ML20057A420
| ML20057A420 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 09/03/1993 |
| From: | Holland W, Kellog P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20057A412 | List: |
| References | |
| 50-327-93-33, 50-328-93-33, NUDOCS 9309140178 | |
| Download: ML20057A420 (41) | |
See also: IR 05000327/1993033
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S UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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" REGION 11
101 MARIETTA STREET, N.W., SUITE 290U
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p ATLANTA, GEORGIA 303234199
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Report Nos.: 50-327/93-33 and 50-328/93-33
Licensee: Tennessee Valley Authority
6N 38A Lookout Place
1101 Market Street
Chattanooga, TN 37402-2801
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Docket Nos.: 50-327 and 50-328 License Nos.: DPR-77 and DPR-79 ;
Facility Name: Sequoyah Units 1 and 2
Inspection Conducted: July 11 through August 7, 1993 '
Lead Inspector:
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~ RET) dent Inspector
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W./E. Hol -
Date' Signed
Inspectors: S. M. Shae fer, Resident Inspector '
A. R. Long, Resident Inspector
S. E. Sparks, Project Engineer
C. R. Ogle, Resident Inspector, H. B. Robinson
M. T. Widmann, Reactor Engineer, RII
B. R. Bonser, Senior Resident Inspector, Vogtle
S. G. Tingen, Resident Inspector, Surry
J. Zeiler, Resident Inspector, Catawba
Approved by: I ~~/ ./ 6793
Datt Signed
Pai// 'O .' ( tn1 tion 4A
Difis -
or Proj cts
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SUMMARY
Scope:
Routine resident inspection was conducted on site in the areas of plant '
operations, plant maintenance, plant surveillance, evaluation of licensee
self-assessment capability, licensee event report closecut, followup on
previous inspection findings, and engineered safety function system walkdowns. <
During the performance of this inspection, the resident inspectors conducted
several reviews of the licensee's backshift or weekend operations.
This report also addresses special inspections conducted in the areas of
backlog and operations. These two areas were identified by the licensee as
needing attention in their subt'+tal of the Sequoyah Restart Plan to the NRC.
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9309140178 930903
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Results:
In the area of Operations, two examples of weaknesses were identified
regarding the adequacy of operation's procedures. One en .mple related to the
utilization of a System Operating Instruction (SOI) outside of its intended
purpose and a second example involved an S0I that was difficult to perform as
written. In addition, a lack of attention to detail was identified regarding
the completion of procedure documentation (paragraphs 3.a.2 and 3.a.3).
In the area of Operations, a violation was identified regarding inadequate
configuration controls for a temporary system important to safety (paragraph
4.a).
In the area of Engineering, a violation was identified regarding an inaccurate
Catege y 1 drawing which resulted in a control air system isolation event.
Two additional examples of Category 1 drawing discrepancies were also
identified (paragraph 4.b).
In the area of Maintenance, an Unresolved Item was identified
regarding potential inoperability of both Control Room Emergency Ventilation
System trains. This issue is unresolved pending the completion of the
licensee's incident investigation to resolve when the B train Control Room
Isolation was made inoperable (paragraph 4.d).
In the area of Maintenance, a violation was identified for failure to perform
Technical Specification required boron sampling of the water in the Unit 1 '
refueling cavity (paragraph 5.b).
In the area of Maintenance, a violation was identified for failure to perform
timely reviews of completed surveillance instructinos as required by Site
Standard Practice 8.2 (paragraph 5.d).
In the area of Plant Support, strengths were identified regarding licensee
internal and external assessments. The senior management oversight group's
continuing frank and honest perception of Sequoyah's progress allowed
management to sharpen their focus on problem areas. The Nuclear Assurance
Department continued to provide good feedback to plant management on
continuing problem areas during their ongoing assessment processes i
(paragraph 6).
In the area of Operations, an Inspector Followup Item was identified regarding
the inspector's identification of unevaluated boric acid conditions on the
inside of the Unit 1 containment steel liner and the intended design of liner
flashing (paragraph 9.b).
In the area of Plant Support, a concern was identified regarding management's
decision on Unit I to remain flooded at refueling water levels with known
refueling cavity liner leakage while concentrating on Unit 2 restart work.
Specifically, at the flooded condition, leakage through the refueling cavity i
liner resulted in NRC identification of wetting of safety-related components
in the Unit I lower containment (paragraph 9.b).
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In the area of Engineering, a violation was identified for failure to control ;
the design / modification of heat trace on a safety system (paragraph 10.b).
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In the area of Maintenance, a weakness was identified regarding the acceptance
of degraded performance from heat trace stripchart recorders (paragraph 10.b).
In the area of Operations, a non-cited violation was identified for failure to ;
identify a disabled annunciator in accordance with administrative requirements l
(paragraph 10.b). !
In the area of Engineering, a Deviation was identified for failure to maintain
the FSAR current with actual plant configuration or processes (paragraph
10.c).
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REPORT DETAILS
1. Perrr w Contacted
Licensee Employees
- R. Eytchison, Vice President Nuclear Operations
- R. Fenechs Site Vice President
- K. Powers, Plant Manager
- J. Baumstark, Operations Manager
- L. Bryant, Maintenance Manager
- H. Burzynski, Nuclear Engineering Manager
- D. Driscoll, Site Quality Assurance Manager
- J. Gates, Outage Manager
C. Kent, Chemistry and Radiological Controls Manager
- D. Lundy, Technical Support Manager
- R. Rausch, Planning and Schedule Manager
- R. Shell, Site Licensing Manager
J. Smith, Regulatory Licensing Manager
- R. Thompson, Compliance Licensing Manager
- J. Ward, Engineering and Modifications Manager
- N. Welch, Operations Superintendent
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NRC Employees
R. Crlenjak, Chief, DRP Branch 4
P. Kellogg, Chief, DRP Section 4A
- Attended exit interview.
Other licensee employees contacted included control room operators,
shift technical advisors, shift supervisors and other plant personnel.
Acronyms and initialisms used in this report are listed in the last
paragraph.
On July 22 and 23, Mr. A. F. Gibson, Director, Division of Reactor
Safety, Region II, visited the Sequoyah site. Mr. Gibson reviewed
restart activities with NRC inspectors onsite regarding NRC inspections-
in progress, had discussions with licensee management, and attended NRC
inspector exit meetings.
On July 22 and 23, Mr. Paul Kellogg, Section Chief, Division of Reactor
Projects, RII, visited the Sequoyah site. Mr. Kellogg toured portions
of the facility with the inspectors, met with TVA management, and
attended NRC inspector exit meetings.
On July 23, 1993-the licensee announced corporate management changes.
The changes were in the Technical Support organization. Effective
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July 26, Mr. J. P. Maciejewski moved from General Manager of Nuclear
Assurance to General Manager of Operations Services. Mr. Paul Baron,
Browns Ferry Manager of Nuclear Assurance and Licensing was selected as
the new General Manager of Nuclear Assurance. Both positions report to
Dr. Mark Medford, Vice President of Technical Support.
On July 27, the licensee issued Revision I to the Sequoyah Nuclear Plant
Restart Plan. The revision generally incorporated additional or updated
processes issued since Revision 0; reflected additional BRC task l
assignments, and incorporated senior management oversight group
comments. ;
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On August 4, 1993 the NRC Sequoyah Restart Panel met onsite to review )
the progress of NRC activities being accomplished at Sequoyah Nuclear
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Plant prior to restart of a unit.
On August 5,1993 the NRC restart panel met with licensee management on ;
site in a public meeting to discuss restart activities with licensee
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senior management. The licensee presented the status of restart
activities to date including ongoing licensee assessments of progress
and post restart plans. NRC management and staff members in attendance -
included:
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S. Ebneter, Region II Administrator ;
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E. Herschoff, Director, DRP, RII i
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A. Gibson, Director, DRS, RII (NRC Restart Panel Chairman) .
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F. Hebdon, Project Director, NRR (NRC Restart Panel Member) ;
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R. Crienjak, Chief, Branch 4, DRP, RII (NRC Restart Panel Member)
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P. Kellogg, Chief, Section 4A, DRP, RII i
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D. LaBarge, Senior Project Manager, NRR (NRC Restart Panel Member) ]
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2. Plant Status
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Unit I began the inspection period in day 95 the Cycle 6 refueling ,
outage in MODE 6 (fuel onload in progress). The licensee completed fuel l
onload on July 12. On July 16, the refueling cavity was lowered to !
facilitate repairs to an air leak which developed on the supply line to i
the inflatable refuelii.g cavity seal. After repairs were completed on l
July 17, the refueling cavity was filled to elevation 726 and the Unit 1 ;
cavity was covered with a tarp as an FME measure. Unit I remained in :
this condition (MODE 6) through the remainder of the period while work j
effort focused on Unit 2. ;
Unit 2 began the inspection period in MODE 5 (Day 132 of a forced I
outage). During the period activities were completed in accordance with j
the licensee's restart plan and forced outage schedule. At the end of ;
the inspection period, Unit 2 remained in MODE 5 with activities ongoing i
in accordance with the licensee's restart plan.
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3. Operational Safety Verification (71707)
a. Daily Inspections
The inspectors conducted daily inspections is 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
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deviation reports, tagout logs, temporary modification logs, and
tags on components to verify compliance with approved procedures.
The inspectors also routinely accompanied plant management on
plant tours and observed the effectiveness of management's
influence on activities being performed by plant personnel.
1) On July 17, 1993, the inspectors reviewed Unit I activities
associated with refueling cavity draindown. The draindown
was to support repairs on the air supply line to the reactor
cavity inflatable sesl (as discussed in paragraph 4.a). The
inspectors reviewed selected portions of 0-S0-68-4, DRAINING
THE REACTOR COOLANT SYSTEM, Revision 9. The inspectors
concluded that the draindown was accomplished in accordance
with c.he 50.
During the review, the inspectors were informed by the unit
operator that the final draindown was delayed. This was due
to step 6.2.20 of the instruction limiting the number of
turns which HCV-74-34, RHR to RWST return isolation valve,
was opened. Step 6.2.20 instructed the operators to
throttle HCV-74-34 to achieve less than or equal to 500 gpm
and not to exceed 2 turns open. However, during the
draindown, operators noted that the two turns allowed by the
procedure only corresponded to a 45 gpm flowrate. In
addition, the operators recalled that during prior
performances of the procedure, the flowrate may have been
much closer to the 500 gpm limit at two turns.
- Given this information, the inspectors questioned the
licensee if the reduced flow rate could be a result of
, previous inconsistencies involving operators failing to ,
appropriately account for slack in the valve operator during
the throttling of some valves.
The licensee reviewed the valve maintenance history. This
indicated that the valve had been worked on during the
current outage. This work involved tightening of the valve
internals. The licensee concluded that this accounted for
the variance in the flowrates which were observed by the
operators. The inspectors agreed with the licensee's '
determination;-however, considering the work
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performed on the valve, the change in flowrate for the
draindown could have been better anticipated. The licensee
stated that a re-baseline of the desired flowrate for a
given number of valve operator turns would be performed.
Once completed, the procedure would also be revised to
reflect the expected flowrate. The inspector did not have
any further concerns. !
2) During a review of activities in progress concerning valve
lineup checklist, System Operating Instruction, S01-88.1, '
" Containment Iso',ation System," Revision 34, an inspector
identified a number of concerns with the sign-offs and the
use of the procedure. Four valve positions indicated on
S01-88.1 were identified by the operator as not being in the
position listed on the instruction. However, a sign-off was
made by the operator and a yellow " post-it" was placed on
the instruction to indicate the position found in the field.
During review of 501-88.1,Section V, the inspector noted
that an operator should fill out a CDS, attach it to the
instruction and circle on the procedure the mispositioned
valve (s) when identified; howaver, during the review of 501-
88.1 no valves were circled and no CDS sheet was attached to
the procedure. ,
The inspector discussed the inconsistencies with operations
personnel. 501-88.1 was developed to verify containment
isolation during reduced inventory or mid-loop. Plant
Operations was using the instruction to determine open
penetrations in containment during MODE 6 work. The
checklist was being used for recording openings in '
containment to provide information to the SR0 to enable
quick closure of the containment openings in the event it
was necessary. The inspector concluded that the checklist
procedure in use was weak in providing guidance for the .
containment closure function. However, the inspector also
concluded that the licensee did maintain configuration
control of the components during the activities. The
licensee agreed with the inspector's conclusions and
initiated the development of a new check list designed for
the specific purpose of tracking openings in the containment
during MODE 6 operations. The inspector considered the
utilization of 501-88.1 for use outside of its intended
purpose as a first example of a weakness with regard to the
adequacy of operations procedures.
In addition to the above, during the inspector's review of
SSP-12.3, EQUIPMENT CLEARANCE PROCEDURE, Revision 1, a lack
of attention to detail was identified in a operations
tag-out process. During the tagging out of the steam
generator blowdown sample isolation valves, Tag-out Number
1-92-1381, the operator did not properly fill out the valve
location or number description as part the clearance
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procedure. Two valve listings were incomplete. Valves 821
and 823 had no prefix identifier associated with the listing ;
(e.g. 1-VLV-1-820). The licensee recognized the inattention l
during the performance of the procedure.
3) On July 29, with Unit 2 in Mode 5, the inspectors witnessed
operations personnel add borated water to the RWST from the
Boric Acid Blender using procedure 501-62.2, Boron
Concentration Control, Rev. 40. This procedure contains
multiple (12) sections for configuring the Boron
Concentration Control System in various modes of operation.
The instructions for configuring the system in its normal
mode of operation, automatic makeup, are prescribed in
Section VI.A of this procedure. In order to refill the
- RWST, the operators were using Section VI.I, Blending to !
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RWST Using Boric Acid Blender. The refill activity was
initirted successfully and without incident. However, during l
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review of the procedure, the inspectors noted that Section i
4 VI.I was not a self-complete or stand-alone instruction in t
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that it required that the operators refer to Section VI.A to
perform critical steps and then return to Section VI.I. '
This in and of itself was not a problem, but the procedure ;
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failed to specify which steps in Section VI.A were necessary
to be performed. The operators indicated that they knew ;
which steps were necessary based on their knowledge of the !
, system and from repeated performance of the procedure. The !
l operators performed steps 1-5 in Section VI.A which included i
! verifying that valve and power availability checklists were j
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completed, as well as starting the Primary Makeup and Boric :
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Acid Pumps, and placing the blender outlet valve to its Auto i
position. ,
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! During discussions with the operators concerning the
- procedure, the inspectors learned that an operations i
procedure upgrade program had been ongoing and one of the l
areas identified was the need to revise procedures with !
multiple sections to be more self-complete or stand-alone.
The inspectors questioned the procedure writers about the :
i status of this upgrade program and learned that it had been i
initiated in late 1987 as a result of identified weaknesses 1
in the technical quality and format of operation procedures. 1
However, the licensee reported that this project had not
been completed due to the redirection of plant resources,
and there were currently 64 procedures that had not been
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revised. The licensee reported that revisions to all
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procedures that were categorized as critical to operations
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were' completed. The inspectors concluded that without prior
knowledge or experience with the subject procedure, it would ;
, be difficult to perform as written. This is considered a
- second example of a weakness with regard to the adequacy of 1
operations procedures. The inspectors considered that the i
upgrade project needs additional management attention.
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In addition, the inspectors, at the exit interview, ,
questioned how the remainder of the procedures to be ,
upgraded were being tracked for completion; or if the
procedures needed to be added as an additional backlog area.
The licensee indicated they would review the procedure
revision process status. The inspectors will monitor this
issue in future inspections.
b. Weekly Inspections ,
The inspectors conducted weekly inspections in the following
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
progress, radiation protection controls, missile hazards, and ,
plant housekeeping conditions / cleanliness.
On July 17, the inspectors were in the control room to monitor
maintenance activities to repair an air leak on the Unit I reactor
cavity seal air supply line and to monitor operators control of
the draindown for the repair. A video monitor in the Unit I area ;
of the control room had been allowing the operators to view the :
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leaking supply line and closely monitor the actual water level
(near the vessel flange). The video camera position was being ,
controlled by Health Physics personnel (Rad Con) in the refueling
deck health physics office. However, once the maintenance
activity began, the inspectors noted that the camera was moved
from the activity to another area. The inspectors questioned the
operator as to why the camera was moved off the activity. The
operator indicated that Rad Con frequently moved the cameras off
of work in progress.
The inspectors questioned the operator if he needed to watch the
repair to the cavity seal air supply. The operator stated that he
could still adequately monitor the water level with the camera in '
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the current position. The operator also indicated that he was
reluctant to request Rad Con to move the camera back to the ;
activity because he did not want to interfere with the work '
activity. The inspector agreed that the operator could adequately
monitor the water level with the camera in the new position;
however, the inspectors also considered that operator monitoring ,
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of the seal airline repair activity may have been appropriate due
to the importance of the evolution. i
The inspectors discussed the above practices with Operations and l
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Rad Con management. They indicated to the inspectors that the use '
of the available cameras would be better defined between *
Operations and Rad Con personnel. This included guidance for
Operations use of cameras for monitoring of evolutions in -
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progress. The inspectors considered that management actions taken
to correct the subject practices were appropriate; however, the i
inspectors also concluded that the above activity demonstrated
poor interaction between Operations and Rad Con personnel due, in
part, to inadequate communication of management expectations in
this area. i
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 I
isolation lineups; and verification that notices to workers are
posted as required by 10 CFR 19.
d. Other Inspection Activities
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Inspection areas included the turbine building, diesel generator
building, ERCW pumphouse, protected area yard, control room, Unit ,
I and 2 containments, 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; l
and that appropriate actions were taken, if required. RWPs were ;
reviewed, and specific work activities were monitored to assure i
they were being accomplished per the RWPs. Selected radiation ;
protection instruments were periodically checked, and equipment l
operability and calibration frequencies were verified. t
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e. Physical Security Program Inspections
In the course of the monthly activities, the inspectors included a l
review of the licensee's physical security program. The ;
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performance of various sh:fts of the security force was observed
in the conduct of daily activities to include: protected and vital i
area access controls; searching of personnel and packages; !
escorting of visitors; badge issuance and retrieval; and patrols t
and compensatory posts. In addition, the inspectors observed i
protected area lighting, and protected and vital areas barrier ;
integrity.
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f. Licensee NRC Notifications
(1) On July 13, 1993 the licensee made a four hour notification
to the NRC as required by 10 CFR 50.72 regarding an
inadvertent closing of containment isolation valves during
tagout on a non-essential control air header. The closing
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of the valves constituted an ESF actuation. The event i
occurred while operators were establishing a clearance ;
boundary for modifications to the control air system. All !
safety systems functioned as required, with the exception ,
that the B auxiliary air compressor failed to load. The
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licensee initiated an Incidant Investigation to determine l
the root cause and develon - arrective actions for the cient.
This event is further dis u sed in paragraph 4.b. ;
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(2) On July 15, 1993 the licensee made a special report in ;
accordance with TS 3.7.11.1, Action b. due to the removal of ;
portions of the auxiliary building high pressure fire *
- protection system from service. The applicable system ;
4 piping was removed to facilitate repairs to system leakage. ;
Compensatory measures were taken to provide adequate backup .
- fire protection and monitoring during the evolutions. The !
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estimated time for the repairs was two weeks.
1 (3) On July 19, 1993 the licensee made a four hour notification !
to the NRC as required by 10 CFR 50.72 regarding a manual
ESF actuation of the B ABGTS. A Unit 2 steam generator
1 rccirculation pump motor in the auxiliary building general ,
supply fan room caught fire necessitating stopping of the i
i auxiliary building supply fans. The stopping of the supply :
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fans prompted the licensee to start the ABGTS to provide 4
ventilation to the affected areas. The motor fire was j
, contained in approximately six minutes. No other equipment
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was affected. The licensee initiated an incident
investigation to determine the cause of the motor fire. )
(4) On August 1, 1993 the licensee made a four hour notification !
to the NRC as required by *.0 CFR 50.72 regarding a condition ;
which could potentially fail to control a radiological !
release and/or mitigate the consequences of an accident. A l
potential for both of the Control Room Ventilation trains to '
have been inoperable was discovered. The licensee
discovered that the B train MCR isolation signal was
inoperable due to a lifted lead on scal-in circuitry. The B
train CRI capability was last proved operable during testing
performed on July 15, 1993. Subsequent testing of the B
train revealed that it was inoperable. At various instances
during the period July 15 through July 29, 1993, the A train
operability was affected due to work or outages on A train
components. Corrective actions for the event involved a
field design change which installed the misplaced wire and
tested the circuitry to prove operability of the B train
CRI. This event is further discussed in paragraph 4.c as an
Unresolved Item.
(5) On August 5, 1993, the licensee made a four hour l
notification to the NRC as required by 10 CFR 50.72 l
regarding the identification of a non-1E qualified control i
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circuitry on the auxiliary building general supply and l
exhaust, and fuel handling exhaust fans. The non-lE
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qualified control circuitry on the fans could result in
their failure to trip on an auxiliary building isolation i
signal. Failure to trip would not allow adequate filtering ,
and control of radiation releases from the auxiliary :
building. This condition was identified by licensing ,
engineering personnel as a result of a generic review of a !
Watts Bar CAQR. The inspectors will followup on the ,
licensee's corrective actions for this issue. )
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Within the areas inspected, no violations were identified.
4. Maintenance Inspections (62703 & 42700)
During the reporting period, the inspectors reviewed maintenance i'
activities to assure compliance with the appropriate procedures and
requirements. Inspection areas included the folicwing:
a. On July 17, the inspectors monitored activities associated with ,
leaks on the Unit I cavity seal ring air supply. The leaks were !
identified on July 14, after refueling was complete. The repairs j
were made in accordance with WR C075932 and WO 93-04454-00. The
work involved the replacement of a l\4 inch flexible tube from the 1
reactor cavity seal air supply manifold to the cavity seal. The
seal is put in place during floodup of the refueling canal and is
pressurized by air (normal) or nitrogen (backup) supplies.
The inspectors reviewed the work order package and observed the
replacement of the tube. In general, the activity was controlled
in an adequate manner. However, the inspectors observed that once
the new tube was installed, the worker stepped on the air supply !
several times during cleanup of the job site. Also, the worker l
repeatedly stepped on the cavity seal ring (with the supply air
secured) during the beginning of the activity.
After the repairs were completed, a small leak still remained at
one of the mechanical fittings. The licensee evaluated the leak
and determined that the amount of leakage was negligible and
decided that reflooding of the refueling cavity was acceptable.
The inspectors concluded that although the repairs to the supply
line did not. fully eliminate the leakage, the repairs did
substantially reduce the leakage such that the air supply pressure
to the seal could be maintained.
During the review of the completed work package after the repairs
were performed and during discussions with plant personnel -
involved in the activity, the inspectors identified the following
discrepancies: l
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The work plan indicated that the normal and backup air I
supply to the seal were isolated; however, the return of the I
backup supply was annotated as "not applicable." j
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All of the normal and backup supply valve manipulations were ,
performed without the use of second party or independent l'
verification.
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None of the _ configuration changes to the air supply valves
were annotated on Appendix A of SSP-6.24, MAINTENANCE
MANAGEMENT SYSTEM CONFIGURATION CONTROL LOG, Revision 3.
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Although the workplan required the maintenance actirity to ;
be performed with the vessel level at 702 feet (at f.'enge), l
the work was actually performed at several inches abow this ;
level. ;
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The inspectors discussed these discrepancies with licensee j
management. The most significant concern was that the normal and :
' backup supply valves were being operated, in part, by work plan i
instructions, and not part of a configuration control program or :
process. In addition, several of the above examples indicated :
that valve operations were either accomplished or not accomplished l
e at the will of the craft. The inspectors considered that the j
valves associated with maintaining the reactor cavity seal j
pressurized during core alterations should be in the licensee's i
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configuration control program. j
f The inspectors reviewed the licensee's configuration control l
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program administrative requirements. The program is_ implemented l
via SSP-12.2, SYSTEM AND EQUIPMENT STATUS CONTROL, Revision 4. l
The inspectors determined that the temporary pressurization system
for +,he reactor cavity seal was not being controlled by SSP-12.2 i
during core alterations. The inspectors concluded that adequate l
controls had not been in place for the reactor cavity air supply i
to support previously performed refueling evolutions. The- !
inspectors considered that SSP 12.2 was inadequate in that the ;
procedure did not require configuration control for valves in this ;
important to safety temporary system. Failure to provide for i
configuration controls for a temporary system important to safety j
is identified as a Violation (327, 328/93-33-01) Inadequate i
Configuration Control for a Temporary System Supporting fuel !
Handling Evolutions. l
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b. On July 13, 1993, while establishing a clearance for DCN M-9507 in !
the control air system for work involving a moisture element, both~ !
control air headers in the auxiliary building were inadvertently i
isolated. The isolation resulted in the closing of containment ;
isolation valves associated with the ice condenser and radiation -
monitor systems.
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The inspectors responded to the plant and control room when
notified of the event. They concluded that operations response '
and immediate corrective actions for the event was good. All
safety systems functioned as required, with the exception that the i
B auxiliary air compressor was reported as to have failed to load -
as required. The licensee initiated an incident investigation to
determine the root cause and develop correctivo actions for the '
event. The cause of the isolation of both the A and B air headers
was determined to be an inaccurate category I drawing which was
used to establish the clearance boundary. Specifically, drawing ,
transition flags on the control air flow diagrams mislabeled '
headers A and B on drawing 47W848-2. This drawing error was
determined to have occurred during a 1977 revision.
WR C223971 was initiated to investigate the control air compressor
B problem. The licensee identified that the B auxiliary control
air compressor actually did load; however, valve 0-FCV-32-94, '
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Dryer Purge Valve, failed open allowing air to bypass to the vent
muffler. Repair to the failed valve was initiated and completed.
Corrective actions for the drawing problem involved a walkdown of
all the drawing transition flags on the control air drawings. No
additional problems were identified. Additional walkdowns were ,
performed on other systems such as high pressure fire protection,
service air, and raw cooling water. These systems were chosen, in i
part, due to the drawing for these systems having multiple sheets
and thus more transition flags. No additional problems were
identified. The licensee concluded that other systems that were t
previously walked down during the design baseline verification '
program were acceptable without further walkdown.
Additional corrective actions for the event, according to the t
licensee, will include a functional evaluation of the drawing .
program by Nuclear Engineering. This evaluation will utilize !
questionnaires, drawing deviation searches, and other means to *
identify the potential extent of condition for other drawings.
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The inspectors reviewed the s@ ject event in regard to regulatory
significance. 10 CFR 50, Appeacix B, Criterion III, requires, in
part, that drawing changes be adequately reviewed for accuracy.
The failure to maintain the subject category I control air system ,
drawing in an accurate configuration is identified as a Violation [
(327,328/93-33-02). ;
During the licensee's review of the event, they determined that '
one recent transition discrepancy was found on the service air !
system and actions had been initiated to correct the problem prior !
to the event of July 13. This discrepancy was also on a Category i
1 drawing. In addition, a third Category 1 drawing discrepancy
was identified by the licensee on July 29. This example involved j
logic diagram 47W611-88-1. The problem was identified during an !
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unrelated work activity. Corrective actions for this problem were ,
initiated by the licensee.
c. On July 30, 1993, the inspectors observed the maintenance
activities associated with the 18-month calibration of
differential pressure switch FS-311-8 which controls the operation
of the Control Building Emergency Air Clean-Up Fan A-A. This
activity was accomplished according to procedure SI-197, Periodic
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Calibration of Control Building Heating Ventilation, and Air
Conditioning System, Rev. 2. The inspector verified that the
activity was properly coordinated through operations, ensuring t
that TS LCO 3.7.7 was entered for rendering Control Building
Emergency Air Cleanup Fan A-A inoperable during the activity.
Instrument technicians determined that the "as-found" setpoints
for the switch were within acceptable limits. The inspector
reviewed the work package, completed procedures, and test
equipment calibration data. No discrepancies were identified. l
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d. On August 1, 1993, an event was discovered regarding a condition
which could potentially have made inoperable both of the Control
Room Ventilation trains. The licensee discovered that the B train i
MCR isolation signal was inoperable due to a lifted lead on the i
seal-in circuitry. The B train CRI capability was last proved
operable during testing performed on July 15. Subsequent testing
of the B train on August I revealed that it was inoperable. At !
various instances during the period July 15 through July 29, 1993,
the A train MCR ventilation system operability was affected due to
work or outages on A train components.
wediate corrective
actions for the event involved a field design change which
properly installed the misplaced wire and performed testing to
prove operability of the B train CRI capability.
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The inspector interviewed licensee personnel involved in the event
investigation process. Preliminary information indicated that
work had been performed on B train ventilation system components
shortly before the train was di covered to be inoperable on August
1. However, by the end of the inspection period, the licensee
could not determine when the lifted seal-in lead was disconnected.
The inspectors will monitor the licensee's incident investigation ,
in this area in future inspections. The event could have
potentially made inoperable both trains of the control room
isolation capability. This issue will be identified as URI 327,
328/93-33-03, pending the completion of the licensee's incident
investigation to resolve when the B train CRI was made inoperable.
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Within the areas inspected, two violations were identified. ,
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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 surveillance:
a. On July 20, the inspectors observed the performance of a portion
of 2-SI-SXP-074-128. A, RESIDUAL HEAT REMOVAL PUMP 2A-A QUARTERLY
OPERABILITY TEST, Revision 1. The steps observed were performed
to verify check valves 2-74-555 and 2-74-515 were closed and
sealing. The inspector observed good test control and ,
communications during the conduct of the surveillance. The
inspector also reviewed the completed surveillance package after
reviews were completed by the operating crew. No deficiencies
were noted.
b. On July 20, 1993, with Unit 1 in Mode 6 and the refueling cavity
flooded, the licensee determined that a required TS surveillance
to measure boron concentration in the Unit I refueling canal had
not been performed at the required frequency. Surveillance
requirement 4.9.1.2 states that the boron concentration of the
reactor coolant system and the refueling canal shall be determined
by chemical analysis at least once per 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The licensee has
interpreted this requirement to mean that boron samples of the RCS
and refueling canal are required at least every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in MODE
6. The purpose of this requirement is to maintain and verify a
uniform boron concentration in the water having direct access to
the reactor vessel. This surveillance is normally performed by ;
the chemistry department on Monday, Wednesday and Friday.
According to the licensee, chemistry technicians contacted the :
control room on July 13,14,16 and 19 and asked if the refueling
canal was full of water. The technicians received a response that
the refueling canal was drained and concluded that a boron sample i
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was not necessary. Apparently the control room misunderstood the
technicians question and thought the question referred to the fuel
handling building transfer canal. This apparent breakdown in ,
clear communication resulted in a failure to sample the shield
building refueling canal by July 17, 1993 as required.
When cavity samples were taken the boron concentration was in ,
specification. The inspector concluded from the preliminary
information that this was an example of poor control during the
conduct of special condition surveillance. Another illustration '
of this is that the licensee identified the subject missed TS
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surveillance as a result of identifying that they had missed an '
ODCM surveillance to take tritium grab samples with the refueling '
canal flooded and the shield building exhaust in operation.
The inspectors reviewed the subject event for regulatory
significance. The failure to perform TS surveillance 4.9.1.2 is j
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identified as a Violation (327/93-33-04). In addition, the
inspectors were specifically concerned with the frequency of
missed surveillance's at Sequoyah. This was particularly evident
during the closecut of LERs in paragraph 7 of this report. This
concern was discussed with the licensee. The inspectors will r
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continue to monitor the licensee's activities in this area during
future inspections.
c. The inspectors reviewed the July 14, 1993 results of surveillance
1-SI-SFT-074-001.0, RHR Injection Flow Rate Measurement, Pump
Performance and Check Valve Test, Revision 3. One of the purposes
of this surveillance is to verify a minimum RHR pump flow rate in
accordance with TS 4.5.2.h.3. TS 4.5.2.h.3 specifies a minimum
flow rate of 3931 gpm; however,1-SI-SFT-001.0 is more ,
conservative in that it specifies a minimum flow rate of 4227 gpm.
During the test, the B RHR pump flow rate was 4100 gpm which
failed to meet the procedure's minimum acceptance criteria of 4277 i
gpm.
The B RHR pump was declared inoperable for Modes 1 through 4. ;
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During the test of the B RHR pump, RWST level was 30%. The
licensee concluded that the cause of the low B RHR pump flow rate
was due to a low HPSH attributed to low level in the RWST. At the y
end of the inspection period, the licensee was in the process of i
revising the RHR pump flow rate acceptance criteria in 1-SI-SFT- 3
001.1 to account for the effect of RWST level on pump discharge !
flow rate. The inspector considered the licensee's actions
adequate to resolve the concern.
d. During this inspection period, the inspectors reviewed recently
completed SI packages to determine if they were beiag reviewed ;
within the timeframe required by the licensee's procedures. Over ;
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the past two years, several events have occurred where, as a
result of routine engineering review of completed sis, operability ;
problems were identified. ;
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The inspectors reviewed procedure SSP-3.2, Surveillance Test !
Program, Rev.1, which controls the implementation of the
licensee's surveillance program. Section ?.5.3 of this procedure i
describes the licensee's process for reviewing completed SI ;
packages. Item 3.5.3.H requires that TS related packages be ;
returned to the SI Scheduling Group within 10 calendar days :
following completion of the surveillance. The inspectors reviewed l
a small sample of recently completed surveillance packages to
determine if this 10 day review period was being adhered to. As a
result, several examples were identified where this requirement
was not being met. Among these included the following:
Surveillance Procedure /Sub.iect Performance Review l
Date Time
SI-45.1 (service water pump J-A test) 05/07/93 16 days ;
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51-45.2 (service water pump K-A test) 05/07/93 15 days
SI-45.3 (service water pump L-B test) 05/08/93 15 days
SI-45.4 (service water pump H-B test) 05/08/93 24 days
SI-46.5 (CCS pump C-S test) 06/02/93 17 days
SI-100 (vital battery channel I test) 05/28/93 18 days
SI-100 (vital battery channel II test) 05/04/93 30 days
SI-102 (diesel generator inspections) 08/06/93 12 days
The inspectors discussed these discrepancies with the SI
Scheduling Group and learned that a process existed for tracking
TS related sis that have not been returned within 10 days. The
inspectors reviewed a current (July 29) listing of delinquent sis,
noting that the total of 45 for both units was a high number. The
licensee indicated that this number had increased significantly
since the outage began, and that the number had been as high as
60. The licensee reported that prior to the outage, the i.tsber of
delinquent sis ranged between 5 and 15, which was still considered
by the inspectors to be higher than what could be reasonably
maintained during non-outage conditions. The inspectors noted
that as part of the restart program for the current dual Unit
outage, the status of delinquent sis is one of 50 backlog items
that is being tracked and is currently receiving increased
management attention. The failure to perform SI reviews in
accordance with the timeframe specified in SSP 8.2 is identified
as a Violation. This violation will be identified as VIO 327,
328/93-33-05, Failure to Follow the Requirements of SSP-8.2 for
Timely Surveillance Instruction Reviews.
Within the areas inspected, two violations were identified.
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
effectiveness of these programs.
a. On July 23, 1993 the inspectors attended the exit meeting for a
SMOG which had been established for the purpose of providing
senior TVA management with independent assessments of the Sequoyah
Restart Program and other selected areas of interest. The initial
SMOG exit meeting was discussed in inspection report 327, 328/93-
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The SM0G concluded that several of the issues identified in their ,
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initial reviews were now being addressed by Sequoyah management.
However, the SM0G considered additional management attention was
needed in insisting that programs were proactive, thorough, well ,
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planned and formal in implementation. In addition, a lack of
individual accountability for personnel performance problems t
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a. (Closed) LER 50-327/91-01, Electrical Board Room and Main Control
Room Air Handling Unit Sequence Timers not Calibrated Within the
Required Fregrency Because of Nontechnical Specification
Classification. This issue involved the failure to test a plant
modification in accordance with TS 4.8.1.1.2.d.10 which requires
that EDG load sequence timers be calibrated every 18 months. The
plant modification involved installation of sequence timers for
the MCR and electrical board room AHUs. These sequence timers
were not calibrated in 18 month intervals after installation. The
root cause of these sequence timers not being calibrated within
the TS required frequency was the failure to recognize that the
timers were required to be calibrated by TSs. Also, the WP for
the installation of these t'; m was not expeditiously closed
which contributed to the probit ' losing the WP would have
required review of the modificat wo and identify required
surveillance procedures. As corrective action the licensee
reviewed all open WPs and made the appropriate procedural
revisions. The licensee also placed the electrical board room and
MCR air handling unit sequence timers into their SI program. The
inspectors reviewed procedures 1/2-SI-EDC-202-220.A&B, Setpoint
Verification and Calibration For Time Delay Relays Associated With
Automatic Load Sequence Timers, Revision I and verified that the
procedures contained instructions for calibrating the MCR and
electric board room AHU sequence timers. The inspectors also
reviewed the current status of open WPs and DCNs. There were
approximately 22 open WPs. Nine of the open WPs were scheduled to
be completed prior to startup of the respective unit and the
remaining dealt with security which would be closed when the
security entrance is complete. There were approximately ten open
DCNs. Seven were recently initiated and the remaining three were
approximately six to eight months old. The inspectors verified
that the three older open DCNs where either startup items or were
modifications tn non-safety related systems. The inspectors
concluded that plant modifications were being closed in a timely
manner.
b. (Closed) LER 50-327/93-06, Inadequate TS Surveillance Performance
for Four Fire Protection Valves. This issue involved a
surveillance procedure that was rewritten to incorporate the new
procedure format. During the rewrite, verification that four
containment isolation valves in the fire protection system
repositioned during the test was inadvertently omitted from the
procedure. As a result the October 7, 1991 performance of 1-SI-
OPS-82-26.A, Loss of Offsite Power With SI-D/G 1A-A Containment
Isolation Test, failed to verify that these containment isolation
valves repositioned in accordance with TSs 3.7.11.2 and 4.6.3.2.
The inspectors reviewed 1-SI-0PS-82-26. A, Revision 4 and verified
that it was revised to properly test the four valves. The
inspectors also reviewed the March 29, 1993 performance copy of 1-
SI-0PS-82-26. A, Revision 4 and verified that the four valves were
tested. As corrective action the licensee reviewed procedures
prepared or reviewed by the individuals involved with the
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The inspectors concluded that the continuing frank and honest
perception of Sequoyah's progress allowed for management to focus
on problem areas. The inspectors consider that the SMOG
assessments are a strength regarding the licensee's internal
commitment to change the way that they will do business at i
Sequoyah. ;
b. During this inspection period, selected reviews were conducted of
the licensee's on-going self-assessment programs in order to
evaluate the effectiveness of these programs. The inspectors
continued to receive weekly debriefs from the onsite nuclear ,
assurance group. The latest debriefs indicated that progress was '
being made in all program areas. In addition, the latest SMOG
review considered the nuclear assurance restart readiness reviews
to be very positive and provide sound performance indicators that
should facilitate early identification and resolution of problems.
The inspectors consider that the Nuclear Assurance Department
continues to provide good feedback to plant management on
continuing problem areas. The inspectors consider this area to be ;
a strength. '
c. On' July 22, 1993, the inspector monitored an incident
investigation meeting to determine the causes and corrective r
action for a missed TS surveillance. The lead investigator had
prepared a package of material on the event for each of the
meeting participants. During the meeting the lead investigator
covered the details of the event and assigned individuals follow-
up items. The inspector concluded that the meeting was productive -
for the participants; however, overall the meeting did not reach ,
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its full potential and did not appear to receive the priority one :
would expect for an event that has occurred previously and of this
significance. One participant was distracted by having to leave
for another meeting and there was no operations representative
present to follow that important area. The inspectors will review
the results of the licensee's investigation when the LER is issued
to assess the licensee's investigation of the event. ,
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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inadequate procedure for technical adequacy and no discrepancies
were identified. The licensee also enhanced training of ,
independent qualified reviewers to include this issue. The .
inspectors reviewed lesson plan EGT224.102, Independent Qualified ;
Review, dated July 2, 1993 and verified that the course was
enhanced. While discussing this issue with the operations ,
procedure gnup, a procedure writer identified an error in logic
drawing 1, C/-611-88-1. The drawing did not show valves26-241 -
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and 26-242 as having a phase A containment isolation signal input.
The procedure writer processed a Design Change Notice Drawing
Deviation to get the drawing revised. This drawing problem and -
other drawing issues were also discussed in paragraph 4.b of this
report.
c. (Closed) LER 50-327/93-08, EGTS Decay Cooling Valve failed to Open l
as Required During a Surveillance Requirement Test Because of
Miscalibrated Flow Switches. This issued involved an incorrect
procedure revision that resulted in a flow switch being calibrated
to the wrong setpoints. The revision was incorrect in that a
previous revision that specified the desired flow switch setpoints
was inadvertently omitted during a subsequent revision. As a
result, the two decay cooling valves in the A EGTS train would not
automatically open if the system was placed into operation. TS 3.6.1.8 requires these valves to be operable in Modes 1, 2, 3 and
4. This condition existed from April 1992 to March 1993. The
licensee evaluated the operability of the EGTS in this condition
and concluded that the design temperature would not be exceeded.
Therefore, the system was operable. As corrective action the flow
switch was recalibrated and valves tested in accordance with 0-SI-
OPS-065-136.0, EGTS Cleanup Subsystem Functional Test, Revision 0.
The inspectors reviewed the performance copy of 0-SI-0PS-065-136.0
that was performed on April 27, 1993 and verified that the EGTS
Train A decay cooling valves properly operated. Personnel that
are qualified reviewers or preparers were retrained on how to
properly incorporate procedure revisions. The inspectors reviewed
the training letter that provided this training. Also as
corrective action the licensee sampled procedures to verify that
all procedure revisions were being properly incorporated. The QA
Department performed this review and identified another example
where procedure revisions were not properly incorporated into a
procedure. As a result the procedure group sampled additional :
procedures and did not identify any similar findings. The QA
Department has scheduled a followup assessment in this area to
begin August 20, 1993.
d. (Closed) LER 327/93-10, Westinghouse Electric Corporation Error '
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Results in Nonconservative COMS Setpoints. This issue involved an
error in the development of the calculation for the COMS setpoints
and was generic to all Westinghouse plants that had COMS setpoints
generated by Westinghouse. The error resulted in COMS setpoints
that did not conform to the standards of 10 CFR 50.60, Acceptance
Criteria for fracture Prevention Measures for Lightwater Nuclear
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Power Reactors for Normal operation. In a letter dated June 5,
1993, the licensee requested and exemption from the requirements
of 10 CFR 50.60 and on June 18, 1993 this exemption was approved
by the NRC. This exemption allowed the licensee to operate with
the existing COMS setpoints. ;
Within the areas inspected, no violations were identified.
8. Action on Previous Inspection Findings (92701,92702)
a. (Closed) VIO 328/92-22-02: Failure to follow the Requirements of
SSP-12.5 and Maintenance Procedure 03027-2002. This event
involved an instrument technician failing to properly re-terminate
a wire in flow switch 2-FS-74-24 associated with the miniflow
valve for RHR pump 28-B. This miswiring occurred during
performance of maintenance procedure 03027-2002 for calibrating >
the flow switch and resulted in the malfunctioning of the RHR
miniflow valve when the pump was later operated as part of routine i
testing.
The violation involved the failure to follow both the maintenance
procedure 03027-2002 and the independent verification requirements
of procedure SSP-12.6. The licensee determined the wiring error
was caused by personnel inattention to detail, inadequate self-
checking work practices, and the failure to conduct proper second '
party verification. In addition, post-maintenance test
requirements were not accomplished to ensure the proper operation
of the miniflow valve following repairs.
The inspectors reviewed the licensee's response to the violation
and verified that the licensee's corrective actions to prevent
recurrence had been satisfactorily completed. These corrc-ctive
actions included: 1) verifying the correct flow switch wiring in
all other RHR miniflow valves, 2) briefing maintenance craftsmen,
planners, and procedure writers on this event with emphasis on the
need for adequate post-maintenance testing and independent l
verification, 3) revising the RHR miniflow valve switch i
maintenance procedures to require independent verification for >
wiring connections, and 4) training planners on the proper way to
specify acceptance criteria for verifying that components can .
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perform their intended functions.
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The inspectors noted that the commitment to revise only the l
instrument calibration procedure for the RHR flow switch to be !
limited in scope, but, during the conduct of this review, it was
found that all other instrument calibration procedures have also
been enhanced to include independent verification of lifted wires,
jumper removals, and instrument tubing connections. The
inspectors also noted that the licensee had recently revised the
verification program procedure, SSP-12.6, Equipment Status
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Verification and Checking Program, Rev. 4. This procedure was ,
effective on June 15, 1993, and resulted in fundamental changes in .
the verification process. These included: 1) deleting the 2nd f
party verification technique, 2) redefining independent .
verification as being conducted physically separate and it a !
different time from when the activity was initially performed, and
3) adding a " Concurrent Verification" technique which requires
agreement between the performer and the verifier prior to
performing a given act. The inspectors consider these chsnges to
be enhancements to the verification process and should help reduce
the occurrence of component mispositionings due to personnel ,
error. The inspectors considered the licensee's actions in
response to this violation to be satisfactory.
b. (Closed) VIO 50-327,328/93-02-01, Violation of TS 6.8.1 for .
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Failure to follow and/or Inadequate Procedures with Multiple
Examples. In a letter dated March 25, 1993 the licznsee responded
to this violation and identified the corrective actions to be ,
implemented in response to the violation. The first example of
this violation involved operators performing switching evolutions
out of sequence. As corrective action the licensee issued SSP- ,
12.8, Switchyard Switching Order Execution, dated June 1, 1993. ,
The inspectors reviewed SSP-12.18 and verified that switching !
orders were required to be accomplished in the given order. The
second example of this violation involved a system engineer and
non-licensed operator performing maintenance on Unit 2, number 3
heater drain tank level controller without a WR or procedure. As
corrective action the licensee issued memorandums dated April 9 ;
and 26, 1993 to Operations, Maintenance and Technical Support '
personnel explaining the station policy on adjustment of level
indication controllers and use of metering orifice clean-out
plugs. The inspectors reviewed the memorandums and considered the
policy acceptable. The inspectors also discussed the policy with
a licensed operator and concluded that the operator w&s
knowledgeable of the policy. The third example of this violation
involved delaying a PM for calibration of the Unit 2 6.9 KV
shutdown board delay relays without providing a technical
justification. As corrective action the station increased
sensitivity to delinquent PM by requiring the Maintenance Manager
to review the delinquent PM list on a weekly basis and the Site VP
review delinquent PMs on a monthly basis. The inspectors reviewed
the current delinquent PM backlog and concluded that technical
justifications were being provided for PMs that were delinquent.
However, the inspectors also noted that there were a large number,
approximately 242, of delinquent PMs with technical
justifications. The inspectors were informed that a large number
of scheduled PMs were postponed during the Cycle 5 RFOs.
c. (Closed) VIO 50-327,328/93-05-03, Failure to Comply With the ,
Requirements of TS 3.6.11, 3.6.1.2.c and 3.6.1.3.b. This issue
involved a loss of primary containment integrity due to an
improperly assembled flange on the Unit I upper containment outer
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airlock bulkhead. In a letter dated April 20, 1993, the licensec l
responded to this violation. The letter stated that as long term l
corrective action the SI that tests the containment personnel i
airlocks would be revised to include testing the back side of the !
subject blank flange and blind flanges, with similar application,
would be evaluated to determine whether alternate testing methods
are appropriate. The inspectors reviewed SI-159.1.2, Personnel !
Airlock Pen-X2B operability and Overall Leakage Test, Revision 3
and verified that it contained instructions to test the upper
containment outer airlock bulkhead blank flange from the back
side. The licensee's evaluation to determine if similar types of
flanges should be tested from the back side concluded that it was
not feasible. The inspectors concluded that the licensee's
corrective actions were adequate.
Within the areas inspected, no violations were identified.
9. ESF SYSTEM WALKDOWNS (71710)
During the inspection period, walkdowns were performed on portions of
the Unit 1 Reactor Coolant System (RCS), the Emergency Gas Treatment *
System (EGTS), and the Unit 1 Ice Condenser System were conducted.
Inspector findings and conclusions are discussed below.
a. EMERGENCY GAS TREATMENT SYSTEM
Areas inspected included the EGTS room, Unit 2 annulus, and the ;
main control room EGIS panel. The following material condition
deficiencies were identified in the EGTS room:
There was an air leak located upstream of the pressure
regulator to the SOV for valve 2-FCV-65-9. '
There was tape covering a small hole in the ductwork between
valves 2-FCV-65-50 and 1-FCV-65-51. ,
The patches on the flexible ductwork downstream of EGTS fan l
B-B were not fully secured. i
The following material condition deficiencies were identified in
the Unit 2 annulus: ,
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Lubricant was leaking from the actuators on Valves 2-PSV-65= l
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87 and 2-PSV-65-81.
The annulus door was not properly aligned and the top latch
was broken.
The inspectors discussed these deficiencies with the system
engineer and walked the system down a second time with the system
engineer. During this walkdown WRs were initiated for the above
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- deficiencies that had not been previously identified. Most of the !
l deficiencies were also identified by the licensee during their .
recent walkdown of the' system. None of these deficiencies
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rendered the EGTS inoperable.
Housekeeping was considered adequate in the EGTS room and poor in
the annulus. There was debris on the floor of the annulus. The
debris included broken light bulbs, broken telephone, tape and ,
paper. There was plastic tubing, rope, cable, and electrical
extension cords hanging from the railings or walls. ,
b. UNIT 1 REACTOR COOLANT SYSTEM
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l Areas inspected included portions of the Unit I lower containment,
l raceway, seal table area, and other safety-related areas.
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Housekeeping in the general areas was adequate for an outage ;
period. The following significant material condition deficiencies i
were identified:
(1) In the Ur. "vay, the inspectors identified remnants of
previous bot.- _.d leakage on the containment vessel steel
liner. The leakage was from various accumulator and/or fan
rooms above the raceway compartment. The inspectors noted
that the leakage had been accumulating behind a stainless
steel flashing barrier, approximately 5 feet tall, which
I runs the full circumference of the r.cceway attached to the !
inside of the containment liner. The leakage had been
flowing behind the flashing due to deteriorated sealant
along the top of the flashing. The inspectors were ,
concerned that the boric acid behind the flashing could 1
cause corrosion on the containment liner. Based on the
appearance of the sealant, the inspectors also concluded
that the condition existed for a long period of time.
l The inspectors identified the concern to the licensee. At
the end of the inspection period, the licensee was preparing
to remove flashing from the suspect areas to inspect the
containment liner for corrosion.
In addition to the above concern, the inspectors questioned
whether the licensee had been maintaining the design basis
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for the stainless steel flashing. Preliminary reviews
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identified that the flashing design was for post-LOCA
containment liner thermal shock considerations. The
inspectors questioned whether this design function was
dependent on a water tight seal from the flashing to the
containment liner. With questionable sealing due to the
i deteriorated sealant, the inspectors considered that the
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flashing barrier was not waterproof.
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The above issues were identified as an IFI with regard to
the inspectors identification of unevaluated boric acid
conditions on the inside of the Unit I containment vessel
steel liner and design of liner flashing (IFI 327, 328\93-
33-06).
(2) Water or similar liquid was found on raceway floor near
accumulator room number 3. The inspectors' concern was that
the liquid may have been coming from behind the stainless ,
steel flashing barrier as described in previous paragraph. >
(3) During tours of the lower containment, the inspectors
reevaluated previously identified reactor cavity liner
leakage. Specifically, significant leakage from the
refueling cavity was identified as flowing down the outside
of the vessel biological shield / support concrete wall. Most
of the leakage was being collected via plastic tarps and ;
funnels; however, some was not. Additional leakage was
identified on one of the reactor cavity drain plugs which
are installed during the outage for cavity floodup. The
liner leakage issue and potential pathways of this leakage
were previously discussed in Inspection Report 327, 328/93-
13.
Tours made by the inspectors this inspection period were
conducted with the refueling cavity at approximately 23 feet
above the vessel flange; whereas previous inspections were
performed at lower water levels. At the current level, the
liner leakage was more pronounced and estimated at
approximately 3,000 gpd by the licensee. Due to previous
concerns raised by the inspectors, increased monitoring of
the leakage quantity had been occurring; however, the
inspectors concluded that the licensee was not aggressively
monitsring current leakage paths or aware of changes in
these paths. This resulted in the inspectors identification
that safety-related components such as seismic supports,
junction boxes for both trains of control rod drive
equipment, pipe and conduit supports, etc. were being wetted
with borated water. Due to the broad area of leakage, it
was difficult for the inspectors to determine the extent of
the condition, in that, flowpaths along ventilation,
conduit, supports, and the floor of th9 containment could
have deposited the leakage in other areas.
The inspectors discussed these concerns with licensee
management. As a result, the licensee reevaluated the
priority of an existing action plan to identify the leakage
sources. The ac.tions include both wet and dry cavity
detection techniques. In addition, a preliminary evaluation
of the effect of the leakage on safety components was
initiated. The inspectors will continue to monitor the
licensee actions in this area during future inspections.
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The inspectors discussed the development of the current
situation with licensee management. Shortly after refueling
was completed, a Unit I schedule decision was made not to
install the reactor head and complete evolutions which would
include reducing the refueling cavity levels and ;
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subsequently reduce or eliminate the subject leakage. This
decision was made, in part, to allow more work resource ;
focus on Unit 2 restart issues. The inspectors concluded
that the decision not to complete Mode 6 evolutions was made i
without fully considering the excessive leakage through the i
Unit I cavity liner into lower containment. The inspectors
were soecifically concerned that safety-related components
and support equipment were being exposed to boric acid
envirtiments for an extended period of time.
A concern was identified regarding management's decision on
Unit 1 to remain flooded at refueling water levels with
known refueling cavity liner leakage while concentrating on
Unit 2 restart work. Specifically, at the flooded I
condition, leakaae through the refueling cavity liner i
resulted in NRC identification of wetting of safety-related
components in the Unit I lower containment.
) c. UNIT I LOWER ICE CONDENSER l
4 Areas inspected included the ice bays, visible portions of the ice ;
buckets, and electrical and glycol conduit / piping. In addition, :
the inspectors also reviewed the implementation of a recent q
modification to the Unit 1 ice condenser. The modification i
installed sealant to cracks which were previously identified in
the wear slab (floor) of the condenser. The following
observations and/or material condition deficiencies were
identified:
$ -
Housekeeping during modifications in progress was mixed;
- however, the inspectors considered that completed areas were
adequately addressed regarding cleanliness. The inspectors
- recognized that final inspections had not been performed.
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Several ice door blast bags were torn which could allow the
j shock absorber material to be released and possibly impact
the containment sump (post-LOCA).
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Several differences were identified regarding the
performance and as-left conditions of condenser floor
l sealing modifications between portions of the condenser. ;
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The inspectors verified that the applicable work plan for !
the modification provided the latitude for these
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modification will be reviewed during closeout of Violation
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327, 328/92-06-02, Failure to Meet the Requirements of TS l
3.6.5.3 for Ice Condenser Door Operability.
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During discussions with Modifications personnel, the
inspector was informed that several of the ice doors had a
potential interference fit with the door frame as a result
of the above modifications. The inspector noted that
testing (door pull test) was scheduled to be performed which
would identify any potential operability problem in this
area prior to unit restart. The licensee was informed of
this potential problem at the exit interview.
Within the areas inspected, no violations were identified.
10. 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 Reports 327, 328/93-16 and 327, 328/93-23.
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
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, CAQR corrective actions, DCNs,
Major Issues List items, obsolete equipment items, and other open
issues. The inspectors verified that items recommended by the BRC
as restart items were listed on the most current Restart Evalu-
ation for Sequoyah Nuclear Plant printout or were scheduled to be :
presented to the MRRC. Items identified as non restart items were l
reviewed and discussed as necessary with the accountable system
engineer to ensure that adequate justification existed to defer l
until post restart. In addition, portions of the associated i
sections of the FSAR, TSs, and Sequoyah's Restart Plan were also
evaluated.
The systems reviewed during this inspection period are identified
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below:
System 43 -
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Sampling
System 55 -
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System 61 -
Ice Condenser
System 92 -
Nuclear Instrumentation
System 234 - Heat Tracing
The results of this period's review of the licensee's backlog
evaluation process indicated that, in general the process was
acceptable. However, the inspectors identified several
deficiencies in the licensee's review process. As part of the
backlog review process, the System Engineer, Department Manager,
BRC, and MRRC, review the backlog item against the restart
evaluation criteria and concur on the item being restart or post ,
restart. (MRRC only reviews backlog items considered to be
restart items.) A number of the Backlog Review Item Forms were
identified by the inspector as deficient in the following ways: ;
. Missing signatures from either the System Engineer or
Department Manager.
- No restart evaluation criteria xmpleted on the form during ~
the review process.
~ Restart criteria checked-off as applicable while 1
concurrently the backlog item being checked-off as having no
restart criteria applicable.
In addition, during review of a modification package provided by e
the licensee on one of the backlog items, the inspector identified ;
missing signatures by the Nuclear Engineering Coordinator on the i
transmittal forms of primary drawings for Work Package 1516-02,
SQN AI-19 Form, Part VI Revision 10, Attachment 18.
At the time of the inspection, the missing signatures and
uncompleted restart backlog item evaluations identified by the
inspector were forwarded to the system engineer and site licensing
to be addressed. The inspectors considered these discrepancies as
an example of a lack of attention to detail.
Based on these reviews, the inspectors concluded that the backlog
review process, although not totally without error, was considered
adequate to accomplish its objective. In addition, the system ,
engineers for the systems reviewed were generally knowledgeable of
their systems functions. The engineers were cognizant of the
associated restart and post restart work scheduled on their
systems, with some exceptions as discussed in following
paragraphs.
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b. System Walkdowns (71707)
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The results of the inspectors system walkdowns were as follows:
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System 43 - Sampling
Several minor issues were identified on the sampling system to the
systems engineer and chemistry laboratory supervisor during the
wal kdown. The issues identified included: abandoned pressure,
temperature and flow equipment not tagged in the plant, pressure
gauges not properly maintained, tools (e.g. vice grips,
screwdriver, open end wrench and crescent wrench) were left inside
contaminated cabinets on small tubing, and water spillage on the
work bench at the liquid sampling panel, in a clean area, was
noted by the inspector two consecutive days during the system
wal kdowns. At the end of the inspection period, the licensee
indicated that the issues identified by the inspector would be
addressed appropriately. '
Sequoyah has a plant modification and design change control
program in place, SSP 9.3, Revision 6, that addresses abandoning
equipment. However, SSP 9.3 does not address older equipment
abandoned previous to the program being implemented. Sampling
system equipment that was abandoned in 1982 has not been tagged in
the plant. The systems engineer was aware of this discrepancy,
but the issue had not been resolved. Chemistry laboratory
technicians, users of the system, are not aware of equipment out
of service.
Upon further discussions with the system engineer and operations
personnel, the licensee was aware of other systems that have old
equipment abandoned in place and are currently not tagged in
accordance with their plant modification program SSP-9.3. :
There was currently no mechanism in place to review old equipment
taken out of service to place it in the current abandonment
program. These concerns were brought up to the licensea at the
exit briefing. In response to the discussions, the licensee plans
to review all equipment abandoned in place and develop a complete '
listing of abandoned equipment for both units in accordance with
SSP-9.3.
During walkdowns and discussions with the systems engineer and
chemistry laboratory supervisors, the inspector was made aware
that the sampling system was functioning, but not as designed.
Compensatory measures (i.e. grab sampling) were being implemented
to ensure that sampling requirements were being met. Proper
analysis and trending of data could not be performed by the
technicians when their time was spent manually collecting grab
samples from the system. Instrument availability was identified
as a concern. Fifty percent of the sampling system instruments
were routinely inoperable, and as high as 80% at any one time.
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Numerous work requests had been written by the licensee to upgrade
the operation of the sampling system. At the time of this ,
inspection, the field work required to improve the operation and t
performance of the sampling system had begun. The inspectors
concluded that this system had not received adequate attention
during previous operation. *
System 55 - Annunciators i
The inspectors reviewed the system engineer's notebook for the
annunciator system. With the system engineer, the inspectors
reviewed the status of all items identified in the notebook. For
those items identified as non-restart the inspectors interviewed
the system engineer and other necessary tech support personnel to
understand the logic used to categorize the item as a non-restart
item. The inspectors concluded from these reviews that the
licensee had appropriately categorized backlog for the annunciator
system. The inspectors also concluded that the items identified
as post-restart had an appropriate justification to delay repairs.
The inspectors also performed a partial system walkdown. This
included an inspection of the interiors of approximately 8
cabinets containing the annunciator hardware, as well as, the
inside of two control room panels. The inspectors also witnessed
diagnostic tests performed by the system engineer on the
annunciator system.
During the walkdown, the inspectors noted minor material
deficiencies in the cabinets inspected. These included items such '
as tie wraps clippings, a wire remnant, and a disconnected clamp
for a sound powered phone conduit. The inspectors were' advised
that some of the cabinets in which the debris was found had been ;
the subject of recent modification work and that the final
closecuts of the cabinets were not complete. These items were
identified to the system engineer for resolution. The inspectors
also noted sunflower seeds in the bottom of two annunciator
cabinets. This was identified to licensee management during the
weekly debrief on July 16, 1993. Prior to their departure from
the site, the inspectors were adviced by the system engineer that
WRs had been written to address these observations. The
inspectors concluded that none of the identified represented a :
restart item. No other items were identified during the walkdown.
Overall, the inspectors concluded that the review of the
annunciator system backlog had appropriately categorized the
backlog work. Further, the inspectors did not note any new ;
material deficiencies that impacted the annunciator system
readiness for restart.
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System 61 - Ice Condenser
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The inspectors reviewed the system engineer's notebook for the ice
condenser system. The inspectors discussed with system ;
engineering personnel the status of items identified in the
notebook. For items identified as non-restart which did not have '
a clear justification, the inspectors interviewed technical
support personnel to ascertain the rationalization used to
categorize the item as a non-restart item. The inspectors
concluded from these reviews that the licensee had appropriately ,
categorized backlog for the ice condenser system. The inspectors '
also concluded that the items identified as post-restart had
appropriate jrstification for not incorporating the item into the
restart work. The inspectors also noted that the system engineer '
was reviewing the aggregate affect of all the ice condenser system
WRs on system performance. ;
The inspector also performed partial system walkdowns in the Unit i
1 ice condenser and on associated equipment for both unit's
condensers. The results of this walkdown were previously
identified in paragraph 9.c.
System 92 - Nuclear Instrumentation
The inspector did not identify any discrepancies on the nuclear
instrumentation system. A concern was raised to the system
engineer on the cleaning of the NIS instruments. A preventive
maintenance (PM) procedure was written to require cleaning of the
NIS equipment on a routine basis. Over the last several years
that PM was eliminated. The inspector raised a concern on how the
licensee would clean the NIS instruments and what would ensure
that the equipment would not short circuit because of accumulated '
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dirt and dust. As a result of the concern identified, the
licensee is reconsidering implementing the cleaning PM for the NIS
instruments.
System 234 - Heat Tracing
The inspectors reviewed the status of all items identified in the l
system engineer's notebook. For each item, the inspectors
examined the logic used to categorize items as restart or non- ;
restart. Special emphasis was placed by the inspectors on :
understanding the suitability of delaying repairs for those items !
classified as non-restart. Finally, the inspectors performed a i
partial walkdown of the system. The results and conclusions of
this inspection are discussed below:
Heat Trace Stripchart Recorders
During the system walkdown, the inspectors observed the !
performance of the stripchart recorders installed to monitor heat ;
trace equipped piping. Of the 8 recorders surveyed by the l
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inspectors, 7 had performance or material problems that rendered
the stripchart recorders potentially inoperable. Five of the
stripchart recorders that were potentially inoperable monitored
some TS related circuits. Four of these stripcharts had active,
high priority WRs but none were coded as restart items. (The ,
inspectors were informed that the remaining stripchart recorder
was to be repaired under a PM.)
The inspectors reviewed a listing of previous WRs associated with
the heat trace stripchart recorders. This listing indicated
previous problems similar to those observed by the inspectors as ,
well as repetitive failures.
The inspectors discussed the issue of degraded stripchart
performance with the system engineer and licensee management. The
inspectors were presented with similar arguments from several
licensee personnel to minimize the significance of the stripchart
recorders. The arguments are summarized as follows: 1) the flow
path from the boric acid tanks is not routinely designated as one
of the TS required boron injection flowpath(s) (hence, monitoring '
its temperature on a constant basis is of reduced consequence); 2)
the stripchart recorders are nbsolete and difficult to maintain;
3) the weekly TS required surveillance can be accomplished by the
use of measuring and test equipment; 4) the stripchart recorders
will be replaced during the U2C6 outage coincident with the
licensee's implementation of a reduction in boric acid
concentration; and 5) when the boric acid concentration is
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reduced, the heat tracing will be abandoned and the need to
monitor CVCS piping temperatures to prevent crystallization will
be eliminated.
The inspectors concluded that the licensee has and continues to
accept degraded performance from its heat trace stripchart
recorders. While the ISs do not require the stripchart recorders,
they are the devices used to ensure proper daily performance of a
safety-related system. If a need arises to rely on the BA system
for a TS boration flowpath, the ability to monitor and trend
temperatures of heat traced piping will be severely hampered. The
licensee's willingness to accept this degraded performance is a
weakness.
Disabled Centrol Room Annunciators
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The inspectors reviewed the status of the control room
annunciators associated with the boric acid heat trace system.
Annunciators 1-XA-55-60-21 and 1-XA-55-6C-28, SI/CVC Trouble
System A Heat Trace and SI/CVC Trouble System B Heat Trace,
respective.y, were provided in the control room to alarm on
abnormal heat trace performance. This alarm feature is discussed
Section 6.3.2.2 of the FSAR. Both alarms were disabled on March
6, 1992 in accordance with Sequoyah Nuclear Plant Periodic ;
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Instruction 0-PI-0PS-301-001.0, Annunciator Alarm and/or P-250
Computer Point Disablement. ;
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The inspectors independently reviewed the safety l
Assessment / Evaluation performed in accordance with site Standard !
Practice, SSP-12.13,10 CFR 50.59 Evaluations of- Changes, Tests, i
And Experiments, to support the annunciator disablements. While j
the inspectors agreed with the conclusions of the Safety i
Assessment / Evaluation, the inspectors did note two minor errors. ;
First, Safety Assessment Item C stated that the heat trace system '
is not required by Tech Specs. Section 3/4 1.2 of the TS Basis
states that associated heat tracing systems are required
components for the boron injection system. Thus, the statement in
- the safety assessment is technically incorrect. This error was ,
not noted in the reviews of the safety assessment. However, this
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point was not central to the conclusions arrived at in the
evaluation. Furthermore, the discussion in the safety evaluation !
correctly categorized the need for heat trace. Second, Appendix ,
C, Safety Assessment / Evaluation Cover Sheet QA Record for the {
evaluation, incorrectly states that FSAR change is not required as :
a result of the analyzed disablements. These errors were
identified to the licensee. l
The inspectors noted on July 15, 1993, that the annunciator i
windows were not annotated to reflect the fact that the alarms ;
were disabled. Step 6.4 [6] of Stquoyah Nuclear Plant Periodic !
Instruction, 0-PI-0PS-301-001.0, Annunciator Alarm and/or P-250 .
Computer Point Disablement requires that a blue dot be attached to !
the annunciator window when it is disabled. No blue dots were
affixed to the disabled annunciator windows. However, the
disabled annunciators were appropriately annotated in the 1
Disabled / Nonfunctional Annunciator Sequential Log and the points ;
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were properly listed in the computer generated Disable Report. '
Therefore, the failure to place blue dots on the disabled
annunciator has minimal safety significance. ,
On July 21, 1993, the inspectors observed blue dots affixed to the l
disabled annunciators. The licensee also discussed with the !
inspector a proposed change to 0-PI-0PS-301-001.0 to reduce the ,
potential for errors when disabling annunciators in the future. .
The failure to properly mark a disabled annunciator is identified !
as a Violation (NCV 327/93-33-07), Failure to Properly Annotate ,
Disabled Control Room Annunciators. This violation will not be j
subject to enforcement action because the licensee's effort in :
identifying and correcting the violation meet the criteria j
specified in Section VII.B of the Enforcement Policy. j
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Inoperabla Unit 1 Emergency Boration Flowpath
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Heat trace circuits 61 P/S were originally provided to maintain
the temperature of a significant portion of the boric acid- !
flowpath to Unit I above the 145" F minimum of TS 4.1.2.1. and
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4.1.2.2.. Specifically, the circuit was originally installed
between the filter bypass line and the emergency boration line.
Hence, the circuit provided heat trace protection for the Unit I
emergency boration flowpath.
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The inspectors reviewed documentation that indicated the licensee
had experienced problems with the performance of this circuit
prior to 1992. However, repair efforts had failed to affect a
long term solution to the problem. In January 1992, a portion of
the CVCS piping in the vicinity of the emergency boration line
connection dropped in temperature. The resultant boric acid
precipitation caused a blockage in the emergency boration
flowpath. The emergency boration flowpath was subsequently
declared inoperable. The licensee's corrective actions included
clearing the blockage, installing temporary heat trace on a
portion of the emergency boration flowpath, and implementing a
TACF to resolve circuit 61 performance.
The temporary heat trace was installed on the last 6 - 8 feet of
piping in the BA flowpath just upstream of the emergency boration
line connec+'on. This 120v heat trace was powered from a plug in
a wall outlet. The installation of this heat trace was
accomplished by WR C125530. This installation resulted in a
change to the design of the heat trace circuit as described in
Section 6.3.2.2 of the FSAR. Specifically, the FSAR requires 100
percent redundant and separate heat tracing each supplied from a
separate bus capable of being connected to the redundant emergency
diesel generators.
Criterion III, Design Control of Appendix B to 10 CFR 50 requires
that design changes be subject to design control measures. Site
Standard Practice, SSP-6.1, Conduct of Maintenance, requires that
deviations from design configuration be accomplished in accordance
with AI-19 (Part VI) Modifications: Permanent Design Change
Control Program or SSP-12.4 Temporary Alterations Control Form.
Despite these requirements, the design of the heat trace circuitry
on the Ur.it 1 emergency boration flowpath was modified by a work
request on January 25, 1992. Failure to implement the design
control proce;s for modification of heat trace circuitry on CVCS
is identified as a violation (327, 328/VIO 93-33-08), Design
Change To Heat Trace Circuitry For Unit 1 Emergency Boration
Flowpath Outside Of Plant Procedures.
Temporary Alteration, TACF 0-92-0005-234 was started to
reconfigure circuits 61 P/S. The TACF divided the existing
circuit into two separate circuits. The terminal 200 feet of the .
original 61 P/S circuits was designated as 115 P/S. These new
circuits were powered through temporary cables from spare circuits
in the SIS heat trace panels. The first 60 feet of the original
circuits 61 P/S remained powered from the original power supply
and retained the original circuit designations of 61 P/S.
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Following the circuit reconfiguration, the licensee determined
that circuits 115 P/S would still not maintain satisfactory
temperatures in the CVCS piping. Therefore, the temporary heat ,
trace powered from the wall outlet was left installed and the Unit '
I emergency boration flowpath remained inoperable. It was
recognized by the licensee that additional efforts would be
required to ensure adequate heat trace circuits 115 P/S
performance. However, the TACF was not completed and no MOD /TACF
was accomplished to restore the system. ,
Throughout the inspection effort, the licensee asserted that
despite the technical inoperability of the Unit 1 emergency
boration flowpath, the flowpath remained functional. The !
inspectors independently reviewed a Boration Flow Path
Verification Test performed in accordance with 0-SI-0PS-000-009.R
on March 19, 1993, that indicated satisfactory Unit 1 emergency
boration flows. Thus, the inspectors agreed that boric acid could ;
be injected into Unit I along this flowpath.
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In summary, at the time of the inspector's walkdown of the boric
acid heat trace system during the week of July 12, 1993 the Unit 1
boric acid flowpath was inoperable, but available; circuits lib .
P/S were powered from temporary cables; and temporary heat trace
powered from a wall outlet was installed in the emergency boration
flowpath. This configuration had existed for approximately 18
months.
The inspectors also noted that the restoration of the Unit 1
emergency flowpath was not classified as a restart issue. The
inspectors reviewed documentation that indicated that contrary to
the system engineer's recommendation the item was categorized by
the BRC and MRRC as a non-restart issue.
Based on discussions with various licensee personnel, the
inspectors concluded that the licensee's decision not to restore
the Unit 1 emergency boratioa flowpath for the previous 18 months
or prior to restart was based on the following: the TS
requirements for boration flowpaths could be satisfied with
flowpaths from the RWST, and a modification to implement reduced
boric acid concentration, currently scheduled for the U2C6 outage
would eliminate the need for this heat tracing.
During the inspection period, the licensee decided to implement a .
modification to restore proper performance and configuration of
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heat trace circuits 115 P/S. This modification will also remove ;
the temporary heat trace. The inspectors were informed that this i
modification would be accomplished prior to U1 restart. Further, ,
the licensee has committed to have the MRRC revisit all '
outstanding heat trace issues.
Overall, the inspectors determined that the backlog review process ,
for the heat trace system had failed to appropriately categorize :
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all issues. Based on arguments presented by several licensee
personnel, the' inspectors concluded that this failure was due to a
willingness by the licensee to accept degraded performance from
the heat trace system,
c. FSAR Review: (71707) !
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The inspector compared the current FSAR to the existing system i
configurations installed at Sequoyah Units 1 & 2. The inspectors i
identified that the licensee currently does not meet the license !'
commitment of.FSAR Section 7.7.1.3.1, " Monitoring Functions
Provided by the Nuclear Instrumentation System," for power range i
channels. .The power range channel recorders installed in the !
control rooms of units 1 and 2 are not, and have not, been
functioning since early 1991. At the time of the inspection, the i
licensee was not able to exactly determine when the recorders were ;
considered inoperable. Power range channels recorders monitor ;
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power distribution in the core within specified safe limits. The :
recorders are used to measure reactor power level, axial- power !
imbalance, and radial power imbalance. The power channels, as ;
delineated in the FSAR, are to be capable of recording overpower
excursions up to 200 percent of full power. Sequoyah currently i
has that capability through the Intermediate Range recorders. ,
Based on this information, the inspectors concluded that the lack !
of operable power range channel recorders was a Deviation from j
what was described in the FSAR. ;
In evaluating the FSAR for the Sampling System, the inspector :
identified a number of discrepancies between FSAR Section 9.3.2.2, t
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" System Description," and the existing system configuration
installed in the plant. Most notably were various system :
components either abandoned, incorrect system function or type- .
component described in the FSAR for the sampling system. The !
following examples illustrate the type of discrepancies identified :
in the FSAR: !
- Not all sample lines originating within containment have
air-operated valves installed. Work Package, WP-1515 and i
WP-1516, were completed in 1990 to install solenoid operated i
valves in the steam generator blowdown sampling system.
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- No portable sample analyzer equipment .s available to j
measure boron concentration in the reactor coolant system as '
described in the FSAR. ,
- Boron concentration monitors are abandoned in place, but l
their function is described in the FSAR.
- Hot sample room primary samples are not analyzed for pH.
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. Automatic analyzers and/or recorders do not analyze silica
or sodium. The equipment associated with these variables
are abandoned or out of service. ,
FSAR discrepancies in Table 9.3.2-1, Sheets 1 - 10, describe
equipment abandoned or out of service by the licensee;
- Specific components of the ccudensate demineralizer, System I
062, are abandoned or out of iervice.
- Specific components of the Waste and Auxiliary Waste "
Evaporator systems are abandoned or out of service.
- Specific components of the Waste Treatment, System 028, are
abandoned or out of service.
Revisions 6 and 8 to Table 9.3.2-1, were issued by the licensee,
on equipment which are abandoned or not in service. In addition,
sampling points currently being used by the chemistry laboratory
technicians are absent from the itemized list in the table.
Based on this review the inspector has concluded that the
licensee's current FSAR deviates from license commitments
describing the function and type of equipment in service at t
Sequoyah. The systems affected were the NIS and Sampling systems.
The identified FSAR discrepancies will be identified as a
Deviation from the FSAR (327, 328/93-33-09). ,
d. Plant Operations (71707) ,
During this period, reviews continued in the operations department +
area in accordance with the NRC restart issues plan. The
inspectors specifically focused on corrective actions for past
regulatory issues relating to conduct of operations and
configuration controls. Regulatory issues closecut is addressed
in paragraph 8.
The inspectors also reviewed the following specific items:
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The inspectors continued to hold weekly meetings with
operations management to discuss progress being made in thre
area of operator preparation for return of Unit 2 to
operation. Conduct of operation and configuration control
areas were specifically reviewed.
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The inspectors continued to monitor the operations
department standdown meetings which were held during this
period. Plant tours and control room observations allowed
for a determination that operator attention to detail and
accountability for actions were improving. l
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Detailed reviews on Nuclear Assurance observations in the
operations areas were reviewed.
Based on the issues addressed in this report, the inspectors
consider that sensitivity to the way business is being
accomplished at Sequoyah needs further management attention. ,
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In the areas inspected, one violation, one non-cited violation, and one
deviation were identified. ,
11. Exit Interview
The inspection scope and results were summarized on August 9,1993 with
those individuals identified by an asterisk in paragraph I above. The ;
inspectors described the areas inspected and discussed in detail the -
inspection findings listed below. Proprietary information is not
contained in this report. Dissenting comments were not received from
the licensee.
Item Number Descrintion and Reference
VIO 327, 328/93-33-01 Inadequate Configuration Control for
a Temporary System Supporting Fuel
Handling Evolutions (paragraph 4.a).
VIO 327, 328/93-33-02 10 CFR 50, Appendix B, Criterion III
violation for failure to maintain
the subject category I control air
system drawing in an accurate
configuration (paragraph 4.b).
URI 327, 328/93-33-03 Unresolved Item pending the
completion of the licensee's
incident investigation to resolve
when the B train CRI was made
inoperable (paragraph 4.c).
VIO 327, 328/93-33-04 Failure to perform TS surveillance
4.9.1.2 concerning refueling cavity
boron concentrations (paragraph
5.b).
VIO 327, 323/93-33-05 Failure to follow the Requirements
of SSP-8.2 for Timely Surveillance
Instruction Reviews (paragraph 5.d).
IFI 327, 328/93-33-06 NRC identification of unevaluated
boric acid conditions on the inside
of the Unit I containment vessel
steel liner and the design of liner
flashing (aaragraph 9.b).
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NCV 327/93-33-07 Failure to Properly Annotate )
Disabled Control Room Annunciators !
(paragraph 10.b). l
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VIO 327/93-33-08 Design Change To Heat Trace
Circuitry For Unit 1 Emergency
Boration Flowpath Outside Of Plant :
Procedures (paragraph 10.b). :
DEV 327, 328/93-33-09 Deviations from the licensee's
current FSAR and plant
configuration affecting the Nuclear
Instrumentation and Sampling systems
(paragraph 10.c).
Strengths and weaknesses summarized in the results paragraph were
discussed in detail.
Licensee management was informed of the items closed in paragraphs 7
and 8.
12. List of Acronyms and Initialisms
,
ABGTS - Auxiliary Building Gas Treatment System
AHU -
Air Handling Unit !
AI -
Administrative Instruction
BRC -
Backlog Review Committee '
CAQR - Condition Adverse to Quality Report
CCS -
Component Cooling Water System
CDS -
Configuration Determination Sheet
CFR -
Code of Federal Regulations i
COMS - Cold Over Pressure Mitigation System
CRI -
Control Room Isolation
CVCS - Chemical Volume Control System
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DCN -
Design Change Notice
DRP -
Division of Reactor Projects
EDG -
EGTS - Emergency Gas Treatment System
ERCW - Essential Raw Cooling Water
ESF -
Engineered Safety Feature
FCV -
Flow Control Valve
FME -
FSAR - Final Safety Analysis Report ,
GPD -
Gallons per Day
GPM -
Gallons per Minute
IFI -
Inspector Follow-Up
KV -
Kilovolt
LC0 -
Limiting Condition for Operation [
LER -
Licensee Event Report
LOCA - Loss of Coolant Accident
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MCR -
Control Room
NCV -
Non-cited Violation
MRRC - Management. Restart Review Committee
NIS - Nuclear Instrumentation System
NPSH - Net Positive Suction Head
NRC -
Nuclear Regulatory Commission
NRR - Nuclear Reactor Regulation
ODCM -
Offsite Dose Calculation Manual
OPS -
Operations
PMs -
Preventative Maintenance
PMT -
Post-maintenance Test
QA -
Quality Assurance
RCS - Reactor Coolant Sy, tem
RF0 -
Refueling Outage
RHR -
RII -
NRC Region II
RWP -
Radiation Work Permit
RWST - Refueling Water Storage Tank
SI -
Surveillance Instruction
SMOG - Senior Management Oversight Group
50 -
System Operations
501 -
System Operating Instruction
SOS -
Shift Operating Supervisor -
S0V -
Solenoid Operated Valve
SQN -
Sequoyah
SR0 -
Senior Reactor Operator
SSP -
Site Standard Practice
TACF - Temporary Alteration Control Form
TS -
Technical Specifications
URI -
Unresolved Item
VIO -
Violation
VLV -
Valve
WO -
Work Order
WPs -
Work Plans
WR -
Work Request
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