ML18152A137
| ML18152A137 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 03/29/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A138 | List: |
| References | |
| 50-280-99-01, 50-280-99-1, 50-281-99-01, 50-281-99-1, NUDOCS 9904150277 | |
| Download: ML18152A137 (25) | |
See also: IR 05000280/1999001
Text
Docket Nos.:
License Nos.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
9904150277 90950030029280
ADOCK
Q
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
50-280, 50-281
50-280/99-01, 50-281/99-01
Virginia Electric and Power Company (VEPCO)
Surry Power Station, Units 1 & 2
5850 Hog Island Road
Surry, VA 23883
January 17, 1999 - February 27, 1999
R. Musser, Senior Resident Inspector
K. Poertner, Resident Inspector
G. McCoy, Resident Inspector (In Training)
P. Fillion, Reactor Inspector (Sections E8.1 - E8.8)
W. Stansberry, Security Specialist (Sections S1 .5, S2.8, S3.3,
S5.1, S6.1, S7.1, S7.2, S7.3 and S7.4)
R. Haag, Chief, Reactor Projects Branch 5.
Division of Reactor Projects
Enclosure
EXECUTIVE SUMMARY
Surry Power Station, Units 1 & 2
NRC Integrated Inspection Report Nos. 50-280/99-01, 50-281/99-01
This integrated inspection included aspects of licensee operations, engineering, maintenance,
and plant support. The report covers a six-week period of resident inspection; in addition, it
includes the results of announced inspections by a regional security specialist and reactor
inspector.
Operations
Operators actions to reduce power following a steam generator chemistry excursion
resulting from loss of the condensate polishers were appropriate and met the licensee
administrative requirements associated with steam generator chemistry. Degraded
condenser hotwell chemistry due to. inleakage from the circulating water system caused
the chemistry excursion when the condensate polishers were isolated (Section 01.2).
The diesel fuel oil system was properly aligned and material condition was adequate
(Section 02.1 ).
A tagging record for maintenance on the Number 2 emergency diesel generator was
properly prepared, authorized, and implemented (Section 02.2) .
Inspectors observed operator simulator requalification training for an operating crew .
The scenario was challenging and operator performance and communications during
the exercise were exemplary (Section 05).
Maintenance
Turbine driven auxiliary feedwater pump maintenance and testing activities were
observed to be properly performed and documented. All test acceptance criteria were
met (Sections M1 .1 and M1 .2).
Corrective maintenance on the outside recirculation spray su*ction valve was performed
properly and the decision not to perform local leakrate testing after repairs was valid
(Section M1 .3).
Engineering
By completing the spent fuel pool power upgrade modification, the licensee has satisfied
all commitments associated with issues related to spent fuel pool decay heat removal
reliability and the maintenance of adequate coolant inventory in the spent fuel pool
(Section E1 .1 ).
A non-cited violation was identified for failing to provide the main control room with an
up-to-date copy of an abnormal operating procedure (AOP) relating to a loss of power
condition affecting Unit 1. The AOP was revised following a modification to the Spent
Fuel Pool Cooling pump power supplies (Section E1 .1 ).
2
Two examples of a non-cited violation were identified for inadequate design controls. In
the first example, the design reviews for Unit 2 low head safety injection pump minimum
flow requirements were inadequate. The second example involved a calculation for
Number 3 emergency diesel generator battery not recognizing a transfer switch that
allowed additional loads on the battery (Sections E8.1 and E8.4).
A non-cited violation of 1 OCFR 50.59 was identified for a 1988 modification to increase
the capacity of the 125 VDC distribution system batteries and a procedure which
allowed the interconnection of two batteries via a DC tie breaker. This condition
involved an unreviewed safety question and therefore was not allowed under 1 O CFR
50.59 (Section E8.5).
Plant Support
A primary coolant sample was properly drawn and analyzed. Proper radiological
practices were used by the technician performing the evolution (Section R1 .1 ).
A Fitness For Duty program 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> NRC notification was implemented according to
procedural commitments and regulatory requirements (Section S1 .5).
The security equipment at the Independent Spent Fuel Storage Installation was found
operational and performing as intended (Section S2.8) .
Safeguards events were logged, tracked, trended, analyzed, and resolved according to
the Physical Security Plan commitments (Section S3.3).
The security force was effectively trained and requalified according to the Training and
Qualification Plan and regulatory requirements (Section S5.1 ).
Site and security management provided support to the physical security program and
was effective in administrating the security program. Management controls of the
security program were aggressive, effective, and comprehensive (Sections S6.1 and
S7.4).
The Nuclear Oversight audits and Self-Assessment audits were thorough, complete,
and effective in uncovering weaknesses in the security system, procedures, and
practices. The audit and self assessment program was a strength to the security
program (Section S7.1 ).
The licensee assigned and analyzed problems properly so that logical conclusions could
be reached. Corrective actions were appropriately prioritized. Problem analysis was a
strength of the security program. The corrective action program was technically sound,
effective, and performed actions in a timely manner (Sections S7.2 and S7.3) .
Report Details
Summary of Plant Status
Unit 1 and Unit 2 operated at power the entire reporting period. On February 4 while Unit 2 was
at reduced power for turbine valve testing, a power reduction was started due to a secondary
water chemistry excursion. Power was stabilized at 88 percent once the chemistry parameters
improved. Power was returned to 100 percent later that day. Unit 2 began its end of cycle
power coast down on February 24. A Unit 2 refueling outage is scheduled to commence on
April 18, 1999.
I. Operations
01
Conduct of Operations
01.1
General Comments (71707)
The inspectors conducted frequent control room tours to verify proper staffing, operator
attentiveness, and adherence to approved procedures. The inspectors attended daily
plant status meetings to maintain awareness of overall facility operations and reviewed
operator logs to verify operational safety and compliance with Technical Specifications
(TSs). Instrumentation and safety system lineups were periodically reviewed from
control room indications to assess operability. Frequent plant tours were conducted to
observe equipment status and housekeeping. Deviation Reports (DRs) were reviewed
to assure that potential safety concerns were properly reported and resolved. The
inspectors found that daily operations were generally conducted in accordance with
regulatory requirements and plant procedures.
01.2
Unit 2 Power Reduction
a.
Inspection Scope (71707)
b.
The inspectors reviewed the circumstances surrounding a Unit 2 power reduction due to
steam generator chemistry problems.
Observations and Findings
On February 4, at 10:06 a.m., a power reduction to 90 percent power was commenced
on Unit 2 to allow performance of a turbine valve freedom test. During the test, the
number 4 governor valve oscillated excessively resulting in a load reject signal being
generated at 12:02 p.m. The load reject signal armed the steam dumps and bypassed
the condensate polishers as designed. The valve freedom test was suspended and the
condensate polishers were returned to service within approximately 31 minutes.
Subsequent steam generator chemistry samples indicated increasing levels of sodium
and chlorides. At 1 :55 p.m., chlorides in the A steam generator exceeded the Action
2
Level 2 criteria of 50 parts per billion (ppb). Once an Action Level 2 parameter has been
exceeded, a power reduction to approximately 30 percent within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is required.
Chloride concentration in the A steam generator peaked at 66 ppb. Chloride
concentrations in the B and C steam generators did not exceed 50 pp,b, but did exceed
the Action Level 1 criteria of 10 ppb. Based on Action Level 2 chemistry conditions in
the A steam generator, a power reduction from 90 percent power was commenced at
2:28 p.m. The power reduction was stopped at 2:38 p.m. when chemistry samples
indicated that chloride levels in the A steam generator were below 50 ppb. The power
reduction was terminated with the unit at 88 percent power. The unit remained at 88
percent power until chloride levels were reduced to below the Action Level 1 criteria of
1 O ppb. At 8:35 p.m., a power increase was commenced and the unit was returned to
100 percent power at 11 :40 p.m.
The inspectors reviewed the chemistry sample results, reviewed the administrative
requirements associated with the steam generator chemistry conditions, and observed
the power reduction. The control room operators appropriately followed the
administrative requirements to reduce power based on a steam generator chemistry
parameter exceeding Action Level 2. The termination of the power reduction was also
appropriate following confirmation that chloride levels were below Action Level 2
conditions. The inspectors noted that condenser hotwell chemistry was degraded due to
waterbox inleakage from the circulating water system. The licensee plans to perform
maintenance on the turbine valves during the upcoming April / May refueling outage .
c.
Conclusions
Operators actions to reduce power following a steam generator chemistry excursion
resulting from loss of the condensate polishers were appropriate and met the licensee's
administrative requirements associated with steam generator chemistry. Degraded
condenser hotwell chemistry due to inleakage from the circulating water system caused
the chemistry excursion when the condensate polishers were isolated.
02
Operational Status of Facilities and Equipment
02.1
Diesel Fuel Oil System
a.
Inspection Scope (71707)
b.
The inspectors performed a system walkdown of the emergency diesel generator (EOG)
fuel oil system.
Observations and Findings
During the inspection period, the inspectors performed a detailed system walkdown of
the EOG fuel oil system. The system consists of two underground storage tanks that
are common to all three EDGs. Each EOG has two fuel oil transfer pumps that take a
suction from the underground storage tanks and deliver fuel oil to a wall mounted day
tank located in the associated EOG room. One pump is designated the ready pump and
the other pump is designated as the standby pump. The pumps take a suction off
C.
3
different underground storage tanks and operate based on an input signals from level
switches located in the day tank. The ready pump would start first based on a low level
switch actuation and the standby pump would only start if a lower level in the day tank is
detected by the level switch. Additional reviews of EOG fuel oil requirements were
performed as part of the closeout for Inspection Followup Item (IFI) No. 50-280,
281 /98001-01 and are documented in Section 08.1.
The inspectors reviewed the system valve alignment procedures and walked down
accessible portions of the system to verify proper alignment and material condition. The
inspectors also observed installed pipe supports and hangers and verified electrical
system configuration. The EOG fuel oil system was properly aligned and material
condition was adequate. During the walkdown, the inspectors identified that the
underground fuel oil storage tank vents were attached to the non-seismic above ground
fuel oil storage tank. The inspectors questioned the adequacy of attaching the tank
vents to a non-seismic structure. The licensee stated that the adequacy of the system
configuration had been previously reviewed and was found to be acceptable. The
inspectors reviewed the licensee documentation and determined that their acceptability
determination was based on engineering concluding that the loss of the vents was not a
credible event (i.e., during a seismic event the vent piping would still perform its
function). The inspectors were still reviewing this item at the end of the inspection
period .
The inspectors also questioned the licensee whether the fill piping from the non-seismic
above ground storage tank to the underground tanks, which runs through the fuel oil
transfer pump house, was seismically installed. The concern for this item dealt with a
possible rupture of the piping during a seismic event and flooding of the ready transfer
pumps. The licensee was reviewing the piping qualification at the end of the inspection
period. As an interim compensatory measure, the licensee closed the outlet valve from
the above ground storage tank while they were reviewing this issue. Additional review
of the fuel oil piping seismic requirements for the tank vent piping and the fill piping is
identified as Inspection Followup Item 50-280, 281/99001-01: Review of fuel oil piping
seismic requirements.
Conclusions
The diesel fuel oil system was properly aligned and material condition was adequate.
An inspection followup item was identified concerning fuel oil piping seismic
requirements.
02.2
Emergency Diesel Generator (EOG) Tagout
a.
Inspection Scope (71707)
The inspectors reviewed tagging record 2-99-EE-0004, "EOG Number 2 Maintenance."
b.
Observations and Findings
The inspectors reviewed tagging record 2-99-EE-0004. The tagout was implemented to
isolate the Number 2 EOG for maintenance activities. The inspectors verified the tagout
4
was properly prepared and authorized, that the tagged components were in the required
positions with the appropriate tags in place and that the tagout was adequate for the
work to be performed. The inspectors also verified that the equipment was restored to
the proper position following completion of the maintenance activity and that the tags
were removed.
c.
Conclusions
A tagging record for maintenance on the Number 2 emergency diesel generator was
properly prepared, authorized, and implemented.
05
Operator Training and Qualification (71707)
On February 5 the inspectors observed operator simulator requalification training. The
training exercise was associated with reactor trip response. The training was conducted
for an operating crew. The scenario presented was challenging. The training included
industry experience items and addressed recent plant modifications. The inspectors did
- not identify any deficiencies and operator performance and communications during the
exercise were exemplary.
08
Miscellaneous Operations Issues (92901)
08.1
(Closed) Inspection Followup Item (IFI) 50-280, 281/98001-01: Review EOG fuel oil
requirements. This item was opened to determine the basis for the fuel oil volume
(minium 35;000 gallons) required by the TS and to review the availability of power for
the two fuel oil transfer pumps associated with the Number 3 EOG. LER 50-280,
281/98003-00 discussed the lack of procedural guidance for aligning power to Number 3
EOG fuel oil transfer pumps during loss of offsite power events. This LER was closed in
Inspection Report No. 50-280, 281/98-10 based on emergency operating *procedures
being revised to provide interim guidance and modifications that are planned to provide
permanent corrective action.
The inspectors reviewed the TS (including the basis), the UFSAR, and the original NRC
Safety Evaluation Reportrelating to EOG fuel oil requirements. TS 3.16.A.1 requires
that the underground storage tanks contain a combined fuel oil volume of 35,000
gallons and that the day tank contain 290 gallons. The TS basis and the Updated Final
Safety analysis Report (UFSAR) state that the underground EOG fuel oil storage tanks
contain a seven (7) day supply of fuel, 35,000 gallon minimum, for the full load operation
of one EOG. The Safety Evaluation Report discussed that the 35,000 gallon
requirement was based on the amount of fuel oil to supply one EOG operating at full
load for seven days. The inspectors verified that 35,000 gallons of fuel oil is an
adequate supply to operate one EOG at full load for seven days. The inspectors noted
that more than one EOG would be operating following a loss of offsite power event, and
that the EOGs would not be continuously loaded to full load" as described in the TS and
UFSAR for the entire seven days following a design basis event. The inspectors verified
that the fuel oil storage volume requirement was consistent in the TS, UFSAR and the
NRC Safety Evaluation Report and that the licensee was satisfying this requirement.
08.2
5
(Closed) IFI 50-280, 281/97010-02: Review licensee actions to resolve AMSAC enable
setpoint issues. This item involved the enable setpoint associated with arming of the
AMSAC system during power escalations. The licensee initially lowered the enable
setpoint to ensure that the AMSAC system armed prior to exceeding 40 percent power.
Based on further reviews by the AMSAC system vendor and licensee it was determined
that the original setpoint was adequate and the setpoint was returned to the original
value. The inspectors reviewed this item and discussed the final resolution with licensee
personnel. The inspectors determined that licensee actions adequately resolved this
item.
II. Maintenance
M1
Conduct of Maintenance
M1 .1
Unit 1 Turbine Driven Auxiliary Feedwater (TDAFW) Pump Valve Maintenance
a.
Inspection Scope (62707)
The inspectors observed portions of the work activity associated with Work Order (WO)
00401603 and reviewed the completed work package.
b.
Observations and Findings
On February 3, the inspectors reviewed the maintenance activities associated with WO 00401603. The work order was generated as a preventative maintenance activity to
lubricate the turbine trip valve associated with the Unit 1 TDAFW pump (1-FW-P-2).
The work activity was performed in accordance with procedure O-MCM-421-02, "Terry
Turbine Gimpel Trip Valve Maintenance," Revision 3-P1. The work activity consisted of
inspecting and lubricating the turbine trip valve, 01-MS-TV-120. The inspectors
observed portions of the work activities and noted that the procedures were being used
by the mechanics and good work practices were being followed. The inspectors noted
that the component was properly isolated to allow the work activity to commence safely.
c.
Conclusions
Auxiliary feedwater turbine trip valve maintenance activities were properly performed
and documented.
M1 .2
Unit 1 TDAFW Pump Surveillance
a.
Inspection Scope (61726)
The inspectors observed Unit 1 TDAFW pump surveillance testing.
b.
Observations and Findings
On February 3, the inspectors observed a recirculation test of the Unit 1 TDAFW pump
conducted in accordance with procedure 1-0PT-FW-003, "Turbine Driven Auxiliary
6
Feedwater Pump 1-FW-P-2," Revision 1 O-P1. The inspectors also observed the
performance of procedure 1-0PT-FW-007, "Turbine Driven AFW Pump Stea!'f1 Supply
Line Check Valve Test," Revision 1. A pre-job briefing was held and the work was
performed in accordance with approved procedures. Temporary speed-sensing
equipment was used to monitor the turbine performance during start-up, and indicated
that the governor valve was operating normally.
c.
Conclusions
The turbine driven auxiliary feedwater pump was tested in accordance with approved
procedures and all test acceptance criteria were met.
M1 .3
Outside Recirculation Spray (OSRS) Valve Maintenance
a.
Inspection Scope (62707)
b.
The inspectors observed portions of the work activity associated with Work Order (WO)
00405662 and reviewed the completed work package.
Observations and Findings
On February 23, the inspectors reviewed emergent maintenance activities associated
with WO 00405662. The work order was generated as corrective maintenance after
OSRS suction valve, 1-RS-MOV-1558, failed to fully open during testing per procedure
1-0PT-RS-007, "Containment Outside Recirculation Spray Pumps MOV Stroke Test."
The valve operator was inspected and several internal gears were found to be
damaged. The licensee determined that the damage was due to misalignment of the
gears. The valve operator had been overhauled during the previous refueling outage
(October - November 1998). The gears were replaced and the valve retest consisted of.
a stroke test per procedure 1-0PT-RS-007.
Table 5.2-2 of the UFSAR requires 1 OCFR50 Appendix J testing for this valve, with a
- note indicating that the system is water filled and not considered a credible leakage path
from containment. Because of the note in the UFSAR and the fact that the work was
limited to the valve operator and did not affect the valve seating/ leakage characteristic,
i.e., did not invalidate the previous leakrate test, the licensee determined that no local
leakrate testing was required. The inspectors discussed with the NRC Office of Nuclear
Reactor Regulation the need to perform a local leakrate test and determined that since
the seat leakage characteristics of the valve had not been altered by the maintenance
the decision to not perform a local leakrate test was valid.
c.
Conclusions
Corrective maintenance on the outside recirculation spray suction valve was performed
properly and the decision not to perform local leakrate testing after repairs was valid .
7
Ill. Engineering
E1
Conduct of Engineering
E1 .1
Spent Fuel Pool (SFP) Cooling Pump Power Upgrade Modification
a.
Inspection Scope (37551)
The inspectors reviewed the licensee's final actions associated with SFP decay heat
removal reliability and the maintenance of adequate SFP coolant inventory.
Specifically, the plant modification to upgrade the power supply for the SFP cooling
pumps from a non-safety related source to a safety related source was reviewed.
b.
Observations and Findings
In 1996, the NRG identified a number of issues related to SFP decay heat removal
reliability and the maintenance of adequate coolant inventory in the SFP. A review was
conducted to identify plant specific and generic areas for regulatory analyses. These
matters were reviewed in detail in NRG Inspection Report No. 50-280, 281/98-04. The*
only outstanding issue was the implementation of a modification to change the power
supply for the SFP cooling pumps to a safety related source. The licensee committed to
complete this modification by the end of 1999.
The inspectors reviewed portions of Design Change Package (DCP)97-004, "Spent
Fuel Pool Cooling Pump Power Upgrade." In this DCP the power supply for pump 1-FC-
P-1 A, was changed to motor control center 1 H1 -2N, a 480 volt safety related bus
supplied from the 1 H 4160 volt safety related bus. Additionally, the power supply for
pump 1-FC-P-1 B was changed to motor control center 2H1-2S, a 480 volt safety related
bus supplied from the 2H 4160 volt safety related bus. The inspectors walked down the
new power supplies and verified that the pump motor power supplies were connected in
accordance with the DCP. With the completion of this modification, the licensee has
satisfied all commitments associated with issues related to SFP decay heat rem.oval
reliability and the maintenance of adequate coolant inventory in the SFP.
During the inspectors review of the modification, two issues were identified. Just prior to
returning the 1 A fuel pool cooling pump to service following the power upgrade, a .
discussion between the inspectors and the operating crew revealed that the operators
lacked detailed knowledge on the specifics of the modification (i.e., the location of the
circuit breakers for the SFP cooling pumps and which electrical buses will be supplying
power to the pumps). This matter was brought to the attention of operations
management. The operating shift orders were amended to ensure operators were
made aware of the specifics of the modification. On January 28, the portion of the
modification affecting the 1 A SFP cooling pump was completed and the pump was
returned to service.
On January 29, during a tour of the control room, the inspectors noted that a priority
document associated with DCP 97-004 had not been updated in the main control room
file. The licensee's design control administrative procedure, VPAP 0301, "Design
8
Change Process," Revision 9, states that priority documents must be updated prior to
system testing. Specifically, Revision 12 to Abnormal Operating Procedure, 1-AP-
10.07, "Loss of Unit 1 Power," although revised and approved by licensee personnel,
had not been provided to the main control room. This upgraded procedure provided
crucial directions to plant operators not to restart the 1 A SFP cooling pump if the 1 A
containment spray pump was in operation and being supplied power by the Number 1
EOG generator during accident conditions. The reason for the prohibition to not start
the 1 A SFP cooling pump, if the 1 A containment spray pump is running, involves the
potential for overloading the Number 1 EDG.
The inspectors brought this matter to the attention of operations management. A
deviation report (DR) was written and the upgraded copy of AOP 1-AP-10.07 was
promptly placed in the main control room abnormal operating procedures file. TS 6.4.A.3 requires that detailed procedures be provided for actions to be taken for specific
and foreseen malfunctions of systems. The failure to provide the main control room with
an up-to-date revision of AOP 1-AP-10.37, "Loss of Unit 1 Power," is a violation of TS 6.4.A.3. This Severity Level IV violation is being treated as a Non-Cited Violation,
consistent with Appendix C of the NRC Enforcement Policy. This violation is in the
licensee's corrective action program as DR S-99-0229, and is identified as NCV 50-
280/99001-02.
c.
Conclusions
By completing the spent fuel pool power upgrade modification, the licensee has satisfied
all commitments associated with issues related to spent fuel pool decay heat removal
reliability and the maintenance of adequate coolant inventory in the spent fuel pool.
A non-cited violation was identified for failing to provide the main control room with an
up-to-date copy of an abnormal operating procedure (AOP) relating to a loss of power
condition affecting Unit 1. The AOP was revised following a modification to the Spent
Fuel Pool Cooling pump power supplies.
EB
Miscellaneous Engineering Issues (92903)
E8.1
(Closed) Unresolved Item (URI) 50-281/98201-03: Unit 2 low head safety injection
(LHSI) pump minimum flow. The problem involved one of the two redundant Unit 2
LHSI pumps which was weaker than the other pump. This meant that, given the piping
configuration, the weaker pump would receive less than the manufacturer
recommended minimum flow when the two pumps operated in parallel under minimum
flow conditions, i.e., discharge pressure of the LHSI pumps is less than RCS pressure.
During these conditions the weaker pump could be subject to damage. This item is
discussed in NRC Inspection Report No. 50-280, 281/98-07, where some of the
corrective actions were reviewed. In 1988 when the licensee performed evaluations
pursuant to NRC Bulletin 88-04, "Potential Safety-Related Pump Loss," they performed
an adequate minimum flow evaluation for the Unit 1 LHSI pumps, which included
testing. The evaluation showed that the two pumps were evenly matched, and minimum
flow would be assured for all modes of operation. However, the licensee incorrectly
assumed that the Unit 2 LHSI pumps would be the same. In the Architectural/
9
Engineering (A/E) inspection of 1998, the NRC identified that this assumption was not
correct. The Unit 2 LHSI pumps 1 A and 1 B are not evenly matched. Later, evaluations
. showed that the actual conditions would result in significantly less than recommended
minimum flow in parallel pump operation described above. The licensee evaluated this
reduced minimum flow for the weaker Unit 2 LHSI pump and determined that the pump
would remain operable for the situation described above. An important consideration in
this determination was that the operators would secure the pump within 30 minutes for a
safety injection actuation in which the LHSI pumps were not injecting water into the
RCS.
10 CFR 50, Appendix B, Criterion Ill, Design Control, requires that controls be provided
for verifying the adequacy of the design such as by the performance of design reviews
or the performance of suitable testing programs. In the case of the Unit 2 LHSI pump
minimum flow requirements, the design reviews were inadequate and failed to verify the
adequacy of the design. No testing was performed to verify the adequacy the Unit 2
LHSI pump minimum flow design. This constitutes a violation of 1 OCFR 50, Appendix B,
Criterion Ill, Design Control. This Severity Level IV violation is being treated as a Non-
Cited Violation, consistent with Appendix C of the NRC Enforcement Policy. This
violation is in the licensee's corrective action program as DR S-98-0660, and is identified
as NCV 50-280, 281/99001-03. A second example of this design control violation is
discussed in Section E8.4 .
The licensee was developing a design change package to modify the recirculation path
piping to achieve increased minimum flow. This modification was scheduled for
implementation on Unit 2 during the April/May 1999 refueling outage and later on
Unit 1. In reviewing the change package, the inspectors observed that the change
would result in improved recirculation (i.e. minimum flow) for the parallel pump case, but
would decrease flow for the single pump operation case. Documentation indicated flow
would be reduced from 340 GPM to 200 - 250 GPM. The change package did not
provide a clear basis for the adequacy of 200 GPM to preclude hydraulic instabilities.
For this reason, an Inspection Followup Item is established; IFI 50-280, 281/99001-04.
(Closed) IFI 50-280/98201-04: Motor thermal overload for LHSI pump 1-SI-P-18. The
inspectors reviewed Calculation EE-0497, Safety-Related 480 V Load Center
Coordination, Revision 1, issued October 29, 1998. The inspectors noted that the
pages covering the set points for the circuit breakers for the LHSI pump motors were
revised to obtain new set points for 1-SI-P-1 B. The inspectors reviewed these revised
calculation sheets in detail, and agreed that the new solid-state trip device and set
points will provide proper protection and coordination. The inspectors cross checked the
licensee's time-current plot against the manufacturer's published time-current
characteristic curve. The licensee developed DCP 98-056, which was in the final
concurrence stage. The inspectors observed that the DCP included the changes
recommended by calculation EE-0497. The implementation schedule was acceptable.
E8.3.
(Open) IFI 50-280, 281/98201-05: Adequacy of 4160 VAC electrical cables to withstand
fault current. This issue encompasses two related but separate concerns involving
undersized 4160 VAC electrical cables. The first concern involved the scenario of a fire
10
induced short-circuit on a cable not required for safe shutdown and possible damage to
a cable required for safe shutdown if the two cables are located in the same cable tray.
In this concern, the postulated fire starts from a non-electrical source in a different fire
zone than the safe shutdown equipment. The second concern involved postulated
random short-circuits that result in cable fires in two different fire zones (the zone where
the short-circuit occurred and a second zone through which the faulted cable is routed).
This scenario would not be bounded by the Appendix R analysis since that analysis
assumes a fire in only one zone.
The licensee calculated, using standard techniques, the temperatures at the
conductor/insulation interface that could result from plant specific short-circuits on the
undersized cables. They also calculated the maximum short-circuit for which these
cables would not exceed the rated momentary temperature of 250 °C. They also
reviewed various test reports which were generated by testing laboratories which dealt
with the effects of high currents on cables. The calculation results and test reports were
integrated into a rationale justifying the existing installation. That rationale is
summarized below.
Whenever a short-circuit occurs on a cable, the highest temperature resulting from that
short-circuit is always at the point of the fault. This statement is based on the fact that
the short-circuit must involve arcing. Therefore, even if the faulted cable is undersized
in the traditional sense from the short-circuit viewpoint, any conductor vaporization or
melting that may result would always happen first at the point of the fault. Once
conductor vaporization or melting occurs, the fault is self clearing. Vaporization with
concomitant explosion of the cable would never occur at a point along the cable
between the fault and the power source. The licensee's documentation indicated that
this concept essentially precludes and addresses the first concern stated above.
The extremely high temperatures calculated for the undersized cables were based on
solid three-phase faults and a breaker clearing time of seven cycles. In reality, any fire
induced cable fault would have to begin as a ground fault, which could then progress to
a three-phase fault. Ground faults are limited to 1400 Amperes, which is significantly
less than the maximum three-phase fault of about 33,000 Amperes. This concept
means that the circuit breaker in effect operates faster than seven cycles for the three-
phase fault. This effectively fast circuit breaker time tends to protect the cables from
severe damage along the length due to the fault currents, which is relevant to the first
concern.
Testing shows that when cables are subjected to overcurrents such as would result from
short-circuits two different results occur depending on the level of current. Extremely
high currents result in rapid melting of the conductor which stops the current flow
because there is no longer a complete path for the current. The temperature at the
surface of the conductor remains below the self ignition temperature of the insulation.
This statement is supported by test results. Therefore, extremely high currents do not
result in fires along the cable between the point of fault and power source. Current
levels about equal to motor locked rotor current when allowed to flow for extended
periods of time caused cable fires during testing for this situation. However, there is
nothing about the fact that certain cables are undersized for short-circuit that makes
them more vulnerable to long term overload type currents. Calculation showed that the
E8.4
11
cables in question are in fact protected for currents up to 11,000 Amperes, which is an
extremely high current level. The licensee's documentation indicated that these
concepts alleviate the second concern.
Pending further NRC review of the licensee's rationale, this item remains open.
(Closed) URI 50-280, 281/98201-08: EOG Battery Transfer Switch. This issue is
discussed in NRC Inspection Report No. 50-280, 281/98-07. The control panels for the
No.1 EOG are supplied 125 VDC power through a transfer switch, which provides the
capability to receive power from the No.1 EOG battery or No. 3 EOG battery. The
normal power source for No. 1 EOG control power is the No.1 EOG battery. There is a
similar arrangement for the No. 2 EOG control panel with the capability of receiving
power from the No. 3 EOG battery through another transfer switch. The transfer
switches are not described in the UFSAR. Calculation 14937.28-E-7, "Verification of
Lead Storage Battery Size for Emergency. Diesel Generator," Revision 2, issued
November 29, 1989, did not account for any increased load on No. 3 EOG battery due
to the operation of the transfer switches and the alignment of No. 3 EOG battery to
either the No. 1 or 2 EOG control panels.
Operation of the transfer switches was mentioned in two operating procedures;
Abnormal Operating Procedure, O-AP-17.04, "EOG 1or EOG 2 - Emergency
Operations," and Fire Contingency Action Procedure, O-FCA-12.00, "Emergency Diesel
Generator Operation." The current revisions for these procedures contain strict cautions
and controls on operation of the transfer switches. The previous revision of the
abnormal operating procedure contained the following cautions regarding operation of
the transfer switches: 1) an evaluation should be made before using the switch; 2) the
No. 3 EOG should already be running; and 3) the No. 1 and 2 EDGs should not be
aligned to No. 3 EOG battery at the same time. The current revision added the
statements that the transfer switches are for emergency use only and the switches can
not be used without Shift Supervisor approval. The previous revision of the fire
contingency action procedure stated that the transfer switches could be used with Shift
Supervisor direction. The current fire contingency action procedure revision contains
similar cautions described above for the abnormal operating procedure. The transfer
switches are currently padlocked and a caution tag is affixed stating: "Use of this
throwover switch requires the Shift Supervisor to invoke 1 OCFR50.54x." This was
verified by the inspectors. In addition, OCP 98-055 was prepared to remove fuses which
are located between the transfer switches and No. 3 EOG battery. The inspectors
concluded that the corrective actions stated above resolve the original concern
embodied in the URI. Also, the NRG has determined that existence of the transfer
switches with the original controls did not constitute an unreviewed safety question.
10CFR50, Appendix B, Criterion Ill, Design Control, requires that measures be
established to assure the design basis for structures, systems and components are
correctly translated into specifications, drawings, procedures and instructions. Not
having the transfer switch and potential for additional loads on the No. 3 EOG battery
addressed in calculation 14937.28-E-7, "Verification of Lead Storage Battery Size for
Emergency Diesel Generator," Revision 2, represents a violation of 1 OCFR50, Appendix
B, Criterion Ill. This Severity Level IV violation is being treated as a Non-Cited Violation,
consistent with Appendix C of the NRG Enforcement Policy. This violation is in the
E8.5
12
licensee's corrective action program as DR S-98-0605, and is identified as NCV 50-280,
281/99001-03. The first example of this design control violation is discussed in Section
E8.1.
(Closed) URI 98201-09: DC tie breaker. This issue is discussed in NRC Inspection
Report No. 50-280, 281/98-07 which states that the issue will remain open pending
review by the NRC to determine whether an unreviewed safety question was involved.
The NRC has completed its review, and determined that the circumstances surrounding
the interconnection between the two redundant trains of the 125 VDC Distribution
System involved an unreviewed safety question as defined in 10 CFR 59.59, Changes,
Tests and Experiments. It involved an unreviewed safety question because actual
operation of the tie breaker was different than described in the UFSAR and operation of
the tie breaker as described in procedures created the possibility for a malfunction of a
different type than previously evaluated in the UFSAR. Section 8.4.4 of the UFSAR
states, "The manually operated bus tie breaker provides for parallel operation of the bus
sections with either battery out of service for maintenance." This statement meant that
one battery must be disconnected from its bus before the tie breaker was closed.
These words were put into the UFSAR after the 1988 battery capacity upgrade
modification when it was recognized that the interrupting rating of individual feeder
circuit breakers would be exceeded with two batteries connected.
The molded-case tie breaker does not have any automatic tripping capability, so it was
essentially a manual switch. Maintenance Operating Procedure 1-MOP-EP-030,
"Removal from Service and Return to Service of Station Battery 1 A," Revision 0, issued
on January 30, 1997, directed that maintenance personnel first close the tie switch then
disconnect the battery which will be receiving maintenance. The practice of connecting
the two batteries via the tie breaker was only allowed and actually performed when the
plant was shutdown. The lack of circuit breaker interrupting capability when redundant
trains are connected together without any electrical isolation devices created the
- potential for severe damage or degradation to both trains of the 125 VDC Distribution
System, which was an unanalyzed malfunction. The NRC has now analyzed this
malfunction during shutdown conditions and concluded that the increased ~isk of core
damage was very small. The longer term corrective action will be to reconfigure the tie
between the two batteries to have two automatic type molded case circuit breakers in
series. This would meet the intent of the Safety Guide requirement to have interlocks
on inter-train tie breakers.
The inspectors concluded that the circumstances of the tie switch constituted a violation
of 1 O CFR 50.59 in that the licensee did not recognize the unreviewed safety question
created by the 1988 battery capacity upgrade modification and procedure for operation
of the tie breaker. After the identification by the NRC, the licensee entered this problem
into their corrective action program and implemented adequate compensatory
measures. This Severity Level IV violation is being treated as a Non-Cited Violation,
consistent with Appendix C of the NRC Enforcement Policy. This violation is in the
licensee's corrective action program as DR S-98-0719, and is identified as Non-Cited
Violation 50-280, 281/99001-05 .
E8.6
(Closed) IFI 50-280, 281/98201-19: Recirculation Spray (RS) System flow. The
inspectors reviewed the licensee's corrective actions for this issue. The licensee
13
analyzed system flow in calculations, and determined new flow distributions taking into
consideration any diverted flow paths and repositioning of valves to limit diverted flow.
The calculations reviewed were:
ME-0418, "Outside Recirculation Spray Flow," Addendum A, dated September
30, 1998.
ME-0405, "Inside Recirculation Spray Flow," Addendum A, dated September 30,
1998.
The inspectors also reviewed DCP 98-040, "Recovery of RS System Delivered Spray
Flows - Unit 1." This modification was essentially a valve alignment procedure change
to close off certain diverted flow paths. The inspectors also confirmed through
reference to the appropriate operations procedure, 1-0P-RS-001 A, "Outside Recirc
Spray System Alignment," Revision 3, that the modification was implemented.
E8.7
(Open) VIO 50-280, 281/98007-01: Failure to take corrective action for identified design
problems. This violation had two examples cited. The first involved the set point for the
circuit breaker trip device for the inside recirculation spray pump motors. The inspectors
reviewed the revised set point calculations and the proposed design change package
prepared to implement the set point change. These were the same calculation and DCP
described in Section E8.2. The corrective actions for this example of the violation were
satisfactory. The second example cited in the violation involved lack of voltage
calculations on the 125 VDC Distribution System. Completion of work on the
calculations is scheduled for the end of 1999. Therefore, the violation*remains open
pending inspection of the voltage calculations.
E8.8
(Closed) URI 50-280, 281/98007-03: Failure to submit LER within 30 days. The NRC
has reviewed the licensee's interpretation of the 30-day reporting requirement in terms
of preliminary evaluation time in the case of design basis issues. The inspector
concluded that the licensee's interpretation was valid in this particular case. This
conclusion should not be construed as agreement that the 30-day reporting requirement
for design basis issues can be automatically extended but as an acknowledgment that
the timeliness for initial reportability determination for this case was appropriate due to
the complexity of the design basis issues.
IV. Plant Support
R1
Radiological Protection and Chemistry Controls (71750)
On numerous occasions during the inspection period, the inspectors reviewed radiation
protection (RP) practices including radiation control area entry and exit, survey results,
and radiological area material conditions. No discrepancies were noted, and the
inspectors determined that RP practices were proper .
14
R1 .1
Primary Demineralizer Influent Sample
S1
a.
Inspection Scope (71750)
The inspectors observed the drawing and analysis of depressurized primary coolant
samples.
b.
Observations and Findings
On February 3, 1999, the inspectors observed the licensee obtain primary coolant
samples from both Unit 1 and Unit 2 in accordance with procedure, CH-11.201,
"Sampling Primary Demineralizer Influent," Revision 4. The inspectors also witnessed
the analysis of the sample for boron concentration. The results were consistent with
previous samples when plotted on the unit trend graphs. The technician utilized proper
radiological control practices by using low-dose waiting areas while the sample lines
were being purged and storing the samples in shielded areas in the chemistry
laboratory.
c:
Conclusions
A primary coolant sample was properly drawn and analyzed. Proper radiological
practices were used by the technician performing the evolution .
Conduct of Security and Safeguards Activities
On numerous occasions during the inspection period, the inspectors performed
walkdowns of the protected area perimeter to assess security and general barrier
conditions. No deficiencies were noted and the inspectors concluded that security posts
were properly manned and that the perimeter barrier's material condition was properly
maintained.
S1 .5
Fitness For Duty Program
a.
Inspection Scope (81502)
The inspectors evaluated the disposition of Fitness For Duty (FFD) events to verify that
the licensee's FFD program was being implemented according to regulatory
requirements and Physical Security Plan (PSP) commitments.
b.
Observations and Findings
The inspectors reviewed and evaluated the licensee's Significant Fitness for Duty Event
NRC 24 Hour Notification form for event No. 35396 dated February 23, 1999. Licensee
personnel made the required notifications and complied with the reporting requirements
of Virginia Power Administrative Procedure (VPAP)-0105, "Fitness For Duty Program,"
Revision 11 .
C.
15
Conclusions
A Fitness For Duty program 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> NRC notification was implemented according to
procedural commitments and regulatory requirements.
S2
Status of Security Facilities and Equipment
S2.8
Independent Spent Fuel Storage Installation (ISFSI)
a.
Inspection Scope (81001)
The inspectors reviewed the physical protection system installed at the Independent
Spent Fuel Storage Installation.
b.
Observations and Findings
The ISFSI had an intrusion detection system (IDS), assessment capabilities of
annunciated alarms of the isolation zones, personnel and vehicle access control,
security equipment power supply, and a testing and maintenance program for the
protection equipment. The inspectors tested the IDS zones and found them operational.
The inspectors found that the Closed Circuit Television (CCTV) assessment equipment
provided clear and prompt assessment capabilities. The inspectors observed IDS
alarms annunciating in the alarm stations in concert with the CCTV assessments.
c.
Conclusions
The security equipment at the Independent Spent Fuel Storage Installation was found to
be operational and performing as intended.
S3
Security and Safeguards Procedures and Documentation
S3.3
Security Event Logs
a.
Inspection Scope (81700)
b.
The inspectors reviewed Security Event Logs (SEL) for 1998 to verify that the licensee
appropriately analyzed, tracked, resolved, and documented safeguards events that the
licensee had determined did not require reporting to the NRC.
Observations and Findings
This review found that the licensee tracked, trended, analyzed, and had taken corrective
actions to resolve the events described in the SELs. The inspectors also found that
there were no significant increasing or decreasing trends in the event categories. Any
increases noted were attributed to the preparation of the performance assessment
during this inspection period. The inspectors noted that the process of documenting the
events and tracking the findings within the corrective action program involved numerous
data bases and document files.
16
c.
Conclusions
Safeguards events were logged, tracked, trended, analyzed, and resolved according to
the Physical Security Plan commitments.
Security Safeguards Staff Training and Qualification
S5.1
Security Training and Qualification
a.
Inspection Scope (81700)
The inspectors observed individual security officer training and reviewed training and
qualification commitments to ensure that the training met the criteria in the Training and
Qualification Plan.
,,
b.
Observations and Findings
Members of the security organization were requalified at least every 12 months in the
performance of their assigned tasks, both normal and contingency. This included the
conduct of physical exercise requirements and the completion of a firearms course.
Through the observation of security personnel performing their duties, and interviews
with security force personnel, the inspectors found that the training complied with
1 O CFR 73, Appendix B, proficiency requirements .
c.
Conclusions
The security force was effectively trained and requalified according to the Training and
Qualification Plan and regulatory requirements.
S6
Security Organization and Administration
S6.1
Management Support and Effectiveness
a.
Inspection Scope (81700)
b.
The inspectors evaluated the degree of licensee management support for the security
program and the effectiveness of licensee management relative to the administration of
the physical security program.
Observations and Findings
The inspectors interviewed management and non-management personnel and reviewed
security related documents to determine the breadth and depth of the support provided
and program effectiveness resulting from that support. The inspectors determined that
licensee management exhibited an awareness and favorable attitude toward physical
protection requirements. The following items demonstrated the support system for the
security program:
17
The support management provided for testing and maintenance of security
equipment was appropriate. A review of the maintenance request and requests
for engineering assistance (REA) records revealed that the oldest work order
was dated October 1998 and a HEA dated back to January 1998 for a
compensatory measure implemented at zone five of the protected area
perimeter was still open. The zone five REA was discussed with an
Instrumentation and Controls (l&C) supervisor to evaluate the coordination
between security and l&C.
The average time of posted security officer compensatory measures used to
compensate for equipment failures was less than three hours.
The security officer staffing level has been stable since the beginning of 1997 .
To enhance the site access program, licensee management continued to
support the work in progress for the Security Access Control System.
An effective vehicle barrier system has continued to be implemented .
Site management effectively enhanced and corrected a long term problem with
the security uninterruptable power supply .
c.
Conclusions
Site and security management provided support for the physical security program and
was effective in administrating the security program.
S7
Quality Assurance in Security and Safeguards Activities
S7.1
Audits/Self Assessment Program
a.
Inspection Scope (81700)
b.
The inspectors evaluated the audit and self assessment program and procedures. The
requirement for an annual audit of the security and contingency programs was also
evaluated.
Observations and Findings
The Nuclear Oversight (NO) audit findings for 1998 and 1999 were reviewed. NO Audit
Report 98-01 stated that no regulatory compliance issues were noted and that the
security and FFD program was a strength, proactive, thorough, detailed, and
aggressive. The security internal Self-Assessment (SA) audits for 1998 were also
reviewed. The SAs were directed by the Manager, Nuclear Security and Administrative
Services and conducted by site security personnel. Sixteen areas of the security
program, and the FFD program were reviewed. Between the NO audits and SA audits,
the security and FFD program were audited at least every twelve months. In addition,
security management initiated a Surry Nuclear Power Station Security Value
18
Assessment Program. Senior site management was queried on security services
provided to their site customers. The results were 93 percent positive comments and 7
percent negative comments. The audit and self assessment program of the security
program was found to be a strength in the management of the security program.
c.
Conclusions
The Nuclear Oversight audits and Self-Assessment audits were thorough, complete,
and effective in uncovering weaknesses in the security system, procedures, and
practices. The audit and self assessment program was a strength of the security
program.
S7.2
Problem Analysis
a.
Inspection Scope (81700)
. The inspectors reviewed and evaluated how problems related to logged safeguards
events (SEL), Deviation Reports (DR), and Licensee Event Reports (LER) were
analyzed.
b.
Observations and Findings
During the inspection, a representative sample of the problems identified by inspections,
DRs, LERs, and SELs were reviewed to verify that the problems were appropriately
assigned, analyzed, prioritized for corrective action and reached logical conclusions.
The inspectors found that problems were assigned for analysis according to VPAP -
1601, "Corrective Action," Revision 10, and were appropriately analyzed according to
VPAP - 1604, "Root Cause Evaluation Program." Six security individuals were fully
trained in Root Cause Analysis. The inspectors found this area to be a strength in the
security program.
c.
Conclusions
The licensee assigned and analyzed problems properly so that logical conclusions could
be reached. Corrective actions were appropriately prioritized. Problem analysis was a
strength of the security program.
S7.3
Corrective Actions
a.
Inspection Scope (81700)
b .
The inspectors reviewed and evaluated corrective actions implemented by the licensee
as documented in the DRs, SELs, and LERs.
Observations and Findings
The inspectors reviewed a sample of corrective actions that had been implemented to
verify that the actions taken were technically sound and performed in a timely manner.
The effectiveness of the corrective actions was reflected in the fact that most problems
19
were not repetitive. Also, contributing to the success of the corrective actions was the
concise, thorough, and timely problem analysis process cited in Section S7.2 and the
prioritizing of corrective action as required in VPAP - 2801, "Commitment Management,"
Revision 0.
c.
Conclusions
The corrective action program was technically sound, effective, and performed in a
timely manner.
S7.4
Effectiveness of Management Controls
a.
Inspection Scope (81700)
b'.
C.
The inspectors evaluated the overall effectiveness of the licensee's controls for
identifying, analyzing, and resolving problems. The inspectors evaluated the adequacy
of corrective actions to prevent recurring problems.
Observations and Findings
The inspectors reviewed previous audits, self-assessment program documents, LER,
SEL, and DR documents to ascertain the effectiveness of management controls. The
licensee's strong problem analysis program was reflected in the aggressive DR program
and documentation. Adverse events, trends, and problems were identified, analyzed,
and eventually brought to closure through the DR program. The absence of recurring
major regulatory issues, the continued strong support in upgrading the security access
program and security uninterruptable power supply, the successful preparation and
execution of the security tactical performance assessments, the adoption and
implementation of enhanced training programs, and the integration of new technology
into the training and operation of the security program were indicative of the
effectiveness and involvement of management controls. The continued expansion and
refinement of the above discussed management efforts and controls contributed to a
strong security program.
Conclusions
The management controls of the security program were aggressive, effective, and
comprehensive.
V. Management Meetings
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on March 10, 1999. The licensee acknowledged the findings
- presented .
v
20
The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified.
PARTIAL LIST OF PERSONS CONTACTED
M. Adams, Superintendent, Engineering
R. Allen, Superintendent, Maintenance
R. Blount, Manager, Operations & Maintenance
E. Collins, Director, Nuclear Oversight
M. Crist, Superintendent, Operations
J. Grau, Acting Superintendent, Training
E. Grecheck, Site Vice President
B. Stanley, Supervisor, Licensing
T. Sowers, Manager, Nuclear Safety & Licensing
W .Thornton, Superintendent, Radiological Protection
IP 37551:
IP61726:
IP 62707: .
IP 71707:
IP 71750:
IP 81001:
IP 81502:
IP 81700:
IP 92901:
IP 92903:
Opened
INSPECTION PROCEDURES USED
Onsite Engineering
Surveillance Observation
Maintenance Observation
Plant Operations
Plant Support Activities
Independent Spent Fuel Storage Installation
Fitness for Duty Program
Physical Security Program for Power Reactors
Followup - Operations
Followup - Engineering
ITEMS OPENED, CLOSED, AND DISCUSSED
50-280, 281 /99001-01
IFI
Review of fuel oil piping seismic
requirements (Section 02.1)
50-280/99001-02
50-280, 281/99001-03
Failure to update a main control room
procedure prior to the return to service of a
component recently modified by a design
change (Section E1 .1)
Two examples of design control problems
identified by the A/E team (Sections E8.1
and E8.4)
\\J
,.
21
50-280, 281 /99001-04
IFI
Review the acceptability of reduced
minimum flows for the low head safety
injection pumps after piping modifications
(Section E8.1)
50-280, 281/99001-05
Failure to correctly apply 1 O CFR 50.59 for
a modification to the 125 voe batteries
when an unreviewed safety question
existed (Section E8.5)
Closed
50-280, 281/98001-01
IFI
Review EOG fuel oil requirements (Section
08.1).
50-280, 281/97010-02
IFI
Review licensee actions to resolve AMSAC
enable setpoint issues (Section 08.2).
50-280/99001-02
Failure to update a main control room
procedure prior to the return to service of a
component recently modified by a design
change (Section E1 .1)
50-281/98201-03
Unit 2 low head safety injection pump
- minimum flows (Section E8.1)
50-280, 281/99001-03
Two examples of design control problems
identified by the A/E team (Sections E8.1
and E8.4)
50-280/98201-04
IFI
Motor Thermal Overloads for LHSI pump 1-
SI-P-1 B (Section E8.2)
50-280, 281/98201-08
EOG battery transfer switch (Section E8.4)
50-280, 281/98201-09
DC tie breaker (Section E8.5)
50-280, 281 /99001-05
Failure to correctly apply 1 O CFR 50.59 for
a modification to the 125 VDC batteries
when an unreviewed safety question
existed (Section E8.5)
50-280, 281 /98201-19
IFI
Recirculation spray system flow (Section
E8.6)
50-280, 281/98007-03
Failure to submit LER within 30-days
(Section E8.8)
Discussed
50-280, 281/98201-05
50-280, 281/98-007-01
22
IFI
Adequacy of 4160 VAC electrical cables to
withstand fault current (Section EB.3)
Failure to take corrective action for
identified design problems (Section EB. 7)