ML20197D211
| ML20197D211 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 12/10/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20197D206 | List: |
| References | |
| 50-354-97-09, 50-354-97-9, NUDOCS 9712290003 | |
| Download: ML20197D211 (29) | |
See also: IR 05000354/1997009
Text
.
.
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Do:ket No:- 50 354
License Nos: NPF 57
Report No. 50 3E4/97 09
Licensee: Pubhc Service Electric and Gas Company
Facility: Hope Creek Nuclear Generating Station
Location: P.O. Box 236
Harscocks Bridge, New Jersey 08038
Dates: October 5,1997 November 15,1997 ,
'
inspectors: S. A. Morris, Senior Resident inspector
J. D. Orr, Resident Inspector ,
G. C. Smith Senior Physical Security inspector .
E. B. King, Physical Security Inspector .,
E. H. Grav, Senior Reactor Engineer
Approved by: James C. Linville, Chief, Projects Branch 3
Division of Reactor Projects
,
t
9712290003 971210
PDR ADOCK 05000354 i
G PDR u.
.. - -
.-. . - . . . , - - . . _ _ - - --- . - . - . . - . - - . . - .. . . ,
.. - - . - . .. -- - _ - _ ...- - - - - .
!
< * 1
!
l
.
l'
EXECUTIVE SUMMARY
, Hope CreJk Generating Station
NRC Inspection Report 50 354/97 09
'
j
] This integrated inspectior. includes aspects of licensee operations, engineering,
maintenancc, and plant support. The report covers a six week period of resident -
inspection; in addition, it includes the results of announced inspections by three regional .
inspectors, one who reviewed PSE&G follow up activities to the core spray norzle through j
wallleak event and two who evaluated the effectiveness of site security programs and i-
-
- practices.
! QacIations 1
!
Operators demonstrated inconsistent performance overall, and exhibited notable
.
- weaknesses with respect to attention to detail and awareness of equipment status. i
4
(Section 01.1) !
PSE&G personnel displayed excellent overall performance in the development, pre bricling,
, and implementation of the plan to drain down the reactor cavity and vessel to support core
]
- spray nozzle repair efforts. (Section 01.2) ,
Operators exhibited poor performance during the conduct of an infrequently performed l
- shutdown margin demonstration in that a stuck control rod procedure was not followed ;
and conservative decision making with regard to reactivity management was not
4 demonstrated. Additionally, these actions and decisions were not sufficiently challenged
by control room observers. (Section 04.1)
,
The inspectors judged that Quality Assurance findings were well supported, independent,
-
and promptly referred to station management for action. Quality Assurance oversight of
control room activities was usua'ly good. (Section 07)
Maintenance ;
!
- Maintenance department technicians exhibited adequate performance during the conduct of
outage work activities and testing. While procedure and work order usage was generally
good, deficiencies in interdepartmental coordination and foreign material exclusion controls
were evident. (Section M1.1)
Numerous unplanned emergency diesel generator start attempts and equipment restoration
delays were encountered as a result of poor work centrols over mechanical govemor
maintenance and replacements. (Section M4.1)
Maintenance technicians improperly set up the mechanical overspeed trip device for the 4
. reactor core isolation cooling turbine in part due to weak procedural guidance, which
complicated a subsequent tutbine overspeed event. Insufficient verting of the turbine
control oil system, again partly because of limited proceduro guidance, was judged to be
the primary cause of the overspeed event. (Section M4.2)
ii
4
h
e
-+-m+ s-,-w .----s,, wm -~-w-nse, e A -- - m-me-w.* s m~ m-em.~-n--..,mSm -rw-,,-w-+,,w e mm t.e + mv- ,--r e. - , <p-w- mm nn gn--,-.--e---- a m n v m ,- wv mm w n , , ,.$
_ _ ._ _ . _ _ . . _ . _ _ . _ _ _ _ _ _ _ _ . _ . _ _ _ _ . _ . . _ _ ._ __ _ _ .. _
. I
!
'
,
PSE&G performed a detailed and thorough evaluation of the f ailed core spray nozzle weld
j history, previous nondestructive testing, and through wallleak causal f actors. Proposed-
corrective actions were judged to be reasonable and appropriately focused on preventing
recurrence. However, the f ailure to detect and repair a weld flaw in 1995 during a focused i
ultrasonic inspection of the noted core spray nozzle highlighted weaknesses in the Hope ;
Creek inservice inspection program. (Section M8.1) i
inadequate surveulance test procedure development led to the undetected inoperability of
,
one train of the filtration, recirculation, and ventilation system. Corrective actions were ;
-
effective. (Section M8.3)
Enaineerina -
PSE&G promptly developed and implemented an acceptable design cho. ige packege to !
resolve a self identified issue involving bracket weld cracks on jet pump instrument lines. l
(Section E1.1) !
Engineering department prepared safety evaluations were of good quality and were
appropriately focused on the potential nuclear safety impact of the plrnt design or
equipment changes. (Section U2.1)
PSE&G acted promptly and effectively in the resolution of a self identified issue involving a
potential secondary containment bypass leakage pathway. (Section E8.4)
'
!
Plant Suonort
PSE&G maintained an effective site security program. Management support of program
'
objectives was evident. Performance of security department person.nc! cnd equipment
were generally good.
,
PSE&G's provisions for land vehicle control measures satisfied regulatory requirements and
licensee commitments. The site protected area barrier was properly installed and
maintained, and satisfied the requirements of the NRC approved security plan.
!
s i
l
iii
- . - . _ _ _ . _ _ _ _ _ . _ _ , _ _ _ _ _ _ _ _ _ _ _ _ - - . .__ _ _ . _ _ . _ _... _ _ ..
.
.
TABLE OF CONTENTS
EX E C UTIVE SU M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
T A B L E O F C O N T E N T S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv
1. O p e r a t i o n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01.1 General Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01.2 Reactor Cavity and Vessel Drain Down Evolution ............ 2
04 Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . 3
04.1 Shutdown Margin Demonstration . . . . . . . . . . . . . . . . . . . . . . . . 3
07 Quality Aseurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
08 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
08.1 (Closed) LER 50 354/9713 01: Unplanned high pressure coolant
injection system inoperability ..........................6 ,
ll . M a in t e n a nc e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
M1.1 General Observations of Maintenance and Surveillance ........ 6
M4 Maintenance Staf f Knowledge and Performance . . . . . . . . . . . . . . . . . . 7
M4.1 Emergency Diesel Generator Maintenance and Testing . . . . . . . . . 7
M4.2 Reactor Core Isolation Cooling System Maintenance and Testing .9
M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
M8.1 (Closed) URI 50 354/97 07 02:"A" core spray nozzle (N50) sofe end
leak, non-destructive examination and repair . . . . . . . . . . . . . . . 10
M8.2 (Closed) LER 50 354/97 23: core spray nozzle weld through wallleak
..............................................11
M8.3 (Closed) LER 50-354/97 26:*E" filtration, recirculation, and
ventilation system recirculation unit inoperability due to tripped high-
high temperature switch - procedure deficiency . . . . . . . . . . . . . 11
Ill . E ng ine e r ing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 2
E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
E1.1 Jet Pump Instrument Line Bracket Weld Cracking . . . . . . . . . . . 12
E2 Engineering Support of Facilities and Equipment ................. 13
E2.1 Design Change Package and Safety Evaluation Review ....... 13
E8 Miscollaneous Engineering Issues . . . . . . . . . . . . . . . . . . , . . . . . . . . . 14
E8.1 (Closed) LER 50 354/96-09: operation in an unanalyzed condition due
to inappropriate service water system / safety auxiliaries cooling
system throttle valve settings . . . . . . . . . . . . . . . . . . . . . . . . . 14
E8,2 (Closed) LER 50-354/9615: potential to operate in an unanalyzed
condition due to a design deficiency in the (service water emergency)
overboard discharge line . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
E8.3 (Closed) LER 50 354/97-24:as found values for safety relief valve lif t
setpoints exceed technical specification allowable limits ...... 15
E8.4 (Closed) LER 60 354/97 25: design deficiency potential for an
unmonitored release path through the station service water system
iv
_ _ - . _ -_
l
- ;
l
i
i
.
..............................................16 l
E8.5 (Closed) URI 50 354/96 04 06:non conservative rnaximum ultimate l
'
heat sink temperatura limit . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
E8.6 (Closed) VIO 50 354/E96 28104013: inappropriate service
water / safety auxiliaries cooling system throttle valve settings . . . 16 !
l
IV. Pl a nt S u pp or t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 16 l
S2 Status of Security Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . 17
S2.1 Protected Area Access Control of Vehicles . . . . . . . . . . . . . . . . 17
S2.2 Alarm Stations, Communications and Assessment Aids . . . . . . . 17
S2.3 Testing, Maintenance and Compensatory Measures . . . . . . . . . . 18
S5 Security and Safeguards Staff Traininn and Qualification . . . . . . . . . . . 19
S6 Security Organization and Administration . . . . . . . . . . . . . . . . . . . . . . 19
S7 Ouality Assurance in Security and Safeguards Activities ...........20
S7.1 Audits .........................................20 !
S8 Miscellaneous Security and Safeguards issues ............. . . . . 21 l
S8.1 Vehicle Barrier System . . . . . . . . . . . . . ................21 .
S8.2 Bomb Dia st Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 l
S8.3 Procedural Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 2
V. M a nag eme nt M e e ting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 2
X1 Exit Meetine Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 2 i
X2 Review of Updated Final Safety Analysis Report . . . . . . . . . . . ..... 22 i
i
v :
-- - - . , ._ ,_
.
,
Report Details
1, 0Refstions
01 Conduct of Operations
.
QM General Observatlora
a. jnsocution Scone 171707)
Throughout the report period, the inspectors routinely reviewed and obserwd
operator performance with respect to technical specification (TS) action statement
tracking, proceduto compliance, attention to detail, and reportable event accuracy
and timeliness. Quality assurance (OA) efforts were also assessed.
b. Qb.tmiyations and Findinas
The inspectors witnessed inconsistent performance by operators during their
conduct of routine and off normal activities. For example, reactor fuel reload
activities were executed very well, in contrast to the offload activities earlier in the
outage. All fuel moves were performec'in a single dimension, and no errors were
noted in bundle selection or placement. As noted in section 01.2 below, efforts
involving the reactor cavity drain down were conducted effectively. Shutdown
cooling and spent fuel pool decay heat removal system flow paths were closely
controlled and protected. Control room operators were generally f amiliar with most
work being conducted in the plant.
OA inspector coverage in the control room was frequent and provided generally
good independent assessment of plant activities. Of particular note, a OA inspector
questioned operators on whether a decision to commence core alterations
(operational condition') from operational condition 5 was consistent with TS 3.0.4
since two trains of the filtration, Iacirculation and ventilation system (FRVS) were
inoperable. TS 3.0.4 mandates that entry into an operational condition shall not be
made when conditions for the limiting conditions for operation (LCO) are not met
and the associated action statement ultimately requires a plant shutdown. The
FRVS TS 3.6.5.3 LCO requires that all six FRVS recirculation units be operable in
operatii, ial condition'. Because of OA intervention in this issue, a potential TS
violation was avoided during the operational condition change.
The inspectors noted other performance deficiencies during the report period.
Specifically, on November 7,1997, relieving operating shitt personnel questioned
off going operators about the status of the safety parameter display system. At
that point off going operatorr reallred that the system had been inoperable for
nearly 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, since the degraded condition was first identified and
communicatsd to engineering personnel for resolution earlier in their shif t. Operators
appropriately recognized that this condition required a non-emergency 10 CFR
50.72 report to the NRC as a " major loss of emergency assessment capability" in
accordance with the Hopa Creek emergency classification guide. Operations
management concluded that this reportable event resulted from inadequate
turnovers, follow up, and communichtions.
,
,. -
rv- r- . ,- , - , - - - - - ,- -,--n--e,
. ..--_. - ._ - . . - - _ __. . . ._ _- - _ _ .
.
.
2 I
Othat weaknesses were identified as well. A loss of offsite power / loss of coolant
accident (LOP /LOCA) surveillance of the *B" 4100 VAC vital bus had to be rapeated >
when the *B" residual heat removal system pump failed to start because the motor
supply breaker switch was inadvertently lef t in " pull to lock." Implementation of
several test procedures, including a reactor core isolation cooling system valve
inservice test procedure observed by the inspectors, did not meet department
expectetions for placekeeping. A reactor auxiliaries cooiing system head tank
overflowed while troubleshooting continued on an emergency diesel generator ;
control system because operators did not maintain full cognizance of system status.
Though not anticipated, a service water pump automatically started as designed i
during a remote shutdown panel test because the pump controls were left in
automatic during the activity. While performing core alterations, secondary
containment pressure went positive with respect to atmospheric conditions during
recovery from a LOP /LOCA surveillance when a reactor building ventilaCon
subsystem tripped. The unreliability of this subsystem had been demonstrated by
earlier unexplained trips, and caused the inspectors to question the decialen (af ter
the f act) to continue fuel movements during the noted LOP /LOCA tert.
c. C,onclusiont
Operators demenstrated inconsistent performance overall, and exhibited notable
weaknesses with respect to attention to detail and awareness of equipment status..
Quality assurance oversight of control rooms activities was usually good.
QL2 Reactor Cavity and Vessel Drain Down Evolution
a. Impection Scope (71707)
The inspectors observed portions of the planning, briefing, and implementation of a
first time evolution involving a reactor cavity and vessel drain down to suoport weld
repair efforts on the "A" core spray line nozzle.
b. Observations and Findinos
Weld repairs for the through wallleakage on the "A" core spray nozzle (see NRC
Inspaction Report 50 354/97 07 for details) required that the vessel penetration be
drained of water. Because this penetration is not isolable from the reactor vessel,
operators devised a plan for draining the cavity and vessel to a level below the
nozzle to support the work. The reactor fuel bundles were completely offloaded
into the spent fuel storage pool. The inspectors reviewed the newly prepared
procedure, which was in part based on other industry experience, and jedged it to
be of good depth and quality. PSE&G completed thorough reviews of the
procedure, which included a final approval by the station operations review
committee.
The pre evolution briefing was timely and comprehensive, and was attended by a
wide array of direct and peripheral evolution participants. Contingency measures
were thoroughly discussed, and effective communications were stressed.
_ _ _ _ _ _ __
_ _ _ .. _ . - . _ _ _ _ _ _
_ _ . _ _ _ _ _ _ _ . _ - _ _ _ ,
[
4
3 [
'
Because the entire core had been transferred to the spent fuel storage pool,
operators planned a functional test of the residual heat removal fuel pool cooling
assist mode bnfore the fuel pool getes were installed. The inspectors observed the
functional terit, an activity which had not been perforrned since Hope Creek pre-
operational testing. Based in part on a prior detailed procedure walk through, the ;
test was completed without error or incident.
Operators properly conducted the drain down evolution using the newly developed
procedure. Appropriate actions were taken upon discovery that the equipment pool
gate seals were leaking water at a rate of several hundred gallons per minute, ,
Oulck recognition and timely response !n accordance with pre planned contingencies
and briefings ensured that no additional complications were encountered. The gate
seals were repairet, and the drain down was completed successfully. The
inspectors witnessed excellent management oversight and interdepartmental l
coordination during this activity. +
c. Conclu11ong
PSE&G personnel displayed excellent overall performann ir* the development, pre-
bilefing, and impleninntation of the plan to drain down the reactor cavity and vessel
to support core spray norrie repair efforts.
04 Operator Knowlvdge and Performance ,
QL1 Shutdown Maroin flamonstration
a. ADippetion Scone U1707)
The inspectors observed portions of a post refueling reactor shutdown margin
demonstration performed to demonstrate compliance with technical specification 3.1.1.
b. Observations and Findinas
On November 12,1997, with the plant in operational condition 5 (reactor vessel
head removed). control roon, operators began a core shutdown margin
demonstration in accordance with procedure HC.RE ST.ZZ 0007(O). This test ;
'
involved the full withdrawal of twenty control rods (of 185 total) selected by the
reactor engitioering .tarf. Operamrs invoked "special test exception" TS 3.10.3 to
permit conduct of this infrequently p9rformed svolution since the test required the
mode switch to be placed in the **.tartup" pc ition, defeating the one-rod out
interlock normally required le operational condition 5. The inspectors verified that all
associated TS required conditions were satisfied during performance of the test,
which included reactor protection system (RPS) shorting link removal and the need '
fo % dependent oversight and verification of test procedure compliance by a
" technically qualified member of the staff," in this case the reactor engineering
department supervisor, since the rod worth minimiter was inoperable.
_ _-, __ - . - - . _. __
.
.
4 -
Operators experienced difhculty withdrawing several of the test-designated control
rods. As cuch, early in the evolution during an initial observation, the inspectors ,
noted that operators appropriately implemented step 4.6 of the stuck control rod l
procedure, HC.OP AB.ZZ 104(O), which requires that control rod drive (CRD)
hydraulic system drive water pressure be " raised in 50 psiincrements" until the
tod(s) were freed during single notch attempts, at which time the pressure "should
be immediately restored to the norrnal range" (260 270 psi). However, later in the
evolution during a subsequent observation, the inspectors noted that one control
rod appeared to withdraw from the core abnormally f ast, and determined that drive
water prewsure was still at an elevated level (approximately 400 psi), indicating that
drive pressure was not returned to the normal range following successfulinitial
movement. Additionally, operators did not return the drive water pressure to the
normal range prior to selecting and withdrawing the next rod in sequence. This
latter observation indicated that operators inappropriately remained M the stuch rod
procedure without first meeting the prerequisite of unsuccessful control rod
movement with normal drive water pressure. The inspectors questioned this
practice because it appeared to be contrary to the noted proceduro guldance, and
because continuous rod withdrawals from position 00 to 48 were being performed.
,
The senior reactor operator (SRO) supervising the evolution stated that he felt
justified in departing from the stuck rod procedure (both the prerequisites for usage
and step 4.6 regarding the incrementalincreases in drive pressure) in part because.
he was concerned that repeated cycling of the CRD pressure control valve was
distracting his reactor operator from monitoring the source range count rate nuclear
instrumentation. Further, the SRO stated that he " knew," based on experience, that
every rod in the test sequence would require an elevated drive water pressure in
order to be withdrawn. He further stated that the on duty operations
superintendent also endorsed this practice. The reactor engineering department
supervisor monitoring the evolution did not express a concern. The inspectors
shared their observations with a quality assurance inspector also present in the
control room but that individual did not independently pursue resolution of the issue
with station management. Finally, no narrative log entries were made describing
the basis for departing from the specific requirements of the abnormal operating
procedure.
The inspectors judged that operator's acted non-conservatively when they elected
not to adhere to the requirements of the stuck control rod abnormal operating
procedure, in that they permitted reactivity additions at potentially unknown or
uncontrolled rates. Specifically, operators performed an infrequent evolution which
added positive reactivity to an essentially now, untested reactor core with several
new control rod blades using CRD mechanisms and hydraulic control units which
had undergone either complete replacements or large scale maintenance, with their
operability not yet fully demonstrated. Defense-in-depth from a potential fission
product release was reduced since one of the principal barriers was degraded (i.e
the vessel head was removed). The one rod-out interlock was defeated because the
reactor mode switch was in "startup" to support performance of the test.
Moderator temperature was below 100 degrees F, increasing core reactivity. The
rod worth minimizer was inoperable and was being compensated by additional
- . . . - . - ___ _ __
_ _ ._ . .
.
. I
1
5
human oversight Collectively, the inspectors judged that these conditions 6Sould
have warranted increased vigilance by reactor operators adding reactivity to the
core, especially during an evolution that is designed to verify that the reactor will
remain sufficiently ruberitical with twenty rods fully withdrawn.
The inspectors reviewed other PSE&G procedures prescribing expectations for
reactivity management and conservative decision making. The inspectors identified
two procedures, NC.NA AP.ZZ 0005(O) (NAP 5) and HC.0P AS.ZZ 0002(Z), which
provide guidance la these areas. Sections 5.21 and 6.30 of NAP-5 prescribe station .
'
policy on the use of reactivity controls and specifies that personnel "act
conservatively when f aced with adverse conditions which could affe-t reactor
safety." The latter noted procedure, which is a specific Hope Creek operations
department performance standard, requires operators to adhere to reactivity
manipulation procedures " alertly and cautiously," and to move control rods in a
" deliberate, :arefully controlled manner." The inspectors judged that the standards
of performance defined in these two documents were not met during the November
12,1997 shutdown margin demonstration.
Until the inspectors discussed their observations with senior site management on
November 13,1997, the significance of the noted issues went unrecognized by
station personnel. Station management demonstrated an appropriate response to
the issues, which included a formal debriefing with all of the station operators, and,
initiation of a formal root cause and fact finding investigation. Memorandums
reiterating expectations for maintaining " utmost caution" during reactivity
manipulations were also issued. The responsible on shif t operations superintendent
was reassigned to other duties.
The inspectors noted that no actual safety consequences resulted from performance
of the shutdown margin demonstration. Also, actual measured control rod speeds
during the test were later determined to be within the analyzed envelope. However,
plant eperation outside established reactivity manipulation procedures under the
described circumstances reflected a poor operating practice and was judged to be
an apparent violation of TS 6.8.1 procedure requirements. (eel 50 354/97 09 01)
c. Conclusions
Operators exhibited poor performance during the conduct of an infrequently
performed shutdown margin demonstration in that a stuck control rod procedure
was not followed and conservative decision making with regard to reactivity
management was not demonstrated. Additionally, these actions and decisions were
not sufficiently challenged by control room observers.
07 Quality Assurance in Operations
The Quality Assurance (QA) departrnent conducted a detailed team review and audit
of Hope Creek operations department performance with focus on technical
specification (TS) implementation and action tracking during the report period. The
inspectors observed portions of the audit and discussed relevant QA findings with
.
4
0
lead oversight personnel. The QA team concluded that verbal communications,
peer checking, infrequent evolution pre job briefs, and senior reactor operator
oversight of control room activities were good. No improper operability
determinations were identified. Howrver, the team Judged that procedure
placekeeping and documentation, as well as TS action statement tracking, were
weak. The team also concluded that there appeared to be a negative trend with
respect to conservative decision making. Several examples, including the above-
described shutdown margin demonstration issue, were used as a basis for reaching
this conclusion. The inspectors judged that QA findings were well supported,
independent, and promptly referred to station management for action.
08 Miscellaneous Operations issues
QL1 (Closed) LER 50 354/9713 01: unplanned high pressure toolant injection system
inoperability. This event was described in detailin NRC Inspection Report 50-
354/97 04 and resulted in issuance ci a violation of 10 CFR 50 Appendix B
Criterion XVI. This supplemental LER was submitted to describe in greater detail
the impact and significance of the event. Specifically, plant operators failed to enter
TS 3.0.3 and commence a plant shutdown because the inoperability of the high
pressure coolant injection (HPCI) system was not recognized during the period of
time when two trains of the residual heat removal system were inoperable for on-
line maintenance. The inspectors judged that the LER accurately described the
circumstances of the event and that proposed corrective actions were reasonable.
No additional new information was provided by this LER.
II. Maintenang_t
M1 Conduct of Maintenance
M 1.1 General Observations of Maintenance and Surveillanca
a. inspection Scope (71707)
Throughout the report period, the inspectors conducted frequent observations of
station maintenance and surveillance activities to verify proper procedures were in
use, adequate retests were completed or scheduled, monitoring and test equipment
(M&TE) was within calibration, housekeeping and foreign material exclusion
standards were satisfied, and coordination between departments was evident.
Additionally, the inspectors reviewed PSE&G actions taken in response to self-
identified or self revealing issues involving maintentnce or testing. A sample of
safety-related equipment tagouts were evaluated for adequacy of development and
implementation. Detailed assessments of specific observations and reviews are
described in section M4.
- - . . .. . _ _ - _ -.____-_ - - - _... . - - - _ _ . _. -- - . - _ - -- - -__ - .
'
.
i
/ ,
,
b. Observations and Findinas
,
The inspectors observed inconsistent performance with respect to maintenance
department activities. While most work orders reviewed spelfied adequate post-
maintenance retest activities, some were noted to be deficient because the
proposed tests were too narrowly focused. Though inspector verifications of
equipment tagouts did not identify any deficiencies, several self identified "near-
misses" were docurnented. Most observed maintenance was adequately supervised
and coordinated between engineeri ,g and operations, however on one instance
security grates were partially removed from circulating water system piping without
prior notification of security personnel to ensure that appropriate compensatory
measures were in place.
Weld overlay repairs of the through wallleak on the NSB core spray nozzle were
well planned, coordinated and executed. Underwater work in the primary
- containment suppression pool to replace the *D" residual heat removal suction
strainer was aiso well executed. Torus cleaning activities were judged to be
excellent; the inspectors conducted an extensive pre closeout tour of the torus and
found only minor deficiencies.
Howover, several performance deficiencies were also noted. For example, foreign
~
.
material exclusion practices on the refuel floor were initially poor in that several
objects were inadvertently dropped into the reactor cavity while the reactor vessel
head was removed. Subsequent actions to improve performance in this area were
effective, including more strict use of lanyards, tool controls, etc. A vital bus loss
of power / loss of coolant accident surveillance test activity had to be repeated
because maintenance technicians improperly set up the M&TE used for test data
collection. Poor coordination with operations personnel during conduct of scram
discharge volume (SDV) flushing resulted in the generation of an unexpected half-
scum signal when water level exceeded SDV the trip setpoint.
,
c. Conclusions
Maintenance department technicians exhibited inconsistent performance during the
conduct of outage work activities and testing. While procedure and work order
usage was generally good, deficiencies in interdepartms. ital coordination and foreign
material exclusion controls were evident.
M4 Maintenance Staff Knowledge and Performance
M4.1 Emeroency Diesel Generator Maintenance and Testina
a. Inspection Scone fQ2707)
The inspectors reviewed the circumstances surrounding several f ailed post-
maintenance tests and surveillances of the emergency diesel generators (EDG).
Additionally, the inspectors observed the startup and troubleshooting of the "A"
EDG on November 6,1997. Discussions related to the testing failures were held
with control room operators, engineers, and maintenance supervisors,
i
-. , _ . _ . , -_,.-~e_. ,. - .-.- _ . . . - - .._ . , , . , . . ...., , . _ . _,. . ,,m- m . _ . . . .m . _ _
-- .. . .
.
8
b. Observations and Findinas
Following a scheduled electronic governor replacement, maintenance technicians
began overspeed trip testing on the "B" EDG on September 27,1997. The
technicians noted during restoration from the %st that the mechanical governor
speed control adjustment, used during the o tspeed test, could not be returned to
its original pre test setting. The entire mechanical governor assembly was then
replaced based on a vendor recommendation, and the damaged unit was shipped
offsite to a repair f acility. PSE&G reviewed the maintenance history on the *D" EDG
mechanical governor and determined that the most likely failure of the speed control
was an over adjustment of the speed knob on September 27,1997 con blned with
inadequate tightening of internal governor dial stops in December 1994.
On September 29,1997, two attempts were made to start the "B" EDG for post-
maintenance testing af ter the mechanical governor replaccment. On both attempts
the EDG tripped on low lube ol' pressure. PSE&G later determined that the initial
setup of the new mechanical governor did not ellow the engine to develop sufficient
speed to clear the low lube oil pressure trip. PSE&G subsequently developed a new
procedure which provides guidance for performing initial diesel generator mechanical
governor setups af ter maintenance or replacement (" Diesel Generator Speed / Load
Control System Alignment," HC.MD CM.KJ-0015(O)h The inspectors learned that
previous mechanical governor maintenance was conducted with direct oversight by-
vendor representatives using work orders ind vendor technical references as
guidance.
On November 6,1997, following outage work, the "A" EDG was carrying the
10A401 vital bus in accordance with " Integrated Emergency Diesel Generator
1 AG400 Test 18 Months," HC.OP ST.KJ-0005(O). During the test, the control
room operators discovered that the EDG would not respond to speed changes. The
EDG was shut down and engineering personnel developed an action plan to
troublesnoot the control problem. Technicians subsequently determined that the
mechanical governor was improperly set, controlling the engine speed at too low a
value which prevented the electronic governor from effecting speed changes.
Further investigation by PSE&G determined that the speed knob on the mechanical
governor was not restored to the proper position at the conclusion of an earlier
overspeed test.
The inspectors noted that none of the affected EDG's described above were
required to be operable at the time of the maintenance or testing. Additionally, all
of the applicable technical specification EDG surveillance tests were completed
satisfactorily for each machine prior to restoring them to an operable status,
c. Conclusions
Namerous unplanned emergency diesel generator start attempts and equipment
restoration delays were encountered as a result of weak work controls over
mechanical governor maintenance and replacements.
- -- - _. - _ -.----_- - - -.- - - - - -
. !
!
l
9 !
M4.2 Reactor Core Isolation Coolina System Maintenance and lestina >
a, lasoection Scone (62707)
The inspectors reviewed the maintenance conducted prior to and following a reactor
'
core isolation cooling (RCIC) system turbine overspeed trip event du'ing testing,
b. Observations and Findinos
On November 9,1997, with the rtuctor plant in operational condWnn 6,
maintenance technich.ns attempted to perform an overspeed trip test of the RCIC
turbine using auxiliary steam in accordance with procedure HC.MD PM.FC 0001(O),
- Reactor Core isolation and Cooling Steam Turbine Inspection and P.M." The pre.
Job brief for the evolution was good in that Individuals were assigned specific
4 actions should unforeseen e.ircumstances arise during the test. As required, the t
'
turbine was uncoupled from the pump and turbine speed was controlled from a local
potentiometer and was raised in 50 rpm increments, with an overspeed trip t
expected at approximately 5625 rpm. At 4900 rpm, the RCIC turbine unexpectedly ;
accelerated to about 7500 rpm. A maintenance technician in the RCIC room
immediately tripped the turbine with the local trip device after recognizing the
,
overspeed condition, as assioned during the pre job brief. The RCIC system was
not required to be operable at the time of the test.
The inspectors judged the PSE&G's troubleshooting plans and follow up actions to
the overspeed event to be adequate. Based in part on vendor recommendations,
RCIC turbine inspections were conducted to verify that the no equipment damage
resulted. PSE&G determined that one of the causes of the event was that the
mechanical overspeed trip device was not properly set up during the previous
system maintenance, primarily bucause the work procedure did not provide
sufficient detail to ensure consistent implementation. PSE&G revised the HC.MD-
PM.FC 0001(Q) procedure to include a detailed verification that the mechanical
overspeed trip device is properly set prior to operating the turbine. Engineers
determined the most likely cause of the overspeed event, aside from the failure of '
the trip mechanism, was air entrapment in the turbine governor control oil following
a filter change. PSE&G enhanced the RCIC turbine operating procedures by adding
additional oil system venting activities to minimize the potential for air introductlen
during RCIC operation.
c. Conclusions
Maintenance technicians improperly set up the mechanical overspeed trip device for
'
the RCIC turbine in part due to weak procedural guidance, which complicated a
subsequent turbine overspeed event, insufficient venting of the turbine control oil
wystem, again partly because of limited procedure guidance, was judged to be the
primary cause of the overspeed event.
. ~ . _ . _ _ , . - _ _ _ _ __ _. _ _ _ _ - - _ _ - - _ _ _ _ _ _ _.-
.
10
M8 Miscellaneous Maintenance issues
M8.1 (Closed) URI 50-354/97 07-02:"A" core spray nozzle (NSB) safe end laak, non-
destructive examination and repair.
a. htmgetion Scoce (73115)
This inspection was conducted as a followup to an issua 8M' unresolved following a
recent inservice inspection program assessment. The W ..ivolved the f ailure to
identify degradation prior to the development of a through wallloak in the NSB core
spray nozzle to safe end weld. The process employed to repair the lock (weld
overlay with .emperbead welding) on the low alloy steel nozzle was also reviewed.
b. Q32servations and Findinos
The inspectors reviewed PSE&G's formal root cause evaluation report for the NSB
core spray injection nozzle through-wallleak, dated November 4,1997, af ter
meeting with some of the participants on the evaluatio.: team. The inspectors
found ti at extensive fact gathering and root cause analysis were performed with
appropriate corrective actions either proposed or implemented. The safety
significance of the degraded NSB weld were discussed in the report, which stated
that there were no actual consequences and that there was no impact on public
health and safety. Though an increass in unidentified drywellleakage (from 0.3 to
0.0 gallons per minute) was noted in August 1997 during plant operation, this
increased leakage was withh TJ limits and was not associated with an increase in-
radiation. Because the crack exhibited the * leak before break" behavior expected
for the materials of construction, any further crack propagation with the plant
operating would have resulted in an increased unidentified leak rate followed by a
normal plant shutdown prior to a catastrophic pipe f ailure. Postulation of
consequences of the worst case event, that is a failure of the core spray line
initiated by a transient (e.g. seismic event) was evaluated by the PSE&G engineers
and found to be within the plant's design and licensing bases.
PSE&G identified one of the causal f actors of this issue was ineffective computer-
based ultrasonic testing (UT) dats evaluation. Recent re review of 1995 UT data
identified a misdiagnosed degrav'.d condition to have been present in 1995. The
1995 UT analyst noted the presence of a recordable indication, but judged that
there was no requirement for either supplemental non destructive examination (NDE)
or UT examination of the area containing the indication. PSE&G's recent review of
UT data on 19 other similar welds, including the conduct of UT on six of these
welds in 1997, did not identify any similar problems. On another set of 16 welds
that were examined by the somo UT process as the NSB weld, a reexamination of
six of these in 1997 by manual UT did not identify degradation. Other than the NSB
wold UT problem, no other incidents of a f ailure to identify potentially significant
flaws were found.
The 1995 UT analyr t dispositioned the NSB weld indication as acceptable based on
the nozzle weld data provided which indicated that the material was INCONEL 82
.
B
11
and was therefore not susceptible to stress corrosion cracking. During the
licensee's root cause analysis, it was determined that the construction material
should have been recorded as INCONEL 182 which is susceptible to cracking.
Immediate corrective actions to resolve the through-wallleakage included the repair
of the NSB weld by weld overlay. The corrective actions directed toward improving
the effectiveness of UT of welds similar to NSB included specific instructions to
Level 111 UT examiners for dissimilar welds, procedure reviews to clarify data
interpretation actions, industry involvement to improve UT of dissimilar welds,
additional review of causes and corrective actions, requirement for indepeMent
review of UT data by a second analyst for category D welds, consolidatice nd
review by data analysts of as-built data for each weld, and review of site specific
flaws and reflectors by the data analysts prior to review of new NDE data.
The failure to promptly idenufy the degraded core spray nozzle weld in 1995, a
condition adverse to quality, coupled with the f ailure to reques supplernental
nondestructive evaluation or supplemental ultrasonic examination of the area when
the indication was initially discovered, represented an inadequacy in the inservice
inspection program. As such, this event was deemed to be a violation of 10 CFR
50 Appendix B, Criterion XVI Corrective Action. However, because this violation
was non repetitive, and because of the prompt and thorough development of root
causes and corrective actions, thlF violation is being treated as a Non-Cited
Violatiore, consistent with Section Vll.B.1 of the NRC Enforcement Policy (NUREG-
1600). (NCV 50 345/97 09 02)
c. Conclusions
PSE&G performed a detailed and thorough evaluation of the failed core spray nozzle
weld history, previous nondestructive testing, and through wall leak causal f actors.
Proposed corrective actions were judged to be reasonable and appropriately focused
on preventing recurrence. However, the failure to detect and repair a weld flaw in
1995 during a focused ultrasonl< inspection of the noted core spray nozzle
highlighted weaknesses in th.: Hope Creek inservice inspection program.
M3.2 (Closed) LER 50 354/97 23: core spray nozzle weld through wallleak. This event is
described in dew in NRC Inspection Report 50-354/97 07 and was left unresolved
pending an NRC assessment of the completed root cause evaluation for why
analyses of a previot3.nna.t nic tes't of this nozzle failed to detect a weld flaw.
This assessment was wu sh I during the current report period with the results
described in section M8.1 above. No new information was provided by this LER.
M8.3 (Closed) LER 50-354/97-26:"E" filtration, recirculation, and ventilation system
recirculation unit inoperability due ,o tripped high-high temperature switch -
procedure deficiency. This LER describes a self-identified issue in which the "E"
filtration, recirculation, and ventilation system (FRVS) recirculation unit was found
to be inoperable just prior -o conducting a monthly technical specification (TS)
surveillance test on Sept inber 12,1997. PSE&G determined that the unit had
been inoperable since the conclusion of the previous monthly test completed on
- _- - . .
.
.
12
August 17,1997, because of a recent surveillance tcat procedure change which
was deficient. Specifically, the FRVS test procedure was recently modified to
change the method used to verify heater power consumption at the end of a ten
hour heater run. However, no provision was included to allow the f an to run after
the heaters were deenergized to cool the coils. As such, when the unit ,is secured
following the August 17 test, the heater high-high temperature switch unsnowingly
tripped, rendering the unit inoperable. PSE&G recognized in t.'to LF.R discussion that
because the FRVS unit was inoperable for greater than sev',n days ithe TS allowed
outage time for one inoperable FRVS unit), the plant should have commenced a
shutdown on August 24,1997.
The inspectors verified that the FRVS surveillance test procedure was appropriately
revised following identification of this issue and that subsequsnt FRVS test runs
have not experienced any similar problems. This licensee-identified and corrected
technical specification violation is being treated as a Non-Cited Violation, consistent
with Section Vil of the NRC Enforcement Policy (NUREG 1600). (NCt! 50 354/97-
09-03)
111. Enaineerina
E1 Conduct of Engineering
ELj. Jet Pumo Instrument Line Bracket Weld Crackina
a. Inspection Scope (37051)
The inspectors reviewed PSE&G's actions in response to a self identified discovery
of three jet pump sensing line bracket weld cracks,
b. Observations and Findinas
Oming in-vessel visual inspections of jet pumps, PSE&G inspectors determined that
rn pump numbers 8,9, and 15 all exhibited instrument line bracket weld cracks
v nich required repair. Station engineering personnel proposed the use of
" temporary" clamps to secure the affected sensing lines rather than repair the
deficient welds. Hope Creek staff also performed comprehensive inspections of all
20 jet pumps, including the lower elbows next to the inside of the vessel where
cracking had been recently discovered at the Peach Bottom Atomic Power Station
(GE-BWR4). No cracking was noted in these areas at Hope Creek.
A conference call between NRC and PSE&G technical staff was held on November
14,1997 to discuss the issues related to the proposed jet pump clamp repair
methodology. The clamp design was developed for use at the Susquehanna Steam
and Electric Station (GE-BWR4) where similar jet pump instrument line bracket weld
i
cracking was detected in 1994. The installed clamps had been inspected at that
station during two subsequent refueling outages with no noted degradation.
PSE&G performed a detailed analysis of the potential effects on reactor operation
should a jet pump instrument line break while at power, and concluded that there
l
l
l
. . . - .-. -
_ ._ _ _ __ _ _ _ . . _ . _
.
(
--
g
13
would be no impact on safe plant operation. No concerns were raised during the .
course of the conference call.
The inspectors reviewad the design change package and associated evaluation for
installation of the jet pump clamps, and judged them to be acceptabla. Additionally,
thi inspectors observed portions of the actual clamp installation process, including a
review of the installation procedure, and did not identify 6ny deficiencies. Based on
the results of future refu(I outage inspections of these cumps, these jet pump
modifications may become a permanent installation.
c. Conclusiong
PSE&G promptly developed and implemented an acceptable design change pa::kage
,
to resolve a seliidentified issue involving bracket weld cracks on jet pump -
, instrument lines.
E2 Engineering Support of Facilities and Equipment
. Q1 Desian Chanae Packsae and Safetv Evaluation Review
a. Insoection Scoce (37551)
The inspectors reviewed the 10 CFR 50.59 safety evaluations associated with the
following plant system design modifications implemented during this report period:
- lsofoam in the turbine auxiliaries cooling system (TACS) accumulator floating roof
- Ultrasonic Test Scanner bearing cap - potentiallost part in reactor vessel
- Alternate air supply to SACS flow control valve for safety-related chiller units
- Re route service water vacuum breaker piping from secondary containment
Additionally, the inspectors observed the installation of several other engineering
design change packages needed before the restart from the RF07 refuelinr, outage,
including:
- Emergency core cooling system suppression pool suction strainer modifications
- Jet pump instrument line clamps
- Rod sequence control system elimination
- Reactor recirculation pump mechanical seal cartridge upgrade
.
b. Observations and Findinas
PSE&G engineering developed approximately 70 design change packages for
installation during the RFO7 refueling outage, several of which were not part of the
original outage work scope but were deemed necessary as a result of self identified
adverse or degraded conditions. For instance, a safety evaluation was prepared on
November 12,1997, to assess the impact of plant operation with an unrecovered
loose part in the reactor vessel. Specifically, a 1" x 2" steel bearing cap which had
fallen ' ff an ultrasonic testing rig used for in-vessel weld inspections was never
-- - - - -_
_ _ - __ _ _ _ _ _ ____ _
- - .
. . . - _. _ -
~
l
.
14
recovered despite extensive efforts to locate and retrieve the item. The safety
evaluation thoroughly assessed the potential concerns associated with this lost part,
including possible effects on control rod movement, core flow restrictions, etc., and ,
judged that even though the issue involved a " change" to the facility as described ir,
the UFSAR,it did not result in the need for prior NRC review and approval.
Several other engineering saf sty evaluations were reviewed and judged to be
acceptable.10 CFR 50.59 " applicability reviews" and unreviewed safety question
determinations included sufficient scope, detail and analysis to justify tha final
conclusions. The inspectors determined that none of the plant modifications
reviewed resulted in final installed conditions which were inconsistent with.
continued safe plant operation. In fact, most of the 70 change evaluations
completed during the outage were developed to enhance safe and uneventful plant
operation, as opposed to simply accepting degraded conditions "as is" or providing
.
for operational conveniences. ,
Based on the limited sample of evaluations reviewed, the inspectors judged that the
quality of the 10 CFR 50.59 process had improved over the past operating cycle.
Process improvements such as evaluation " grading," cross disciplinary peer
roviewing, independent auditing, and focused engineering department training
resulted in better and more thorough safety evaluations. Based on interviews with
engineering management personnel, the inspectors learned that the process will
continue to evolve based on recently issued regulatory and industry guidanco,
c. Conclusions
Engineering department prepared safety evaluations were of good quality and were
appropriately focused on the potential nuclear safety impact of the r! ant design or
equipment changes.
E8 Miscellaneous Engineering issues
EQJ fClosed) LER 50-354/96-09: operation in an unanalyzed condition due to
inappropriate service water system / safety auxiliaries cooling system throttle valve-
settings. This LER describes a self-identified issue involving a March 1996
discovery that station service water (SSW) system throttle valves were set
improperly in November 1992 after a design change which replaced these valves,
that would have prevented adequate SSW cooling flow to the safety auxiliaries
cooling system (SACS) heat exchangers during design basis accident conditions.
PSE&G recognized that while no safety consequence resulted from this failure to
maintain appropriate system configuration control, the plant was operated for nearly
four years outside of the design and licensing basis (see NRC Inspection Report 50-
354/96 06). PSE&G attributed the cause of this deficiency to an inadequate
engineering design modification process, which in 1992 did not require design
calculation assumptions to be verified by field data collected after modification
installation.
- - _ .
.
.
15
The inspectors determined that PSE&G's design change process was modified to
include the need to conduct field verifications of design calculation assumptions.
Additionally, PSE&G conducted a thorough design bases validation of the SSW and
SACS systems by performing an independent service water system operational
performance inspection, an NRC review of which was documented in NRC
inspection Report 50-354/97-06. Lastly, in direct response to the issue described in
this LER, on October 23,1996, the NRC issued a violation of TS 3.7.1.2.b, which
requires that an operable service water flow path be maintained to ensure adequate
cooling to the SACS heat exchangers (see section E8.6 below).
kBJ (Closed) LER 50 354/9615: potential to operate in an unanalyzed condition due to
a design deficiency in the (service water emergency) overboard discharge line.
During station service water (SSW) system design bask reviews performed in
response to previously identified discrepancies, engineering personnel identified an
error in SSW design calculations in that emergency discharge point dynamic flow
conditions were not properly accounted for. This discovery rendered the technical
specification (TS) limit on maximum ultimate heat sink (UHS) temperature non-
conservatively high (see NRC inspection Reports 50 354/96 04,96 06, and 97-01).
A public meeting between the NRC and PSE&G was held on July 18,1996, to
discuss this and other related SSW and SACS system design issues, as well as
instituted compensatory measures and proposed corrective actions. Compensatory
measures included placement of an administrative limit on maximum UHS
temperature and development of specific operator actions in the event of a loss of
one SSW or SACS loop. Corrective actions included the conduct of an independent
service water system operational performance inspection, followed by the submittal
of any needed license change requests.
PSE&G completed its SSW/ SACS / UHS design basis review in May 1997, and
submitted associated TS amendment requests for NRC review promptly thereafter.
An independent NRC inspection of the design basis review effort was documented
in NRC Inspection Report 50 354/97-06. NRC review of PSE&G-proposed licenso
changes was completed in October 1997, and were issued as TS Amendment 106.
The NRC safety evaluation report included with this amendment did not identify any
concerns with the PSE&G-proposed changes.
EDJ (Closed) LER 50-354/97-24:as found values for safety relief valvo lift setpoints
exceed technical specification allowable limits. This LER was written to document a
repeat issue involving main steam line safety relief valve (SRV) setpoint drift outside
technical specification (TS) limits. As found " bench testing" of the 14 Hope Creek
SRV's, which are a two-stage Target Rock design, determined that ten of the valves
had excessive drift (worst case was + 9.4%). The setpoint drift issue has been an
on-going industry-wide concern and several industry-driven corrective actions have
been proposed. The inspectors determined that PSE&G has been aggressively
pursuing resolution of this issue, which has included design changes to SRV pilot
valve seating materials. All SRV setpoints wera verified to be within TS allowable
drif t limits prior to reinstallation in the main steam system.
.
16
EBA (Closed) LER 50 354/97 25: design deficiency potential for an unmonitored release
path through the station service water system. This LLR describes a self identified
discovery of a potential secondary containment bypass leakage pathway. After a
postulated loss of power accident, station service water (SSW) system solenoid-
operated vacuum breakers would fall open allowing the reactor building atmosphere
to communicate directly with SSW piping, which discharges water outside the
secondary containment. This design deficiency was recognized by technicians
performing maintenance on the noted sotenoids. PSE&G promptly developed a
design change packagt to re-route the vacuum breaker vent piping to the outside
environment rather than from inside the reactor building. The inspectors reviewed
the design change package and the associated safety evaluation, es well as walked
down the modified piping after installation was complete. No defic!sncies were
noted. The inspectors judged that PSE&G acted promptly and effectively in the
resolution of this issue.
,
ESJ (Closed) URI 50-354/96 04-06:non-conservative maximum ultimate heat sink
temperature limit. This issue was left unresolved pending NRC review of PSE&G
corrective actions to self identified discrepancies in the service water and safety
auxiliaries cooling system design bases. These discrepancies resulted in the need
for several compensatory measures to be put in place to ensure that the ncted
systems remained operable. A detailed discussion of the NRC and PSE&G follow up
to this and other related issues is described in sections E8.1 and E8.2 above.
EQJ (Closed) VIO 50-354/E96 281-04013: inappropriate service water / safety auxiliaries
cooling system throttle valve settings. This issue was described in detailin NRC
Inspection Report 50 354/96-06,LER 50-354/96-09,and section E8.1 above. The
inspectors verified that corrective actions stated in PSE&G's violation response
letter dated November 22,1996, were completed. These actions included (1) a
comprehensive service water system flow balance in which engineering flow
calculation assumptions were validated with field data, (2) the engineering process
for making design modifications was enhanced with additional specific training
provided, and (3) an independent service water system operational performance
inspection was conducted.
IV. Plant Scoport
S1 Conduct of Security and Safeguards Activities
a. Insoection Scone
A focused review was performed to determine whether the PSE&G security
program, as implemented, met the licensee's commitments in the NRC-approved
security plan (the Plan) and NRC regulatory requirements. The security program
was inspected during the periods of November 3-7 and November 12,1997. Areas
inspected included: management support; audits; alarm stations, communications,
and assessment aids; testing, maintenance and compensatory measures; training
and qualification; protected area access centrol of vehicles; and the vehicle barrier
system.
. . . . - . - - _- - - -. . - . . , . . _ .
.
,
17
b. Observations and Findinas
Management support was ongoing as evilenced by the procurement and installation
of four X ray machines for access searco * packages, installation and
implementation of hand geometry, and range upgrades to enhance tactical response
training. Audits were thorough and in depth, alarm station operators were
knowledgeable of their duties, communications requirements were performed in
accordance 'vith the Plan, and assessment aids had adequate picture quality.
Vehicles requiring protected area access were controlled as required in the Plan.
Applicable procedures and security equipment were tested and maintained in
accordance with the Plan, and security training was performed in accordance with
the NRC approved training and qualification (T&O) plan.
Based on the observations and discussions with security management and plant "
.
engineering personnel, the inspectors determined that the PSE&G's provisions for
land vehicle control measures satisfied regulatory requirements and licensee
commitments,
c. Conclusions
PSE&G conducted security and safeguards activities in a manner that protected
public health and safety and that the program, as implemented, met the licensee's -
commitments and NRC requirements.
S2 Status of Security Facilities and Equipment
E2d Protected Area Access Control of Vehicles
a. inspection Scoce
The inspectors evaluated whether PSE&G controlled access of all vehicles to the
protected area in conformance with the Plan and regulatory requirements.
! b. Observations. Findinas and Conclusion
On November 5 and 6,1997, the inspectors observed security force members
(SFMs) performing vehicle searches. Additionally, the inspectors discussed vehicle
authorization and escort requirements with security management and SFMs and
determined that vehicles requiring protected area access were controlled as required
d
in the Plan and applicable procedures.
S2J Alarm Stations. Lommunications and Assessment Aids
a. Insoection Scoce
The inspectors determined whether the Central Alarm Station (CAS) and Secondary
Alarm Station (SAS) are: (1) equipped with appropriate alarm, surveillance and
communication capability, (2) continuously manned by operators, and (3) use
_ _ _ ,
- . . - . . .- _ - - - . ~ - --
i
.
18
independent and diverse systems so that no single act can remove the capability of
detecting a threat and calling for assistance, or otherwise responding to the threat,
as required by NRC regulations,
b. Observations and Findinos
i inspector observations of CAS and SAS operations verified that the alarm stations
were equipped with the appropriate alarm, surveillance, and communication
capabilities. Interviews with CAS and SAS operators found them knowledgeable of
their duties and responsibilities. The inspectors also ver!fied through observations ;
'
and interviews that the CAS and SAS operators were not required to engage in
activities that would interfere with the assessment and response functions, and that
.the licensee had exercised communication methods with the local law enforcement
agencies as committed in the Plan.
,
Additionally, on November 5,1997, the inspectors evaluated the effectiveness of
the assessnient aids, by observing on closed circuit television, a walkdown of the
4
protected area. The inspectors determined that the assessment aids in both cf the
alarm stations had adequate picture quality,
c. Conclusion
' The alarm stations and communications adequately implemented PSE&G's Plan
commitments and NRC requirements.
SM Testino, Maintenance and Comoensatorv Mean!ntt
, a. Inspection Scope
The inspectors determined whether programs were implemented to ensure the
reliability of security related equipment, including proper installation, testing and
, maintsnance to replace defective or marginally effective equipment. Additionally,
the inspectors evaluated the effectiveness that the compensatory measures put in
place when security related equipment fails,
b. Observations and Findinas
Tht, inspectors reviewed testing and maintenance records for security related
equipment and found that documentation was on file to demonstrate that the
licensee was testing and maintaining systems and equipment as committed to in the
Plan. A priority status was being assigned to each work request and repairs were
normally completed the same day a work request necessitating compensatory
i measures was generated. The inspectors also noted that the working relationship
between security and maintenance departments was improving and tracking and
trending programs to monitor recurring equipment problems to determine when
,
engineering support was required, were being implemented.
. - . - - .- --
._ . . _ . _ _ _ . .. _ __ ._ . _ _ . _ _
.
.
19
c.. Conclusions
Documentation on file confirmed that security equipment was tested and maintained
as required. Repair work was timely and the use of compensatory measures was
found to be appropriate and minimal.
S5 Security and Safeguards Staff Training and Qualification
a. insoection Scone
The inspectors evaluated whether members of the security organization were
trained and qualified to perform each assigned security related job task or duty in
accordance with the NRC approved T&Q plan,
b. Observations and Findinas
On November 5,1997, the inspectors randomly selected and reviewed the T&Q
records of thirteen security force members (SFMs). Physical and firearms
requalification records were inspected for armed SFMs and security supervisors.
The inspectors found that the training had been conducted in accordance with the
T&Q Plan and was properly documented.
During discussions with the security training staff and security management, the ;
inspectors were informed that new response weapons were purchased to enhance l
the licensee's tactical response capabilities. However, the new weapons will not be l
issued until all SFMs have been properly trained and qualified with the new
weapons. Further discussions revealed that the licensee was in the process of
upgrading its firing range. On November 6,1997, the inspectors toured the firing
range and determined, based on observations, that the upgrades would enhance
tactical response training. Additionally, the inspectors interviewed a number of
'
SFMs to determine if they possessed the requisite knowledge and ability to carry
out their assigned duties,
c. Conclusions
The inspectors determined that training had been conducted in accordance with the
T&Q plan. Based on the security force members responses to the inspectors *
questions and observations, the training provided by the security staff was
considered effective.
S6 Security Organization and Administration
a. insoection Scoce
The inspectors conducted a review of the level of management support for PSE&G's
physical security program.
_
_ . _ - _ . ._ _ _ _ _ . _ _ _ _ _ _.
.
.
20
b. Observations and Findinas
The inspectors reviewed various program enhancements made since the last NRC-
in@ection, which was conducted in April 1997. These enhancements included the
procurement and installation of four X ray machines for access search of packages,
and installation and implementation of hand geometry and range upgrades to
enhance tactical response training.
The inspectors reviewed the Manager - Nuclear Security's position in the
organizational structure and reporting chain. The Manager - Nuclear Security
reports to the General Manager Salem Operations, who reports directly to the
Senior Vice President - Nucleer Operations, who reports directly to the Chief Nuclear
Officer and President Nuclear Business Unit.
c. Conclusions ,
Management support for the physical security program was judged to be effective.
No problems with the organizational structure that could be detrimental to the
effective implementation of the security and safeguards programs were noted.
S7 Quality Assurance in Security and Safeguards Activities
S2d Audits
a. Insnection Sco.ag
The inspectors reviewed the licensee's Quality Assurance (QA) report of the NRC-
required security program audit to determine if the licensee's commitments as
contained in the Plan were being satisfied,
b. Observations and Findinas
The inspectors reviewed the 1997 combined QA audit of the security, access
authorization and fitness for-duty (FFD) programs, conducted May 19-30,1997,
(Audit No.97-031). The audit was found to have been conducted in accordance
with the Plan and FFD regulation. To enhance the effectiveness of the audit, the
PSE&G's QA audit team included four independent technical specialists.
The audit included findings in the security, access authorization and FFD areas,
however, the inspectors determined that the findings were not indicative of major
programmatic weaknesses. The inspectors further determined, based on
discussions with security management and FFD staff and a review of the responses
to the findings, that the resultant corrective actions were effective.
c. Conclusions
A recent Quality Assurance Audit of security was very comprehensive in scope and
depth, and at,dit findings were reported to the appropriate levels of management.
The inspectors judged that the audit program was being effectively administered.
I
- - _ _ -_
.-. . . . . - ._-
,
,.
21
88 Miscellaneous Security and Safeguards issues
Sfld Vehicle Barrier System (VBS)
General
On August 1,1994, the Commission amended 10 CFR Part 73, " Physical Protection
of Plants and Materials," to modify the design basis threat for radiological sabotage
to include the use of a land vehicle by adversaries for transporting personnel and
their hand carried equipment to the proximity of vital areas and to include the use of
,
a land vehicle bomb. The amendments required reactor licensees to install vehicle
control measures, including VBSs, to protect against the malevolent use of a land
vehicle. Regulatory Guide 5.68 and NUREC/CR-6190 were issued in August 1994
to provide guidance acceptable to the NRC by which the licensees could meet the
requirrments of the amended regulations.
Letters dated February 28,1996 and June 19,1996 from PSE&G to the NRC
forwarded Revisions 6 and 7 to its physical security plan that detailed the actions
implemented to meet the requirements of 10 CFR 73.55 (c)(7),(8), and (9) and the
design goals of the " Design Basis Land Vehicle" and " Design Basis Land Vehicle
Bomb." A NRC July 6,1996, letter advised the licensee that the changes
submitted had been reviewed and were determined to be consistent with the .
provisions of 10 CFR 50.54(p) and were acceptable for inclusion in the NRC-
approved security plan.
This inspection, conducted in accordance with NRC Inspection Manual Temporary
Instruction 2515/132," Malevolent Use of Vehicles at Nuclear Power Plants," dated
January 18,1996, assessed the implementation of the licensee's vehicle control
measures, including vehicle barrier systems, to determine if they were
commensurate with regulatory requirements and the licensee's physical security
plan.
The inspectors reviewed documentation that described the VBS and physically
inspected the as-built VBS to verify that it was consistent with the licensee's
summary description submitted to the NRC. The inspectors' walkdown of the VBS
and review of the VBS summary description disclosed that the as-built VBS was
consistent with the summary description and met or exceeded the specifications in
NUREG/CR-6190. The inspectors determined that there were no discrepancies in
the as-built VBS or the VBS summary description.
$12 Bomb Blast Analysis
The inspectors reviewed the licensee's documentation of the bomb blast analysis
and verified actual standoff distances provided by the as-built VBS. The inspectors'
review of the licensee's documentation of the bomb blast analysis determined that
it was consistent with the summary description submitted to the NRC. The
inspectors also verified that the actual standoff distances provided by their as-built
VBS were consistent with the minimum standoff distances calculated using
__ _ _.
.- - - - - . - _ . -. .
.
.
22-
'
NUREG/CR-6190. The standoff distances were verified by review of scaled-
drawings and actual field measurements. No discrepancies were noted in the
documentation of bomb blast analysis or actual standoff distances provided by the
as-built VBS.
, ESJ Procedural Controls
The inspectors reviewed applicable procedures to ensure that they had been revised
to include the VBS. The inspectors reviewed the licensee's procedures for VBS
access control measures, surveillance and compensatory measures. The procedures
contained effective controls to provide passage through the VBS, provide adequate
surveillance and inspection of the VBS, and provide adequate compensation for any
degradation of the VBS. The inspector's review of the procedures applicable to the
VBS disclosed no discrepancies.
V. Manaaement M_tafirnt
X1 Exit Meeting Summary
The inspectors presented their findings and conclusions to members of licensee
management at the conclusion of the report period on November 21,1997. 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.
X2 Review of Updated Finst Safety Analysis Report (UFSAR)
A recent discovery of a licensee operating its f acility in a manner contrary to the UFSAR
description highlighted the need for a special focused review that compares plant practices,
procedures, and parameters to the UFSAR description. Since the UFSAR does not
specifically include security program requirements, the in:;pectors compared licensee
activities to the NRC approved physical security plan, which is the applicable document.
While performing the inspection discussed in this report, the inspectors reviewed
Section 4.1.2 of the Plan, titled " Protected Area - Physical Barrier Description" was
reviewed. The inspectors determined, by observations, that the protected erea barrier was
properly installed, maintained and satisfied the requirements of the Plan.
-
.
.
23
- INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 61726: Surveillance Observations
IP 62707: Maintenance Observations
IP 71707: Plant Operations
IP 73755: Inservice inspection - Data Review and Evaluation
IP 81700: Physica! Security Prograrn for Po ner Reactors
ITEMS OPENED, CLOSED, AND DISCUSSED
OpentLd
50-354/97-09-01 eel Shutdown margin demonstration, apparent TS 6.8.1
violation
Onened/CloLqd
50-354/97 09 02 NCV Violation of 10 CFR 50 Appendix B, Criterion XVI
Corrective Action
50-354/97-09-03 NCV FRVS recirculation unit inoperability
Q219d
50-354/E96-281-04013 VIO Inappropriate service water / safety auxiliaries cooling
system throttle valve settings
50 354/96-04-06 URI Non-conservative maximum ultimate heat sink
temperature limit
50 354/97-07-02 URI 'A' core spray nozzle (N5B) safe end leak, NDE and
repair
50-354/96-09 LER Operation in an unanalyzed condition due to
inappropriate SWS/ safety auxiliaries cooling system
throttle valve settings
50 354/96-15 LER Potential to operate in an unanalyzed condition
50 354/97-13 01 LER Unplanned HPCI inoperability
50 354/97 23 LER Core spray nozzle weld through-wallleak
50-354/97 24 LER As found values for safety relief valve lift setpoints
exceed TS allowable limits
50 354/97 25 LER Design deficiency - potential for an unmonitored release
path through the SSW system
50-354/97 26 LER "E" FRVS recirculation unit inoperability
. . - . . - .
-.
- 1 .
24 j
h
LIST OF ACRONYMS USED
CAS Central Alarm System
- CRD. Control Rod Drive
EDG Emergency Diesel Generator ,
FRVS- - Filtration, Recirculation and _ Ventilation System
HPCI High Pressure Coolant injection
LER Licensee Event Report
LCO ~ Limiting Conditions for Operation
LOP /LOCA - Loss of Offsite Power / Loss of Coolant Accident
- M&TE Monitoring & Test Equipment
- NDE- Non-destructive Examination ,
,
- - NRC Nuclear Regulatory Commission
_
PDR- Public Document Room .
PSE&G Public Service Electric and Gas
OA: Quality Assurance -
,
RCIC Reactor Core Isolation Cooling
RG Regulatory Guide
RP&C_' Radiological Protection & Chemistry
RPS Reac. tor Protection System
SACS Safety Auxiliaries Cooling System
SAS Secondary Alarm System
SFM Security Force Members
SRO. Senior Reactor Operator
SSW- Station Service Water
T&O Training and Qualification
TACS Turbine Auxiliaries Cooling System
the Plan- NRC approved Physical Security Plan
TS -Technical Specification
UFSAR Updated Final Safety Analysis Report
'
UT Ultrasenic Testing
- VBS
. Vehicle Barrier System
-
1
e
-
-. w -p_ .- y y - v_, -
.m-_._-- _eg .ge.g .w g, y y ,,e