ML20216C668
| ML20216C668 | |
| Person / Time | |
|---|---|
| Site: | Summer  |
| Issue date: | 05/04/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20216C650 | List: |
| References | |
| 50-395-98-02, 50-395-98-2, NUDOCS 9805190380 | |
| Download: ML20216C668 (25) | |
See also: IR 05000395/1998002
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U. S. NUCLEAR REGULATORY COMMISSION
REGION II
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. Report No.: 50-395/98-02
Licensee: South Carolina Electric & Gas (SCE&G)-
Facility: V. C. Summer Nuclear Station
Location: P. O. Box 88 I
Jenkinsville. SC 29065
Dates: February 22 - April 4,1998
Inspectors: B Bonser Senior Resident Inspector
T. Farnholtz, Resident Inspector
W. Stansberry, Reactor Inspector RII (Sections S2.1, S4.1.
S4.2 S6.1, S6.2. S6.3 and S7.1)
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Approved by: R. C. Haag, Chief Reactor Projects Branch 5
Division of Reactor Projects
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9805190380 980504
PDR ADOCK 05000395
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EXECUTIVE SUMMARY
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V. C. Summer Nuclear Station 1
NRC Inspection Report No. 50-395/98-02
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This integrated inspection included aspects of licensee operations.
j maintenance, engineering, and plant support. The report covers a six-week
t period of resident inspection: in addition, it includes the results of an
j announced inspection by a regional inspector.
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l Ooerations
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. Operators acted promptly in response to a deaerator relief valve lifting
l and prevented a more significant challenge to plant operation (Section )
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01.2). j
e A review of four admistrative control programs implemented by Operations
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identified inattention to or lack of awareness of administrative control l
- details in three of the programs. The specific examples were
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recognizing an engineering evaluation should have been updated when the
work scope changed: not caution tagging three non-safety related valves;
and. not revising an operating administrative procedure when painting
criteria were revised (Section 01.3).
. Compensatory actions for an emergency feedwater isolation issue were
satisfactorily implemented (Section 01.4).
l . The knowledge level and performance of the intermediate building
i operator during routine rounds were good. The observed diesel generator
l compensatory actions were effective to ensure diesel operability. The
( observed scope of the o)erator rounds was effective to ensure that
l potential equipment pro)lems were identified (Section 04.1).
- e A review of the V. C. Summer Institute For Nuclear Power Operations
! report concluded that the content of tne report was consistent with
recent NRC assessments of licensee performance (Section 08.3).
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Maintenance
e ' Observed maintenance on a component cooling water pump. a molded case
circuit breaker. and a diesel generator identified no concerns. Good
work practices and techniques were noted (Section M1.1).
! . Surveillance activities were conducted satisfactorily and in accordance
with applicable procedures. Good planning for the tests was evident and
communications during the tests were effective (Section M1.2).
. A pre-job briefing for a moisture se)arator reheater performance test
I was thorough, clear. and detailed. Expected plant response was
discussed (Section M1.3).
- Reactor coolant pump (RCP) seal water flow transmitter preventive
maintenance was performed adequately. A review of maintenance
procedures for similar RCP seal water flow transmitters identified
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procedures of significantly different ages. Although the older revision
was performed adequately the inspectors considered it a poor practice to
not revise all applicable procedures together (Section M3.1).
- A licensee assessment and failure cause determination reports of four
previous diesel generator failures adequately identified the root causes
and corrective action (Section M8.2).
Enaineerina
e An engineering evaluation to allow gagging a secondary plant deaerator
relief valve in the closed position and to allow raising the setpoint of
a second deaerator relief valve was technically adequate
(Section E1.1).
- An unresolved item was identified to assess the safety significance of
raising turbine first stage pressure during moisture seaarator reheater
testing on steam line isolation actuation setpoints. T11s was not
addressed in the se"ety evaluation for the test (Section E1.2).
Plant Sucoort
e A violation was identified for the failure of a security officer to
prevent access to a vehicle until the vehicle search was completed.
(Section S2.1).
- Security personnel possessed appropriate knowledge to carry out their
assigned duties and responsibilities, including response procedures, use
of deadly force, and armed response tactics (Section S4.1).
- The security organization's response capability to security threats,
contingencies, and routine response situations including drills, were
consistent with the security procedures and the approved Physical
Security Plan and the Safeguards Contingency Plan (Section S4.2).
- Management support for the security program was generally strong. A
notable exception to this support was compensatory measures remaining in
place for two years (Section S6.1).
- Management's administration of the security program was proactive and
effective (Section S6.2).
. The total number of trained security officers and armed personnel
immediately available to fulfill response requirements met Physical
Security Plan requirements. One full-time member of the security
organization who had the authority to direct security activities did not
have duties that conflicted with the assignment to direct all activities
during an incident (Section S6.3).
.- Overall the licensee was effective in identifying analyzing, and
resolving security related problems. The adequacy of corrective actions
to prevent recurring problems was found to be excellent. There were
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strengths in the maintenance program of the security equipment and
system that supported plant operations and safety. The licensee was
aware of the weakness in the security system due to aging equipment that
could eventually lead to system degradation (Section S7.1). j
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Reoort Details
Summary of Plant Status
Unit 1 began this inspectir,n period at 100 percent power. On March 8 power
was reduced to 94 percent to reseat a deaerator relief valve. On March 14,
power was returned to 100 percent following completion of maintenance on the
deaerator relief valves. On April 4. power was reduced to 87 percent for main
steam safety valve (MSSV) testing. Power was returned to 100 percent l
following completion of MSSV testing on April 4. l
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I. Operations j
01 Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent
reviews of ongoing plant operations. In general, the conduct of
operations was professional and safety-conscious; specific events and
noteworthy observations are detailed in the sections below. l
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01.2 Resoonse To Deaerator Relief Valve Liftina
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a. Jnsgection Scooe (71707)
The inspectors reviewed the response by operators to a deaerator relief j
valve lifting on March 8. j
b. Observations and Findinas
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At about 8:58 a.m. on March 8. the intermediate building auxiliary {
operator, while on rounds, notified the control room that it appeared a l
deaerator (DA) alief valve was lifting. It was confirmed that DA i
relief valve XVa-2252A-HV was lifting. Control room operators also i
observed a corresponding decrease in DA level. In order to reduce i
pressure in the DA and reseat the relief valve the shift supervisor !
directed a power reduction. During the aower reduction. DA relief valve
XVR-22528-HV also started to lift. At a]out 9:20 a.m.. both relief
valves reseated. At 9:35 a.m. the power reduction was stopped and ;
power was stabilized at 94 percent. i
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The DA system is pressurized by the condensate pumps and provides i
sufficient head to meet the net positive suction head requirements for )
the feedwater booster pumps during steady-state operation. The prompt '
action by operators to reduce pressure in the DA prevented a loss of DA j
level control and a potential challenge to plant operation.
l c. Conclusions !
Operators acted promptly in response to a deaerator relief valve lifting
and prevented a more significant challenge to plant operation. l
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01.3-Review of Ooerations Administrative Controls
! a. Insoection Scooe (71707)
The inspectors reviewed several operations administrative control
programs, i
b. Observations and Findinas
Control of Temocrary Eauioment
On March 10. 1998, the licensee generated Work Request (WR) 9805330 to
install temporary demineralizers on the 412 foot level of the
intermediate building to facilitate draining chromated water from the B
Component Cooling Water (CCW) pump to re) lace the outboard seal. An
engineering evaluation was attached to t1e Removal and Restoration (R&R)
form to support the installation of the demineralizers. The evaluation
was written for work on the B CCW pump and included considerations such
as floor loading, impact on essential equipment, fire concerns, and
flooding concerns. The B CCW pump work was completed, and the p_ ump was )
tested and declared operable on March 11.
The licensee determined that similar seal replacement work would be
3erformed on another CCW pump within a short time frame and elected to
cee) the demineralizers in place beyond the completion of the B CCW aump
wort. A revision to WR 9805330 was made to take out references to t1e
B CCW pump and to make it generic to include all CCW pumps. The
associated R&R remained in effect but personnel failed to identify that
the supporting engineering evaluation should be updated to consider the
increased time that the demineralizers would be in place. This
oversight was discussed with cognizant ]ersonnel. An updated
engineering evaluation was prepared. T1e results of the evaluation were 1
the same. The requirement in Operations Administrative Procedure (OAP)-
111.1 to have a R&R to track the demineralizer installation and removal
was satisfied. However, operations demonstrated an inattention to
administrative controls in not recognizing that the supporting
engineering evaluation did not address the most current demineralizer 1
application.
Eauioment Misalianment Control
On March 18, the inspectors reviewed the equipment misalignment status
and monthly misalignment audits. Equipment is allowed to be misaligned
under specific guidelines given in OAP-105.2 " Equipment Misalignment
Procedure." Revision 1. The purpose of the procedure is to allow short
term misalignment of equipment and ensure proper configuration control.
A review of the status log found that there was no listed misaligned
i equipment on the day of the review. The procedure requires that
equipment exceeding 30 days of misalignment shall be evaluated for
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- continued misalignment. If continued misalignment is required, a '
i Caution Tagout shall be issued and the item (s) removed from the
l Equipment Misalignment Status Log. The inspectors review of 30 day
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-evaluations for January, February, and March of 1998 identified that
three valves. XVT00127A-AR. XVT001278-AR and XVT00127C-AR. had been
l misaligned since December 16. 1997. These three non-safety related
valves were on the Condenser Air Removal system. The three misalignment
! evaluations the inspectors reviewed identified the misaligned valves but
did not caution tag the valves. On March 16 the licensee identified the
oversight and caution tagged the three valves. Since regulatory
requirements were not applicable to configuration control of these three
l valves, no violation occurred. However, since the same equipment
misalignment controls were used for both safety and non-safety related
ecuipment, the inspectors were concerned that future similar
acministrative oversights, if not corrected, could result in problems
controlling safety-related equipment. When the inspectors identified
this concern to the licensee, a Condition Evaluation Report (CER) 98-
0256 was prepared documenting the oversight. This was the second
example of operation's inattention to administrative controls.
Control Room Paintina
On March 24. the inspectors ooserved painting in the control room. A
review by the inspectors of the controlling maintenance procedure and
the operations procedure for )ainting identified that guidelines in the
two procedures conflicted. T1e inspectors were concerned with the
controls govorning painting in the control room and the potential for
degradation d ventilation system efficiency. The inspectors brought
this issue to the attention of the shift supervisor. The shift
supervisor reviewed the conflict and found that the requirements in
Operations Administrative Procedure (0AP)-111.1, " Guidelines For
Operations Department Special Instructions." Revision 1 were outdated.
Procedure OAP-111.1 limited touch up painting in the control room to 200
square feet per day or a total of 1000 square feet. Any painting in
excess of the limits required an erigineering evaluation. The procedure
in use by the pair.ters was Civil Maintenance Procedure (CMP)-500.003,
" Application of Paint To Surfaces Outside The Reactor Building."
Revision 4. The maintenance procedure allowed up to 1000 square feet of
painting a day in the control room envelope. An engineering evaluation
is necessary when painting a total of 4000 square feet. The inspectors
observed that the painters were following the guidelines contained in-
the maintenance procedure. The maintenance procedure was based on an
engineering review of painting in the control room. The inspectors
reviewed the engineering analysis and it appeared satisfactory. The
inspectors concluded that the painting in t1e control room was being
performed in accordance with established procedures. The inspectors
considered the outdated 0AP as a third example of operation's
inattention to administrative controls.
Eauioment Bvoass Authorization
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On March 18. the inspectors reviewed the licensee's Bypass Authorization
! log bcok and the licensee's administrative controls for authorizing
bypass installation (Station Administrative Procedure (SAP)-148). At
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the time the inspectors reviewed the log there were three active bypass
authorizations. The oldest bypass had been installed in November 1997.
Each of the bypasses was installed in accordance with the administrative
controls and had received the appropriate 10 CFR 50.59 screening and had
be3n approved by the Plant Safety Review Committee.
c. Conclusions
A review of four admistrative control programs implemented by Operations l
' identified inattention to or lack of awareness of administrative control !
details in three of the programs. The specific examples were: not i
recognizing an engineering evaluation should have been updated when the
work scope changed: not caution tagging three non-safety related valves:
and, not revising an operating administrative procedure when painting j
criteria were revised
01.4 Emeraency Feedwater (EFW) Isolation
a. Insoection Scooe (71707)
The inspectors verified the licensee's compensatory actions in response
to an issue concerning isolation of EFW.
b. Observations and Findinas
On March 20. the licensee identified an issue concerning the ability to
isolate EFW to a faulted steam generator for a secondary system pipe
break outside containment. This issue was reviewed and is documented in
NRC Inspection Report No. 50-395/98003.
The inspectors verified the implementation of the licensee's interim
compensatory actions. They included a revision to the Emergency
0)erating Procedure (EOP) Users guide to describe operator actions for
t11s event and stationing an o)erator at the control room evacuation
panels where EFW isolation can se performed. On several occasions ,
during the ins)ection period the inspectors verified the operatar 1
stationed at tie control room evacuation Janels was attentive and
knowledgeable of the required actions to ]e taken in response to a
faulted steam generator. The inspectors identified no concerns,
c. Conclusions <
Compensatory actions for an emergency feedwater isolation issue were
satisfactorily implemented.
04 Operator Knowledge and Performance
04.1 Intermediate Buildina 00erator Rounds
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a. Insoection-Scoce (71707)
The inspectors accompanied the Intermediate Building (IB) operator
during the performance of a routine tour and TS required log taking.
b. Observations anj Findinas
On March 29. the inspectors observed the routine activities of the IB
operator which included a complete tour of the assigned spaces and the
recording of logs. Areas toured in the IB included vital switchgear
rooms, the reactor control rod equipment room, the control room
evacuation panels, the Diesel Generator (DG) rooms, the main steam
isolation valve area, and ventilation' equipment areas. Also included
were the Service Water (SW) building, and the fire pump and circulating
water pump areas. The operator toured these areas in a systematic
manner and inspected all areas. During the tour the_ IB operator also
verified DG operability due to a failure of the A DG local annunciator
panel. The annunciator failure had caused DG annunciators to alarm in
the control room. As a compensatory action the IB operator verified
locally that the DG was operable. Logs were recorded on a handheld
electronic device which was later downloaded into a computer for data
storage and reviewing. The o)erator demonstrated a good level of
knowledge and familiarity wit 1 his duties and responsibilities.
c. Conclusions
The knowledge level and performance of the intermediate building
-operator during routine rounds'was good. The observed diesel generator
compensatory actions were effective to ensure diesel operability. The
observed scope of tne operator rounds was effective to ensure that
potential equipment proalems were identified.
08 Miscellaneous Operations Issues (92901)
08.1 (Closed) Violation (VIO) 50-395/97003-01: Failure to establish
procedures appropriate to the circumstances. On April 26, 1997, the
licensee failed to establish operating procedures that would enable
operators to maintain adequate control of Steam Generator (SG) water
levels and failed to provide adequate operating instructions for
response to a turbine trip.
Corrective actions taken by the licensee included revising General
Operai.ing Procedure (GOP)-4 " Power Operation (Mode 1)." The inspectors
verified that the revisions provided additional guidance to the
operators for maintaining the required feedwater differential pressure
during power escalation. .Also. Abnormal Operating Procedure (AOP)-
, 214.2. " Response to Load Rejection / Runback." Revision 3 was revised to
provide additional guidance for response to a potential feedwater
isolation as the result of a turbine-trip due to high-high SG water
levels. The inspectors reviewed these revisions and considered them to
be adequate. The revised procedures were validated on the simulator and
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lessons learned from this event were-incorporated into operator training
scenarlos.
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08.2 (Closed) VIO 50-395/97003-03: Failure to follow procedure to raise
l Reactor Building (RB) pressure. On April 13. 1997, the licensee failed
l to implement the requirements of System Operating Procedure (SOP)-114, 1
, " Reactor Building. Ventilation System." when an operator opened the l
l containment purge exhaust isolation valves instead of the reactor i
building alternate purge supply isolation valves as required by the
procedure.
The licensee revised SOP-114 to show a clear difference between the
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purge supply and exhaust sections to clarify the different recuirements
for the operators. The inspectors reviewed the revision and cetermined
that the revised procedure was improved in that the two operations
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(raising and lowering RB 3ressure) were each contained in separate
sections. In addition, t1e licensee installed operator aids in the form
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of red plastic labels on the Heating. Ventilation, and Air Conditioning
(HVAC) panel. The purpose of these tags was to help prevent inadvertent
operation of the containment purge exhaust isolation valves. The
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inspectors considered these actions adequate to prevent recurrence of
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08.3 Review of Institute For Nuclear Power Ooerations (INPO) Reoort
a. Insoection Scooe-(71707)
The inspectors reviewed the final INP0 evaluation report for
V. C. Summer.
b. Observations and Findinas-
The INPO onsite assessment was conducted during the weeks of June 23 and
June 30, 1997. The inspectors reviewed the INP0 report to identify any
issues that were not consistent with NRC findings and assessments. The
issues identified in the INP0 report were found to be consistent with
recent NRC assessments of licensee performance.
c. -Conclusions
A review of the V. C. Summer INP0 report concluded that the content of
the report was consistent with recent NRC assessments of licensee
performance.
II. Maintenance
M1 Conduct of Maintenance
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M1.1 fagneral Comments
a. Insoection Scoce (62707)
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The inspectors observed all or portions of the following work
activities:
. WR 9800102. B Component Cooling Water (CCW) Pump Outboard Seal
Replacement
. Preventive Maintenance Task Sheet (PMTS) 9801120. Inspect Fuel
Injection Pump Studs on the A Diesel Generator (DG).
- PMTS P0211043. Inspection (Partial Teardown) of the A DG Main Air
Start Valve B.
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. PMTS P0211042. Inspection (Partial Teardown) of the A DG Main Air
l Start Valve A.
. PMTS 9801547. A DG Engine Quarterly Maintenance.
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. WR 9718157. Repair A DG Number 11 Cylinder Lube Oil Leak Where Oil
is Fed to Rocker Arm.
. WR 9717799. Realace Tubing from Gage Panel to Valve Before Failure
-Starting Air pressure Number 1.
. WR 9717800. Re) lace Tubing from Gage Panel to Valve Before Failure
-Starting Air 3ressure Number 2.
. WR 9800091. Replace Bound Up Stator Temperature Selector Switch.
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. PMTS 9722364. Molded Case Circuit Breaker Testing XMC1DB24-12GH.
b. Observations and Findinas
The observed maintenance activities were conducted using the appropriate
)rocedures, tools, and technicues. The maintenance technicians were
(nowledgeable and demonstratec good work practices. No concerns were
identified.
c. Conclusions
Observed maintenance on a component cooling water pump, a molded case ,
circuit breaker, and a diesel generator identified no concerns. Good l
work practices and techniques were noted. l
M1.2 Surveillance Observation
a. Insoection Scooe (61726)
The inspectors observed or reviewed the following surveillance testing
activities:
, STP-123.003B Train B Service Water System Valve Operability Test.
! Revision 3.
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l -STP-116.001. Reactor Building Cooling Unit Functional Test. Revision 5.
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l. STP-117.001. Iodine Removal System' Test. ?,evision 3.
STP-125.002. Diesel Generator Operability Test. Revision 18
b. Observations and Findinas
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Observation and review of surveillance testing found good planning. '
communications and procedural adherence. Test acceptance criteria were
met.
c. Conclusions j
Surveillance activities were conducted satisfactorily and in accordance
with applicable procedures. Good planning for the tests was evident and !
communications during the tests were effective.
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M1.3 Moisture Seoarator Reheater (MSR) Testina
a. Insoection Scooe (62707)
The inspectors attended a pre-job briefing for aerforming an MSR test.
The attendees included on shift operators and t1e engineer in charge of
the test,
b. Observations ~and Findinas
On March 16, 1998, the inspectors attended a pre-job briefing for the
3erformance of Preventative Test Procedure (PTP)-230.001. "MSR Steam
- low Setup and Verification." Revision 3. The purpose of the test was
to verify the optimal operation of the MSRs
The pre-job briefing was conducted by the engineer in charge. The !
inspectors considered the briefing to be thorough, clear, and detailed. 1
The details of the test and the expected plant response was discussed.
All questions were addressed.
c. Conclusions
A pre-job briefing for a MSR performance test was thorough, clear, and .
detailed. Expected plant response was discussed. !
M3 Maintenance Procedures and Documentation
M3.1 Observation and Review of Flow Transmitter Calibration Procedures
a. Insoection Scooe (61726)
The inspectors observed 3erformance of preventive maintenance on a
Reactor Coolant Pump (RC)) seal water flow transmitter and reviewed the
procedures.
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b. Observations and Findinos
On March 13. the inspectors observed Instrument and Control (I&C)
technicians perform Instrument Control Procedure (ICP)-340.022. "RCP 3
Seai Water Flow JFT00124." Revision 3 to complete PMTS 9717006. The
inspectors observed testing of the transmitter and reviewed the
procedure. The testing was performed satisfactorily and no concerns
were identified.
The inspectors reviewed the procedures for the similar flow transmitters
in the other two RCP seal water loops. The procedure the inspectors
observed the I&C technicians utilizing was dated March 14. 1986. The
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inspectors identified that the similar procedure for RCP 1 seal water
loop. ICP-340.024, "RCP 1 Seal Water Flow IFT00130," Revision 4, was
dated July 7, 1994. The inspectors were concerned that procedures of
significantly different ages were being used on similar transmitters and
that all the procedures for the similar flow instruments had not been
updated since 1986.
The inspectors review of both procedures identified several differences.
These included a different procedure format different references to
test equipment and the plant computer, and the inclusion of ste)s for
lifted leads and fitting replacement in the newer procedure. T1e older
procedure required going to other procedures to document lifted leads or
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fitting replacements. The inspectors found that licensee guidelines for
procedure revisions contained in Station Administrative Procedure (SAP)-
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139 " Procedure Development, Review. Approval and Control." Revision 18.
did not "pecifically require a timeframe for. updating procedures. The
inspectors concluded that the older revision was adequate to perform the
maintenance. However, the inspectors considered not revising all
applicable procedures for other similar instrument loops when a revision
was made to an instrument loop procedure was a poor practice.
c. Conclusions
Reactor Coolant Pump (RCP) seal water flow transmitter preventive
maintenance was performed adequately. A review of maintenance
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procedures for similar RCP seal water flow transmitters identified
procedures with revisions that were eight years apart. Although the
older revision was performed adequately, the inspectors considered not
revising all applicable procedures together was a poor practice.
M8 Miscellaneous Maintenance Issues (92902, 92903)
M8.1 (00en) Unresolved Item (URI) 50-395/98001-01: Review solid state
protection system TS operability and testing requirements. The
inspectors verified that procedures STP-345.037, " Solid State-Protection
System Actuation Logic and Master Relay Test Train A." Revision 14. and
STP-345.074, " Solid State Protection System Actuation Logic and Master
Relay Test Train B," Revision 9, were revised. Procedure STP-345.037
was revised on January 29 and performed on January 30, 1998. Procedure
STP-345.074 was revised on February 17 and performed on February 20.
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1998. The rocedures were revised to verify that the parallel inputs
for high-high SG level and SI were tested in the feedwater isolation fj
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circuitry.
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The licensee documented this issue on January 23.1998, in CER 98-0087.
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This was based on a Westinghouse Technical Bulletin dated December 20.
l 1997. The licensee considered these procedural changes as an (
i enhancement to their Solid State Protection System (SSPS) testing and i
L considered the surveillance tests to be adequate prior to making the l
changes in the surveillance test procedure. The inspectors questioned '
the licensee's position on this issue based on the definition of
Actuation Logic Test in the TS. The TS definition states that an
Actuation Logic Test shall be the ap)lication of various simulated input
combinations in conjunction with eac1 possible interlock logic state and
verification of the required logic output. On March 19. the licensee 1
reevaluated their position on this issue and concluded that the SSPS
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, surveillance testing was not adequately testing these circuits and the
inadequate surveillance testing was re)ortable. On March 23. during a
telephone conference with NRC staff, tie licensee stated that they had
l reevaluated their position on this issue. The NRC staff is continuing
l to review the licensee's resolution to the inadequate TS surveillance
testing and how these actions compare to TS required actions for
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inadequate surveillance testing.
M8.2 (Closed) Insoection Followuo Item (IFI) 50-395/97013-01: Licensee's
effort to identify the root cause and corrective action for the A diesel
generator problems. In response to the four failures of the A DG the
licensee performed an independent assessment of the failures and ,
- performed Failure Cause Determinations for each of the failures. The i
inspectors reviewed each of the licensee's assessments.
The inde)endent assessment of the licensee's actions in response to the
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A DG aro31 ems concluded that the A DG was operable and recurrence of the
insta)ility would not be expeci.ed. This conclusion was based on the
corrective actions taken by the licensee, analysis results by Woodward,
the governor vendor, bench testing of components on site, and completion
of comprehensive post-maintenance testing. Failure analysis results
performed on the suspect. components verified that the abnormal
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conditions observed on the A DG were attributable to the component
l failures. It was concluded that no common component failure linked the
four failures on the A DG. The inspectors concluded that the licensee
had adequately reviewed and identified the root cause of each A DG
problem.
l The independent assessment also made several recommendations. These l
recommendations included suggested improvements in the process for l
controlling troubleshooting activities and governor set-up procedures:
improvements in training of operations and maintenance personnel and
adjustment of the governor system; and the documentation of all
unexpected events during maintenance and troubleshooting. Several other '
testing and maintenance recommendations were made by the assessment
team. The assessment team also concluded that the licensee's actions
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L -taken and responses provided to industry information documents were
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inadequate with regards to the information directly applicable to the
recent events at Summer. The licensee prepared a summary of corrective
actions and proposed completion dates. The inspectors concluded that
the independent assessment of the A DG events had provided the licensee
with . ,eful feedback and proposed enhancements to licensee programs,
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The inspectors also reviewed the Failure Cause Determination reports !
prepared by engineering for each of the four A DG problems. The
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inspectors were satisfied that the licensee had adequately reviewed each
A DG issue and proposed corrective actions. The failure reports
concluded the following: 1) the A DG load swings experienced on November
11, 1997, and December 2,1997, were attributed to failure of the
governor electronic control (EGA) unit: 2) the A DG load swings on
November 21. 1997, were attributed to a failure of the relay which
caused droop to not be inserted properly and resulted in improper load
l sharing between the A DG and the grid: and 3) the A DG problem on
December 30, 1997, that resulted in a plant shutdown, was attributed to
a failure of the governor hydraulic actuator (EGB) unit. The inspectors
concluded that the licensee had identified the root cause of the A DG
problems and proposed adequate corrective action. Based on this review
and earlier reviews of the A DG failures the inspectors did not identify
any violations of regulatory requirements. Closeout of this IFI also
closes all required followup reviews for Notice of Enforcement
Discretion (NOED) 97-2-003 which was granted on November 13. 1997, for a
twelve hour extension of the TS Action Statement involving the first A ,
DG failure. '
III. Enaineerina
El Conduct of Engineering
El.1 Review of Enaineerina Evaluation for Deaerator Relief Valve liftina
a. Insoection Scooe (37551)
The ins)ectors reviewed an engineering evaluation concerning a DA relief i
valve w11ch lifted on March 8, 1998.
'
b. Observations and Findinas
On March 8,1998 a DA relief valve (XVR-2252A-HV) lifted at a system
operating pressure of approximately 107 psig (See Section 01.2). Plant
power was reduced until the valve reseated at a pressure of
approximately 99 psig. In addition, a second DA relief valve
(XVR-2252B-HR) showed evidence that it had lifted and reseated during
the same event.
The setpoint for these two valves (A and B) was 116 +/- 3 asig to
correspond to the maximum allowable working pressure for t1e DA. When
the A valve lifted and reseated, it was observed that there could be a
mechanical problem with the valve internals which could potentially
.
,
12
prevent the valve from reseating if it lifted again, The licensee
. performed an engineering evaluation to allow the A valve to be gagged in
'
the closed position. To do this, the licensee calculated the DA relief
valve flow ca)acity to ensure that sufficient capacity would be
available wit 1 the A valve gagged closed. In addition to the A and B j
valves, the DA has two other relief valves installed to prevent over
pressurization (XVR-1304-EX and XVR-1306-EX). The total flow capacity
was calculated through the three operable valves and it was determined
'
that a sufficient design margin existed to allow the A valve to be
gagged closed.
In addition to gagging the A valve closed, the licensee performed an l
engineering evaluation to raise the setpoint pressure of the B valve to i
12] +0/-8 psig. This would continue to meet the American Society of l
Mechanical Engineers (ASME) Code allowance for the DA. The maximum
working pressure for the DA is 116 psig. The ASME Code specifies that
no pressure relieving devices can be set higher than 105 percent of the
maximum working pressure (121 psig for the DA).
The inspectors reviewed the engineering evaluation and calculations and
determined that they were adequate to provide reasonable assurance that
the DA would continue to be overpressure protected with the new
configuration until such time that the permanent repairs could be i
performed. The method used represented good engineering practice and
contained all necessary data. No concerns were identified.
Also contained in the engineering evaluation were three 10 CFR 50.59
screenings to allow gagging closed the A relief valve, to allow
in-place testing of the A and B valves, and to raise the setpoint of the
B valve. These screenings were sufficiently detailed to support that no
10 CFR 50.59 evaluations were required.
c. Conclusions
An engineering evaluation to allow gagging a secondary plant deaerator
relief valve in the closed position and to allow raising the setpoint of
a second deaerator relief valve was technically adequate.
E1.2 Turbine First Staae Steam Pressure Chanaes
a. Insoection Scooe (37551)
The inspectors reviewed the effect of changing main turbine first stage
pressure during MSR testing.
b. Observations and Findinas
On March 16 the licensee began MSR steam flow testing (see Section
' M1.3) to establish the optimal amount of high pressure steam flow to the
High Pressure (HP) turbine and the MSRs. The licensee believed by
rebalancing steam flow between the MSRs and the HP turbine. greater
j secondary plant efficiency could be obtained. The actual test was well
1
. =
13 j
controlled and involved decreasing steam flow to the MSRs and increasing l
steam flow to the HP turbine incrementally. The test was performed
slowly over severai days to allow the plant to reach equilibrium after
each incremental change. ;
1
The steam flow rebalancing had the effect of increasing HP turbine first i
stage steam pressure as indicated on pressure transmitters IPT-446 and
IPT-447. These steam pressure transmitters provide input into the rod
control and steam dump control systems, and provide inputs into the
protection channels used to calculate the high steam flow coincident
with Lo-Lo Tave main steam line isolation setpoint. On March 23. ],
'
during the conduct of the test, the operations shift engineer questioned
the effect of the change on first stage pressure on the protection
channels. The test had raised first stage c
pressure of about 676 psi to a peak of 711.)ressure from
psi on March 23.a normal
The test
was terminated and the MSRs were placed back in service in accordance
with the system operating procedure.
The steam line isolation engineered safeguards feature system actuation
instrumentation requirements are given in TS 3.3.2. Table 3.3-3. 4.d and
Table 3.3-4. 4.d. The high steam line flow setpoint is described in TS
as a function of load corresponding to 40 percent of full power steam
flow between zero and 20 percent load followed by a linear ramp to 110 1
percent of full power steam flow at 100 percent load. Turbine first
stage pressure is used as a measure of percent load. At the end of the
inspection period the licensee was continuing to evaluate the potential
effects of increasing first stage turbine pressure prior to resuming the
test.
The ins)ectors reviewed the safety evaluation for increasing steam flow
to the iP turbine. A discussion of the effects on the high steam line
flow accident and the main steam isolation setpoint had not been
included in the safety evaluation. Pending completion of the licensee's
evaluation to assess the safety significance of raising turbine first
stage pressure, this issue is identified as URI 50-395/98002-01.
c. Conclusions
An unresolved item was identified to assess the safety significance of
raising turbine first stage pressure during moisture se]arator reheater
testing on steam 1ine isolation actuation setpoints. T1is was not
addressed in the safety evaluation for the test.
IV. Plant Support
R1 Radiological-Protection and Chemistry (RP&C) Controls
R1.1 General Comments (71750)
The inspectors observed radiological controls during the conduct of
tours and observation of maintenance activities and found them to be
acceptable.
]
. .
14
S2- -Status of Security Facilities and Equipment
$2.1 Protected Area Access Control-Vehicles
,
a. Insoection Scooe (81700)
1
I The ins)ectors evaluated the licensee's vehicle access control program
l for. paccages, personnel and vehicles entering the protected area. This
l was to ensure compliance with criteria in Sections 1 and 3 of the
Physical Security Plan (PSP) and Security Plan Procedures (SPPs) 202 and
203.
b. Observation and Findinas
l
The inspectors reviewed applicable access control procedures to ensure
that the licensee provided appropriate access controls for the protected
areas.
!
'
,
The inspectors verified that personnel, hand-carried packages or
l material, and delivered packages or materials were searched adequately
'
before being admitted to the )rotected area. The inspectors observed
that security personnel searcled for firearms, explosives, incendiary
devices, and other items that could be used for radiological sabotage.
These searches were either by physical search or by search equipment.
! The inspectors found the following circumstances concerning personnel
l access control at the Vehicle Access Portal (VAP). A coded, numbered.
l picture badge identification system was used for personnel who were
authorized unescorted access to the protected area through the VAP.
I Picture badges issued to nonlicensee personnel indicated authorized
access areas and showed that no escort was required. The licensee used
I
biometric hand geometry to ensure personal identification of individuals
I entering the protected area at the VAP.
The inspectors verified that access control program records were
available for review and contained sufficient information for
identification of persons and vehicles authorized access to the
protected area.
During an evaluation of vehicle access control at the VAP, the
inspectors observed two individuals, a vehicle operator and accompanying
personnel, being processed through the personnel search equipment. They
l were cleared for access to the protected area by the security biometric l
system before the vehicle was searched. The first individual cleared l
went from the VAP search building directly to the unsearched vehicle and
, began to unload material from the vehicle to be searched by the security
l
officer. SPP 202. " Vehicle Access Requirements," Revision ll, paragraph
5.3.3.A.1.2).c), states that when a security officer conducts a search
of a vehicle. the security officer is to ensure that neither the
operator nor the accompanying aersor el are provided access to any 1
portion of the vehicle until tie vehicle search is completed. The
.
15
failure to search a vehicle properly before the vehicle entered the
protected area is identified as a Violation (VIO) 50-395/98002-02.
c. Conclusions
l
l A violation was identified for the failure of a security officer to
! prevent access to a vehicle until the vehicle search was completed. ,
l l
l S4 Security and Safeguards Staff Knowledge and Performance
'S4.1 Security Force Knowledae
l a. Insoection Scooe (81700)
The inspectors interviewed and observed security personnel to determine
if they possessed adequate knowledge to carry out their assigned duties
and responsibilities, including response procedures, use of deadly
force, and armed response tactics.
,
b. Observations and Findinas
The inspectors randomly interviewed approximately 20 security personnel, .
including supervisors, and witnessed approximately 30 others in the l
3erformance of their duties during normal and security event conditions. )
iembers of the security force were knowledgeable in their duties and I
responsibilities, response commitments and procedures, and armed !
response tactics. The inspectors found that armed response personnel !
had been instructed in the use of deadly force as required by i
c. Conclusions .
l
Security personnel possessed appropriate knowledge to carry out their
assigned duties and responsibilities, including response procedures, use
of deadly force, and armed response tactics.
S4.2 Resoonse Caoabilities
a. Insoection Scooe (81700)
The inspectors evaluated the security organization's response capability
to security threats, contingencies, and routine response situations,
including drills to ensure consistency with the security procedures, the
approved PSP. and Safeguards Contingency Plan (SCP).
b. Observations and Findinas
The inspectors reviewed the response commitments of the SCP in the
following areas: deadly force, central and secondary alarm station
operations, communications, and security system degradations. Response
personnel were required to be competent in these skills before doing
response duties. As stated in S4.1. response personnel interviewed were
. .
.
16
knowledgeable of their responsibilities and duties indicated in these
skills. The licensee conducted two table top drills and two response
exercises during the inspection. The ins)ectors observed the drills and
exercises, and reviewed the critiques. T1e critiques stated the number
of adversaries and their objectives involved in each drill. The 1
performance of each res
weaknesses were noted. ponse member was indicated and any strengths or
c. Conclusions
The security organization's response capability to security threats,
contingencies, and routine response situations including drills, were
consistent with the security procedures, the approved Physical Security
Plan, and the Safeguards Contingency Plan.
S6 Security Organization and Administration
S6.1 Manaaement Sucoort
a. Insoection Scooe (81700)
The inspectors evaluated the level of management support for the
security program.
i
b. Observations and Findinas
The ins)ectors verified that station and security management support was
'
thorougl in identifying, reviewing, and analyzing the root cause of
problems. setting priorities for corrective actions and, usually, timely
correcting identified problems. The problems of the security computer
system were reviewed and are discussed in S7.1. The inspectors reviewed
the progress to correct the protected and vital area violation stated in
the Safeguards Information Inspection Report No. 50-395/96-03 dated 4
March 22. 1996. The compensatory measures implemented to temporarily l
secure the subject areas were still in place. The inspectors indicated
that compensatory measures which are two years old were not indicative
of proactive management support for the security program. '
c. Conclusions
t
Management support for the security program was generally strong. A
notable exception to this support was compensatory measures remaining in
, place for two years.
S6.2 Manaaement Effectiveness
a. Insoection Scooe (81700)
The inspectors evaluated the effectiveness of management's
administration of the security program.
.
17
b. Observations and Findinas-
The inspectors verified station and security management had established
l organizational goals and objective measures necessary to determine
l- security effectiveness Management has ensured that responsibility for
l all necessary activities were assigned to qualified subordinates as
L evident by Security Plan revisions and organizational improvements.
This effectiveness was also found in the security training improvements
l described in Section SS.1 of Safeguards Information Inspection Report
No. 50-395/96-06. Management's review and follow-up of the performance
'
i of delegated responsibilities were done by personal observations, formal
channels for opinions from subordinates, internal and external audits,
and tracking and trending of security events.
c. Conclusions
Management's administration of the security program was proactive and
-
i
effective, t
l S6.3 Staffina Level
a. Lrtsnection Scooe (81700)
The-inspectors evaluated the total number of trained security officers
and armed personnel immediately available at the facility to fulfill
response requirements specified in the PSP. The inspectors also
determined if one full-time member of the security organization, who had
the authority to direct security activities, did not have duties that
! conflicted with the assignment to direct all activities during an
incident.
b. Observations and Findinas
The inspectors verified that the licensee has an onsite physical
protection system and security organization. The security organization
and physical protection system were designed to protect against the
design basis threat of radiological sabotage as stated in ,
10 CFR 73.1(a). The inspectors verified that at least one full-time !
manager of the security organization was always onsite and had no duties '
that conflicted with the assignment to direct all activities during an j
incident. This individual had.the authority to direct the physical '
, protection activities of the organization. The inspectors reviewed four
shift rosters and interviewed security force personnel on two shifts. '
The licensee had the number of trained security officers and armed
personnel immediately available to fulfill response requirements and
l commitments of the PSP.
l c. Conclusions ;
The total number of trained security officers and armed personnel
immediately available to fulfill response requirements met Physical
l Security Plan requirements. One full-time member of the security
1
, .
18
l
organization who had the authority to direct security activities did'not ,
have duties that conflicted with the assignment to direct all activities
during an incident.
S7 Quality Assurance in Security and Safeguards Activities
S7.1 Effectiveness of Management Control
a. Insoection Scoce (81700)
The inspectors evaluated the overall effectiveness of the following:
licensee's controls for identifying, analyzing, and resolving problems:
determine adequacy of corrective actions to prevent recurring problems;
and determine whether there are strengths or weaknesses in the controls
for issues that could enhance or degrade plant operations or safety.
b. Observations and Findinas
The inspectors reviewed documented security issues, events, and problems
to determine the adequacy of the licensee's controls and effectiveness
in the following: initial identification of the problem: elevation of
the problems to the proper-level of management for resolution: root
cause analysis: disposition of operability problems; implementation of
corrective actions: and expansion of the scope of corrective actions to
include related systems, equipment, procedures, and personnel actions.
The inspectors also reviewed documented security issues, events. and
problems to determine the strengths or weaknesses in the. licensee *s
controls. These areas have been addressed in Sections S4.1. S4.2 and
S6.1. S6.2, and S6.3.
Discussions with maintenance personnel and reviews of the Security
Events Logs. Summaries, and Work Orders revealed that there was a
potential weakness in having sufficient spare parts on hand to maintain
the security computer system for the next five years. The system was
installed in the late 1980s. Presently, security maintenance personnel
were doing an exce)tional job in maintaining the security system. The l
prompt and thorougl sevicing of the security system was notable. Record !
reviews indicated that the number of equipment failures was i
progressively escalating. This may result in a system degradation. The i
licensee indicated that there was approximately five years of spare
parts available onsite if the maintenance and repairs of the system
degradation do not increase substantially. The licensee was aware of
this problem and has plans to update the security computer system within
the next five years. i
i
c. Conclusions ,
!
Overall the licensee was effective in identifying, analyzing, and
resolving security related problems. The adequacy of corrective actions
to prevent recurring problems was found excellent. There were strengths
in the maintenance program of the security equipment and system that
supported plant operations and safety. The licensee was aware of the
i
.
.
19
weakness in the security system due to aging equipment that could
eventually lead to system degradation.
L Manaaement Meetinas
X1 Exit Meeting Summary
i
The inspectors ) resented the inspection results to members of licensee
management at t1e conclusion of the inspcction on April 20. 1998. The
licensee acknowledged the findings presented.
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 )
Licensee
F. Bacon, Manager. Chemistry Services
L. Blue. Manager. Health Physics
S. Byrne. General Manager. Nuclear Plant Operations
R. Clary. Manager. Quality Systems
M. Fowlkes. Manager, Operations
S. Furstenberg. Manager. Maintenance Services
D. Lavigne. General Manager. Nuclear Support Services
G. Moffatt. Manager. Design Engineering
K. Nettles. General Manager. Strategic Planning and Development
L. Hipp. Manager. Nuclear Protection Services
A. Rice Manager Nuclear Licensing and Operating Experience
G. Taylor. Vice President. Nuclear Operations
R. Waselus. Manager. Systems and Component Engineering
R. White. Nuclear Coordinator. South Carolina Public Service Authority
B. Williams. General Manager. Engineering Services
G. Williams. Associate Manager. Operations
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 61726: Surveillance Observations
IP 62707: Maintenance Observations
IP 71707: Plant Operations
IP 71750: Plant Support Activities
IP 81700: Physical Security Program for Power Reactors
IP 92901: Followup - Plant Operations
IP 92902: Followup - Maintenance
IP 92903: Followup - Engineering
, .
20
ITEMS OPENED. CLOSED. AND DISCUSSED
Ooened
50-395/98002-01 URI assess safety significance of raising first
stage turbine pressure (Section E1.2)
50-395/98002-02 VIO failure to search vehicles according to Security
Plan Procedures (Section S2.1).
1
Closed
50-395/97003-01 VIO failure to establish procedures appropriate to
the circumstances (Section 08.1)
50-395/97003-03 VIO failure to follow procedure to raise reactor
building pressure (Section 08.2) ;
50-395/97013-01 IFI licensee's effort to identify the root cause and
corrective action for the "A" diesel generator l
problems (Section M8.2)
Discussed
50-395/98001-01 URI review solid state protection system TS
operability and testing requirements '
(Section M8.1)
l
l
1
l