
" d N 88"U'" sosi ruimese monumances costract I
m be opers to i
James Lieberman. Director.OfBcm of '
attend === by all maamers of the Nh Remilatmy
general public.This pohey statement facement. W --mn DC =c555
ri- the two. year mal program
and mforms the pubhc of how to get
gQyk
infonnanon on spenr-mg open surnasustrasrr seronssavsoec ;
'
enfot-mant conferences. R. . ~ . . .
.
J
Danne This tnal program is effect:ve on The NRC's curmaze pohey on
july 10.19EL srbile ennnnam, en the emorrsmmt conferen:ss as addrmed m ,
prognan are bang racerved.Sabrau '
Seenon V of thelatest arrision to the
en-= t= on or before the -- J== -GeneralStatement of Pohey and
of the tnal pregnun ar+=mdad for July
u.1SEL Commaants received after this
L=. for Enfarr=rnent A entm= "
date wdl be emesidered if it is pracucal IEnfM""'"=nt Policy) 10 CFR part 2.
to do so, but the Pa====a= s able to appenrtm C that was pnhh=had on
asenes consadoration andy for enmmenta
Feoruary18.1982(57FR 532).The
E=formaant Policy states that.
recurved on or before this data.
.
enferram== conferences wdl not
- normally be open to the public."
however,the r==nn==an has accaded
to rmpi=nant a tnal program to i
cetermme wnether to mamtam the l
current pohey with regard to !
emercemetrt confermnema or to adopt a j
-
- new coucy that wenid allow most ;
enforn man' wa6a to be open to f
attmnaem oy aH memoers of the pubhc. (
Policy Statament
Posnica
The NRC is impism,mme a two. year I
mal pronram to allow punhc j
ooserranon of selected emormt i
conferences.The NRC wdl momtor the ,
program and detenmns wnether to
estaolisa a permanent pohey for
concuenng open b- .- . .t l
conferenas cased on an assessment of
t::e followmg cntena: l
(1) Whetner the fact that the
conferena was open mmartad the
NRC's amh4 to enannet a mesmm:ml j
comerence and/or tmpimnent the NRC's j
emorremme program:
(2) Whetner the open conference
.
z=cactec the tiansee s paracrpanon m
tse comerence
(3) Whetner the NRC EMU a
.-ems-. , mmn =* of resources m
Tamrme the conterence puohC. and
(4)The errant of pubhcmterest m
opemen tne enforcement conference.
_ _ _ . _ . _ _ _ _ _ _ _ _ _ _ _ _ . _
_. . _ _ . - _ _ ._. _ __
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Fedent Regimese / Vol 57. No.133 / Friday, fair to,1sur. / Nectans arFR3 l
L Caltads Forad="h"T Oyami tisse smassonas of hommmess welbe webiesttopesammeteenemma that
sndassammescaminemma commmann spesamme sessaors. .
mens,benman,gemen. tans,e .
g,g,,,,,g g=='====
wdl act be l==y==la and other h isisch them W bepeNeRud.andhet l
innemmessa of thesumammag typen of diengitteeymmmmemaybesuussued.
~
'P"" he pubhe d he emissumanat
hemuse sash maisms6ammesmaammm m eto
Wenid he an R. f- Opus m.a- - , commatomimu mtamimma-
IndividmaLesaf theasman,thengaaat Camissammme - hamadenumbW !
- 8 *
,,_"_,",3 As anos asitis essersumed that an mesangbesmosa I
. --- ma %e m .sNRCa.d.e o.m
-
pubbs an=-venon,the NRC willarauy asimummmamassmanummeescopender =!
I' " " "1
fab whose has sagessend MY *op*',,** ,",idic Pubbe h Rissetope isr .
l
that the indlemineMs)tavolved be observenon as part of the agsscy's trial
puset at the ammmma Puemas namesmyopemandessment i
'
program and send the hemmees a copy of coudesumansesesummaded thatW the
(3)Is basedanes Andees amNRC gg, y,g,,g g ,,,,,,,,, gg ,g,,, , ,
"I
gg,,,","; " the programs f '- win be assad to es,,,,,meme e,mem,,,,,, ,,, ,,j,,,,g to )
======= me imme of perumpense it
WActh*==== m abw =====-a
m bras m ee amommit enamence
fwmarseemwoneammy beammiset to -
change pnertoanyseemimms
infanammon mesh could be so that the NRC can acasamle as
amissammmmmaseenand W te '
8PP"'8"* *IY 8" """8" staammesas of wisess or expuummmes of I
Esimen e s emmimumcas 4 h NRC wdl also maiy appugmas opmmon made by NRC empioyees at l
State haasan officers mat an op,, ,,ga,,,,,m e,,g,,,,,, ,, g, ,
g, % ensonema coerenes has he" lack thereof.meestmamaded to
~~~~" "A a d that it is open to punhc repruumm Anstdesmemanamn er beMais.
meosdisciamag es exposed m ;
indmdmal's amme.in asididost h NRClatands to annousce open
" """"""
enfesammentsammenene willnot be enfore- a==e commsemess ao skgwc * **"'I' '"' 8'8"* '"""8" '
oPen to thepublicif the comismuce wH nonnady at least 2C womesyn sa * " ""'"' '
be osmemused bytaisphone or the
advance of the ensoren. ant camenence '"""'8'I"*"""'""" """" ,
i
conferumme willbe naammaand at a throman the foHouans-
m bepamdedeappausyto 1
' reistivelysmoulemasse's incauty. (1) Namens pasase a es Pubhc ""
'""*the
m """ *"". Thus ========
mgmieBas !
Finally,umk esappmunieithe DoommentRam i
- Exacmave Diresser forOperanons. ~ (2)TolMnse tassommme ======== and
enfassammtcamimemons wdlnot be (3) Toll-free esecuame baumesnomse
- I"
opas as the peldic kt specialcases m======= mmw and haan 1
where good assesans meetshourn anar Penang estahh=h==at of the toH-fme Dated at sessums.&dD. this 7th slay el lely
halm the hemm6L of puhuc assumese evetems ame pundse aneycaH 188L
obserummes acumut the poemanalunpact (3D114es-4732 to esema a reemnang of For the Nasimar Augummanry e-
on the agencya =========' acnon m a up====g open emarcement Sammunil.Chilk.
p-. .- L. cess.
-
- -
cosnerences. The NRC will issue another sacreemryofshe cammmmmmes.
He NRC wdlsente to conduct open Feoeral Reesternonce sier tne tou free p Doc.g2. tazza ned 7-maM
enforemment comeurences enrms see m==se eyenems are eseem ,w,, ,,,, n,
L , c analpumqpent m aczoronnce To assist the NRCIn mesam;
with thsinuseums tierse gemas: appropnate arrennemanes to suuport
(1) .^ . r ' 725 pescentof all punhc observenen aiessorcommes
elisphie amorommuant contenecas comarma-= ananvasonas amusemesa m
rana ===== by the NRC wul be spes for sn=mne a parttemar enforcement
pubiacobaarvemen: comerence anomd nonfy thenoemdoal
(2) Atlenas one open amorcement idenafiedtn the meennt nonce
confersace wdl be ca=a=r*=d mseca of annormemg the open emorre==rit
the resonal o*=- and
-
-
causurumme no inner saan five ousmass
(3) Open -a- com='*ar*= days pnor to the emortamment
will be conoucted witti a vanety of the corrierence.
poemanal bias in the MOom Wmommma
a
seleenon process and to attemot to meet f
the three soais seated above.sverv In atzernears mth carent practree.
fouria ammhis emmuscammet causarence enforcement comerences md er=wnn=
invomag one of three categones of to nonnady be nasa as me NRCr=nn=I
ticensees wdl asumady be sous so tne ofnces.Memoers of the onblic wdlbe
poidseeunagthe eialpremram. allowse access to the NRCresonaa
However. m caans waere tnere is an offirms to aremme aman
l
ongesag " ' , procesamg wrth comerences in acaxensase wns one a
one or sense uservunnes, estrarcounsurt **Stanaani Openmas Preapouros For
comierenome invervuus ansees reisted to L ,SecurneSopportForNRC
the emmenstmasacef the angomag 14==rmar= Ana Masonas * puebabed
l
adrachema== may aise be openes.For Novancer1.1981ISSFR 56251LThase
the purposesas almaammipngpuu.the pran===res prtmde that visitors may be
,