ML20056D147
| ML20056D147 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 07/21/1993 |
| From: | Holland W, Kellogg P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20056D132 | List: |
| References | |
| 50-327-93-23, 50-328-93-23, NUDOCS 9308050034 | |
| Download: ML20056D147 (39) | |
See also: IR 05000327/1993023
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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REGION 11
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101 MARIETTA STREET. N.W., SUITE 2900
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ATLANTA, GEORGIA 30323-0199
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Report Nos.:
50-327/93-23 and 50-328/93-23
Licensee: Tennessee Valley Authority
6N 38A Lookout Place
1101 Market Street
Chattanooga, TN 37402-2801
Docket Nos.:
50-327 and 50-328
License Nos.: DPR-77 and DPR-79
Facility Name:
Sequoyah Units 1 and 2
Inspection Conducted: June 6 through July 10, 1993
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Lead Inspector:
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W. 17
hr" Sea 4ar Wsid I 1nspector
D&tre Signed
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Inspectors:
S. M. Shaeff r Resident Inspector
A. R. Long, Resident Inspector
S. E. Sparks, Project Engineer
P. A. Balmain, Resident Inspector, Vogtle
K. D. Ivey, Resident Inspector, Watts Bar
W. K. Poertner, Resident Inspector, Oconee
C. A. Hughey, Resident Inspector, Grand Gulf
R. C. Haag, Senior Resident Inspector, Summer
P. C. Hopkins, Resident Inspector, Catawba
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P. G. Humphrey, Resident Inspector, Watts Bar
J. F. Melfi, Resident Inspector, Trojan
L. Garner. Project Engineer
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Approved by:
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PauyJ. Kellogg
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Date SYgned
D m sion o
sf
ects
SUMMARY
Scope:
Routine resident inspection was conducted on site in the areas of plant
operations, plant maintenance, plant surveillance, evaluation of licensee
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self-assessment capability, licensee event report closecut, and followup on
previous inspection findings. During the performance of this inspection, the
resident inspectors conducted several reviews of the licensee's backshift or
weekend operations.
9308050034 930721
ADOCK 05000327
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This report also addresses special inspections conducted in the areas of
backlog and operations. These two areas were identified by the licensee as
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needing attention. in their submittal of the Sequoyah Restart Plan to the NRC.
Results:
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In the area of Operations, a weakness was identified regarding an assistant
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unit operator being inattentive while on duty (paragraph 3.a (1)).
In the area of Operations, a violation was identified for failure to ensure
that all fuel handling was performed in accordance with Site Standard Practice
-12.1 (paragraph 3.a (2)).
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In the area of Operations, a non-cited violation was identified for failure to
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notify the NRC as required by Technical Specification Limiting Condition for
Operation 3.7.11.1 ACTION b.2.a (paragraph 3.f (6)).
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In the area of Safety Assessment / Quality Verification, a violation was
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identified for frilure to adequately implement corrective action for
identification and removal of foreign material in the reactor vessel prior to
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the Unit 1 Cycle 6 core reload (paragraph 4.b).
Reviews of licensee assessments by a senior management oversight group,
Nuclear Assurance, and an operational restart readiness team resulted in a
conclusion that the licensee's ongoing self assessments are providing
meaningful input to site and corporate management regarding restart plan
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acceptability and implementation (paragraph 6).
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In the area of Safety Assessment / Quality Verification, a violation was
identified for failure to promptly identify the procedure problem associated
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with LER 327/92-21 during corrective action for LER 327/92-03 (paragraph 7.b).
Reviews of licensee outage performance were conducted in several functional
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areas during the period (paragraph 3.g).
The licensee's continuing excellent
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performance in maintaining outage person-rem dose expenditure and personnel
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contamination events well below projected goals was considered to be a
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strength in the radiological controls area. Also, system engineering
activities associated with backlog reviews was considered as good. However,
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reviews in the operations, maintenance, and safety assessment / quality
verification areas were mixed. These areas had regulatory issues which-
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resulted in identification of violations discussed in this report.
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Inspections, to date, indicate that the licensee is addressing backlog issues
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in the manner described in the Sequoyah Restart Plan. However, several
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restart plan inconsistencies were noted by the inspectors during this period.
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They were:
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Need for clarification on how emergent issues (issues after May 1, 1993)
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were being reviewed.
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Need for clarification of how post restart issues would be prioritized.
(The process for this item had not been presented to the inspectors when
the inspection period ended.)
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Need for senior plant management to better communicate expectations to
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BRC, lower levels of management, and system engineers regarding
execution of the restart plan (uniform clarification of restart criteria
to all).
This observation was considered to take on added importance
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later in the inspection period based on the inspectors comments during
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the last week of this period.
Several plan enhancements or corrections were accomplished during this
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inspection period. The inspectors consider that the licensee needs to
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formally incorporate these enhancements or corrections into the plan and
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formally communicate this information to the NRC (paragraph 9.a).
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The inspectors concluded, based on licensee assessments, review of operations
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standdown meetings, and general observations during the period that general
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operator performance regarding attention to detail and sensitivity to not
living with past problems is improving (paragraph 9.b).
A review of licensee previous commitments concluded that the licensee has
implemented a comprehensive and effective program to track and respond to
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commitments (paragraph 10).
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REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- R. Fenech, Site Vice President
- D. Keuter, Vice President, Nuclear Readiness
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- K. Powers, Plant Manager
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- J. Baumstark, Operations Manager
- L. Bryant, Maintenance Manager
- M. Burzynski, Nuclear Engineering Manager
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- M. Cooper, Restart Plan Coordinator
- D. Driscoll, Site Quality Assurance Manager
- T. Flippo, Acting Site Support Manager
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- J. Gates, Outage Manager
C. Kent, Chemistry and Radiological Control Manager
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- D. Lundy, Technical Support Manager
R. Rausch, Modifications Manager
- R. Shell, Site Licensing Manager
J. Smith, Regulatory Licensing Manager
- R. Thompson, Compliance Licensing Manager
- J. Ward, Engineering and Modifications Manager
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- N. Welch, Operations Superintendent
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- K. Whittenberg, Public Relations Manager
NRC Employees
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R. Crlenjak, Chief, DRP Branch 4
P. Kellogg, Chief, DRP Section 4A
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- Attended exit interview.
Other licensee employees contacted included control room operators,
shift technical advisors, shift supervisors and other plant personnel.
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Acronyms and initialisms used in this report are listed in the last
paragraph.
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During the month of June 1993, several management changes were announced
for Sequoyah.
These changes were:
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R. Shell replaced M. Cooper as the Site Licensing Manager
effective June 10, 1993.
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T. Flippo replaced P. Wallace as Acting Site Support Manager
effective July 1,1993.
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K. Powers replaced R. Beecken as the Sequoyah Plant Manager
effective July 5,1993.
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On June 22, 1993 the NRC Restart Panel was on site to discuss restart
activities with licensee management.
The licensee presented an update
on implementation of their restart action plan.
NRC management in
attendance included:
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S. Ebneter, Region II Administrator
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E. Merschoff, Director, DRP, Region II
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A. Gibson, Director, DRS, Region II (NRC Restart Panel Chairman)
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F. Hebdon, Project Director, NRR (NRC Restart Panel Member)
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R. Crlenjak, Chief, DRP Branch 4, RII (NRC Restart Panel Member)
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D. LaBarge, Senior Project Manager, NRR (NRC Restart Panel Member)
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P. Kellogg, Section Chief, DRP, Branch 4, RII
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2.
Plant Status
Unit 1 began the inspection period in day 60 of the Cycle 6 refueling
outage (vessel defueled). The licensee commenced refueling of the
reactor (MODE 6 entry) on June 18. On June 19, refueling operations
were suspended due to the toppling of a fuel assembly in the reactor
pressure vessel. This event and recovery of the assembly is further
discussed in paragraph 3.a (1). After recovery of the fuel assembly,
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the licensee completed inspections of the toppled assembly and lower
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core support areas and discovered that foreign material had caused the
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fuel assembly to fall.
On July 6, subsequent core inspections
identified two additional pieces of foreign material.
On July 7, the
licensee decided to unload the 37 assemblies in the core to facilitate
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further inspections for foreign materials. On July 8, the licensee
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recommenced refueling (MODE 6 entry). At the end of the inspection
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period the licensee was continuing with fuel onload (approximately 60%
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of the core had been reloaded).
Unit 2 began the inspection period in MODE 5 (Day 97 of a forced
outage).
During the period activities continued with regard to piping
replacement in the secondary plant due to erosion.
In addition, other
items identified as required for restart of the unit were also worked.
At the end of the period, Unit 2 remained in MODE 5 with work ongoing in
accordance with the licensee's forced outage schedule.
3.
Operational Safety Verification
(717'J7)
a.
Daily Inspections
The inspectors conducted daily inspections in the following areas:
control room staffing, access, and operator behavior; operator
adherence to approved procedures, TS, and LCOs; examination of
panels containing instrumentation and other reactor protection
system elements to determine that required channels are operable;
and review of control room operator logs, operating orders, plant
deviation reports, tagout logs, temporary modification logs, and
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tags on components to verify compliance with approved procedures.
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The inspectors also routinely accompanied plant management on
plant tours and observed the effectiveness of management's
influence on activities being performed by plant personrel.
(1)
During a routine tour of the Auxiliary Building on June 8,
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two NRC inspectors identified an AU0 that appeared to be
less than fully alert while on duty.
The individual was in
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the auxiliary building AVO station on elevation 669. After
observing the individual for several minutes, the inspectors
entered the station to ensure that the individual was not
physically ill.
The AUD became alert when the inspectors
approached.
The inspectors informed Operations Management of the
incident. After reviewing the problem, licensee management
informed the inspectors that the subject AU0 was not
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performing duties at the time of the observation, as he was
waiting to be called for portions of leak rate testing that
had not yet begun. The AVO was disciplined for being less
than attentive while on duty. The inspectors considered the
licensee's actions appropriate.
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After the event, the inspectors were informed that this
individual had been observed less than attentive by peers,
prior to the inspectors identification.
The inspectors
consider that operator peer identification of the problem,
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without taking action prior to the inspectors
identification, was a weakness in the way operators
performed their jobs (acceptance of peer inattentiveness as
acceptable performance). The fact that operators recognized
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their weakness after the problem, and were willing to share
the observations with management was an indicator to the
inspectors that they are recognizing that past performance
has been lacking, and that they are willing to improve in
the way they will perform their jobs in the future.
(2)
On June 19, 1993, the resident inspectors were notified by
the licensee that fuel movement on Unit I was halted due to
fuel assembly H64 (in core location G-7) tilting out of
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position during core reload evolutions. This event is
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discussed further in paragraph 3.f (4).
The fuel assembly which tilted had been used during one
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previous cycle.
It also was the 44th assembly being loaded.
The core holds 193 assemblies when fully loaded.
Operators had completed landing the assembly into position,
unlatched the assembly from the fuel handling manipulator
crane, and were raising the manipulator into the mast.
Operators looked into the vessel from the bridge and noticed
the assembly tilting over. The top of the assembly came to
rest on the core baffle plate approximately at location A7,
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with the assembly about 21 degrees from a vertical position.
Operators immediately stopped fuel handling evolutions.
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Operators also entered A0I-29, DROPPED OR DAMAGED FUEL
ASSEMBLY OR LOSS OF REACTOR CAVITY WATER LEVEL, and
performed applicable steps.
On June 21, 1993, the licensee commenced reco.ery operations
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in accordance with Fuel Handling Instruction FHI-3A,
RECOVERY OF LEANING FUEL ASSEMBLY H64. The NRC granted
discretionary enforcement of TS 3.9.6, which requires fuel
assemblies to be moved with the manipulator crane, to allow
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for recovery of the fuel assembly with the manipulator crane
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auxiliary hoist.
The auxiliary hoist was used to raise the
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assembly to a vertical position and secure it so that it
could be latched by the manipulator crane.
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C" ring the recovery operati:n. the maximum allowable weight
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of the recovery Ligging and assembly (1750 pounds) for the
auxiliary hoist wat exceeded.
The weight limit was
specified in the p.ocedure and had been briefed prior to
commencing recovery operations. Manaaement had to hhit the
evolution due to command and communication problems between
the control room and the containment.
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NRC personnel observed portions of the these initial
recovery efforts from several locations.
One inspector was
in the control room monitoring the licensee evolutions.
Another inspector was in the containment during portions of
the recovery.
Also, an NRC senior project manager was
observing recovery evolutions on a closed circuit tel
sion
in one of the licensee's conference rooms.
All of the NRC
personnel noted poor command and control during this part of
the recovery evolution, in that the refueling crew appeared
to be more concerned with getting the job done than focusing
on safety.
The inspectors reviewed Site standard practice SSP-12.1,
CONDUCT OF OPERATIONS, Revision 5. Paragraph 3.1.2 discusses
the responsibilities of the Operations department positions.
Step 3.1.2.M.8 of SSP-12.1 requires that the fuel handling
supervisor (a licensed SRO) ensure that all work is
performed in a safe manner by the appropriate procedure.
The inspectors concluded that the fuel handling supervisor
did not perform the evolutions of FHI-3A in accordance with
the requirements of SSP-12.1.
Failure to ensure that all
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fuel handling was performed in accordance with SSP-12.1 is
identified as a Violation (327/93-23-01).
The inspectors were also concerned that management in the
control room was having a difficult time communicating with
the refueling crew in containment.
The inspectors consider
that the command and control of the fuel recovery evolution
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could have been better managed and that senior plant
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management's decision to stop the fuel handling recovery
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effort was appropriate.
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To preclude further command and control problems, plant
management established a special recovery team in
containment to control the evolutions.
The team included a
test director (505/SR0) to direct all operations and
communicate with the CIPTE manager in the control room. The
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refueling SRO in containment took his orders directly from
the test director in containment, although he maintained his
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function as specified in TS.
The inspectors monitored licensee recovery operations during
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selected portions of the remainder of the recovery
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operation, and found the new recovery organization to be
more responsive to safe and controlled recovery of the fuel
assembly.
Pretest briefings stressed a conservative,
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cautious approach.
Requirements and expectations were
effectively conveyed regarding chain of command,
communications, procedural compliance, step by step
signoffs, and maintenance of chronological test logs. The
avoidance of becoming frustrated and impatient was strongly
stressed.
Personnel being briefed displayed a good
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questioning attitude, and there was good QA involvement
throughout the process.
Inspectors observed subsequent evolutions in progress from
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the control room, inside Unit I containment, and from other
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locations which had closed circuit TV monitoring of the
evolutions. The activities were professionally conducted,
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and demonstrated good command and control. Order was well
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maintained despite the presence of a large number of people
in the containment.
The test director was effective in
communicating information from the containment to the
control room clearly and completely.
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On June 25, 1993, the licensee recommenced recovery
operations for fuel assembly H64 in core location G-7. The
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fuel assembly was being held in place with J-hooks and
associated rigging attached to the auxiliary hoist, and
rested approximately three quarters of an inch above the
lower core plate. Revision 1 of FHI-3A included steps for
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transferring the assembly from the auxiliary hoist to the
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manipulator gripper so that the manipulator gripper could be
used to move the assembly to the upender.
To secure and
stabilize the assembly during and after disconnecting the J-
hooks in preparation for latching by the manipulator
gripper, a stainless steel wedge and/or hydraulic duckbill
jack would be installed under the FA bottom nozzle.
Further
stabilization would be provided by looping a wire rope under
the top nozzle of H64 in G-7, and by a wire rope hooked to
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the assembly in location J-7.
These wires were to be
secured to the cavity wall.
If necessary, the duckbill jack
could provide supplemental lifting force to free the
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assembly without exceeding TS limits on the hoist.
During performance of step 5.1B [1] of FHI-3A, the operators
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were unable to hook the cable on the upper nozzle plate for
the assembly in core location J-7.
The procedure was halted
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for equipment modification. Also during this evolution, QA
identified that the J-hooks used in the rigging were carbon
steel, rather than stainless steel as specified in the
safety evaluation.
A corrective action document was
initiated to address this discrepancy.
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On June 26, 1993, the licensee recommenced recovery
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operations of fuel assembly H64. Operators were able to
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connect the hook to the fuel assembly upper nozzle in core
location J-7 and secured the cable on the refueling cavity
wall.
However, during performance of step 5.lB [4] of FHI-
3A, the operators were unable to loop the wire rope under
the bottom of the top nozzle of assembly H64. The evolution
was again halted for equipment modification and procedure
revisions.
On June 27, 1993, the licensee recommenced recovery
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operations of fuel assembly H64.
Procedure FHI-3A had been
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revised to allow for positioning of a wedge and a jack under
assembly H64 ahead of looping the wire rope as described
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above.
Installation of the wedge was accomplished; however,
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the wedge did not contact the fuel assembly lower nozzle
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foot as required by step 5.1B [6] of the procedure. Also
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during placement of the duckbill jack in accordance with
step 5.1B [7], the jack would not stay in position. The
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procedure was again halted to address these additional
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problems.
A new bracket was designed, constructed, and tested to allow
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for accomplishment of step 5.1B [4] of the revised
procedure. The operators effectively positioned the bracket
with wire ropes attached on the top nozzle of assembly H64.
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The wire ropes were then tied off at appropriate locations
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on the North and East sides of the refuel floor. After
completion of this evolution, all recovery evolutions were
halted pending resolution of the wedge and jack problems.
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At this point, the licensee had Westinghouse engineer better
recovery equipment and demonstrate that the equipment was
effective at its Waltz Mill facility.
The licensee's
reactor engineering manager participated in the testing of
the redesigned jack, which utilized a parallel jaw lifting
mechanism to better fit the assembly foot. In addition, the
jack was designed to be secured in position through
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alignment on one of the flow holes. A training film was
provided by Westinghouse to aid in briefing the recovery
crew on use of the new equipment.
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On July 1,1993, the licensee recommenced recovery
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operations of fuel assembly H64. However, during attempts
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to install the new jack assembly, an interference was
encountered with an incore thimble guide nut located at an
adjacent location on the core basket. This guide nut had
not been considered in the equipment design and the mockup
testing at Waltz Mill. The evolution was again halted for
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equipment modifications and procedure revisions.
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On July 2,1993, the licensee recommenced recovery
operations of fuel assembly H64.
Video recordings from the
previous day had shown a dark line on the lower core plate
near location G-7 which might have represented a defect or
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foreign object. The licensee conducted further observations
of the core plate with the underwater camera and confirmed
that the dark line was a scratch rather than a crack or
foreign object.
The modified jack was installed and 200 pounds of pressure
was applied to assembly H64's lower nozzle plate foot, then
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the auxiliary hoist load was reduced to remove the J-hooks
that had been used to upright the assembly.
After the J-
hooks and auxiliary hoist rigging were moved out of the way,
the licensee latched assembly H64 with the manipulator
crane. The assembly was successfully pulled up by the
manipulator crane using a force less than limits prescribed
by procedure. The jack was not needed to further assist in
freeing the assembly.
The bracket and rigging on assembly H64 was removed and the
assembly was transported to the refueling transfer canal.
The assembly lower nozzle plate was inspected at this
location and no significant damage was observed.
The assembly was then lowered into the transfer cart
upender. However, the assembly would not fully insert into
the upender. Operators decided to remove the assembly from
the cart and transfer it back to the reactor vessel.
The
assembly was transferred back to location A-5 in the reactor
vessel. The assembly was left in this location, latched to
the manipulator crane, two inches off index in both
directions.
Recovery evolutions were secured for the day.
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Following removal of assembly H64 from location G-7, the
licensee noticed a foreign object located on the lower core
internals at location G-7 adjacent to assembly location H-7.
The licensee determined that the foreign object was
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approxim: tely 3/4 inch high and was cylindrical in
configuration.
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On July 3,1993 the licensee recommenced recovery operations
on fuel assembly H64. The assembly was returned to the
transfer cart upender; however, additional attempts to
insert the assembly into the upender were unsuccessful.
Operators then placed assembly H64 in the RCC change fixture
location in the transfer canal and _ inspected the upender
with the underwater camera.
No problems with the upender
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were identified.
Fuel assembly H64 was then transferred
from the RCC change fixture location back to location A-5 in
the reactor vessel. The assembly was left in this location,
latched to the manipulator crane, and recovery evolutions
were secured for the day.
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On July 4, 1993 the licensee recommenced recovery operations
of assembly H64. The licensee established two refueling
crews for recovery operations from this point forward and
continued with recovery evolutions on a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> basis. The
SOS /SR0 test director position was secured and normal
refueling staffing resumed.
The licensee moved assembly H64 back to the RCC change
fixture while a manipulator crane load functional test was
performed. The wedge and jack used for stabilizing H64 was
removed from the vessel, and the hook released from the
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assembly in core location J-7.
Blanking plates were
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installed in the flow holes in core locations G-7, G-8, and
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H-8 in the lower core internals of the reactor vessel.
Operators then removed the fuel assembly from location H-7
and returned the assembly to the spent fuel pool where it
would be inspected for damage.
Flow holes at location H-7
were then blanked and the foreign object was retrieved.
The
licensee determined that the foreign object had been in the
RCS for a reasonably long period of time based on radiation
levels of the object after retrieval. The flow nozzle
blanking plates were then removed, and a lower internals
video inspection performed.
The licensee then commenced removal of fuel assemblies at
locatio,s G-6 and H-6 to the spent fuel pit to be inspected
for possible damage.
The assemblies in locations J-7, J-9,
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and G-9, which are symmetric to location G-7, were removed
for replacement with new fuel assemblies. Calculations were
performed to support the core design change.
On July 5, 1993 the licensee had revised the procedure to
allow for loading of assembly H64 into the upender in a
manner that would accommodate additional bowing of the
assembly. The assembly was successfully loaded and
transferred to the spent fuel pool.
After assembly H64 had
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been transferred to the spent fuel pool, the licensee exited
the NOUE at 11:35 pm on July 5, 1993.
Overall, the inspectors consider that the licensee recovered
the tilted fuel assembly in a generally safe manner.
Although the recovery evolutions on June 21, 1993, were not
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accomplished in accordance with procedure and resulted in a
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violation described earlier in this paragraph, subsequent
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evolutions were well controlled.
However, greater
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thoroughness in the licensee's planning efforts for the
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recovery could have prevented delays for modification of
equipment and/or procedural changes.
The inspectors review of activities related to the removal
of the cylindrical object from the Unit 1 core which caused
the assembly to topple and other foreign objects found in
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the core is discussed in paragraph 4.b.
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b.
Weekly Inspections
The inspectors conducted weekly inspections in the following
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areas:
operability verification of selected ESF systems by valve
alignment, breaker positions, condition of equipment or component,
and operability of instrumentation and support items essential to
system actuation or performance.
Plant tours were conducted which
included observation of general plant / equipment conditions, fire
protection and preventative measures, control of activities in
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progress, radiation protection controls, missile hazards, and
plant housekeeping conditions / cleanliness.
(1)
The inspectors noted that on June 8, 1993 an unannounced
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fire drill was performed to satisfy the requirements of an
annual QA fire protection audit.
Neither of the two AU0s
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assigned to the fire brigade responded within the required
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time limit. One individual said he was delayed in exiting
the auxiliary building. The other said that he was unable
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to find gear in the equipment cage which fit him. This
second individual had notified his supervisor two weeks
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previously that he did not have proper gear, but did not
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mention the lack of equipment again when subsequently
assigned to the fire brigade.
The fire drill was successfully repeated the folicwing day.
This second drill was also unannounced. The first of the
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AU0s from the previous day's drill participated and reached
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the designated area in a timely manner.
The second AU0 from
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the previous day's drill was made ineligible for the fire
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brigade until he obtained proper gear.
Three additional
drills were subsequently conducted, and all were
successfully completed.
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Operations management issued Operations Policy statement 93-
037 to clarify AVO fire brigade responsibilities, pending
revision of the appropriate plant procedures. The AU0s
assigned to the fire brigade are responsible for physically
verifying that their gear is in the storage cage and in good
shape, and they are required to notify their supervision if
assigned to a c-zone or other duties which could interfere
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with their timely response to a fire.
Personnel have been
trained on these responsibilities.
(2)
On June 16, 1993, the inspector noted a half-filled bucket
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of waste oil next to control air system air compressor A.
A
Transient Fire Load
aching permit (#93-0119, dated March
24,1993) was hung tearby.
The inspector noted that this
breaching permit expired the previous day, June 15.
This
condition was identified to the licensee and the bucket of
oil and the permit were promptly removed.
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(3)
During tours of the turbine building, inspectors noted
improperly secured high pressure gas bottles.
The
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inspectors brought this issue to the attention of the
licensee. The licensee conducted a walkdown of the plant to
correct the deficiencies.
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The inspectors consider the above practices to be examples of poor
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attention to detail and a lack of sensitivity by operators in
assuring that issues are promptly identified and corrected,
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c.
Biweekly Inspections
The inspectors conducted biweekly inspections in the following
areas:
verification review and walkdown of safety-related tagouts
in effect; review of the sampling program (e.g., primary and
secondary coolant samples, boric acid tank samples, plant liquid
and gaseous samples); observation of control room shift turnover;
review of implementation and use of the plant corrective action
program; verification of selected portions of containment
isolation lineups; and verification that notices to workers are
posted as required by 10 CFR 19.
d.
Other Inspection Activities
Inspection areas included the turbine building, diesel generator
building, ERCW pumphouse, protected area yard, control room, Unit
I containment, vital 6.9 KV shutdown board rooms, 480 V breaker
and battery rooms, and auxiliary building areas including all
accessible safety-related pump and heat exchanger _ rooms.
RCS leak
rates were reviewed to ensure that detected or suspected leakage
from the system was recorded, investigated, and evaluated; and
that appropriate actions were taken, if required.
RWPs were
reviewed, and specific work activities were monitored to assure
they were being accomplished per the RWPs.
Selected radiation
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protection instruments were periodically checked, and equipment
operability and calibration frequencies were verified.
On July 1,1993, the inspector toured the lower compartment of
Unit 2 containmmt.
The inspector noted that containment was
generally clean, but did observe some items in containment (e.g.
gloves, a rag, a tape measure).
The inspector observed two items
that needed to be assessed or repaired. These were:
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Oil underneath the Number 1 RCP.
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A torn electrical conduit into the valve actuator for the
accumulator Number 1 outlet block valve.
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The licensee verified the inspector's observations and brought
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these concerns to outage management to resolve prior to restart.
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The licensee initiated WR C173654 to fix the accumulator block
valve.
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e.
Physical Security Program Inspections
In the course of the monthly activities, the inspectors included a
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review of the licensee's physical security program. The licensee
performance of various shifts of the security force was observed
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in the conduct of daily activities to include: protected and vital
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area access controls; searching of personnel and packages;
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escorting of visitors; badge issuance and retrieval; and patrols
and compensatory posts.
In addition, the inspectors observed
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protected area lighting, and protected and vital areas *.,arrier
integrity.
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f.
Licensee NRC Notifications
(1)
On June 11, 1993 the licensee made a four hour notification
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to the NRC as required by 10 CFR 50.72. They reported
discovery of inadequate ventilation design which may have
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resulted in both trains of both units' vital power supplies
being inoperable. The licensee determined that the design
was inadequate in the area of ventilation cooling for the
480 volt board room power supplies. The licensee identified
that one train of ventilation supplied redundant trains of
safety-related components.
A failure of this train could
have led to exceeding temperature limitations for the vital
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power supply areas.
The licensee will implement corrective
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actions to provide appropriate train cooling for vital power
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supplies prior to either unit entering MODE 4.
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(2)
On June 14, 1993 the licensee made a four hour notification
to the NRC as required by 10 CFR 50.72 due to an ESF
actuation.
Unit 1 MCR operators were attempting to start
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the #1 RCP motor, which was uncoupled to the pump. The
uncoupled run was requested due to a motor change out during
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the refueling outage. The motor was started and the 1A
start bus tripped on overcurrent, which deenergized the 1A
and 1C 6.9 KV Unit boards. The 1C Unit board was supplying
the IB shutdown board (SDB), and thus caused an undervoltage
condition on the IB SDB. Undervoltage on the IB SDB
completed the logic to start all four EDGs.
All four EDGs
started as designed, and the IB SDB completed its load shed
and subsequently was carried by the IB EDG.
The load shed
and load sequencing of the IB SDB occurred as designed with
no problems. At the time of the event, Unit I was defueled.
One of the two spent fuel pool cooling pumps tripped off
during this event, and thus no spent fuel pool cooling was
lost.
The MCR appropriately implemented AOI 35 for blachut
operation, and all systems responded normally.
(3)
On June 15, 1993 the licensee made a four hour notification
to the NRC as requirea by 10 CFR 50.72 regarding a degraded
conditior, while shut hwn. As discussed above, on June 14,
1993, the licensee made a four hour notification as a result
of an ESF actuation (EDG start) due to loss of an offsite
start bus breaker. The licensee's investigation determined
the root cause to be an overcurrent current transformer that
was installed out of phase since November 1991. This
condition would allow the breaker to trip under nominal load
which is outside design basis.
(4)
On June 19, 1993 the licensee made a call to the NRC as
required by 10 CFR 50.72 due to a Notification of Unusual
Event. On June 19, 1993, at approximately 10:55 A.M., fuel
movement on Unit I was halted due to a fuel assembly (H64)
tilting out of position during core reloading evolutions.
The assembly had been used during one previous cycle.
It
also was the 44th assembly being reloaded. The core holds
193 assemblies when fully loaded.
Operators had completed landing the assembly in position,
unlatched the assembly from the fuel handling manipulator
crane, and were raising the manipulator into the mast.
Operators looked into the vessel from the bridge and noticed
the assembly tilting over. The top of the assembly came to
rest on the core baffle plate approximately 1ocation A7.
After movement stopped, the assembly appeared to be
approximately 21 degrees from a vertical position.
Operators immediately stopped fuel handling evolutions.
Operators also entered A01-29, DR0pPED OR DAMAGED FUEL
ASSEMBLY OR LOSS OF REACTOR CAVITY WATER LEVEL and performed
applicable steps.
After discussions between operations and management, a
decision was made to enter the site emergency plan.
At 1149
A.M., The licensee declared a notification of unusual event
based on conditions that warrant increased awareness.
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Initial assessments indicated that radiation levels had not
changed and that the assembly was not damaged (no indication
of increased activity due to possible fuel pin failure).
The licensee immediately convened an incident investigation
team to review the event. Plans were formulated to recover
the fuel assembly. This effort is further discussed in
paragraph 3.a (2) of this report.
?
The NRC senior resident inspector responded to the site to
review the event and evaluate licensee actions.
The
inspectors monitored licensee recovery actions until the
assembly was recovered and returned to the spent fuel pit.
The licensee exited the notification of unusual event at
11:35 pm on July 5, 1993.
(5)
On June 25, 1993 the licensee made a notification to the NRC
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as required by TS 3.7.11.1 due to inoperability of the plant
fire suppression system.
Portions of the system became
inoperable when the licensee closed valve 0-26-696 to
isolate a leak in one suppression header which was being
aligned for maintenance. The licensee complied with all
,
required ACTION statements of TS 3.7.11.1.
(6)
On July 2,1993 the licensee made a notification to the NRC
as required by TS LC0 3.7.11.1 ACTION b.2.a which requires
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> notification. However, the entry was accomplished
on June 21, 1993 in accordance with approved procedure. The
licensee failed to notify the NRC within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> as
required by TS LC0 3.7.11.1 ACTION b.2.a.
All other LC0
ACTION requirements were accomplished with the exception of
the notification. The licensee instituted an incident
investigation to determine why proper notifications were not
made.
Failure to notify the NRC as required by TS LC0
3.7.11.1 ACTION b.2.a is identified as a non-cited violation
(327,328/93-23-02). This violation will not be subject to
enforcement action because the licensee's efforts in
identifying and correcting the violation meet the criteria
specified in Section VII.B of the Enforcement Policy.
(7)
On July 4,1993 the licensee made a four hour notification
to the NRC as required by 10 CFR 50.72 concerning an
inadvertent ESF actuation.
At approximately 2:55 pm, three
of the four emergency diesel generators received an
automatic start signal due to the IB-B, 6.9 KV shutdown
board isolating from its normal power supply.
The IB-B
emergency diesel did not start due to it being out of
service in accordance with approved maintenance procedures.
Some minor loads powered from the IB-B, 6.9 KV shutdown
board were deenergized until the board was restored with
normal power.
The other three diesels did not connect to
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their respective shutdown boards due to normal power being
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available. All safety systems performed as designed.
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The initial evaluation of the cause of the ESF signal was
determined to be an inadequate procedure. . The licensee
commenced an incident investigation to evaluate the cause of
the ESF actuation and propose corrective actions. An LER
will be written for this event.
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g.
Outage Functional Area Reviews
During this period, the inspectors focused on review of licensee
performance at the end of the Unit 1 Cycle 6 refueling outage, as
well as the Unit 2 forced outage in several functional areas.
The
following conclusions were reached during this period:
Operations - Operator performance during this period was
considered to be mixed. Most evolutions, including system
restorations, processing of clearances, and monitoring of plant
status were accomplished in accordance with requirements.
However, initial recovery evolutions of the tilted fuel assembly
H64 were not accomplished as required by procedures.
In addition,
the inattentive AUD issue was considered to be an operational
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weakness. These conduct of operations issues resulted in
identification of a violation of regulatory requirements and an
operational weakness (see paragraph 3.a).
Radiological Controls - Performance in this area was considered to
be very good.
Person-rem expenditure and personnel contaminations
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continued to be well below projected levels even though RWP work
growth continued. The inspectors consider that the sustained good
performance in this area is a strength.
Maintenance - Performance in this area for the inspection period
was considered mixed. Most maintenance activities reviewed were
accomplished in accordance with requirements. However, activities
associated with foreign material exclusion, indicate that
additional management attention is needed in this area.
Engineering / Technical Support - Performance in this area was
considered to be generally good.
Reviews of system backlogs
determined that system engineers were knowledgeable on their
systems and the status of backlogs.
However, some system
engineers were not aware of current status of system corrective
action implementation.
Safety Assessment / Quality Verification - Performance in this area
was considered to be mixed. The licensee had conducted good
assessments of several areas and were benefiting from results of
the assessments in continuing with corrective actions for problem
areas identified at the plant. However, regulatory issues
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identified in paragraphs 4.b and 7.b of this report indicated that
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corrective actions for past problems had not always been
effective.
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Within the areas inspected, one violation and one non-cited violation
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were identified.
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4.
Maintenance Inspections
(62703 & 42700)
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During the reporting period, the inspectors reviewed maintenance
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activities to assure compliance with the appropriate procedures and
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requirements.
Inspection areas included the following:
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a.
ARROWHART CONTRACTOR INSPECTIONS
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On June 7, 1993, PER 930208 was written identifying a problem with
the subject contractors. The PER described a condition where
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interlock contacts on the Arrowhart contractor for 1-FCV-67-124
were found gummed up to the point it caused the valve to
malfunction. The PER also determined that the problem could
potentially affect operability on both units. At the time of
identification of the problem, Unit I was defueled and Unit 2 was
in MODE 5.
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The licensee evaluated the PER and commenced an inspection effort
4
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of breakers with Arrowhart contractors on June 9, 1993. The
licensee initially believed that the problem was limited to the
Unit I contractors due to recent PMs being performed on Unit 1.
During the rest of the inspection period, the inspectors monitored
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licensee activities associated with the Arrowhart contractor
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issue.
The inspectors met with system engineers on several
occasions to obtain an update on the findings. When the
inspection period ended, the licensee had identified a total of 58
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failures (17 safety-related/41 non safety related) on motor
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starters with Arrowhart contractors. The procedural criterion for
identification of failure was auxiliary contacts sticking or
sluggish when tested.
In addition, another 139 contractors were
cleaned during the inspections. The total number of motor
starters inspected was approximately 609.
The inspectors reviewed work order 93-03411-00 associated with
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operational checks of identified contacts associated with 18
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starters for A and B train components, work order 93-03350-00
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associated with inspections of starter contractors located on
Reactor MOV boards IB1-B and 282-B in the auxiliary building, and
work order 93-03351-00 associated with inspections of starter-
contractors for 21 components on Unit 1 Reactor and MOV boards.
The inspectors concluded that the inspections were conducted in
accordance with procedural requirements.
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The inspectors concluded that the licensee had identified a
significant problem associated with Arrowhart contractors on motor
starters located throughout the plant.
However, no failures
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occurred on the units during this period which caused safety-
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related components required for MODE 5 or MODE 6 operation to
become inoperable. The inspectors also considered the actions
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taken by the licensee to be necessary in order to assure
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reliability of the starters. This issue was further reviewed by a
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region based inspector and discussed in inspection report 327,
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328/93-31.
b.
FOREIGN MATERIAL INSPECTIONS
During the inspection period the inspectors reviewed licensee
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activities associated with the recovery of the foreign objects
from the Unit I reactor core.
An event occurred on June 19, as
described in paragraph 3.a.2, which involved the tipping of a fuel
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assembly due to a foreign object on the lower core support plate
!
when the assembly was being placed in the core.
Two additional
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small foreign objects were also discovered in similar locations in
the Unit I reactor core.
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The inspectors monitored the foreign object removal process at
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numerous instances and verified the activities were in accordance
with WR C128210 and MI-1.1.5, GENERAL FOREIGN OBJECTS RETRIEVAL
PROCEDURE - UNITS 1 AND 2, Revision 1.
Observations of activities
'
in-process concluded that the individuals involved in the
activities performed the recovery evolutions in a safe manner.
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All of the objects identified were recovered.
Blanking plates
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were properly installed in the flow holes at appropriate locations
,
to prevent movement of the object further into the core. The
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inspectors concluded that the retrieval activities were performed
<
in accordance with requirements.
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The inspectors reviewed the objects recovered from the Unit 1
)
reactor core. The object related to the fuel assembly tipping
event was identified as an expander device for a Westinghouse
,
steam generator tube plug approximately 0.75 inch in height and
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0.5 inch in diameter. The additional two objects consisted of a
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paint chip approximately 1.0 inch square and a metallic item
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approximately 1 x 0.25 x 0.0625 inches (possibly a section of
gasket material). At the end of the inspection period, the
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licensee had not completed the root cause investigation for entry
of the foreign material into the Unit I vessel.
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In addition to the above, the inspectors specifically reviewed the
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opportunities that the licensee had to identify the expander plug
which caused the fuel assembly to tilt.
Discussions with reactor
engineering personnel indicated that two inspections of the lower
support plate were performed to identify foreign material.
The
first was performed on June 12 by TVA personnel and the second by
Westinghouse personnel on June 17.
Both inspections were
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performed utilizing a camera attached to a pole and lowered into
the reactor core.
The Unit I core onload was begun on June 18.
The inspectors noted that water clarity and lighting appeared
[
adequate for performing the lower core inspections.
On July 8, 1993 the inspectors attended a PORC meeting, which
presented Incident Investigation II-S-93041, Tilted Fuel Assembly
1
During Unit 1 Core load. At this meeting, the inspectors learned
that a video recording and additional verification of the lower
core inspection was not performed for the current UIC6 reload.
The inspectors recalled that during independent review of a video
,
recording made during the VICS outage, the licensee identified
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foreign material on the lower support plate. The identification
of the foreign material was made after the commencement of core
reload activities; however, was in time to allow the licensee to
+
remove the foreign material (part of an upper grid assembly) prior-
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to placing an assembly in the subject area.
This possibly
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prevented a previous tilted fuel assembly problem.
The inspectors discussed with the licensee why a video review,
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which had appeared to have been proved prudent in previous core
reloads, was not performed for the UIC6 core load. The licensee
indicated that they did not feel that the video taping and
additional review was necessary. The licensee stated that they
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primarily relied the personnel performing the inspections "on
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line" to properly identify any foreign objects. Additionally, the
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video was previously performed because it was convenient to
complete coincident with other required inservice inspection
procedures.
Corrective actions for 11-S-91-118, which were
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initiated as a result of the foreign material found during the
UICS outage, included procedure revisions to N-VT-8, VISUAL
EXAMINATION OF PWR REACTOR VESSEL INTERIORS AND INTERNALS. The
revisions were made to ensure that timely review of the video was
performed prior to fuel reload. However, prior to the VIC6
4
reload, responsibility for foreign material inspections was
transferred to the reactor engineering group.
Video taping and
additional reviews were not included in the reactor engineering
procedural requirements.
Based on the above information and discus.; ions with the licensee,
the inspectors concluded that, review of a video inspection of the
core support would not have ensured the identification of the
foreign object.
However, the video review would have provided an
additional opportunity for identification, as was established
during the Unit 1 Cycle 5 outage.
The inspectors reviewed the licensee's performance regarding
foreign material exclusion / detection during the Unit 1 Cycle 6
refueling outage from a regulatory point of view. During the Unit
1 Cycle 5 refueling outage, the licensee discovered a foreign
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object in the reactor vessel during fuel reload.
The licensee was
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able to recover the object prior to placing any fuel assembly in
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the location of the foreign object. An incident investigation of
that event was conducted and the licensee implemented corrective
actions to prevent recurrence. However, those corrective actions
were not effective in preventing a foreign object from causing a
fuel assembly to tilt out of position during the Unit 1 Cycle 6
refueling outage.
10 CFR 50, Appendix B, Criterion XVI requires, in part, that
measures shall be established to assure that conditions adverse to
quality such as.nonconformances are promptly identified and
corrected.
In the case of significant conditions adverse to
quality, the measures shall assure that the cause of the condition
is determined and corrective action taken to preclude repetition.
Failure to adequately implement corrective action for
identification and removal of foreign material in the reactor
vessel prior to the Unit 1 Cycle 6 core reload is identified as a
violation of 10 CFR 50, Appendix B, Criterion XVI (327, 93-23-04).
Within the areas inspected, one violation was identified.
5.
Surveillance Inspections
(61726 & 42700)
During the reporting period, the inspectors reviewed various
surveillance activities to assure compliance with the appropriate
procedures and requirements. The inspection included a review of the
following procedures and observation of surveillances:
H
a.
On July 10, 1993, the inspectors reviewed activities associated
with 2-SI-0PS-026-180.A, FIRE PUMP 2A-A START TEST, Revision 2.
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The SI partially fulfills Surveillance Requirement 4.7.ll.1.a by
providing steps to verify the operability of- the 2A-A fire pump
via a start and 15 minute run. The inspectors reviewed the-
documentation in the SI package and verified the as-left condition
!
of components utilized during the testing activities.
No
discrepancies were noted.
b.
Late in the inspection period, the inspectors reviewed
approximately 35 records contained in 0-SI-0SL-000-011.0,
CONTAINMENT ACCESS, Revision 3.
The records reviewed were for
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Unit 2 containment access authorizations for July 9,1993. The-
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inspectors noted that all records appeared to be accurate,
detailed, and complete.
Sign-off's for end of work cleanliness
and foreign material accountability were completed as required.
These reviews were accomplished, in part, due to recent licensee
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identified problems associated with foreign material exclusion
issues.
The inspectors will continue to closely monitor this
area.
Within the areas inspected, no violations were identified,
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6.
Evaluation of Licensee Self-Assessment Capability (40500)
During this inspection period, selected reviews were conducted of the
licensee's ongoing self-assessment programs in order to evaluate the
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effectiveness of these programs.
,
a.
On June 11, 1993 the inspectors attended the exit meeting for a
Senior Management Oversight Group (SM0G) which had been
established for the purpose of providing senior TVA nuclear
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management with independent assessments of the Sequoyah Restart
Program, its implementation, and an operational readiness review
prior to restart. The principal function of the group was to
provide advice and assistance to TVA management on the
programmatic issues related to the restart of Sequoyah Nuclear
Pl ant.
The SM0G had concluded at this point in their review that the
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current Sequoyah Restart Plan is adequate, and if executed as
planned would provide for return of Sequoyah to safe operation.
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The SM0G considered that the restart schedule was aggressive and
that a continuation of observed performance errors raised a
concern of the effectiveness of ongoing corrective actions.
The inspectors consider that the SMOG exit provided licensee
,
senior management with a frank and honest perception of where
Sequoyah was regarding restart readiness.
The inspectors will
continue to monitor the results of the licensee's independent
assessments.
,
b.
During this inspection period, the inspectors have been provided
with weekly updates on the licensee's Nuclear Assurance Restart
Readiness Reviews.
The Nuclear Assurance department has been
conducting reviews in several areas in order to evaluate Sequoyah
readiness for restart. These areas include (1) Balance of Plant,
,
(2) Operations department, (3) Programs, (4) Backlogs / Work
"
Prioritization, (5) Personnel, Organization, and Culture, and
Corporate / Site Interface.
Reviews through July 1, 1993 indicate that improvement is needed
in all areas reviewed except for Corporate / Site Interface. The
inspectors will continue to monitor the licensee's effort in this
area. However, the inspectors are also continuing with
independent assessments of the licensee's restart plan.
The inspectors consider that the Nuclear Assurance effort is
providing positive feedback to plant management.
The effort is
identifying several areas which need continuing management
attention.
c.
On July 2, 1993 the inspectors attended the exit meeting for the
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Sequoyah Nuclear Plant Restart Readiness Team (RRT) review of
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Operations. The RRT was a team lead by a TVA senior manager and
staffed by experienced contractors. The RRT conducted reviews of
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the Operations Department in the middle of May 1993, and returned
on June 21, 1993 for an additional 2 weeks of assessment.
The team noted several positive observations during the exit
meeting on July 2.
They were: (1) Communications between the
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Operations department management and the Operations staff
continued to improve; (2) 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shift rotation implementation
with five discrete groups was considered a significant
accomplishment which would strongly support a team approach to
plant operation; (3) General operator attitudes continued to
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improve; (4) Some progress had been made in upgrading procedures;
and (5) Operations ownership of plant conditions was improving.
Several other observations were made concerning site management
following through with what they started, other departments
support of the Operations initiatives, and Operations management
,
emphasis of SOS /ASOS tours of the plant / procedural compliance
across the board / consistent self checking practices.
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The RRT concluded that the Operations department would be ready
I
for the planned restart of Unit 2 provided that consistent
application of standards by management continues, and provided
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more proactive, effective support is undertaken by other
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organizations.
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The inspectors consider that the RRT provided a reasonable
assessment of their observations of the Operations department.
!
The inspectors will continue with their independent assessment of
the performance of the Operations department.
Inspector
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observations for this period are discussed in paragraphs 3 and 9
of this report.
The inspectors considered that the licensee's ongoing self assessments
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are providing meaningful input to site and corporate management
,
regarding restart plan acceptability and implementation.
.
Within the areas inspected, no violations were identified.
7.
Licensee Event Report Review (92700)
The inspectors reviewed the LERs listed below to ascertain whether NRC
reporting requirements were being met and to evaluate initial adequacy
of the corrective actions.
The inspector's review also included
followup on implementation of corrective action and/or review of
licensee documentation that all required corrective action (s) were
either complete or identified in the licensee's program for tracking of
outstanding actions.
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a.
(Closed) LER 327/92-19, Technical Specification Radiation Monitor
Setpoints Nanconservative. The licensee issued this LER when
certain TS radiation monitors setpoints were found calculated
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nonconservatively. The subject monitor setpoints.did not account
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for the system design, which has the gas sample chamber upstream
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of the sample pump. This arrangement creates a partial vacuum
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near the detector when sampling, which reduces the air (and
potential radionuclide) density. To account for actual
radionuclide concentration, a correction factor is made to the
radiation monitor setpoint. The licensee had revised affected
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procedures by December 31, 1992 to account for their design.
To verify that they did not exceed an actuation setpoint on this
monitor during previous operations, the licensee reviewed previous
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plant data sheets. The licensee's review showed that they did not
exceed an actual actuation setpoint during previous plant
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operations.
The licensee attributed the root cause for this event as a
miscommunication within TVA. The radiation monitor vendor
informed the licensee about the basis for the detector
t
calibration, but the plant did not receive this information.
The
licensee noted that their current controls of vendor information
l
'
should prevent a similar problem.
i
b.
(Closed) LER 327/92-21, Failure to Verify Valve Positions for
Verification of Containment Integrity.
The issue involved failure
i
to perform verification of containment integrity for ten manual
drain and test connection valves in each unit. The su. 1illance
instruction steps were waived by the performers when the units
'
were at power because of potential industrial safety concerns.
_
The inspectors reviewed the licensee's corrective actions and
i
verified that SSP-2.51, RULES FOR PROCEDURE USE, Revision 0 was
!
issued to clarify requirements for procedure step waiver.
!
)
However, the licensee also stated in their LER response that 7.n
earlier LER 327/92-03 identified an event where fire protection
i
valves inside containment were waived for inspection. The
'
inspectors concluded that the corrective actions for LER 327/92-03
should have identified the problem discussed in this LER.
10 CFR Appendix B, Criterion 16 requires, in part, that conditions
adverse to quality are promptly identified and corrected.
Failure
j
to promptly identify the procedure problem associated with this
,
LER during corrective action for LER 327/92-03 is identified as a
]
,
violation (327, 328/93-23-03).
,
c.
(Closed) LER 327/92-22, Control Room Emergency Ventilation System
Inoperable Because of Closure of Tornado Dampers.
The issue
involved entry into LCOs 3.0.3 and 3.7.7 when both trains of the
control room emergency ventilation system (CREVS) were declared
..
.
,
I
j
22
inoperable following clesure of the tornado dampers that isolate
the fresh air intake to the CREVS. Operations personnel closed
the tornado dampers in accordance with abnormal operating
instruction (A01). After the downgrading of the torndo warning
i
to a tornado watch, the CREVS was returned to operable status, and
the LCOs were exited.
The inspector reviewed A01-8, Tornado
Watch / Warning, and concluded that the correct actions,
i.e.,
'
closing the tornado dampers, were implemented in response to the
tornado warning.
d.
(Closed) LER 327/93-01, Ice Bed Monitoring Surveillance
i
Requirement Time Interval Exceeded Because of Poor Communications.
l
The issue involved inadequate communication between operators and
i
others regarding conditional surveillance requirements when the
equipment normally used to monitor a TS required parameter becomes
i
Licensee corrective actions included additional
!
training and review of this event with operations crews.
In
'
addition, a more formal method of initiating conditional sis was
developed and implemented.
e.
(Closed) LER 327/93-02, Manual Reactor Trip as a Result of a Lock-
!
up of the Rod Control System. The issue involved operator
initiation of a manual trip due to experiencing an urgent failure
'
condition in the rod control system during a controlled shutdown.
i
The operators manually tripped the reactor from low power due to
'l
Xenon increasing and possibly shutting down the reactor while
troubleshooting was being planned for the rod control system. The
!
cause of the rod control problem was subsequently determined to be
i
a problem in the timing circuitry of the rod control system. The
inspectors reviewed the licensee actions at the time of the
'
problem and the LER. All actions were considered to be correct
2
based on conditions.
t
f.
(Closed) LER 327/93-03, Reactor Trip as a Result of an Inadvertent
,
Trip of the Exciter Field Breaker. The issue involved an
automatic reactor trip of Unit I from approximately 100 percent
power due to personnel error. The event was discussed in
inspection report 327, 328/93-05.
Licensee corrective actions
included appropriate action against the person making the mistake.
'
In addition, a plant policy on activities associated with
sensitive equipment was established. This policy was established
.
'
with a new procedure (SSP-12.63, SENSITIVE EQUIPMENT CONTROL,
Revision 0). The inspectors reviewed the LER and the licensee's
corrective action.
g.
(Closed) LER 327/93-04, Containment Personnel Airlock Blind Flange
Leakage Causes Airlock Inoperability. The issue involved licensee
identification of a potential containment leakage path which was
i
greater than TS bypass leakage limits. This issue was discussed
!
in inspection report 327, 328/93-05. A violation of regulatory
requirements was issued for this event.
The inspectors reviewed
___
_
,
.
.
,
.
23
the LER and will review other licensee corrective actions during
closecut of the violation.
,
h.
(Closed) LER 327/93-05, Inadvertent Actuation of a Containment
Isolation Valve During Response-Time Testing Performance as a
Result of Personnel Error. The issue involved instrument
'
maintenance personnel shorting a circuit during performance of a
,
maintenance activity. The shorted circuit resulted in a blown
fuse and a containment isolation valve closing. After the event,
1
the fuse was replaced and the valve reopened. Part of the event
was attributed to limited access for installation of test
l
equipment.
Corrective actions included instructing maintenance
personnel to be more careful when working in limited access areas.
The inspectors reviewed the LER and licensee actions.
,
i
i.
(Closed) LER 327/93-07, Inadvertent Actuation of a Containment
!
^
Isolation Valve as a result of Removal of Fuses from the Wrong
Circuit. This issue involved the actuation of a containment
isolation valve when its control power fuses were mistakenly
removed. The subject valve is a containment radiation monitor
isolation valve. The mistake was immediately identified by the
AU0 performing the fuse removal. The licensee attributed the
event to personnel error as a result of inadequate self-checking
'
and a failure to follow applicable procedures during the
installation of clearance tags.
In addition, equipment label
l
deficiencies were considered contributing factors.
The inspectors reviewed the specific errors made during the fuse
3
pulling process. According to the licensee's report, two
personnel were performing the evolution utilizing independent
,
verification techniques, rather than second-party verification
,
techniques. The individual incorrectly assumed that the
'
independent verification was of a higher quality than the second
party process. However, in the situation of pulling fuses, this
assumption allowed an error to occur, which resulted in the
inadvertent actuation.
'
The licensee has had previous problems with regard to independent
and second party verifications.
Like this event, the majority of
them issues were the result of the wrong type of verification
beix .ssigned to the activity. However, the inspectors
,
'
considered that the previous activities resulted in the wrong type
of verification being assigned due to the existence of an
i
inadequate PMT with the activity.
Regardless, the inspectors were
'
concerned that corrective actions taken for the previous events,
,
which included increased verification training, did not preclude
this event.
The inspectors reviewed the corrective actions for this event.
,
Immediate actions included the restoration of the affected
i
equipment to service. Other actions included the installation of
fuse column identification nameplates for the identified areas,
j
.
".
,
.
.
l
24
'
In addititn, retraining was provided to personnel that perform
clearance process tagouts with regard to the proper verification
methods.
The licensee is also continuing to emphasize
expectatiors relative to personnel errors, failure to follow
procedures, and work verification requirements via long term
corrective attions for these type of events.
Based on the
inspectors re/iew, corrective actions for this event are
)
considered adequate.
,
!
j.
(Closed) LER 328/92-14, Limiting Condition for Operation Entered
i
Because of Hydrogen Analyzer Inoperability.
The issue involved
the entry into TS 3.6.4.1 and 3.0.5 because the A-train hydrogen
analyzer was inoperable, and the emergency power to the B-train
hydrogen analyzer was out of service for routine maintenance. The
A-train hydrogen analyzer wn inoperable because of a leaking
t
pressure-relief, pop-off valv2 on the reagent gas supply header.
The pop-off valve had allowed the reagent gas bottles to slowly
I
leak down such that insufficient gas was available for the
hydrogen analyzer to perform its intended function. The root
cause of the event was the unexpected failure of the pop-off
i
valve.
The inspector reviewed the licensee's documentation of the
corrective actions taken which involved replacing a seal ring in
the valve. The work was performed per Work request C133967 and
completed, final review, on November 13, 1992.
k.
(Closed) LER 328/93-02, Containment Boundary Isolation Valves
,
Discovered Misconfigured for an Indeterminate Reason. The event
occurred on March 21, 1993 on Unit 2 while in Mode 5, and involved
an unplanned clo.sure of Engineered Safety Feature valve 2-FCV-77-
10.
It resulted from a high spike on radiation monitor, 2-RM-90-
278, Reactor Coolant Drain Tank Discharge and resulted in the
initiation of Incident Investigation, II-S-93013, which revealed
that the RM had been spiking and closing the valve since November
13, 1992. However, this was not considered to be reportable since
the radiation monitor does not initiate an ESF signal and was not
an instrument required by the Technical Specifications.
The inspectors reviewed the incident investigation and learned
that the corrective actions taken by the licensee were to upgrade
the work priority for Work Request, WR C174065, that had been
initiated on November 13, 1992 to correct the condition. The WR
had not been given sufficient priority based on an evaluation that
the instrument was not a Technical Specification requirement and
replacement of the monitor was not completed until April 4,1993.
Although the event first occurred in November 13, 1993, the
licensee determined it not to be reportable and therefore no
report was issued.
The event occurred several more times and not
reported until the occurrence on March 21, 1993. The earlier
determinations that the event was not reportable was based on the
-
-
.
.
.,
.
25
philosophy that component level actuations were generally not
reportable. This philosophy was later discussed on May 6,1993 in
an NRC sponsored workshop on Draft Revision 1 to NUREG-1022,
'
" Event Reporting Systems - 10 CFR 50.72 and 10 CFR: 50.73:
Clarification of NRC Systems and Cuidelines for Reporting." It
appears that the philosophy used which resulted in the licensee
not reporting the earlier events meets the criteria for non-
reportability as outlined in the workshop discussions. The
inspectors determined the licensee's corrective actions were
acceptable.
1.
(Closed) LER 328/93-03, Inadvertent Actuation of Engineered Safety
Feature Component as a Result of Equipment Failure. The issue
involved continued spiking of a radiation monitor causing a
containment isolation valve to close. After increased sensitivity
by operators determined that the valve closure was reportable,
prioritization of maintenance was increased and the radiation
monitor was determined to have a failed detector. The failed
detector was replaced to resolve the problem in March 1993.
The inspectors reviewed the event and corrective actions. The
inspectors also noted that management has reenforced expectations
to operations personnel with emphasis on escalation and resolution
of repeat alarms from plant equipment. The inspectors have noted
this type of increased operator sensitivity during the recent
past.
m.
(Closed) LER 328/93-04, failure to Perform a Technical
Specification Surveillance Instruction for Verification of Ice
Condenser Chemistry Within the Required TS Timeframe.
The issue
involved the licensee's failure to perform a TS required
surveillance of the boron concentration of the ice in the Unit 2
ice condenser within 12 months. This issue was reviewed in
-
inspection report 327, 328/93-09.
In that report a review of the
issue and licensee corrective actions resulted in identification
of a non-cited violation. The inspector reviewed other corrective
actions identified in the LER and determined that they were
accomplished.
Within the areas inspected, one violation was identified.
8.
Action on Previous Inspection Findings
(92701,92702)
a.
(Closed) VIO 328/92-11-02, Failure to Follow and/or Inadequate
Procedures Resulting in a Loss of Configuration Control of the
Spent Fuel Pit Cooling System. The issue involved improper
operational control of the spent fuel pit cooling system due to
inadequate procedures.
In addition, configuration control
administrative processes were either not required for this
condition or applied in an inconsistent manner.
. _ _ -
_
_
_
._
-
,
.
.
.
26
!
The licensee responded to the violation in a letter dated June 12,
,
1992. Corrective actions for the violation included revision of
the applicable operational procedures to provide valve checklists
for different conditions.
In addition, the administrative-
,
controls for configuration of systems was enhanced.
Also,
.
operations personnel performance meetings were conducted to
j
emphasize rigorous and consistent application of basic operational
tools in everyday performance of work to prevent mistakes.
-
The inspectors reviewed the licensee's implementation of
corrective actions for configuration control problems and consider
that actions are complete for this violation.
.
b.
(Closed) VIO 327/92-29-01, failure to Maintain Operable B Train
i
Safety Injection Pump From July 31 to August 10, 1992. The issue
!
'
involved a misaligned (stuck) pump breaker trip button which
rendered the subject pump inoperable for the period stated.
,
t
'
The licensee responded to the violation in a letter dated October
29, 1992.
Corrective actions included design and installation of
new, longer pump trip buttons on all safety-related 6.9 KV
breakers.
In addition, the licensee instituted extensive
corrective measures to enhance the verification and post-
maintenance testing processes and practices.
The inspectors reviewed the licensee's implementation of
corrective actions for this violation.
The inspectors have
verified that all safety-related 6.9 KV pump breakers have been
modified with longer trip buttons.
In addition, the inspectors
are reviewing ongoing corrective actions for verification of
,
system configuration control and post-maintenance testing. The
inspectors consider that corrective actions have progressed to a
point where this violation can be closed.
c.
(Closed) VIO 327, 328/92-36-03, Failure to follow and/or
inadequate procedures for configuration control of RWST heaters
I
and EDG fuel oil pump transfer switch positions. The issue
involved misposition of the IB1-B and the IB2-B day tank supply
pump handswitch to the off position instead of the auto position.
The normal position of the switch is the auto position, reference
i
501-82.2 Diesel Generator IB-B, Revision 39, Section 82.2G, V.B.2.
The licensee responded to the above violation by letter to the
NRC, dated February 16, 1993. The inspector verified that the
licensee completed actions as stated in the above letter.
i
d.
(Closed) URI 327, 328/88-37-01, Concerns Regarding High Impedance
Faults and the Requirements of 10 CFR 50, Appendix R.
The issue
involved the requirements of 10 CFR 50, Appendix R, Section
III.G.2 with regard to maintaining one train of hot standby
systems free of fire damage.
Concerns were identified in IR 327,
328/88-37, that high impedance faults were not addressed in the
.-
.
$
27'
i
Associated Circuits Analysis which would affect the licensee's
i
ability to meet the requirements of 10 CFR 50, Appendix R.
.
To address the concern, the licensee prepared Calculation No. SQN-
APS-015, dated April 9, 1990. The calculation concluded that
there was margin available in all of the normal upstream feeder
i
breaker trip settings for each distribution board such that, a
breaker trip, as a result of high impedance fault currents during
.
an Appendix R event, was not a concern and that no modifications
!
were reeded. Subsequent review by the NRC staff concluded that
'
the licensee's calculation was acceptable. The review determined
i
that the calculation was acceptable. The review also recognized
1
that the calculation addressed certain recommendations for other
'
possible improvements; however, NRC review concluded that there
was sufficient margin in the main feeder breakers' long-time trip
settings such that no plant modifications were warranted.
,
On September 1,1992, the licensee revised Calculation SQN-APS-015
,
to remove the recommendations to de-energize the load breakers for
the non-1E power outlets and resetting the long-time setting for
!
the 480 volt C & A vent board 2Al-A. These revisions were made
based on the adequate margins to sustain high impedance faults on
the Appendix R distribution boards as detailed in the calculation.
Based on review of the licensee's calculation SQN-APS-015, the
'
inspectors consider the URI closed.
!
e.
(Closed) IFI 327, 328/88-37-02, Concerns Regarding Separation of
Cables and the Requirements of 10 CFR 50, Appendix R.
The issue
involved the requirements of 10 CFR 50, Appendix R, Section '
III.G.2 with regard to maintaining one train of hot standby
systems free of fire damage. Concerns were identified in IR 327,
i
328/88-37 with respect to separation of cables associated with the
VCT and Charging Pump B such that the licensee could not meet the
i
requirements of 10 CFR 50, Appendix R and would not be met until
completion of certain modifications.
The issue was originally identified as part of a 1984 10 CFR 50,
Appendix R, reevaluation.
The concern was identified as
Interaction 120 in IR 88-37.
Interaction 120 identified cables
that could interact with the control cables for the VCT outlet
j
valves (FCV-62-132, 133) at multiple locations within the plant.
Because these valves are connected in series, spurious actuation
(caused by fire) of either valve could cause a loss of suction to
both of the charging pumps. The licensee took immediate
compensatory actions via placing the area under a roving fire
watch round while the issue was being resolved.
The licensee's original disposition of the issue consisted of
j
operator action to remove power from the valves and to switch over
to the RWST for CCP suction if fire was confirmed in various areas
of the auxiliary building. NRC IR 88-24 concluded that this
disposition was unacceptable. This was based on inadequate
.
-
.
.
28
assurance that, if the valves closed and the non-operating CCP was
also damaged by fire, the operating CCP could be shut off before
sustaining damage.
The licensee's final resolution of Interaction 120 was to add
ste -mounted limit switches on the VCT outlet valves designed to
open the redundant train RWST outlet valve. The modification
ensures that adequate suction is maintained on the operating CCP
in the event of the postulated fire. The inspectors verified
completion of the above modifications via the work documentation
package. The work was performed during each Unit's respective
cycle 4 refueling outage.
Based on a review of the above modification, the NRC staff
considered that Appendix R requirements for Interaction 120 were
being met.
Within the areas inspected, no violations were identified.
9.
RESTART REVIEW ACTIVITIES
During this period, inspection activities continued regarding review of
the licensee's restart plan. These inspections included verifications
that the licensee was following their plan in the backlog and operations
areas.
Initial inspections of the licensee's restart plan were
addressed in inspection report 327, 328/93-16.
a.
Review of Backlog Evaluation Process (71707)
During this inspection period, the inspectors reviewed the
licensee's backlog evaluation process. The inspectors verified
,
that open items which were evaluated by the licensee as restart
1
items met the criteria established.
Items which were not restart
items were verified by the inspectors to have an acceptable
justification to defer until post restart. The inspectors
reviewed the system backlog notebooks which the licensee developed
to document these evaluations. The system notebooks contained
!
maintenance work request listings, CAQ corrective actions, DCNs,
Major Issues List items, obsolete equipment items, and other open
i
issues. The inspectors verified that items recommended.by the BRC
,
as restart items were listed on the most current Restart Evalu-
l
ation For Sequoyah Nuclear Plant printout or were scheduled to be
presented to the MRRC.
Items identified as non restart items were
j
reviewed and discussed as necessary with the accountable system
,
engineer to ensure that adequate justification existed to defer
until post restart.
The inspectors reviewed system notebooks for the following sys-
tems:
System 01
-
-
. . -
-
-
'
>
.
. .
..
i
.
I
I
29
i
System 03
-
)
'
l-
System 15
-
' Steam Generator Blowdown
System 18
-
Fuel Oil
l
,
System 26
-
High Pressure Fire Protection
System 30
-
Ventilation
.
System 56
-
Temperature Monitoring.
l
System 62
-
Chemical and Volume Control
System 63
-
Safety Injection
,
System 65
-
Emergency Gas Treatment
System 67
-
Essential Raw Cooling Water
System 70
-
Component Cooling Water
System 72
-
System 74
-
e
System 78
-
Spent Fuel Pit Cooling
System 82
-
Standby Diesel Generators
I
!
System 83
-
Hydrogen Recombination
System 86
-
D/G Starting Air
1
1
System 88
-
Containment Isolation
j
System 90
-
Radiation Monitors
Reactor Protection
.
System 99
-
System 249 -
Standby Diesel Batteries
System 268 -
Hydrogen Mitigation
The inspectors identified that the work request listings were
difficult to audit because each system engineer did not annotate
restart items consistently.
The inspectors required system engi-
neers assistance to interpret the notations in the backlog
notebooks in order to evaluate the disposition of work requests.
In addition, the inspectors identified several cases where
department manager signatures or system engineer concurrences were
not signed off on the Backlog Review For Restart forms. The
.e
l
.
,
,
.
'
30
inspector considers this a lack of attention to detail in
i
documenting the backlog reviews.
The incomplete sign-offs were
corrected when the inspector informed the licensee.
The inspector
considered system engineer knowledge good and did not identify any
instances where backlog items were deferred without proper
justification.
During reviews of the RHR, Containment Spray, and Containment
f
Isolation systems, the inspectors considered the system engineer
'
knowledge and understanding of the overall system condition to be
good. The inspectors identified several items that were
identified as non restart that did not contain sufficient detail
in the system notebooks to determine the extent and scope of the
activity to be accomplished and did not contain adequate
documentation to justify the non restart determination. These
.i
items were discussed with the system engineer and determined to be
l
non restart items; however, in several instances the system
engineer was not completely cognizant of the activity identified
,
as non restart and had to research the item prior to providing the
justification for the item being identified as non restart.
,
During reviews of the CVCS, SI, and Radiation Monitoring system
notebooks, the inspectors noted inconsistencies in methodologies
'
used by each system engineer to keep the notebooks current which
made the books difficult to understand and audit.
System
engineers were generally very knowledgeable of their systems and
'
the application of the restart criteria to the identified backlog
,
items, however; they were not aware'of the status of work
completion on their systems.
During inspections of backlog for the ERCW and FP systems, the
t
inspectors concluded that backlog reduction decisions were made on
i
number rather than criteria.
For the ERCW systems some of these
,
types of calls were made for the backlog of open WRs (180) to be
i
reduced by 60%. One exception was the replacement of the
traveling screens wire mesh. The mesh has a large number of holes
and the WR will install stainless steel mesh.
This was not made a
restart item even though the system engineer stated that the
traveling screens were one of the top three system problems.
,
,
Of the 99 open WRs in the Fire Protection System, only 25% will be
closed prior to restart. The inspectors questioned some of the
items in this system that will not be worked for restart.
They
>
were:
,
-
Reachrod inoperable for hose station isolation valve
-
Sticking handswitch for strainer backflush
-
Slow response time for annunciator and pump start signal
due to pressure switch not actuating properly
.
. _ _
_
-
_
_
_
__
__
_-
.
.
.
'
.
31
-
Isolation valve difficult to operate (two men could not
operate)
-
Need to replace leaking valve which allows ERCW pump house
1
hose station to pressurize and makes it difficult to use
j
During reviews of the backlog status for the Fuel Oil and Spent
I
Fuel Pit Cooling systems with cognizant system engineers, the
j
inspectors concluded that the system engineers were significantly
.
involved in the initial backlog review, for items prior to May 1,
1993, and the restart criteria had been implemented correctly in
l
each of the backlog dispositions for these systems.
Both system
l
engineers indicated that they were satisfied with the backlog
'
dispositions for all open work.
The inspectors noted that backlog reviews were not included in the
i
notebooks for items identified after May 1, 1993.
In addition,
i
the inspectors discussed Operations review of WR/W0s with the SRO
l
assigned to review them for. the Work Control section. This SR0
-
'
stated that backlog evaluation sheets were not filled out for new
WR/W0s; the backlog determination were made by the work control
SR0 and documented on the WR card. Any item required to be
completed prior to restart would then be placed on the restart
i
list. The remainder of the items will be part of the backlog.
!
The licensee's restart plan for backlog includes programmatic
reviews for several types of programs. The inspectors discussed
!
the licensee's method.for conducting the programmatic reviews and
i
!
identified no concerns. The inspector reviewed the backlog status-
for TACFs and discussed the justification for the restart
'
dispositions with the cognizant engineer.
From this_ review, the
'
inspector concluded that the restart criteria were satisfactorily
i
implemented for TACFs.
l
During reviews of the Hydrogen Mitigation, and Hydrogen
!
Recombiners systems, the inspectors noted only one work request
per system was identified as backlog. The inspectors determined
i
that both had been properly evaluated by the licensee for restart.
During reviews of the Component Cooling System, the inspectors
,
noted 100 open work orders that were not identified in the outage
schedule.
Fifty-seven of these items were designated as required
i
for restart.
Five DCNs were identified and 4 of those were
,
designated as required for plant restart.
The inspectors agreed
with the licensee's evaluation of the work items based on the
restart criteria. However, the inspectors consider that post
i
restart items which do not jeopardize the function of the system
i
such as missing needles on local indicators should receive high
!
priority for post restart corrective action.
l
!
The inspectors performed a walkdown of Reactor MOV Boards to
[
evaluate the adequacy of the drawings to the configuration for the
<
i
!
t
!
. , _
_
r
...
.
.
.
.
32
Component Cooling System.
The following drawings were reviewed as
l
part of this inspection for the electrical breakers. These were
i
as follows:
-
CCD 1,2-45N751-8, R-II, Wiring Diagrams 480V Reactor MOV BD
182-B Single Line SH-2
,
-
CCD 1,2-45N751-4, R-9, Wiring Diagrams 480V Reactor M0V BD
1A2-A SINGLE LINE SH-2
-
CCD 1,2-45W751-3, R-10, Wiring Diagrams 480V Reactor MOV BD
1A2-A Single Line Sheet-1 One discrepancy was identified on
this drawing. The hand switch for FCV-70-139 was identified
as FCV-70-130 handswitch. The licensee initiated action to
correct the deficiency.
Preventative Maintenance
The preventative maintenance for the following electrical breakers
was reviewed during the inspection period to determine the
>
adequacy of the preventative maintenance program. The results of
this review are as follows:
Date of Reg'd
Board
Compartment
Equipment
Last PM Frequency
SD 181-B
3C
4/90
3rd Refuel
4C
4/90
3rd Refuel
4B
4/90
3rd Refuel
'
MOV IB2-B
13B
FCV-70-26
NONE
11A
FCV-70-3
NONE
MOV IB2-B
14B
FCV-70-75
NONE
MOV IB2-B
20A
FCV-70-207
NONE
MOV IB1-B
T.B. PUMP IB-B
7/93
4th Refuel
19E
FCV-70-197
NONE
'
13A
FCV-70-10
NONE
j
VENT 2Al-A
SC
H2 INVERT 0R
NONE
VENT 281-B
7B
H2 INVERT 0R
NONE
,
The General Electric Vendor Manual, SQN-VTM-Gn30-0010, recommended
i
two tests be performed on the subject breakers which consisted of:
(a) Routing Field Testing and (b) Verification Field Testing.
However, the vendor specified that the frequency of testing should
include allowances for environmental conditions at the breaker
locations, such as dust, temperature, frequency of operation, and
etc.
However, EPRI did issue a recommended test periodicity for
molded case circuit breakers. This was published in EPRI NP-7410s
Vol. 3, October 15, 1991.
The licensee has indicated that the current program does not
provide for testing of molded case circuit breakers that are not
included in the Technical Specifications.
Some plans have been
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,
!
initiated to start testing the safety-related breakers which are
not designated as required by the Technical Specifications to
verify operability. However, the test program for testing
-
breakers not specified in the Technical Specifications has not
'
been formalized. This will be identified as an Inspector Follow-
up Item, 327, 328/93-23-05, Review of Licensee Program to Test Non
T.S. Molded Case Circuit Breakers.
,
,
During the last week of the inspection period, the inspectors
reviewed the restart determinations for backlog and emergent work
items for system 99, Reactor Protection System, and portions of
the ventilation system designated as system 30. The inspection
t
consisted of system notebook reviews, discussions with system
engineers, comparisons of information in the system notebooks with
the work scope defined in the outage work list and that contained
in the work request / order data base, and review of the outage
scope addition and deletion process.
For system 99, no items were identified which should have been
i
designated restart per the Restart Plan criteria that were not
identified as such.
However, Unit I restart item number 103 was
,
consider closed, as indicated by completion of a closeout form by
the Technical Support ICE supervisor on July 1,1993, with only
part of the work performed. The system engineer indicated that
the intent of the item had been met and the form contained
adequate justification that replacement of only three of the four
specified Solid State Protection System power supplies were
necessary prior to restart. At the time restart item numSer 103
was reviewed by MRRC, MRRC was informed that the vendor had five
power supplies available and work request C128741 and C128742 were
designed to be performed prior to restart. These work request
were written to either replace or refurbish the powers supplies on
unit 1 SSPS trains A and B.
Subsequently, the vendor was able to
only provide three new power supplies. Thus, the closeout
involved a reduction in scope and was authorized at a level of
management below the level of management that had required it to
be performed.
This inappropriate practice was discussed with
plant management. Work request C007360 was subsequently issued on
July 8 to replace the fourth power supply.
In addition, at the
end of the report period, guidance was being prepared to inform
plant personnel of management's expectations involving processing
closure of items involving scope reductions.
During discussions concerning the appropriateness of the closure
of restart item number 103, the licensee identified to the
'
inspectors that the closure form had been signed at a level of
management below that anticipated. The management expectation was
that closure forms would be signed by a department manager or
higher level of management, i.e., was not to be delegated down the
management chain. At the end of the report period, actions were
being taken to ensure that appropriate personnel were aware of
this management expectation.
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34
The inspection of the system 30 items was not completed in that it
was not possible to determine why certain items did not meet the
restart criteria.
The lead system engineer for the system was not
available during the inspection and the other system engineer that
was assigned portions of this system was unable to explain, from
the existing documentation, why some items were included or
excluded from the restart work scope.
This was especially evident
in discussions associated with ventilation components for the
turbine building.
For the safety-related components, it was
1
apparent that the criteria for designating items as work prior to
restart had been conservatively implemented.
During the inspection, it was determined that inconsistencies
,
existed among system engineers' understanding of the priority
codes 'as they related to restart.
Engineering supervision
.'
indicated that actions would be taken to ensure engineering
'
personnel understand the use of priority codes.
In addition, the
inspectors determined that there were significant inconsistencies
among system engineer's understanding involving management's
implementation expectations for restart criteria 5 and 6
associated with B0P equipment availability and plant reliability.
At the time of the inspection, this appears not to be a problem
'
due to the amount of special management oversight and the
conservatism used to date in categorizing items. However, during
future outages, when the special review processes of the present
outages are no longer in place, it will be important that system
engineers clearly understand managements' expectations in this
'
area.
During a briefing on July 9,1993, the Site Vice-President
indicated that this observation involving the system engineers'
restart criteria understanding independently confirmed information
that he had received from his staff.
He indicated that additional
training would be provided to the system engineers, possibly
including meetings between the system engineers and the MRRC.
As part of the inspection associated with emergent items, the
inspectors reviewed the use of the addition / deletion form, Att.
3.2 to the Restart Plan. The inspectors determined that there had
existed a misunderstanding concerning when deletion of items from
the outage required use of Att. 3.2 with its additional management
reviews, as well as, Site Standard Practice form 7.2, the usual
mechanism for removing items from the outage. When this was
discussed with plant management, the inspector was informed that
this problem had previously been identified and actions had been
taken to identify and correct this deficiency for unit 2 items and
similar actions had been initiated for unit 1 items.
In addition,
the inspectors noted that, on occasion, Att. 3.2 forms would
indicate that an item was to be deleted from the outage due to
lack of materials but would not address why it was acceptable per
the restart criteria to delete it as a restart item.
In each
instance, the form had been returned or in the process of being
returned to the system engineer for additional deletion
justification. This was discussed with the cognizant Technical
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Support supervisor who indicated that he would review the
situation and take actions, if necessary, to address this
-
observation.
The inspectors noted examples in which communication problems had
occurred between various management organizations.
In addition to
the closure form signature authorization misunderstanding
discussed above, the following examples were noted. The BRC
members had_ indicated to the inspectors that for emergent items
identified between May 1 and July 1,1993, the BRC had been tasked
by the MRRC to verify by sampling that the items had been properly
classified as restart or non-restart. However, the Site Vice-
P.'esident informed the inspector that each and every one of the
emergent items issued during this period would be reviewed by the
,
BRC.
In another instance, the MRRC delegated the approval of the
deletion of MRRC approved restart items to the BRC.
It was the
+
MRRC's understanding than the BRC would periodically review this
process with the MRRC including examples of items being removed.
However, when this deletion approval authority had been described
to the inspectors by the BRC, the report back to MRRC was not
described. This discrepancy was subsequently discussed with
management and the only BRC member that could be reached indicated
that he was unaware of this expectation.
Furthermore, although
the BRC had been granted deletion authorization for approximately
one week and had begun implementing this responsibility, the
individual responsible for revisions to the Restart Plan was
unaware of this change.
The inspectors reviewed proposed changes to the Restart Plan.
The
significant process changes were typically enhancements to the
Restart Plan involving additional management or independent
reviews to provide assurance that the intent of the Restart Plan
was and would be successfully implemented.
This was censidered
noteworthy and reflected a commitment by management to effect
positive change at the site.
j
The inspectors performed partial system walkdowns of the following
i
systems:
System 01
-
System 03
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System 18
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Fuel Oil
System 30
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Ventilation
System 62
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Chemical and Volume Control
System 63
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Safety Injection
System 65
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Emergency Gas Treatment
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System 67
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Essential Raw Cooling Water
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System 72
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System 74
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,
System 82
-
Standby Diesel Generators
,
System 249 -
Diesel Standby Batteries
,
Several minor discrepancies were identified including: pressure
transmitter housing cover was loose for 1-PT-3-132C; control air
was heard to be leaking in the Unit I steam generator level
control valve mezzanine, and a level control valve had evidence of
a significant packing leak.
The licensee was informed of these
items and the inspector noted that the packing leak was previously
identified by the licensee under WR C126530 and was determined to
be a restart item during the backlog evaluations.
The overall
material condition of most of the systems was good.
The inspector performed a limited walkdown of portions of the Unit
l
2 CVCS system, SI system, RHR A and B systems. There were
'
numerous temporary component identification tags (" green tags"),
some dating back a few years.
Some seal leakage was observed on
i
RHR 2A-A pump as evidenced by a large accumulation of crystallized
.
'
boric acid. There were several very loosely secured argon bottles
in the 2A-A centrifugal charging pump room and 2B-B safety
injection pump room which presented a potential personnel safety
and missile hazard.
In addition, an industrial cleaner (Dyna-
Clean Foam) was found by the inspector in a painters bucket in the
'
2A-A centrifugal charging pump room. This cleaner was
_
specifically marked as "not approved for use with materials that
come in contact with the RCS".
Discussions with responsible
chemistry department personnel revealed that this cleaning agent
"
was not authorized for use in those areas.
Inspectors from Region
II, Division of Radiation Safety and Safeguards were informed and
will follow this issue.
During a walkdown of selected portion of the ERCW system, the
inspectors noted the overall housekeeping condition of the plant
was fair to good. However,the ERCW pump house was an exception.
The pump house was dirty with trash not having been picked up.
There were several spared junction boxes that were left in place
when some heat tracing was abandoned.
Also, two examples of inattention to detail by maintenance
personnel were noted. The first one dealt with parts taken off
the AFW pump turbine being placed in the corner of the room and
!
not being bagged nor tagged.
Some the items were bolts which
could be confused for other applications.
The second item dealt
with the motor driven AFW pump constant level oilers being loose.
There are set screws or thumb screws for tightening the oilers but
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37
about half of the oilers were loose. Also the instructions in the
.
PM procedure for changing out the oil only addresses one type of
!
I
oiler. The inspector talked with system engineer about the need
to included all relevant information.
A walkdown of various system 30 components in the auxiliary and
,
diesel generator buildings was performed.
Excluding identified
deficiencies, the material condition of equipment was generally
,
'
good. The inspectors observed three conditions which required
further evaluation. These were: 1) two of the four Auxiliary
Building Gas Treatment System fan A-A mounting bolts appeared to
have the nuts improperly installed; 2) cooling air flow could not
,
be detected through the diesel generator 2A-B control board; and
!
3) the diesel generator IA room exhaust fan damper was not full
open.
In addition, the system engineer, who accompanied the
inspectors, identified that the exhaust fan for the diesel
generator 2A-A electric board room was operating; however, its
discharge damper was closed.
Engineering personnel indicated that
i
work request would be issued to correct these conditions as
required.
Review of Design Changes
The inspectors reviewed the following design change notices (DCNs)
.
on system 82.
DCN M6604 - This design change was initiated due to a 10CFR part
21 notice from Morrison Knudsen on SQN EDG's not having an
independent pneumatic starting air system, but it also corrected
several undesirable wiring situations existing for some time.
Additional problems were identified.
DCN M6604 was revised to
correct them and achieved the following:
.
-
Rewired the air start motor engaged contacts so that a EDG
starting air system could be taken out of service without
affecting the EDG's ability to start.
-
Rewired the EDG's idle start circuitry to prevent the
initial speed surge to greater than 550 RPM on starting,
from releasing the Idle circuit seal in.
-
Replaced the indicating lamps on the EDG engine control
panel. The original lamp sockets were susceptible to
i
shorting out while installing a bulb which blew a fuse that
'
disabled the Diesel Generator.
-
The Manual and Auto voltage M0P controllers panel wiring was
changed to allow the vendor current controller to be a
direct replacement part. Controller are only available
direct acting and were being rewired prior to being
installed as reverse acting controller.
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38
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Rewired the air valve solenoid to prevent disabling the
diesel on an air valve solenoid fuse blowing.
-
An FDCN is planned to be submitted to address the speed M0P
in a similar manner as item above.
.
DCN M9096 - This design change was to eliminate an EMF noise being
introduced in to the Woodward Governor panel of EDG 2B-B and
causing it to swing its load. This DCN installed an interposing
,
relay in the engine control panel to isolate the Woodward Governor
l
panel from EMF noise.
i
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There are currently 24 design change issues which are directly
associated with the main steam system. Six of these are considered
restart required items. These are:
-
Issue #93106 Main Steam Dump Drain Tank level switch (Unit
2)
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Issue #93107 Main Steam Dump Drain Tank level switch (Unit
.
!
1)
.
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Issue #93142 Hanger Modification
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Issue #93183 Replace 1-FCV-1-17 (Terry Turbine)
-
Issue #93057 Unit 1 Foxboro controller relay replacement
'
for steam dumps and PORV's
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Issue #92257 Unit 1 Valve vault overpressurization
.
An additional two modifications will be implemented prior to
restart.
i
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Issue #93148 U1 pressure seal valve
-
Issue #93149 U2 pressure seal valve
The inspectors noted that the remaining modifications are
tentatively scheduled to complete by the conclusion of the cycle
10 refueling outages. The inspectors concluded that the licensee
has addressed all necessary modifications for system 01 for
restart.
Several post-modification tests and ongoing maintenance were also
observed from start to finish including discussions with foremen
and supervisors.
The inspections, to date, indicate that the licensee is addressing
,
backlog issues in the manner described in the Sequoyah Restart
Pl an .
However, several restart plan inconsistencies were noted by
the inspectors during this period. They were:
.
.
.
.
= = . -
.-
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+
3
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1
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1
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Need for clarification on how emergent issues (issues after
May 1, 1993) were being reviewed.
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Need for clarification of how post restart issues would be
,
prioritized.
(The process for this item had not been
!
presented to the inspectors when the inspection period
ended.)
.
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Need for senior plant management to better communicate
expectations to BRC, lower levels of management, and system
engineers regarding execution of the restart plan (uniform
clarification of restart criteria to all). This observation
!
was considered to take on added importance later in the
inspection period based on the inspectors comments during
the last week of this period.
,
Several plan enhancements or corrections were accomplished during
this inspection period. The inspectors consider that the licensee
i
needs to formally incorporate these enhancements or corrections
,
into the plan and formally communicate this information to the
NRC.
i
b.
Plant Operations (71707)
(1)
One June 9, 1993, the inspector attended an all-day
Operations Standdown meeting, during which various licensee
managers addressed Operations, Work Control, and Fire
Operations personnel. The meeting included both short and
long term performance goals, and emphasized management
expectations for Operations as the " responsible owner" of
Sequoyah.
Findings of a recent assessment of operator
performance by the Restart Readiness Team were discussed,
and the need for improvement in the identified areas was
strongly stressed.
,
Recent operational weaknesses were discussed. On June 8,
1993, NRC inspectors had discovered an AUD who was
inattentive to his duties.
On June 8, 1993, two AV0s failed
to respond to a fire drill within the required time limits.
These occurrences are discussed in more detail in paragraphs
3.a (1) and 3.b (1), respectively.
Licensee management made it quite clear that these and other
recent performance problems could not continue without
serious consequences.
Good performers were urged to take
personal responsibility to improve poorer performers, for
'
the mutual success of the itam.
Significant time was devoted at the standdown to
configuration control, and to the procedures, policies, and
expectations for independent verification. A number of
example situations were discussed. The amount of dialogue
l
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which ensued indicated that this clarification by management
was beneficial.
In the future, independent verification
will be used for configuration control, and concurrent
independent verification will be used for procedure steps
i
which present immediate plant safety or personnel hazards if
improperly performed. With the exception of certain system
i
alignment checklists, required independent verifications are
to be performed before performing the next step in the
procedure, unless proper approval is granted. Persons
performing independent verification may travel together as
long as the work is actually independent.
The quality and use of procedures was stressed by management
as an area in particular need of improvement. Operators
were reminded to apply a common sense approach to
implementing procedures, not to live with problems with
equipment and procedures, and to be proactive rather than
i
reactive. Policies on procedure notes vs. formal changes,
j
and for marking steps as NA, were clarified.
Procedure
adherence was reinforced by a training film provided by Duke
Power.
A highly experienced ex-navy individual had been hired by
the licensee to act as an AUD evaluator, coach and mentor.
He discussed his activities to improve the level of
performance of AVO rounds and related activities and to
foster communication and teamwork.
The Operations Superintendent addressed the usage of E0Ps
and A01s. He discussed an operational event where
performance of an A01 interfered with the performance of an
E0P, and described instances during simulator training where
operators had consciously and unnecessarily delayed obvious
and prudent actions until they reached these steps in the
procedure.
He stated that if plant conditions warrant the
performance of an A0I during an E0P, then the required A01
should be performed concurrently (on a not-to-interfere
basis) with the E0P. Also, independent actions to mitigate
the effects of an adverse condition may be taken which are
not addressed by procedure or may be taken earlier than the
sequence specified in the procedure. SRO concurrence is
required before performance of such actions. A01s and
independent actions will not be performed while performing
time-critical evolutions or immediate action steps. When
the A01 for a loss of offsite power is run concurrently with
an E0P, the ASOS/SR0 will assign an operator responsibility
for the A0I if an ASOS is not available.
Other areas reviewed and discussed during the standdown
included shift staffing, operator aids, disablement of
nuisance alarms, compensatory measures, operator tours and
roundsheets, logkeeping, sensitive equipment control,
_ _
_
_ _
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41
surveillance instruction coversheets, procedure change
processes, the TSCCR process, and general conduct of
operations.
In general, the presentations were clear and
thorough. The Operations Superintendent explained the
rationale behind many of the procedure steps and changes,
,
which was a positive feature of the briefings.
>
Operations personnel appeared receptive to the policies and
expectations conveyed by licensee management. Throughout the
standdown, the inspectors noted that operations personnel
did not hesitate to ask probing questions, offer their
I
suggestions to management, and express perspectives and
i
opinions even when these differed from those of management.
.l
The inspectors concluded that the operations standdown
i
meeting adequately presented the performance expectations of
i
management, particularly with respect to an attitude of
ownership and personal responsibility for quality.
(2)
During this assessment period, inspectors from other plants
,
and Region II reviewed operations performance in the areas
i
of control room conduct, operator logs, control room draw-
ings and shift turnovers.
Senior operator and operator
!
knowledge of system status and plant conditions was accept-
'
able, and accurately reflected in control room logs. Con-
>
duct and turnovers was also adequate.
During a review of
control room drawings, the inspectors noted the AFW system
flow diagram was cluttered and difficult to interpret, since
it depicted all three trains of AFW for both units on a
l
single drawing.
The inspectors also noted that the electri-
cal drawings were not clearly indexed and it was difficult
.'
to move from larger one-line drawings to component level
elementary diagrams.
One inspector attended the operations shift turnover
!
conducted at 7:00 am on June, 18, 1993.
The inspector
4
-
considered that the turnover was well conducted with a good
i
exchange of information from the SOS to the crew.
.
Discussion of issues and activities was encouraged and
carried out during the turnover.
In addition, the crew was
addressed by the Site Vice President and Plant Manager about
expectations and the upcoming " quiet time" for Unit 1.
Expectations for operator attention to detail was addressed
by the Operations Superintendent. The inspector considered
the turnover and status handout provided to the crew was
good.
It contained sufficient detail on ongoing activities
and problems, and was written in an easy-to-read format.
The defense in depth status sheets were considered to be
beneficial.
(3)
On June 28, 1993 the operations department commenced 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
shift operation.
Shift turnover times were established at
._.
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42
I
7:00 am and 7:00 pm.
This change resulted in SRO, R0, and
ADO turnover times being the same.
Previous shift coverage
had SR0s on 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts, and R0s and AU0s on 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />
shifts. The inspectors monitored shift turnover activities
to evaluate implementation of the new shift hours. They
';
noted that turnovers with full crew complements allowed for
better communication of turnover issues to the operations
oncoming crew. However, during one of the morning shift
,
turnovers, the inspectors noted excessive noise level in the
cafeteria area.
The inspectors concluded, based on licensee assessments, review of
,
operations standdown meetings, and general observations during the
period that general operator performance regarding attention to
,
detail and sensitivity to not living with past problems is
'
improving.
No Violations or Deviations were identified.
10.
Review of Licensee Previous Commitments
(92701, 92702)
>
The inspectors reviewed the licensee's corporate commitment tracking
system (CCTS), and performed independent verification of selected items
to determine if the licensee had satisfied commitments that were open
when Units 1 and 2 restart in 1988. The purpose of this review was to
determine if the licensee's CCTS was adequately identifying and tracking
NRC commitments. The review identified that all commitments that were
open at the time of the 1988 Sequoyah Units 1 and 2 restart have been
i
closed, with the following exceptions:
-
Commitment items associated with control room design review (CRDR)
remain open. These items consist of Category 3 Human Engineered
Deficiencies (HEDs) (non safety significance), to be completed
,
during each unit's cycle 6 refueling outage. Unit 1 is currently
in the cycle 6 refueling outage, with Unit 2 scheduled to begin
cycle 6 refueling in January 1994. The licensee plans to
implement 14 items during these refueling outages. The schedule
for these remaining open items was provided to the NRC in a letter
dated February 4, 1993. This submittal also indicated that 107
nonsafety significant HEDs would not be pursued because resolution
is no longer cost effective. All Category 1 and 2 HEDs (safety
,
significant) have been completed.
-
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Civil issues identified in Inspection Report 50-327,328/88-12
remain open. The licensee has submitted additional information
for all remaining issues, which is currently under review by NRR.
-
The licensee has yet to complete modifications to resolve the
problem of Unit Board breaker capability.
Several letters have
,
'
been docketed informing the NRC of changes in the licensee's
approach to resolution of the issue, and schedule changes. The
.
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43
licensee stated in a March 24, 1993 letter, that the completion of
l
modifications for this issue would be accomplished by the end of
the Unit 2 cycle 6 refueling outage. This outage is currently
i
scheduled for January 1994.
The licensee identifies this issue as
not a nuclear safety concern.
'
The inspectors conducted an independent review of selected items and
commitments that were open at the time of the Units 1 and 2 restart in
1988.
The following items were reviewed by the inspectors, with status
as noted:
'
a.
EDG voltage transient response and EDG performance evaluations.
This issue is associated with the licensee's commitment to improve
EDG voltage trar.sient response performance.
By letter dated March
!
3,1988, the licensee informed the NRC of the actions taken to
evaluate improvements and recommended in the Sequoyah Nuclear
.
Plant Diesel Generator Evaluation Report (DGER). This report
documented that the 1987 EDG test results were bounded by TVA's
i
EDG analysis and that the safety related systems and components
will perform their intended safety function when powered by the
EDGs with acceptable margin to insure their operability.
Additionally, the DGER contained actions that could be taken to
improve EDG performance.
By letter dated July 8, 1988, the licensee identified to the NRC
various commitments as a result of their review of the DGER.
These commitments included:
.i
(1)
Modifications to enhance the EDG transient voltage response
'
for one EDG, which included (1) resetting the exciter-
current transformer taps to achieve flat compounding, and
(2) rep?acement of the existing pneumatic load sequence
timers with more accurate electric timers.
1
(2)
Upon completion of item (1), the licensee will perform a PMT
to determine if improvement in the EDG transient voltage
response is acceptable.
'
(3)
If the evaluation from (2) is unacceptable, the licensee
will install a voltage overshoot reduction device (V0RD) on
the above EDG.
.
(4)
The licensee will perform a PMT on the above EDG to
determine the acceptability of the VORD.
(S)
The licensee will implement the modifications that provide
an acceptable improvement in the transient voltage response
on the three remaining EDGs.
(6)
PMTs on the remaining EDGs will then be performed.
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(7)
The licensee will provide the NRC with the evaluation and
i
test results of the PMTs which provide acceptable
l
improvement in the four EDG transient voltage responses.
The inspector reviewed the following documentation:
'
,
t
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Diesel Generator Voltage Response Improvement Report.
-
PMTs associated with the above EDG testing.
I
,
!
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DCN M007398, Reset exciter control current transformer taps
This DCN satisfies commitment (1) (1) above.
!
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ECN L7286B, Replacement of EDG load sequence electro-
mechanical timing relays with electronic relays. This ECN
satisfies commitment (1) (2) above.
!
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DCN M01367A, Installation of a VORD, and reset exciter
i
control current transformer taps (Unit 1). This DCN
,
satisfies commitment (3) above.
l
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DCN M013678, Installation of a VORD, and reset exciter
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control current transformer taps (Unit 2).
This DCi1
satisfies commitment (5) above.
,
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By letter dated May 18, 1990, the licensee provided the NRC
i
with the evaluation and test results of the PMTs which
provide acceptable improvement in the four EDG transient
!
voltage responses.
This letter satisfies commitment (7)
,
above.
,
Based on a review of the above documentation and discussions with
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the EDG system engineer, the inspector concluded that the licensee
has satisfied the above commitment associated with investigating
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and implementing modifications to improve EDG voltage transient
response.
b.
Issues related to cable installation and test program,
qualification of cables for expected life of the plant before
return from refueling outage, including silicone cables. The
inspector reviewed related correspondence associated with the
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silicone rubber-insulated cable 40 year qualification test report.
This correspondence included a test report conducted by Wyle
Laboratories, entitled " Qualification Test Program for Silicone
Rubber Insulated Cables for Use in Tennessee Valley Authority's
Sequoyah and Watts Bar Nuclear Plants", which was performed in
December 1988. This test report concluded that the test
specimens, subjected to normal radiation exposure, thermal aging,
and accident radiation exposure, demonstrated the capability to
,
maintain specified voltage and current during the specified Design
Basis Event (LOCA Simulation).
The licensee docketed the findings
,
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of this test report in a letter to the NRC dated March 13, 1989,
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and concluded that the samples have successfully demonstrated that
the silicone rubber insulated cables installed at the plant are
capable of performing their intended function inside containment
for the life of the plant plus LOCA conditions, and that the
remaining concerns have been resolved regarding cable installation
practices at the plant. The inspector concluded this issue to be
'
closed.
c.
From the Supplement 1 NUREG 1232, TVA committed to submit the
accelerated field weld program for Unit I within six months after
the restart of Unit
1..
TVA satisfied this commitment with a
submittal to the NRC dated May 5,1989.
'
d.
TVA to resolve the problem of Unit Board breaker capability.
The
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inspector reviewed the licensee's internal correspondence and
_i
discussed planned modifications with the system engineer.
In a
TVA letter to the NRC dated August 4, 1989, TVA committed to
provide a detailed description and the implementation schedule for
the resolution of Sequoyah's fdult current problem for the 6.9 KV
unit board breakers by October 20, 1989. The letter indicated
!
that 6.9 KV unit boards are equipped with ITE Imperial Corporation
7.5HK500 breakers that have a one time interrupting capability of
550 megavoltamperes (43,829 amperes at a maximum system voltage of
1
7.245 KV. The maximum calculated fault current for these boards
is 49,455 amps at 7.245 KV. To correct the problem, TVA committed
to installation of instantaneous overcurrent relays on the
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incoming breakers from the unit station service transformers so
that a high level fault on the load feeder would be interrupted by
the incoming breaker. The licensee satisfied this commitment by
letter dated October 19, 1989, which provided a detailed
description and implementation schedule. TVA committed to
implement the required modifications before startup after the Unit
>
2 Cycle 5 refueling outage. TVA stated that this issue was not a
nuclear safety concern.
By letter dated November 29, 1991, the licensee informed the NRC
that a reevaluation of the planned resolution determined that it
was not required, for the following reasons.
lhe licensee is
installing new common station service transformers (CSSTs) with
automatic load tap chargers. When installation is complete, the
CSSTs will be able to provide the units with a better voltage-
regulated power supply.
For this reason, the licensee will be
using the CSSTs instead of the unit station service transformers
(USSTs) as the normal power supply for the unit boards. The USSTs
will only be used to supply power to the unit boards while at
power for maintenance purposes. The licensee committed to the
completion of the above modifications before the end of the Unit I
cycle 6 refueling outage.
The NRC's Electrical Distribution System Functional Inspection
(50-327,328/91-02) reviewed the licensee's planned modifications
to the CSSTs and concluded that it would provide a permanent
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solution to the bus transfer scheme problem.
The Inspection
Report also stated that the control circuitry should be carefully
{
evaluated and the question of reliability should be addressed.
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By letter dated March 24, 1993, the licensee informed the NRC of
.
an extension of commitments associated with this issue. Due to
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procurement problems associated with load cabling for the CSSTs,
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the licensee stated that the completion of modifications for this
issue would be accomplished by the end of the Unit 2 cycle 6
refueling outage.
This outage is currently scheduled for January
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1994.
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Although the licensee satisfied the original docketed commitment
)
by letter dated October 19, 1989, the inspector concluded that the
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licensee has yet to install hardware to resolve this issue.
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However, the inspector also concluded that the licensee has
docketed several letters that inform the NRC of changes in their
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approach to resolution of the issue, and schedule changes.
?
The licensee's CCTS identified the original items related to this
,
issue as closed.
However, new items were opened (and remain open)
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with appropriate references to the original issue.
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e.
From Supplement 1 NUREG 1232, URI 50-327,328/88-37-01, and IFI 50-
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327,328/88-37-02. Both of these items were associated with Fire
!
Protection. The licensee had provided information related to
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these issues to the NRC for review.
Subsequent review by the NRC
i
staff indicated that the licensee had adequately resolved both of
the issues.
Closure of these items was discussed in paragraph 8.
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of this inspection report.
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f.
TVA to revise the HVAC instrumentation accuracy calculation and
address the seismic threshold limits, specify the HVAC equipment
to be inspected after a seismic event, provide an inspection
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procedure, and clarify the calculation. The NRC considered
resolution of this issue could be implemented after restart. The
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inspector reviewed documentation associated with this issue, which
included CAQR SQP880101. The issue was specifically related to
the licensee's failure to consider the effect on plant environment
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and equipment qualification of a main steam line break in the
.
vicinity of the auxiliary building air intake canopy. Temperature
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switches 1-TS-30-103, 1-TS-30-103A, 2-TS-30-104, and 2-TS-30-104A
were added to the HVAC room on each respective unit to detect a
main steam or feedwater line break in the vicinity of the
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auxiliary building air intake canopy. The switches were installed
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with appropriate logic to initiate an auxiliary building isolation
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to preclude the HVAC system from spreading steam throughout the
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auxiliary building general spaces. These switches however, were
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added prior to implementation of equipment qualification
guidelines. The HVAC equipment room had always been thought to be
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a mild environment. During analysis it was shown that the
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postulated main steam /feedwater line break could result in a harsh
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environment.
Part of the corrective actions for this CAQR was to
,
relocate, replace, or qualify existing equipment. Accordingly,-
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the above temperature switches were to be replaced with switches
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which were qualified for the harsh environment.
Other equipment
in the room was also to be evaluated for environmental effects on
operability.
As part of the CAQR, the licensee had established
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compensatory measure 880101 prior to completion of the above
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activities.
The inspector reviewed documentation associated with the above
issue. This documentation included:
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DCN M-00263B, Unit 1 DCN provided for the replacement of
original Unit I temperature switches, and relocation-of
electronics for other equipment. The safety evaluation
>
associated with this DCN also evaluated other equipment and
reviewed accuracy calculations associated with the
temperature switches. This DCN was completed and closed
November 11, 1991.
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DCN X00155B, Unit 2 DCN provided for the replacement of the
original Unit 2 temperature switches, and safety evaluation
for other equipment. The safety evaluation associated with
this DCN also evaluated other equipment and reviewed
accuracy calculations associated with the temperature
switches. This DCN was completed and closed ' August 14,
1992.
Based on a review of the above documentation, the inspector
concluded that the licensee has satisfied the commitment
associated with the above issue.
g.
Corporate guidance to be developed on use of teflon tape and a
single defined tape replacement plan. The inspector reviewed
documentation associated with this issue, which included CAQR CHS
870003. This issue was also discussed in Inspection Report 50-
327,328/87-37. The CAQR discussed discrepancies between a
corporate specification and a Sequoyah site specification
document. The inspector reviewed G-29 Volume IV Materials
Handling and Process Specifications for Material Fabrication and
Handling Requirements for Austenitic Stainless Steel, Process
Specification 4.M.I.1, Revision 14, Section 3.10.1.
This
specification delineates the temperature and radiation level usage
requirements of TFE type thread sealant materials, the pipe thread
position to start the tape, and acceptable vendor brand numbers.
The site specific procedure has been revised to delete reference
to the use of teflon tape. As such, the use of teflon tape is now
controlled via the corporate procedure G-29. -The inspector
concluded the licensee has satisfied the above commitment.
h.
Resolution of Safety Systems Outage Modification Inspection
(SSOMI) Issues from IR 50-327,328/86-68 (See IR 90-06). Inspection
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Report 90-06 addressed issues in which most were closed. Other
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issues were translated into IFI 90-06-05, which were closed in IR
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90-28.
i.
Replace bismuth solder FLAS-5 fuses from lots 2 and 3 with cadmium
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solder fuses before Mode 4.
This issue was identified in LER
,
327/87-30 regarding a blown fuse in emergency start circuits
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resulting in spurious emergency diesel generator starts on two
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occasions. This LER was reviewed and closed in NRC Inspection
Report 50-327,328/88-19, with the licensee replacing the fuses
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with fuses of the proper lot number.
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The inspectors concluded from the review of the commitments that the
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licensee has implemented a comprehensive and effective program to track
and respond to commitments.
11.
Exit Interview
The inspection scope and results were summarized on July 13, 1993 with
those individuals identified by an asterisk in paragraph I aLsve. The
inepectors described the areas inspected and discussed in detail the
is lection findings listed below.
Proprietary information is not
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contained in this report.
Dissenting comments were not received from
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the licensee.
Item Number
Descriotion and Reference
VIO 327/93-23-01
Failure to ensure that all fuel
handling was performed in accordance
with SSP-12.1.
NCV 327, 328/93-23-02
Failure to notify the NRC as
required by TS LC0 3.7.11.1 ACTION
b.2.a.
VIO 327/93-23-03
Failure to adequately implement
corrective action for identification
and removal of foreign material in
the reactor vessel prior to the Unit
1 Cycle 6 core reload.
VIO 327, 328/93-23-04
Failure to promptly identify the
procedure problem associated with
LER 327/92-21 during corrective
action for LER 327/92-03.
IFf 327, 328/93-23-05
Review of Licensee Program to Test
Non T.S. Molded Case Circuit
Breakers.
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Strengths and weaknesses summarized in the results paragraph were
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discussed in detail.
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Licensee management was informed of the items closed in paragraphs 7
and 8.
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12.
List of Acronyms and Initialisms
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A0I
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Abnormal Operating Instruction
AS05 -
Assistant Shift Operations Supervisor
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AVO
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Assistant Unit Operator
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Backlog Review Committee
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CCD
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Configurated Control Drawing
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Component Cooling Water System
CFR
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Code of Federal Regulations
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CIPTE -
Complex or Infrequently Performed Test or Evolution
CR
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Control Room
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CREVS -
Control Room Emergency Ventilation System
CVCS -
Chemical Volume and Control System
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Containment Ventilation Isolation
DCN
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Design Change Notice
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Division of Reactor Projects
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E0P
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Emergency Operating Procedure
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EPRI -
Electric Power Research Institute
ERCW -
Essential Raw Cooling Water
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Engineered Safety Feature
,
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Flow Control Valve
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Fire Protection
FSAR -
Final Safety Analysis Report
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Heat Exchanger
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Individual Data Package
IFI
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Inspector Followup Item
IR
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Inspection Report
KV
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Kilovolt
LCO
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Limiting Condition for Operation
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Level Control Valve
LER
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Licensee Event Report
LOCA -
Loss of Coolant Accident
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Main Control Room
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Motor Operated Valve
MRRC -
Management Restart Review Committee
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Non-cited Violation
NRC
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Nuclear Regulatory Commission
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Nuclear Reactor Regulation
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Operational Control Center
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Pressure Control Valve
PERP -
Plant Evaluation Review Panel
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Preventative Maintenance
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Post-maintenance Test
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PORC -
Plant Operations Review Committee
PORV -
Power Operated Relief Valve
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Parts per Million
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Pressurized Water Reactor
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Quality Assurance
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Rod Centrol Cluster
RCDT -
Reactor Coolant Drain Tank
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RII
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NRC Region II
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Radiation Monitor
R0
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Reactor Operator
RRT
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Restart Readiness Team
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Radiation Work Permit
RWST -
Refueling Water Storage Tank
SDB
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Shutdown Board
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Surveillance Instruction
S0
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System Operations
S01
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System Operating Instruction
SOS
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Shift Operating Supervisor
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Senior Reactor Operator
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Site Standard Practice
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SSPS -
Solid State Protection System
.
TACF -
Temporary Alteration Control Form
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TS
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Technical Specifications
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TSCCR -
Technical Specification Component Condition Record
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Unresolved Item
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Volume Control Tank
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Violation
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Work Order
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Work Request
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