ML20134F014
| ML20134F014 | |
| Person / Time | |
|---|---|
| Site: | Vogtle  |
| Issue date: | 10/28/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20134F006 | List: |
| References | |
| 50-424-96-10, 50-425-96-10, NUDOCS 9611040220 | |
| Download: ML20134F014 (28) | |
See also: IR 05000424/1996010
Text
. _ . - - . . . . . - . - - - - - . - . - . . - . . . - . - ~ . - . - - .-
. - ,
l
.
'
U. S. NUCLEAR REGULATORY COMMISSION (NRC)
REGION II
i
Docket Nos. 50-424 and 50-425
License Nos. NPF-68 and NPF-81 .i
!
Report No: 50-424/96-10, 50-425/96-10
Licensee: Georgia Power Company (GPC)
l
Facility: Vogtle Electric Generating Plant. Units 1 & 2 (VEGP) l
Location: 7821 River Road i
i
'
Waynesboro. GA 30830
i
Dates: August 18 - September 28. 1996
Inspectors: C. Ogle. Senior Resident Inspector i
M. Widmann, Resident Inspector i
K. O'Donohue. Resident Inspector (in training) '
J. Shackelford Reliability and Risk Analyst. NRR (Section
M3.1)
R. Frahm Jr. Operations Engineer. NRR (Section M3.1) !
E. Christnot. Resident Inspector. Hatch (Section M1.5)
T. Ross. Senior Resident Inspector. Farley (Section 08.1 and ,
E8.1)
Approved by: P. Skinner. Chief Projects Branch 2
Division of Reactor Projects
!
l
i
'
!
i
1 .
f Enclosure 2
9611040220 961028
PDR ADOCK 05000424 l
G PDR )
-e%w .-n m. 7 v -~p , g-
-- . - - - . - . - - - . - .-. - - . . . - - .- - --. - - -
,
.~ i
l
EXECUTIVE SUMMARY j
l Vogtle Electric Generating Plant, Units 1-and 2 i
NRC Inspection Report 50-424/96-10, 50-425/96-10
i
This integrated inspection included aspects of licensee operations. l
engineering, maintenance, and plant support. The report covers a six-week
period of resident ins)ection. In addition, it includes the results of l
announced inspections )y two visiting resident inspectors and two headquarters l
..
personnel. :
Doerations ;
i
e In general, the conduct of operations was satisfactory (section 01.1). 1
I
l e Plant control was good, procedures were used, and a)propriate trending i
! of data was observed by the inspectors during the slutdown of Unit 2
(section 01.3).
i l
!
e A non-cited violation was identified for improperly implementing a l
l procedure used to drain the pressurizer relief tank (section 01.4).
!
.
'
e A violation was identified as a result of 1-HV-8220, reactor coolant
system hot leg post accident sampling system (PASS) isolation valve,
being in the improper position for approximately 55 hours6.365741e-4 days <br />0.0153 hours <br />9.093915e-5 weeks <br />2.09275e-5 months <br />. This is a
containment isolation valve whose position is indicated in the control
room. This is a repeat event (section 02.2).
e The inspectors identified examples of minor deficiencies involving
caution and hold tags (section 03.1).
'
e Independent Safety Engineering Group (ISEG) assessments of outage risk i
, were identified as a positive example of licensee self-assessment
l (section 07.1)
Maintenance
e In general, maintenance and surveillance activities witnessed by the
inspectors were satisfactorily performed (section M1.1 and M1.2).
e As part of the licensee's routine monitoring program, debris was ,
identified in a nuclear service cooling water line to the safety
injection pump 1A lube oil cooler (section M1.3).
e A non-cited violation was identified as a result of an improperly
established relay calibration procedure. The procedure specified
,
installing a mechanical block in the relay during the calibration but
l did not provide instructions for removing the block (section M1.4).
l
l Enclosure 2
l
, ,. - - , , . , , -.
_ _ . _ . _ _ _ . . _ _ . _ . - _ _ _ _ _ _ . . _ _ . _ _ _ . _ _ _ _ .
!
I
,
l
.
. ;
2 ;
i
e An Inspector Followup Item (IFI) was identified in the area of safety l
assessment associated with taking equipment out of service with respect ,
to 10 CFR 50.65 (a)(3) Maintenance Rule. Several weaknesses with the t
licensee's implementation of the Maintenance Rule were noted-(section i
M3.1). i
.
Enaineerina
I
e Inspector concerns regarding observed practices were identified during !
the performance of main steam relief valve testing. While these !
practices did not impact the operability of the valve, the concerns were ;
e provided to licensee management for consideration (section E2.1). !
i
'
e The licensee was complying with the provisions of its boraflex
surveillance program. The current interim compensatory measures !
developed to mitagate the ongoing degradation of boraflex were well
thought out, conservative, and supported by sound engineering judgement ,
and evaluations. Compensatory measures were evaluated pursuant to 10 i
CFR 50.59, incorporated into the u) dated UFSAR and plant procedures, and i
implemented. An unresolved item (JRI) was identified for some spent i
fuel pool (SFP) boraflex concerns pending receipt and review of the l
lecensee's response to generic letter (GL) 96-04 (section E8.1). :
Plant SuDDort
e A violation was identified concerning an unsecured designated vehicle in
the protected area (section 53.1).
1
i
!
!
i
! Enclosure 2
i
l l'
l
(
l
_
l
_ _ _____ _ _ _. . _ _ _ _ _ _ . . . ._ . _ _ _ .
!
.
.
Reoort Details
Summary of Plant Status j
! Unit 1
'
1 Operated at full power throughout the inspection period. .
Unit 2 f
The inspection report period began with the unit coasting down from 100% power [
in preparation for the Unit 2 fifth refueling outage (2R5). Unit 2 completed i
412 days of continous run prior to shutdown. The unit shutdown was commenced ;
on September 8, with entry into mode 5 occurring on September 9, 1996. Mode 6 l
was attained on Seatember 13, and fuel offload completed on September 18. i
1996. Reload of t1e fuel into the reactor vessel was in process on September !
28th. j
,
!
I. Operations
01 Conduct of Operations !
01.1 General Comments (71707) )
L :
Using Inspection Procedure 71707. the inspectors conducted frequent i
reviews of ongoing plant operations. In general, the conduct of
'
operations was satisfactory.
01.2 !) nit 2 Shutdown (71707)
The inspectors witnessed the Unit 2 shutdown activities in preparation
for the 2R5. This included observation on September 7-9, 1996 of
! selected sections of the following evolutions: power reduction and entry
into mode 2 (Procedure 12004-C Power Operation); entry into mode 3
(Procedure 12005-C. Reactor Shutdown to Hot Standby): entry into mode 4 j
(Procedure 12006-C. Unit Cooldown to Cold Shutdown): and placing the i
residual heat removal system (RHR) in service (Procedure 13011, Residual i
Heat Removal System). j
Plant control was good, procedures were used, and appropriate trending !
of data was observed by the inspectors. ,
!
i- 01.3 Core Offload (60710)
-l
The inspectors witnessed portions of activities related to core offload 1
and fuel handling in the spent fuel pool per Procedures 93300-C Conduct
of Refueling Operations: 93641-C, Development and Implementation of Fuel
Shuffle Sequence Plan; and FP-GAE/GBE-FE3, Vogtle Canister Sipping
i
Enclosure 2
l
,. _ -
.
.
2
Procedure. The activities reviewed in the spent fuel pool included fuel
shuffle to prepare for core rel]ad, fuel map)ing to verify the
assemblies were positioned in a:cordance wit 1 the fuel shuffle data
sheets, and fuel sipping of ass 3mblies from 2RS.
Overall, the conduct of the core offload was in accordance with
procedures and the evolutions witnessed by the inspectors in the spent
fuel pool were satisfactorily performed.
01.4 Pressure Relief Tank (PRT) Draindown Procedure Not Procerly ImDlemented
a. Insoection Scooe (71707)
The inspectors reviewed the circumstances surrounding the draining of
the Unit 2 PRT on September 11. 1996 without nitrogen being aligned to
the tank. This included a review of Procedures 13004-2. Pressurizer
Relief Tank Operation: 13201-2. Gaseous Waste Processing System; and the ,
integrated plant computer trend plots of PRT pressure and level. The '
inspectors also interviewed cognizant operators and reviewed logs on the
issue,
b. Observations and Findinos
On September 11, 1996, operations personnel draining the PRT, observed
unexpected changes in PRT pressure, level, and reactor coolant drain
tank pump flow. The draindown was stopped and the licensee determined
that the PRT pressure had been reduced to approximately zero pounds 3er
square inch gauge (psig) as a result of nitrogen being isolated to t1e
PRT. The inspectors were subsequently informed by the licensee that !
their examination of the tank and review of later system operation i
revealed no damage. The inspectors independently inspected the PRT and l
noted no deficiencies. i
The draining of the PRT had been immediately preceded by PRT venting
using a waste gas compressor in accordance with Section 4.4.4 of
Procedure 13201-2. During this venting, nitrogen was isolated to the l
PRT by means of a manual isolation valve. When the desired PRT pressure !
'
reduction had been accomplished, the waste gas compressor was stopped
and a partial restoration performed. The manual nitrogen isolation
valve was not reopened prior to draining the PRT per Procedure 13004-2. l
The inspectors were informed that only a partial restoration from the
venting lineup was performed to facilitate venting the PRT again after
it had been drained.
During their review the inspectors determined the following:
-
The transition between PRT venting and draining was not properly
accomplished. Not opening the manual nitrogen supply valve prior
to exiting the venting evolution resulted in not satisfying a
prerequisite and initial condition of Procedure 13004-2. Some
Enclosure 2
--- - . - - . . . . ~ . - - -... - . _ - -.-.- _- - - . . - . .
l
!
l
j
.
i
3 l
>
operators involved were aware that only a partial restoration was i
performed following venting. However, the impact of this partial :
restoration was not properly evaluated. l
.
-
The operators failed to abide by a caution in Procedure 13004-2 !
I
requiring that a positive pressure of 3-5 psig be maintained ;
within the PRT while draining. Prior to starting the draindown.. !
PRT 3ressure was a) proximately 1 psig, outside the range specified ;
in t1e caution. W1en questioned on this discrepancy the cognizant l
l operators indicated that they were aware of the initial PRT !
l pressure as well as the caution. The inspectors noted that this !
l practice is not consistent with routine inspector observations on !
f procedural compliance. l
l- !
' -
The unexpected changes in PRT-pressure, level. and reactor coolant !
drain tank pump flow were detected after several minutes of j
draining by inquisitive operators. However. an earlier j
,
o)portunity to detect the isolated nitrogen sup)1y was missed when :
'
t1e control room operator failed to detect no clange in PRT :
pressure upon opening two other nitrogen supply valves. j
Planned corrective actions identified by the licensee included revising !
the procedure and counselling the responsible operators. ;
,
c. Conclusions i
Technical Specification (TS) 6.7.1 recuires that written procedures -
shall be established, implemented, anc maintained. The inspectors "
concluded that Procedure 13004 2 was not properly im31emented in that an :
initial condition to properly align. nitrogen to the )RT was not met i
prior to draining the tank. Furthermore. operators failed to maintain l
adequate nitrogen pressure in the tank. This is contrary to the ;
requirements of TS 6.7.1. However, consistent with Section VII of the i'
NRC Enforcement Policy this was identified as non-cited violation (NCV)
50-425/96-10-01. PRT Draindown Procedure Not Properly Implemented. ,
02 Operational Status of Facilities and Equipment
t
[
l
02.1 Testina Performed In Resoonse To Industry Control Rod Insertion Problems
a. Insoection Scooe (71707)
The inspectors witnessed portions of licensee actions taken in res)onse ;
to industry problems involving control rod performance. These pro)lems
were the subject of NRC Bulletin 96-01. Control Rod Insertion Problems.
Activities witnessed by the inspectors included a manual reactor trip
and rod cluster control assembly (RCCA) drag testing.
l
1
&
- Enclosure 2
--- , - - , . - -
___ __ __ . _ . .. _ _ _ _ _ _. _ _ _ _ _ _ . _ _ _ _ _ _
,
'
i
.
'
4
b. Observations and Findinas ;
i
During the Unit 2 reactor shutdown cn September 8, 1996, the licensee
conducted a pre-planned reactor tri) from approximately 3% power. The i
trip was initiated with control banc D at 138 steps and all other rods l
fully withdrawn. The inspectors observed that all rods fully inserted. '
Later in the report period, the inspectors also reviewed a. video tape
recording made of the digital rod position indications during the trip
and again noted all rods fully inserted.
On September 23, 1996, the inspectors witnessed portions of RCCA drag i
testing performed in the spent fuel 2001 (SFP). This testing was ,
conducted in accordance with Westinglouse Procedure STD-FP-1996-7686, '
Rev. O. RCCA Drag Force Testing. In this testing, a load cell was used
to measure the drag forces associated with withdrawal and insertion of
each RCCA over approximately 9 feet of movement. The licensee stated
i that all 53 rodded assemblies from the previous cycle wre
l
'
satisfactorily tested in this fashion. Based on their independent
review of the drag test data, the inspectors concurred with the
licensee's assessment.
The inspectors also noted that the licensee elected to test all 53
rodded assemblies although they were only required to test 22. The 22
,
assemblies tested were based on once burned rodded assemblies over 29500
!
Megawatt Days / Metric Tons of Uranium (MWD /MTU) and all twice burned
rodded assemblies between 43000 and 49000 MWD /MTU. The inspectors noted
that testing all 53 assemblies was a conservative action on the part of
the licensee.
c. Conclusions
l The inspectors concluded that the testing was adequately performed in
accordance with written procedures.
02.2 Post Accident Samolina System (PASS) Valve 1-HV-8220 In Imoroner
Position
l a. Insoection Scoce (71707)
!
The inspectors reviewed the circumstances surrounding the licensee's
September 19. 1996, identification that 1-HV-8220 reactor coolant
system (RCS) hot leg PASS sample isolation valve, was open instead of
shut as required. The inspectors reviewed operations, and maintenance
activities that may have required manipulation of this valve. This j
review included daily, weekly, and monthly surveillances, maintenance -
work orders (MW0s), in addition to primary chemistry sampling !
! requirements performed during routine operations. The inspectors also
- reviewed Procedures 14905-1, RCS Leakage Calculation (Inventory 1
i Balance): 35611-C. Remote Operation of the Post Accident Sampling l
! System; and 35614-C Operation of the Post Accident Sampling System.
,
! Enclosure 2
<
- _ . - - - - , - -- , . .
. . - _ - , - - - - - . - - - - _ . - . - - - - . - - . . -
!
t
.
.
5 i
b. Observations and Findinas
t
On September 19. 1996, during a turnover walkdown of the Unit 1 main
control room boards, the oncoming balance of plant operator identified
valve 1-HV-8220. RCS hot leg PASS sample isolation valve. in the o)en
position. This is a normally closed containment isolation valve w1ose
l
position is indicated by both the handswitch and main control board
'
lights. Following identification, the valve was shut without incident
using the control room handswitch. ,
l
Based on a review of the event sequence log. the inspectors determined j
l that the valve was in the incorrect position for approximately 55 hours6.365741e-4 days <br />0.0153 hours <br />9.093915e-5 weeks <br />2.09275e-5 months <br />. l
The event sequence log indicates that the valve opened on September 16
at 11:39 p.m. and remained open until 7:07 a.m. on September 19. The
inspectors * review of the primary chemistry 109. Procedures 35611-C. and
35614-C data sheets indicated that no primary sampling was performed
during that time period. The inspectors had previously identified this
same valve as being in the incorrect position on September 12. 1995, and
January 27. 1996. This issue was addressed as part of violation (VIO) ;
50-424/95-31-01. Unit 1 Post Accident Sampling System Valve In Incorrect i
Position and NCV 50-424/95-21-01. Mispositioned Fuel Oil Storage Tank :
Drain Valve and RCS Hot Leg PASS Sample Valve, respectively. The !
licensee had attributed these previous occurrences of 1-HV-8220 being !
!
found in the wrong position to performances of RCS leak rate
calculations resulting in a pressure pulse in the piping that allowed ,
the valve to be lifted off its seat. Once the valve partially opened,
the design of the 1-HV-8220 electrical circuit sealed-in the open signal
1 and the valve repositioned to full open. A modification was undertaken
l on August 26, 1996, to replace the valve with a new design based on the
- system application. The work was completed on Se)tember 11. 1996. A
'
review of the Unit 1 control room log indicated tlat no RCS leak rate
calculation was performed on September 16. A RCS leak rate was
performed on September 15 at 10:59 a.m.. however a review of the j
sequence of events log indicated that the position of 1-HV-8220 did not .
change as a result of this surveillance.
!
c. Conclusions
The inspectors noted that although the valve was improperly positioned. !
the valve remained operable and capable of performing its design
function. Therefore, the safety consequence of the mispositioned valve
was minimal. Additionally, it is noteworthy that the valve was detected
to be in the incorrect position by an operator as a part of his !
turnover. However, the fact that the valve position information was !
readily available to the operators, the duration, the repetitive nature
of this event, and the continuing occurrences of mispositioned valves !
all increase the significance of this issue.
'
. Enclosure 2
. _ , . .-
_ _ . _ _ _ _ _ _ _ _ . . . .__ - _ _ . . _ _ . _ _ . _ . _ _ . _ _ _ .
!
l .
i
.
6 ;
i
Overall, the inspectors concluded that four shifts were not cognizant of
the status of valve 1-HV-8220. This is a violation of Procedure 10000- ,
C. Conduct of Operations, which requires shift personnel be aware of !
,
equipment component status and system lineups. This is identified as
l VIO 50-424/96-10-02. Unit 1 Post Accident Sampling System Valve !
l Mispositioned.
t 1
!
03 Operations Procedures and Documentation j
03.1 Walkdown of Clearances (71707)
l
l During the inspection period, the inspectors walked down the following j
clearances:
29615151 RHR train B electrical and mechanical system tagout
29615181 Chemical volume and control system seal injection ,
tagout for reactor coolant pumps 1, 2. 3. and 4 1
29615988 Dilution valves !
l l
The inspectors did not identify any problems or concerns during these
walkdowns.
I During a few routine plant tours, the ins)ectors identified examples of
minor deficiencies involving caution and 1old tags. These deficiencies
were identified to control room personnel for resolution. The
inspectors also discussed their observations in this area with the
Operations Manager near the end of the inspection report period. The
inspectors noted this was a minor degradation in the licensee's usually
l strong performance in this area.
l
l 03.2 Walkdown of Miscellaneous Systems Inside Containment
a. Insoection Scoce (71707)
i The inspectors walked down, reviewed, and observed portions of the
following activities and procedures in progress: ,
11899-2 RCS draindown configuration checklist (sightglass walkdown)
13005-2 Reactor coolant system and refueling cavity draining
13115-2 Containment spray system train A & B
13130-2 Post-accident hydrogen control; hydrogen monitor system
train A & B
13601-2 Steam generator and main steam system operation
13615-2 Condensate and feedwater systems
23985-2 Reactor coolant system temporary water level system (reactor
vessel level instrumentation)
27505-C Opening and closing containment equipment hatch
i
i
'
Enclosure 2
l
-- - . - -- . - . - . - . .-- . . .-. . -._ !
i
l
! 7
b. Observations and Findinas
l
The inspectors concluded that the setup of the RCS sightglass and the
reactor vessel level instrumentation was in accordance with the written
procedures. The necessary equipment to establish and maintain
observation of the RCS and reactor vessel level was properly installed
and vented. The equipment necessary for the closure of the ecuipment
hatch in the event of an emergency was readily available insice
containment. The inspectors also verified that the maintenance crew
responsible for closure of the hatch was designated before each shift.
'
No concerns or discrepancies were identified during the valve lineups
l and containment penetration walkdowns conducted.
07 Quality Assurance in Operations
07.1 Licensee Self-Assessment Activities (40500)
The inspectors reviewed multiple licensee self-assessment activities
including:
-
Two (2) Plant Review Board (PRB) meetings (September 10 and
September 17)
l 1
-
Safety Audit and Engineering Review post-audit conference for a
materials control audit
-
ISEG assessments of shutdown risk during the 2R5 (dated September
10. 13. 18. 20. and 24)
-
Near Miss reviews 96-10 and 96-11
The ISEG assessments of outage risk were timely and provided specific
l
recommendations to plant management on measures that could be taken to
enhance plant posture relative to outage risk. This was identified as a
positive example of licensee self-assessment.
No concerns were identified. The inspectors concluded that the self-
assessment activities observed were effective.
08 Hiscellaneous Operations Issues (92901)
l 08.1 (Closed) VIO 50-425/95-11-01: Loss of Containment Integrity During
Refueling
The licensee submitted its reply to the NRC Notice of Violation by
c letter dated May 22, 1995. The ins)ector reviewed the corrective
l actions detailed in this letter. T1ese corrective actions included
. Enclosure 2
(
. _ . _ _ - _ . . _ _ _ _. _ _ _ . _ _ . _ . _ _ _ . . . . _ . _ _ _ . _
-
-
!
.
8
training of all responsible organizations and the establishment of a :
unique computer code in the nuclear plant management information system l
(NPMIS) database for plant components that could potentially impact i
containment integrity. The inspector reviewed the training lesson plans ,
and handouts used to discuss this event with Operations, Maintenance and !
Work Planning groux The licensee also provided the inspector with a :
demonstration on t1e capability of generating status reports of all >
MW0s, surveillance test procedures and clearances that could affect !
containment integrity by utilizing the Integrated Leak Rate Test coding i
in the NPMIS database. Based on this review, this VIO is closed. j
!
,
'
II. Maintenance
i M1 Conduct of Maintenance
l \
M1.1 Maintenance Work Order Observations
a. Insoection Scooe (62707). (62703)
The inspector observed portions of maintenance activities involving the
following work orders:
Work Order No. Comoonents
29501197 2-1201-04-251, RHR loop 1 hot leg suction bypass check
valve replacement
29502837 Engineered safety features chiller modification design
change package (DCP) 94 VAN 0033
29600304 Motor driven auxiliary feedwater (MDAFW) pump train A
outboard bearing replacement
, 29600316 2-HV-8701B, RHR loop 1 suction isolation valve:
l replace gears and convert to SB actuator per DCP
95V2N0023 (electrical)
'
29600926 2-HV-87028. RHR loop 2 suction isolation valve; motor
operator changeout and conversion to SB-1 actuator
(mechanical)
29600929 SFP fuel shuffle prior to core reload i
29601038 Steam generator 1 and 3 sludge lancing i
29601067 Diesel generator train 2B mechanical maintenance )
29601280 Pressurizer 2-PSV-8010A, B, and C code safeties ;
removal i
29602104 MDAFW pump train A bypass discharge line orifice
installation: DCP 95V2N0019
29602164 Pressurizer level transmitter LT-0460, low side root
valve replacement ;
Diesel generator train 2A mechanical maintenance
-
29602326
!
j Enc 1mure 2
_ _ _ _ . . _
- . __
,. _ . _ _ _ _ . _ . _ _ _ _ _ ..
- . _ . - - . . _ - _ . _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _
t
.
9
b. Observations and Findinas l
The observed maintenance activities were satisfactorily performed.
f
M1.2 Surveillance Observation ;
a. Insoection Scooe (61726) i
The inspector observed portions of the following surveillance
activities: ,
Surveillance Descriotion
i
14005-2 Shutdown margin and Keff calculations i
14928-2 Containment ventilation isolation-refueling '
14905-2 RCS leakage calculation
24531-2 Pressurizer level protection channel III 2L-461 analog
channel operational test and channel calibration
24991-2 Protection group II solid state protection system
input relay test
28916-C Containment type B & C leakage totalization
b. Observations and Findinas
The observed surveillances were satisfactorily performed.
M1.3 Nuclear Service Coolina Water (NSCW) System Debris
a. Insoection Scooe (62707)
, The inspectors reviewed the details associated with the licensee *s
j identification of debris in the Unit 1 NSCW system.
I
'
b. Observations and Findinas
On September 17, 1996, during a routine surveillance, the licensee
measured NSCW system flow to the safety injection pump 1A lube oil
cooler at 7.1 gallons per minute (gpm). Though this flowrate was below
the surveillance acceptance criteria, it was above a previously
calculated minimum, hence the pump remained operable. Later that day,
the Jump was removed from service and the lube cooler flow orifice
flusled. Two small )ieces of metal were removed by the flush and post--
flush flow through tie orifice returned to normal. The inspectors
examined the debris and noted that the material was similar to material
previously identified as pump bearing material.
.
1
!
l
Enclosure 2
_ _ _ _ __
_ _ - _ _ _ . _ _ _ _ . _ . _ . _ _ _ _ _ . . _ _ _ _ _ _ _ . - . _
!
'
,
. >
10
c. Conclusions !
The program to identify and removed debris from the NSCW System has
identified another instance of debris in the NSCW lines to a safety ;
related component. l
!
M1.4 Diesel Generator Underfreauency Relay Calibration j
a. Insoection Scoce (61726) I
'
The inspectors reviewed the circumstances surrounding the identification
of a mechanical contact block inside an underfrequency relay on diesel ;
generator (DG) 28 on September 7. 1996. The event was reviewed to i
determine the adequacy of the controls during the calibration process l
and if the problem documented per deficiency card (DC) 2-96-081 i
potentially affected more relays than just the DG underfrequency relay. :
As a result of this event the inspectors reviewed Procedures 13145-2,
Diesel Generators. 23278-C. Westinghouse Type KF Underfrequency Relay ,
Calibration, the MWO used to aerform the calibration, and the DC ;
associated with the event. T1e inspectors also interviewed the ;
instrumentation and control (I&C) technician involved. the system '
engineer, a systems electrical engineer, a maintenance I&C procedure
writer, and licensee management as to their review of this issue. j
i
b. Observations and Findinas
On September 7, at approximately 10:21 a.m. the DG was started for the !
monthly operability test. Upon starting annunciator ALB38-D06, Diesel
Generator 2B Generator Underfrequency. illuminated. I&C was notified to
investigate. A piece of paper was identified blocking the cylinder unit
contacts closed inside the underfrequency relay. After removal of the
obstruction the DG was successfully paralleled with 2BA03 4160V bus and
the surveillance 14980-2. Diesel Generator Operability Test, was
completed satisfactorily.
The inspectors' review of maintenance activities identified that an
underfrequency relav calibration had been completed the previous day,
During the calibration, the technician was required to block closed the
relay cylinder unit contacts to simulate the underfrequency condition.
However. a review of Procedure 23278-C by the licensee identified that
the procedure did not contain a step to remove the block once installed.
The inspectors' review of other relay calibration procedures for diesel
generators identified one additional procedure that did not address the
removal of the blocking mechanism before restoring the device to service
(Procedure 23227-C G.E. Type CEH51A Loss of Excitation Relay
- Calibration). In addition, the licensee identif.ed nine additional
)
I
'
Enclosure 2
i
i
- .- ,-r- -- ,- .-, , ,,.
--- -y , -e.- . - - - -
___ _ ___ _ _ _ _ .. _ _ . _ _ _ _ . _. _ . _ _ ._. _._._. _ _ ._. _
,
l
.
.
11
procedures that did not contain an independent verification to ensure
the device used to block contacts was removed. As c0rrective action the
licensee stated their intention to revise the procedures to incorporate
the necessary steps to address these issues,
c. Conclusions '
The inspectors concluded that although the relay block would prevent
synchronizing the diesel to the 4160 bus the diesel remained o)erable
and capable of performing its design function. Specifically, tie relay
did not impact the emergency starting and loading of the diesel.
Therefore, the safety consequences of the underfrequency relay being -
blocked closed were minimal. However, the relay calibration procedure
was not properly established as required by TS 6.7.1. Procedure and
Programs. Consistent with Section VII of the NRC Enforcement Policy
this was identified as NCV 50-425/96-10-03. Inadequate Procedure For
Westinghouse Type KF Underfrequency Relay Calibration.
M1.5 Nuclear Safety Coolina Water Pumo 1 Trio (Unit 1)
i
a. Insoection Scooe (62707) )
l
The inspectors reviewed maintenance activities involved with a NSCW pump
1 trip which occurred during relay testing. The activities were
performed under MWO 19601884. Discussions were held with maintenance
personnel, control room operators, and supervisors,
b. Observations and Findinas
i
During the performance of Procedure 14622-1. Slave Relay Test. NSCW Pump
! 1 trip)ed approximately one minute after starting. It was also observed
l that t1e breaker, 1ABB22. for the puma discharge valve 1HV-11600, had
trippec. The breaker was reset and t1e discharge valve.was stroked
successfully. The pum) was restarted and tripped after one minute and
six seconds. The disclarge valve started opening 59 seconds after the ;
start of the pump and tripped 15 and one-half seconds later. The :
breaker was reset and the valve stroked closed. As part of the l
troubleshooting activities the breaker was tested and no deficiencies
were observed. Maintenance personnel determined that due to timer drift
the following occurred.
-
The pump was started and the 45 second sequence began. This
allows the pump to come up to speed and pressure before the
discharge valve opens.
,
-
The valve did not start to open until approximately 57 seconds l
! after pump start. l
4
.
l Enclosure 2 l
l
- . -
. _ . . . _. .. ._. _ . _ _ __ . _. _ __ _ ._ __ __
.
.
12
-
At the 70 second sequence the discharge valve should be full open.
-
Due to the valve opening starting approximately 12 seconds late.
when the 70 seconds sequence ended the valve was not fully open.
-
The pump logic sensed this and triaped the pump. This gave an
immediate close signal to the disc 1arge valve which was in the
process of opening. ;
l
-
The close signal was inserted into a valve that was moving in the !
! open direction. This rapid reversal caused the breaker to sense :
an overcurrent condition and trip.
l
Maintenance personnel reset the time sequences to their proper values
and performed a satisfactory calibration check on the agastat timer
relay.
M2 Maintenance and Material Condition of Facilities and Equipment i
M2.1 Diesel Generator Crankcase Cracks (62707)
l
On September 9.1996, during pre-maintenance testing of the DG 2A, two J
cracks were identified by the licensee on the crankcase. The licensee's :
inspection of the other remaining DGs revealed similar cracks on all the
DGs. The cracks are located at the corners of the crankcase where the
l crankcase flange bolts to the base of the engine. The cracks are in the
l fillet radius of the flange and on the vertical face of the crankcase.
I
The licensee's initial determination has concluded that the cracks stem
,
from a downward bending force applied to the flange. According to the
!
DG vendor the most likely source of the bending forces was a relaxation
l of the hold-down bolts. As corrective action the licensee has torqued
l the DG 2A crankcase holddown bolts. The licensee plans to map and
l monitor the cracks at scheduled maintenance intervals of 18 months for
change.
The inspectors were informed by the licensee that the cracks did not i
represent a challenge to the operability of the engines. This l
conclusion was based on correspondence with the engine vendor that !
stated that the cracks are outside the main structural force lines and
,
will not propagate into a load carrying member of the crankcase. The
I
inspectors reviewed this correspondence and have no further questions in
this area.
, l
- Enclosure 2
- . .- _ _ _ _ _ . . ._ -
.
.
..
13
M3 Maintenance Procedures and Documentation
M3.1 Plant Safety Assessments Before Takina Eauioment Out of Service
i a. Insoection Scoce (62707)
, Paragraph (a)(3) of 10 CFR 50.65 states, in part, that the impact on
plant safety should be taken into account before taking equipment out of
service for monitoring or preventive maintenance. The inspectors
reviewed the licensee's procedures that were used to implement this
,
requirement and discussed the process with appropriate licensee '
personnel.
b. Observations and Findinas
The inspectors reviewed the licensee's program and practices associated
with the 50.65 (a)(3) safety assessments conducted prior to removing
plant equipment from service. The site Maintenance Rule Coordinator
indicated that Vogtle's maintenance rule program was designed and
implemented in accordance with Nuclear Utilities Management and
Resources Council (NUMARC) 93-01. Industry Guidance for Monitoring the
Effectiveness of Maintenance at Nuclear Power Plants. NRC Regulatory
Guide (RG) 1.160, Monitoring the Effectiveness of Maintenance at Nuclear
Power Plants, endorses NUMARC 93-01 as an acceptable method for
com)1ying with the provisions of 10 CFR 50.65. RG 1.160 states that the .
metlods described in the guide will be used to determine compliance with l
10 CFR 50.65, except in those cases when a licensee proposes an i
acceptable alternative method for complying with the regulations. In I
particular NUMARC 93-01 states that the development of an approach to l
assess the impact on overall plant safety functions upon removal of
'
structures, systems, or components (SSCs) from service consists of three
steps: (1) identify key plant safety functions to be maintained: (2)
identify SSCs that support key plant safety functions: and (3) consider
the overall effect of removing SSCs identified above from service on key
plant safety functions.
Vogtle's maintenance rule program was described in Procedure 00353-C.
Revision 2. Maintenance Rule Implementation. Section 3.5 of 00353-C
indicated that the Manager of Outages and Planning was responsible for
assessing the effects on the performance of the plant when performing
elective maintenance activities on safety-related or risk significant
systems. Section 4.5 of 00353-C, Removal of Equipment for Service,
described Vogtle's program for meeting the requirements of the overall
plant safety assessment portion of (a)(3) of the maintenance rule. This
descri) tion simply stated that use of existing programs such as the 28
day scledule. Plan of the Day meetings, and fragnets are methods for
accomplishing this assessment. The procedure did not incorporate any of
i the aforementioned guidance as prescribed by NUMARC 93-01.
l Additionally, the inspectors conducted interviews with the )lant
I personnel who were assigned the responsibility to conduct t1e
Enclosure 2
l
l
_ _ _
.
.
14
assessments required by Vogtle administrative procedure 00353-C as well
as other key plant operations personnel. It was determined that none of
the individuals who were interviewed had a familiarity with the guidance
contained in the NUMARC guidelines. Furthermore, it was unclear as to
how the licensee considered the impact on overall plant safety for
emergent work resulting from unscheduled or corrective maintenance.
This process was not described by procedure, although the Manager
Outages and Planning indicated that the probability risk assessment
department was contacted when the plant was in an " odd configuration"
meaning that more than one significant system was out of service at a
given time or when established unavailability goals for a given system
were exceeded.
The maintenance rule states that the assessments should be performed
prior to all maintenance activities (including equipment monitoring) and
hould take into account a consideration of the total plant equipment
which is out of service. The licensee had a plant philosophy which was
documented in the form of Management Standard No. 18. Standard for
Removal of Safety Related or Risk Significant Systems from Service,
dated January 29. 1995. This standard governed the conduct of elective
naintenance on safety related and " risk significant" equipment as
defined by the licensee's maintenance rule program. The licensee's
established policy was to conduct major maintenance on only one safety
related/ risk significant system at a time. Additionally, the philosophy
was to minimize the actual out of service time for the affected
equipment. However. the inspectors noted that this management standard
was limited to only safety related or risk significant equipment
Additionally, the management standard was focused primarily on those
activities involving major maintenance rather than using a broad
interpretation of other maintenance activities such as surveillances and
monitoring as specified in the NUMARC 93-01 guidance. Further, the
standard did not contain meaningful guidance as to what specific methods
or considerations should be employed in assessing the impact of the out
of service equipment other than ensuring that the total out of service
time for the affected equipment did not exceed the established
maintenance rule goals
The inspectors attended the licensee's daily )lanning meeting to observe
the assessments associated with the daily wor ( activities which had been
scheduled. During the particular meeting which was witnessed, there was
no significant maintenance either scheduled or ongoing. However, the
ins)ectors did not observe any systematic, formal or overt safety or
rist assessment in progress. The licensee indicated that the personnel
involved in the planning and scheduling process implicitly used
risk / safety assessment as a matter of due course in the conduct of their
responsibilities. Further, a heavy reliance was placed on systems
knowledge and operational experience. Thus, the licensee asserted, the
assessments were considered to be an integral and implicit part of the
meeting rather than a separate topic of discussion. Consequently, the
licensee did not generate or maintain the records of any specific
Enclosure 2
_ _ _ _ . . . _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _.. _ _ _ . _ _ _ _ _
,
'
j
i
-
.
- . ,
15 !
i ~
assessment activities which may have been performed during the planning i
meetings. The inspectors also noted that the plant staff did not appear
- to be making routine use of any information or insights (other than the
} total maintenance unavailability data for major safety related/ risk-
- significant systems) which might have been gained by the licensee's -
i individual plant evaluation. The inspectors acknowledged that a current
equipment out-of-service / degraded daily report is discussed during the ,
,
daily operations morning meeting and a copy is kept in the control room.
-
However, this information was not observed to be used in a formal,
j systematic risk assessment.
1
i The inspectors noted that the licensee's proposed method of risk ,
! assessment during shutdown and outage configurations was to use the !
i Outage Risk Assessment Management (ORAM) methodology. Although the i
i inspectors did not specifically review any ORAM models or assessments.
. the a)proach which was described appeared to be consistent with that
j, used ay similar facilities for outage risk management.
i c. Conclusions i
5 .
.
-
.i
j The lack of a detailed procedure and appropriate training for key -
-
personnel in the guidance and methods 3rescribed by NUMARC 93-01 was
I considered to be a weakness. This lacc of formal guidance and training, !
I and a heavy reliance on normal plant scheduling meetings resulted in a
- highly informal process. The licensee's program did not provide for the ;
i specific identification of undesirable plant configurations or any. ;
i decision thresholds or criteria which could be used by the key plant l
l personnel involved in the assessment process. The observed process was :
not systematic, and the lack of specific guidance and documentation of
'
i
assessments made it difficult to ascertain whether the assessments which i
were conducted would be reproducible and consistent. There was no !
discernible documentation or feedback mechanism which would allow plant
management or the quality assurance organization to conduct meaningful
audits of the assessment process to verify compliance with the
regulation and to facilitate any improvements which might be
appropriate. ;
!
The lack of guidance or methods to incorporate assessments associated ,
with emergent maintenance was also considered to be a weakness. Since .
emergent maintenance is by definition unexpected, the overall assessment
process must be flexible enough so as to determine the new level of l
plant risk which results when emergent m-intenance is necessary. Once j
the new level of risk has been assess _.. then appropriate recovery or ;
contingency actions can be evaluated, i
The licensee's focus on only major maintenance activities associated l
with safety related/ risk significant equipment was also considered to be
~
a weakness. The inspectors acknowledged that while the scheduling
philosophy appeared to be conservative, the potential impact of other I
less significant maintenance and surveillance activities being performed
Enclosure 2
...
~. . -- . - - - .
.
.
16
on other equipment should also be emphasized. As noted earlier, the
maintenance rule addresses the impact of a broad range of maintenance
activities with respect to the total alant equipment out of service, not
just major maintenance associated wit 1 safety related equipment.
Although the inspectors did not identify any potentially risk
significant configurations at Vogtle, the inspectors could not conclude
that the licensee's program would be effective in preventing such
configurations from occurring in the future. Based on the findings, the
inspectors considered that the issue of whether or not adequate
assessments were being performed as prescribed by 10 CFR 50.65 and as
required by the licensee's maintenance rule program constituted an IFI
50-424.425/96-10-04. Adequacy of Licensee's Maintenance Rule
Evaluations.
The inspectors noted that the licensee management disagreed with the
conclusions drawn concerning weaknesses in the licensee's program. The
licensee acknowledged the inspectors' findings of fact regarding the
structure, content, and conduct of the program, however, the licensee
disagreed that these observations would provide the basis for a
conclusion that weaknesses existed in the program.
M8 Miscellaneous Maintenance Issues (92902)
M8.1 (Closed) Licensee Event Reoort (LER) 50-424/96-009: Leaking Valve
Results In Fuel Handling Building Isolation
This event was discussed in Inspection Report 50-424.425/96-09,
paragraph 01.3. The licensee determined that two valves in the sampling
system leaked. thereby allowing the two PASS system relief valves tr
lift behind the PASS panel. As corrective action, the licensee replaced
the suspect leaking valves as well as the relief valves. The inspectors
verified the corrective actions and concluded that they were
appropriate. No additional issues were revealed by the LER. This LER
1s closed.
III. Enaineerina
E2 Engineering Support of Facilities and Equipment
E2.1 Main Steam Relief Valve Testina
a. Insoection Scooe (37551)
The inspectors observed portions of Unit 2 main steam relief valve
setpoint testing and adjustment conducted on September 5, 1996. This
included a review of the contractor's Procedure TT-96008. 0A-4 Trevitest
Procedure: Procedure 28210. Main Steamline Code Safety Valve Setpoint
Maintenance: Technical Manual I-1137, Installation. Operation and
Enclosure 2
_ _ . _ _ _ _ _ _ _ _ _ _ _ _ . . _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _
i
-
.
. .
17
Maintenance for Self-Actuated Safety Valves; and the licensee's ,
Bolting / Torquing Manual.
b. Observations and Findinas
The overall evolution was well coordinated. Particularly noteworthy was
the detailed pre-evolution brief conducted by the performance team. The
inspectors also observed appropriate communications between the main
steam valve room and the control room. ,
However, during the testing the inspectors noted that the contractors
performed steps not contained in their plant approved procedure.
Specifically, the inspectors noted that the installation and placement -
of the test device was more involved than specified in the vendor's
_ procedure. Additionally. the locknut was tightened using'a nut wrench
impacted by a hammer, a technique not discussed in the vendor procedure.
The inspectors were subsequently provided information that the_ observed
practices were consistent with the vendor's standard practices,
c. Conclusions
i
The inspectors concluded that the observed practices did not impact the
setpoint of the valves.
E2.2 Pressurizer Code Safety Testina I
a. Insoection Scooe (37551) !
The inspectors reviewed the results of pressurizer code testing due to a
four-hour notification the licensee issued on September 25, 1996.
! b. Observations and Findinas
On Seatember 22. during the 2R5 pressurizer code safety valve testing. !
l all t1ree valves. 2-PSV-8010A. B. and C. failed to lift within the TS
'
limits of 2485 psig (11%) on their initial lifts. 0f the three valves.
2-PSV-8010C lifted approximately 3.2% above the setpoint, at
approximately 3565 psig. Due to the magnitude of the failed lift, a
four-hour notification was made pursuant to 10 CFR 50.72 (b)(2)(i)
requirements based on the licensee's belief that 2-PSV-8010C represented
a potential unanalyzed condition that would significantly impact plant
safety. Although results indicated that 2-PSV-8010A'and 2-PSV-8010B
tested outside the TS lift criteria of 2485 psig 11% the licensee
determined that the two valves did not represent a condition that would
significantly compromise plant safety.
}
As a result of the failed lift tests, the licensee replaced the bellows
- and spindle on 2-PSV-8010C, and adjusted the lift pressure on 2-PSV-
! 8010A and 2-PSV 80108. Each valve was retested after their respective
- maintenance with successful results.
- Enclosure 2
,
r. - ,, , .r,- _
18
The licensee stated their intention to issue a LER on the Unit 2
3ressurizer code safety test results. The inspectors will review the
_ER when issued.
E2.3 Modification To Enhance Valve Reliability
a. Insoection Scooe (62707)
The inspectors reviewed implementation of DCP 94-VAN 0033. Borg Warner
Electric / Hydraulic Valve Modification. The inspectors reviewed the DCP.
implementing MW0s for Unit 2 valves, and witnessed a portion of the DCP
implementation on one valve.
b. Observations and Findinos
The DCP modified the orientation of the servo-motor and hydraulic pump
for several valves in the essential chill water and nuclear service
cooling water systems. Additionally, an indication of hydraulic fluid
reservoir level for the valves is also provided by the DCP.
The inspectors noted that the DCP package and associated work
instructions were adequate. Further, these instructions were at the
work site observed by the ins)ectors and were in use. The work observed
by the inspectors was thorougl with ap3ropriate attention to detail on ,
the part of the technician. The post-)CP testing appeared appropriate.
'
E8 Miscellaneous Engineering Issues (92903)
EA 93-304 01012: Inaccurate DG Start Counts Reported in April 9.
1990 Restart Briefing and Corrective Action
Letter (CAL) Response Letter.
EA 93-304 01022: Inaccurate DG Start Counts Reported in April 19.
1990 LER.
EA 93-304 01032: Inaccurate and Incomplete Information Reported
in June 29. 1990 LER Revision.
EA 93-304 01042: Inaccurate and Incomplete Information Reported
in August 30, 1990 Letter.
.
These violations were issued in correspondence to GPC from the NRC dated
May 9. 1990. Subject: Notice of Violation and Proposed Imposition of
Civil Penalties - $200.000, and Demands for Information. Additional
correspondence was sent to GPC relative to these violations on August
19, 1994 and February 13, 1995. GPC responded to these violations in
correspondence dated May 27, 1994: July 31, 1994: August 17, 1994, and
March 1. 1995.
NRC inspectors have reviewed the licensee's corrective actions
associated with these violations. In addition, inspectors have
frequently monitored activities at Vogtle to determine if the corrective
actions have been effective. These reviews and monitoring activities
Enclosure 2
_ _ _ _ _ _ _ _ _ . _ _ _ _ _ . _ _ _ _.___ .
4
I
.
.
.
- 19
- have concluded that the actions taken have been sufficient to preclude
! events such as those that formed the basis for the Notices of Violation.
.
Based on these actions, your corrective actions for these violations
j appear to be effective and these violations are closed.
I E8.1 (Closed) IFI 50-424/95-06-04: Accelerated Boraflex Coupon Degradation ;
4
Unit 1 Spent Fuel Pool ,
After the fifth Unit 1 refueling outage, selected longterm and !
i accelerated exposure boraflex coupons were removed from the Unit'l SFP l
in accordance with Procedure 88020-C. Boraflex Surveillance Program "
Spent Fuel Pool. Subsequent laboratory analysis determined that the
- accelerated boraflex coupons had experienced excessive shrinkage that ,
! failed to meet the surveillance acceptance criteria for allowed
j dimensional changes (i.e., no greater than 2.0% change from original -
1 dimensions). DC 1-95-018 was written on March 3. 1995, to document this
j problem. The longterm coupons had also experienced some shrinkage. l
- Although this shrinkage was within the surveillance acceptance criteria.
! the licensee became. concerned that the Unit 1 criticality analyses did
l not explicitly allow boraflex shrinkage. DC 1-95-041 was written on May
i 23. 1995, to document this. additional concern. In order to address i
these problems, the site issued request for engineering assistance (REA)
95-V1A614 to recuest engineering support regarding reportability, being .
in an unanalyzec condition, and the prospects for continued use of the ;
Unit 1 SFP with degrading boraflex.
,
i By letter dated June 20, 1995, the corporate office responded to the REA i
i concluding that the current degraded condition was not reportable - an i
j unanalyzed condition existed, but based upon an additional criticality
- evaluation this condition did not significantly compromise plant
- safety. The REA response also provided specific recommendations
'
regarding fuel management restrictions for the Unit 1 SFP. which
3
included prohibiting the storage of new fuel in the Unit 1 SFP.
- Furthermore, a Boraflex Task Force was formed to address the longterm
i degradation of boraflex and consider revising the SFP rack criticality 1
analyses. On October 23, 1995. DC 2-95-185 was written to document that
the results from the analysis of Unit 2 accelerated and longterm
boraflex coupons indicated shrinkage at, and slightly exceeding, the
surveillance program acceptance criteria and 2.0% shrinkage limit
assumed in the Unit 2 criticality safety analyses submitted to the NRC
by letter dated August 12. 1988. To address the expanded scope of
boraflex degradation. VEGP letter LCV-0686 dated November 8.1995.
established administrative controls for fuel management in the Unit 1
and 2 SFPs to ensure the conclusions of current criticality analyses i
remained valid until new analyses were conducted. These administrative
controls were evaluated pursuant to 10 CFR 50.59. approved by the PRB as
licensing document change recuest (LDCR) FS95-073 on January 3.1996. !
and incorporated into the Upcated Final Safety Analysis Report (UFSAR)
as a revision to section 4.3.2.6.a. The November 8. 1995 letter also
reconfirmed the expanded problem of Unit 1 and 2 boraflex degradation in
Enclosure 2
- .- - -. . - . . - - . . - - - - - - - . . - - - . - . - . - - .
3 .
- 20 l'
i excess of acce) table limits was not reportable. Furthermore. it
i acknowledged tlat the administrative controls were only temporary since
they were based upon predictive assumations regarding the deteriorating
- conditions of boraflex in the SFP raccs. Due to the uncertainties ar.d
, difficulty in predicting the behavior of degrading boraflex, the
- licensee commenced a reanalysis of the Unit 1 and 2 SFPs to eliminate
'
the dependence upon boraflex. Upon completion of this reanalysis and
NRC. approval, the temporary fuel management restrictions of UFSAR '
, 4.3.2.6.a could be lifted.
>
After the sixth Unit 1 refueling outage. DC 1-96-312 was written on July l
3 10. 1996, to document the increasing degradation of the accelerated and i
longterm boraflex coupons all of which failed the surveillance
'
acceptance criteria for dimensional changes due to shrinkage. !he ;
accelerated coupons also failed to meet their surveillance acceptance i
criteria for change in specific gravity (i.e.. no greater than 10%). !
But all coupons continued to meet the acceptance criteria for hardness '
and neutron attenuation. The effects of continued, increasing boraflex j
degradation was addressed by VEGP letter LCV-0854 dated July 30, 1996. !
This letter concluded that even with the increased boraflex degradation. ;
and assuming no soluble boron in the SFP cooling water, the
subcriticality margin requirements of TS 5.6.1.1. and original design
basis (i .e. . Keff less than 0.95) were still met. Furthermore, the
degrading boraflex condition was not safety significant because the
level of soluble boron (typical concentration about 2000 ppm) maintained
in the SFP assured subcriticality well below-TS and design basis ;
requirements regardless of boraflex.
Each of the aforementioned documents letters. DCs. UFSAR revision.
surveillance procedure, and coupon analysis results were reviewed by the
inspector and discussed with the responsible site reactor engineer. Two
conference calls were also held on August 28 and 29. 1996. with the site i
reactor engineer, corporate Nuclear Fuel engineers, and NRC inspector to j
discuss the ongoing degradation and current design requirements of
boraflex in the Unit 1 and 2 SFP racks, effectiveness of the boraflex
surveillance program, interim compensatory measures and longterm i
corrective actions. 1
The administrative controls of UFSAR 4.3.2.6.a for Unit 1 and 2 SFP fuel
management were incorporated into plant procedure 93641-C. Development
And Implementation Of The Fuel Shuffle Sequence Plan. Revision 6. dated
January 23, 1996. This procedure was reviewed by the inspector and
verified to be consistent with the revised UFSAR. These administrative
controls restricted the placement of any fuel assembly with less than
17100 MWD /MTU to only those Unit 2 SFP rack locations that had not
previously contained an irradiated fuel assembly. One exception being.
that independent of burnup a single assembly may be placed in the center
of a 3X3 array of empty SFP rack locations for the purpose of fuel
inspection and repair. VEGP letter ELV-05885 letter dated January 31,
1996. established the Unit 2 SFP rack locations that were suitable
Enclosure 2
.
21
(i.e., unirradiated) for storing new or low burnup fuel based on
historical Unit 2 fuel shuffle sheets provided by reactor engineering.
The inspector reviewed this letter, which included a marked up Unit 2
SFP map showing irradiated and unirradiated rack locations. On August
26 and 29.1996, the inspector toured the Unit 1 and 2 SFPs and verified :
that the new fuel assemblies for the upcoming Unit 2. refueling outage !
were stored in designated, unirradiated rack locations. Furthermore, !
the inspector noticed that the new fuel assemblies in the Unit 2 SFP and '
spent fuel assemblies in the Unit 1 SFP were stored in a checkerboard
fashion. This was a further conservative measure taken by the licensee. *
U)on completion of this inspection followup, the inspector concluded !
tlat the licensee was complying with the provisions of its boraflex !'
surveillance program. Also, the current interim compensatory measures
developed to mitigate the ongoing degradation of boraflex were well
thought out, conservative.in nature, and supported by sound engineering
judgement and evaluations. These compensatory measures were evaluated
pursuant to 10 CFR 50.59, incorporated into the updated UFSAR and plant
procedures, and implemented accordingly. Furthermore, the actual safety
implications associated with continuing boraflex deterioration were
insignificant based upon the established fuel management compenatory
measures and the concentration of soluble boron maintained in the SFPs.
However, during this inspection the following comments and/or concerns
were discussed with responsible licensee engineers and plant management:
I
e The unirradiated Unit 2 SFP rack locations deemed acceptable for .
storage of new fuel were not specifically identified by an l
approved plant procedure (e.g., procedure 93641-C).
e Although, the descriptive portion of the 10 CFR 50.59 safety ,
evaluutlor dated November 9. 1995 (included as 3 art of LDCR FS95- :
073) was suitably comprehensive and detailed, tie Section B.
Safety Evaluation did not adequately address all the questions
related to 10 CFR 50.59(a)(2). There was insufficient detail or
information in Section B. to address the consequences and/or
probability of a loss of subcriticality from the malfunctioling
(i.e., deteriorating) boraflex in the SFP racks to determir.e an
unreviewed safety question did not exist.
e The present rate of boraflex deterioration could most likely
exceed the bounding limits of acceptable shrinkage established by
the July 30, 1996 letter. This letter concluded that TS and i
design basis requirements of Keff less than 0.95 were met, in the
past, based on certain estimated shrinkage limits. Exceeding
these limits would once again place the SFPs in an unanalyzed
condition.
e Certain surveillance program implementation issues associated with
boraflex coupon sampling methodology were identified (e.g.. no
samples have been taken from the Unit 2 control coupons to assess
Enclosure 2
-
--.- - - . - .
_ . _ _ - _.- __ _ _ _ _ _ . _ _ _ . _ . . . _ _ _ _ _ _ _ . _ _ _ _ . _ . ._
c
'
,.
22
l
deterioration due to dissolution versus radiation; accelerated
erosion induced deterioration of Unit 1 coupons due to SFP cooling
flow) .
i e The SFP rack boraflex shrinkage in excess of the design
'
assumptions stated in the Unit 2 criticality safety analyses
! submitted to the NRC by letter dated August 12, 1988, could have
been reported pursuant to 10 CFR 50.73(a)(2)(ii)(B) as a
'
" condition that was outside the design basis of the plant."
t
'
Generic Letter (GL) 96-04 Boraflex Degradation In Spent Fuel Pool
Storage Racks was issued June 26, 1996, with a response due from
licensee's 120 days from the issue date. The comments and or concerns
l listed above were subsequently identified to the licensee (by the
resident inspector) on October 23, 1996, as unresolved item (URI) 5')-
'
'
424.425/96-10-06. Spent Fuel Pool Boraflex Concerns, pending receipt and
i
review of the licensee's response to GL 96-04. ,
Based on this review the IFI is closed. <
, ,
IV. Plant Suooort .
S3 Security and Safeguards Procedures and Documentation
S3.1 Desianated Vehicle Unsecured Inside the Protected Area
! i
a. Insoection Scooe (71750)
The inspectors reviewed the circumstances surrounding the licensee's
identification of a designated vehicle not properly secured inside the
protected area on August 26, 1995. In res)onse to tnis issue, the l
inspectors reviewed the Physical Security 31an, applicable security '
procedures, vehicle records, and the statement of the individual
responsible for leaving the vehicle unattended. The inspectors
interviewed the involved officer the security manager, and licensee
management as to their review of this event.
, b. Observations and Findinas
At approximately 3:02 p.m. on August 26, 1996, the licensee's security l
patrol identified an unattended designated vehicle, a tractor, in the '
protected area with the keys in the ignition. The driver was located,
the vehicle physically removed from the protected area, and the '
1
designated vehicle status rescinded.
,
From interviews and security statements, the inspectors determined that
-
this incident was the result of an inadvertent error on the part of a
contractor. From discussion with the involved officer, the inspectors
learned that the individual stated to the officer that he was aware of
- Enclosure 2 l
4
_ . - , - - , . .
-
- . - _.
._. _ _ _ . . _ _ . _ _ _ . . . . _ _ _ . _ _ . _ _ . _ _ . . _ _ _ _ _
e
e
-
23 :
the requirement to remove the keys from the vehicle but forgot to do so :
'
, when he exited the vehicle.
I
- '
c. Conclusions
Failure to remove keys from an unattended designated vehicle in the !
3rotected area is contrary to the requirements of procedure 00653-C. ,
3rotected Area Entry / Exit Control. This was identified as a VIO 50- !
i 424.425/96-10-05. Designated Vehicle Left Unattended Inside the
!
Protected Area.
-l
!
V. Manaaement Meetinas
X1 Exit Meeting Summary
The inspectors ) resented the inspection results to members of licensee
management at t1e conclusion of the inspection on October 4.1996. 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.
,
J. Beasley. Nuclear Plant General Manager
l P. Rushton, Plant Support Assistant General Manager
J. Gasser. Plant Operations Assistant General Manager
'
S. Chestnut. Manager Operations
l
'
K. Holmes. Manager Maintenance
M. Sheibani. Nuclear Safety and Compliance Supervisor 1
i E. Kozinsky. Planning & Control Supervisor
G. Hooper. Engineering Group Supervisor
D. Minyard. Engineer Senior
C. Tippins, Jr., Nuclear Specialist I
.
l
S. Kitchens. Nuclear Support General Manager j
J. Bailey Manager of Licensing ;
, A. Farruk. Probabilistic Risk Assessment Supervisor
K. Powers. Engineer Senior
!
l
l
Enclosure 2 l
l
l
!
, . . . , - . .-.
_ __ _ _. _ _ . . _ _ _ _ _ - _ . _ _ . _ . - . _ _ _ _ _ _ _ _ _ _ . . _ . . _ .
,
.
.
.
24
l
l INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering -
l
IP 40500: Effectiveness of Licensee Controls In Identifying. Resolving, and
Preventing Problems :
IP 60710: Refueling Activities '
IP 61726: Surveillance Observations
IP 62707: Maintenance Observations
IP 71707: Plant Operations
IP 71750: Plant Support Activities .
'
IP 92700: Onsite Notification of Written Reports of Non-routine Events At '
Power Reactor Facilities
IP 92902: Followup - Maintenance '
IP 92903: Followup - Engineering .
!
ITEMS OPENED, CLOSED, AND DISCUSSED
Ooened
50-424/96-10-02 VIO Unit 1 Post Accident Sampling System Valve
Mispositioned (Section 02.2)
- 50-424,425/96-10-04 IFI Adequacy of Licensee's Maintenance Rule
'
Evaluations (Section M3.1)
50-424.425/96-10-05 VIO Designated Vehicle Left Unattended Inside the
!
Protected Area (Section S3.1)
50-424.425/96-10-06 URI Spent Fuel Pool Boraflex Concerns (Section E8.1)
Closed
50-425/96-10-01 NCV PRT Draindown Procedure Not Properly Implemented
(Section 01.4)
50-425/95-11-01 VIO Loss of Containment Integrity During Refueling
(Section 08.1)
50-425/96-10-03 NCV Inadequate Procedure For Westinghouse Type KF
Underfrequency Relay Calibration (Section M1.4)
EA 93-304 01012 VIO Inaccurate DG Start Counts Reported in April 9.
1990 Restart Briefing and CAL Response Letter
(Section E8)
EA 93-304 01022 VIO Inaccurate DG Start Counts Reported in April 19,
1990 LER (Section E8)
EA 93-304 01032 VIO Inaccurate and Incomplete Information Reported
in June 29, 1990 LER Revision (Section E8)
i
'
EA 93-304 01042 VIO Inaccurate and Incomplete Information Reported
in August 30, 1990 Letter (Section E8)
50-424/96-009 LER Leaking Valve Results In Fuel Handling Building
Isolation (Section M8.1)
50-424/95-06-04 IFI Accelerated Boraflex Coupon Degradation Unit 1
, Spent Fuel Pool (Section E8.1)
Enclosure 2
l
l
, - - __
- . -- , - -
.
.
25
LIST OF ACRONYMS USED
X. List of Acronyms Used
CFR - Code of Federal Regulations i
DC - Deficiency Card ,
DCP - Design Change Package
DG - Diesel Generator
GL - Generic Letter
GPC - Georgia Power Company
I&C - Instrumentation and Controls
IFI - Inspector Followup Item
ISEG - Independent Safety Engineering Group
LDCR - Licensing Document Change Request '
LER - Licensee Event Report
MDAFW - Motor Driven Auxiliary Feedwater
MWD - Megawatt Days
MWD - Maintenance Work Order
NCV - Non-Cited Violation
NPF - Nuclear Power Facility
NPMIS - Nuclear Plant Management Information System *
NRC - Nuclear Regulatory Commission
NRR - Nuclear Reactor Regulation ,
NUREG - Nuclear Regulations
NUMARC - Nuclear Utilities Management and Resources Council
ORAM - Outage Risk Assessment Management
PASS - Post Accident Sampling System '
PDR - Public Document Room
PRT - Pressurizer Relief Tank .
PRB - Plant Review Board
psig - Pounds Per Square Inch Gauge
0A - Quality Assurance
RCCA - Root Cause and Corrective Action
RCS - Reactor Coolant System <
REA - Request for Engineering Assistance l
RG - Regulatory Guide 1
RHR - Residual Heat Removal System ,
SFP - Spent Fuel Pool l
SSC - Structur'e, System, or Component i
TS - Technical Specifications
UFSAR - Updated Final Safety Analysis Report ,
VEGP - Vogtle Electric Generating Plant i
VIO - Violation
2R5 - Unit 2 Fifth Refueling Outage
i
l
Enclosure 2
!
l
l
_