ML20198N931
| ML20198N931 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 12/29/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20198N889 | List: |
| References | |
| 50-458-98-16, NUDOCS 9901060254 | |
| Download: ML20198N931 (55) | |
See also: IR 05000458/1998016
Text
!'
l^-
ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket No.:
50-458
License No.:
Report No.:
50-458/98-16
Licensee:
Entergy Operations, Inc.
Facility:
River Bend Station
Location:
St. Francisville, LA
Dates:
July 20 through August 7,1998
Inspectors:
M. Runyan, Reactor Inspector, Engineering Branch
P. Goldberg, Reactor inspector, Engineering Branch
R. Bywater, Reactor inspector, Engineering Branch
P. Qualls, Fire Piotection Engineer
D. Wigginton, Project Manager
R. Fretz, Project Manager
Accompanying
T. Tinkel, Consultant
Personnel:
R. Cooney, Consultant
Acproved By:
T. Stetka, Acting Chief, Engineering Branch
Division of Reactor Safety
ATTACHMENT:
Supplemental Information
I
i
i
9901060254 981229
ADOCK 05000458
G
'
.
..
.
TABLE OF CONTENTS
EX ECUTIVE SU M MARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv
\\
Report Details . . . . . . . . . . . . . . . . . . . . . . . .
........ 1
'
....................... ..
111. Engin e e rin g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
E1
Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
l
E1.1
Standby Gas Treatment System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
E1.2 4.16 kV Electrical Distribution System . .
......... ..... ..... 5
E1.3 High Pressure Core Spray System . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
E1.4 Condition Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
E1.5 Temporary Alterations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
E2
Engineering Support of Facilities and Equipment . . . .
................ 14
E2.1
Evalcation of 10 CFR 50.59 Safety Evaluation Program . . . . . . . . . . 14
E4
Engineering Staff Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . 16
E4.1
General Engineering Experience and Competence . . . . . . . . . . . . . 16
E8
Miscellaneous Engineering Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
E8.1
(Closed) Inspection Followup Item 50-458/9621-01: Entergy Operations,
l
'
Inc., Resolution of Quality Assurance Program Required for Resource
S ha rin g . . . . . . . . . . . . . . . . . . . . . . . . . .
... ....... 17
.......
E8.2 (Closed) Inspection Followup item 50-458/9622-01: Adequacy of Molded
Case Circuit Breaker Trip Setpoints . . . . . . . . . . . . . . . . . . . . . . . . 17
E8.3 (Closed) Inspection Followup Item 50-458/9627-02: NRR to Review
Near-Buoyant Objects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..... 18
E8.5 (Closed) Licensee Event Reoort 97-007: Cracked Screw Assembly
Swivel Pads on Emergencj Diesel Generators Could Have Prevented
Fulfillment of Safety Function . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
E8.6
Engineering Backlog .
...................................20
E8.7
System Engineering . .
...................................20
E8.8
USAR Review Program . . . . . . . . . . . . . . . . . . . . . . . .
....... 21
..
E8.9 Year 2000 Computer issue . . . . . . . . . . . . . . . . . .
.... 22
.......
IV. Plant Support . . . . . . . . . . . . . . . . . . . . . . .
.... 23
.............................
F8
Miscellaneous Fire Protection Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
F8.1
(Closed) Unresolved Item 50-4J8/97201-01: Smoke detector application,
placement, and installation in fire area C-24 does not meet requirements
of License Condition 2.C.10 .
.... 23
.. ............. .....
.
F8.2
(Closed) Unresolved item 50-458/97201-02: Failure to include fire
protection check valves in a functional testing program . . . . . . . . . . . 23
F8.3
(Closed) Unresolved item 50-458/97201-03: Lack of engineering
evaluations to establish the fire-rating or fire-resistant capabilities of fire-
rated boundaries. . . . . . . . . . . . . . . . . . .
.25
............... .
Il
_ .
- _ _ _
. _ _ . ~ .
_ _
.
F8.4
(Closed) Unresolved item 50-458/97201-04: Outdated equipment and
failure to assign personnel to the fire brigade who have normal plant
duties that do not conflict with their response to a plant fire. . . . . . 26
F8.5
(Closed) Unresolved Item 50-458/9720105: Failure to perform an
adequate operability assessment and provide appropriate compensatory
measures for conditions affecting the functionality of post-fire safe-
shutdown capability. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
F8.6
(Closed) Unresolved item 50-458/97201-06: Failure to perform an
adequate post-fire safe. shutdown analysis that meets the licensee
commitment to Sections Ill.L.1, Ill.L.2, and Ill.L.7 of Appendix R to
10 CFR Fad 50 . . .
............................. .... 27
..
F8.7
(Closad) Unresolved nam 50-458/97201-07: Deficiency in the design of
the reactor overpressure protection system, under certain postulated
conditions, could lead to inadvertent actuation of 16 SRVs resulting in an
un-analyzed plant transient . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
F8.8
Othe r FPFi lssues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
F8.8.2 Control of Combustible Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . .33
V. Manag e m ent M e e ting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A
XI
Exit Me etin g Sum mary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
iii
_
._.
.
.
.-.
--
- - _ .
.-
_ .
--
.
i
EXECUTIVE SUMMARY
1
River Bend Station
NRC Inspection Report 50-458/98-16
i
t uring the period of July 20 through August 7,1998, an engineering and fire protection
inspection was conducted onsite. The safety system engineering inspection was performed on
the standby gas treatment system, the 4.16 kV electrical distribution system and the high
prestare core spray system. in addition, a followup inspection of previous inspection findings
was conducted in engineering arc. ; ire protection. The team also reviewed the status of various
programs which were planned or in progress.
Overall, the team determined that engineering activities were generally effectively implemented.
This determination was based on calculations, modifications, and condition reports that
exhibited sound engineering practices.
Enaineerina
The quality of recent design calculations showed improvement over earlier design
calculations, in that they contained more detail and were sufficient to facilitate an
independent review of the design. The older calculations were found to be adequate
after consultations with licensee engineers (Section E1.1.2).
The team concluded that the 4.16 kV electrical distribution system was well designed
and its design basis was well documented. The methodology used in updating older
calculations was a strength (Section E1.2.2).
No discrepancies were identified for the surveillance testing of the 4.16 kV electrical
distribution system. The time delay relay settings for loss of power instrumentation
surveillances were ir. correctly listed in the Updated Safety Analysis Report; however,
these settings were correctly stated in the Technical Specifications and in the
associated surveillance procedures (Section E1.2.3).
A problem was observed in the relief valve setpoint program, in that data sheets, with
values often differing from the design cold set pressure, had been used in one case to
set a relief valve, resulting in an improper setting. The licensee quickly recognized the
error, which did not introduce a safety concern, and corrected it (Section E1.4).
The team observed that two failures of the high pressure core spray system discharge
relief valve had occurred within the past four years. The licensee was still in the process
of determining the root cause (Section E1.4).
The temporary alteration program was effectively implemented. However, in response
!
=
'
to NRC questions, the licensee determined that containment temperature had, on one
occasion. dropped to 60 degrees Fahrenheit compared to an assumed design minimum
temperature of 70 degrees Fahrenheit. The licensee initiated a condition report to
resolve the implications of this discrepancy (Section E1.5).
.
iv
'
i
.
.~
..
-
-
-
.
.
Overall, the 10 CFR 50.59 program was found to be satisfactory. However, the failure
to identify as an unreviewed safety question an increase in the calculated doses for a
loss of coolant accident as reported in the updated safety analysis report was identified
as a violation of 10 CFR 50.59. Specifically, the exclusion area thyroid dose increased
from 32.8 to 37.8 rem, and the low population zone thyroid dose increased from 50.3 to
115.1 rem (Section E2.1).
The team concept developed in system engineering was effective because the
assignment of several individuals to each system increased the overall level of expertise
and provided more flexibility in supporting operations (Section E8.7).
Plant Support
The failure to provide a procedure for using standby service water for fire protection was
identified as a noncited violation (Section F8.2).
The condition where a postulated fire could have potentially caused all 16 safety relief
valves to open due to a fire-induced circuit failure was identified as a violation for failure
to implement the provisions of the fire protection program as required by Operating
License Condition 2.C.10. However, the licensee identified the violation and committed
to perforrn a modification to correct the condition during the April 1999 refueling outage.
<
in accordance with Section Vll.B.6 of the NRC's Enforcement Policy, the NRC exercised
discretion and did not propose a civil penalty nor issue a violation in this case (Section
F8.6).
v
-
...
...
..
--
-
. - - -
--
.- -
. .
..
- . - .
.
-..
- .
Report Details
Summary of Plant Status
The unit operated at full power during the onsite portion of the inspection.
,
L
111. Enoineerina
!
l
E1
Conduct of Engineering
E1,1
'
'E1.1.1 System Descriotion
L
Mechanical
,
in the post-accident mode following a design basis accident (DBA), standby gas
treatment system (SGTS) fans draw down and maintain a negative pressure in the
containment annulus and auxiliary building. The technical specifications (TS) require
the SGTS to draw down the annulus to a negative pressure of at least 0.5 inches water
glass (wg) within 18.5 seconds of system initiation and to draw down the auxiliary
building to a negative pressure of at least 0.25 inches wg in 13.5 seconds. Air removed
!
from these areas is processed through the SGTS filter train before it is discharged to the
atmosphere. The filter train processes potentially contaminated air from the annulus
and auxiliary building following a DBA to limit thyroid and whole body dose to within the
limit 1 of 10 CFR Part 100 at the site boundary (exclusion area boundary) and
low! population zone outer boundary. Following initial draw down, the SGTS is designed
i
to maintain a negative pressure of less than 0.5 inches wg in the annulus and less than
'
O.25 inches wg in the auxiliary building continuously for 100 days.
l
Electrica;
i
The major components of this system receive electric power from 480 volt standby
buses 1EJS*LDC 1 A&2A (Red Train) and 1EJS*LDC 1B&2B (Blue Train). These 480
voit buses are in turn fed from 4.16 kV standby buses ENS-SWG 1 A&1B respectively,
j
which are provided off site power via 230 kV-4.16 kV Reserve Station Service
Transformers RTX-XSR 1C&1D. The 4.16 kV buses may also be provided with power
,
l
by emergency diesel generators (EDGs) 1EGS-EG1 A & 18 when power is not available
from the grid.
The air-operated fan and filter inlet and outlet dampers are operated by 125 volt de
solenoid valves. On a loss of de power, the dampers fail open. Red train solenoids are
supplied power by de bus EMB-SWG01 A and blue train solenoids are supplied power by
de Bus EMB-SWG01B.
!
i
I
!
!
.
.
The 480 volt fans and the filter heater circuit breakers have solid state tripping devices,
which operate on overcurrent. The breakers are also tripped by load shed signals.
The fans are started automatically by load sequencer signals, by Radiation
,
'
Monitor RMR-RE103, and by loss of air flow from the opposite-train fan.
J
E1.1.2 Desian Review
a.
Insoection Scoce (93809)
Mechanical
The team exam'ned portions of various documents that discussed the safety and
design basis of the SGTS. These documents included the Updated Safety Analysis
Report (USAR), TS, the system requirements documents, calculations, drawings, and
condition reports (CRs). Additionally, discussions of various related topics were
conducted with licensee engineeru.
Electrical
The team reviewed one-line diagrams to assure that redundant components were fed
from separate buses and reviewed one calculation involving the fan flowswitches.
b.
Observations and Findinas - Mechanical
i
USAR Fidelity
The team's review of the USAR identified a few examples of incorrect information in
the SGTS sections. USAR Section 6.2.3.2.1, stated that the SGTS fan receives
power from the EDG within 38 seconds after the design basis accident (DBA) (i.e.,
30 seconds plus 8 seconds for the fan to attain rated speed). A review of other
documentation (e.g., Calculations ES-194-3," Auxiliary building pressure following a
loss-of-coolant accident (LOCA)," Revision 3, and G13.10.2.7*23, " Shield building
J
annulus following a LOCA," Revision 1) and discussions with engineering personnel
)
confirmed that the 38-second value was incorrect. The correct value was 48 seconds,
i
The incorrect 38-second value also appeared in Table 6.2-34 and Figure 6.2-61b.
USAR Section 6.2.3.3, discussed the positive pressure period (PPP) for the annulus and
auxiliary building. The PPP is the time following a DBA that the pressure is more
positive than -0.25 inches wg. The USAR stated that the PPP for the auxiliary building
was 111 seconds. A review of other documentation and discussions with engineering
personnel confirmed that the 111-second value was incorrect. The team noted that the
i
associated procedures were not affected by this USAR discrepancy.
i
k
.
1
2
!
I
I
,
..
.
i-
?
-
The licensee had already identified these errors during their ongoing USAR
programmatic review, but the USAR had not yet been updated at the time of this
l
inspection. The team determined that the errors did not result in a safety concern. The
l
licensee was also aware of some additional SGTS USAR errors, and License Change
Notice (LCN) 15.06-006 was in process to correct them. The failure to update the
I
USAR was considered to be a violation of 10 CFR Part 50.71(e). This failure constitutes
a violation of minor significance and is not subject te formal enforcement action.
Calculations
I
The team found that certain older River Rend Station (RBS) calculations for SGTS
lacked sufficient explanation and detail in some areas to permit an independent review
without obtaining additional information.
l
The team reviewed Calculation BV45.22-1," Fan External Total Pressure Fans
1GTS*FN1 A & FN1B Annulus and Auxiliary Building Exhaust, Accident Mode,"
Revision O. This calculation was designated safety-related. The pressure drop
calculation for node 4 to 5 used an input value of 2.269 inches wg based on
l
Calculation BV45.20-1, " Fan External Total Pressure 1GTS*FN1 A & FN1B
Containment /Drywell Purge Exhaust, Normal Operation Mode lil," Revision 1. A cross
check of Calculation BV45.20-1 did not reveal how the 2.269 inch water value was
determined. When presented with this observation, the licensee informed the team that
after performing their own review, they determined that the result of this portion of the
calculation was correct as stated. The team verified that the calculation was correct.
However, the licensee agreed that the calculation lacked sufficient detail to readily
understand how the 2.269 inches wg value was derived in this portion of the calculation.
.
The licensee stated that this information would be added to Calculation BV45.22-1.
The team reviewed Calculation PB-251,"To Determine the In-Leakage and Amount of
Exhaust Air Required To Maintain A Negative Pressure of 1/4 in. W.G. in the Aux. Bldg,"
Revision 0. This was a safety-related calculation. The team noted that the calculation
was overly conservative in determining the time to achieve negative pressure in the
auxiliary building. This resulted in an oversized fan being specified. The licensee agreed
with the team's observation that the oversized SGTS fan would create a larger negative
pressure condition in the auxiliary building than otherwise required by the design. While
l
the team noted that plant operation and testing confirmed this observation and that this
condition did not represent a safety concern, the team also noted that the higher
negative pressure caused door passage problems. The team considered this problem
to be a burden for site personnel The effect of this condition on plant operations is
j
further discussed in Section E8.2 of NRC Inspection Report 50-498/9805.
The team reviewed Calculation G13.18.2.1*079-00," Evaluation of Standby Gas
l
Treatment System Drawdown Data," Revision 0. This was a recently prepared
safety-related calculation that was representative of the quality of calculations currently
!
being prepared by the licensee. This calculation was considered to be well written and
exemplified the team's general impression that the technical quality of calculations was
'
improving.
t
3
_-
_
__
-
. . - - -
. .
..
-. . _ -
.
.
Observations and Findinas - Electrical
The team reviewed Calculation IA-GTS*1,"Setpoint Calculation 1GTS*FS 24A & B,"
i'ievision 4, which was the safety-related setpoint calculation for the flowswitches that
monitor airflow from Fans 1GTS*FN 1 A&18. No discrepancies were identified in this
review.
-
c.
Conclusions
Some portions of the USAR contained incorrect information in the sections affecting the
SGTS. The licensee had previously identified these errors and was in the process of
correcting them. Some older SGTS calculations lacked sufficient detail to permit a
meaningful independent review, without obtaining clarification from licensee personnel.
The quality of more recent calculations showed improvement over earlier calculations.
E1.1.3 Surveillance Testina
a.
Inspection Scope (93809)
The team examined portions of selected documents that discussed surveillance test
requirements for the SGTS. Primarily, these documents were the TS and condition
reports (CRs) that addressed issues related to SGTS surveillance test results. Selected
requirements found in the evaluation of the CRs were compared to corresponding TS
requirements for consistency.
b.
Observations and Findinas
j
No areas of concern were identified during this review.
c.
Conclusions
'
The team concluded that the surveillance testing program with respect to the SGTS was
j
satisfactory.
E1.1.4 Desian Modifications
a.
Insoection Scope (93809)
The team reviewed four engineering requests (ERs) that documented plant
modifications affecting the SGTS. In add un to the documentation for the particular
modification, other documentation contained or referenced in the ER documentation
packages were selectively reviewed. These documents included 10 CFR 50.59
screenings and evaluations, calculations, and LCNs.
!
b.
Observations and Findinas
.
No areas of concern were identified during this review.
<
j
4
!
i
..
- - - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
.
c.
Conclusions
The team determined that the plant modification program with respect to the SGTS was
satisfactory.
E1.2 4.16 kV Electrical Distribution System
E1.2.1 System Descriotion
The standby power system, which supplied Class 1E safety-related motors and
4.16 kV/480 volt load centers, was arranged in three divisions. These divisions were
designated Train A (Red), Train B (Blue), and Train C (Orange).
Train A was supplied power from the 230 kV grid by preferred Station Service
Transformer 1RTX-XSR1C, whereas Train B was supplied from the 230 kV grid via
preferred Station Service Transformer 1RTX-XSR1D. Train C was supplied power from
1NNS-SWG1C, which in turn was supplied by either 1NNS-SWG1 A or 1NNS-SWG1B.
Those switchgear sections were supplied from the 230 kV grid by either Station Service
Transformer 1RTX-XSR IC or 1D. Each of the divisions was also provided with an
emergency diesel generator (EDG).
E1.2.2 Desian Review
a.
Inspection ScoDe (93809)
The team reviewed System Design Criteria Document SDC-302 ENS," Safety Related
4.16 kV Electrical Distribution System Design Criteria," Revision 0, seven design basis
calculations, seven CRs, two ERs, four one-line diagrams, the USAR, and seven
surveillance test procedures (STPs). The team assessed technical adequacy,
consistency, and completeness of the system. The team also conducted a walkdown of
the 4.16 kV switchgear.
b.
Observations and Findinas
The team determined that the system design criteria document was satisfactory in
scope and accuracy. The criteria clearly described the safety function of the Class 1E
standby buses. The criteria also addressed the supply of nonsafety-related plant
auxiliaries that require a reliable power supply and were therefore fed from the safety-
related buses.
Most of the calculations reviewed by the team were performed originally by an
architect / engineer. The licensee was in the process of updating most of these
calculations. The newly revised calculations were observed to be of considerably better
quality than the originals. The team considered the licensee's ongoing efforts to update
the existing electrical calculations to be a strength.
No discrepancies were identified during the system walkdown.
5
i
l
!
<
_ - - - -
---
- __ - _ - _
__ _ _ -_-_ _ ___ _ __ ____- _-__ __-
.
.
c.
Conclusions
The team concluded that the 4.16 kV electrical distribution system was well designed
and documented. The methodology used in updating older calculations was a strength.
E1.2.3 Surveillance Testing
a.
Inspection Scope (93809)
The team reviewed Procedure STP-302-1601, " ENS-SWG1 A/B Loss of Voltage
Channel Calibration and Logic System Functional Test," and the resultant data from
procedure performance.
b.
Observations and Findinas
The tearn observed that the surveillance test results for STP-302-1601 were satisfactory
for the last three times it was performed.
The team identified discrepancies associated with time delay relay settings in the
loss-of-power instrumentation surveillance tests listed in TS Table 3.3.8.1-1. There
were inconsistencies among the values in this table and those reported in the USAR and
the STPs. USAR Section 8.3.1.1.3.9 lated the second time delay associated with
degraded voltage for Divisions 1 and E as 50 seconds, whereas TS Table 3.3.8.1-1
listed this time as 60 seconds. The same 'ISAR Section listed the time delay
associated with Loss of Voltage for Division 3 es 2 seconds while item 2.b of the TS
Table 3.3.8.1-1 listed this time as 3 seconds. The USAR Section listed the first time
delay associated with Division 3 degraded voltage as 10 seconds whereas item 2.e of
the same TS table listed it as 3 seconds.
The licensee responded to the team's observation with documentation that indicated
that the values in the USAR were in error and that the TS and surveillance procedures
were correct. The team agreed with the licensee's response and noted that since the
TS and the surveillance test procedures were correct, the error had not affected the
validity of past surveillance tests. In response to the team's finding, the licensee
initiated CR 98-1004, which identified the discrepant condition and recommended that
the USAR be revised to agree with the TS. This failure to correct the USAR error was a
violation of 10 CFR 50.71(e). This failure constitutes a violation of minor significance
and is not subject to formal enforcement action. In addition, since the licensee's review
of the USAR was in progress and, because additional reviews by the licensee in this
USAR section were pending, the team considered it likely that this inconsistency would
have been discovered and corrected independently by the licensee.
c.
Conclusions
in a limited sample, the team did not identify any discrepancies in surveillance testing of
the 4.16 kV electrical distribution system. Some USAR discrepancies, which were not
safety significant, were identified during this review.
6
-
..
- - _ _ _ _ - _ - _ _ _ _ _ - _ _ _ _ _ - _ - _ _ _ _
l
l
,
E1.2.4 Desian Modifications
a.
Insoection Scoce (93809)
The team reviewed Modification Requests 86-0595 and 86-1119.
b.
Observations and Findinas
Modification Requests 86-0595 and 86-1119 involved changing time delay relay settings
used in EDG starting circuits. The modification requests were complete and included
satisfactory safety evaluations.
c.
Conclusions
Based on review of the selected modification requests, the team concluded that these
modifications of the 4.16 kV electrical distribution system were satisfactory.
E1.3 Hiah Pressure Core Sorav System
E1.3.1 System Description
Mechanical
The high pressure core spray (HPCS) system is one of the four subsystems that
comprise the emergency core cooling system (ECCS) that cools the reactor following a
loss of coolant accident (LOCA). If the break is small, the HPCS system is designed to
maintain coolant inventory as well as vessel level while the reactor coolant system is still
,
pressurized. If the water levelis not maintained by the HPCS system, the automatic
depressurization system (ADS), low pressure coolant injection (LPCI) system, and/or the
low pressure core spray (LPCS) systems are automatically initiated.
The HPCS system consists of a pump, discharge piping fill pump, injection valve, spray
sparger head, other system piping and valves, suppression pool suction strainer, system
instrumentation and controls, and electrical switchgear and power supplies. The system
is designed to operate from normal offsite auxiliary power or from an emergency diesel
generator (EDG) if offsite power is not available.
The HPCS system cerves as a backup to the reactor core isolation cooling (RCIC)
system to maintain the reactor water level in the event the reactor becomes isolated
from the main condenser during operation and feedwater flow is lost.
Electrical
The HPCS pump motor receives electric power from Division 3,4.16 kV standby bus
E22*S004. The motor-operated valves that are part of the HPCS system are supplied
power from standby MCC 1E22*S002, which is fed from the Division 3,4.16 kV bus via
4.16 kV /480 volt transformer 1E22*S003. Although not part of the HPCS system, the
standby service water (SSW) pump motor (SWP-P2C) is also supplied power from bus
E22*S004. The normal supply to E22*S004 is from 1NNS-SWG10, which in turn is
7
L -
-
.
.
. .__
.
.
.
_ _ _ _ _ _ _ _ _ _ _ _ _ _
-
.
.-
.-
. .
.
l
!
!
supplied by either 1NNS-SWG1 A or SWG18. Both of these buses are supplied from
the 230 kV grid via preferred station service transformers 1RTS-XSR1C or XSR1D.
l
When the normal supply to E22*S004 is lost, the EDG supplies power to the system.
125 volt dc power is provided to the diesel generator and to E22*S004 from battery
1 E22*S0018AT via 125 volt de bus 1 E22*PNLS001.
E1.3.2 Deslan Review
a.
Insoection Scoce (93809)
i
The team examined portions of various documents that discussed the safety and design
basis of HPCS. These documents included the USAR, TS, system requirements
documents, calculations, drawings, and test reports. Additionally, discussions on
various ietated topics were conducted with engineering personnel.
b.
Observations and Findinas
USAR Fidelity
The review of the USAR identified one example of incorrect information in the HPCS
sections. Table 6.3-1 stated that at 30 seconds following the start of a DBA LOCA, the
HPCS injection valve is open and the pump is delivering design flow, completing HPCS
startup. Based on a review of other portions of the USAR and discussions with the
licensee, the 30 second value was determined to be incorrect. The correct value was 27
seconds. Upon additional review, the licensee determined that this was an
i
administrative error and that the 30 second value should have been removed with other
changes addressed by LCN 06.03-030 dated December 12,1997. This failure to
correct the USAR was a violation of 10 CFR 50.71(e). This failure constitutes a violation
of minor significance and is not subject to formal enforcement action. The licensee
initiated CR-98-1001 to document the incorrect 30 second value in Table 6.3-1 and
indicated that an LCN to change the USAR would follow. The EDG loading calculations
were not affected by this error.
Calculations
The team reviewed Calculation G13.18.2.2*031-0," Net Positive Suction Head (NPSH)
Available for ECCS Pumps for Suction from the Suppression Pool Under Accident
Conditions,* Revision 0. This calculation supported analysis of a recent major design
modification that installed new design ECCS suction strainers in the suppression pool.
The team determined that this calculatic? was satisfactory.
System Desian Criteria
The team reviewed the HPCS system design criteria. One example was found where
the information was inconsistent with the USAR. Section 3.3.1 of the system design
criteria addressed the HPCS pump and stated that the minimum required net positive
j
suction head (NPSH) for the pump was 2 feet at a reference location 36 inches above
the pump mounting base plate. A review of the manufacturer's test report T-36631-1,
,
"HPCS 15 Stage Pump Performance Curve (Byron Jackson)," June 29,1977, indicated
i
8
i
--
.
1
I
-
that the NPSH required was 1 foot, referenced to 3 feet c.bove the mounting flange.
USAR Table 6.3-13 likewise stated that the HPCS NPSH required was 1 ft at 3 ft above
the mounting flange. The licensee stated that this portion of the system design criterion
was covered by an open item listed in the back of the system design criteria that
indicated that an update was required because of the ECCS suction strainer
modification (i.e., the error was scheduled to be corrected). Because this error did not
affect the analytical design of the plant, the team noted that the discrepancy did not
constitute a safety concern.
Setooint Calculations
>
The team reviewed Calculations 1 A-E22*04, "Setpoint Calculation HPCS Condensate
Storage Tank Low Level," Revision 2, and 1 A-E22'05, "Setpoint Calculation
1E22*ESN655C & G," Revision 4. The methodology used in both setpoint calculations
was in accordance with applicable standards. The team did not observe any
assumptions that were not acceptable and considered these calculations to be
satisfactory,
c.
Conclusions
One portion of the USAR contained incorrect information in the sections affecting
HPCS. One example was found in the HPCS system design criteria where information
was inconsistent with respect to the USAR. Three calculations supporting the HPCS
design were observed to be satisfactory.
E1.3.3 Surveillance Testina
a.
Inspection Scope (93809)
The team examined portions of selected documents that discussed surveillance test
requirements for the HPCS system. These documents included the TS, surveillance
test procedures (STPs), and related CRs.
b.
Observations and Findinas
The team examined selected requirements in the STPs were compared to
corresponding requirements to assure consistency. In addition, selected test results
were reviewed to compare for consistency with the corresponding procedure and to
confirm that the results were within acceptance limits. No areas of concern were
identified during this review.
c.
Conclusions
The team determined that the surveillance testing program with respect to the HPCS
system was satisfactory.
9
.
..
.
.-
..
. _ - _ _ - _ _ _ - _ - _ _
_
. _ . _ - _
_ _ . . _ . . _ . _ _ _ _ _ _ _ _ _ . _ . _ . _ _ _ _ . _ . _ _ _ _ _ _ . _ _ _ _
d
.
,
E1.3.4 Desian Modifications
'
a.
Insoection Scope (93809)
.
The team reviewed three engineering requests (ERs) describing plant modifications that
-
,
affected the HPCS system.
' b.
Observations and Findinas
No areas of concern were identified during this review. The team determined that the
plant modification program with respect to the HPCS system was satisfactory.
c.
Conclusions
The team determined that the plant modification program with respect to the HPCS
system was satisfactory.
E1.4 Condition Reports
a.
Insoection Scoce (37550)
The team reviewed Procedure RBNT-030, " Initiation and Processing of Condition
Reports," Revision 12. In addition, the team reviewed 46 CRs associated with the
)
' SGTS, the HPCS system, and the 4.16 kV electrical distribution system. The team
1
'
discussed the CR process and some of the CRs with licensee personnel.
b.
Observations and Findinas
The team determined that the CR process provided a single process for documenting
the evaluation and resolution of problems, concerns, activities, and conditions that could
adversely affect or have the potential to adversely affect the safe operation of the plant.
As an overall observation, the team found that the licensee was using the CR program
successfully, in most cases, corrective actions were complete and well documented.
The team reviewed CR 97-1881, dated October 20,1997, and CR 97-2131, dated
December 18,1997. The first CR, CR 97-1881, stated that the set pressure of the
HPCS diesel generator starting air relief valves was set too low and reset them from
250 to 270 psig by means of Maintenance Action item Number 313888. The licensee
concluded that the setpoint was incorrect because the valve data sheet listed the
j
setpoint as 270 psig. The inservice test procedure correctly listed the spring set
1
pressure as 250 psig. At the time, the licensee erroneously assumed that the setpoint
value in the inservice test procedure was not correct. The second CR, CR 97-2131,
.
documented that the relief valves were incorrectly set at 270 psig. The licensee initially
concluded that the maintenance personnel incorrectly read the setpoint data sheet.
However, subsequent to this finding, the licensee realized that the new set pressure
was incorrect and promptly installed valves with a setpoint of 250 psig. The team
reviewed a number of safety and relief valve data sheets for setpoints and compared
these values with the spring set pressure listed in Procedure STP-000-6606,"Section XI
10
_
_ _ .
-
_
_
.
- -
- -
- -.
.
_-
- -
_ _ - - - - - - - - -
'
l
.
.
Safety and Relief Valve Testing," Revision 6. The procedure defined the cold differential
l
test pressure as the inlet static pressure used for bench testing the valve. This set
l
pressure was adjusted for back pressure and temperature. The team noted that the
valve data sheets contained only the process setpoint, not the cold differential test
i
'
pressure. Out of 31 data sheets reviewed, the team found 13 examples where the
setpoint on the data sheet was different from the cold differential test pressure listed in
!
the test procedure. These disparities ware not unexpected because of the differences in
l
how the values are derived, but the team noted that, based on the differences noted, the
invalid use of data sheets could result in an incorrect pressure being set in the field.
The team determined that the pressure relief valve set pressure program had a
weakness since, at least in this one case, the valve data sheets were improperly used
for determining spring setpoints. For valves within the ASME Section XI inservice
Testing Program, the surveillance test procedure was required to be used for setting
pressures in the field and the data sheets were for information only. Therefore, this
l
problem did not appear to involve a safety concern, and the improper use of the data
sheets appeared to be isolated. However, the licensee agreed that further actions were
needed to correct the noted inconsistencies. The licensee's resolution of relief valve
setpoints was identified as an inspection followup item. (50-458/9816-01)
The team reviewed CR 96-1585, dated August 31,1997, which documented an
electrical spike on the reactor building annulus ventilation radiation monitor, which
caused a ventilation system isolation and autostart of SGTS Train A. The licensee
concluded that the spike was probably due to an electrical noise spike in the detector
circuitry. There were two radiation monitors and the SGTS would start if one of them
alarmed. Since 1995, there had been shc inadvertent starts of the SGTS caused by
false alarms of a radiation monitor. The underlying cause of the problem was an
l
actuation logic (one out of two) that did not preclude system actuation from a single
faulty detector. The team identified this situation as an observation but noted that the
inadvertent actuations did not present a safety concern.
The team reviewed CR 97-0804, dated May 29,1997, which documented the failure of
the HPCS pump discharge relief valve. The licensee discovered that the bellows in the
relief valve was broken, which allowed water to exit the weep hole in the valve bonnet.
The licensee performed a root cause inspection and came to a preliminary conclusion
that the bellows failed due to chloride stress corrosion cracking. The licensee consulted
the valve manufacturer who stated that the only bellows failures they had seen were
cause:I by valve cycling, which fatigued the bellows. The vendor stated that they had
not seen a beliows failure due to chloride stress corrosion cracking. During reviews
prompted by NRC questions during the inspection, the licensee determined that the
bellows in the same valve had failed in 1994. The 1994 failure was only documented as
a work request, not as a CR. As a result, the licensee had been unaware that the
bellows failure in 1997 was a repeat failure. The team was concerned that the use of
work requests could preclude the identification of repeat occurrences. Since CR
97-0804 was not yet closed, the licensee initiated another action to discuss the bellows
failure with the system engineer to determine if, during quarterly surveillance testing of
the HPCS pump, the relief valve cycled or chattered. The team noted that the failure of
the bellows would cause the opening pressure of the relief valve to be higher than
intended and, therefore, result in a higher pump discharge pressure. The team
(
11
!
.
. - _ _ _ _-__-_ - ____ _ _ __-
.
.
concluded that even with this postulated pressure increase, the increase would not
damage the system and that the system would still be operable. Review of the
licensee's determination of the root cause of the relief valve failure and the licensee's
review to investigate the possible misuse of the work request system in 1994 was
identified as an inspection followup item (50-458/9816-02).
c.
Conclusions
in most cases, engineering actions in response to CRs were satisfactory. Several
problems involving the relief valve setpoint program and a relief valve failure were noted
and brought to the licensee's attention.
E1.5 Temocrary Alterations
a.
Inspection Scope (93809)
The team reviewed the licensee's temporary alteration program and discussed some of
the safety-related temporary alterations with appropriate licensee personnel, in addition,
the team reviewed Procedure ADM-0031," Temporary Alterations," Revision 8A.
b.
Observations and Findinas
The team noted that the procedure defined a temporary alteration as any temporary
change that did not conform to approved drawings or other design documentation or
changed the design function of the equipment. The procedure specified that a
temporary alteration could not remain open beyond the operating cycle in which it was
installed unless an extension was obtained in accordance with the procedure.
Of the 11 existing temporary alterations,2 were installed in 1995,2 in 1996,3 in 1997,
and 4 in 1998. Two of the eleven temporary alterations were designated as
safety-related.
Temporary Alteration Number 96-025," Removal of Standby Liquid Control System Heat
Trace Capability and Annunciator Function," dated September 12,1996, removed an
annunciator in the control room that was intermittently clarming and considered a
nuisance and also removed power to all standby liquid control system heat trace circuits.
The licensee stated that a pending modification to the plant would eliminate the standby
liquid control system suction line heat trace controls and annunciation in the future.
The team reviewed the safety evaluation for the temporary alteration. When the system
was required to be operable in Modes 1 and 2, the sodium pentaborate se Jtion
temperature was required to be greater than 45 degrees Fahrenheit. The team noted
that with the improved Technical Specifications, the standby liquid control system was
no longer required to be operable in Mode 4 with a control rod withdrawn. The safety
evaluation stated that the ambient containment temperature was adequate to maintain
the solution above the precipitation temperature. In addition,if the ambient containment
12
j
-
-.
- ---
. - - . . - - . - - . _ _ _
- - -.-- .
..- -.
!
.
1
,
i
!
temperature decreased such that the solution temperature approached the 45 degrees
Fahrenheit limit, the tank heaters were available to provide solution heating. The
licensee concluded that because the heat tracing had no function in maintaining the
i
l
system operable or supporting the system response to an accident, there was no effect
on operation of the system with the heat tracing disabled.
l
The team questioned if consideration was given to a reactor stanup during winter with a
cold containment temperature and asked to see the minimum recorded containmcat
'
temperature. During review of this question, the licensee initiated CR 98-0991 after they
,
I
determined that the environmental design criterion's minimum containment ambient
temperature was 70 degrees Fahrenheit, whereas the minimum recorded containment
l
temperature was 60 degrees Fahrenheit. The 60 degrees Fahrenheit temperature was
recorded during an unplanned outage in January and February 1996. The licensee
performed a preliminary review of the qualified equipment in containment. The licensee
found that the equipment reviewed were generally unaffected by temperature values
l
below 70 degrees Fahrenheit. Most equipment could be shown to be operable at
l
temperatures of approximately 40 degrees Fahrenheit. As noted above, the sodium
l
pentaborate solution in the standby liquid control system required a minimum
l
temperature of 45 degrees Fahrenheit. The team was satisfied that the standby liquid
i
control system had not been adversely affected by this low temperature condition.
!
In the CR, the licensee recommended that the basis for the minimum containment
temperature of 70 degrees Fahrenheit be evaluated and revised as necessary. The
licensee also recommended that procedures should be strengthened to provide
guidance to monitor containment temperature and to take actions to maintain
temperatures during cold weather shutdowns. This issue was identified as an inspection
followup item (50-458/9816-03) pending review of the licensee's actions to determine
I
whether the 60-degree temperature excursion caused a safety concern, and whether
the 70-degree temperature limit should be reduced to accommodate future anticipated
low temperatures in containment.
Based on the low number of existing temporary alterations and quality of the
documentation, the team determined that the licensee was managing the temporary
alteration program in a satisfactory manner.
c.
Conclusions
The licensee was managing the temporary alteration program in a satisfactory manner.
A question concerning the minimum containment temperature was identified for future
followup.
.
I
~
13
1
l
l
-
-
.
.
.
E2
Engineering Support of Facilities and Equipment
E2.1
Evaluation of 10 CFR 50.59 Safety Evaluation Prooram
a.
Inspection Scope (37001)
The team reviewed the licensee's 10 CFR 50.59 Safety Evaluation Program in
accordance with Inspection Procedure 37001. This included a review of procedures and
controls, training and qualifications of personnel performing evaluations, and completed
safety evaluations.
b.
Observations and Findinas
Procedures and Controls
The procedure governing the process for conducting 10 CFR 50.59 safety evaluations
was RBNP-057,"10 CFR 50.59 License Basis Reviews and Environmental Evaluations,"
j
Revision 7. It implementeo the guidelines recommended in NSAC-125, " Guidelines for
10 CFR 50.59 Safety Evaluations," June 1989, as revised by Nuclear Energy Institute
(NEI) document NEl 96-07, "10 CFR 59 License Basis Reviews and Environmental
Evaluations," dated June 30,1998, Revision 7, to determine whether a proposed
change, test or experiment involved a change to technical specifications or an
unreviewed safety question (USO). Procedure RBNP-057 assigned responsibilities for
individuals allowed to prepare, review, and approve formal safety evaluations as well as
performing 10 CFR 50.59 applicability screenings.
The team reviewed the classifications of procedures identified by the licensee in
Procedure RBNP-057, as requiring screening and/or a 10 CFR 50.59 evaluation prior to
implementing procedure changes. A review of applicable procedures determined that
the licensee's classifications were appropriate.
j
The team identified a potential concern with program procer.'ures during review of a
10 CFR 50.59 safety evaluation screening performed for Teroporary Alteration 97-018.
This temporary alteration modified the internals of the control rod drive system flow
control valves, C11-FCVD012A/B. These valves supply seal injection / purge water to the
reactor recirculation pump seals. The temporary alteration was implemented during a
recent outage without a 50.59 evaluation.
The team was concerned that the 10 CFR 50.59 screening did not properly determine
whether a safety evaluation was required. A review of the USAR description by the
team for the recirculation pump seals did not reveal any description of the seal
injection / purge water system. Therefore, since this information was not described in the
USAR, the temporary alteration package screening determination that a 10 CFR 50.59
safety evaluation was not required, was appropriate.
14
.
.
Trainino and Qualifications
The team reviewed training outlines and materials for the initial and requalification
programs for personnel responsible to prepare and approve 10 CFR 50.59 safety
evaluations. The training materials noted the disagreements between the NRC and the
licensee regarding the definition of " increases in the consequences," as discussed later
in this section of the report.
Imolementation
The team reviewed 18 safety evaluations identified on the most recent Summary Report
of 10 CFR 50.59 changes. For each item, the team reviewed documentation of the
proposed change, the USAR review (including scope of USAR documents reviewed),
technical specification (TS) screening, and appropriateness of the safety evaluation's
conclusions. The team determined that each of these safety evaluations was
catisfactory.
As discussed above, the fusee recently adopted procedure changes, which
implemented NEl 96-07 guidance. All safety evaluations approved by the Facility
Review Committee after this procedure change went into effect (seven evaluations)
'
were reviewed in order to determine whether an inappropriate use of an " increase in
consequences" was made.
Safety Evaluation (SEN) 98-0033, " Revise LOCA Calculations," evaluated an LON,
which changed LOCA dose calculation results in USAR Table 15.6-7. The LCN was
prompted from (1) a revision of the positive pressure period (PPP) in response to NRC
Information Notice (IN) 88-76, (2) correction to inaccuracies in the suppression pool
j
water volume, (3) addition of a liquid leakage term in response to IN 91-56, and (4)
enhancement of engineered safety features liquid leakage. As a result, exclusion area
thyroid dose increased from 32.8 to 37.8 rem, and low population zone thyroid dose
increased from 50.3 to 115.1 rem. In the 10 CFR 50.59 safety evaluation
documentation, the licensee stated that, " . . . the dose consequences remain below the
regulatory limits of 10 CFR Part 100 and 10 CFR Part 50, Appendix A, General Design
Criterion (GDC) 19 as approved per NUREG-0989 and License Amendment 98." The
licensee's position was that, in the safety evaluation report (SER) for License
Amendment 98, " . . . the NRC's acceptance criteria for the removal of PVLCS are 10 CFR Part 100 and GDC 19, not the specific values calculated by either the NRC or
RBS." This statement conflicted with the NRC's publicly-stated position on increases in
consequences. The team determined that the licensee did not appropriately follow the
current 10 CFR 50.59 rule and should have declared the dose increase to be a
unreviewed safety question (USQ).
The team identified that the licensee's use of NEl guidance for " increases in
consequences"; specifically, the guidance on implied approval of 10 CFR Part 100
l
l
15
l
l
l
-
.
limits, was contrary to NRC requirement because increases in consequences involve a
)
USO when established licensee analysis values as reviewed by the NRC are exceeded.
10 CFR 50.59(a)(1) states, in part, that a holder of a license authorizing operation of a
production or utilization facility may make changes in the facility as described in the
safety analysis report without prior Commission approval unless the proposed change
involves an unreviewed safety question.
10 CFR 50.59(a)(2) states, in part, that a change shall be deemed to involve an
unreviewed safety question if the probably of occurrence or the consequences of an
accident previously analyzed in the safety analysis report may be increased.
The implementation of the USAR change as addressed by SEN 98-0033 increased the
consequences of a loss of coolant accident because the calculated doses were
increased. This was considered to be an unreviewed safety question. The failure to
obtain Commission approval prior to creating an unreviewed safety question by
changing the facility as described in the USAR was identified as a violation
(50-458/9816-04).
However, the team also noted that the low population zone thyroid dose increase was a
result of overly conservative assumptions and calculations in response to IN 91-56. The
-
IN directly applied to a potential flow path from the safety injection system to the
refueling water storage tanks and the licensee made a number of conservative
assumptions in order to create an analogous flow path from the residual heat removal
(RHR) system to the condensate storage tank. In addition, the licensee did not credit
the standby gas treatment system in their dose calculations. The team also noted that
no regulatory dose limits were exceeded as the result of this USAR change. As noted in
Section XI of this report, the licensee disagreed that this issue constitued a violation of
NRC requirements.
c.
Conclusions
Overall, the 10 CFR 50.59 program was found to be satisfactory. Safety evaluation
documentation was thorough and provided appropriate justification for the conclusions.
in one case, the licensee inappropriately concluded that a USAR change did not involve
'
an unreviewed safety question. This was identified as a violation of 10 CFR 50.59.
E4
Engineering Staff Knowledge and Performance
E4.1
General Enaineerina Experience and Competence
a.
Inspection Scoce (37550)
The team interacted with a large number of engineering and licensing staff personnel
during the inspection.
16
.. ..
_._
_
_
__
_- - .=
_
-_. - __
-_ -
-
.
.
b.
Observations and Findinas
Based on this inspection effort, the team determined that engineering personnel were
experienced and possessed good technical and plant knowledge. Personnel knowledge
included a good understanding of the engineering processes and organizational
j
interfaces involved in controlling, maintaining, and supporting the operating plant.
1
c.
Conclusions
Based on the results of this inspection, the team concluded that engineers possessed
good experience levels and competence in completing their assigned tasks.
E8
Miscellaneous Engineering issues (92903)
E8.1
(Closed) Inspection Followuo item 50-458/9621-01: Entergy Operations, Inc.,
Resolution of Quality Assurance Program Required for Resource Sharing
i
Backaround
This item was opened to track licensee action on a licensee-identified issue involving the
<
lack of clear quality guidelines controlling the procurement of services from one Entergy
site by another Entergy site. The licensee generally used standard procurement
proceaures for this process but often bypassed these controls. This was a concern
because the quality assurance programs varied from site to site.
Inspection Followup
.
To address this concern, Entergy developed Corporate Policy PL-126," Site
Providing Services to Other Sites," Revision 0, dated January 25,1997. Each
Entergy site was to revise their site procedures to be consistent with the corporate
,
policy. Procedure RBNP-093," Control of Shared Services," Revision 0, was developed
)
to implement the corporate policy and was placed into effect on June 22,1998.
Based on a review of Corporate Policy PL-126 and Procedure RBNP-093, which
appeared appropriate for the situation and internally consistent, the team concluded that
the licensee had adequately addressed this issue.
E8.2 (Closed) Inspection Followuo item 50-458/9622-01: Adequacy of Molded Case Circuit
Breaker Trip Setpoints
Backaround
Valve E51-MOVF064, RCIC turbine outboard isolation valve, failed to close because its
supply breaker tripped in response to an instantaneous reversal from an open to a close
demand signal. The licensee's original investigation did not include a review for generic
implications, in response to the NRC concern, the licensee reopened their review to
identify any generic concerns.
4
'
17
l
_ - _ -
_
_
_
i
.
As a separate concern, the NRC noted that the licensee's molded case circuit breakers
were set to trip at a maximum of 11 times the fullload current rather than the value of
1.73 times the locked-rotor current, as recommended by the Electric Power Research
Institute (EPRI). This was a concern because some high speed motors can have
locked-rotor currents approximately 10 times the full load current. Consequently, a
current of 11 times the full load current could be as low as 1.1 times locked-rotor current
for these motors.
The safety concern for both issues discussed above was that inadvertent breaker trips
could preclude the capability to remotely operate essential motor-operated valves.
Inspection Followup
The licensee issued CR 96-1110A to investigate the NRC concerns. The outcome of a
study of the locked-rotor and full load current for all safety-related high speed (>3400
rpm) motors was that 14 molded case circuit breakers were either adjusted or the trip
coils were replaced.
As a secondary corrective action, the licensee identified an additional 48 molded case
circuit breakers that had instantaneous trip coil settings that were less than 150 percent
of the measured inrush current. Of these,14 breakers had been adjusted with the
remainder to be completed by the end of 1999.
The licensee was confident that once the scheduled breaker adjustments are complete,
all of the breakers would have settings greater than the EPRI recommended 1.73 times
the locked-rotor current.
The licensee identified 19 motor-operated valves that could be susceptible to circuit
breaker trips during reversals in direction of travel. In each case, the ramifications of
this phenomenon were shown to be minimal because of administrative controls, such as
limiting conditions for operation being in effect, operators stationed locally, or other
administrative controls. The trip of Valve E51-MOVF064 occurred during a refueling
"
outage under a limiting condition for operation.
The team determined that the licensee had acceptably addressed the concerns
regarding molded case circuit breaker settings, pending additional operating experience
that may, potentially, necessitate additional actions. The team determined that the
'
licensee had not violated any plant procedures within this scenario of events.
E8.3 (Closed) inspection Followuo item 50-458/9627-02: NRR to Review Near-Buoyant
Objects
Backaround
The NRC identified a concern that objects of specific gravity slightly greater than water
(near-buoyant) could be carried by a tornado into the SSW cooling tower and be carried
into the suction of the SSW pumps. This matter was referred to the NRC program office
for further review.
i
18
.
.
Inspection Followuo
The NRC program office determined that licensees do not have to specifically address
the effect of near-buoyant debris to meet design mquirements of cooling water supplies
unless a significant source of such material exists in the vicinity and is capable of
becoming airborne due to a tornado. The team determined that a source of
near-buoyant materials, r,uch as paper, grasses, hardhats, etc., were not present in
sufficient quantities near the plant site. Even if these materials were carrieo into the
l
cooling tower, the team noted that the licensee would have some tims (a matter of days)
.
to clear the debris to ensure adequate long-term cooling.
l
E8,5
(Closed) Licensee Event Report 97-007: Cracked Screw Assembly Swivel Pads on
Emergency Diesel Generators Could Have Prevented Fulfillment of Safety Function
Backaround
The licensee issued CR 97-1647, " Swivel Pads on Cylinders 1 and 2 of the Div 11 Diesel
Generator have Cracks," on September 28,1997. The licensee discovered that six
valve adjusting screw assembly swivel pads (VASASPs) on the Division i emergency
diesel generator (EDG) and four VASASPs on the Division 11 EDG were cracked. The
VASASPs work in conjunction with the valve adjusting screw assemblies, which are
threaded screws that allow a fine adjustment of the valve clearances on the EDG. A
failure in this system could cause a loss of EDG function. Although the VASASPs were
cracked, they were functional and could have supported continued EDG operation.
However, as a conservative measure, the licensee declared both EDGs inoperable. The
plant was in Mode 5 at this time and the licensee entered the appropriate limiting
condition for operation. Within 4 days, all VASASPs, whether cracked or not, on both
EDGs had been replaced, and both EDGs were declared operable.
Inspection Followuo
The team reviewed the licensee event report and CR 97-1647. In the root cause
determination, the licensee, in consultation with the manufacturer, determined that the
cracks resulted from three conditions: (1) the material lot used to manufacture the
VASASPs was incorrect and had lower toughness than desired for the application, (2)
the swaging of the VASASPs socket over the ball of the valve adjusting screw
assemblies was performed to an excessive degree during the manufacturing process,
and (3) the ball on the valve adjusting screw assembly of at least one of the cracked
assemblies had an edge that helped to precipitate the crack. The licensee inspected
the replacement units before they were installed and determined that none of them were
affected by any of the above three conditions. This determination was supported by
discussions with the manufacturer, who shted that the swaging process had been
revised to prevent excessive swaging and that the materials used in the manufacturing
process were of sufficient toughness.
The licensee addressed the generic aspects of this event by considering two
possibilities: (1) that other components procured from the same manufacturer had
similar material and processing deficiencies, and (2) that the manufacturer had supplied
other nuclear utilities with defective VASASPs. With regard the first issue, the licensee
19
- _ _ - _ _ _
__
-_
_ - ___ _
.
.
reviewed the vendor's quality assurance program and reviewed the material history of
components supplied the manufacturer. Based on this information, the licensee
concluded that, absent information to the contrary, it was reasonable to consider the
EDGs operable pending discovery of any additional defects. With regard to the second
issue, the licensee determined that only one other nuclear plant used VASASPs of this
type, and that plant had not installed any VASASPs processed from the defective
material lot. The manufacturer processed a report in accordance with 10 CFR Part 21
to notify the industry of the problem.
The team determined that the licensee had adequately addressed the defects
discovered in the VASASPs. Corrective actions were comprehensive and appeared
sufficient to preclude rer-rence of the event.
E8.6 Enaineerina Backloa
a.
Insoection Scope (37550)
The team reviewed the licensee's engineering backlog and the manner in which it was
being trended and tracked. In addition, the team discussed the backlog with appropriate
licensee personnel.
b.
Observations and Findinas
The engineering backlog had a downward trend since January 1997. For design
engineering, the total engineering workload decreased from approximately 1900 items in
January 1997 to approximate!y 1000 in June 1998. The design engineering backlog
consisted of ERs, open modifications, open CR actions, and other miscellaneous items.
The system engineering backlog also had a slightly downward trend since January
1997, with a reduction from 170 to 149 items.
The number of open temporary modifications had a downward trend since 1992, at
which time there were 73 open temporary modifications. At the time of this inspection,
only 11 remained open. The licensee's goal of maintaining the number of temporary
alterations less than or equal to 15 had been met since 1996.
c.
Conclusions
The team concluded that the engineering backlog was declining and was being
managed effectively by the licensee.
E8.7 System Enaineerina
l
a.
Insoection Scope (37550)
The tearn discussed the status of the system engineering department with applicable
department managers. In addition, the team interviewed some of the system engineers.
I
20
__
. -
. _ . _ _ _ _ _
. _
. . _ . _ _ _ _ _ _ _
- _ _ . _ . _ _ _
l.-
l
l
.
t
b.
Observations and Findinos
!
The system engineering department consisted of approximately 22 to 24 engineers, with
each system engineer responsible for three to five systems. The system engineering
manager stated that the number of system engineers had remained steady for the past
l
few years, in October 1997, the licensee initiated a team concept for the system
l
engineers where three or four engineers shared a number of primary systems.
'
Eventually, each member of the system engineering team would become an erjert on
all of the systems within the team's responsibility. The system engineers who were
interviewed believed that the team concept was good since it allowed for peer review of
each other's work. The team considered the team concept to be a strength,
c.'
Conclusions
System engineering appeared to have adequate staffing and was stable. The team
'
concluded that the system engineering team concept was a strength.
l
E8.8
USAR Review Procram
l
i
a.
inspection Scope (37550)
l
!
The team reviewed the licensee's program for reviewing the USAR. The review was
focused on portions of the effort that affected the SGTS and the HPCS system.
b.
Observations and Findings
The USAR review effort was described in "USAR Review Procedure," Revision 3, dated
May 7,1998. Section 1.2 of this procedure stated that the objective of this review was
,
,
l
to improve USAR accuracy through a reasonableness review and to identify the areas of
the USAR that require a more detailed evaluation. The review process relied on the
personal experience and knowledge of the designated reviewer and on the review of
pertinent documents. The designated reviewers were assumed knowledgeable in the
aubject matter and could exercise their judgment in using the procedure. A line-by-line
compliance to the guideline was therefore not necessary as long as the review objective
was met and the review was appropriately documented. The review therefore was not
intended to verify and validate full accuracy of the USAR text. However, during the
review, areas of the USAR requiring a detailed examination were to be identified for
future action.
j
For the purpose of the review, the USAR was divided into 151 parts. At the time of the
inspection,18 of the 151 parts had been reviewed and approved as part of the Phasa 1
i
" reasonableness" review. The remaining parts were in various stages of completion.
I
Nonc of the USAR sections for the plant systems selected for the team's review had
been completed (i.e., SGTS and HPCS). However, portions of these sections were in
various states of completion. At the request of the team, the licensee provided the
partially completed packages for review.
!
!
!'
21
!
l
,
.
_ _.
.
.
To obtain some insight into the nature and quality of the review process, the team
selected the package for the mechanical review of USAR Section 6.3," Emergency Core
Cooling Systems," for an in-depth evaluation. The licensee reviewer found that the
information in the section was appropriate for the subject matter and that the section
reasonably reflected the plant design and operating conditions. Some references to
other USAR sections, figures, tables, and external documents were found to be
incorrect and some editorial errors were identified. There were no obvious technical
inaccuracies or areas of technical concern to the reviewer. The team concurred with the
reviewer's assessment of this section.
c.
Conclusions
The ongoing USAR review effort appeared to be satisfactory; although, the team noted
that the review was not a line-by-line verification.
E8.9 Year 2000 Computer issue
a.
Inspection Scoce (37550)
The team reviewed the licensee's plans for ensuring the continued operability of digital
equipment in the year 2000.
b.
Observations and Findinas
The team reviewed " Year 2000 Desktop Guide," Revision 0, dated July 28,1998, which
established the licensee's plan to ensure that plant systems and components influenced
by digital circuitry will continue to operate safely and efficiently following January 1,
2000. The guide also identified additional dates that could result in computer difficulties.
The licensee employed 11 full-time contractors along with in-house participation to
address this issue. All work on critical systems was scheduled to be completed by
January 1,1999, with continued work on important systems to be completed in July
1999. At the time of the inspection, this activity was approximately two weeks behind
schedule, but, based on the resources available, the licensee did not believe that
meeting the deadlines would be a problem or that excessive use of overtime work would
be needed.
The team observed that the licensee's program was comprehensive and that strong
management support was evident.
c,
Conclusions
The licensee's program to address the Year 2000 computer problem appeared to be
satisfactory.
22
.~
.
.
IV. Plant Support
F8
Miscellaneous Fire Protection issues (92904)
The team reviewed the following items that were identified during the NRC's Fire
Protection Functional Inspection (FPFI) and documented in NRC Inspection
Report 50-458/97-201. The team also reviewed the licensee's June 30,1998, response
to the FPFI report.
F8.1
(Closed) Unresolved item 50-458/97201-01: Smoke detector application, placement,
and installation in fire area C-24 does not meet requirements of License
Condition 2.C.10.
Backaround
The FPFI team reviewed the placement of smoke detectors in Fire Area C-24. The
FPFI team observed that the smoke detectors were not installed in the pockets between
the ceiling beams. The licensee performed Calculation G13.18.12.2-127," Evaluation of
Smoke Detector Installation in Fire Area C-24 As Compared to NFPA-72E-1978,"
Revision 0, to address the FPFI concern. The calculation concluded that the fire
detectors were installed in accordance with the Code of Record and the licensing basis.
Inspection Followuo
The licensee's evaluation stated that the detectors were installed in accordance with the
National Fire Protection Association (NFPA) Code of Record, NFPA-72E-1978, for the
plant fire detection system. The team reviewed Calculation G13.18.12.2-127,
Revision 0, the Code of Record, and the installed configuration of the detection system
in Fire Area C-24. The team verified that the licensee's conclusion was correct and that
the system was installed in accordance with requirements.
F8.2
(Closed) Unresolv9.0 item 50-458/97201-02: Failure to include fire protection check
valves in a functional testing program.
Backaround
As described in Section 9.5.1.2.2.0," Seismic Design Requirements," of the USAR, a
Seismic Category I water supply is provided from the standby service water (SSW)
system to the seismically designed fire protection standpipe system to provide water for
hose stations serving equipment required for safe plant shutdown following a safe
shutdown earthquake. A seismically-qualified check valve is located in the normal fire
protection water supply piping upstream of each of the three SSW system cross
connections. These hose station supply header check valves are designed to prevent
diversion of SSW system flow through a break in the nonseismically qualified fire
protection water supply piping when the SSW system is being used as the fiie protection
.
23
!
l
,
.
-
--
-
.--
-
!-
l
l
water supply. The NRC identified that the licensee did not have procedures for testing
these check valves. The subject valves were: Valve FPW-319," auxiliary and reactor
building fire protection header to hose racks inlet check valve"; Valve FPW-V395, " fuel
I
building fire protection header hose racks header check valve"; and FPW-V820, " control
building fire protection header hose racks inlet check valve."
inspection Followup
The licensee's FPFI report response stated that the subject valves were tested in
accordance with the requirements of the Technical Requirements Manual (TRM) and
that the setject valves were verified to open in accordance with the TRM-required
Procedure, STP-251-3702, every 3 years. The team reviewed Procedure
STP-251-3702, " Fire Hose Station Water Flow Test and Hose Hydro inspection,"
Revision 7. The team noted that this procedure implemented the requirements of
surveillance requirement TSR 3.7.9.4.4 by partially opening each hose station valve to
verify that the valves were operable and that there was no flow blockage. This test
involved cracking open the hose rack angle valve to allow 2 to 3 gallons of water to flow.
The team concluded that performing this test at each hose station resulted in only a
partial stroke of the hose station supply header check valves. There was no test to
j
verify that the check valves had closed.
The licensee's FPFI report response identified that the subject check valves were
reviewed in an engineering analysis, which recommended that they could be screened
from additional testing. The team reviewed Engineering Document No.1961C," River
Bend Station Check Valve Program Development," Revision 0. The check valve
analysis and prioritization that were performed as part of this evaluation concluded that
the subject valves were * Priority 5/ low usage," and recommended that the valves be
inspected every five plant operating cycles. The licensee used the recommendation of
this study, combined with the good historical performance and maintenance history of
these and similar valves, to conclude that no additional testing or inspections were
necessary. The team did not have a concern with the technical adequacy of this
conclusion.
The team reviewed Procedure STP-251-3502," Fire Protection Water Valve Cycle
Test," Revision 9, and verified that the manual isolation valves immediately upstream
of the hose station supply header check valves were included in the test. These
seismically-qualified, normally open, manual isolation valves were required to be
cycled through at least one complete cycle of full travel every 12 months.
Procedure STP-251-3502 accomplished this requirement. These valves provided
additional assurance that if the SSW system was required for fire protection water
system supply following a safe shutdown earthquake, a break in the nonseismically
qualified portion of the fire protection system could be isolated.
The team asked the licensee for a copy of the procedure that would be used to place
the SSW system in service as a source of fire protection water if necessary following a
l
safe shutdown earthquake. The team was informed that there was no procedure for
i
accomplishing this task and were provided with a copy of CR 98-0214, dated
February 26,1998, that also identified that there were no procedures to implement this
.
function. The CR identified a corrective action for Plant Engineering to develop a scope
I
24
l
l
- .-
-
-
. -
-
-
_ _ .
- - .
.
and outline of operating instructions to place the SSW system in service to supply water
to the fire protection system in the event of a loss of the fire protection water supply.
This corrective action had a due date for completion of August 26,1998. The CR
identified another corrective action for Operations to develop a procedure using the
outline developed by Plant Engineering. This corrective action had a due date for
completion of June 30,1999.
The team was concerned that this due date may not be appropriate and that operators
may not be knowledgeable of the capability or have the necessary training for placing
.
the SSW system in service in the event of a loss of fire protection water supply before
the procedure is written. The licensee provided the team with a copy of System Training
Manual Lesson Plan RBS-1-STM-GPST-A0118.00," Service Water Systems." This
lesson plan identified that operators were taught that the SSW system was capable of
providing a backup source of water to the fire protection system by means of opening
the manually-operated cross-connect valves. The licr;nsee also provided the team wi'h
a copy of Emergency Operating Procedure EOP-0005," Injection lato RPV with Fire
System," Revision 11, which identified procedural steps for using the fire protection
water supply system to inject into the reactor via the SSW system cross-connect valves.
,
Based on the existence of this procedure and operator training regarding capability of
j
the SSW system as a backup supply of water for the fire protection system, the team
j
concluded that there was no safety issue, which would require immediate action to
J
implement the corrective actions identified in the CR. The team did note, however, that
the SSW system lesson plan provided operators with incorrect training. The training
stated that check valves in the SSW system piping prevented fire protection system
water from entering the SSW system. These check valves had been previously
removed to allow a means of injecting water into the reactor per EOP-0005. The
licensee acknowledged the team's observation and initiated actions to correct the
training.
Technical Specification 5.4.1.d required that written procedures shall be established,
implemented, and maintained covering fire protection program implementation. The
failure to have written procedures for using the SSW system as a source of water to the
fire protection system, as described in the fire protection program, was a violation of
Technical Specification 5.4.1.d. This nonrepetitive, licensee-identified failure, which is
scheduled for correction by the licensee, is being treated as a noncited violation,
consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-458/9816-05).
F8.3
(Closed) Unresolved item 50-458/97201-03: Lack of engineering evaluations to
'
establish the fire-rating or fire-resistant capabilities of fire-rated boundaries.
Backaround
The FPFI team identified that the licensee did not have acceptance criteria for the
clearance around a fire door that was in accordance with the requirements of National
Fire Protection Association (NFPA) 80. The team reviewed the licensce's evaluation of
fire door clearance acceptance criteria.
25
,
.
Inspection Fo.suo
The licensee provided copies of a fire door test conducted October 22,1986, by the
door manufacturer for the type of doors used at the station. The test demonstrated that
the door successfully passed a 3-hour fire endurance test. Therefore, the team
concluded that the licensee adequately demonstrated that the installed fire door
configuration would pass a 3-hour fire test.
F8.4
(Closed) Unresolved Item 50-458/97201-04: Outdated equipment and failure to assign
personnel to the fire brigade who have normal plant duties that do not conflict with their
response to a plant fire.
Backaround
The FPFI team identnied that the licensee's fire brigade personnel protection equipment
was outdated by current technology. The FPFI team also identified that the licensee
was not implementing the fire brigade staffing in accordance with a document, which
was referenced by the SER. The team reviewed the licensee's response to these two
fire brigade issues.
Insoection Followup
The licensee reviewed the FPFI team observation concerning the quality of the
personnel protection equipment for the fire brigade. At the time of this inspection, the
licensee had on order or had received state-of-the art fire protection equipment for fire
brigade members.
The facility operating license requires that the licensee implement the approved fire
protection program as approved in the USAR, the safety evaluation report (SER) dated
May 1984, and Supplement 3 to the SER dated August 1985. Section 9.5.1.3 of the
SER stated that the licensee committed to implement the NRC supplemental guidance
provided in " Nuclear Plant Fire Protection Functional Responsibilities, Administrative
Controls and Quality Assurance," dated August 29,1977. This letter stated that the
responsibilities of the fire brigade members, under normal plant conditions, should not
conflict with their responsibilities during a fire emergency. The licensee determined that
the statement in the SER (concerning the subject commitment) was in error because
they had never made the referenced commitment in any licensing submittals. The
licensee stated that they would send a letter to the NRC to document and correct the
error. The team reviewed the licensee's current fire brigade staffing requirements in the
approved fire protection program and noted that the licensee complied with the
requirements identified in 10 CFR Part 50, Appendix R. The team reviewed licensee fire
brigade drill response time records for the 18 months preceding this inspection and
noted that the fire brigade responded in a timely manner during these drills.
The team concluded that the licensee was taking actions to ensure that fire brigade
personnel had state-of-the art personnel protection equipment. The team also
concluded that the fire brigade members could respond to a fire in a prompt manner.
26
_
-
- - - . . =
c
.
F8.5
(Closed) Unresolved item 50-458/97201-05: Failure to perform an adequate operability
assessment and provide appropriate compensatory measures for conditions affecting
the functionality of post-fire safe-shutdown capability.
Backaround
The FPFI team identified that the licensee had removed an installed Thermo-Lag fire
barrier, rendering the barrier inoperable, while maintaining only an hourly fire watch
patrol. The FPFI team was concerned that since the barrier had been completely
removed, the compensatory measures that the licensee implemented were less than
adequate.
Inspection Followuo
The team observed that the licerdee's fire protection program required that an hourly
fire watch patrol be implemented when a missing or degraded fire barrier was identified.
The team found that the licensee implemented the requirements of the fire protection
program. However, during interviews with licensee personnel, they indicated that they
understood the concern expressed by the FPFI team that additional fire protection
enhancements may be warranted for planned impairments of significant portions of a
fire protection system. The licensee's position was that additional fire protection
enhancements could have been considered for this impairment but that the
requirements of the fire protection program were not violated in this case. The team
agreed with the licensee's conclusion that the use of an hourly fire watch patrol was
consistent with regulatory requirements. The team concluded that although the licensee
should have considered the implementation of additional fire protection features t".
compensate for the removed Thermo-Lag barrier, no violation occurred.
F8.6
LClosed) Unresolved item 50-458/97201-06: Failure to perform an adequate post-fire
safe-shutdown analysis that meets the licensee commitment to Sections lil.L.1, Ill.L.2,
and Ill.L.7 of Appendix R to 10 CFR Part 50.
Backaround
The FPFI team questioned whether the licensee performed an adequate post-fire safe
shutdown analysis. Specifically, a postulated fire in certain areas of the plant could
potentially cause all 16 safety relief valves (SRVs) to simultaneously open. The licensee
had identified this issue in 1996 but had determined that it was not credible and that
further consideration of the issue was not within the scope of its fire protection program
requirements.
Inspection Followun
Operating License NPF- 47, Condition 2.C.10, required that the licensee shall comply
with the requirements of the fire protection program as specified in Attachment 4 to the
license. Attachment 4 required that the licensee implement and maintain in effect all
provisions of the approved fire protection program as described in the Final Safety
Analysis Report for the facility through Amendment 22 and as approved in the SER,
dated May 1984, and SER Supplement 3, dated August 1985.
27
-
. ,
-
--
__.
- .
.
.
The SER Supplement 3, page 9-13, stated that the fire protection program was in
conformance with the guidelines of Branch Technical Position CMEB 9.5-1and
10 CFR Part 50, Appendix R, Section Ill.G. The United States Courts have held that for
fire areas where alternative or dedicated shutdown is chosen, then 10 CFR Part 50,
Appendix R, Section Ill.L must apply. Therefore, the team concluded that the
requirements of 10 CFR Part 50, Appendix R, Section s Ill.G and Ill.L were applicable
as referenced to License Condition 2.C.10.
Each of the 16 SRVs was provided with a Division I and a Division 11 solenoid.
Energization of either solenoid caused its associated SRV to open. Four Rosemount
pressure transmitters were located in the reactor building and converted a reactor
pressure input signal into a de output signal. Two of the transmitters were used for the
Division l SRV solenoids and the other two were used for the Division ll SRV solenoids.
A high pressure condition detected by both pressure transmitters for either division
j
satisfied the controllooic to energize their associated set of solenoids and open all
i
16 SRVs.
The two twisted pairs of pressure transmitter signal conductors for each division were
contained in a common multi-conductor cable from the containment penetration to the
l
trip unit in the main control room. If one of the wires in a pair were too short to the other
wire of the same pair, a high RCS pressure signal would be received by the SRV
pressure logic trip unit. If the other pair in the same cable were to short together, a
second high-RCS pressure signal would be received by the SRV pressure logic trip unit,
which would satisfy the trip logic to open the SRVs. The fault current caused by these
circuits was too low to cause the circuit protective fuses to open. Therefore, fire
damage to either of two multi-conductor cables (Division I or Division 11) could cause the
trip logic to be satisfied and result in the spurious opening of all 16 SRVs. Opening all
SRVs when the reactor is at full power would result in a blowdown to the suppression
pool and a rapid reactor pressure vessel depressurization.
in 1996, the licensee identified the potential that fire-induced circuit failures within a
single multi-conductor cable could result in spurious high-pressure signals that would
cause all of the SRVs to open. In Engineering Report (ER) 96-0672, dated November
18,1996, the licensee stated its position that only one fire-induced spurious operation
need be assumed during the fire event requiring alternate shutdown except in the case
of hi/lo pressure interfaces. Specifically, the licensee took the position that since it
would take two shorts to occur in either single multi-conductor cable of concern, and that
these conditions need not be assumed to occur concurrently, the single multi-conductor
cable was an acceptable condition. The licensee based its position on its interpretation
of the response to Question 5.3.10 in Generic Letter (GL) 86-10. " Implementation of Fire
Protection Requirements," April 24,1986. No modifications were performed or planned
to correct the condition.
Question 5.3.10 of GL 86-10, " Design Basis Piant Transients," states, "What plant
transients should be considered in the design of the alternative or dedicated shutdown
systems?" The response states,"Per the criteria of Section Ill.L of Appendix R, a loss
of offsite power shall be assumed for a fire in any fire area concurrent with the following
assumptions: (a) the safe shutdown capability should not be adversely affected by any
one spurious actuation or signal resulting from a fire in any plant area; (b) the safe
28
>
shutdown capability should not be adversely affected by a fire in any plant area, which
results in the loss of all automatic functions (signals, logic) from the circuits located in
the area in conjunction with one worst case spurious actuation or signal resulting from
the fire; and (c) the safe shutdown capability should not be adversely affected by a fire
in any plant area, which results in spurious actuation of the redundant valves in any one
high-low pressure interface line.
The team considered that the licensee's conclusions regarding this issue were in error.
The licensee's interpretation that only one circuit failure (one twisted pair of wires
shorting together) needed to be considered did not meet the NRC's implementation
guidance in the GL 86-10 response to Question 5.3.1. This question," Circuit Failure
Modes," states, "What circuit failure modes must be considered in identifying circuits
associated by spurious actuation?" The response states,"Section s !ll.G.2 end Ill.L.7 of
Appendix R define the circuit failure modes as hot shorts, open circuits, and shorts to
ground. For consideration of spurious actuations, all possible functional failure states
must be evaluated, that is, the component could be energized or de-energized by one or
more of the above failure modes. Therefore, valves could fail open or closed; pumps
could fail running or not running; electrical distribution breakers could fail open or
closed. For three-phase AC circuits, the probability of getting a hot short on all three
phases in the proper sequence to cause spurious operation of a motor is considered
sufficiently low as to not require evaluation except for any cases involving Hi/Lo
pressure interfaces. For ungrounded de circuits, it it can be shown that only two hot
shorts of the proper polarity without grounding could cause spurious operation, no
further evaluation is necessag except for any cases involving Hi/Lo pressure
interfaces." Since the SRVs were not Hi/Lo pressure interfaces and the SRV circuitry
did not meet either of the exceptions discussed in the answer to Question 5.3.1,
evaluation of the SRV circuitry was required.
Section Ill.G.2 of Appendix R specified that where cables or equipment including
associated nonsafety circuits that could prevent the operation or cause the maloperation
due to hot shorts, open circuits, or shorts to ground of redundant trains of systems
necessary to achieve and maintain hot shutdown conditions were located within the
same fire area outside primary containment, that they be provided with fire protection
features necessary to ensure that they remain free of fire damage in accordance with
Appendix R, Section s Ill.G.2.a b, or c.
Appendix R, Section Ill.G.3, specified that alternative or dedicated shutdown capability
is required where the protection of systems whose function is required for hot shutdown
does not satisfy the requirement of Appendix R, Section Ill.G.2.
For a fire in the main control room, the system credited in the fire hazards analysis for
alternative shutdown reactor pressure vessel level control was the steam-driven reactor
core isolation cooling (RCIC) system. However, if all of the SRVs were to spuriously
open due to shorts of the SRV pressure transmitter conductors, the rapid
depressurization would eliminate the steam pressure required to drive the RCIC system
i
29
_ _ . _ _ . . _ _ . - _ _
_ ___._.._._ _
_ . _
l .
.
turbine. Therefore, because fire-induced short circuits of the SRV pressure transmitter
conductors (located in the same fire area) could prevent the operation of the RCIC
system, which was required to achieve and maintain hot shutdown conditions, the
licensee was not in conformance with Appendix R, Section Ill.G.2. If a licensee does
not comply with Appendix R, Section Ill.G.2, then the licensee is required to provide
alternative or dedicated shutdown capability per the requirement of Appendix R,
Section Ill.G.3.
The normal emergency core cooling system (ECCS) and reactor feedwater systems
were not electrically isolated from the effects of a main control room fire. Therefore,
their availability to perform an RCS makeup function cannot be assured (e.g., there is
potential for a main control room fire to damage ECCS initiation logic, cause spurious
closing of ECCS flowpath valves, or cause spurious ECCS pump shutdowns).
Ii'
Using the GL 86-10 guidance, should a postulated control room fire occur that required
l
evacuation, a reactor trip must be initiated as the operators leave to go to the remote .
shutdown panel. If th,e SRVs were to spuriously open, a rapid RCS depressurization
'
would occur. As a result of this depressurization, the RCIC system would be
unavailable. The "A" train of the RHR system was protected from the effects of a fire,
but it would be in a suppression pool cooling mode lineup for decay heat removal rather
than low pressure coolant injection (LPCI). An operator at the remote shutdown panel
would have to manually realign the system from the suppression pool cooling mode of
'
operation to the LPCI mode of operation.
10 CFR Part 50, Appendix R, Section Ill.L, required, in part, that the alternative
shutdown capability shall be able to maintain reactor coolant inventory and that it be
capable of maintaining the reactor coolant level above the top of the core. The licensee
performed an analysis of this event, which concluded that if the operator initiated
injection using the RHR system within 10 minutes after event initiation, the ECCS
!
acceptance criteria of 10 CFR 50.46 were not exceeded but reactor coolant level would
not be maintained above the top of the core. Therefore, an alternative or dedicated
,
shutdown capability was not provided in accordance with Appendix R, Section Ill.G.3
that met the performance goals of Appendix R, Section Ill.L. This was a violation of
License Condition 2.C.10.
The NRC had a meeting with the licensee to discuss this issue at on August 19,1997.
At this meeting, the licensee reaffirmed the position that considering multiple circuit
failures was outside the scope of Appendix R and the Generic Letter 86-10
implemenMon guidance. The licensee also presented information at the meeting that
concluded that this event was of very low probability and was not risk significant
in its response to the FPFI report, dated June 30,1998, the licensee committed to
implement a modification to mitigate the effects of any hypothetical SRV cable short
j
during the April 1999 refueling outage. However, the licensee reiterated its position that
i
its present configuration was in compliance with the fire protection program licensing
basis.
i
30
-.
-
-.
-
_ .
. -
.
.-
-.
.. . _ - . .
-- .
- - - - .
.
.-
.
d
!
The NRC had a meeting with the licensee on July 29,1998. At that meeting, the
licensee described conceptually a modification that would bypass the short circuit signal
l
and eliminate the spurious SRV actuation concern. The licensee reiterated its
commitment to install the modification during the April 1999 refueling outage.
The team noted that the licensee had proceduralized operator actions and had
conducted operator training to mitigate the post-fire SRV actuation event as described
above. Also, the team noted that although a refueling outage had already occurred
since the time of the FPFI inspection when a modification could have been performed,
'
the licensee had committed to perform a modification within a reasonable time after the
i
issuance of the FPFI report.
)
In accordance with Section Vll.B.6 of the NRC Enforcement Policy, the NRC exercised
its enforcement discretion to not propose a civil penalty and to not issue a violation in
this case. Discretion was warranted because: (1) the apparent widespread
misunderstanding of the requirements, (2) the fact it was licensee identified, (3) the low
risk significance, (4) the fact that the licensee took compensatory actions, and (5) the
]
l
licensee commitment to implement a modification during the next refueling outage that
'
will correct the condition.
F8.7
(Closed) Unresolved item 50-458/97201-07: Deficiency in the design of the reactor
overpressure protection system, under certain postulated conditions, could lead to
inadvertent actuation of 16 SRVs resulting in an un-analyzed plant transient.
Backarourt_d
,
'
The FPFI team questioned whether the design of the safety relief valve (SRV) actuation
I
circuitry complied with the requirements of general design criteria (GDC) 23 of
l
10 CFR Part 50, Appendix A. GDC 23 requires, in part, that the protection system be
designed to fail in a safe condition if a postulated adverse environment (such as a fire) is
experienced. The FPFI team was concerned that the protection system was not
designed to fail in a safe condition as exemplified by a postulated fire causing two
conductor-to-conductor shorts in a reactor pressure vessel pressure transmitter cable
'
and simultaneous opening of all 16 SRVs. The postulated transient had not been
j
reviewed in the safety analysis report.
Inspection Followup
The team reviewed the design of the SRV overpressure logic, the reactor protection
l
system, and the engineered safety features to determine whether the SRV overpressure
logic circuitry was within the scope of GDC 23.
The team reviewed USAR Section 3.1,"Conformance with NRC General Design
Criteria," Section 7.2, " Reactor Protection (Trip) System," and Section 7.3, " Engineered
Safety Features." USAR Figure 7.2-1, Sheet 3, identified that the four reactor vessel
1
,
31
_ _
_ _ _ _ _ _ _ _ _ . _ . _ . _ _ . . - . _ _ _ _ _ _ . _ _ . . _ _
_ _.. _ _
.
4
pressure transmitters that provided input to the reactor protection system were
B21-PTN078A, B21 PTN078B, B21-PTN078C, and B21-PTN078D. The pressure
transmitters that provided input to the SRV overpressure logic were B21-PTN068A,
B21-PTN0688, B21-PTN068E, and B21-PTN068F. Therefore, the SRV overpressure
. logic circuitry was not part of the reactor protection system addressed by GDC 23.
The GDC discussion in USAR Section 3.1 also referenced USAR Section 7.3. The
applicable discussion therein concerned the automatic depressurization system (ADS).
The team reviewed Section 7.3, and noted that although Section 7.3 included a
i
description of the SRV overpressure logic circuitry in Figure 7.3-2, Sheets 6 and 6A,
l
which used the affected pressure transmitters, ADS actuation did not require reactor
.
pressure as an input. Therefore, the SRV ov9rpressure logic circuitry was not
l
necessary for ADS actuation and not part of the protection system addressed by
'
Based on the above review, the team concluded that the SRV overpressure logic
circuitry was not part of the protection system as identified in GDC 23.
F8.8
Other FPFI issues
The team reviewed the following additional FPFI issues that were identified as " Program
Weaknesses" in the FPFI inspection Report.
F8.8.1 Fire Suporession System in Fire Area C-4
a.
Insoection Scope
The FPFI team observed that the licensee had installed six side wall sprinkler heads to
provide automatic suppression in Fire Area C-4. The FPFI report noted that the heads
were not installed in accordance with the applicable NFPA Code and that no Code
deviation evaluation had been performed. The team reviewed licensee Calculation
G13.18.12.2-126," Justification for Deviations From NFPA 13-1983 For Suppression
System AS 6C in Fire Area C-4," Revision 0. The team also conducted a visual
inspection of Fire Area C-4.
b.
Observations and Findinas
The licensee completed Calculation G13.18.12.2-126 after the FPFI and the calculation
confirmed that the side wall sprinkler installation deviated from the requirements of
NFPA Code 13-1983. However, the calculation concluded that the deviation was not
safety significant. The team visually inspected Fire Area C-4 and noted that
combustible materialloading in the fire area was extremely low. The team also noted
that there were additional upright sprinkler heads instalied, in accordance with NFPA
Codes, throughout the fire area. Therefore, the team concluded that the as-built fire
suppression system was acceptable.
i
!
32
l
_ _ _ _ _ _
.
.
With regard to the generic aspects of this issue, the licensee informed the team that it
performed walkdowns of each fire area and did not identify any areas where the fire
suppression or detection system was inadequate. Additionally, the licensee planned to
perform a rigorous fire protection system design basis reconstitution effort, including
Code reconciliation. Deviations identified would be appropriately evaluated.
Operating License NPF-47, Condition 2.C.10, specified that the licensee shall comply
with the requirements of the approved fire protection program. The fire protection
program stated that the sprinkler systems were designed using the guidance of
NFPA 13; however, no deviation from the NFPA Code was described in the program.
Generic Letter 86-10 informed licensees' that deviations from the Code should be
identified and justified. This failure constituted a violation of minor significance and was
not subject to formal enforcement action.
c.
Conclusions
The team concluded that the licensee's evaluation was adequate to demonstrate that
full NFPA Code compliance was not needed for the side wall sprinkler heads in Fire
Area C-4 after this deviation was identified by the FPFI team. The failure to have
identified and justified this deviation from the NFPA Code was determined to be a
violation of minor significance.
F8.8.2 Control of Combustible Materials
a.
Inspection Scope
The FPFI team identified that Procedure FPP-0040, " Control of Transient
Combustibles," Revision 7, may not provide adequate control of transient combustible
materials in the plant. The team reviewed Procedure FPP-0040, visually inspected
housekeeping in various plant areas, and interviewed licensee personnel responsible for
the program.
b.
Observations and Findinas
The team observed that Procedure FPP-0040 did not explicitly contain each statement
contained in the NRC guidance concerning control of transient combustible materials.
The team observed that personnel were allowed to leave some small amount of
materials at the job site that had work in progress without formal review by the fire
protection staff. Tir team observed, however, that there was no excessive amount of
transient materials in the plant. The team noted that each small amount of materials left
in the plant had a " Work in Progress" sign in the area, which was dated and had a
responsible organization listed. The team did not observe any " Work in Progress" signs,
which had been left in place for an excessive amount of time. Interviews with
responsible plant personnel demonstrated that the staff had a high awareness of the
issue and could quickly identify and remove any excessive combustible materials that
might accumulate in the plant.
33
..
.
.
.
.
.
. _ _ _ _ _ _ _ _ _ -
. _ - . . - .._
..___m._
. . _ . _ . _ . . _ . _ . _ . _ - . . _ _ _ . _ . _ _ _ _ . _ . _ . . _ . _ . _ . _ . _
.
c.
Conclusions
l
The team concluded that the licensee was effectively controlling the use of transient
l
combustible materials.
1
V. Manaaement Meetinas
XI
Exit Meeting Summary
l
The team presented the preliminary inspection results in a debriefing to members of
l
licensee management on August 7,1998. The licensee acknowledged the findings
presented, but disagreed with two of the proposed violations discussed during the
meeting. The licensee did not agree that the issue stated in Section E2.1 of this report
constituted a violation of 10 CFR 50.59. In this matter, the licensee stated that they
l
were implementing the guidance of the Nuclear Energy Institute that was disseminated
j
l
industry-wide. The team explained that, since the NRC does not fully endorse this
guidance, utilities that use it are vulnerable to enforcement action. The licensee also did
not agree with a violation of failure to protect against the effects of a control room fire as
described in Section F8.6 of this report. In this case, the licensee believed that it was in
compliance with the regulations, and that guidance in Generic Letter 86-10 specifically
exempted the subject wiring configuration. As stated in the report, this violation was not
j
issued on the basis of an exercise of enforcement discretion.
1
Following additionalin-office review, the team presented the inspection results to
members of licensee management via telephone on October 15,1998.
.
The licensee was asked whether any materials examined during the inspection should
l
be considered proprietary. The licensee stated that some information reviewed by the
team was proprietary. This information was returned and was not discussed in the
report.
1
i
34
- .
. -
.-- -
--
-
- - - .
1
'
-
a
.
i
e
,
,
i
ATTACHMENT
SUPPLEMENTAL INFORMATION
- PARTIAL LIST OF PERSONS CONTACTED
Licensee
.
-
!
R. Azzerello, Manager, Electrical and instrumentation and Control Engineering .
_V. Bacanskas, Lead Engineer, Fire Protection
,
R. Brian, Manager, Mechanical Design Engineering .
R. Buell, Manager, Project Management
3
P. Campbell, Technical Assistant
D. Dormady, Manager, Plant Engineering
B. Ellis, Fire Protection Engineer
'
J. Fowler, Quality Programs Manager
. T. Hoffman, Supervisor, Engineering
R. Kerar, Fire Protection Engineer
R. King, Director,' Nuclear Safety and Regulatory Affairs
D.' Lorfing, Licensing Supervisor
S. Martin, Supervisor, Design Engineering
J. McGaha, Executive Vice President
D. Mims, General Manager-
1 W. O'Malley, Manager, Operations
D. Pace, Director, Engineering
B. Thumm, Licensing Engineer -
NRC
N. Garrett, Resident inspector -
INSPECDON PROCEDURES USED
1
92903'
Followup-Engineering
93809
Safety System Engineering Inspection
92904
Followup Plant Support
37550
Engineering
4
'
37001
10 CFR 50.59 Evaluations
1
_
_
- ___ __
_
_. _.
- _ _ _ . _ _ _ . _ . _
,
!
REMS OPENED. CLOSED. AND DISCUSSED
i
Opened
,
50-458/9816-01
IFl
Problems with Pressure Relief Valve Set Pressure
Program (Section E1.4).
50-458/9816-02
IFl
Root Cause of Relief Valve Failure (Section E1.4).
50-458/9816-03
IFl
Containment Temperature issues (Section E1.5).
50-458/9816-04
Failure to Consider an increase in Dose Consequences
to be an Unreviewed Safety Question (Section E2.1).
j
50-458/9816-05
Lack of Procedure to Use Service Water for Fire
Protection (Section F8.2).
Closed
'
50-458/97-007
LER
Cracked screw assembly swivel pads on emergency
diesel generators could have prevented fulfillment of
safety function (Section E8 5).
50-458/9621-01
IFl
Entergy Operations, Inc., resolution of quality assurance
,
,
program required for resource sharing (Section E8.1).
50-458/9622-01
IFl
Adequacy of molded case circuit breaker trip setpoints
(Section E8.2).
l
50-458/9627-02
IFl
NRR to review near-buoyant objects (Section E8.3).
j
50-458/97201-01
Smoke detector application, placement, and installation
in fire area C-24 (Section F8.1).
!
50-458/97201-02
Failure to include fire protection check valves in a
functional test program (Section F8.2).
50-458/97201-03
Lack of engineering evaluation to establish fire
rating / fire resistance capabilities of fire-rated boundaries
(Section F8.3).
50-458/97201-04
Failure to assign other people to fire brigade
(Section F8.4).
50-458/97201-05
Failure to perform adequate operability assessment
(Section F8.5).
50-458/97201-06
Failure to perform adequate post fire safe shutdown
analysis (Section F8.6).
50-458/97201-07
Deficiency in design of reactor overpressure protection
system (Section F8.7).
50-458/9816-05
Lack of procedure to use service water for fire protection
(Section F8.2).
2
.
-
,
LIST OF ACRONYMS USED
)
ADS'
automatic depressurization system
cfm
cubic feet per minute
CR
condition report
condensate storage tank
design basis accident
i
Electric Power Research Institute
ER
engineering request
FPFI
fire protection fu'nctionalinspection
)
GDC
general design criterion
GL
generic letter
j
high-efficiency particulate air
4
IN
NRC Information Notice
LCN
license change notice
l
LER
licensee event report
loss-of-coolant accident
[
low pressure coolant injection
low pressure core spray
NEl
Nuclear Energy Institute
National Fire Protection Association
net positive suction head
NRC
Nuclear Regulatory Commission
PPP
positive pressure period
River Bend Station
- RCIC
reactor core isolation cooling
3
._.
_.
__
_ _ _ __
. . _
. . - _ . _ _ . _
. _ . . . _ _ . ._..
. _ . . . . . . . _
1...w.
la
i
l
~RHR
i
t
L
SEN-
safety evaluation (10 CFR 50.59)
safety evaluation report .
SGTS.
l
standby service water
surveillance test procedure
TP.
temporary test procedure
.TRM -
Technical Requirements Manual
TS--
. Tec'inical Specifications
Updated Safety Analysis Report
'
USO.
unreviewed safety question
VASASP
valve adjusting screw assembly swivel pad
wg
water glass
)
i
-
I
t
>
4
l
l
.
--,
,,-
..
.
- _ . -
. . .
-
._-
.-
._
_
o -
!
l
.
LIST OF DOCUMENTS REVIEWED
l
l
Procedures
I
NUMBER
DESCRIPTION
REVISION
i
ENG-3-037
Engineering Request
Revision 2
Process
l
RBNP-030
Initiation and Processing of
Revision 12
l
Condition Reports
!
J
EDP-AA-20
Engineering Calculations
Revision 12
RBNP-088
USAR Maintenance
Revision 0
'
l
No Number
USAR Review
Revision 3
l
l
STP 203-6305
HPCS Quarterly Pump and
Revision 7
'
l
Valve Operability Test
STP-203-6805
HPCS Cold Shutdown Valve
Revision 4
Operability Test
l
STP-302-1601
ENS-SWG1 A/B Loss of
Revision 0
Voltage Channel Calibration
and Logic System Functional
Test
PL-126
Site Providing Services to
Revision 0
Other Sites
RBNP-093
Control of Shared Services
Revision 0
ENG 3-006
Modification Design
Revision 16
Guidance
I
ENG 3-033
Modification Design Control
Revision 4
,
'
Plan
ADM-0031
Temporary Alterations
Revision 8A
RBNP-030
Initiation and Processing of
Revision 12
Condition Reports
RBNP-057
10 CFR 50.59 License Basis
Revision 7
!
!
Reviews and Envirc.unental
l
Evaluations
i
l
STP-000-6606
Section XI Safety and Relief
Revision 6
Valve Testing
5
l
_ _ _ _ _ _ _ _ _ _ _ _
O
e
STP-251-3702
Fire Hose Station Water
Revision 7
l
Flow Test and Hose Hydro
inspection
STP-251-3502
Fire Protection Water Valve
Revision 9
Cycle Test
EOP-0005, Enclosure 7
Injection into RPV with Fire
Revision 11
System
SOP-0042
Standby Service Water
Revision 16B
System Operating Procedure
SOP-0037
Fire Protection Water
Revision 16
System Operating Procedure
Enaineerina Reauests and Temporary Alterations
NUMBER-
DESCRIPTION
REVISION /DATE
ER 97-0147
ECCS Suction Strainer
-
Modification
ER 97-0277
Correct ESK-6GTS02
6/3/97
ER 97 0324
HPCS Design Basis
6/5/97
Information
ER 98-0166
SGTS Modification
4/19/98
ER 98-0230
SGTS Modification
-
ER 98-0233
SGTS Evaluation
6/17/98
ER 96-0017
Status of Normal / Preferred
1/16/96
Transfer
ER 96-0602
CSH PS235 & 249 Setpoint
8/22/96
Change
ER 97-0293
Modify Control Circuit of
6/10/97
E22*S004-ACB01
ER 98-0430
SRV Control Circuit
7/28/98
Modification
ER 96-0072
Spurious High RPV Signal
11/18/96
Initiation of SRVs
TA 96-13
Install enhanced option 1 A
10/10/97
flow control trip reference
card in APRM B
'
6
e
. _ _ _ _ _ _ _ - .
_ - . .
. . _ .
_ _ .
. _ .
. . . .
. . _ . _
..
_ - _ _ _
_ _ _ _ . - _
-
1
.' '
. .
TA 96-025
Disable SLC suction piping
9/01/96
'
heat trace and alarm
Condition Reports (CRs)
l
L
NUMBER
DESCRIPTION
REVISION /DATE
!-
CR 96-1137
CST Level for Vortex -
-
L
Prevention Allowance
}
CR 96-1511 ~
SGTS Fan GTS*FN1 A
6/7/96
Rotating Backwards
l
CR 97-0526A(CR-97-2154)
SGTS Surveillance Test -
-
l
Validity
o
l
l
CR 97-0800 '
-
CR 97-0808
Low Vacuum in Annulus
-
l'
(Ventilation)
..
,
(
-.CR 98-0430
SGTS High Air Flow
-
.
t
- ..
CR 98-0437
SGTS High Air Flow
4/17/98
CR 98-0795
Div i and ll D/G Control Air
)
-
'
I
CR 98-0913
USAR Review Updates for
-
Section 6.3
'
CR 98-0924
High Vacuum Reading in
7/21/98
Auxiliary Building
- CR 98-1001
USAR Table 6.3-1 Error
-
CR 97-1494
STP-302-1602 Timer 62-6
9/17/97
j
CR 97- 0122
Circulating Water Pump
2/4/97
l
Motor Heater Removal
J
CR 97-1322
ENS SWG 18 ACB 29 Gnd
9/4/97
Overcurrent Relay
<
CR 94-1032
.52S contacts on 4.16 kV
8/18/94
,.
Switchgear
. CR 97-0793
Spring Charging Motor
5/28/97
Control Cicuit
CR 96-1516.
E22*S001 Battery Service
8/19/96
Test
7
, .
l:
,
,
-
.-_
-
.
_ _ _
_
._m
_ _ . _ _ _ _
_ .
..
..
_.
.Q.
'
a
CR 96-0562
HPCS Pump Motor Breaker
6/27/95
i
CR 97-1067
HPCS Breaker trip when
7/22/97
started
l
CR 97-0795
incorrect Calcula:!on used
5/26/97
SPDS EGF ESX15
l ~
CR 97-1079
. Allowable Values in TR
7/24/97
3.8.4.7~
'
!~
- CR 97-0942
E22-LTN 054 C&G incorrect
5/17/96
!-
head correction
!
CR 96-1380
HPCS Diesel Alarm
7/21/96
!
l
CR 96-1459
HPCS 125V dc Distribution
8/7/96
System
'
CR 96-1516
Div 3 Volt Profile inrush I not
8/19/96
'
included
CR 97-2010
E22 MOV FO12 failed to
11/11/97
open
,
J
CR 96-1283
GTS-FNI A appeared to have
7/28/96
secured on its own
i
- CR 98-0632
GTS-FLT1 A heater failed to
5/21/98
energize as required by
i
procedures
L
CR 97-1157
Grease sjung from motor
8/6/97
'
bearings on both standby gas
treatment fan motors
97-1988
Auxiliary building supply fan
11/6/97
l
did not trip on low flow as
expected
CR 98-0230
High negative prassure in the
3/3/98
auxiiiary building and annulus
with standby gas treatment -
,
running
1
,
l
CR 98-0296
Difficulty opening aux building 3/19/98
doors with standby gas
,
running
8
E
!
.
.
_
..
O
CR 98-0415
Questions asked about the
4/15/98
impact of auxiliary building
access with both trains of
standby gas running -
CR 98-0430
Lineup of standby gas to limit
4/6/98
the off site dose limits
CR 96-1320
STP does not test the
7/16/96
pressure drop across the
profilters as required by TS
CR 98-0591
Incorrect acceptance criteria
5/17/98
was adopted for the high
pressure core spray pump
room cooler
CR 97-1690
10CFR21 notification for
9/30/97
defects and noncompliance
concerns for the EMD air start
motors
i
CR 98-0708
The current plant
6/8/98
l
configuration does not -
correspond to that described
in the SAR with respect to the
reserve volume of water in
the CST
CR 96-1593
Discrepancy in the minimum
10/3/96
temperature in the HPCS
diesel generator room
CR 97-1420
Piece of plastic gasket found
9/15/97
in service water side of heat
exchanger
CR 95-0581
Failure to grease the core
7/13/95
spray DSL turbo lube oil
pump during performance of
CR 96-1581
Discrepancy between FSAR
9/12/96
and calculated maximum
temperature for HPCS pump
room
CR 96-1313
Battery performance
7/15/96
L-
discharge test was terminated
'
prior to meeting the
procedure conditions
9
-
.. ..
.. .. ..
..
.
.
.
.
..
.
.
_ - _ _ -
.
CR 98-0109
Heater cable was spared
2/1/98
without a 50.59 evaluation
CR 96-1137
Condensate storage tank
6/20/96
technical specification
minimum level requirement
may not ensure that 1254k
gallons of makeup water is
available
CR 95-0717
Discrepancies between
7/17/95
USAR figures and other
drawings
CR 98-0846
Two pieces of grey colored
8/23/95
/
cement were discovered on
top of the breaker when it
was removed from the cubicle
CR 97-0606
While running HPCS purnp it
4/30/97
was observed that the
minimum flow valve
functioned sluggishly
CR 97-2010A
HPCS minimum flow valve
1/22/98
demonstrated erratic
operation
CR 97-2100
HPCS minimum flow valve
11/11/97
failed to auto open
CR 97-0804
HPCS discharge relief valve
5/29/97
found with ruptured bellows
CR 98-0991
Actual containment
8/5/98
temperature was lower than
the minimum containment
temperature specified in the
Environmental Design Criteria
CR 96-1585
Standby gas system initiated
8/31/96
due to spike to radiation
monitor
.CR 97-0792
Radiation monitor went into
5/28/97
alarm and started standby
1
gas fan
^
CR 961584
Radiation monitor spiked and
8/31/96
,
started standby gas fan
j
10
1
>
-.
- . .. .
.
. _ _ _ _ _ _
_ _ _ _ _ _ _ _ _ _
_ _ _ _ _
. _
. _ .
_ . . _
.
.. ._
-
_
. _ _
._
-4
L
I
l
i.
CR 98-0216
Annulus high pressure alarms 2/27/98
!
were received
CR 97-1881
The relief valves for the diesel 10/20/97
l
starting air system were reset
to a higher set pressure
CR 97-2131
The relief valves for the diesel 12/18/97
l
starting air system were set
back to the original set
,
pressure
l
l
CR 961379
Relief valve for the
10/30/96
l
condensate pump motor air
.
l
cooler is set higher than
j
i
required
CR 96-1994
Relief valve on the
11/21/96
,
i
condensate emergency
i
makeup hotwelllevel control
l
valve bypass line is set higher
'
than required
CR 96-1571
Setpoints for the main steam
8/29/96
pressure relief valves are not
l
In accordance with those
i
required by plant design
documentation
!
'
CR 97-2008
Relief valve was replaced
11/11/97
tiecause the valve set
pressure was 30 psi too high
CR 96-1082
46 discrepancies were
6/13/96
discovered between the
setpoints required by the
plant safety and relief valve
data sheets and the setpoints
etched on the valve data
plates
i
CR 92-0603
There is a question as to
8/21/02
what the actual pressure
setting is for the HPCS air
start system air dryer
discharge lines
l'
i
11
1
I
l
_
. _ _
..
.
..
~
..
..
.._
- . .
- .
l
'
!
I
CR 98-0998 -
Open cable tray floor
8/6/98
i
penetrations without
!
guardrails in cable chase
'
room on 116' elevation
.
CR 98-0803
Fire detection, suppression,
6/25/98
and barrier issues
i
CR 97-0991
Po?'v d multiple shorts in
7/2/97
"
e
reactor > .ssure vessel
pressure transmitters causing
j
all 16 SRVs to open
l
-
CR 98-0214
No procedure to provide SSW 2/26/98
to fire protection hose
stations
'
Calculations
'
NUMBER
DESCRIPTION
REVISION
l
BV45,191
Fan External Total Pressure
Revision 1
l
i
Fans 1HVR-FN7A & FN78
Auxiliary Building Exhaust
System Normal Operation
1
Modes I,11, & Ill
BV45.20-1
Fan External Total Pressure
Revision 1
1GTS*FN1 A & FN1B
Containment /Drywell Purge
Exhaust, Normal Operation
Mode 111
BV45.22-1
Fan External Total Pressure
Revision 1
Fans 1GTS*FN1 A& FN1B
Annulus and Auxiliary
Building Exhaust, Accident
Mode
Net Free Air Volume of the
Revision 0
Auxi!!ary Bldg
Shield Bldg Annuius
Revision 4
Following a LOCA
l
Shield Bldg Annulus
Revision 5
Following a LOCA
'
i
i
Auxiliary Building Pressure
Revision 3
i
Following LOCA
'
12
i
l
l
l
!
B
4-
s.
i'
G13.18.14.1 *027-0
. Evaluation of Post-LOCA
Revision 0
Auxiliary Building Positive
> .
. Pressure Period in Support
l
of CR-98-0437
G13.18.2.1*079 00
Evaluation of SGTS -
Revision 0
I
Drawdown Data
G13.18.2.2'031-0
Revision 0
1.
Pumps for Suction from the
Suppression Pool Under
' Accident Conditions-
G13.18.2.7*23
Revision 1
Folicwing a LOCA (Note:
This calculation supersedes
'
_ To Determine the in-Leakage Revision 0
PB-251
and Amount of Exhaust Air
Required to Maintain a
Negative Pressure of 0.25 in
wg in Auxiliary Building
E129
Load Study 13.8 & 4.16 kV
Revision 4c
System
s
E130
Sizing Ground Resistors
Revision 3
4.16 kV System
E131
Station Service Short Circuit
Revision 1 & 8 addendum
Analysis
E132
Voltage Profile
Revision 3 & 9 addendum
1
E167
5 kV Cable Sizing
Revision 2 addendum B
EOS-64
5 kV Cable Lie Extension
4/8/85
lA-GTS*1
Setpoint Calculation
Revision 4
1GTS*FS 24A & B
IA-E22*04
Setpoint Calculation HPCS
Revision 2 addendum 4
Condensate Storage Tank
i
Low Level
j
1
l lA-E22*05
Setpoint Calculation
Revision 4
1E22*ESN 655C & G
lA DFR#2
Setpoint Calculation HPCS
Revision 5
Floor Water Level
l
I
I
13
l
t
g
y
v
. , , -
-
r
e-
.
O
G13.18.12.0*03
Common Cause Failure 4 kV
6/28/90
Circuit Breakers
G13.18.3.1 *01
Sustained & Degraded
Revision 1
Voltage Setpoints Div 1&2
G13.18.12.2-126
Jastification for Deviations
Revision 0
From NFPA 13-1983 For
Suppression System AS-6C
in Fire Area C-4
G13.18.3.1 *02
Sustained & Degraded
Revision 2
Voltage Setpoints Div 3
Drawinas
NUMBER
DESCRIPTION
REVISION
PID-27-15A
Engineering P&l Diagram
Revision 1
System 257 5sandby Gas
Treatment
PID-27-04A
Engineering P&l Diagram
Revision 2
System 203 HPCS System
PID-9-10E
Engineering P&l Diagram
Revision 18
System 256 Service Water
-Standby
PID-15-1C
Engineering P&l Diagram
Revision 9
System 251 Fire Protection
Water & Engine Pump
EB-45C-11
Ventilation and Cooling Plan
Revision 11
EL 95'-9" Auxiliary Bldg
EE1A
Main One Line Diagram Key
Revision 19
Drawing
EE1K
4.16 kV One Line Diagram
Revision 17
1 ENS *SWG 1 A
EE1L
4.16 kV One Line Diagram
Revision 14
1 ENS *SWG 1B
I
EE1M
4.16 kV One Line Diagram
Revision 7
E22*S004
i
1EJS* LOC 1 A&2A
480 V One Line Diagram
Revision 10
Standby Bus
i
14
.
4
l
s;
,
o
1EJS* LOC 1B&2B
480 V One Line Diagram
Revision 9
' Standby Bus
Miscellaneous Documents
NUMBER
DESCRIPTION
REVISION
River Bend Station Updated
Revision 10
-
Safety Analysis Report
Operating License NPF-47
River Bend Station Operating Revision 101
,
and Appendix A
License and Technical
Specifications
SDC-203
HPCS System Design
Revision 0
Critena
j
l
SDC-302 ENS
Safety Related 4.16 kV
Revision 0
Electrical Distribution System
Design Criteria
SURD-P50
SGTS Evstem Description
Revision 0
and ReqJirements Document
Test Report
HPCS 15 Stage Pump
6/29/77
T-36631-1
Performance Curve (Byron
Jackson)
Year 2000 Desktop Guide
Revision 0
-
Entergy Operations, Inc.,
7/29/98
-
Fire Protection PEER Group
Position Paper Regarding -
Fire Brigades and OSHA
29 CFR 1910.134
1961C
River Bend Station Check
Revision 0
Valve Program Develooment
STM-GPST-A0118.00
Service Water Systems
-
Training Manual
i
e
i
15
l
'
l
l
k
. -
_
-_
_
_
_
.
-N
?
i
Safety Evaluations
Document Evaluated
Safety Evaluation (SEN)
LCN 04.06-032
97-0063
,
l
LCN 06.03-029
97-0071
!
LCN 07.03-151
96-0086
l
_ LCN 08.03.062
96-0026
LCN 08.03-069
97-0023
'
MR 95-0010 & LCN 09.03-219 REVS
96-0098
MR 96-0068 & FCN 1, LCN 09.03-231
97-0073
CR 95-0839 & LCN 09.05-108
96-0052
MR 96-0048 & LCN 10.04-160
97-0016
97-0072
97-0005
LAR 97-03 REV 1
97-0009
ER 97-0155
97-0038
l
ER 97-0294
97-0081
ER 97-0607
97-0087
CR 96-1644
97-0008
,
'
!
SOP-0018
97-0007
97-0084
Safety Evaluations
!
SEN
Document
Title
l
98-0027
ER 98-0380
Repair / Replacement of HVC System Damper Blade Seals
98-0028
ER 98-0321
Uprate Motor Data to Reflect Actual LRA Test Data
98-0029
ER 98-0136
Evaluation of Alternate HVK Chiller 1C Motor
98-0030
ER 98-0068
Replace Trend Recorders with Digital Recorders
08-0031
ER 98-0397
Repair /Rertacement of HVC System Damper Blade Seals
l
98-0032
ER 97-0040
BWR Stab' ity Enhanced Option 1 A
98-0033
LCN 15.06-006
Revise LOCA Calculations
1
l
i
!
l
16
l
l
,