IR 05000327/1993042
ML20059L098 | |
Person / Time | |
---|---|
Site: | Sequoyah ![]() |
Issue date: | 11/09/1993 |
From: | Holland W, Kellogg P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
To: | |
Shared Package | |
ML20059L077 | List: |
References | |
50-327-93-42, 50-328-93-42, NUDOCS 9311160299 | |
Download: ML20059L098 (70) | |
Text
I
./po cr c%+,t UNITED STATES NUCLEAR REGULATORY COMMISSION p*
-
REGION 11
'3 g
101 MARIETTA STREET, N.W., SUITE 2900 -
7,, g
- j ATLANTA, GEORGIA 303ZM199
%
b... #a, Report Nos.:
50-327/93-42 and 50-328/93-42 Licensee:
Tennessee Valley Authority 6N 38A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Docket Nos.:
50-327 and 50-328 License Nos.:
DPR-77 and DPR-79 Facility Name:
Sequoyah Units 1 and 2 Inspection Conducted:
S ember 4 through October 10, 1993 Lead Inspector:
/
f-f,
// 9 1 3 W.
Hg1Thna vn i-Jesdien hspector Dat4 Signed Inspectors:
S. M. Shaeffer, Resident Inspector A. R. Long, Reactor Inspector J. L. Shackelford, Reactor Engineer G. A. Schnebli, Resident Inspector S. E. Sparks, Project Engineer J. T. Munday, Resident Inspector M. T. Widmann, Reactor. Engineer C. R. Ogle, Resident Inspector Approved by:
' /
/
.
Paiil i
Jrpftion 4A Datt Sfgned
'
.
Divi.
or rojects SUMMARY Scope:
Routine resident inspections were conducted on site in the areas of plant'
operations, plant maintenance, plant surveillance, evaluation of licensee self-assessment capability, licensee event report closeout, and followup on previous inspection findings. During the performance of this inspection, the resident inspectors conducted several reviews of the licensee's backshift or.
weekend operations.
In addition, inspectors commenced 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> monitoring of:
Unit 2 restart activities on October 1,1993.
These 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> monitoring activit.ies continued for the remainder of the inspection period.
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 submittal of the Sequoyah Restart Plan to the NRC.
~'
9311160299 931109 PDR ADDCK 05000327 G
r l
._
E
1L Results:
l In the area of Operations, a continuing weakness was noted regarding assistant
,
i unit operators being inattentive (apparently asleep) on duty (paragraph 3.a).
In the area of Plant Support, degradation of the Fire Protection System was
noted to be a cor,tinuing problem. Tnis is an example of a poor plant material condition area.. The licensee was aware of this system's condition and is
,
planning for system repair / modification in future years.
(paragraph 3.f(3)),
In the area of Maintenance, a violation was identified for failure to follow l
the requirements of Site Standard Procedure 12.3 during performance of i
maintenance activities on the IB 6.9 KV Unit board (paragraph 4.b)
In the area of Engineering, an unresolved item was identified regarding past
maintenance and design aspects concerning containment sump operability
(paragraph 4.c).
l In the area of Maintenance, containment lower compartment coolers were identified as components with continuing cooler leakage problems.
The i
'
I licensee was aware of the components' conditions and was planning for
>
l corrective actions in the fdure (paragraph 4.e).
l In the area of Maintenance, a violation was identified for failure to control l
post maintenance testing activities in accordance with administrative procedure requirements (paragraph 5).
In the area of Engineering, a review of the current Nuclear Experience Review program provided reasonable assurance that incoming generic issues would be i
appropriately dispositioned. However, some deficiencies were noted indicating
l that additional management attention to this area was warranted (paragraph 6.a
.
l and an additional example in 4.c.5).
L!
In the area of Engineering, a weakness was identified regarding several examples where the Management Restart Review Committee (MRRC) was not
,
<
.
presented with an adequate explanation or engineering basis for restart decisions to be made by the MRRC.
Examples -included evaluations and
,
I corrective actions for existing discrepancies on Unit 2 main. steam piping
-
'
structural supports and evaluations for ice condenser basket structural
integrity.
In addition, a weakness regarding licensee initial evaluation and documentation of engineering evaluations for PER corrective actions for
restart was identified. (paragraphs 6.b and 6.c).
'
i L
In the area of Engineering, a weakness was identified regarding the logging I
'
and inventories of foreign material in each units' reactor coolant system.
The total foreign material inventories and safety justifications were not being monitored via one program / owner or implemented by an organized method i
(paragraph 8.1).
l l
I J
,
,
?-<
I
]
,
In the area of Maintenance, a weakness was-identified regarding the-lack of a
_ periodic corrosion inspection of the containment liner behind installed -
.,
stainless steel flashing and a failure of the licensee to identify the
potential for the degraded condition (paragraph 8.m).
In the areas of Operations, Maintenance, and Engineering, the: licensee ~has
,
made good progress in the implementation of their restart plan and has outlined a general post restart plan which forms a basis for better planning a
in the future. Management should closely monitor implementation of future post restart activities and assure that backlogs are reduced'to or below I
established goals (paragraph 9.a).
In the area of Operations, specific inspection observations of control room-
!
.
t operator performance noted an increased safety sensitivity.and better attention to detail when compared to past startups (paragraph 9.b).
l
.i r
P
,
!
'
I
,
i u..
T g
REPORT DETAILS 1.
Persons Contacted Licensee Employees
- R. Fenech, Site Vice President
- K. Powers, Plant Manager
- J Baumstark, Operations Manager L. Bryant, Maintenance Manager M. Burzynski, Nuclear Engineering Manager
- D. Driscoll, Site Quality Assurance Manager
<
- T. Flippo, Site Support Manager
- C. Kent, Chemistry and Radiological Control Manager D. Lundy, Technical Support Manager R. Rausch, Site Planning and Scheduling Manager
- R. Shell, Site Licensing Manager
- M. Skarzinski, Technical Performance and Programs Manager J. Smith, Regulatory Licensing Manager J. Symonds, Acting Modifications Manager-
- R. Thompson, Compliance Licensing Manager
- P. Trudel, Design Engineering Manager
- J. Ward, Engineering and Modifications Manager
- N. Welch, Operations Superintendent NRC Employees R. Crlenj k, Chuf, DRP Branch 4
- P. Kellogg, Chid, 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 October 1,1993, the NRC Restart Panel met with licensee management on site in a public meeting to discuss restart activities. The licensee presented the status of restart activities to date.
NRC management and-
'
staff members in attendance included:
'
-
S. Ebneter, Region II Administrator
!
-
G. Lanias, Assistant-Director for Region-II Reactors, NRR
-
E. Herschoff, Director,=DRP, Ril
-
A. Gibson, Director, DRS, RII (NRC Restart Panel Chairman)
-
F. Hebdon, Project Director, NRR (NRC Restart Panel Member)
'
-
R. Crlenjak, Chief, Branch 4, DRP, RII (NRC Restart Panel;Nember)
-
P. Kellogg, Chief, Section 4A, DRP, Rll
l
<
,
.
$
!
i
'
2.
Plant Status
Unit 1 began the inspection period in day 151 the Cycle 6 refueling outage in MODE 5 (RCS sweeps and vents in progress). At the-end of the
.;
inspection period Unit I remained in MODE 5 with efforts continuing to
correct restart items.
!
Unit 2 began the inspection period in MODE 5 (Day 188 of a forced outage).
During the period restart activities were completed in accordance with the licensee's restart plan and forced outage schedule.
Unit 2 completed restart maintenance actions and was making preparations
for heatup (entry into MODE 4) in accordance with procedures when the
inspection period ended.
3.
Operational Safety Verification (71707)
a.
Daily Inspections r
The inspectors conducted daily inspections in the'following areas:
control room staffing, access, and operator behavior; operator
'
adherence to approved procedures, TS, and LCOs; examination of I
panels containing instrumentation and other reactor protection system elements to determine that required channels are operable;
and review of control room operator logs, operating orders, plant deviation reports, tagout logs, temporary modification logs, and
.
tags on components to verify compliance with approved procedures.
The inspectors also routinely accompanied plant management on j
plant tours and observed the effectiveness of management's
influence on activities being performed by plant personnel.
'
Approximately 5:00 a.m. on October 10, 1993, the inspector j
observed two individuals in positions that demonstrated an
inattention to duty (apparently asleep) while seated in the alcove adjacent to the Unit 2 containment spray pump rooms. One of the-individuals was seated in. a chair, slumped forward with his head down. The other individual was sitting on the floor with his knees drawn up and head down.
The inspector approached to within one foot of the individual in the chair with no response on the part of that individual. The inspector touched and then gently tapped this individual' on the shoulder to inform him of the u
inspector's presence. The individual straightened up and 'the -
inspector noted his eyes were reddened. The inspector briefly-l discussed with the individual the need to stay awake and. requested.
'
that he wake up the other sleeping individual. The inspector
,
subsequently discussed this observation with the Unit 2 AS05 and the 50S. The inspector was informed later that both individuals were AU0s but that neither'was stationed as a TS required L
watchstander.
This event was reviewed with licensee management later the same l
day. The NRC noted, during these discussions, that an event l
.
_
-
-
I
!
!
E
,
occurred on June 8,1993, where the NRC identified 'an AU0 that appeared to be less than fully alert while on duty.
This
'
occurrence was addressed in inspection report 327, 328/93-23.
The
_
inspectors concluded that this is a continuing weakness regarding operator performance / sensitivity.
'
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 i
plant housekeeping conditions / cleanliness.
c.
Biweekly Inspections The inspectors conducted biweekly inspections in the following areas:
verification review and walkdown of safety-related tagouts in effect; review of the sampling program (e.g., primary and secondary coolant samples, boric acid tank samples, plant liquid and gaseous samples); observation of control room shift turnover; review of implementation and use of the plant corrective action program; verification of selected portions of containment isolation lineups; and verification that notices _to workers are posted as required by 10 CFR 19.
d.
Other Inspection Activities Inspection areas included the turbine building, diesel generator
-
building, ERCW pumphouse, protected area yard, control room, Unit 2 containment, vital 6.9 KV shutdown board rooms, 480 V breaker
'
and battery rooms, and auxiliary building areas including all
accessible safety-related pump and heat exchanger. rooms.
RCS leak rates were reviewed to ensure that detected or suspected leakage
,
from the system was recorded, investigated, and evaluated; and that appropriate actions were taken, if required.
RWPs were
,
reviewed, and specific work activities were monitored to assure
'
they were being accomplished per the RWPs.
Selected radiation
,
protection instruments were periodically checked, and equipment
!
operability and calibration frequencies were verified.
(1)
A01-27 Cabinet j
During the inspection period, the_ inspector reviewed the i
adequacy of the equipment storage cabinet utilized during the implementation of A01-27, CONTROL ROOM INACCESSIBILITY.
Inspection Report 327, 328/93-300 had-identified some discrepancies in this area regarding the availability and
.
-
.
[-
,
t i
j
organization of cabinet equipment. On August 30, a control
room abandonment drill was conducted which utilized the A01-
'
27 storage cabinet. The inspectors observation of the drill indicated that the licensee had adequately addressed the
!
earlier problems concerning the cabinet.
I (2)
On September 24, 1993, the inspectors conducted a walkdown of the Unit 2 containment. Housekeeping in the containment
was considered to be good.
However several potential problems were noted by the inspectors. They were:
-
Two junction boxes in lower. containment for. electrical equipment had cover plate fasteners which were loose.
-
Two valve operator electrical conduits in accumulator room # 4 had loose mechanical connectors.
-
Some glycol line locations did not have insulation material properly installed, t
-
Several connectors on the upper containment floor
- l appeared to be damaged and missing covers.
-
Some pealing paint was observed on the upper
containment wall.
I
!
These items were brought to the attention of the Operations
'
Manager who was also involved'in the walkdown. The
inspectors will review these issues with plant management prior to unit restart.
I 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
,
'
performance of various shifts of the security force was observed in the conduct of daily activities to include: protected and vital
,
area access controls; searching of personnel and packages; t
escorting of visitors; badge issuance and retrieval; and patrols
!
and compensatory posts.
In addition, the inspectors observed
!
protected area lighting, and protected and vital areas barrier integrity.
l f.
Licensee NRC Notifications j
(1)
On September 16, 1993, the licensee made a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> notification to the NRC as required by technical'
j specification LC0 3.7.ll.l.b, ACTION b.2.
The activity
.j requiring the call involved repair of a portion of.the
auxiliary building high pressure fire protection system due to a pinhole leak in the system caused by microbiological induced corrosion. During the outage, the licensee also
.,
R l
-
-
- -
.
I
!
,
attempted to repair a header isolation valve which had.
excessive leakby when closed. The licensee was unable to
,
establish a freeze seal isolation boundary for the i
maintenance activity and returned the system alignment to normal.
!
(2)
On September 18, 1993, the licensee made a four hour
,
notification to the NRC as required by 10 CFR 50.72 q
regarding identification of unqualified coatings in the Unit
'
2 containment.
Identification of this new area of
,
unqualified coating resulted in exceeding the evaluated total area of unqualified coating which could detach from'-
j its component and be washed to the containment' sump area
~
during a design basis accident. The discovery resulted'in
.
exceeding the current analyzed surface area and could
potentially result in inoperability of ECCS components under -
- !
design basis conditions. Unit 2 was in MODE 5 at the time.
,
ECCS components affected by this condition were not required to be operable in this MODE.
'
(3)
On September 25, 1993, the licensee made a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> notification to the NRC' as required by technical specification LC0 3.7.11.1.b, ACTION b.2.. The activity
'
requiring the call involved another attempt to repair of a portion of the auxiliary building high pressure fire protection system due to a pinhole' leak in the system caused by MIC. During the outage, the licensee also intended to
repair a header isolation valve which had excessive leakby
when closed. Attempts to establish system isolation were j
again unsuccessful. The licensee returned the system alignment to normal.
J The inspectors have noted several times -during the past year.
i where licensee actions have been required to compensate for degraded fire protection system conditions. The licensee.
l also is aware of this degradation'and is scheduling
-
corrective actions over the next few years to' upgrade the l
fire protection system. These upgrades include i
repair / replacement of degraded piping / components with new piping / components.
In addition, a partially closed system l
using a tank of treated water and new pumps is projected to.
reduce the piping / valve degradation due to MIC attack that the current system is subjected to. The' inspectors will continue to monitor licensee actions in this' area.
(4)
On September 27, 1993,'the licensee made a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> notification to the NRC as required by technical specification LC0 3.7.11.1.b, ACTION _b.2.
The activity requiring the call involved surveillance testing which required making part of the fire protection inoperable.
Surveillance testing was completed and the licensee restored the system alignment to normal.
j
_
..-
.
-
,
.
(5)
On October 4, 1993, the licensee made a four hour notification to the NRC as required by 10 CFR 50.72
..
regarding identification of unqualified coatings in the Unit-I containment.
Identification of this new area of
unqualified coating resulted in exceeding the evaluated
!
total area of unqualified coating which could detach from -
-
its component and be washed'to the containment sump during a design basis accident. The discovery resulted in exceeding the current analyzed surface area and could potentially
'
result in inoperability of ECCS components under design basis conditions. Unit I was in MODE 5 at the time. ECCS components affected by this condition were not required to i
be operable in this MODE.
Within the areas inspected, no violations were identified.
~
+
4.
Maintenance Inspections (62703 & 42700)
.
During the reporting period, the inspectors reviewed maintenance
activities to assure compliance with the appropriate procedures and
requirements.
Inspection areas included the foll oing:
l a.
During the previous inspection period, the inspectors became aware-of apparently recurring problems with the manual isolation valve on the Unit 1 fire protection header at the intake pumping station.
On August 21, 1993, the licensee made a 24-hour notification to the NRC regarding their determination that 1-VLV-26-575 would not cycle during surveillance testing of FP i
flowpaths. On September 2,1993, another 24-hour notification was l
,
made when the valve was found inoperable for a second time during
a fire pump surveillance.
Each time, the licensee entered TS action statement 3.7.11.1.b.
'
The inspector discussed the valve problems with cognizant licensee personnel, and reviewed the applicable maintenance documentation (0-MI-MVV-000-008.0, Revision 5, MAINTENANCE OF CSSC VALVES; and WO 93-07653-00).
The first reported failure of the valve to cycle, on August 21, resulted from loose bolts on the operator mounting bracket. This condition kept the rack and pinion gear from meshing. After the gear box was aligned and the bolts tightened, the valve stroked satisfactorily. Although the valve was difficult to turn at that time, a single individual was able i
to do so without applying excessive force. The second reported failure of the valve to cycle, on September 2, resulted from a broken pin which allowed the stem to freewheel inside the operator-
,
gear. The broken pin was replaced.
However, following this
.j second maintenance, the valve would not cycle. Although the valve
'
would turn easily in the open direction, it required excessive force to close.
The gearbox turned freely when disconnected, indicating that the problem was in the valve itself.
The system j
. -.
-. -.
.
- <
.
j l
engineer made a decision that this was not acceptable, and that l
the valve should be replaced.
l
\\
On September 8, 1993, the inspector observed attempts to
.
manipulate the 575 valve leading to the decision to replace the j
'
valve. The valve was rep; aced on September 20, 1993. The inspector observed portions of this work activity. A direct replacement for the original model was unavailable, so an-l
'
equivalent substitute was installed.
Engineering justification-
.
for this change was provided in DCN S-0100667-A.
The problem with j
l the original valve was found to have resulted _ from galling' between -
i l
the bushing and the shaft. The inspector did not identify any i
issues associated with the replacement of the Unit 1575 valve.
'l All work was completed in accordance with the work package.
Similar problems did not exist on the Unit 2, 575 valve, on which'
l-
'
maintenance had been performed during the fall of 1992.
'
,
The inspector concluded that the maintenance activity was accomplished in a satisfactory manner.
However, this review was one of the indicators that the fire protection system was in poor material condition.
i b.
On May 14, 1993, a potentially significant event (with respect to personnel safety and possible damage to equipment) was averted when an alert AS0S was preparing to energize the 1B 6.9 kV Unit
-
Board and discovered a set of electrical grounds incorrectly placed on the line side of breaker 1714.
Personnel were working j
inside the back of the cabinet.
Because the unit board bus was
'
grounded, serious equipment damage and. personnel injury might have occurred if the board had been energized with'the ground installed.
'
During this inspection period, the inspector conducted further independent followup of the event through discussion of the incident with cognizant licensee personnel, viewing the internals-of a similar Unit Board IB breaker compartment, and review of the following documents:
-
Incident Investigation 11-S-93-033, Revision 0, issued July 22, 1993, and Revision 1, issued September 30, 1993
.
-
SSP-12.3, EQUIPMENT CLEARANCE PROCEDURE, Revision 2, and Revision 3
-
Hold Order 1-93-1220
-
SI-266.1.1,.60-MONTH INSPECTION OF ITE 7.5HK-500 6900V l
BREAKERS, performance dated May 18, 1993
-
PM 050391002, 6900V UNIT BOARD "1B" BREAKER MAINTENANCE, performance dated June 3, 1993
,
-
MI-10.4, 6900V BREAKER INSPECTION, Revision 18, performance dated May 18, 1993
-
NUCLEAR POWER SAFETY AND HEALTH MANUAL, PART IV-A, ELECTRICAL SAFE WORK REQUIREMENTS
-
SMMD 91-010-MMO, WORK ON ENERGIZED CIRCUITS THAT EXCEED 125 VOLTS SSP-12.3 prescribes the licensee's established process for providing protection for personnel and plant equipment during operation, maintenance and modification activities through the use of clearances.
Requestors obtain clearances through the designated representative of the SOS, which is the AS05. After.
Operations has hung the clearance tags and formally issued the clearance, the clearance holder is required to perform a walkdown of the clearance prior to beginning the work activity.
Persons performing work within the clearance boundary are to sign on to the clearance hold order form. The procedure requires that only one person be on a clearance when testing such as-high potential testing (meggering) is being performed within the clearance boundaries.
If a clearance holder desires to place an electrical-ground within the boundaries of the clearance, the ground and associated disc are obtained from Operations.
On July 22, 1993, the licensee issued an Incident Investigation report on the events of May 14, 1993. Although the II accurately and thoroughly documented the facts of the incident, the inspector concluded that the licensee's analysis and followup was not sufficiently thorough. The inspector's-independent review of the event identified the following findings, which were not brought -
out in the licensee's 11 and were not initially recognized by the licensee:
(1)
In addition to incorrectly placing the ground outside the clearance boundary, the electrical crew violated SSP-12.3. by -
performing the work in compartment 1714 without actually being covered by the hold order. This was not brought out in the II. The performance of work without authorization in accordance with SSP-12.3, and the placement of a. ground outside the established hold order boundary, were identified as the first example of VIO 327,328/93-42-01.
(2)
The II was incorrect in concluding that: (1) the clearance boundaries of H0 1-93-1220 were sufficient for the work:
activities on the 6.9kV UB 1B and (2) personnel were fully protected by the H0.
During discussions with the inspector, the Electrical
__
Maintenance Manager and the II author confirmed that 250 V control power was present during the work.in the compartment,
of breaker 1714.
In addition, the crew had also used a glow
.
.
.
.
t j;
.
l
.
i stick to confirm the presence of 6.9 kV in breaker-
'
compartment 1622, which was not covered under a hold order
and was known to be energized.
"
In neither case had the crew obtained appropriate approval l
for working in the vicinity of the energized equipment.
..
.*
Licensee management acknowledged that this was not-acceptable with respect to personnel safety.
.
(3)
The II stated that the foreman was provided with a ground obtained from the foreman who held HP ?-93-1220.
It appears.
'
from the information in the II that-the foremen involved in this incident circumvented the requirements of SSP-12.3, Section 3.1.5.N, which requires.that the person assuming responsibility for placing and removing safety grounds SHALL-be issued the clearance before placing the ground. The 11 revealed that all of the involved foremen were aware that plant procedures did not allow the foreman working on the UB
,
to be added to H0 1-93-1220 because testing was in progress..
,
Additionally, they were aware that the foreman could not.
i obtain an authorization for a ground because he was not on a clearance. Nevertheless, they provided him with the ground he requested.. This was a violation of SSP-12.3, Section
.
,
3.1.5.N, and was identified as an additional example of VIO
!
327,328/93-42-01.
'
(4)
Based on the inspector's review of this incident and discussions with licensee personnel, the inspector concluded
that a lack of personnel sensitivity to safety and
procedural compliance regarding clearance orders associated
'
with this event, was not an isolated case. Through
interviews and procedure reviews the inspector discovered that workers inappropriately believed that hold orders were
'
not always necessary for cleaning potentially energized
.
breaker compartments. Certain SI and PM procedures could be
!
misinterpreted to support these beliefs.
Some electricians
- l considered equipment safe-to work providing no voltage was i
present, as opposed to first ensuring the equipment is
'
properly cleared and tagged, and then confirming that no voltage is present as a backup measure. The inspector also-
.
determined that some personnel believed it' was a common and
!
acceptable practice to remove all but one individual from
!
the clearance during testing, but allow other foremen to
,
continue working under his cognizance. On September 13,
1993, and on other occasions thereafter, the Maintenance.
Manager affirmed to the inspector that this was not within
the intent of SSP-12.3 and was not an acceptable practice.
.
.
(5)
Although the II indicated that multiple persons should not have.been on H0 1-93-1220 on the morning of May 14, 1993, due to testing in progress, the inspec or noted that multiple individuals were on the H0 dur ng that time. At b
I l
..
,.
,
t i
,
t all times there were at least two persons on the clearance j
and at times there were three. However, the inspector noted i
that the documentation on the H0 was insufficient'to i
establish exactly what testing, if any, was in progress on r
the morning of May 14. The only work activities listed for
,
that period were board cleaning, some MOV work, 'and " belt
inspection."
To clarify the apparent discrepancy between the II findings
!
and the actual number of individuals signed on the clearance
'
on May 14, 1993, the inspector obtained and reviewed the following documents, which documented the performance of I
meggering within the boundaries of H0 1-93-1220:
!
-
PM 055091000: CLEAN, INSPECT AND REPAIR 480V SHUTDOWN.
BOARD 1Al-A, had signatures dated May 11 and May 14, 1993, which documented meggering.
!
-
PM 055101000, CLEAN, INSPECT AND REPAIR 480 V SHUTDOWN BOARD 1A2-A, had signatures dated May 13, 1993, which documented meggering.
The inspector determined that the foreman for PM 055091000
'
was logged onto H0 1-93-1220 under PM 054951000 from 3:46
,
p.m. on May 13 until 1:38 a.m. on May 14. A log entry by this individual, dated May 14, indicated that meggering of
.,
the bus took place during his shift. The inspector noted that during this same time period, the H0 documented that multiple persons were signed on to the hold order, in i
violation of SSP-12.3.
'
'
This failure to remove multiple individuals from the hold order while meggering was in progress is identified as a j
violation of SSP 12.3, Sections 3.1.4.D and 3.1.4.E, which
!
require that during testing activities such as meggering, i
only the person doing the testing shall be on the clearance.
This was identified as an additional example of.VIO
!
327,328/93-42-01.
l
6)
The inspector identified a number of. work activities which j
were shown on several PMs as being performed under a i
particular H0, but were not shown on the corresponding i
clearance holder sheets.
Some of these work activities
'
included meggering. Unless work activities are listed on
!
the clearance hold order sheet, ther e is no assurance that i
the Control Room is aware that the work is being performed,
as was the case with the improperly installed ground in ci compartment 1714.
_;
For example, although the documentation for PM 055091000 and PM 05101000 identified the performance of meggering during
)
May 1993, and listed 1-93-1220 as the applicable hold order, j
.!
.l l-i
-
.-.
l
!
neither PM appeared in the section of the clearance holder form where work documents are to be listed.
For PM
05509100, the meggering of SD Bd 1Al-A on May 11 was
'
identified in a footnote on the H0, although.the PM number-was not specified.
For PM 055101000, neither the PM number nor the foreman (as listed in the PM) were noted on the.
.
clearance form, and there was no documentation of meggering for the applicable time period.
l
'
The inspector reviewed a sampling of hold-orders involving meggering for a selected two-week period. Based on the M&TE checkout records for the first two weeks of June, and a review of the referenced work documents, the inspector.
determined that meggering was performed under the following
hold orders and work documents, on the following dates:
-
H0 1-93-1015/PM012271029, PM012271030,
!
PM012271031/ June 3, 4, 5, 13, 14, and 15, 1993
-
H0 1-93-1076/PM012271003/ June 11 and 17, 1993
<
,
-
H0 1-93-1239/PM056032000/ June 14, 1993 j
-
H0 1-93-1239/PM056052000, PM056032000, PM056720001/ June 12 and 14, 1993
-
H0 1-93-1302/PM012271009/ June 7, 1993
-
H0 CLD-410/WO 93-03472-00/ June 14, 1993 t
Of these, PMs 012271003, 05605200, and 056032000 were not listed on the H0 referenced in the PM. Also, PM012271003
-
had meggering dated June 17, 1993,- but the Hold Order listed l
in the PM (HO l-93-1076) was released by the ASOS on June
!
15, 1993.
E The above failures to assure that work activities are
'
I appropriately logged on the clearance holder form as required by SSP-12.3 is an additional example of V10 327,328/93-42-01.
!
7)
A majority of the H0s reviewed during this inspection were l
incompletely filled out with respect to the work document
and work description sections. SSP-12.3. ~ ' in 3.2.9 l
requires that clearance sheets shall be c.are:
y and
=
completely filled out to ensure that all information is-i recorded and available for future reference.
The procedure calls for the work document and work description to be
entered on the clearance sheet. The inspector noted
instances where this information was not entered on H0s 1-l
,
l 93-1220, 1-93-1302, 1-93-1239, 1-93-1015, and 1-93-1076.
'
l The inspector considered this poor documentation practice to
!
l
,.--
-
n -- -
_
.
L
_;
l _
be a contributing factor to the identified failures to
l remove all but-one individual from clearances during
I testing. This was identified as an additional example of VIO 327, 328/93-42-01.
The inspector noted that this event had one or more precursors.
,
On November 8, 1991, a fire occurred on 480 V shutdown board IB-B
+
when electricians used a glowstick on an energized circuit outside
of their work boundary. According to the II written for this
'
event, a review of LER and NER data bases had identified other
previous events at Sequoyah and other TVA plants associated with
.;
working on energized boards.
In addition, the inspector noted y
that a QA review conducted from July 6 through November 12, 1992, identified weaknesses in implementation of the clearance process.
On September 30, 1993, the licensee issued Revision 1 to the II, which was responsive to the concerns identified during this inspection. The revised II concluded that electrical safety
standards at Sequoyah were set too low, especially with respect' to
~
working in the vicinity of energized equipment. According to the
'
revised II, licensee management suspected that some employees had i
developed an attitude that, in order to expedite work, it was acceptable to violate certain safety practices and procedural i
requirements as long as one was careful.
As an immediate corrective action, discussions were conducted with Maintenance Electrical Group personnel on September 29 and 30, 1993, to reinforce the necessity for procedural-compliance and
'
ensure that work will be conducted safely. Additionally,
-
operations eliminated the floating ground process, and implemented i
large yellow " Ground Installed" placards to make grounds more -
!
noticeable.
Finally, longer term corrective measures were also~
documented in the II, and include _both procedure revisions and.
-
implementation of a training program geared toward changing work
-
+
practices and attitudes, j
l In summary, the inspectors concluded that both the 1992 and 1993 l
Ils provided the-facts essential for an understanding of the root
problems addressed in this inspection. However, in each case the l
licensee failed to determine the root causes sufficiently to-u prevent recurrence. The licensee's analyses and followup of both events was inadequate with respect to the general: lack of l
personnel sensitivity and procedural compliance revealed by the i
incident.
'
c.
During the inspection period, the inspectors monitored a number of issues, which in general, could potentially lead to containment'
sump blockage. The inspectors were concerned that the individual issues or the aggregate could adversely affect the safety function-
,
of the containment sump. The specific issues included:
!
deterioration and delamination of certain containment liner coatings; identification of unqualified coatings inside and-i
-
.
_
.-
!
I
outside the sump zone of influence; inadequate logging of unqualified coatings; and other issues involving materials and/or equipment which ctuld affect the sump. The inspectors reviewed and monitored the r llowing issues for restart:
o 1)
The licensee initiated PER 930266 to document the failure of maintenance planning to adequately provide for control of
_j vendor coated (unqualified) equipment installed in the
,
containment, specifically within the zone of influence (ZOI). The PER identified various vendor coated items which were not properly accounted for.
.
The ZOI was established in 1987 via a Westinghouse calculation (WCAP 11534) and was developed to define and assess the impact of protective coatings on the performance
,
of the containment sump, post accident.
The' study specifically addressed the impact of unqualified coatings, assuming that qualified coatings within the containment would not delaminate and therefore not adversely affect the
,
"
safety function of the sump. With a slight variation for different coating thicknesses, the WCAP defined the 20I as approximately a 12 foot radius from the center of the sump.
The conclusions of the WCAP were that as long as the unqualified coatings in the ZOI were maintained at less than 56.5 square feet, the sump would not be degraded by unqualified coatings during accident conditions.
The licensee performed walkdowns of the ZOI to correct the problem and determined that the actual quantity of unqualified coatings was less than that maintained in the i
'
control log. Nevertheless, the licensee did not adequately control and/or log the amounts of unqualified coatings in the ZOI. The final amount of unqualified coatings, after subsequent inspections.in the Unit 2 201, was 55.95 square feet.
Further inspection made in the Unit 2 ZOI by the inspectors are discussed later in the report.
,
2)
Incident Investigation II 930442 was initiated due to the licensee's identification that an extensive quantity (143 square feet) of unqualified coatings was identified on the
- 4 RCP motor stand interior.
The #4 RCP is the only RCP in the ZOI. This finding existed on both Unit I and 2.
The unqualified coatings were identified as a result of-walkdowns being performed as corrective action for _PER 930266, described above.
.i To address this problem, the licensee performed modifications to the Unit 2 RCP #4 motor stand; installing i
screens to prevent the unqualified coatings from migrating _
j to the sump, post accident. At the end of the inspection
'
period, the licensee had not concluded their 11 and assessment of the safety impact of the excessive unqu'alified i
J
.
.
-
I
_
i
1
'
coating in the ZOI. The inspectors will review this area in.
I detail when the licensee's evaluations are complete.
,
3)
PER 930510 was identified to document that the exterior of
the containment liner was not topcoated as described in the-
FSAR. This finding existed on both Unit I and 2.
The FSAR-i stated that the exterior of the liner would have an epoxy l
topcoat and a red lead oil paint as primer.
o The licensee addressed this issue by performing a safety
l assessment which concluded that the topcoat was not needed.
'i This conclusion was based on the determination that the topcoat was only provided for decontamination purposes and.
-)
its absence did not compromise the structural integrity of
!
'
the liner.
The licensee plans to reflect the change via an
';
FSAR revision.
"
t 4)
PER 930510 also addresses potential safety concerns related to the delamination of the interior containment liner coating in upper containment. The PER also addresses differences between the FSAR description of internal liner coatings and the current plant configuration.
The coatings installed on the interior of the containment
!
,
liner consists of a Carboline Carbo-Zinc 11 SG primer and a
'
c
'
Carboline Phenoline 305 topcoat. The delamination of the t
topcoat is attributed to the lack of topcoat adhesion due to
)
improper thickness application of the primer during
'
construction. The excessive primer thickness prevented proper curing of the primer and resulted in the topcoat adhesion problem. During the inspector's review,~.the licensee was asked to evaluate the remainder of._ the primer j
for adequate corrosion protection. The licensee concluded
,
that the failure'of the topcoat did not present a safety j
concern before or during accident conditions. Walkdowns performed of the affected areas did not identify any I
corrosion as a result of the lack of topcoat.
Problems with the delamination were first identified in 1977. The licensee estimated that approximately 40 percent of the topcoat has been removed in Unit 2 (mostly in 1986-i 87). However, due to the continuing delamination problem, additional areas were identified during the current Unit 2.
outage. As a result, the licensee removed the predominant failed coatings from the upper containment. However,- the inspectors concluded that the remaining original " qualified" coatings in' the upper containment could no longer be-considered qualified.
Review of the WCAP issued in 1987 did address the potential failure of coatings 'in the upper..
containment. The conclusions made in the WCAP were that debris from the refueling canal drains would not reach the sump by being transported through the pool.
Based on the l
,
l
,
.
..
m
inspector's initial review of the WCAP, the current condition of the inner containment coatings, and the previous NRC reviews performed regarding NUREG-1232, Volume 2, Part 1,.the inspectors concluded that this was not an immediate restart issue. 'The inspectors will monitor the-licensee's resolution of this issue with respect to generic industry resolutions.
5)
An issue was identified regarding unqualified coatings on the SGs.
Specifically, coatings on the generators beneath -
the installed mirror insulation had been identified as not being qualified. The licensee received this issue in April 1993 via NRC Information Notice (IN) 93-34.
The IN also addressed a problem concerning temporary fibrous material, which could also lead to sump degradation.
In May 1993, NRC Bulletin 93-02 was issued which specifically addressed the temporary fibrous' material aspect of the IN.
The licensee closed the IN based on their response to the Bulletin in June 1993. However, during an NRC Operational Readiness Assessment Team inspection conducted during the early part of the inspection period, the NRC identified the unqualified coatings beneath the mirror insulation was not properly addressed as part of the IN. This will be identified as an additional example of a deficiency identified regarding weak Nuclear Experience' Reviews (NER)
as discussed in paragraph 6.a.
The licensee concluded that the mirror insulation of the #4.
SG (only SG in the ZOI) would not be dislodged during a design accident. This conclusion was based on a leak before break assumption. The inspectors will monitor the licensee's resolution of this issue with respect to generic industry resolutions.
6; PER 930553 identified that one of the 2 inch x 0.25 inch'
bars which secure the top of the Unit 2 containment sump screen was not installed. The licensee evaluated the condition and determined that the missing bar did not degrade the safety function of the sump during an accident.
The missing bar was repaired prior to restart.
The inspector had discussions with the licensee regarding the resolution of the above, and other containment sump related issues. The inspector specifically focused on assumptions made in WCAP 11534, FSAR descriptions, and the actual condition of the containment sumps.
On October 8, the inspectors performed a detailed review of the Unit 2 201. Specific attention was focused on the licensee's current unqualified coating amounts of 55.95 square feet. As previously noted, the WCAP limit was 56.5 square' feet. With
i l
r
.
t respect to unqualified coatings, the inspectors raised the
following issues-
-
The inspectors questioned the condition of qualified
.
coatings within the zone of influence.
Flaking of qualified
!
paint was identified throughout the zone of influence..This
- :
problem was predominately in the lower portions of the zone.
-
The inspectors questioned the licensee's method of defining zone boundaries. For example, the number four RCP rests
!
entirely within the zone of influence and contains.
unqualified coatings; however, a catch basin exists under a
!
large portion of the RCP. The licensee assumed that any.
!
runoff containing unqualified coatings that is within.the
zone defined by the catch basin is contained within the
catch basin. The inspectors were unable to determine if the
runoff will actually be contained by the catch basin or be l
diverted away from the catch basin and washed to the sump.
l
-
The inspectors identified a black spongy substance which had been installed between structural support and concrete
,
interfaces. This substance was within the zone of influence
!
and could be easily dislodged. The inspectors questioned whether this material should be added to the analysis for potential sump blockage.
.
-
The inspectors questioned two components on which the
licensee could not identify coatings as qualified or
,
unqualified.
These two items were a light cover and a i
junction box.
,
-
In addition, the inspectors identified within the-zone of
-
influence the following items which could potentially
'
contribute to sump blockage.
,
- An unattached metal valve tag.
-
- Numerous pieces of loose duct tape.
,
- Pipe insulation identification stickers.
i
- Radcon survey location identification stickers.
,
- A sign located on an ice bay door.
Based on these inspections the inspectors concluded that the
,
aggregate effect of the above concerns warranted further review by
the licensee before restart of the plant.
In addition, the
inspectors concluded that the licensee's compliance with unqualified coatings limit was questionable.
The inspectors discussed the findings with licensee management.-
The licensee took immediate actions to correct the deficiencies
'
identified in the Z01. These included removal of components with l
unqualified coatings, repair of qualified coating surf aces, and-i removal of debris.
!
i i
i I
'
-
,
,,.
--
.
l
17 l
Based on additienal inspections of the Unit 2 containment sump ZOI on October 9, the inspectors concluded that the licensee had adequately addressed the above concerns for restart.
It should be-i noted, however, the inspectors also concluded that the licensee's i
maintenance of the 20I in the past had been less than adequate, i
considering the importance of the sump's safety function and
!
previous problems in this area. The inspectors will review the-l safety and regulatory significance regarding the identification of
,
excessive unqualified coatings in the ZOI when the licensee has completed their incident investigation. The licensee's past maintenance and design aspects of the containment sump will be
'
reviewed as Unresolved Item 327, 328/93-42-02.
d.
On June 17, 1993, during a walkdown of Start Bus 2A, the
,
inspectors observed that slugs of copper tubing were being used as electrical cnnnectors in certain fuse holders. At that time, the
inspectors discussed this practice with cognizant licensee personnel, and determined that the system was four-wire grounded-t and that the copper slugs were in the line to ground. Therefore this application was technically acceptable.
During this inspection period, the inspector selected two of these slugs (for
the cooling fan controls for breakers'1512 and 1612) and confirmed
that they were reflected on an approp., ate-system drawing (45N761-e 1) and S0I checklist (0-50-202-1, 6900V START BUSES POWER CHECKLIST, ATTACHMENT 2). The 501 checklist referenced Contract l
drawings 33-47035-E65 and E68. The inspector had no further
'
questions.
e.
Late in the inspection period, the inspectors noted that several r
Unit 2 containment lower compartment cooler leaks were identified-l and repaired. During testing activities, after the initial leaks
'
were repaired, several other leaks were identified and repaired.
After leak repairs were completed, the inspectors observed water i
on the floor in the vicinity of three of the four lower compartment coolers during a containment tour.
Subsequent licensee inspections identified small leaks on two of the coolers.
t Containment lower compartment cooler leaks has been identified as a continuing problem at Sequoyah. The licensee has written a PER-(SQPER93-0604) to address Unit 2 operability for this recurring problem. The PER contains an engineering evaluation which
!
concleded that the coolers are operable. The inspectors reviewed
-
the evaluation and concluded it was adequate.
However, the inspectors also concluded that the containment lower compartment cooler leakage problem is another example of poor material condition of these components.
Licensee management were aware of.
..
this problem area.
!
Within the areas inspected, one violation and one unresolved item were
identified.
~
,
f
o-
5.
Surveillance Inspections (61726 & 42700)
During this report period inspectors reviewed maintenance activities in the area of post maintenance / modification testing. The inspectors reviewed approximately seventy-five completed work orders, ten design change notices, observed five PMTs, and reviewed applicable portions of the following procedures:
-
SSP-6.1, Conduct Of Maintenance
-
SSP-6.22, Planning Work Orders
,
SSP-6.25, Performance Of Work Orders
- '
-
SSP-6.267 C9mpletion Of Work Orders
'
-
SSP-6.31, ikintenance Management System Pre-Or Post-maintenance isting i
-
SSP-8.1, Conduct Of Testing
?
-
SSP-8.3, Post Modification Testing
-
SSP-12.1, Conduct Of Operations
-
SSP-12.2, System And Equipment Status Control
.
-
SSP-12.57, Technical Specification Component Condition Record
'
-
SSP-12.6, Equipment Status Verification and Checking Program l
-
Sequoyah Surveillance Instruction SI-166, Summary of Valve Tests for ASME Section XI
-
0-SI-SXV-000-006.0, Testing Of Category "A" And "B" Valves After Maintenance Or Upon Release From A Hold Order The inspectors verified by a review of the aforementioned PMTs that the equipment would perform their intended function following maintenance, i
the original deficiency was corrected, and a new deficiency was not
,
created. Overall the PMTs reviewed satisfied these three criteria.
However, the inspector identified the following weaknesses:
,
(a)
Work packages were reviewed which contained more than one i
unrelated activity. Work Order 92-11668-00 was written to
,
troubleshoot a problem with the acid storage tank level indicator, 0-LI-14-137.
Included in this package was planning to-disassemble i
and remove a 90 degree elbow, replace 3 inch valve 0-14-339, repair / replace tank manway covers, replace tubing and fittings on
the number one pump, replace 1.5 inch valve 0-VLV-14-576, install
'
a weld overlay at the outlet to 0-L1-14-347, clean the tank, and
fabricate a temporary cover on top of the tank.
Discussion with
'
craft and operations personnel indicated that this practice
,
resulted in the packages being complicated and confusing. They i
further stated that cost reduction was one reason several repairs
were made using one work document.
')
(b)
Several work packages contained PMTs which stated, " Verify no Leakage" or " Verify no external leakage." The PMTs did not-specifically state the locations to be checked, a joint or~
_ _
j packing, whether a specific pressure _ was to be obtained prior. to.
)
the test, and in several cases involving valve replacements, did
'
,
. -
-
-
_-
-.
_ _ _ _ _ _
.
._ ___ _ _ _.
t
.!
!
.
not verify no seat leakage. Three examples are work orders 93-01241-00, 93-04194-00, and 93-06724-00.
(c)
Many work packages contained little or no documentation _ of. the
actual work or PMT performed. Work Order 93-02891-00 written to replace a relay, contained documentation which simply stated that l
the relay was installed and tested satisfactorily per work
'
instructions. Work Order 93-03371-00 contained limited step text
or documentation. A good example of documentation was observed in
work order 93-04750-00 which replaced a solenoid valve and i
pressure regulator. The documentation very explicitly stated what-
'
work and PMT was performed.
(d)
One work package reviewed contained two work orders with the same document number, 93-03898-00. One work order was written for the electrical group to check an annunciator circuit and the other was written to repair a float.
(e)
One work order reviewed, 93-01947-00, had a signature indicating the PMT was complete; however, the procedure which controlled the PMT had not been filled out.
(f)
A review of the PMT for the MSIVs was identified by the inspectors to be inadequate in some cases. The PMT for work request C222713, on MSIV 2-FCV-1-29, was written by the planning group to require Parts B & C be completed after all maintenance work was completed.
Similarly, the PMT for work request C004737, on MSIV 2-FCV-1-4, was written by the planning group to require Parts A & B be completed.
Sequoyah SI-166, " Summary of Valve Tests for ASME-
,
Section XI," requires that Parts A & C be performed as the PMT for MSIVs. The Part A of SI-166 was not specified in the planning of work request package C222713.
Part C of SI-166 was not specified in work request package C004737. This is considered a weakness in work package planning for PMTs.
(g)
Discussion with Maintenance work supervisors and Operations SR0s indicated that work closure reviews were cursory. Additionally, several packages reviewed by the inspectors awaiting the " work i
package complete" signature on the WACF, contained errors or were found to be missing signatures. When questioned, maintenance personnel stated that these would be corrected during the final
" work completed" review.
SSP-6.26, " Maintenance Management System Completion Of Work.Or-ders," Sectfon 3.1.B.1, states that to close out a work document as complete, the General Foreman / Designee must ensure all
documentation used to perform and/or document work is attached to the work order package and ensure all signatures and date entries have been addressed.
SSP 6.31, " Maintenance Management System Pre-Or Post-Maintenance Testing," Section 3.4, Responsibil'. ties, states that prior to close out of a work document the SR0/ SOS /AS0S shall review and verify the completion of PMTs listed in the work
-
- -.
-
M
l
-
I package.
Contrary to this Work Order 93-08201-00 contained signa-tures by both the Maintenance work supervisor and Operations SRO indicating that all PMTs had been completed, however, a PMT
,
requiring a verification of no external leakage had not yet been completed. This constitutes examples one and two of VIO 327,
!
328/93-42-03, Failure to perform Post Maintenance Testing in Accordance with Administrative Requirements.
A review of valve checklist 0-SI-SXV-000-006.0, " Testing Of Category "A" And "B" Valves After Maintenance Or Upon Release From j
A Hold Order," by the inspectors identified several concerns. The valve checklist is used as a " master list" to ensure that all i
technical specification related valves that have had some worked
)
performed by the maintenance shops or other craft, are stroked to complete the post-maintenance testing requirements, thereby,
'
completing all the work related activities associated with the-valve (s). Upon completion of the stroke test, if the valve (s)
operate as required, the valve (s) are considered operable by
<
Operations.
From discussion with Onora+%.; personnel, if a valve j
has all associated maintenance work completed and a valve stroke I
test is the only outstanding item left for package review and closeout, Operations and Maintenance sign-off the documentation in i
the work request / order package, add the valve number to the valve
-
checklist 0-SI-SXV-000-006.0, and close the TSCCR. Site Standard Practice 12.57, " Technical Specification Component Condition
,
Record," Section 3.8, states that a TSCCR shall not be closed out'
until the Technical Specification related equipment covered by this record is restored to Technical Specification operability.
It also states that if the maintenance is complete, but the Post
'
Maintenance Test is not completed, the TSCCR form should be
'
modified to reflect the Technical Specifications of the incomplete l
It further states that a TSCCR shall be closed out when:
l
'
.
-
The condition reported on a TSCCR form is corrected.
-
The work tracked by the ISCCR is completed.
-
It is replaced by another TSCCR.
The work packages listed on the valve checklist, 0-SI-SXV-000-006.0, and the associated TSCCRs, were inappropriately closed out by Operations and Maintenance. The
,
premature closure of the work request packages ~ is in violation of l
Sequoyah Site Standard Practice 12.57.
l This constitutes the third example of violation 327, 328/93-42-03.
. ;
I (h)
Other weaknesses and issues identified by the inspectors on review j
of the valve checklist, 0-SI-SXV-000-006.0, included:
Valve checklist entry 2-FCV-313-223. The associated work
i request listed for the valve is incorrect. The work request l
l-
- i
!
i
-,
k
+
4 covers work on a exhaust fan damper in the turbine building.
,
Valve checklist entry 2-FCV-70-198.
The associated. work-I
.
request package, at the time of the inspection, was in the l
planning group. No work had been performed by the maintenance groups by this work request package number.
In addition, the column " Local Stroke Verification - Yes/No,"
,
was not checked off by the unit operator.
Valve checklist entry 2-PCV-1-30. The " Work Request / Hold
Order Number" column required to be listed on the valve checklist form listed a surveillance ~ procedure, 0-SI-SXV-000-008.0.
,
Valve checklist entry 2-FCV-313-229. The date entered for
=
completion of proper documentation and successful stroke
,
test was inadvertently written as September 20, 1997, instead of 1993.
As a result of these findings, the licensee generated Problem Evaluation Report SQ93-0557 to determine the root cause and
_
develop corrective action. The inspector reviewed the completed
.
PER and noted that the licensee performed a 100% verification of
,
the PMTs for til valves transferred to the master list since
"
March 1, 1993. The findings from this review provided multiple examples of the weaknesses identified by the inspectors. -The licensee took immediate corrective action which included correcting the mistakes that were found, initiating a TSCCR for j
the components listed on the valve checklist. 0-SI-SXV-000-006.0,
.
and issuing Standing Orders93-079 and 93-082. -These Standing Orders clarified the process for transferring a PMT from a WO to
the valve checklist and described the documentation and review expected when closing out W0s. Corrective actions not yet completed include revising the valve checklist, SI-SXV-000.006.0 j
and various maintenance procedures to include more specific direction in transferring PMTs from W0s, standardization of incorporating PMTs into W0s, and written expectations on the amount of detail to be included in W0s. Additionally, training is j
to be provided to Operations, Maintenance, and Modifications
'
personnel to review the incident, the procedures involved, and the processes used. While the corrective actions-identified by the licensee have not yet been completed in their entirety, the inspector believes the immediate actions are sufficient to address Unit 2 restart concerns, and to prevent further recurrence until the long term actions are completed.
Within the areas inspected, one violation was identifie.
,
b
.
i 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.
Nuclear Experience Review The inspector reviewed the licensee's program for review of NRC information notices. The inspectors selected three recent
information notices and evaluated the -licensee's program regarding-review of these issues.
The results' are as follows:
(1)
Information Notice 93-22, TRIPPING OF KLOCKNER-M0ELLER MOLDED-CASE CIRCUIT BREAKERS DUE TO SUPPORT LEVER FAILURE,
dated March 26, 1993-t This IN involved spurious tripping of certain K-M molded case circuit breakers due to failure of switch latch support levers. On April 20, 1993, the NER staff sent the IN to i
Corporate Nuclear Materials for action, and to the remainder i
of the normal distribution for information. Nuclear Materials identified that Sequoyah and Watts Bar had some of the breakers, and this information was forwarded to those-sites for action.
For Sequoyah, it was determined that the only installed breaker of this type was in the Amertap
.
condenser tube cleaning system, which' is non-safety related.
In addition, the ambient temperature of the cabinets is expected to be less than the threshold temperature mentioned
,
in the IN. One additional breaker was found in stock,. which
was retained as a potential replacement for the Amertap t
system. This spare breaker was tagged and the MAMS records annotated to refer to the restrictions of the'IN and associated NER review.
The inspector concluded that this item was appropriately dispositioned by the NER process and
'
acceptably resolved by the responding.line organization.
i (2)
Information Notice 93-32, NONCONSERVATIVE INPUTS FOR BORON DILUTION EVENT ANALYSIS, dated April 21, 1993 This IN involved nonconservative assumptions in the licensing basis of dilution events for Westinghouse plants
which have boron dilution mitigation systems.
It was identified that the use of a generic curve for inverse count
,
rate ratio vs. RCS boron concentration was inadequate, and
the system was unreliable due-to uncertainties associated with the indication of flux doubling by the nuclear instruments.
,
q
!
i n
. -
- _ _.
. _ - - _ - _ _ _ _
j i
The issue was referred to Sequoyah for review and action, but was found to be inapplicable because Sequoyah does not have a boron dilution mitigation system in the plant design.
In addition, the flux doubling criterion for_ boron dilution events described in the IN is not applicable to Sequoyah.
The Sequoyah Gammametrics. source range alarm setpoint is one-half decade above the time-weighted background level.
Setting the alarm setpoint at a factor of 2 above
background, as described in the IN, would result iw spurious
'
alarms. The inspector concluded that this item was.
.
appropriately dispositioned by the NER process and I
acceptably resolved by the responding line organization.
.j (3)
Information Notice 93-33, POTENTIAL DEFICIENCY OF CERTAIN CLASS lE INSTRUMENTATION AND CONTROL CABLES, dated April 28, 1993 This IN involved deficiencies identified during NRC-
,
sponsored cable testing at Sandia National Laboratories.
Several cable types failed during the accident tests or'-
exhibited marginal insulation resistance.
NRC Generic
]
Letter 88-07 provides guidance to licensees on dealing with i
potential EQ deficiencies, and states that the' licensee is -
-
'
expected to make a prompt determination of operability, establish a reasonable schedule to correct the deficiency, and have written justification for continued operation.
When received by TVA, the IN was referred to each of the three sites for action. An evaluation of the applicability j
to Sequoyah was documented on August 5, 1993. This D
evaluation stated that Sequoyah had one of the cable types identified in the IN (BIW Bostrand 7E) installed as pigtails in two vendor-supplied penetrations in-Unit'2. The evaluation identified that the installed cable was from contract 72C61-75164, and as corrective action EQ binder SQN EQ-PENE-002 would be updated to reflect the information in the IN. The NER item was considered closed for Sequoyah.
Subsequently, on August 10, 1993, an internal TVA memorandum-l (B44 930910 004) was issued by corporate engineering to
'
provide guidance to the sites in responding to the IN. The NER forwarded this memorandum to each of the TVA sites for information. This memorandum provided relevant background information on the Sandia tests, an analysis of the anomalous test results, specifics as to the investigations -
'
and actions to be taken for each of the subject cable types,-
,
and other pertinent supplemental information. The memorandum stated that there did not appear to be'any BIW Bostrand 7E cable at Sequoyah, but that other BIW cable was in use which had XLPE insulation.
The memorandum requested i
a response from Sequoyah confirming the' absence of the 7E~
compound. Although the original NER item was closed,
.
-
l
corporate engineering continued to work with the sites, outside of the NER process, to resolve the issue.
i On September 29, 1993, the inspector questiened the licensee on the apparent discrepancy between the original NER closure-and the August 10, 1993, memorandum with respect to the-
.
presence of 7E cable at Sequoyah.
The inspector. questioned ll
'
whether the issue had been adequately reviewed for Sequoyah.
In response to the inspector's questions, the licensee
_
j
'
produced a subsequent memorandum from corporate engineering (B44 930910 010), dated September 10, 1993, which documented
,
that at least two of the cable types in the IN may be in use J
at Sequoyah as pigtail leads in vendor-supplied
.
-l i
penetrations. The September 10 memorandum directed Sequoyah'
to review penetrations for all of the cable types in the IN.
'i The IN issue was repaneled at an NER meeting on September j
30, 1993, and was reopened.
The inspector concluded that ins 93-22 and 93-32 were
]
appropriately dispositioned by the licensee. However, the
!
processing of IN 93-33 led to a concern regarding the closure
'
adequacy of NER issues and the determinations of whether items i
should be classified as information or action.
The inspector discussed the NER process with. current site and j
corporate licensee management, who demonstrated an-acceptable i
sensitivity to generic issues. On September 2, and September 30,_
'
1993, the inspector attended weekly NER meetings and observed incoming potentially generic issues being screened for action.
In-
,
general, the items presented were appropriately dispositioned, and an acceptable threshold and safety sensitivity were demonstrated.
,
The inspector noted a tendency for.the screening reviewers to
'
assume that personnel errors or procedural noncompliance at a
'
particular plant would not be applicable to other TVA plants.
This philosophy was confirmed in discussions with management. The inspector concluded that this philosophy should be implemented cautiously, particularly when the errors or noncompliance were of a type likely to also be made by other individuals, or were.
indicative of training or cultural problems which could exist at other plants as well.
i
.l Nuclear Quality Audit and Evaluation Audit SSA93308 included an assessment of the generic applicability reviews of issues coming
,
to Sequoyah from other sites. The audit concluded that, in most cases, generic issues were adequately evaluated and that the NER program activities were adequate. The audit team identified an example where an inadequate extent of condition review of a Browns-Ferry issue led to similar events not being prevented at Sequoyah.
,
However, weaknesses in extent of condition determinations were_not I
restricted to incoming generic issues and also occurred elsewhere l
taken programmatically. The audit recommended that the rationale
_
in the Corrective Action Program.
Corrective actions were being i
1 '.
.j i
l l-i
.
l supporting generic applicability determinations be better
'
documented.
Based on the above, the inspector concluded that the current NER program provided reasonable assurance that incoming generic issues would be appropriately dispositioned, but that additional-management attention to this area was warranted, b.
Throughout the inspection period, the inspectors monitored the majority of the MRRC meetings and also attended several PORC meetings. The subjects of the meetings included the addition / deletion of restart issues, plant systems and department
'
readiness reviews, backlog and workoff status updates, reactor l
trip report reviews, and other outage related activities. The
'
inspectors concluded that the MRRC continued to make conservative decisions regarding the specific issues presented to the committee. However, the inspectors also identified a weakness involving several examples where the MRRC was not presented with
,
adequate explanation or engineering basis for correct-restart i
decisions to be made by the MRRC.
Examples included evaluations
'i and corrective actions for existing discrepancies on Unit 2 main
_i steam piping structural supports and evaluations for ice condenser
basket structural integrity. Once an accurate' representation of J
the issues was presented to MRRC, the-inspectors concluded that the correct restart decisions were made. The inspectors review of PORC activities during the inspection period indicated that the
safety functions of the committee were being adequately performed.
c.
During the inspection period, the inspectors monitored several MRC meetings which were held each morning in the plant manager's i
office.
Based on increased sensitivity, several problem evaluation reports were written identifying issues which needed
-!
additional information to determine restart requirements.
i The inspectors selected approximately 20 PER issues for review.
~
Several of the issues were engineering issues of a civil / structural nature.
Region specialists conducted a'special
inspection in these areas. Their inspections are documented in l
inspection report 327, 328/93-49. The other corrective action document issues were reviewed by the inspectors during this
,
period. One of the reviews on coatings is' documented in paragraph 4.c of this report.
The other issues were resolved appropriately and documented in the PERs.
However, several of the initial reviews and documentation provided by the licensee resulted in additional questions by the inspectors.
For example, the inspectors reviewed the licensee'.s initial response to PER SQ93-0524. This issue involved licensee identification of several AFW drain valves that were not procured to system design pressure requirements. The licensee's initial-evaluation stated that these valves were satisfactory for Unit 2-restart based, in part, on the fact that they had performed
n i
)
satisfactorily in the system up to this point.
The inspectors requested that the licensee provide additional justif' cation'for usage of the installed valves. After the request,.the licensee obtained additional documentation that the valves had been tested to 3000 psig and they also cut open a valve from shop stores to determine whether adequate structural margin was present. The additional actions and documentation. satisfied the inspector's concern.
The above example was typical of some of the other licensee initial responses and was considered a weakness regarding licensee initial evaluation and documentation of engineering evaluations for PER corrective actions for restart.
>
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 i
reporting requirements were being met and to evaluate initial adequacy i
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.
d.
(Closed) LER 327/92-17, Inadvertent Auto Start Signal to the IB-B Centrifugal. Charging Pump. The issue involved an-ESF actuation resulting from an auto start signal to the IB-B CCP when the CCP undervoltage auxiliary relay latching mechanism unlatched. A labelling activity to identify relays in the 6.9 KV shutdown board logic cabinets was ongoing at the time of the relay actuation.
The licensee submitted a supplemental response to the LER dated September 13, 1993.
In the responses,' the licensee identified the apparent cause of this event to be an inadvertent relay actuation as a result of personnel error. The relay reset plunger was inadvertently engaged during labelling activities. The inspectors reviewed the licensee's evaluation of the event as well as activities associated with the evaluation. No discrepancies were noted.
b.
(Closed) LER 327/92-23, Low Ice Condenser Ice Weights Result in the Plant Operating Outside the Design Basis.
The issue involved an evaluation that determined that for some length of time during both Unit.1 Cycles 4 and 5, the ice condenser had operated below the required 993-pound design analysis assumption for ice basket weights.
Further investigation revealed that Unit 2 had also operated below the design assumption during Cycle l s
i.
l
!
'
,
The licensee performed technical evaluations of the extent of condition for both units' operation. The evaluations concluded.
l that the ice condensers remained OPERABLE during the periods in
'
question. NRC reviewed the licensee's evaluations and considered them acceptable. This evaluation was discussed in paragraph 8.c.
'
Other licensee corrective actions were reviewed and determined to be adequate.
l l
,
l c.
(Closed).LER 327/93-09:. Failure to Perform TS Surveillance for Three Pipe Support Snubbers. The snubbers were not listed on the i
'
applicable SI for visual inspection and were therefore not inspected as required.
Two of these, located on the Unit I and j
Unit 2 CVC systems, were discovered in 1983 but were not added to the-SI at that time due to a misinterpretation of the SE which
'
,
justified continued operation with the snubbers inoperable. The
third snubber, located on the Unit 1 SI system, was omitted from
,
the original SI list because of improper identification of
supports installed through the use of typical drawings for multiple locations. When the problem was identified, the licensee
revised Procedures 1-and 2-SI-MIN-000-001.0 to include the three snubbers. The snubbers were tested and found acceptable ~ and operable, which established that no undue loading had been imparted to the piping systems. The licensee compared the sis to design output documents, and found no new examples of omitted snubbers. All drawings of safety-related snubbers tha.t were formally identified by typical support numbers were upgraded.to.
provide unique identifiers.
d.
(Closed) LER 327/93-11, failure to Establish a Fire Watch as Required by Technical Specifications in Response to Breaching.a
-
The subject event was discovered by the-licensee during a fire protection walkdown. The issue involved the'
breaching of a fire barrier (1-A containment spray heat exchanger
.
!
room) without the proper compensatory measures being established.
The cause of the event was determined to be a lack of knowledge of fire protection requirements by offsite TVA personnel.
Fire detection inside the affected area and fire suppression outside the affected area was operable during the breach period.
Corrective actions for the event included entering the appropriate
,
TS LCO ACTION and the establishment of a roving fire watch.
In-addition, plant management re-emphasized the expectation that the responsible on-site manager will take action to ensure that proper training and oversight is provided to offsite organizations when working at Sequoyah.
e.
(Closed) LER 327/93-12, Failure to' Properly Identify and Plug a Steam Generator Tube That Was Subsequently Determined to Exceed the Technical Specification Plugging Limit. The issue involved the failure to adequately disposition an indication'on the SG No.
1, row 24, column 37 tube during the Unit 1 Cycle 5 refueling" l
outage. The root cause of the event was determined to be that the eddy-current coordinator did not ensure that the task requirements l
l'
I
!
,
l L
j i
and accountabilities were properly communicated to the eddy-current analyst.
Corrective actions for the event included l
procedure revisions to 0-MI-MXX-068-005.0, STEAM GENERATOR PRIMARY SIDE MAINTENANCE ACTIVITIES, Revision 5 to require signatures of
,
eddy-current coordinators and senior-analyst to ensure better communications. The inspector reviewed the LER closure package i.
and verified the revisions to the applicable procedure. The-
'
l inspectors concluded that a contributing cause to the event was the failure of TVA to monitor the contractors activities.
f.
(Closed) LER 327/93-13, Failure to perform a Fire Watch Within the Timeframe Required by Technical Specifications. The subject LER j
involved a missed TS required fire watch due to the patrol assigned to the EDG building not returning to their post after an
evacuation of the EDG building. The personnel left the assigned i
area due to the initiation of a fire panel alarm. The involved personnel mistook the panel alarm for the initiation of a carbon dioxide actuation / evacuation alarm. The existing panel alarm was actuated due to smoke from welding in a different site building.
The initial alarm was. reset by fire operations foreman in five L
minutes; however, the foreman failed to adequately inform the fire i
watches that they were to return to their assigned posts.
Corrective actions for the event included re-establishment of-the
fire watches after approximately two hours and twenty minutes after the initiation of the alarm, lesson plan revisions for fire watches to review the event and different alarms, and an issue identification to review separation of the EDG panel alarm from i
other areas of the plant. The inspectors reviewed the II-for the
)
event and verified the corrective actions taken to date.
The
inspector concluded that the licensee response was adequate.
g.
(Closed) LER 327/93-14, An Inadequate Ventilation Design Results
in Potential Inoperability of Vital Power Equipment.
The licensee
,
identified that the subject issue could result in vital 125 V DC power becoming inoperable for both trains of both units from a
,
single failure of the ventilation supplied to the battery rooms.
Corrective actions for the event included the implementation of j
new design configurations to provide correct train ventilation to
the affected equipment. The inspector reviewed the design changes and verified the completion of DCNs M-09367B and M-09369B which:
l were implemented during the Unit 2 forced 1993 outage.
In I
addition, to correcting the identified deficiency, the licensee i
also performed a study to determine if other safety-related i
ventilation systems had similar cross train problems. No other l
deficiencies were identified. The inspectors concluded that the
,
licensee's corrective actions for the event were adequate.
j h.
(Closed) LER 327/93-15, EDG Start as the Result of an Incorrectly Wired Current Transformer. The issue involved a trip of the 1A start bus alternate feeder breaker upon the start of the Unit I-RCP No. 1 motor. This action resulted in a loss of voltage to the
'
i
-.
--
-
-.
~
,.
.
l
[
)
IB-ts o.9 Kv shutdown board and subsequent start of all four diesels. The licensee determined that the event was caused by an incorrectly wired CT in the alternate feeder breaker protection circuitry.
The CT had recently been replaced due to previously
identified cracking.
Specifically, the cause of the event was a failure to uniquely identify the CT secondary wiring in accordance with site procedures. A contributing cause to the event was that
the PMT for the CT changeout was inadequate to identify the wiring
!
problem All other plant equipment functioned as required during
'
the event.
l
!
The inspectors reviewed and verified the corrective actions taken for the event.
Immediate corrective actions for the event
ir.cluded securing the EDGs which were not supplying voltage to the i
shutdown boards, restoring offsite power, and securing the final i
EDG. Additional corrective actions included the development of
)
procedures to adequately phase check all 6.9 KV cts which had not
been tested upon replacement.
Procedure revisions were also incorporated to clarify the requirement for-unique identification of each configuration change and revisions to SSP 6.31, i
MAINTENANCE MANAGEMENT SYSTEM PRE-OR POST-MAINTENANCE TESTING, to the proper PMT for CT replacement. The inspectors verified that proper testing of the applicable cts was performed or scheduled to be performed during the restart of Unit 2.
Other activities related to this event were also discussed in Inspection Reports 327, 328\\93-26 and 93-47.
)
i.
(Closed) LER 327/93-21, Failure to Perform a Surveillance in the Refueling Canal Because of Miscommunication. The issue involved the failure to perform TS Surveillance 4.9.1.2 concerning the refueling cavity boron concentration. The failure to perform the TS Surveillance was identified as Violation 328/93-33-04. The corrective actions for this event will be evaluated by the inspectors during the review of the licensee's response to the violation.
Within the areas inspected, no violations were identified.
8.
Action on Previous Inspection Findings (92701, 92702)
a.
(Closed) VIO 327, 328/92-06-02, Failure to Meet the Requirements of TS 3.6.5.3 for Ice Condenser Door Operability.
This event was i
the subject of an NRC Enforcement Conference. The issue involved l
a failure to comply with TS requirements for the operability of
'
ice condenser inlet doors on Units 1 and 2 for an unknown period of time.
Initial corrective actions involved the removal of sheet metal flashing beneath each of the lower ice doors to decrease the possibility of an interference fit if the floor should raise.
Interim operation of both units was possible due to compensatory measures involving an ice condenser floor monitoring system. At no time during the subsequent operation, with the monitoring l
l
.
,
.._.
.
.
.
l i
w
,
i
o
system in place, did the movement of the ice condenser floor
'
affect the operability of_the ice condenser doors. However, some-
,
floor movement was observed in both units. These issues were also previously discussed in Inspection Reports 327, 328/92-06 and 92-
'
10.
During the extended refueling outage in 1993, the licensee performed modifications on Unit 1 in an effort to resolve the l
fluctuation of the floor in the lower ice condenser. This significant problem was caused by water intrusion, freezing, and
'
expansion within the floor assembly and caused the lower-ice condenser concrete floor pad to raise up _resulting in the metal i
flashing at the base of the doors to interfere with the door's
-
operation. The water intrusion was determined to be introduced
during the servicing of the condenser during previous unit
outages. The servicing consisted of ice core thermal drilling and
,
reloading of borated ice and/or condenser component defrosting.
The inspectors reviewed the modifications performed on_the Unit 1
ice condenser. One portion of the modification involved drilling t
a hole in each condenser bay floor into the lower section of the I
foam concrete (insulating layer) to facilitate removal of any
_;
accumulated water.
During this drilling, the ice condenser floor
'
was defrosted allowing the buildup of ice under the floor to melt.
Significant amounts of water were removed from the holes (some in
excess of one hundred gallons per bay). After this water removal / draining process, the licensee sealed areas which were identified as potential inleakage paths. These paths were
'i identified at seams in the floor joints, floor' pad cracks, and interfaces of the floor pad with structural steel.
"
The licensee determined that_ part of the floor sealing material has the potential to separate from the floor during an accident
and potentially travel to the containment' sump. This could potentially lead to containment sump plugging. To prevent this,
,
'
the modification also installed a stainless steel mesh and additional sheet metal flashing.to hold down the sealing material should it become dislodged.
In addition to the above, a trial continuous drain system will be incorporated in one of the ice bays. This system is being tested to provide a_ continuous removal method for any buildup of water within the foam concrete layer.
The modification also adjusted ice condenser turning vanes to
.i preclude their interference with the floor pad.
!
Earlier in the outage, the inspectors performed an inspection in the Unit 1 ice condenser to review the implementation and adequacy j
of the modification. Several differences were identified
'
regarding the installation of the mesh and additional sheet metal hold down material.
These differences involved slight inconsistencies in the choice of fasteners; however, subsequent i
review of the workplan demonstrated the latitude for the craft to use any of the fasteners. The inspectors concluded that, ideally, each of the bays modifications should have been identical;
'
,
Lj
l
l
,
however, based on the inspector's review the final product of the
work accomplished to date, is adequate to perform the intended
,
function of the modification.
At the end of the inspection period, work activities involving the modifications were not yet completed. The inspectors will continue to monitor these modification activities during the
,
remainder of the Unit 1 Cycle 6 refueling outage and the success of the modifications during future inspections. The inspectors
'
noted that the floor position monitoring system will remain in service for the next operational cycle to monitor floor movement after implementation of the modifications.
l None of the above modifications were performed on the Unit 2 ice
condenser during.the extended 1993 forced outage.
The licensee intends to continue the use of the floor position monitoring
'
system throughout the current cycle and then implementing the identical modifications as performed Unit 1, pending their success.
The inspectors concluded that the licensee's corrective actions for the violation were adequate.
However, the inspectors also concluded that the licensee should continue the performance of on-
'
line floor position monitoring or equivalent, due to their current methodology for servicing the ice condensers.
..
b.
(Closed) VIO 328/92-17-02, Failure to Meet the Requirements of TS
.
LCOs 3.0.4 and 3.6.2.1.
Inoperable Containment Spray Suction
!
Valves. The issue involved Unit 2 entering Mode 4 and operating _
'
for a period of almost 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br /> with both trains of Containment
.;
Spray inoperable due to the pump suction valves from the RWST
being shut.
l
The licensee responded to the violation in a letter dated July 31,
!
1992. The incident resulted from inadequate configuration control
,
during testing of the containment spray system. This was caused
'
l by operators believing that a procedural exception was allowed for I
the testing activities, failing to fully appreciate the benefits of operational tools, and not questioning the valve positions.
Corrective measures included disallowing procedural exceptions to the configuration control process, requiring control board walkdowns conducted jointly by the outgoing and incoming shifts, and making journal entries for off-normal conditions.
l In addition to corrective actions specific to this violation, the
- !
i licensee has taken extensive actions to strengthen the configuration control process and its implementation. These-corrective measures are discussed in more detail in paragraph 8.e and included a systematic verification of the configuration of required components prior to restart, as well as actions to reinforce management's expectations for configuration control. The Nuclear Assurance organnation has also conducted substantial l
'
'
i review of the area as described in inspection report 327, 328/93-39.
.
The inspectors reviewed the licensee's implementation of
>
corrective actions for configuration control problems and.
concluded that actions are complete for this violation.
j c.
(Closed) URI 327,328/92-31-01, Determination of requirement of TS 4.6.5.1 during performance for "as found" ice condenser status.
This issue was identified during inspection activities discussed in inspection report 327, 328/92-31. The issue involved a question on whether the licensee was required to -follow TS 4.6.5.1 when they were conducting "as found" testing of the ice' condenser.
.
during an outage period. The inspectors noted that a Safety
'
Evaluation Report for Amendment No. 131 to the Unit 1 TS stated that " operability of the ice beds in the ice condenser requires that the ice inventory be distributed evenly throughout the ice condenser bays in containment..."
,
The inspectors held additional discussions with licensee personnel in December 1992. These issues were further discussed in inspection report 327, 328/92-36.
One evaluation addressed past operating conditions, i.e. operational periods prior to cycle 4 and cycle 5 refueling outages. That evaluation resulted in the
,
licensee notifying the NRC that they had operated outside the
,
design basis of the system. Also the evaluation concluded that a
'
10 CFR 50.59 evaluation was not required as the condition clearly represents an unreviewed safety question.
The. inspectors specifically discussed with the licensee why operation outside the design basis for the ice condenser was considered acceptable.
.
!
Licensee engineering personnel stated that their evaluation discussed the containment pressure analysis provided in section 6.2.1 of the FSAR and the computer programs used by Westinghouse (LOTIC 1) which determined ice condenser response during design basis accidents. The licensee's evaluation concluded 'that-sufficient conservatism was included in the ice condenser technical specification requirements such that'there would be an insignificant effect on the analyses, the peak accident pressure would be less than the design pressure, and there would be no
.
i
'
effect on peak temperature. The inspectors also questioned the licensee as to whether the "as found" ice condenser conditions-should be determined as stated in TS 4.6.5.1.d and they responded that only the "as left" ice condenser conditions are required to be verified as meeting the requirements of the TS.
The second evaluation that was discussed addressed how long Unit I~could
operate in its current operational cycle. That evaluation.
concluded that the unit should be able to operate until the end of its current operational cycle (scheduled to end on April 2,1993).
The conclusion was also based, in part, on the containment not :
exceeding its design pressure of 12 psig if a design-basis i
accident occurred during the remainder of the current operational
-
cycle. The inspectors stated that some of the information
.
-
presented in the two technical evaluations may not have been-
'
reviewed by the NRC staff.
NRC staff review of. the above issu'e was completed in September a
1993.
NRR concluded in an evaluation that "the licensee' performed
'
an acceptable analysis of the event." The evaluation. further concluded that TS 4.6.5.1.d'did not require an as-found test and.
evaluation. Allowed equivalent by-pass area for empty ice' baskets.
,
which supported a conclusion that a considerable number of low-
,
weight or empty baskets would be acceptable was also addressed.
Review of this unresolved item determined that no regulatory issue
<
existed.
d.
(Closed) URI 327, 328/92-35-03, Inadequate TS Surveillance Testing
.
Procedures Concerning the CREVS. The issue involved licensee testing of the CREVS in accordance with TS. Marginal testing had been accomplished in the past.
During this period, the inspectors reviewed the licensee's testing of the CREVS. The inspectors noted that the licensee had conducted maintenance to make the CR envelope boundary tighter._
These activities resulted in successful testing of_ trains A and B
of the CREVS on October 1, 1993, and September 25, 1993,.
.
'
respectively. The inspectors reviewed the test and verified that the TS acceptance criteria was _ met with respect to the CR envelope
,
boundary and each adjacent area. They also reviewed test conditions and verified necessary safety-related equipment running to support the test.
l e.
(Closed) VIO 327,328/92-36-01, Failure _to follow and/or inadequate procedures with regard to throttle valve settings.
.
.
This Escalated Enforcement Violation was identified in part.I of a
.I Notice of Violation issued on March 23, 1993. The issue involved-licensee identification of mispositioned throttle valves in the essential raw cooling water and component cooling water systems.
The problem was identified on and appeared to be limited to large butterfly type valves. The root cause of the violation was
identified as a failure to adequately account for slack
)
(handwheel / valve freeplay) during the configuration of the throttle valves. Specifically, procedural guidance was' inadequate to perform proper throttle valve configuration function. The licensee also identified weaknesses in the training of operators regarding the methods utilized for the setting of throttle valves.
A second part of the violation involved the failure to update Surveillance 0-SI-0PS-067-682.M due to an inadequate procedure.
SI-566 was inadequate, in that, it did not ensure that newly established valve throttle positions were correctly transferred to 0-SI-0PS-067-682.M.
'
Immediate corrective actions for the violation included a i
reverification of.the affected throttle valve positions.
A review
'
was also performed regarding the plant systems required to be
,
,
controlled by the plant configuration control process. This review identified additional components (handswitches) whicF were not in the licensee's configuration program. The inspectors reviewed the components and concluded that the licensee's actions to include them in the scope of their ' configuration program was
<
appropriate. Training for operators was also reviewed which.
utilized mock-ups to ensure consistent understanding on the methods used to set throttle valves.
In addition, SI-566 was revised to prohibit the closing of SI-566 prior to the updating of 0-SI-0PS-067-682.M. The inspector verified the completion / performance of the above actions and concluded that
,
'
these actions were adequate.
The violation response, dated April 21, 1993, also indicated that a full verification of the plant components within the configuration control process would be performed prior. to the restart of each respective unit. The inspectors confirmed the cortpletion of these verifications and discussed the discrepancies found with the licensee. Only two configuration discrepancies were identified during this verification and neither involved throttled valves.
.
The inspectors also reviewed an event discussed in Inspection Report 327, 328/93-39 in relation to the subject violation.
In that report, the Unit 2 reactor coolant drain ' tank 2B discharge throttle valve was identified as not being properly configured.
The inspectors specifically evaluated whether the root cause-of the previous violation.was related and if the corrective actions for the violation should have prevented the more recent issue.
The inspectors concluded that the. root causes for the'two. events were different and it was not reasonable to expect that the corrective actions taken should have precluded the later event.
However, the inspectors did recognize that both of the events resulted in the misoositioning of throttle valves due, in part, to operator performance \\ training issues. The licensee has been requested to address these aspects of the RCDT throttle valve mis-configuration in their response to violations issued in IR 93-39.
.
The inspectors will evaluate these aspects during review of the licensee's response to violation 328/93-39-01.
f.
(Closed) V10 328/92-38-01, Failure to maintain the Unit 2 RWST
'
solution temperature at or above 60 degrees F during Mode 1 operation for approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The issue involved the cooldown of the RWST'to below TS limits as a result of concurrent
.
performance of ERCW testing and a containment spray pump quarterly surveillance.
L The licensee responded to-the violation in a letter dated May 21, 1993.
Causes of the event were inadequate command and control.by Operations over m Jtiple testing activities; inadequate logkeeping
,
and shift turnovers; the failure to monitor RWST temperature over
'
several shift ; and an inadequate procedure for the containment
i
!
__
_
_
- - -
e
!
t
spray pump surveillance, which did not identify precautions with regard to system interactions. As corrective action, the operations personnel involved were counselled and other personnel were trained on the lessons learned. The following procedures were revised to include cautions to ensure that the interaction between the CS and ERCW systems does not occur in the future:
,
-
SI-566, ERCW FLOW VERIFICATION, Revision 22, PCF 93-0033
-
2-SI-SXI-067-001.A, INSERVICE PRESSURE TEST OF ERCW SUPPLY HEADER 2A-A, Revision 1, PCF 93-0063
-
2-SI-SXI-067-001.B, INSERVICE PRESSURE TEST OF ERCW SUPPLY HEADER 2B-B, Revision 1, PCF 93-0062
-
2-SI-SXP-072-001.A, CS PUMP 2A-A QUARTERLY OPERABILITY TEST, i
Revision 0, PCF 93-0017
!
-
2-SI-SXP-072-001.B, CS PUMP 2B-B QUARTERLY OPERABILITY TEST, Revision 0, PCF 93-0018
-
1-SI-SXI-067-001.A, INSERVICE PRESSURE TEST OF ERCW SUPPLY HEADER 1A-A, Revision 1, PCF 93-0064
-
1-SI-SXI-067-001.B, INSERVICE PRESSURE TEST OF ERCW SUPPLY
'
HEADER 1B-B, Revision 1, PCF 93-0065
)
-
1-SI-SXP-072-001.A, CS PUMP 1A-A QUARTERLY OPERABILITY TEST, Revision 1, PCF 93-0020
{
-
1-SI-SXP-072-001.B, CS PUMP IB-B QUARTERLY OPERABILITY TEST, Revision 2, PCF 93-00I9 j
,
l The inspector reviewed the above procedure changes, and found them to be technically adequate. However, the inspector noted a minor
,
administrative error, in that the PCF numbers for 1-SI-SXP-067-i
'
001.A and 001.8 were reversed on the PCFs. This was identified to the licensee and promptly corrected.
In addition to corrective actions specific to this violation, the
'
licensee has taken broad-based actions to strengthen overall performance in the Operations area. The inspectors reviewed the licensee's implementation of corrective actions and concluded that actions are complete for this violation.
g.
(Closed) VIO 328/93-02-06, Failure to Follow Multiple Operations Procedures Associated with a Dual Unit Transient on December 31, 1992. This Escalated Enforcement Violation was identified in part III of a Notice of Violation issued on March 23, 1993.
All of the i
examples were related to a dual unit transient which occurred on December 31, 1992. The inspectors reviewed these examples and the licensee's corrective actions as follows:
__
_ -
,
,
III.A.I. III.A.2.a. and III.A.2.b i
!
A0I 34, EMERGENCY B0 RATION, Revision 7, provides the necessary actions to initiate emergency boration when.the reactor is shutdown. This example of the violation involved the failure of'
the operators to follow the requirements of A01-34,.in-that, when i
the RCS temperature dropped to 537 degrees F, the operators used a i
normal boration flowpath, rather than the emergency. boration i
flowpath as required by the AOI.
j A01-34 also provides instructions to operators to adequately
realign and restore components utilized in. normal charging
'
operations and boration flowpaths. This example of the violation
,
involved the failure of the operators to implement specific steps j
in the A0I as follows:
i (1)
RWST suction valve handswitches, 2-HS-62-135 and 136 were
.
not pulled to the A-P AUTO position after manipulation as
required.
(2)
During VCT/RWST valve manipulations, the operator
inadvertently closed the VCT outlet suction supply valves,
2-LCV-62-132 and 133.
The licensee concluded that the root cause for these examples of the violation for failure to follow the emergency boration
]j procedure was personnel error on the part of the operzting crew.
j The crew incorrectly thought that use of the normal boration flowpath was acceptable.
In addition, this error of utilizing the normal boration flowpath set up plant conditions' which allowed for
,
another operator error to occur in the realignment of the volume
'
control tank outlet valves.
In addition to the above, the licensee concluded that an event response weakness was a lack of training, specifically, with minimum shift complements under dual
,
unit transients.
'
Corrective actions for the above examples included counseling of the involved operators regarding the importance of following procedures. These individuals were, in turn, responsible for developing a lessons learned training for all of the operations crews. The inspectors attended one.of the training sessions _and concluded that it was well planned and effectively implemented.
The licensee also established an increased staffing level to provide two reactor operators per unit at all times, until assurances were in place such that it was demonstrated that a minimum shift complement could effectively handle dual unit transients.
In addition,- the ' inspectors verified that training was conducted for all licensed operators on the simulator utilizing varying. shift complements under transient conditions.
The inspectors concluded the licensee's corrective actions-specific to the above violation examples were adequate.
l l
.
_
_
.__
J
)
i
37 j
In addition to the above, corrective actions for these violation--
_j examples also include broad scope improvements to the operations i
organization.
Some of-these evaluations / improvements included
-
processes for continuous coaching to provide constant i
reinforcement and immediate feedback; extended round-the-clock i
i observations in the main control room; an operations restart readiness team assessment; and site quality reviews. The licensee
'
intends on continuing actions regarding the long-term improvement j
process for operations for an extended period of time. The inspectors reviewed the aggregate effect of the operations improvements taken to date. The inspectors concluded that the licensee's long term improvement actions were sufficient to close these examples of the violation.
III.A.3
,
i The Sequoyah FSAR Section 9.2.1.3.3, states that the purpose of l
the TBBPs are provide the additional head necessary to overcome l
high head loss through the thermal barrier.
Each of the TBBP.
motors receive electric power from normal-or emergency power i
sources. TVA design criteria SQN-DC-V-13.9.9 specifies that the
!
TBBPs shall be loaded to the diesel generators simultaneously with the CCS pumps after a loss of offsite power.
Placement of the CR TBBP handswitches in the A-P AUTO positions ensures the above requirements are met. The operating procedures were inadequate, in that, the subject handswitches were aligned in the A-AUTO position prohibiting the accomplishment of the previously l
described function.
The licensee concluded that the root cause of the incorrect TBBP
,
handswitch positions in the system operating instruction resulted i
from an inadequate procedure revision.
Reviews of the procedure I
revision package also failed to identify the error. Corrective actions for the above violation included procedure revisions to correctly reflect the TBBP handswitch position requirement.
Walkdowns were performed by the licensee to determine the extent of condition for CR handswitch position discrepancies.
Four additional components were determined to have handswitches in positions different than that described in the applicable procedure.
These components were the main CR AHUs, the electrical board room AHUs, the upper containment cooling units, and the lower containment cooling units. The licensee evaluated these conditions and determined that they did not adversely affect plant operations. Subsequent monitoring of numerous CR handswitch i
l positions by the inspectors did not reveal any configuration l
discrepancies.
The licensee also performed a procedural review and walkdown to
,
compare design output documents for verification with design requirements. This included an evaluation of 1,493 handswitches by the operations department.
The Technical Support organization also provided an independent assessment of this area. These
,
t
- --
!
,
i
.
l
'
activities concluded that plant procedures did not always clearly identify the condition or position which handswitches should be left.
The discrepancies were provided to the operations procedure supervisor for use during future revisions.
In addition, eleven i
drawing deviations were generated to resolve schematic, logic, and s
switch development deficiencies which were identified during the i
review. The inspectors concluded that'the corrective actions j
taken by the licensee for the violation were adequate.
'
In addition, the inspectors reviewed the resolution of PER SQPER930259.
This PER was due to the identification that during a
control room abandonment and a subsequent loss of offsite power scenario, the TBBPs are locked out from auxiliary control room i
(ACR) operation for a blackout condition until the blackout is l
reset.
In addition, the TBBP's were identified as not being
!
automatically sequenced after a blackout.
Reviews indicated that I
other major equipment such as AFW, CVCS, component cooling etc.,
'
all automatically sequenced on following the subject events.
The
,
PER was reviewed by engineering and the resolution was presented j
to MRRC. The engineering analysis indicated that during a control room abandonment (resulting from a 10 CFR 50 Appendix R event) and a subsequent loss of offsite power, the scenario was outside the design basis accident. This conclusion was based on applicable design criterion not requiring a design basis accident to occur coincidentally with a 10 CFR Appendix R event and a subsequent loss of offsite power. This, in conjunction with the CCPs and the component cooling pumps being automatically sequenced onto the EDG power sources, would ensure that sufficient cooling would be supplied to the RCP seals, given the above scenario.
The inspectors reviewed the applicable design criteria and the FSAR and concluded that the licensee's resolution to the PER was adequate.
However, the inspectors also concluded that the licensee should consider the incorporation of the automatic function for the TBBPs or revise the FSAR and\\or system design criteria to clarify the actual functions required in the auxiliary control room in conjunction with a loss of offsite power. This was discussed with licensee management, who agreed to review the matter based on the inspector's comments.
III.A.4 This example of the violation was issued due to an inadequate
performance of a post trip review (PTR).
SSP-12.9, INCIDENT i
INVESTIGATIONS AND ROOT CAUSE ANALYSIS, provided detailed guidance on the PTR process.
The PTR pertaining to the December 31, 1992, dual unit trip was inadequate. The inadequacies were related to a failure to properly analyze VCT ievel chart recorder traces to
'
corroborate assemptions made during the PTR. The licensee also concluded that the PTR team's performance was affected by the team member having to perform collateral duties during the review process.
. _ _
_ _ _ _ _
The inspectors reviewed the corrective actions for the violation which included procedure revisions to SSP-3.4, CORRECTIVE ACTION, to require an event critique with the involved personnel and PTR-team prior to a review by the Plant Operation Review Committee.
In addition, the completion of an event and causal factor chart for unit restart was also made a requirement. Management emphasis was also placed on shielding the PTR members from collateral duties and proper review and disposition of event anomalies.
During subsequent observations of PTR team members during response to plant transients, the inspectors monitored the adequacy of the team's reviews. The inspectors noted that increased attention was given to the review of raw plant data such as strip charts and alarm printouts to determine event root cause.
In addition, the inspectors reviewed the licensee's Incident Investigation Notebook, Revision 0.
This notebook, which was approved by the Site Quality Manager on August 31, 1993, contained guidelines for the PTR/II event report process.
In addition, it contained necessary checklists to ensure proper reviews and other information to assist in the II process. The inspectors concluded that the notebook provided adequate guidance for the PTR team members to perform their function.
l The inspectors concluded that the corrective actions taken for the violation were adequate. The inspectors will closely monitor the l
PTR team during future plant transients which require the process.
h.
(Closed) VIO 328/93-02-07, Ineffective corrective actions related to the thermal barrier booster pump handswitch. This Escalated i
Enforcement Violation was identified in part III of a Notice of l
Violation issued on March 23, 1993.
l l
III.B The following example was a violation of 10 CFR Part 50, Appendix B, Criterion XVI, for failure to take adequate corrective actions for conditions adverse to quality (CAQ).
Specifically, a CAQ l
existed since March 14, 1992, when the 2A-A TBBP handswitch was
)
l recognized as being misaligned during testing. The resolution to the test deficiency did not correct the problem.
The identical CAQ was again identified during the December 31, 1992 event.
l The licensee's root cause for failure to recognize and resolve the handswitch deficiency was personnel inattention to detail.
It was i
further concluded that the test deficiency had provided an opportunity to discover the improper switch position.
Immediate i
corrective actions for the above example included training for the involved personnel and revising the procedure controlling TBBP
'
handswitch position to reflect the design required position. The licensee also recognized that additional broad corrective actions, which would also improve future personnel performance during similar activities, were needed. These included many initiatives
..
-.
-
_
a
,
.
40-l
,
to strengthen the overall performance of the plant workforce.
Some of these activities included management reinforcement of
expectations, department standdowns, accountability training, and evaluations of site personnel to identify weak areas.needing
,
improvement. The inspectors reviewed the licensee's progress with
'
these efforts and concluded that adequate effort has been implemented to close the violation.
i.
(Closed) VIO 327, 328/93-09-01, Failure to provide for or maintain l
adequate configuration control of safety-related valves and power
supplies. The issue involved the licensee's discovery of two i
safety-related power fuses and seven safety-related valves and two
,
t safety-related power fuses which were not configured as required by the system alignment checklists. The misconfigured fuses resulted from the incorrect type of fuse being installed during a checklist performance. Six of the seven total misconfigured valves were required to be locked but were not.
Five of the i
misconfigured valves were containment isolation valves.
'
The licensee responded to the violation in a letter dated May 21, 1993. Although the cause for the violation could not be explicitly determined, the licensee identified several possible
,
causes and took actions to address each. Corrective actions specific to this violation included reviews and upgrades of operational checklists to eliminate contradictory configuration l
requirements, implementatian of a procedure for better controlling
locked valves (SSP-12.64, LOCKED-VALVE PROGRAM, Revision 0),
development of a more positive method for locking T-handled valves
through the use of cables (DCN S-09565A), and issuance of Revision 3 of 0-SI-0PS-000-187.0, CONTAINMENT INSPECTION, to improve the sequencing of containment closecut and containment integrity verification.
t i
In addition to corrective actions specific to this violation, the licensee has taken corrective actions to strengthen the
,
configuration control process and its implementation.
These t
extensive corrective measures are discussed in more detail in
paragraph 8.e and included a systematic verification of the configuration of required components prior to restart, as well. as actions to reinforce management's expectations for configuration control. The Nuclear Assurance organization has also conducted
,
substantial review of the area, as described in inspection _ report
!
327, 328/93-39.
The inspectors reviewed the licensee's implementation of
corrective actions for configuration control problems and determined that actions are complete for this violation.
'
i j.
(Closed) VIO 327, 328/93-09-03, Failure to provide adequate
instructions for performance of safety-related instrument l
calibrations within required intervals. The issue involved more
than 50 safety-related non-TS instrument calibrations which were P
--
_
-
.
v
'
I
,
i deferred beyond the required surveillance interval without appropriate technical justification.
In response to this
,
violation, the licensee developed a list of components with j
delinquent calibrations. Those which are safety-related,
'
compliance, or PAM instruments will either be calibrated prior to restart or have an appropriate technical justification for the i
deferral.
Procedure SSP-8.2, SURVEILLANCE TEST PROGRAM, was
revised to require a technical evaluation before allowing deferral j
(Revision 1, issued June 30,1993). The inspectors verified that i
late non-TS SI's were either performed or had a technical i
evaluation in place before restart.
]
k.
(Closed) VIO 327/93-23-01, Failure to Ensure that all Fuel Handling Was Performed in Accordance with SSP-12.1. The issue i
involved a fuel handling supervisor failing to comply with load limits during the recovery of a tipped fuel assembly, due to poor command and control of the evolution and an inadequate safety attitude. In response to this event, appropriate personnel actions
,
were taken with respect to the individuals involved.
Before proceeding with the fuel assembly recovery efforts, the licensee
,
took measures to ensure adequate command and control. A second
SR0 was assigned the duties of test director, in addition to the
<
fuel handling SRO. Continuous communications were established via
!
headphones between the test director and the control room, and l
thorough pre-test briefings were conducted before each evolution.
The inspector witnessed significant portions of these evolutions
-
and found them to be well controlled.
1.
(Closed) Violation 327/93-23-03, Failure to Adequately Implement Corrective Action For Identification and Removal of Foreign Material in the Reactor Vessel Prior to the Unit 1, Cycle 6 Core Reload.
The subject event resulted in a fuel assembly tilting out of position during the Unit 1, Cycle 6 refueling outage. The violation was for failure to take appropriate corrective actions for a previous (Unit 1, Cycle 5) foreign material event.
During the previous event, the licensee identified foreign material in the Unit I reactor vessel after the initiation of core reload.
Corrective actions for the previous event included procedure revisions to ensure timely reviews of video to be performed prior to the commencement of fuel reload.
However, prior to the Unit 1, Cycle 6 refueling outage, the responsibility for foreign material inspections was transferred to the reactor engineering group During this transfer of responsibilities, video taping, which
,
provided additional review opportunities, was not included in the reactor engineering procedural requirements.
The inspectors determined that these additional reviews may not have positively
'
precluded the Cycle 6 event; however, the taping would have
,
provided an opportunity for identification.
The inspectors reviewed the licensee's corrective actions for the event. The inspectors verified revisions were incorporated in 0-
^
.
i
-
,
RT-NUC-000-002.0, CORE RECONFIGURATION, Revision 5, to require a lower core plate inspection, evaluation, and videotape of the
>
inspection for independent revies by the Quality Assurance
organization.
In addition, reactor engineering group personnel
who are responsible for performing the lower core plate -
inspections were trained utilizing previous video taped
!
inspections to strengthen their ability to identify foreign objects. The inspectors concluded that these changes will provide
~'
the licensee with better opportunities to identify and remove.
foreign material from the lower core plate prior to the initiation
'
of fuel reload.
The inspectors also reviewed the origin of the steam generator ll expander plug which caused the tilting of the fuel assembly during
.
the Unit 1 Cycle 6 refueling outage. The subject expander plug,
was identified as one which was attempted to be removed during the l
Unit 1 Cycle 4 refueling outage. Multiple SG plugs were being removed due to industry failures being identified with Inconel 600
SG plugs. The subject pluo was removed via a method which
involved mechanical elongation and retraction of the plug.
J However, during the process, failures occurred on the removal of-
'
four of these plugs. The failures involved the cracking.of the
end of the SG tube plug such that the end cap and the expa" der
,
device could not be retracted.
In two of these cases, the licensee could visually verify that the cap and plug devise were
in the tube prior to plugging of the tubes. However, in the-
remaining two cases, the licensee could not visually verify the location of the cap and plug device before plugging of the tubes.
,
'
.
The licensee's hvestigation-concluded that the SG tube plugging
'
expander device, which caused the Unit 1 Cycle 6 event was one of i
those which could not be accounted for. The licensee also concluded that the device must have fallen out of the tube during
the removal process undetected and inspections during the Cycle 4
'
work failed to identify the location of the device.
Corrective
>
actions being taken to preclude similar problems with FME during
SG tube plug removal include the using other methoG2 such as
!
drilling with vacuum attachments.
!
Based or the expander plug being identified in the RCS, the inspectors questioned whether the other expander plug and related i
materials were adequately addressed by the licensee.
i Specifically, the licensee now had evidence that the subject foreign materials could be in the RCS, therefore the inspectors
,
concluded that a safety assessment should be performed in accordance with 10 CFR 50.59 to ensure that the material would not interfere with the safe operation of the facility.
In addition, the inspectors also reviewed the_ method by which the licensee tracked and assessed foreign material in the RCS for each unit.
- The licensee had previously identified various foreign material in both units' RCS. However, based on discussions with technical
'
>
k
-
-
.
.
,
i
,
support, reactor engineering, and engineering personnel,' the
';
inspectors identified that the total amount of foreign materials
,
was not being tracked by the licensee via one system or by one
designated organization. These issues were brought to the
!
licensee's immediate attention. The. inspectors requested that the-licensee provide the necessary documentation to support operation j
with the known foreign material in each. unit's RCS.
The licensee reviewed the inspectors, concerns and agreed that one
)
designated owner should monitor-the foreign materials in'each t
Unit's RCS such that the individual and aggregate effects of the-material could be assessed and periodically reviewed.
In i
addition, the licensee agreed that the remaining SG expander plug
'
device and the other material should be added 'to the Unit 1 RCS j
inventory based on the Unit I fuel assembly tilting event. The
inspectors reviewed the inventories for both Unit 1 and 2 and the.
evaluations for the known materials in each unit's RCS and j
concluded that the licensee had adequately addressed the concern
'
by the end of the inspection period.
The inspectors did not
identify any discrepancies during a review of the licensee's -
'
documentation.
The inspectors concluded that the actions taken by the licensee
for the subject violation were adequate. However, the inspectors also concluded that, prior to this event, the total foreign material inventories and safety justifications were not being i
monitored via one program / owner or implemented by an organized-i method.
By the end of the inspection period, the inspectors
'
concluded that the licensee had adequately organized and improved
-
the method for tracking the known foreign objects in each unit's RCS.
m.
(0 pen) IFI 327,328/93-33-06, NRC Identification of Unevaluated Boric Acid Conditions on the Inside of the Unit 1 Containment j
Vessel Steel Liner and the Design of the Liner Flashing. During
- !
tours of the Unit I lower containment in July of 1993, the j
inspectors identified several areas where boric acid solution i
appeared to have been accumulating behind the stainless steel
~
flashing liner which partially covers ~ the inside of the
.
containment liner in the raceway. The flashing is approximately
?
five feet tall. and runs the circumference of the raceway. Due to-
- !
deterioration af RTV (room temperature vulcanizing) sealing compound between the flashing and the containment liner, boric acid leakage from various components above the raceway, had-previously migrated down the liner and behind the flashing. The inspectors were concerned that this boric acid solution on the -
containment liner could result in degradation to the integrity of the liner if not removed.
l The licensee initiated a work plan to inspect the condition
.
identified by the inspectors in Unit 1.
The licensee removed the
.
!/
l
!.
44-i flashing from the worst case area.
Inspections identified a small amount of boric acid solution at the liner to raceway floor joint.
l-The solution appears to have collected in a low point formed at a
containment liner seam location.
Some corrosion was identified l
once the solution was removed. The licensee evaluated the as-i found condition as oeing limited to surface corrosion. The l
licensee initiated action to clean, recoat with the appropriate
,.
l protective coating and resealing of the flashing to liner joint.
!
- .
The inspectors noted that the majority of the liner surface area
,
behind the removed -flashing appears to not have been exposed to the boric acid soWtion due to an adhesive coating applied to retain insulation to the liner. The licensee will continue to
-
inspect other potential areas in Unit I for evidence of' corrosion -
and evaluate its effect on the containment liner. The inspectors-will continue to monitor the licensee *s actions on Unit l'during future inspections.
.
Inspections were performed in Unit 2 to identify evidence where boric acid solution could have migrated behind the liner.
No
specific areas were identified; however, several areas on the top flashing to liner RTV were found deteriorated. The licensee performed extensive re-sealing of both the tcp and bottom flashing
joints. The inspector verified the repair of the RTV in the identified areas during subsequent inspections. The inspectors-concluded that there was no direct evidence that boric acid had
'
migrated behind the Unit 2 flashing.
However, the inspectors questioned whether liner inspections were l
warranted based on previous flooding events in the raceway or prior boric acid leakage which may have occurred and then cleaned up. The inspectors were concerned that these previous events may have exposed the bottom portions of the liner (behind the
.i flashing) to an environment susceptible to corrosion.
In addition, the inspectors reviewed SI-254, CONTAINMENT VESSEL AND SHIELD BUILDING INTEGRITY VERIFICATION, Revision 5, and concluded
.
that inspections behind the flashing were not being accomplished'
'
on a periodic basis. These issues were brought to managements'
attention. The licensee reviewed other inspection records and noted that an inspection was performed in April 1992 which involved the removal of three areas of flashing from the Unit 2 raceway. No degradation was identified during the inspection.
The licensee had performed the inspection in response to NRC
,
Information Notice 89-79, DEGRADED.C0ATINGS AND CORROSION OF STEEL CONTAINMENT VESSELS. Based on these inspections, the inspectors concluded that no immediate concerns were identified for operation of Unit 2 for the remainder of the fuel cycle.
The inspectors also reviewed the requirements of 10 CFR 50, Appendix J, which requires, in part, that a general inspection of the accessible interior and exterior surfaces of the containment-structure be performed.
In addition, TS Surveillance Requirement 4.6.I.6 requires, in part, that a visual inspection of the. exposed
'
'
i l
l
r accessible interior and exterior surfaces of the containment j
vessel be performed. The inspectors concluded that due to the
!
installation of the flashing and insulation, the licensee's inspections were in accordance.with the above specific
,
requirements. However, the inspectors also.oncluded that periodic inspections behind the flashing would be prudent.
The
,
inspector considered future inspections especially judicious i
because of raceway flooding due to ccntinuing cooler leakage problems and boron leakage from overhead components. This
conclusion was discussed with the licensee. The licensee agreed
!_
that periodic inspections were warranted and would be incorporated
-
into the appropriate procedures.
The inspectors will verify the
!
incorperation of the liner examinations during future inspections.
!
i l-l Based on the above, the inspectors concluded that the licensee's
!
action for Unit 2 restart were appropriate.
However, the
'
inspectors also concluded that more detailed examinations of the liner in the subject area were necessary during the Unit 2, Cycle
!
6 refueling outage. The inspectors will review the condition of l
the Unit I liner when the licensee's inspections and corrective
action are completed. A weakness was identified regarding the t
lack of a periodic corrosion inspection of the containment liner
,
behind installed stainless steel flashing and a failure of the
licensee to identify the potential for a degraded condition.
,
a n.
(0 pen) DEV 327, 328/93-33-09, Deviations from the Licensee's Current FSAR and Plant Configuretion Affecting the Nuclear
,
Instrumentation and Sampling Systems. The issue involved discrepancies between the FSAR ano' actual plant conditions identified during an NRC walkdown of these systems. The specific i
,
deficiencies identified by the NRC reflected a larger issue of
'
licensee insensitivity to the need to update the FSAR to reflect
'
actual plant configuration and operating practices. At the time of this inspection, the specific deficiencie:. identified in the
'
deviation were being corrected, and more extensive corrective.
f actions were being developed and. implemented.
Although resolution i
of the issue will not be complete prior to Unit 2 restart, the inspectors noted that the licensee's restart readiness review of each plant system included FSAR issues. NRC inspectors observed a significant number of the system reviews and identified no problems with the dispositioning of FSAR items. Therefore the i
status of this item is acceptable for restart.
,
i o.
(Closed) URI 327,328/93-39-03: Evaluation of Adequacy of Procedures for EDG Governor Sett;ng. The issue involved the overspeed trip of the 2A-A EDG on August 31, 1993 ~during calibration of the hydraulic governor. The overspeed trip i
-
resulted when an operator misinterpreted a hand signal from the
!
test director and inappropriately turned the voltage regulator.
switch to off. At the conclusion of the previous inspection j
period, review of licensee performance and procedures was ongoing.
-j
.
l
!
!
]
,
i l
)
During this inspection period, the inspector continued to I
investigate the cause and circumstances of the EDG overspeed trip j
by reviewing relevint documentation and interviewing cognizant j
testing and operatiens personnel. The following documents which
controlled the original evolution were reviewed by the inspector:
l Work Order 93-06837-00
-
-
501 82.3, DIESEL GENERATOR 2A-A, Revision 4
_)
i The inspector concluded that neither the WO nor the SOI contained
'
'
clear, detailed instruction steps for the evolution being performed. The WO directed only that." preliminary governor
adjustments" be made before requesting Operations to tie the EDG to the grid. However, the WO did not specify what the adjustments-
~
were or how they were to be performed.
Section H of S01-83.2 covered troubleshooting of the EDG, but contained no specific troubleshooting instructions beyond prescribing the means for
_i changing engine speed while in hydraulic and electric governor j
control.
Step-by-step directions for the calibration process were
being provided verbally by the System Engineer.
i From the wording of the WO, it appeared that the governor
,
adjustments should be completed before placing the regulator handswitch to automatic.
However, the SOI did allow control of-l engine speed via the hydraulic governor control switch either with
!
or without the voltage regulator.
i The inspector concluded that the primary cause of the event was
,
the lack of clear and detailed instruction steps for the governor
calibration. This was identified as a weakness.
Poor communication and control of the work activity were contributing factors. Although the System Engineer was cognizant of the l
necessary actions to be performed to complete the governor calibration, personnel were being directed through a complex-i evolution using hand signals to communicate in a very noisy
environment.
In such an environment, where effective. verbal communication is not possible, the inspector concluded that clear j
understanding of alternate communication processes for equipment manipulations are essential.
Further, the action of the operator indicated that he did not fully understand the evolution and the expected response of the j
equipment before turning the regulator off. This' indicated a i
weakness in pre-job briefing, as well as a lack of' sensitivity to'
'
the responsibility of Operations for the operation of plant equipment.
On September 3, 1993, the inspector witnessed portions of the
reperformance of the governor calibration evolution. A new i
procedure, 2-MI-EDG-082-001.A, CALIBRATION OF DIESEL GENERATOR 2A-A ACTUATORS, was issued to control the activity and included I
,
i
-
detailed steps for performing the-required calibrations.. The
testing was well controlled and proceeded smoothly. Several minor
,
errors in the equipment nomenclature used in the procedure were
!
identified by the licensee during the perfermance of the test, and l
l were properly addressed through the establisi.ed procedure change i
process.
j i
'
p.
Status Review of NRC Bulletin 93-02
)
l During the inspection period, the inspectors performed a restart status review of Bulletin 93-02, " Debris Plugging of Emergency Core Cooling Suction Strainers," which was issued on May 11, 1993.
.
This inspection did not include review of permanent material inside the containment structure which might cause sump plugging
,
issues such as the effect of dislodged coatings. These and other l
similar aspects were considered outside of the scope of the Bulletin; however, recent inspections.in these areas were i
discussed in detail in paragraph 4.c.
- The Bulletin requested that licensees respcnd within 30 days
!
stating whether fibrous air filters or other temporary sources of fibrous material, not designed to withstand a LOCA, are installed
or stored in primary' containment.
It also required licensees to take any immediate compensatory measures that may be required to
assure functional capability of the emergency core cooling l
systems, and to take prompt action to remove any such material.
The intent of the Bulletin was to have the licensee review the use i
of filters or other temporary material which would be outside of -
the scope of their current safety analysis regarding. containment
- !
sump plugging.
TVA responded to the bulletin on June 9, 1993. According to-the l
licensee's response, fibrous air filters are not installed in primary containment during normal plant' operations (i.e., Modes 1
through 4), but are used during outages.
During outages, the use
'
of equipment containing fibrous material is controlled by a procedure for the particular job and its removal 1.s-' controlled by i
a cleanliness inspection of the work are following its use.
In addition, at the end of an outage, a final inspection is performed
-!
using Surveillance Instruction 0-SI-0PS-000-187.0, " Containment Inspection," before entry into Mode 4 from Mode 5.
This procedure ensures that equipment, dirt,.and tools have been removed to i
prevent blockage of the containment sump screen in accordance with
.!
Technical Specification Surveillance Requirement 4.5.2.c.
The Office of Nuclear Reactor Regulation, NRC formally acknowledged receipt of TVA's response by issuing a memorandum dated July 28, 1993. This memorandum indicated that based on the above information, the licensee's response was satisfactory. As of the end of the inspection period, the inspectors' review of the licensee's response and did not identify any issues which would j
impact the restart of either unit.
i l
i i
,.
.
i
!
q.
Status Review of NRC Generic Letter 93-04, Rod Control System Failures at Westinghouse Plants.
The licensee responded to the Westinghouse Nuclear Safety Advisory l
Letter 93-007, " Rod Control System Failure," dated June 11, 1993,
-
by addressing the recommendations 1, 2, and 4 through NER
Evaluation Form, NER No. 930608001, dated July 20, 1993.
In
addition, Sequoyah has responded to Generic Letter 93-04, " Rod
Control System Failure and Withdrawal of Rod Control Cluster
,
Assemblies," by transmittal of TVA memorandum dated August 5, 1993.
The inspectors reviewed the licensee's actions of the submittal.
An action plan was developed by TVA, " Generic Letter 93-04, Milestones Required To Support Action Plan Schedule," and had been
,
updated to reflect the current status of actions. As interim j
measures, the licensee has reviewed surveillance and operations r
procedures and incorporated training to ensure that operators are
'
aware of the Salem rod control system failure event.
!
Subsequently, the Westinghouse Owners Group (WOG) met with NRC and industry representatives on September 13, to discuss the i
development of generic approaches to permanently resolve the rod movement issue. On September 20, 1993, the licensee issued a second response to the Generic Letter. This response indicated
,
that the WOG concluded that General Design Criteria (GDC) 25
'
continued to be satisfied based on the failure exhibited during the Salem event. The licensee's response also indicated that Sequoyah will implement a new current order test (current order traces from each group following each refueling outage) to ensure detectability of abnormalities.
In addition, Sequoyah plans to modify the rod control system current order' timing to prevent any uncontrolled asymmetric rod withdrawal in the event of the failure _
l; identified by the Generic letter.
The schedule for implementation
'
of the long-term action is that the new current order testing to be completed during the current Unit 1, Cycle 6 refueling outage
and for Unit 2, the Cycle 6 refueling outage scheduled for April
'
1994.
The proposed modifications are scheduled during each unit's Cycle 7 refueling outage.
At the end of the inspection period, the licensee was developing
guidance to implement the WOG recommendations pertaining the issue'
in line with the above schedule. -The inspectors concluded'that the licensee had implemented the appropriate interim actions
,
necessary for restart. ~ Initial NRC evaluations of the licensee's i
second submittal indicated that the response was acceptable.
The NRC will continue to monitor the licensee's permanent resolution
'
of the issue in line with generic industry recommendations.
Within the areas inspected, no violations were identifie i
9.
Restart Review Activities i
During this period, inspection activities continued regarding review of i
the licensee's restart plan. These inspections included verifications
,
that the licensee was following their plan in the backlog and operations-l areas.
Initial inspections of the licensee's restart plan were
.
addressed in inspection reports 327, 328/93-16; 327, 328/93-23; and 327,
-l 328/93-33.
i a.
Review of Backlog Evaluation Process (71707)
During this inspection period, the inspectors focused on MRRC reviews being conducted to determine system and department
,
readiness.
In addition, the inspectors specifically reviewed the listing on backlog areas discussed with the NRC in a public meeting on August 5, 1993.
Several of the backlog area reviews were discussed in inspection report 327,328/93-39.
The inspectors completed their reviews of the 50 backlog items with discussion of post restart status as follows:
(1)
WR/W0s - This area included the population of open requests to perform maintenance, modification, or investigative activities on plant process equipment using the work request / work order process as described in site administrative procedures.
This area had received significant NRC review during system reviews over the past three months. At the time of inspection the non-outage corrective' maintenance backlog for the plant was approximately 3400. Approximately 1000 'of this backlog were restart items. The licensee's goal of less that 800 average non-outage corrective maintenance backlog was anticipated to be reached by October 1994. The inspectors reviewed the licensee's action plan for this area and will continue to monitor licensee progress toward this goal during future inspections.
(2)
JC0/EE - This area involves Justification for Continued Operation and/or Engineering Evaluations. At the time of review, backlog of JCOs was four. The inspectors reviewed i
this backlog.
The inspectors noted that one JC0 was inadequate in that it referenced an unissued NRC document in the justification area. NRC staff review of the JC0 concluded that it was not a restart issue. The inspectors
'
noted that control of JC0s had been incorporated into a new
'
administrative procedure in August 1993. _This procedure placed improved controls on the licensee's use of JC0s.
~
,
(4)
Open DCNs - This area includes the summary status of open
'i design change notices. At the time of review, backlog in
'
,
this area for Unit 2 and common was 135 items. Of these, 33 were either not safety-related or security upgrades. A
'
,
~
?
sample of the remaining DCNs were selected by the inspectors for review. Three DCNs were specifically selected and referred to the licensee for additional review. One of the-l three, DCN M08574, addressed a potential pressure locking
!'
valve problem. The licensee deferred corrective action for the Unit 2 valve and prepared an engineering evaluation to a
support their conclusion.
The inspectors reviewed the l
evaluation and concluded that the ' justification was
!
adequate. The other two DCNs involved civil / structural
issues. These items were reviewed by Region based
specialists. They concluded that the licensee adequately
!
reviewed these items and deferral from restart was
appropriate.
j
.
(6)
Drawing Changes - This area includes Category 2 and Category
<-
3 outstanding drawing changes. At the time of review, there
,
were approximately 25,000 drawings requiring over 40,000
,
changes. Category 1 drawing changes are not considered to
.
be a backlog problem since all~ Cat.1. drawings are updated.
!
as part of work package closecut. This area received
~!
special NRC reviews over the last 6 months.
These reviews were discussed in inspection reports 327, 328/93-14 and 327,
328/93-41.
The licensee intends to commit significant resources to reduce backlog in this area over the next 4
'
f years.
Close management attention.is needed in this area in order to effectively reduce these-backlogs.
.;
(8)
Obsolete Equipment - This arei involves equipment that may be difficult to maintain, or is outdated. The listing included obsolete equipment items when the review was conducted.
The licensee has established a plan-to prioritize replacement of obsolete equipment and has assigned priorities. The inspectors concluded that th'
area will receive the necesary attention in the futur-4 sed
.
on the licensee's post restart plan's new way of doin9 business.
ll l
(11)
PCFs - This area involves'the process for making changes to procedures. -Each department determines the need for
procedure revisions and schedules when the revision is to be
accomplished. At the time of review 468 procedures were identified with outstanding procedure revisions in the process. This area is monitored monthly by the Site Vice a
President.
The inspectors' review indicated that the two l
~
organizations with the most outstanding requests were i
!i lq i
d
!
.
~.
...
-
b
q i
'
!
!
'
Operations (180) and Instrument Maintenance.(150). These
,
results are in line with other reviews that have been I
conducted in these areas. Both groups have identified the need for additional post restart resources in procedure areas, i
(12) Vendor Manual Updates - This area involves maintaining
.
current the manuals with changes from vendors that are'
't applicable to equipment in the plant. Two areas are addressed by the licensee in this area. The first area
_
.
includes EQ and key safety-related manuals.
Backlog in this area at the time of review was approximately 80 manuals.
These were scheduled to be corrected by restart.
The other area included remaining manuals. ^ Backlog-in this-area at
'
'
the time of review was approximately 3400. Approximatelyf 1200 of these backlog items are for manuals used on safetyJ related components. The licensee's action plan indicated
-
that this backlog would be worked off-by October 1995.
The'
,
inspectors ccncluded that continuing management is needed to
.
achieve this post restart goal.
(13) DD - This area involves drawing deviations.
Drawing deviations are identified when it is discovered that plant drawings differ from actual plant configuration. At the
-
time of review approximately 500 Category 1 DDs were outstanding.
Plant management has committed to correct all-
,
outstanding Category 1 DDs prior to each Units' respective restart with the exception of new DDs that meet the requirements of the licensee's administrative controls. The inspectors will verify this during' restart monitoring activities. Approximately 800 Category 2 and 3 DDs were outstanding at the time of review. These will be completed as part of the backlog effort discussed in item (6). The
>
inspectors noted that this area was receiving daily management review during this inspection period.
(14)
Set Point and Scaling Documents - This area involves workoff of backlog of setpoint and scaling documents to support instrument channel calibrations. At the time of review, the i
backlog was approximately 25 documents.: Additional reviews-
,
determined that this backlog was being worked in a manner where the backlog would be 0 by restart of _ Unit 2.
Future i
activity in this area was determined to' be.related to design change activity. The design process would update set point
and scaling documents as part of the DCN process. No post
!
restart backlog existed in this area.
e (15) CAQs - This area included condition adverse to' quality documents. At the time of the review, Backlogged CAQs included 45 FIRS, 266 PERs, 66 IIs, and 11 SCARS. All of
the items had been reviewed for restart. The Nucle'ar-l Assurance owned this area and was maintaining close j
!
-_
.
!
!
'
!
f accountability of other department actions for closeout of i
these items. The inspectors concluded that this area is
I; being.better managed since the Nuclear Assurance
'
organization has been given responsibility for this area.
However, close management overview of each item is required.
j
,
l This is being accomplished by the MRC and being closely
l monitored by the inspectors.
.
c (16) Q-List Conversion - This area involves transfer of the Q-List from hard copy paper to an equipment management system.
-i At the time of review, no outstanding Q-List issues were identified other than transfer to EMS.
Project completion date was identified as September 1995. This effort will be reviewed monthly by the Site Vice President.
(22) Old Work Plans - This area included design changes previously implemented with outstanding issues for workplan closure not being completed. Also addressed was open design change package implementation package closeouts.. The
"
backlog for old work plans at the time of review was 20.
The backlog for design change package implementation packages at the time of review was 1.
The inspectors
'
reviewed the listing of open items and conciuced that the licensee had addressed all items necessary for restart of Unit 2.
This area was being reviewed monthly by site management.
(24) SMIs - This area included special maintenance. instructions that had been used to correct deficiencies with pipe supports clamps such as bolt torque, clamp configurations, etc. Restart issue 292 addressed the disposition'of approximately 300 SMI packages. The issue involved material discrepancies for bolting material. This item.was reviewed by region based specialists. They concluded that the i
licensee disposition of this item was adequate for restart.
(25)
Environmental Qualifications - This area involves. backlog of EQ work. At the time of initial review in August-1993, q
approximately 100 backlog issues were outstanding. The
.
licensee's goal at restart was to. reduce the backlog to less-than 10 issues.
During this period, the ' inspectors held
.l additional discussions with management. Additional review -
i of this area determined that backlog would be zero at restart of Unit 2.
At the time of review in September 1993,
,
the backlog was 5.
The 5 items had been worked with l
checking of results as the remaining requirement prior to restart.
The licensee intends to control future backlog so that no issues would remain greater than 90 days. This area will be monitored monthly by site management.
(26) UVAs - This area involves old unverified assumptions in calculations.
Backing in this area at the time of review
,
.
.
..
-
-
-i
!
i was approximately 75. The licensee was working this area in i
a priority manner with a goal to reduce backlog to zero by
October 30, 1993.
'l On September 24, 1993, the inspectors reviewed this backlog l
area again.
The inspectors determined that the backlog had been reduced to 10. All of the backlog items were discussed
.
with engineering management. Of the 10 items remaining, 7
were scheduled to be complete by restart. The remaining three items only required administrative actions to close.
out. The inspectors also confirmed with licensee management that future UVAs would only be used as part of the design process and closed out with the design package completion.
'
(27) QA Level II - This area consists of old low use inventory items that have not been upgraded to new procurement
standards. At the time of review, a backlog of
'
approximately 600 items were in shop stores. The licensee's goal was to work the backlog to zero by October 1994 if funding was provided. The inspectors noted that the inventory items would be evaluated as needed. Monthly i
review of this area is accomplished by the Site Vice President.
!
(28) Material Requests - This area involves material returned to shop stores (approximately 350 items) and material awaiting engineering evaluation (approximately 150 items). The inspectors noted that controls are in place to prevent reissue of these items without evaluations.
The licensee's goal was to reduce this backlog to zero greater than 90 days old by June 1994.
'
(29)
IDPs - This area included safety related and non-safety related instruments that are in the non Technical Specification surveillance instruction program as well as a population of quality related instruments that were not on a regular calibration frequency. Workoff curves indicated
completion of safety related and non-safety related IDPs in
late 1994.
However, quality related 'IDPs workoff has not
been projected. Total backlog of outstanding IDPs at-the j
time of the review was approximately 5700.
This effort is
!
projected to extend out for many years. The inspectors had
reviewed this activity during past inspections. This i
program noted to be an enhancement to a older, cumbersome
program.
The inspectors concluded that continuing
management attention is required to assure that this effort is properly implemented.
(30)
Labels - This area involves a program to label all important components and was developed to use a normal level of effort to implement in that components were to be tagged as the need was identified.
Past efforts did not recognize the
-
... -
-.
,
-.
,
. - -.
-
,
'
l'
,
t
,
effort required in this area. At the time of review, approximately 4,500 tag requests existed. Two hundred of
,
these requests were restart. This area will continue to be worked as level of effort in the maintenance department
'
until after restart of Unit 1.
All' restart requests are to be completed prior to each respective unit restart.
The goal of less that 50 backlog requests greater that 50 days
-
old is scheduled to be achieved by June 1994. The
.l inspectors consider this goal to be appropriate;. however, i
based on past performance in this area, continuing
~
management attention of this area is necessary in order to
achieve the goal.
'
(31) NPRDS - This area involves the number of delinquent Nuclear
!
Plant Reliability Data System component failure reports.
The goal established was less that 3 delinquent (greater
'
than 120 days old). At the time of review, two reports were
,
delinquent. This area will be tracked weekly and included
'
in the monthly maintenance report.
l (32) TROI - (Tracking Reporting Open Item) This area involves the site action tracking data base. Areas tracked included CAQs, NRC Commitments, NERs, TS Changes, TACFs, INP0 Items, i
Lessons learned from outages, RADCON/ Chemistry issues, ANI
.
issues, and Potential Reportable Occurrences.
The licensee used TROI as a tracking data base for other areas; therefore, no post restart goal was assigned to this area.
The inspectors noted that TROI was used daily by the licensee to record and monitor status of issues.
i (34)
EMS-Fuse Tab - This area involves equipment management
system backlog regarding updates for required fuses in the plant.
Safety-related fuse tabs were up to dace in the EMS
,
when the review was conducted. Non-1E fuses and valve tabs
'
were backlogged and requests were being made for additional resources to work in these areas.
This area is scheduled to be completed in FY-95. The licensee established an action-plan and senior management will monitor progress monthly.
(36)
PMs Delinquent - This area involves the two ;najor areas in
'
which preventive maintenance is performed. These areas
'
cover items inside the plant operating area (P0A) which are performed by the generating group and the customer group and items outside the P0A which are solely performed by the
!
customer group. The goal inside the P0A_is less than 5 late. At the time of the review no delinquent PMs were identified inside the P0A. However, some PMs had not been performed. These non-performances were supported by technical evaluations which allowed for deferral in accordance with the licensee's procedures.
The. inspectors were informed that this population consisted of
.
approximately 150 evaluations.
The inspectors reviewed a
.
-
-
.
}
p L
(
a l
l
'
sample of approximately 10 technical evaluations and concluded that they were acceptable for deferral of the PM.
However, the inspectors also noted that two of the deferrals
-,
could have been accomplished easier during the two unit outage. The licensee agreed with this conclusion and stated that increased sensitivity has recently resulted in:a more thorough review of PM deferral technice.", evaluations.
,
(37) PEG Material Issues - This area involves backlog of work for the procurement engineering group.
The goal is to' have less i
than 250 material issues older than 15 days still being worked. The normal level of effort usually maintained this goal; however, additional resources are currently being used-
'
for emergent outage work.
t
'
(38) Old ECN/DCN - This area involves old engineering change.
notices / design change notices that are field complete but
,
have not had design closure. Backlog in this area at time l
of final review was 6 DCNs. The inspectors reviewed the
,
'
outstanding backlog, item by item, and concluded that no outstanding issues existed which could affect safety-related.
equipment operability. Only administrative actions remained
?
on the DCNs which involved safety-related equipment, with
'
the exception of additional tagging of some CCS components.
-
Two of the items were related to security upgrades and the o
dry active waste building. These items did not affect
,
safety systems.
(40) Maintenance History - This area involves completed work orders that are waiting to be entered into maintenance history. The goal was to maintain this backlog.at less than 450. This goal was achiavec during a period from late June
through the middle of August 1993. At the time of review, the number in backlog was over 600. This appeared to be due
'
to a large number of completed work orders in preparation for Unit 2 restart.
Performance was monitored monthly by the Site Vice President.
,
(41)
Procedure-Admin. Hold - This area involves procedures that are placed on administrative hold in accordance with administrative requirements. At the time of review, 694 procedures were on administrative hold. Of the procedures.
'
on hold, 380 were due to be cancelled,118 were technically'
inadequate, 101 were infrequently used, and 173 had other
reasons for being on hold. The inspectors concluded that this area was being appropriately controlled by the Site Support Department.
Other departments owned the backlog and were responsible for procedure correction, which would be
necessary prior to use.
l
..
-w w
w
-
p-
,
8
(42)
PEG /DCN Procurement - This area involved procurement of DCN i
I material by the PEG to support plant modifications.
Backlog
L in this area at Unit 2 restart was expected to be
'
approximately 100 packages involved with Unit-I.
(43) RIP 56 Items - This area involved the replacement item program. Fifty six old, high dollar items were in this program.
If the items were used, they would have to be o
upgraded to current procurement-standards. At the time of review of this area, the review of these items was complete and recommendations for' disposition had been forwarded to the materials group. No additional engineering work was
anticipated in this area.
(44) CCRs - This area involved the calculation cross reference index system. The backlog involves loading all data fields t
for civil engineering discipline calculations into the system. The licensee considers this effort to be an
'
enhancement to be able to fully cross reference the pipe stress, hanger support, and structural calculations. The calculations are retrievable from RIMS and can be manually cross referenced as needed. At the time of review, the backlog population was approximately 20,000- entries.
The
,
licensee has scheduled this effort for completion in FY 1995.
'
The inspectors reviewed this backlog area on two separate occasions with engineering management. The inspectors determined that this backlog was administrative in nature.
All calculations referenced in this backlog are available in completed form in RIMS. The backlog does not involve any potential technical issues.
(45)
PIs - This area involves periodic instructions-(non-TS periodic tests) in deficiency notice status whicn are'
'
overdue in performance or in the review cycle. The goals
-
established included less than 3 PIs past due more than 30 days.
This area is reviewed daily in the plant manager leadership meeting. The inspectors. observed continuing management attention to this area during these meetings.
(46) RCH - This item involves the Reliability Centered Maintenance Program Activities. The program was established.
as a long term effort to improve system / component
,
reliability.. The goal is to review 73 systems prior to.
December 30, 1995. This effort also appears to be a program l
which will help in satisfying the maintenance rule requirements. At the time of review, 32 systems had been-reviewed, 7 systems were in review, and 4 systems were being analyzed. The inspectors concluded that this area was being properly managed.
j
(48) SPTS - This item involves the Site Procedures Tracking System. This system tracks procedure packages.
Procedure sponsors have evaluated their packages against restart
!
criteria. At the time of review there were 39 packages outstanding. The inspectors reviewed the list of outstanding packages and noted that most (32) were EQ binders. The inspectors obtained 'a copy of the changes to the EQ binder packages relating to procedures that were
..
backlorged. The inspectors reviewed the binder changes and
.
concluded that the changes did not require any field work to l
maintain EQ qualification. The inspector concluded that
-:
this area was being properly managed.
(49)
FSAR - This item involved one outstanding civil engineering issue requiring FSAR update. The licensee has scheduled.
this item in the FY-94 workload. The inspectors noted that
this item involved revision to design criteria, generation
!
of 4 calculations, and issuance of a design change notice.on
,
Seismic Instruments in addition to changing the FSAR. The licensee stated that this item could not have emergent items
and that the backlog could not recur.
The outstanding civil
'
engineering issues were reviewed by region based
'
specialists. They concluded that no restart items were remaining in this backlog area.
(50)
PM Revision - This item involves future work requested through the preventative maintenance process.
At the time
,
of review, approximately 2400 revision requests were
'
backlogged.
Items were screened for restart and
,
approximately 150 were identified as restart. Workoff of
!
this area to reach a goal of less than 300 is expected to be completed by July 1997. The inspectors concluded that this area will require continuing management focus in order to achieve the goal.
CONCLUSIONS - The inspectors * reviews of the licensee's backlogs.
allowed for several conclusions. They are
-
Backlogs have been identified and goals established to allow for licensee management to correct longstanding deficiencies l
in management of their workload.
-
Licensee management has committed to monitor identified
.
backlog areas such that the backlog goals should be j
achieved.
-
Sequoyah has established a broad post restart plan which
.
'
should help in management.of both known and future post restart issues.
However, several challenges were also noted.
They are:
.
,
i
_
-
Several backlog areas require commitment of resources in future years which had not been fully allocated at the time of the reviews.
Specific department areas in which backlogs indicated extra need for close management overview include site engineering, operations (procedure upgrades), and maintenance (instrument maintenance'IDPs).
-
The post restart plan did not provide detailed information on prioritization of items for evaluation.
The inspectors concluded that the licensee has'made good progress in the implementation of their restart plan and has outlined a.
general post restart plan which forms a basis for better olanning in the future. Management should closely monitor implementation of post restart activities in the future and assure that backlogs are reduced to or below established goals.
b.
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 closeout is addressed in paragraph 8.
The inspectors also reviewed the following specific items:
(1)
MCR Annunciators and other Operations Workoff Curves.
On several occasions prior to restart, the inspector met with Operations management and reviewed the status of workoff curves for MCR annunciator problems and other items.
The inspector noted that Operations and Maintenance management had made a dedicated effort to reduce the number of these items as low as possible prior to restart, with successful results. As of October 8, 1993, the number of unresolved Unit 2 and common items had been reduced to-21 annunciator problems (includes both disabled annunciators and annunciators for which there is a problem with an input signal), 7 out-of-service control room instruments, and 25 other plant deficiencies noted in the control room by use of orange maintenance request stickers. At the time of the inspector's final review, further reduction in these numbers was expected prior to Mode 4, and work was still in progress toward this goal. A number of the items were deferred past Mode 4 due to operational constraints, but were scheduled for completion prior to the mode in which the equipment'is required.
The inspector discussed with Operations management the nature of each Unit 2 or common item deferred past Mode 4.
There were no deferrals which were not considered acceptable. The number of remaining items was
i
!
i
l l
1 considered by the inspector to represent an insignificant
,
impact on control room operations.
'
l (2)
On August 25, 1993, the licensee responded to an NRC concern regarding compliance with-ANSI-N18.1 - 1971. for the
,
operations manager position.
In their letter to the NRC, the licensee stated that the Operations. Superintendent meets and satisfies the requirements of TS 13.1.3 and ANSI-N-18.1_
i-1971 #or the Operations Manager. The letter also discussed the Plant Manager position and stated that this manager also meets the requirements of the ANSI.
Both of the managers at Sequoyah had filled these positions within the past year.
'
The letter further discussed that the licensee has l
recognized the current limited commercial nuclear power plant operational background of the recently hired l
Operations Manager.
It stated that a training program was l
being developed and implemented for both new managers to I
obtain a senior reactor operator level of knowledge on the
,
Sequoyah Plant.
In the interim, the licensee stated that SR0 type management decisions would be made by the l
Operations Superintendent and his staff.
The inspectors reviewed the licensee's position and proposed
)
training activities with the NRR headquarters staff.
The
'
NRC staff considers the licensee's position on the ANSI
_
requirements to be satisfactory and that the proposed
training appropriate. This submittal addresses the NRC's
'
concern in this area.
j
'I (3)
Operations Department Past Configuration Control Problems During 1992 and 1993, a number of misaligned components were identified at Sequoyah, indicating a need for corrective actions of broad nature. Misalignment of containment spray valves, refueling water storage tank immersion heater power supply switches, a diesel generator day tank handswitch, and certain throttle valves have resulted in NRC violations.
'
In addition, walkdowns identified discrepancies between the.
>
plant and the system alignment checklists.
The licensee took extensive corrective actions to improve
]
the configuration control process and its implementation.
l These included:
j
-
A comparative review of SSP-12.2 valve and power j
availability checklists to plant drawings was
'
performed by Operations and Engineering to ensure that plant components requiring configuration control are, captured in procedures. The review identified approximately 900 discrepancies, which were addressed l-l-
-.
,
l
.i l-
in PER SQPER930051, leading to the revision of over 80 plant procedures.
I i
A task force was convened to review the configuration
-
control process. Other utilities were consulted for
!
suggestions for program improvements.
!
-
Procedures requiring the manipulation of components a
were reviewed to ensure consistency between component configurations.
,
-
A program was established to periodically review
.
configuration status (0-PI-0PS-000-012.2).
-
A standing _ order was issued which disallowed the use _
!
of procedural exceptions to the configuration control process, and required configuration log. entries for in-progress surveillance instructions, system operations, and sis requiring deviation.from the normal system status file ~ alignment.
Logbook entries were required for off-normal conditions.
-
Upgrades were made in the processes for independent verification.
SSP-12.6, VERIFICATION PROGRAM,'was revised to distinguish between independent verification, which is esed for system alignment checklists, and concurrent ' verification, which is a
!
high level of independent verification implemented prior to performing critical steps.
-
SSP-12.64, LOCKED VALVE PROGRAM, Revision 0, was
_
implemented to better control locked valves. An
'
appendix to this procedure was established as the administrative control which defines those valves defined by NE as required to be locked and also those
,
identified by Operations as administrative 1y required to be secured.
The appendix to SSP-12.64 replaced engineering drawings as the administrative control for defining the valves required to be locked.
'
-
A series of meetings were conducted with Operations personnel to provide a clear definition of expectations and ownership,'and stress the need for improved performance in the rigorous use of basic operational tools. These included-Operations Standdown training on April 28, 29, and May 5, 1993.
-
-
Training on configuration control was conducted which included lesson plans, job performance measures, mock-ups, and evaluation criteria. Components with a high potential for being misconfigured were stressed.
.-
.. _. -
,
y
'
Improvements in performance monitoring were
--
implemented to better quantify the long-term effectiveness of current initiatives. Special
'
management evaluations of Operations performance were
.
conducted prior to Unit 2 restart.
!
'
-
Operations management: worked closely with the Site QA organization to ensure that adverse performance trends-would be quickly identified and corrected.
'
A systematic 100% verification of the configuration of required components was initiated for both units, and the Unit 2 verification was completed prior to restart.
Operations personnel told the inspector that only two misconfigured components were identified during this effort for Unit 2.
These were a valve on the boric acid filter system and the handswitch for the 2A-A diesel generator panel fan. They were addressed, respectively, in
'
SQ930436PER, dated August 27, 1993, and in SQ930537PER, dated September 17, 1993. Although the licensee's investigation of these events could not conclusively
_
establish a root cause, it appeared that the mispositioned components were manipulated by someone not following a
,
procedure.
l
.
On September 30, 1993, the Operations Superintendent issued I
a memorandum to all Operations personnel which discussed these events and stressed the importance of using
'
procedures.
On June 16, 1993, Sequoyah Nuclear Assurance issued an assessment of the Sequoyah Configuration Control Program (Assessment Report NQA-SQ-93-024). The assessment team
'
concluded that corrective action commitments in the area of configuration control were complete or satisfactorily in l
progress, and were commensurate with NRC commitments. The team also concluded that plant-wide sensitivity to configuration control was high, Operations had been proactive in making program improvements, and implementation'
of system status files exceeded procedural requirements.
l However, weaknesses in program implementation were also
'
identified. The audit identified a problem with maintaining positive configuration control during maintenance and test activities, particularly in those involving multiple work
l_
activities on the same equipment. A specific example was identified where configuration control was lost' during
'
testing, maintenance, and subsequent retesting of hydrogen analyzers, resulting in the analyzers being left in an-inoperable condition. Operations initiated SQPER931520, which identified that this typ: of problem had been repeated.
The audit concluded that there was a need for
!
a
increased Operations and Maintenance involvement to assure
.
that components are returned to the baseline position.
In addition, the audit identified test awareness. logs not being adequately maintained. During system walkdowns, the assessment team identified that certain EDG crankcase valves were not included on a valve alignment checklist.
,
Operations issued PER SQPER9931513 to address this concern,
.
which the audit determined to be an isolated. case.
!
On June. 30,1993, Operations issued a written response to Assessment Report NQA-SQ-93-024, which documented that all of the assessment findings had been addressed.
SQPER931513 l
was closed with all corrective actions complete, and actions
had been-taken to improve maintenance of the test awareness
'
log. SQPER931520, classified as a restart issue, was.also
,
closed and complete. Due to the potential to misconfigure systems or components, use of the " Test Alignment /
i Restoration" checklist was discontinued. Standing Order 93-040 provides only for the use of approved instructions for
,
configuration control. Training of maintenance planners was conducted and documented.
At the inspector's request, the licensee performed a word-search of the corrective action program data base for all
conditions adverse to quality involving configuration control during the past nine months.
The inspector reviewed this list, and found no indication of additional unaddressed programmatic issues.
The inspector concluded that the licensee's broad-based
'
corrective actions in the configuration control. area have resulted in performance improvements.
(4)
NRC reviews during startup.
On September 29, 1993, the inspectors commenced 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> j
monitoring activities of the licensee's restart of Unit 2.
Inspectors were assigned to monitor general conduct of operations, maintenance, and surveillance associated with Unit 2 restart.
In addition, the inspectors' monitored
management oversight and interaction during startup evolutions. During this inspection period, Unit 2~ remained in MODE 4 with final preparations being made for MODE 4'
i entry. Some of the inspector observations during this period were as follows:
-
The G0I used for startup was not organized in a manner which provided for good operator usage. The licensee
_j was aware of this issue and is taking post restart-actions to enhance G01 quality.
'
.j
,
l
.;
i
-
Operator sensitivity to plant status and appropriate identification of equipment deficiencies during i
startup evolutions was good.
j i
One observation was made regarding inadequate
-
performance of AUD duties (paragraph 3.a).
i
-
100% review of control room drawings for drawing deviations identified no deficiencies, i
-
One attention to detail area needing additional work i
was operator logs.
i The inspectors concluded that during this period operations, maintenance, and testing activities were being accomplished i
in an adequate manner.
Specific observations of control
room operator performance identified increased safety j
sensitivity and better attention to detail when compared to
'
past startups.
Operational Readiness ' Assessment Team (ORAT) Restart Followup c.
During the inspection period, the inspectors reviewed the licensee's immediate corrective actions for two issues identified during the Operational Readiness Assessmert Team (0 RAT). Inspection
{
Report 327,328/93-201. The first issue involved the adequacy of
!
the 18 month surveillance test procedures for the EDGs. The team
questioned testing methodology used during the performance of 2-
)
SI-0PS-082-026.A, LOSS OF 0FFSITE POWER WITH SAFETY INJECTION -
D/G 2A-A CONTAINMENT ISOLATION TEST.
Specifically, during the l
portion of the SI which satisfies TS Surveillance Requirement
.!
4.8.1.1.2.d.7, it was identified that the licensee ran the EDGs at i
a value equivalent to the design limit during the required 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> run.
It was subsequently determined that the'2A-A EDG did not i
exceed manufacturer limits; however, a case was identified on the 1A-A EDG where the limit was slightly exceeded. The inspectors
'
verified that an annual engine inspection was performed on the 1A-A EDG, as suggested by the vendor, to' verify that the engines were not damaged.
No discrepancies were identified.
The licensee has modified the 18 month EDG surveillance such that an operating L
band, lower than the specified limit, will be maintained.during i
subsequent testing. The licensee plans on submitting a TS change to reflect the changes to the surveillance. The inspectors.
concluded that the licensee adequately addressed this concern for restart.
The second issue reviewed by the inspectors involved the capability of certain emergency lighting units located in high temperature areas. The team's concern was that six emergency
!
lights located in both Unit I and 2 West valve vault rooms were possibly inoperable due to room temperature concerns.
To address the concern, the licensee performed an as-found 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> battery i
l
_
_
_
,
I
l t
i
discharge test on the subject batteries. The results of the tests I
were that four out of five Exide batteries passed the discharge j
test.
Inspection of the one Exide battery that failed indicated
'
that the failure resulted from a circuit board charging (
deficiency. The sixth battery (Light Alarm brand name) also passed
the discharge test.
In addition to the testing, the licensee
replaced all of the subject batteries and the failed circuit
.
board.
,
The inspectors discussed the results of the testing with the Fire -
Protection Manager. Although the results of the testing indicated
.,
that the batteries had not been adversely affected by the local.
,
area temperatures, the licensee plans on reducing the replacement
'
frequency of the Exide battery packs from eight to three years for
,
the subject areas. The Light Alarm battery replacement i
periodicity had been and will remain at three years; although the licensee plans to replace this specific battery with an Exide equivalent replacement in the near future.
The inspectors concluded that the licensee adequately addressed the. issue for restart.
Within the areas inspected, no violations were identified.
j 10.
Exit Interview
The inspection scope and results were summarized on October 13, 1993, with those individuals identified by an asterisk in paragraph-1 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 Descriotion and Reference i
I VIO 327, 328/93-42-01 Failure to follow the requirements of Site Standard Practice 12.3 during performance of maintenance activities on the IB 6.9.KV Unit _
board.
URI 327, 328/93-42-02 Review of licensee's past
maintenance and design aspects of the containment sump.
VIO 327, 328/93-42-03 Failure to control post maintenance testing activities in.accordance with administrative procedure
.
requirements.
l
'
.
.
.
-
.
,
l l
"
'
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.
11.
List of Acronyms and Initialisms ABGTS-Auxiliary Building Gas Treatment System
-
.
-
Air Handling Unit y
-
Augmented Inspection Team
>
A01
-
Abnormal Operating Instruction ASME -
Amercian Society of Mechanical Engineers
'
ASOS -
Assistant Shift Operations. Supervisor l
AUD
-
Assistant Unit Operator BD
-
(Electrical) Board CAQ
-
Condition Adverse to Quality CCP
-
Centrifugal Charging Pump
.i CCS
-
Component Cooling Water System CFR
-
Code of Federal Regulations
)
CR
-
Control Room
CREVS -
Control Room Emergency Ventilation aystem
!
-
Containment Spray CSSC -
Critical Safety System Components CT
-
Current Transformer CVC
-
Chemical and Volume Control CVI
-
Containment Ventilation Isolation DCN
-
Design Change Notice DEV
-
Deviation DRP
-
Division of Reactor Projects ECCS -
Emergency Core Cooling System EDG
-
Emergency Diesel Generator EMS
-
Equipment Management System
'l EE
-
Engineering Evaluation EQ
-
Environmental Qualification ERCW -
Essential Raw Cooling Water ESF
-
Engineered Safety Feature FCV
-
Flow Control' Valve FME
-
Foreign Material Exclusion FSAR -
Final Safety Analysis Report GF;
-
General Foreman G01
-
General Operating Instruction H0
-
Hold Order i
-
Heat Exchanger IDP
-
Individual Data Package
,
.!
IFl
-
Inspector Followup Item II
-
Incident Investigation IN
-
Information Notice IR-
-
Inspection Report
JC0
-
Justification for Continued Operation
,
i
k
,
'
KV
-
Kilovolt
LCO
Limiting Condition for Operation
-
-
Level Control Valve
.
'
LER
-
Licensee Event Report
LOCA -
Loss of Cooling Accident
MAMS -
Material Accountability Management System
L
-
Main Control Room
-
Micro-biological Induced Corrosion
. *
-
Motor Operated Valve
-
Management Review Committee
l
MRRC -
Management Restart Review Committee
,
MSIV -
M&TE -
Measurement and Test Equipment
NA
-
Not Applicable
'
-
Non-cited Violation
.;
NE
-
Nuclear Engineering
.i
-
Nuclear Experience Review
~
<
NPRDS -
Nuclear Plant Reliability Data System
NRC
-
Nuclear Regulatory Commission
i
-
Nuclear Reactor Regulation
-
Operational Control Center
y
-
'
PCF
-
Procedure Change Form
i
-
Pressure Control Valve
PER
-
Problem Evaluation Report
PERP -
Plant Evaluation Review Panel
,
-
Preventive Maintenance
'
-
Post-maintenance Test
PORC -
Plant Operations Review Committee
-
Parts per Million
j
PSIG -
Pounds Per Square Inch Gage
!
PTR
-
Post Trip Review
f
-
Quality Assurance
RCDT -
Reactor Coolant Drain Tank
'
-
-
'
RII
-
NRC Region II
-
Radiation Monitor
>
-
Radiation Work Permit
RWST -
Refueling Water Storage Tank
SCAR -
Significant Corrective Action Report
-
Shutdown
'
SD BD-
Shutdown Board
.
-
-
Surveillance Instruction
SMI
-
Special Maintenance Instructions
SO-
-
System Operations
'
l
S01
-
System Operating Instruction
}
505
-
Shift Operating Supervisor
SQN-
-
~Sequoyah
-
Site Standard Practice
.
TBBP -
Thermal Barrier Booster Pump
I
-
m
,.
- - -
,-
TS
-
Technical ' Specifications
TSCCR -
Technical Specification Component Condition Record
UB
-
Unit Board
-
Unresolved Item
UVA.
-
Unverified Assumption
-
Volume Control Tank-
-
Violation
-
Work Order
-
Work Request
ZOI
-
Zone of Influence
t
'
L
l
!
F
'l
-,
-1
-F
-,
.- [
!
i
?
f
l
'
.
.
t
t
.
- - -.--
.
l -
--
-
.
L-.
.
. - - - - -
- -
- - -. - - -