ML18152A457
| ML18152A457 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 01/26/1994 |
| From: | Branch M, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A458 | List: |
| References | |
| 50-280-93-30, 50-281-93-30, NUDOCS 9402080023 | |
| Download: ML18152A457 (13) | |
See also: IR 05000280/1993030
Text
. .
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.:
50-280/93-30 and 50-281/93-30
Licensee: Virginia Electric and Power Company
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
License Nos .. : DPR-32 and DPR-37
Facility Name:
Surry 1 and 2
Inspection Conducted:
December 5, 1993 through January 1, 1994
Inspectors:
. Approved by:
Scope:
M. W.an~ Resident
Inspec or
.
L
~*
/i,i--
J.~k, Resident Inspector
G. A~ seis,ection Chief
Division of Reactor Projects
SUMMARY
//}Gljf-
Date S1gned
I U-~ t_,r 't
Date. STgned
This routine resident inspection was conducted on site in the areas of plant
status, operational safety verification, maintenance inspections, balance of
plant .inspections, revi~w of plant modifications, and action on previous
inspection items.
While performing this inspection, the resident* inspectors
conducted reviews of the licensee's backshifts, holiday or weekend operations
on December 10, 12, 19, 22, and 28, 1993 .
--,
9402080023 940127 *
ADOCK 05000280
G
. PDR
2
Results:
Operations functional area:
Adequate implementation of the freeze protection program was noted
(paragraph 3.b).
Maintenance functional area:
Repetitive process vent Kaman radiation monitor problems continued to occur
throughout 1993.
The licensee's trending programs have identified this as a
recurring problem.
Ccirrective actions have been implemented and plans to
implement additional corrective action were ongoing (paragraph 4.a).
- Engineering functional area:
Station Nuclear Safety Operating Committee review of a safety evaluation
identified an area that -required additional engineering analysi~. This
analysis resulted in a procedural change for injecting temporary leak sealant
into the-packing of the Unit 2 loop fill control valve (paragraph 4.b).
An unresolved item was identified associat~d with the fire barrier adequacy
(i.e., MER-5 chiller cable protection), pending demonstration by the licensee
that the installation and design meets commitments to and regulatory
requirements of 10 CFR, Part 50, Appendix R (paragraph 6) .
REPORT DETAILS
1.
Persons Contacted
. Licensee Employees
- W. Benthall, Supervisor, Licensing
- R. Bilyeu, Licensing Engineer
H. Blake, Jr., Superintendent of Nuclear Site Services
- R. Blount, Superintendent of Maintenance
- D. Christian, Assistant Station Manager
J. Costello, Station Coordinator, Emergency Preparedness
- J. Downs, *superintendent of Outage and Planning
D. Erickson, Superintendent of Radiation Protection
A. Friedman, Superintendent of Nuclear Training
- B. Hayes, Supervisor, Quality Assurance
- M. Kansler, Station Manager
C. Luffman, Superintendent, Security
J~ McCarthy, Superintendent of Operations
- A. Price, Assistant Station Manager
R. Saunders, Assistant Vice President, Nuclear Operations
E. Smith, Site Quality Assurance Manager
- T. Sowers, Superintendent of Engineering
J. Swientoniewski, Supervisor, Station Nuclear Safety
- G. Woodzell, Nuclear Training
NRC Personnel
- M. Branch, Senior Resident Inspector
- S.*Tingen, Resident Inspector
- J. York, Resident Inspector
- Attended Exit Interview *
Other licensee employees contacted included control room operators,
shift technical advisors, shift supervisors *and other plant personnel.
- Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2.
Plant Status
Unit 1 began the*reporting period at 80% power on day 31 of the power
coastdown for refueling.
On December 21, power was reduced from 72% to
approximately 62% in order to remove one tandem drive motor fr6m one of
the two main feedwater pumps for use ~n Unit 2.
The unit operated*at
62% power for the remaining period, limited by only ona MFWP.
The.
refueling outage is sti.11 scheduled to commence on January 21, 1994.
2
Unit 2 began the reporting period at 100% power.
On December 22, power
was reduced to appr9ximately 60% in order to replace a main feedwater
pump motor that was experiencing vibration problems. After the Unit 1
motor was installed in Unit 2, the unit was returned to 100% power* on
December 25.
3.
Operational Safety Verification (71707, 42700}
The inspectors conducted frequent tours of the control room to verify
proper staffing, operator attentiveness and adherence to approved
procedures.
The inspectors attended plant status meetings and reviewed
operator logs on a daily basis to verify operational safety and
compliance with TSs and to maintain overall facility operational
awareness.
Instrumentation and ECCS lineups were periodically reviewed
from control room indication to assess operability. Frequent plant
toufs were conducted to observe equipment status, fire protection
programs, radiological work practices, plant security programs and.
housekeeping.
Deviation reports we~e reviewed to assure that potential
safety concerns were properly addressed and reported.
a.
Unit 2 Control Rod Drive System Urgent Failure Alarm and NOED
On December 15, at 8:37 a.m., a rod control sy~tem urgent fatlure
occurred on Unit 2 during scheduled control rod exercising~
The
urgent failure rendered group 1 rods powered from cabinet (2-RC-
CAB-lAC} immovable (TS i_noperabl e}.
The rods affected included
group 1 rods in SDB "A" as wel 1 as CB
11A
11 and "C".
In SDB
11A
11
,
the first bank tested, the four group 2 rods had inserted three
steps into the core while the four group 1 rods that were also
selected remained.fully withdrawn.
At 8:37 a.m., a LCO was
entered in accordance with TS 3.12.C.3.
TS 3.12.C.3 required that
inoperable control rod assemblies be restored to operable status
within two hours or that the plant be put into a hot shutdown
condition within the next six hours.
Initial troubleshooting began immediately and was witnessed by the
inspectors. This* troubleshooting involv~d looking for lit *
indicator lamps or blown fuses as well as taking electrical
reading at test points itiside the rod control cabinet. There were
no lit indicator lights or indication of blown fuses and the
electrical readings appeared normal.
The K-2 failure detector
card appeared loose (i.e., _about 1/8-inch from fully seated}.
This card was removed, reinstalled, and additional electrical
measurements made with no change in readings noted.
The K-2 card
was replaced and again there was no noted change in electrical
readings.
The old card was reinstalled. However, when the I-2
card, removed to ensure the gripper coils would stay de-energized
during troubleshooting, was reinserted, I&C personnel noted that*
lights on the J-1 failure detector card began flashing.
The J-1
card was replaced and the urgent failure reset. After re~ligning
the SDB "A" _rods to fully withdrawn per a temporary change to the
3
rod realignment procedure, the operators attempted to again
perform the rod exercise PT.
The rod urgent failure reoccurred.
After determining that further troubleshooting and repairs could
not be completed wtthin the action time_ of the TS, the licensee
requested enforcement discretion.
The NRC verbally granted enforcement discretion from TS 3.12.C.3
for Unit 2 only during a telephone conference on December 15,
1993.
Written enforcement discretion was issued the next day.
The discretion permitted continued operation of Untt 2 at power
for a period of 24_hours versus the two hours specified in TS 3.12;C.3.
The additional time was projected to allow
troubleshooting and repairs to the Control Rod Drive System .
. Although the control rod assemblies were immovable on demand from
the Control Rod Drive System, the ability of the control rod
assemblies to perform their intended safety function (trip into
the core) when a safety system setting was reached was not
affected.
Additional troubleshooting after the second urgent failure
revealed that the removed J-1 failure detection card had two loose
capacitors that were not correctly soldered. This defective J-1
card had masked the problem that caused the first urgent failure.
The second urgent failure resulted in the J-1 card indicating that
the failure occurred in the phase "C" stationary gripper
circuitry.
Both the phase control and firing cards for this
circuit were replaced and the control rods_~ere realigned and
satisfactorily tested in accordance with periodic test 2-PT-6,
Control Rbd Assembly Partial Movement.
The Control Rod Drive
System was returned to service and the LCO terminated at 3:06 p.m.
on the December 15.
This NOED is considered closed.
The inspectors noted that these rod equipment failures were-
further examples of continuing equipment malfunctions associated
with the Control Rod Drive System.
The inspectors discussed their
concerns with the Station Manager who indicated that a Station
Level I priority had been opened for engineering to review past
failures and make recommendations for improvements.
The
licensee's cufrent schedul~ for this project indicates that the
review should be completed in time to allow for the implementing
improvements during the upcoming (January 1994) Unit 1 RFO.
Unit
2 improvements should be factored into the next RFO, scheduled for
September 1994.
b.
_ Cold Weather Protection (71714)
During a plant tour on December l2, the inspectors noted that the
licensee was performing operations che~k list procedure no. OC-21,
Severe Weather OC, dated September 7, 1993. This procedure covers
the following forecast weather conditions: high winds and/or heavy
rains, extreme cold and/or heavy snow, and severe hot weather. -.
4
High winds and freezing weather had been forecast for this period
of time.
High winds and below freezing temperatures were expected
in the area and operations, maintenance, etc., used this procedure
to ensure that proper preparations have been made for the expected
inclement weather.
In addition, the inspectors discussed the normal freeze protection
program with the licensee. This program was implemented by
monthly performance (October through March) of STP-52, Cold
Weather Protection, dated April 3, 1992. This procedure contained
a detailed checklist of areas and components that need to be
routinely inspected to ensure that there was adequate protection
to prevent freezing. This procedure, STP-52, was performed by
both operation~ and maintenance personnel~
Deficiencies that were
noted while performing STP~s2 were documented and discrepancy
reports/work requests ~ere written to schedule corrective action.
On December 20, the inspectors reviewed the latest deficiency list
and noted that they were either complete, being worked, or
scheduled.
Walkdowns of exposed areas susceptible to freezing was
conducted by the inspectors.
No discrepancies were identified
that would indicate that the program.was not being adequately
imp 1 emented. *
Within the areas inspected, no violations were identified~
4.
Maintenance Inspections (62703, 42700)
During the reporting period, the inspectors reviewed the following
maintenance activities to assure compliance with the appropriate
procedures.
a.
Proc~~s Vent Radiation Monitor
- During this inspection period the inspectors reviewed the
reliability of the Kaman process vent high range effluent
monitors.* Previous !Rs have addressed recurring problems with the
Kaman radiation monitors.
Most recently, IR 93~23 addressed
spiking on the Kaman ventilation vent effluent monitor 1-VG-RI-l
(TS Table 3.7.6 Item 12).
TS Table 3.7.6, specified operability requirements for accident
monitoring instrumentation. Item 11 of this table specified
.
operability requirements for the process vent high range effluent
radiation monitors.
Kaman radiation monitors l-GW-RM-130-1/2
fulfill this requirement.
Whenever these radiation monitors are
declared. inoperable, an alternate method for monitoring the
process vent effluent was implemented in accordance with TSs .
The process vent Kaman radiation monitors have a history of
operational problems~
In 1991, approximately 11 DRs were written
due to operational problems. Ten DRs were written in 1992.
5
Twenty DRs were written in 1993. Recurring problems associated
with these radiation monitors involved defaulting setpoints, the
iodine/particulate sample becoming saturated with water, check
source failures, and miscellaneous other problems.* The licensee's
trending programs have identified this as a recurring problem.*
Corrective actions have been implemented and plans to implement
- additional corrective action are ongoing.
The inspectors will
continue to monitor the performance of the process vent Kam.an
radiation monitors in order to evaluate the corrective action's
ef feet i veness.
.
b.
Valve Packing Repair with Temporary Leak Sealant
TS 4.11.A.4 and 3.3.A.12 specify that total system uncollected
leakage from SI system valves, flanges, and pumps located outside
of containment not exceed 3836 cc/hr. The SI system leakage is
monitored by performing periodic testing and wal kdowns.
Syste.m
leakage measurements are recorded and tracked in accordance with
procedure 2-NPT-ZZ-001, Quantifying of System External Leakage.
While performing a system leakage inspection on December 23,
operators identified a signiffcant leak rate coolant increase from
the packing of the Unit 2 loop fill control valve, 2-CH-FCV-2160.
The packing leak rate which was previously identified as 6 cc/hr
had increased to 1800 cc/hr.
On December 27, the coolant leak
rate from the packing increased t~ 3120 cc/hr.
Leakage from ihe
- remaining components in the SI system was very low and therefore
the system's total leakage rate remained below the TS maximum
value of 3836 cc/hr.
On December 31, the loop fill control valve packing leak was
stopped by injecting a temporary leak sealant into the packing
area. This maintenance was accomplished by WO 260090-3 and
procedure O-MCM-1918-01, On Line Repairs.
The inspectors reviewed
the procedure and verified that there were provisions for limiting
the amount of leak sealant injected into the packing area and
restricting the leak sealant injection pressure.
The inspectors
also reviewed the work history dating back to 1991 for the Unit 2
loop fill control valve ~nd verified that the valve had not
previously been injected with a temporary leak sealant. The valve
was repacked during the previous Unit 2 1993 RFO.
The inspectors
also verified that there was a WR initiated to return the valve to
it's original condition.
The loop fill control valve is a containment isolation valve that
. is normally closed and not repositioned while the plant is
operating.
Injecting temporary leak sealant into the packing area
precluded further valve operation.
SE 93-246, dated December 30,
was prepared to evaluate operating the unit with the loop fill
control valve permanently shut.
The SE concluded that it was
acceptable to operate the unit in this condition until the next
6
RFO.
The inspectors reviewed SE 93-246 and attended the initial
SNSOC meetings that reviewed the SE.
The inspectors noted that
the SE was not initially approved by SNSOC.
SNSOC had questioned
if the design pressure rating of the packing leak off piping was
evaluated when determining the maximum temporary leak sealant
injection pressure. The packing leak off piping was the injection
point for the temporary leak sealant and the design pressure of
this piping was not -Originally evaluated~
As a result of SNSOC
questioning, the maximum temporary leak sealant injection pressure
was reevaluated and lowered.
The SE was subsequently approved by
SNSOC.
The inspectors concluded that the initial engineering
review for the temporary leak repair was incomplete.
However, the
SNSOC review and approval added value-to the leak repair process,
resulting in an acceptable temporary repair.
Within the areas inspected, no violations were identified.
5.
BOP Inspection (71500)
The inspectors conducted tours _of selected TB and other plant areas
susceptible to flooding.
During these tours, the inspectors verified
the availability of the non-safety related TB sump pumps which the
licensee relies upon to mitigat~ certain flooding scenarios.
Additionally, the inspectors we~e sensitive to ~ny work activities that
would increase the possibility of TB flooding such as openings in the
condenser waterboxes or piping systems.*
On December 29, the inspectors witnessed the licensee performing
maintenance associated with replacing TB sump pump l-PL-P-2F discharge
isolation valve l-PL-12. This maintenance was accomplished in
accordance with WO 279713-04.
In order to accomplish this maintenance,
the power supplies to three of the nine TB sump pumps were danger tagged
in the off position. The three TB sump pumps were inoperable for
approximately 2. 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> while the maintenance was performed.
Previous licensee commitments to the NRC stated that at least seven of
the nine TB sump pumps would be operable. The licensee reevaluated the
!PE calculations and c9ncluded that for short periods of time it was
acceptable to have at least six TB sump pumps operable.
Installing
improved SW expansion joint spray shields was one of the contributors in
reducing the critical flood flow rate which allowed operating with six
The licensee was drafting a letter to the NRC revising
their commitment.
The insp~ctors concluded that l-PL-12 replacement was accomplished in
accordance with the licensee's procedures for minimizing the impact*of
flooding in the TB.
Within the areas inspected, no violations were identified.
7
6.
Review of Plant Modifications {37828)
The inspectors have been closely monitoring the plant modification to
improve the reliability of the control room and emergency switchgear
room chillers. This project is commonly referred to as the MER-5
modification.
The modification basically consisted of constructing a
seismic structure to contain two additional chiller units with their
support systems. Additionally, the modification added flexibility to
.
the power supplies for the two new and the three existing chiller units.
On December 28, the inspectors witnessed/reviewed two activities
associated with the MER-5 modification.
The first involved a freeze
seal to allow valve replacement and tying chill water to one of the
three existing chillers. The second involved installing 3-M fire wrap
over cables and conduit in order to establish fire separation between
the two electrical trains that power the chiller units.
The freeze seal was installed using WO 262059-08 and was controlled by
procedure O-MCM-1918-03 revision 0, Freeze Seal of Piping.
The
procedure required that a SE be performed and approved by SNSOC.
The
inspectors reviewed t~e SE {93-239A) and found it acceptable.
The
piping being frozen was 3-inch diameter carbon steel piping. The
inspectors noted that the piping surface in the freeze seal vicinity was
very rusty and would be difficult to perform the NDE required prior to
freeze seal installation. The Site Services personnel working the job
showed the inspectors IPR 93-431 that documented th~ surface condition
and provided the engineering disposition of the concern prior to the
freeze seal installation~ Specifically, surface grinding to smooth the
area being frozen was performed followed by a successful NDE of the
area.
The conduit fire wrap was being installed per DCP 90-07.
The fire
barrier being installed on the conduit that housed "H" bus power supply
cables was necessary since the "H" bus conduit was routed through the
11 J
11 bus switchgear room within approximately 1-2 feet of the switchgear.
IO CFR 50, Appendix R requires that train {bus) separation be
established by physical distance {20 feet), or by 3-or I-hour fire
barriers ~epending on the specific circumstances.
The stated purpose of
the modification was to provide a I-hour fire barrier between the two
electrical power trains.
The inspectors revi~wed the work package at the job site and noted that
the 3-M installation/qualification instructions discussed a
configuration that was different from that being installed. The 3-M
qualification for a I-hour fire rating described a three wrap system for
< 5 inch aluminum conduit, consisting of two wraps of E-53 and one wrap
of E-54.
The system being installed consisted of three wraps of E-54
which was described by the licensee and their* contractor as thicker
material than the E-53 wrap.
The inspectors requested verification that
the actual installation configuration of 3 wraps of 3-M E-54 was bounded.
by test reports from the vendor.
8
The inspectors were provided a copy of a memorandum from the corporate
fire protection engineer to Site Engineering. This memorandum contained
the engineering evaluation for qualifying three wraps of E-54 material.
- The basis for the fire wrap qualification configuration being installed
was stated to be several 3-M test reports. However, fire test. report
no. 3MFT87-11, wh i.ch was described as the c 1 osest to the actua 1
installation, in a memorandum from PROMATEC, the licensee's contractor,
was not referenced.
The inspectors requested a copy of fire test report
no. 3MFT87-1I for review.
The above referenced memorandum also contained engineering evaluati~n
no. 25 titled, "Evaluation of ~ack of an Automatic Fire Suppression
System in Unit 2 Emergency Switchgear Room Surry Power Station". The
evaluation's purpose was to allow using I-hour fire barrier (i.e., 3
layer fire wrap on power supply cables for- the chiller units). The
original design had specified a 3-hour fire barrier (i.e., 5 wraps of
3-M material) for the cables in question but, because of space
considerations, only 3 wraps could be installed. The evaluation
referenced 10 CFR 50, Appendix R, section III.G.2.c requirement that
stated that two trains of safe shutdown cables could be separated by a
I-hour rated fire barrier, witn fire detection and an automatic fire
suppression system installed in the area.
The licensee's evaluation was
addressing the fact that the emergency switchgear room, where the cables
in question were located, was equipped with a manual not automatic fire
suppression Halon system.
10 CFR 50, Appendix R, section III.G.2.c
would require J 3-hour barrier for this area and an exemption would be
necessary.
During subsequent discussions, the licensee produced* a Surry Appendix R
Report that states that the emergency switchgear rooms for Units I and 2
(fire zones 3 and 4) only had to meet the requirements of 10 CFR 50,
Appendix R, section III.G.3 in lieu of III.G.2.c since remote shutdown
capability existed~
Section III.G.3 only required a fixed suppression
system and did not require it to be automatic. Additionally, train *
separation was not specified.
Based on the conflicting data, it was
unclear as to the fire protection and cable protection design
requirements for-this area.
The fire protection design engineer stated
that for new installations, 111.G.2.c requirements were desired. Since
the control room and emergency switchgear room chiller system were
common to both units, the inspectors questioned the licensee as to
whether the system would be needed to cool equipment that was relied
upon for remote/alternate shutdown. Thereby, it would be required to
meet the requirements of 111.G.2.c (i.e., protected by a 3-hour barrier
or I-hour barrier with automatic fire detection and suppression).
The inspectors requested additional information and historical
correspondence as to the design requirements for protecting the cable in
question. This item is identified as URI 50-280, 281/93-30-01, MER-5
Power Supply Cables Fire Barrier Adequacy, pending demonstration by the
licensee that the installation and design meets commitments to and
regulatory requirements of 10 CFR 50,
Appendix R.
Additionally, 3-M
'
.
9
fire test report 3MFT87-ll has not been provided-by the licensee or
reviewed by inspectors.
The licensee has elected to maintain a fire
watch in the area until thi~ issue is resolved.
_ Within the areas inspected, no violations were identified.
7.
Action on Previous Inspection Items (92701, 92702)
a. - Closed VIO 50-280, 281/92-07-03, Failure To Prevent Foreign
Material From Entering SW System.
When flow testing the Unit I
RSHXs during the 1992 Spring RFO, it was identified that the* flow
rate through RSHX 1-RS-E-IB was low.
Inspection of the heat
exchanger revealed that a rain jacket and rain pants were present
in the tubesheet area which restricted the flow of SW.
It was
concluded that the rain gear was inadvertently left in the system
during maintenance that was performed during the previous fall
1990 RFO.
In a letter dated May 29, 1992, the licensee responded
to this violation.
The cause of this event was attributed to
inadequate implementation of FME controls during the maintenance
performed on-the RSHX system during the 1990 RFO.
As corrective
_action VPAP-1302; Foreign Material Exclusion Program, was
implemented after the Fall, 1990, Unit 1 RFO to establish station
wide FME controls. - In addition, VPAP-1302 was revised -following
rain gear identificat_ion to further enhance the FME program by
requiring additional requirements for documenting clpseout
inspection results. - The inspectors reviewed VPAP-1302, revision -
3, and verified that the corrective actions-in response to
violation were implemented.
b.
Closed VIO 50-280, 281/92-13-01, Failure to Perform Safety
Evaluations for Procedures That Were Used to Operate Plant Systems
Differently Than Described in the UFSAR.
This issue involved
three examples in which the licensee operated plant systems in.a
different manner than described in the UFSAR but had not first
prepared written safety evaluations pursuant to IO CFR 50.59.
The
licensee responded to this violation in a letter dated July 31,
1992.* As corrective action, safety evaluations were prepared for
each of the examples identified. The inspectors reviewed SEs 92-
126, dated June 4, 1992,92-127,.dated June 4, 1992 and 92-171;
dated July 22, 1992.
SEs92-171 and 92-127 identified that
additional procedural controls were necessary.
The inspectors
reviewed procedures 2-0P-49.7, Filling and Draining RSHX Service
Water Supply Piping, revision 2 arid O-OPT-FP-005, Ftre Protection
Water Pumps, revision I and verified that the additional
procedural controls were properly incorporated._
Within the areas inspected, no violations were identified.
10
8.
Exit Interview
The inspection scope and. findings were summarized on January 4, 1994,
with those persons indicated in paragraph 1. The inspectors described
the areas inspected and discussed in detail the inspection results
listed in the front of the report and those listed below.
Description
Status
(Paragraph No.)
Item Number
URI 50-280, 281/93-30-01.
Open
MER-5 Power Supply Cable*Fire
Barrier Adequacy
- {parag.raph 6}.
VIO 50-280, 281/92-07-03
Closed
Failure To Prevent Foreign
Material From Entering S_W
System {paragraph 7.a}.
VIO 50-280~ 281/92-13-01.
Closed_
- Failure to Perform Safety
Evaluations for Procedures
That Were Used to Operate
Plant Systems Differently Than
Described in the UFSAR
{paragraph 7.b}.
Dissenting comments were not received from the licensee. Proprietary *
information is not contained in this report.
9.
Index of Acronyms and Initialisms
CB
CC/HR -
DR
ECCS -
IPR
IR
LCO
MER
.MFWP
NRC
RS
BALANCE OF PLANT -
CONTROL BANK
CUBIC CENTIMETERS PER HOUR
DESIGN CHANGE PACKAGE
DEFICIENCY REPORT
FOREIGN MATERIAL EXCLUSlON
INSTRUMENTATION AND CALIBRATION
INDIVIDUAL PLANT EXAMINATION
I_NSTALLATION PROBLEM REPORT
INSPECTION REPORT
LIMITING CONDITIONS OF OPERATION
MECHANiCAL EQUIPMENT ROOM
MAIN FEED WATER- PUMP
NOTICE OF ENFORCEMENT DISCRETION
NUCLEAR REGULATORY COMMISSION
OPERATIONS CHECKLIST
. PERIODIC TEST
REFUELING OUTAGE
RECIRCULATION SPRAY
RSHX -
SOB
SNSOC -
TS
UFSAR -
RECIRCULATION SPRAY HEAT EXCHANGER
SHUT DOWN BANK
SAFETY EVALUATION
SAFETY INJECTION
,
STATION NUCLEAR SAFETY AND OPERATING COMMITTEE
TURBINE BUILDING
TECHNICAL SPECIFICATION
UPDATED FINAL SAFETY ANALYSIS REPORT
UNRESOLVED ITEM
VIOLATION
WORK ORDER
WORK REQUEST