ML20135C408
| ML20135C408 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 11/16/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20135C400 | List: |
| References | |
| 50-334-96-08, 50-334-96-8, 50-412-96-08, 50-412-96-8, NUDOCS 9612060297 | |
| Download: ML20135C408 (29) | |
See also: IR 05000334/1996008
Text
.- ._. .- - _ . - _ . _. . _ . - _ - . . ._. .-. . _. - _ _ - .
-
,
.
,
l
U. S. NUCLEAR REGULATORY COMMISSION
1
REGION 1
i
.
l Report Nos. 50-334/96-08,50-412/96 08
j
i
Docket Nos. 50-334, 50-412 I
i
h
"
Licensee: Duquesne Light Company (DLC)
Post Office Box 4 l
4
Shippingport, PA 15077
Facility: Beaver Valley Power Station, Units 1 and 2
,
i
'
$. Inspection Period: September 29,1996 through November 16,1996
Inspectors: D. Kern, Senior Resident inspector
] F. Lyon, Resident inspector
.
G. Dentel, Resident inspector
Approved by: P. Eselgroth, Chief
. Reactor Projects Branch 7
,
t
6
.
d
4
i
.
P.
- -. _ _ . , - - . - -- -_ _ _ _ - - .
.
.
EXECUTIVE SUMMARY i
Beaver Valley Power Station, Units 1 & 2
NRC Inspection Report 50-334/96-08 & 50-412/96-08
This integrated inspection included aspects of licensee operations, engineering,
maintenance, and plant support. The report covers a 7-week period of resident inspection.
Ooerations
e Two separate instances of failure to adhere to operations shift rules of practice
resulted in actuation and isolation of CREBAPS cnd entry into TS 3.0.3. A
contributing problem is the susceptibility of CREBAPS to spurious actuations.
Corrective actions addressed the root cause and contributing causes (Section 04.1).
- A training supervisor found the lock for a steam admission valve to the Unit 1
turbine driven auxiliary feedwater pump, not properly locked. Licensee immediate
response included a thorough security review and immediate corrective action was
appropriate (Section 04.2).
- The Unit 1 non-regenerative heat exchanger temperature control valve failed to the
full open position which resulted in a reduced reactor coolant system boron
concentration. Operators identified the failure in an adequate time frame and ,
provided effective actions to mitigate the transient (Section 04.3). l
e Unit 1 operated with two pressurizer power operated relief valve block valves shut
for several years, contrary to the plant design. A 10 CFR 50.59 safety evaluation
was not performed to support this facility configuratior change. The incorrect valve
configuration was safety significant as it accounted for 27% of current core
damage frequency (3.85 E-5). The recent event history review performed by
licensing engineers was comprehensive and provided valuable insight with which to
focus corrective actions. Corrective action taken since the issue was identified in
September 1996 was comprehensive and, to date, properly implemented.
However, station personnel missed several opportunities between 1981 and 1996
to identify the incorrect valve lineup, assess the associated risk significance, and
correct the condition. Processes for communicating individual plant examination
risk insights to station personnel had been ineffective. Failure to properly evaluate
the configuration change and failure to identify and correct the discrepant condition
was an apparent violation (Section 08.1).
Maintenance l
e Cold weather preparations were completed in accordance with applicable
procedures. Lack of a focal point for this activity contributed to a large number of
outstanding cold weather MWRs and failure to complete work in a timely manner on
a control room deficiency (Section M1.2).
e Residual heat removal pump seal testing, pump movement, reinstallation, and post {
installation tests were performed in a safe manner (Section M1.3). )
ii I
l
l
l
_ _ _ . . _ _ _ _ . _ _ _ . _ _ _ _
_ m . _ - _ _ -. -- - - - - - - - - -
.
'
. i
!
.
e Electricians performed J-series relay replacements in a professional manner,
demonstrating excellent job knowledge and communications skills. Procurement,
engineering, and maintenance personnel worked effectively to replace effected J- ;
series relays in a timely manner and thereby restore safety system reliability
(Section M1.4).
Enaineerina
,
o The engineering response to erratic H-02 rod position indication was effective and
completed in a timely manner. The temporary modification provided control room ,
operators with accurate information and eliminated the unnecessary operator l
workload (Section E1.1). i
e Initial engineering evaluations of failed J-series relays were detailed, but too !
narrowly focused. The proposed solution failed to fully recognize vulnerability to !
control power failure. The multi-tiered management review was a strength and
directly resulted in identification of the potentially generic failure and enhanced plant
safety through the replacement of over 200 J-series relays. The licensing
'
department's recommendation to reevaluate NRC IN 92-27 applicability
demonstrated an appropriate desire to learn from industry events. An event case
study was effectively developed and communicated within the engineering
department. Case study seminars were an excellent tool to enhance problem l
solving techniques and reenforce appropriate safety standards (Section E1.2).
e increased Unit 1 containment sump pump down rate was properly evaluated and r
the basis for continued operation was technically sound (Section E2.1). i
1
e Failure to assess expected service life for the RHS pump seals, whose performance
could not be monitored to predict failure, we.s a weakness. Corrective actions were
appropriate and productive in assessing other components for replacement PMs.
Difficulty in assembling licensing bases documentation delayed the decision
regarding whether or not to off-load fuel from the reactor vessel to perform the seal
repair. The licensee performed an indepth safety assessment to support the
decisions regarding the RHS pump seal repair. Management's decision to extend
the outage and repair the pump seals now, rather than risking complete seal failure
during the next plant shutdown, demonstrated a strong safety perspective (Section
E2.2).
e Engineers identified a long standing Unit 2 design deficiency involving the steam
generator water level control system and the protection system. The apparent
cr.use was inac' equate engineering evaluation of a TS amendment in 1990. The
inspectors noted strong engineering support and management influence resulted in
effective immed: ate corrective actions that addressed the apparent cause and the
deficiency (Section E8.1).
iii
.
- - - - -- " -- -
- . =._ = = =: - _ - - -
- - -- - -
.
.
Plant Supoort
e
General employee training provided satisfactory initial training to safely access the
Protected Area and the RCA. In addition, management expectations and worker
rights and responsibilities were clearly stated (Section R8.1).
Adherence to station standards for area housekeeping was poor. Station personnel
did not consistently understand the station's program for controlling transient
combustible material. Adequate actions were taken to address these issues >
(Section F1.11.
'
!
!
i
!
l ;
1
1
?
r
l
t
n
.
.
IV
l
l
- . .. . _ . __ - . _ .
.
!
.*
TABLE OF CONTENTS
Page
EX ECUTIV E S U M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii
TA 8 LE O F C O NTE NTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v ,
- i
>
l. Operations .................................................... 1
'
01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01.1 General Comments (71707) ........................... 1
02 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . 1 l
'
O2.1 Enaineered Safetv Feature System Walkdowns (71707) ....... 1 l
04 Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . 2 <
04.1 Inadvertent Actuation and Isolation of Control Room !
Emeroency Breathina Air Pressurization Svstem . . . . . . . . . . . . . 2
04.2 MS-16 Found imoronerly Locked ....................... 3
)
-
04.3 Temperature Control Valve Failed Open . . . . . . . . . . . . . . . . . . . 4
08 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 j
08.1 (Uodate) URI 50-334/96007-01 ........................ 5 !
l
l
11. M a i nt e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 '
M1 Conduct of Maintenance .................................. 7
.................................................... 7
M 1.1 Routine Surveillance Observations (61726) ................ 7
M 1.2 Cold Weather Preparations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
M1.3 Unit 2 RHS Pumo Seal Leak and Repair . . . . . . . . . . . . . . . . . . . 9
1
M1.4 J Series Relav Reolacements .......................... 9
M8 Miscellaneous Maintenance issues (62707 .................... 10
M8.1 Emeroency Diesel Generator Shutdown Circuit Modification ... 10
lll . Eng ine e ring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
El Conduct of Engineering .................................. 10
E1.1 H-02 Analoo Rod Position Indication (ARPI) Modification . . . . . . 10
E1.2 ITE/Gould J12 Relav Failures due to Thermal Aoina ......... 11
E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . 14
E2.2 Unit 2 Core Offload to Repair RHS Pumo Seals . . . . . . . . . . . . . 15
E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
E8.1 Steam Generator Water Level Control System and Protection
System Interaction ................................ 17
-
I V. Pl a nt S u p p o rt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
'
R8 Miscellaneous RP&C lssues ............................... 19
l
'
R8.1 Plant Access Trainina and Radiation Worker Trainino ........ 19 l
1
F1 Control of Fire Protection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . 19 '
F1.1 Plant Housekeepino and Control of Combustible Materials . . . . . 19
1
1 .
,
V
4
_ . _ __ .___.. .. _ _ . _ _ _ . . . _ _ _ _ _ . . . . _ . . _
.
.
,. _. . . _ _ ___ _ _ . _._._ _ _ _ . .._ _ . _ _ _
.
!
-
t
i
..
.
I
! !
V. Mananoment Meetinos . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
X1 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
X2 Management Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
i
~
'
,
ATTACHMENT .................................................. 22 '
- .
l
I
t
I
i !
t !
'
i
.
h
I
l
i
!
!
t
I
, 1
.
,
I
t
l !
l l
.
.
!
!
s
i h
l'
l
>
,
l
3
, i
l t
( l
.
t
!
i
[
i
1
i
i
f
J
T
l r
. :
I I
1
'
I
i
l
I
t
'
I
I
f
i
t
I
-
1
)
4 !
,' r
1 l
,
VI. ,
!
,
,i
y m y,-, w,e = ,-_g ---- w. m - . , - -
.
m c_. _ -
. _ . _ _ . . - . _ _. _ _ __ ~._ ___ _ _ _ _ _. _ _ _._-
.
.
Report Details
Summary of Plant Status
Unit 1 operated at full power without incident this period.
Unit 2 began this inspection period in Mode 5 (cold shutdown) in the sixth refueling
outage. Two licensee identified problems significantly extended the outage work scope
following core reload. Thermally degraded J-series relays installed in numerous safety
related systems were replaced (Section E1.2). Excessive sealleakage on both residual
heat removal (RHS) pumps required seal replacement (Section E2.2). On October 18, the
plant was placed in Mode 6 (refueling) to defuel the reactor to establish safe conditions for
the RHS pump repair. At the end of the period, following repair of the RHS pumps,'a fuel
reload was in progress.
,
l. Operations
01 Conduct of Operations j
i
01.1 General Comments (71707)'
]:
Using inspection Procedure 71707, the inspe.: ors conducted frequent reviews of
ongoing plant operations. In general, the conduct of operations was professional
and safety-conscious; specific events and noteworthy observations are detailed in
the sections below.
O2 Operational Status of Facilities and Equipment
02.1 Enaineered Safety Feature System Walkdowns (71707) <
l
'
The inspectors walked down accessible portions of selected systems to assess
equipment operability, material condition, and housekeeping. Minor discrepancies
were brought to DLC staff's attention and corrected. Housekeeping discrepancies
are discussed in Section F1.1 No other substantive concerns were identified. The -
following systems were walked down:
- Unit 1 steam driven auxiliary feedwater pump ..
- Unit 2 emergency diesel generator fuel supply and air start systems
- Unit 2 component cooling water system
' Topical headings such a 01, M8, etc., are used in accordance with the NRC
standardized reactor inspection report outline. Individual reports are not expected to
address all outline topics.
- - . . . _ _ _
- - - - - - - - -'-
q
- I
'
.
1
'
04 Operator Knowledge and Performance
04.1 Inadvertent Actuation and Isolation of Control Room Emeroency Breathina Air
Pressurization System
a. Insoection Scone (71707)
l
i
On October 6,1996, Unit 2 control room operators inadvertently actuated the j
Control Room Emergency Breathing Air Pressurization System (CREBAPS).
CREBAPS provides pressurized air to the dual unit control room. Actions to mitigate
the consequences by Unit 1 operators resulted in isolation of the CREBAPS and
entry into Technical Specification (TS) 3.0.3. The inspectors reviewed this event 1
through discussions with the system engineer, control room operators, and )
operations management. The inspectors reviewed operational controls for
troubleshooting logs and examined procedures for operator response to inadvertent
actuation of CREBAPS. The following documents were also reviewed:
- Problem Report 2-96-610, " inadvertent CREBAPS Actuation"
l
Entry"
1/2 OM-44A.4A.B, " inadvertent CREBAPS Activation Recovery," Rev. 3
- 1/2OST-43.17C, " Control Room Area Monitor Functional Test," Rev.14
b. Observations and Findinas
On October 6,1996, while preparing to perform scheduled undervoltage trip circuit
tests for 480V Breaker 6B (MCC E9 feeder), electricians requested operational
support to develop a troubleshooting log which would preclude inadvertent
CREBAPS actuation. A troubleshooting log was developed based on 1/20ST-43-
17C and a CREBAPS actuation circuit breaker was deenergized to prevent actuation
due to radiation monitor spiking upon cycling of MCC E9. Operation Manual
Chapter (OM) 1/2.48.1D, Operations Shift Rules of Practice, Rev. 21, states that
normal precautions identified in the subject equipments operating chapter continue
to apply during troubleshooting activities. 1/2 OST-43-17C included a precaution
which states " . . . transfer switches and circuit breakers must be aligned as
directed in the test to prevent an inadvertent actuation of CREBAPS." Contrary to
the precaution, the transfer switch was not aligned as directed, which directly
caused an inadvertent actuation of CREBAPS. Based on discussions with
operations personnel, the inspectors concluded that additional activity in the control
room, absence of preplanning, and a minimal prebrief contributed to the failure to
identify the error.
Upon GEBAPS actuation, the Unit 1 Assistant Nuclear Shift Supervisor (ANSS)
called the operations break room and requested that a Unit 1 operator go to the
CREBAPS bottles and call the Unit 1 control room when in place for further
instructions. Two operators received the telephone call, each failed to repeat back
the ANSS instructions, and one operator incorrectly communicated to a third
operator to isolate CREBAPS. The failure to repeat back instructions is contrary to
OM 1/2.48.1D. This communications weakness resulted in isolation of CREBAPS
l
2
.
_ - . _ _ . _ _ _ __ . . . _ _ - _ _ _ . _ _ _ . _ _ _ _ _ _ _ _ .
5
.
. .
,
! l
t .- ;
- and entry into TS 3.0.3. The licensee properly reported the event pursuant to l'
50.73(a)(2)(i).
The licensee determined the cause of this event was failure to comply with site .
'
standards and policy with respect to self-checking, proper communication, and !
- -
adherence to approved procedures. A contributing cause was attributed to
susceptibility of inadvertent CREBAPS actuation due to control room radiation
l
!
j monitoring hardware spiking. The inspectors noted that this is the sixth inadvertent
actuation of CREBAPS in the past two years, j
- i
! Corrective actions to address the event included: ;
- Interview and counseling of each of the operations shift personnel involved
- in the incident;
- * Subsequent shift briefings discussed both problem reports; i
- An independent design review of CREBAPS with emphasis on system ,
,
actuation; !
- * Several technical evaluation reports and design changes to reduce CREBAPS ]
j susceptibility to inadvertent actuation; t
- A night order was issued prohibiting the use of the troubleshooting log for l
f' purposes other than documentation during the performance of approved !
procedures.
t i
j TS 6.8.1.1 requires written procedures be properly established and implemented for
- test activities of safety related equipment. Failure to properly implement OM j
j 1/2.48.1D was a violation of TS 6.8.1.1. The corrective actions addressed the i
- apparent cause and the contributing cause. This licensee-identified and corrected
t
violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1
'
of the NRC Enforcement Policy (50-334(412)/98008-01). l
'
!
c. Conclusion
)
i Two separate instances of failure to adhere to operations shift rules of practice
i resulted in actuation and isolation of CREBAPS and entry into TS 3.0.3. A
contributing problem is the susceptibility of CREBAPS to spurious actuations.
Corrective actions addressed the root cause and contributing causes.
4
'
04.2 MS-16 Found improoerly Locked
a. insoection Scooe (71707)
!
On November 1,1996, a training supervisor notified the Unit 1 control room that a
,
padlock on MS-16, one of three steam admission valves to the turbine driven
- auxiliary feedwater pump, was not properly locked. The Senior Reactor Operator
j (SRO) notified security and station management per Special Operating Order
4 1/2 95-1. Security personnel secured the area and posted security at vital target
! sets. The inspectors discussed with control operators the possible causes and
4
independently examined the lock.
!
- 3
1
.
f
-. , ,_ _ _ _ __ . . _ . . _
- - - - . . . - . - . . . - . _.=
_
.
- -.----.--_----.
. .
.
'
1 ,
i ;
b. Observations and Findinas
i
,
A training supervisor found the lock to MS-16 not properly locked. The hasp of the !
!
. lock was found in the down position and captured the chain, but the hasp was not
aligned with the hole in the body of the lock. Security determined the lock,
- although not properly locked, would prevent operation of the valve in its "as found"
! !
condition. The inspectors independently verified that the lock did secured the valve '
g. with the hasp slightly off center from the body of the lock. The valve was found in !
'
its correct locked open position. MS 16 was last operated on October 6,1996 i
l during quarterly surveillance testing. !
The lock was a new lock in response to a problem described in NRC IR No. 50-
i
~
334(4121/96005. The lock was a " key capture" lock which would not allow key i
removal without the lock hasp being in the locked down position. The operators !
! that performed the Operational Surveillance Test (OST) were unaware that the lock
I would allow the hasp to lock without alignment with the hole in the body. ,
! Corrective actions included discussing the event at shift briefings and performing !
j additional inspections of valves recently locked in OSTs. '
.
- i
! c. Conclusion !
!
The inspectors concluded that the lock in the "as found" condition prevented -
cperation of the valve. Licensee immediate response allowed a thorough security .
review and immediate corrective action was appropriate. The inspectors had no !
further questions. ,
,
04.3 Temoerature Control Valve Failed Open j
1
a. Insoection Scooe (71707) '
The inspectors reviewed operator response and the effect on plant operation [
following a charging system letdown temperature control valve failure. The
inspectors examined computer data on key parameters, corrective actions, and root l
.
cause evaluation. The licensee review of the event was documented in !
PR 1-96-857. I
b. Observations and Findinas
On October 22,1996, at 10:17 a.m., the Unit 1 non-regenerative heat exchanger (
temperature control valve failed to the full open position. The valve failure ,
increased cooling and decreased letdown temperature. At lower temperatures, the
letdown demineralizers reduced the boron concentration. This resulted in a dilution
of the Reactor Coolant System (RCS) and a slow heatup of the RCS. At 11:40
a.m., on October 22,1996, control room operators detected volume control tank
temperature had decreased from 96*F (recorded the previous shift log) to 80'F.
The operators found the non-regenerative heat exchanger temperature control valve
was full open and in auto. Operators took manual control of the valve and restored
normal letdown temperatures.
4
_. . - _ _ . _ _ _ _ . . _ _ _ _ . , _. _ . _ . _ . _ _ _ . . . . _ _ _ . _
.-
!
l .-
The root cause investigation identified a loose control cable connector to the
j controller. Instrumentation and Controls (l&C) technicians performed work.on the
l flow controller for the charging system (FCV-CH 122) on the October 22,1996,
l
'
and may have bumped the loose connector resulting in the valve failing open.
Immediate corrective actions was to tighten the loose control cable connector.
Other corrective actions were to increase the low temperature alarm on the non-
, regenerative heat exchanger letdown outlet domineralizer temperature to 85'F from
50'F and to review operations oversight of control board maintenance practices.
!
l The inspectors determined that reactor power (calorimetric) never exceeded 100%
- during the transient. Tave increased approximately 1.6*F. Operator action upon
'
discovery of the valve open was prompt and apprcpristc. Corrective actions
addressed the immediate cause and provided addition actions to assist operators in
- identifying this type of transient.
c. Conclusion
The failure of the temperature control valve was due to a loose connectJr.
{ Operators identified the failure in an adequate time frame and provided iffective
j actions to mitigate the transient. Corrective actions addressed the notec'
.
deficiencies,
i
08 Miscellaneous Operations issues
4
08.1 (Update) URI 50-334/96007-01: Unit 1 Pressurizer (PZR) Power Operated Relief
Valve (PORV) Block Valve Configuration Contrary to UFSAR.
a. inspection Scope (92901. 92903)
The normal switch alignment for Unit 1 PZR PORV block valves was not properly
restored following piping modifications completed in 1981. The Unit continued to
operate with two of three PZR PORV block valves shut for the past fifteen years,
after seismic and PORV leakage concerns were addressed, contrary to the UFSAR
specified configuration. This item was unresolved pending further inspector
evaluation to assess causal factors, extent of condition, safety significance, and
corrective action implementation.
'
b. Observations and Findinos
immediate corrective actions were appropriate as documented in NRC IR No. 50-
334(412)/96-07.1he inspectors questioned whether a 10 CFR 50.59 safety -
evaluation had been done t.o support the valve reclignment. Licensing engineers
conducted a PZR PORV block valve history review from 1979 to present to buer
understand contributing factors and associated risk significance. The inspectors
discussed the history review with the engineers and concluded that the review was
comprehensive and provided valuable insight with which to focus corrective actions.
The inspectors further determined that no safety evaluation had been performed to
support changing the normal PZR PORV block valve alignment in November 1980 or
afterward when seismic modifications and PORV leakage concerns were completely
5
--
_ -.
.
s
'
addressed. Safety evaluations were performed to evaluate the seismic structural
piping modifications, but these evaluations failed to recognize the valve
configuration change as a design change. Consequently the block valve
configuration change was not properly evaluated.
t
TS 3.4.11 permits continued reactor operation with up to three PZR PORV block
valves shut. Notwithstanding, the TS bases clearly state that the block valves are
.
i normally open and are used to isolate the PORVs in case of excessive PORV leakage
' or a stuck open PORV. The inspectors reviewed BVPS1 UFSAR 14.1.7 and
>
confirmed that no credit is given for the operation of any of the three PZR PORVs in
the design load reject accident analysis. This safety analysis bounded operation
- with two PZR PORV block valves shut. However, peak reactor pressure on this
j ' accident with two block valves shut had not been analyzed to assure the PORVs
i
' would function as described in UFSAR 4.2.2.7 to limit peak reactor pressure to a
.
value below the high pressure reactor trip setpoint. In addition, engineers
- determined in October 1996, that operation with the two block valves shut was risk
i
significant as reflected in the BVPS1 probabilistic risk assessment individual plant
[ examination (IPE).
.
!
In 1992, the original IPE submittal (revision O), documented that Anticipated
I
Transient Without Scram (ATWS) initiated events, with two block valves normally
i
shut (instead of open), were responsible for 15% of the total core damage risk
! (CDF). By 1995, the IPE was revised (revision 1) to take credit for several station
safety enhancements and more accurate modeling of actual station r%punent
j
performance characteristics. This update included actual PORV capacity which was
larger than assumed in the original IPE. This revision reduced total CDF f om 2.1E-4
,
event / reactor year to 1.20E-4 events / reactor year, in IPE revision 1, the incorrect
] PORV block valve configuration accounted for 5% of the total CDF.
i The current BVPS1 IPE (revision 2) indicates that safety improvements have further
!
reduced total CDF (with two block valves closed) to 3.85E-5. While reviewing the
- inspectors' concern regarding the current valve configuration, engineers determined
- that the incorrect block valve alignment accounted for 27% of the current CDF.
j The inspectors reviewed the IPE sensitivity analysis and agreed with the licensee
- assessment. Based on this observation and discussions with engineers and
{ operations personnel, the Hspectors concluded that processes for communicating
1 IPE insights to station personnel had been ineffective. Engineers informed the
, inspectors that processes to ensure plant design changes are reflected in the IPE
and to communicate IPE insights, had not yet been formalized.
,
j in 1995, license amendment No.187 was issued and approved in response to the i
licensees response to NRC Generic Letter 90-06 to improve PORV and PORV block !
3
valve reliability. The bases for the revised TS, as stated above, indicates that the
block valves are normally open. This represented another missed opportunity to
identify the incorrect PORV block valve alignment. The inspectors determined that
(
station personnel missed several opportunities between 1981 and 1996 to identify
the incorrect valve lineup, assess the associated risk significance, and correct the
condition.
6
--- - - - - .
'
' '
) f
,
1 .
?
Corrective actions taken since the issue was identified in September 1996 have !
i
been well thought out and properly implemented. A detailed safety evaluation was !
-
prepared which clearly assessed the safety significance and recommended restoring
! the original PZR PORV block valve configuration. Procedures were revised to reflect
l all three block valves normally open and operators were trained on this
configuration. The two block valves were restored to the open position on October
8,1996 resulting in a 27% CDF reduction (New CDF is 2.79E-5 events / reactor !
l year). Management directed that an extent of condition review be perform >d to !
l determine whether other SSCs were modified and not restored following completion I
-
of IE Bulletin 79-14 actions. No additional unplanned modifications were identified !
4
through this review. Several previously licensed personnel were assigned to
! perform a six week reviety of station procedures to evaluate consistency with the
i UFSAR. This effort has been effective in identifying discrepancies which are being
[ properly assessed through the problem report system.
!
c. Conclusions
! Unit 1 operated with two PZR PORV block valves shut, contrary to the UFSAR and
j the TS bases, for over fifteen years. Due to personnel errors, a 10 CFR 50.59
- safety evaluation was not performed prior to changing the facility from that
'
described in the UFSAR license condition. As a result, the reactor plant
configuration differed from that described in the UFSAR for an extended period.
4
The UFSAR was not updated to reflect the long standing facility design change as
l required by 10 CFR 50.71(e),
t
!
The incorrect valve configuration was safety significant as it accounted for 27% of
i
current CDF (3.85 E-5). The recent event history review performed by licensing
j engineers comprehensive and provided valuable insight with which to focus
, corrective actions. Corrective action taken since the issue was identified in
l- September 1996 was comprehensive and, to date, properly implemented.
, However, station parsonnel missed several opportunities between 1981 and 1996
to identify the incorrect valve lineup, assess the associated risk significance, and
! correct the condition. The inspectors determined that processes for communicating
, IPE insights to station personnel had been ineffective 10 CFR 50, Appendix B,
l Criterion XVI requires that measures be established to assure conditions adverse to
quality are promptly identified and corrected. The licensee failed to properly
evaluate the Unit 1 reactor pressure control system configuration change. The -
inspectors concluded that failure to identify and correct this long standing
discrepant condition was safety significant and was an apparent violation of 10 CFR
50, Appendix B, Criterion XVI. .
11. Maintenance
M1 Conduct of Maintenance !
l
M1.1 Routine Surveillance Observations (617261
The inspectors observed selected surveillance tests. Operational surveillance tests
(OSTs) reviewed and observed by the inspectors are listed below.
7
_
__ __ _ _. _ __
- 2 OST-36.1, " Emergency Diesel Generator [2EGS*EG2-1] Monthly Test," Rev.17
- 1 OST-07.01, " Boric Acid Transfer Pump [1CH-P-2A] Operational Test," Rev. 3
- 1 OST-01.11, " Safeguards Protection System Train A Test," Rev. 8
- * 1 OST-11.01, " Safety injection Pump Test [1SI-P-1 A)," Rev. 6
4
The surveillance testing was performed safely and in accordance with proper
procedures. Additional observations regarding surveillance testing are discussed in
.,
the following sections. The inspectors noted that an appropriate level of
supervisory attention was given to the testing.
M1.2 Cold Weather Precerations
a. Inspection Scooe (61726)
,
+
The inspectors reviewed the cold weather preparations for Beaver Valley Unit 2.
The inspectors conducted walkdowns of heat trace systems, examined outstanding
maintenance work requests (MWRs) for the heat trace system, and questioned
maintenance and operations personnel on the systems. The following procedures
were reviewed:
! * 2 OST-45.11(ISS1), " Cold Weather Protection Verification," Rev. 8
+
3 2 PMP-45-SRM-HEATTRACE-B-11, " Train B RWST Heat Tracing Control
System Component Calibration," Rev. 3
+
2 PMP-45-HEAT-TRACE 1E, " Heat Trace Circuitry Operability Checks," Rev.
3
,
J b. Observations and Findinas
4
q Instrumentation and controls techniciana performed yearly calibration of the two
safety related heat trace panels. Electrical maintenance performed heat trace
circuitry operability checks which verified proper current supplied to each individual
- heat trace circuit on the safety related panels. Calibrations are not regularly
performed on the electric unit heaters; instead the plant relies on operational tours
of the areas to identify possible problems. Non-safety related heat trace circuits are
not periodically calibrated. These circuits are functionally tested by operations
personnel by cooling the temperature detector and verifying the circuit energizes.
Operations performed a yearly operating surveillance test to verify electric unit
heaters and heat trace panels are in operation or operate when started. The
! inspectors' review of the procedures and questioning of personnel conducting the
l procedures did not identify any significant areas of concern with regard to freeze
i protection.
A large number of MWRs (over 20) are currently outstanding for the heat trace
system with 10 items over 1 year old. Most MWRs are of low significance.
However, an 18 month old chemical & volume control system heat trace circuit
- malfunction caused frequent and distracting control room alarms. This is contrary
to management expectations for timely completion of control room deficiencies.
- The inspectors observed that there was an absence of a central focal point for cold
weather preparations, and specifically the heat trace system. Four different
'
i
organizations (Operations, instrumentation and Controls, Electrical Maintenance, and
,
8 )
i
i
. - - - - _ - .
- . . . . -- -.- - - - .- - -_.~ - ~
.-
A
Construction) perform different aspects of cold weather preparations and
completion of MWRs. This lack of a central focal point contributed cause to the
large number of outstanding cold weather MWRs and failure to correct the control
room deficiency.
c. Conclusion
Cold weather preparations were completed in accordance to applicable procedures.
The inspectors noted that the lack of a focal point contributed to a large number of
outstanding cold weather MWRs and failure to complete work in a timely manner on
a control room deficiency.
M1.3 Unit 2 RHS Pumo Seal Leak and Reoair
a. Inspection Scone (62707)
Both RHS pump seals began leaking while in service and required replacement as
described in Section E2.2. The inspectors evaluated heavy load lift assessment and
movement activities.
b. Observations and Findinas
Maintenance and engineering personnel designed a single failure proof crane
assembly to lift the RHS pumps for this repair. The RHS pumps were sent to
vendor facilities for seal, shaft, and bearing replacements. Quality as,surance and
maintenance personnel provided oversight for the work activities. Reinstallation
was completed on November 15. The seal testing, pump movement, reinstallation,
and post installation tests were performed in a safe manner,
c. Conclusions
The inspectors concluded that RHS pump seal testing, pump movement, !
reinstallation, and post installation tests were performed in a safe manner.
M1.4 J Series Relav Reolacements
a. insoection Scone (62707)
Maintenance personnel implemented design changes and subsequently replaced and !
retested over 200 Unit 2 J-series relays to address a common mode failure concern
discussed in Section 1.2. The inspectors observed relay replacements and retests
to assess the quality of this corrective action.
b. Observations and Findinos
The inspectors reviewed work packages, observed several safety related J12 relay
replacements, and discussed the work with electrical technicians. Communication
between technicians and with the control room during replacement and testing were
good with clear repeatbacks throughout the evolution. Effective foreign materi J
controls exclusions precautions were consistently used. First line supervisors
,
.g i
i
. , - . , _ . --
_ __ . _ . _ . _ _.. . . _ _ _ - _ _ . _ . _ _ _ . _ _ . _ _
.
i
.
provided appropriate oversight. Technicians were knowledgeable concerning their ;
work activity. The inspectors observed that electricalleads and termination points i
within four motor control centers inspected were clearly labeled and in good ;
condition. !
!
Sufficient relays for this massive replacement project were not available onsite. '
Replacement relays were procured commercial grade and dedicated for safety
related application at a separate facility. Within two days appropriately certified
replacement relays began arriving onsite. The relay replacement project extended .
the refueling outage by about two weeks.
t
c. Conclusions !
!
Electricians performed J-series relay replacements in a professional manner,
demonstrating excellent job knowledge and communications skills. Procurement, ,
engineering, and maintenance personnel worked effectively to replace effected J- i
series relays in a timely manner and thereby restore safety system reliability. I
i
M8 Miscellaneous Maintenance issues (62707)
M8.1 Emeraency Diesel Generator Shutdown Circuit Modification
On September 10,1996, the Unit 2 Emergency Diesel Generator (EDG) 2-2 was
modified to remove a 140 second time delay on the shutdown circuit. This time I
delay would prevent the EDG from restarting during a shutdown sequence if another i
start signal was received. On September 29,1996, while completing the same
modification on the EDG 2-1, it was identified by the licensee that part of the circuit
was still energized contrary to the modification procedure. Troubleshooting
indicated that the Instrumentation and Control (l&C) personnel had verformed a step
out of sequence during the modification of the 2-2 EDG. The modification
procedure was revised and completed on the 2-1 EDG. The 2-2 EDG was
, subsequently taken out of service, and the modification was correctly completed.
The out of sequenc'e step did not affect EDG operability or operability of the
modification. The lack of a second voltmeter during the modification and testing on i
the 2-2 EDG contributed to completing the procedure steps out of sequence. The
inspectors concluded that the shutdown circuit modification improved EDG
availability. The procedural error during installation was licensee identified and
corrected and did not adversely effect EDG availability. I
111 Engineerina
E1 Conduct of Engineering
E1.1 H-02 Analoo Rod Position Indication (ARPI) Modification
a. Insoection Scone (37551)
,
On September 21,1996, operators declared the Unit 1 H-02 control rod ARPl
inoperable due to erratic indication. Engineers developed temporary modification
10
..
.
' .
.
.-
,
i
!
'
i
1-96 25 to restore reliable position indication. The inspectors reviewed the
temporary modification and 10 CFR 50.59 analysis to assess the engineers
performance in resolving this operational issue. i
!
b. Observations and Findinas '
,
On September 21,1996, Technical Specification (TS) 3.1.3.2.c was entered due to :
inoperable H-02 ARPl. Troubleshooting by system engineers and l&C technicians !
isolated the problem to secondary voltages in the position detector, or a connection l
between the detector and the containment operating deck connector plate.
Voltages on the primary windings were steady and used to determine rod position
every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> as required by TS 3.1.3.2.c.1.c. 1
The temporary modification bypassed secondary voltage and used primary detector
voltage to provide stable rod position indication. A root mean square (RMS)
amplifier and signal converter were installed to modify the primary voltage. The
normal loading of the secondary detector is simulated by installation of a loading
resistor. The temporary modification was necessary because further
. troubleshooting to determine the cause of the erratic secondary cannot be
performed at power. Technicians intend to continue troubleshooting the problem at
the next refueling or extended outage.
The temporary modification was installed October 25,1996, and H-02 ARPI
declared operable on October 29,1996 after successful completion of post-
maintenance testing. The inspectors found the temporary modification was
completed in a timely manner with effective controls to minimize any effect on the
ARPI system. Possible failure modes were thoroughly evaluated, and the 10 CFR
50.59 analysis was complete,
c. Conclusion
The engineering response to the erratic H-02 rod position indication was effective
and completed in a timely manner. The temporary modification provided control
room operators with accurate information and eliminates the increased workload
which resulted from periodically measuring and recording primary winding voltages
readings.
E1.2 ITE/Gould J12 Relav Failures due to Thermal Aoina
a. Insoection Scooe (37551,92903,93702)
On October 11,1996, Duquesne Light Company (DLC) determined that J12 series
auxiliary relays installed on Beaver Valley Unit 2 were susceptible to thermal aging
degradation which could potentially result in a loss of control power to multiple
safety related components. Numerous safety related systems including safety
injection, component cooling, charging, quench spray, recirculation spray, ;
emergency diesel generators, and service water were effected. The inspectors '
inspected relays, reviewed engineering evaluations and design changes, and -
11
_. _ - - _ . - - - .- - . .
= - ..-- - - .~. -.- .
l
i
.
'
I i
- i
! '
.
!
- interviewed personnel to determine whether the potential for relay failure was j
l properly addressed.
I
i
l b. Observations and Findinas
Four J12 relays failed during routine refueling outage motor operated valve testing.
j
in each case, the normally energized relay had been deenergized for several days to l
l support electrical bus outage maintenance. Upon bus re-energization two contact i
pairs on the J12 relay failed to pick-up. This prevented manual operation of the
safety related valve it controlled. Valve actuation upon an automatic engineered
! safeguards feature (ESF) signal was not effected, since the failed thermal overload
j'
'
relay and contacts are bypassed by the ESF signal. Maintenance personnel recalled
,
that two additional J12 relays had previously failed and been replaced in 1995.
l~ Relay inspection revealed that the magnetic yoke assembly retainer and the movable
j plastic armature carrier, which surrounds the core and coil, had become discolored
fr m blue to brown, embrittled, and cracked. A team was formed to evaluate the
relay failure as a potentially generic problem. Management placed an operational
j
mode hold on Unit 2 (currently in mode 5) pending resolution of the J12 relay issue.
l The inspectors determined this to be an appropriate precaution considering the
i
number of safety related systems which used these relays. The event was properly
{ reported in accordance with 10 CFR 50.72.
!
Licensing engineers proposed that the observed relay failureis may be a precursor to
coil failure and loss of control power, similar to that reported at another nuclear
! facility in 1991 (LER 50-423/91-30) and discussed in NRC Information Notice (IN)
i 92-27, " Thermally Induced Accelerated Aging and Failure of ITE/Gould AC Relays
,
Used in Safety-Related Applications". A related Part 21 notification was issued in
l 1987 by Telemecanique (ITE/Gould) regarding failed J10 relays. NRC IN 92 27
- noted that J10 relays mounted shoulder to shoulder in a horizontal " ganged"
i arrangement within cabinets exhibited vishle signs of thermal aging. The thermal
'
aging, in time, could result in loss of control power to the related component. In
1993 engineers had determined that no J-series relays were installed at Unit 1.
They further concluded that Unit 2 J10 relays were not susceptible to thermal aging
j based on less challenging mounting configurations and area temperatures.
- Engineers reevaluated applicability of NRC IN 92-27 and inspected additional relays
.
to better understand the observed relay failures. The failed J12 relays had J20M
) magnet block armature assemblies, G10JA116 coils, and were in service for 9
l years. Engineers determined that thermal aging (7-10 years, normally energized)
} caused the plastic armature carrier piece to deform and become brittle. The minor
! deformation interfered with free movement of the armature assembly and caused
! the contacts not to pick-up. However, in each case, upon recycling the power
supply breaker once, the condition cleared itself and the contacts made up. Actual
l broken plastic carrier pieces were observed loose in the two relays which had failed
1 in 1995. The loose pieces could potentially cause binding which would force the
! contacts to remain open.
5
- 12 j
i
i l
!
l
!
l
.~ -
, - -, ,- , , , . , , - - . . . - ,
- . - - . - - - _ - - - . . . - -
-
- --.- - -.- - - .-
,
.-
I
4
- ..
.
1
Based upon the industry information and observed relay degradation, engineering
, recommended replacing the most important J12 relays with available stocked
- relays. A temporary modification was developed to jumper around the thermal
, overload contacts for relays with more moderate operating environments or less
l
'
important functions until additional replacement relays could be procured. A further
, review of other J-series type relays was initiated to assess applicability. The
inspectors questioned what functions were bypassed by the jumpers and whether
! Jumper installation precluded control power failure to the effected component
! circuits. Engineers stated they were confident that relay failure could not cause
{ control power failure. The relays primarily provided indication, alarms, time delays,
] and thermal overload protection and could not adversely effect the ability of the
! components to function in response to a safety related ESF actuation signal.
1 i
.~ Management performed a multi tiered review of engineering's assessment and
'
$ strongly questioned the determination that the circuits were not susceptible to loss
i of control power. Engineers conducted a bench test of a failed J12 relay and a
! more detailed industry event review in response to managements concerns. The
i test J12 relay was energized with the contacts mechanically stuck in the open
i position as could occur due to plastic deformation described above. The excess
,
armature gap caused the coil to generate additional heat. After approximately six
minutes, the coilinsulation broke down and shorted, resulting in a current surge
sufficient to blow the associated component's control power fuse. A blown control
power fuse would cause the component to fail as is. This test demonstrated that if !
the J12 relays degraded further, they may result in control power failure similar to -
that reported at another facility in 1991. The bench test demonstrated that the
initial engineering assessment had been incorrect. Even with the jumper installed ;
across the J-series relay, the thermally aged relay could cause the circuit to lose l
control power and fail as is. '
l
Engineering management performed a case study for this event to better understand i
why engineers failed to identify the vulnerability to loss of control power during I
their initial evaluation. Several potential contributing factors were identified. !
Examples included perceptions that there was preconceived desired outcome, l
schedule pressures, defense of existing conditions instead of proving safety, asking i
the right questions, and clearly knowing the source of information. The engineering I'
department held seminars to fully review this event and learn from it. The
inspectors discussed lessons learned with engineering personnel and determined -
that the case study was effectively developed and communicated within the
engineering department. The seminars were an excellent tool to enhance problem
solving techniques and reenforce an appropriate safety culture. ,,
Engineers determined that the J20M armature assembly was also installed in
normally energized J10 and J13 type relays in Unit 2. Based on these results
management directed that all normally energized J10, J12, and J13 relays be ,
replaced prior to entering mode 4. I
l
l
13
__ _ _ _ _ _ . _ . . _ . _ _ . _ _ __ __ _ _ _ _ _ __ _
>
.
.
'
.
I c. Conclusions
1
j' The inspectors concluded that although initial engineering evaluations had been
detailed, they were too narrowly focused, and failed to recognize vulnerability to ;
control power failure. The multi-tiered management review was a strength and
i directly resulted in identification of the potentially generic failure and enhanced plant
safety through the replacement of over 200 J-series relays. The inspectors
. determined that the licensing department's recommendation to reevaluate NRC IN !
92-27 applicability demonstrated an appropriate desire to learn from industry :
i events. An event case study was effectively developed and communicated within
the engineering department. Case study seminers were an excellent tool to
i enhance problem solving techniques and reenforce an appropriate safety culture.
4 1
! E2 Engineering Support of Facilities and Equipment
'
i ;
- E2.1 Unit 1 Quench Sorav Iniection Valve Leakaoe Assessment
,
l a. insoection Scooe (37551. 71707)
i
- Operators noted that containment sump pump down rate increased approximately 4 I
- gallons per hour (gph) in late September. Operators determined that MOV-OS-
l 101 A, a quench spray injection valve, was leaking by its seat. This valve also
'
functions as an outboard containment isolation valve (CIV). Engineers and
'
operators developed a plan to reduce the leakage and verify valve operability. The >
inspectors reviewed the operability assessment and planned maintenance to i
l determine whether operability considerations were properly addressed.
.
.
b. Observations and Findinas
!
j Operators determined that the sump inleakage was from the reactor water storage
- tank and therefore did not present a reactor coolant system leakage concern.
l However, the ClV function was indeterminate. On October 8, electricians increased
! the valve torque switch setting to improve valve seating force. This activity
required declaring MOV-OS-101 A inoperable. The inspectors verified that the work l
'
1 plan, including tagout boundaries was appropriate to comply' with TS 3.6. The new
j torque value remained within specified maximum thrust limits. The valve was
'
cycled after the torque adjustment. Seat leakage was reduced, but did not stop. ;
.
-
Engineers developed basis for continued operation (BCO) 1-96-007 to evaluate
j valve operability with the seat leakage. The valve's quench spray injection function
i was unaffected. Based on prior evaluations of similar valve leakage observed in
[ 1994 and on current type C leak test results, engineers concluded that the
- containment function remained operable as well. BCO 1-96-007 determined that
i MOV-OS-101 A remained operable and provided instructions to perform a type C
- containment integrity test if inleakage again increased to 3 gph. The inspectors
j determined that BCO 1-96-007 was technically sound.
l
- .
,
!' !
- 14
-
'
.
!
!
i
_ _ _ -
_-- - _ - -, -- _
- - -
_ - - _ ~ - . . - - . -~-- . . - - - - . . _ - . _ - - - - . -
.
!
'
On October 25, type C testing was performed on MOV-OS-101 A due to increased i
containment inleakage past the valve seat. The test confirmed that the valve was
!
properly functioning to assure its containment isolation function. In addition the !
1
type C test caused the valve to seat more firmly and reduced containment
j inleakage. The BCO remained in effect and provided clear instruction to operators !
l regarding seat leakage monitoring following valve operation and requirements to
,
i perform type C tests to revalidate the BCO if leakage increased above 5 gph. -
c. Conclusions
i
The increased Unit 1 containment sump pump down rate was properly evaluated
and the basis for continued operation was technically sound.
E2.2 Unit 2 Core Offload to Reoair RHS Pumo Seals
i
a. Insoection Scope (37551. 92902. 92903) ,
,
The residual head removal (RHS) system is designed to provide shutdown cooling
'
and designated as safe shutdown equipment. RHS has no emergency core cooling
function and is isolated during normal power operation. On October 13,1996,
operators observed that the' Unit 2 "A" RHS pump seal was leaking approximately 1 .
gpm. The "B" RHS pump seal was also leaking, but at a much lower rate. The i
inspectors observed the licensee's resolution of the sealleakage to determine
whether appropriate safety considerations were implemented.
b. Observations and Findinas j
Unit 2 was in cold shutdown (mode 5) nearing completion of a planned refueling
outage when the sealleakage was identified. RHS was in serv!::e while the unit
was maintained in mode 5 pending completion of approximately 250 J-series relay
replacements (see Section M1.3). Elevated RHS pump bearing temperatures were
observed just prior to the sealleak. Engineers determined that the temperatures
rose in response to increased RCS temperature as operators prepared to shift to
mode 4 and was not a contributing cause to the seal leakage. Engineers
subsequently implemented a design change to remove noise insulation from the RHS
pump stand area to improve air cooling. The inspectors reviewed the temperature
trending data, design drawings, and concludei that the engineering assessment was
technically sound.
increasing leakage observed from the RHS pump seals and consultation with the
RHS pump vendor led management to conclude that the seals should be replaced
now instead of awaiting the next planned refueling outage. The seals were nearing
the end of their service life, but had not been previously identified for replacement
in the planned outage work scope. Management determined that the heavy load lift
, path for removal of the RHS motor would pass close to the unisolable incore thimble
tubes and constitute an unreviewed safety question (USO) while fuel was in the
core. Duquesne Light Company (DLC) performed an indepth issue assessment and
on October 18, decided to offload all fuel from the reactor vessel (RV) to establish
15 .
!
l
. - . _ _ _ , , ___ . . _ _ __ __,__. _ _- _ _<
- -.. - - - - _ - - . - . . - . . . - .. - .. _ _ _ - - - _ -.-- .
.
.
'
.
j appropriate plant conditions to safely replace the pump seal and lower bearing on
i both RHS pumps. The inspectors independently reviewed station drawings,
i procedures, and licensing bases documentation and determined that the RHS pump
j lift with fuel in the reactor vessel was an USQ. Management's decision to extend
.
the outage and repair the pump seals now, demonstrated a strong safety
! perspective.
,
'
The inspectors observed that licensing bases documentation was difficult to
i retrieve, which delayed the final decision, thereby prolonging the outage further.
{ The licensing manager informed the inspectors that a new project to computerize
j licensing bases documentation, facilitating quick search capabilities, had recently
l been authorized. The inspectors determined this was a good initiative to improve
'
design bases information accessibility for decision making.
}
! The inspectors questioned why both seals had not been scheduled for replacement
,
'
earlier based on either performance trending or age. The Performance Engineering
manager reviewed trend data with the inspectors. Flowivibration, and temperature
4 data did not provide any indication of seal performance. The only available
l performance indicator was visible inspection, which itself was difficult with the
i noise insulation normally installed. No seal service life was assigned prior to this
! event. Engineers surveyed the industry and determined that typical service life for
i
2
this seal was 7-10 years. None of the other utilities had identified a predictive
maintenance indicator for seal degradation. Several had established a routine
preemptive seal replacement schedule. The inspectors determined that failure to
assess expected service life for a component whose performance could not be
monitored to predict failure was a weakness. Engineers implemented several ,
corrective actions which included establishing a seal replacement preventive !
maintenance (PM) task, further assessment of trending methods, failure analysis for
both RHR pump seals, evaluation of an RHS pursp seal design upgrade, performance
trending procedure revisionn assessment of Unit 1 RHS pump seal age, and
material history reviews to identify other SSCs whose repair history indicate need l
for a replacement PM. This ongoing review was productive in identifying
components, such as an inverter circuit card and a flow transmitter, for replacement
PMs. These corrective actions were appropriate.
I
'
c. Conclusions
The inspectors determined that failure to assess expected service life for the RHS
pump seals, whose performance could not be monitored to predict failure, was a
weakness. Corrective actions were appropriate and productive in assessing other
components for replacement PMs. Difficulty in assembling licensing bases
documentation delayed the decision regarding whether or not to off-load fuel from
the reactor vessel to perform the seal repair. The licensee performed an indepth i
safety assessment to support decisions regarding the RHS pump seal repair.
Management's decision to extend the outage and repair the pump seals now, rather
than risking complete seal failure during the next plant shutdown, demonstrated a l
strong safety perspective.
'
16
.
_ _ . _ _ _
_ ,
__ __
'
l
l
.
E8 Miscellaneous Engineering issues
E8.1 Steam Generator Water Level Control System and Protection System Interaction l
a. Inspection Scone (37551) l
The inspectors reviewed the licensee's evaluation and corrective actions ic response
to an advisory letter by the nuclear steam supply system (NSSS) vendor. The
advisory letter identified a failure mode that would not satisfy lEEE-279-1971, ,
" Criteria for Protection Systems for Nuclear Power Generating Station." The I
inspectors examined the applicability to Unit 1 and Unit 2 designs and evaluated the I
design of the steam generator level and main steam flow taps for Unit 2. ]
b. Observations and Findinas
l
On October 24,1996, engineers identified that BVPS2 had a potential for a ]
condition outside of their design basis and reported the issue pursuant to l
10 CFR 50.72(b)(2)(i). Prior to the licensee reporting this condition, the NSSS l
vendor had issued a nuclear safety advisory letter on August 14,1996, detailing the :
possible failure mode for a protection and control system interaction. Unit 2 has a ;
common tap for one main steam flow channel and steam generator level channel
instruments on each steam generator. The other main steam flow channel and two
other steam generator level channels have independent taps. A failure of the l
common tap would cause main steam flow instrument to faillow, and steam ;
generator level instrument to fail high. Based on IEEE-279 Section 4.7.3, a second ,
failure (a second steam generator level instrument failure in this case) must be :
postulated due to the control system and protection system interaction. Steam !
generator level would decrease in response to the decreased steam flow input into
the steam generator level control system (assumed that the common tap steam flow l
channel is selected). The protection system would not trip the reactor because the
l
reactor trip system requires two out of three low steam generator level channels for i
a reactor trip. The steam flowneedwater flow mismatch coincident with low steam
generator level reactor trip was deleted with Unit 2 TS Amendmeru #27 on )
February 20,1990. This trip signal, if present, would trip the reacJor because it
only requires one low steam generator level signal.
Unit 1 has independent taps and has not eliminated the steam flow /feedwater flow
mismatch coincident with low steam generator level reactor trip. Therefore, the
inspectors concluded this issue was not applicable to Unit 1.
Engineers discovered this issue while Unit 2 was shutdown. Management directed
, that the issue be fully evaluated and initial corrective actions completed prior to
entering Mode 3. Corrective actions included the following:
- Modifications were made to the steam generator water level control
(SGWLC) system which installed a selector switch at the local panel for the
steam flow channels. The independent tap steam flow channel is normally
selected. If the common tap steam flow channel is selected, a newly
17
- _-
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ . _ . _ _ _ _ . _ _ _ . - __
7, _7 _ _ _ . . _
'
.
i
,
installed control room annunciator will alert the operator to enter the
l common tap steam generator level instrument failure procedure (TS 3.3.1.1,
j Table 3.3-1).
- -*
A review of the Unit 1 and Unit 2 plant drawings for steam generators and
the nuclear steam supply system for other common impulse taps for
control / protection system interaction was conducted. None were identified.
t
] A review of the overall TS amendment request process to improve
j coordination of design reviews between Licensing and Engineering was
- commenced.
j *
Final design corrective action will be implemented by the completion of the
- next refueling outage.
l The licensee determined that the apparent cause of this event was failure to
j
adequately review and evaluate the TS amendment, which eliminated the steam
flow /feedwater flow mismatch coincident with low steam generator level trip in
- February 1990. The safety evaluation failed to fully evaluate the mechanical
! aspects of the TS amendment request. The inspectors held discussions with
Licensing, Operations, and Engineering personnel to fully evaluate the corrective
actions in place and the significance of the long time design flaw. The inspectors
concluded that the corrective actions addressed the design flaw, the apparent
cause, and will provide effective measures for design control. The probability of
occurrence of a tap / impulse line failure coincident with a second failure appears
low. However, the consequences of the event would potentially be significant.
10 CFR 50.55a(h) requires that protection systems must meet the requirements in
IEEE-279. The inspectors determined that the Beaver Valley Unit 2 design of the
SGWLC system and its interaction with the protection system without the steam
flow /feedwater flow coincident with low steam generator level reactor trip did not
meet IEEE 279. This licensee ident'.fied and corrected violation is being treated as a
Non Cited Violation censistent with Section Vll.B.1 of the NRC Enforcement Policy
(50-412/96008-02).
c. Conclusion
Engineers identified a long standing Unit 2 design deficiency involving the steam
generator water level control system and the protection system. The apparent
cause was inadequate engineering evaluation of a TS amendment requested in
1990. The inspectors noted strong engineering support and management influence
resulted in effective immediate corrective actions that addressed the apparent cause
and the deficiency.
l
18 I
I
l
I
. _ .
- . - _ . - . - - - . - - . - -.
__, - . - - . . . - - . - _ .-
-
l
l
) *
- .
j IV, Plant Suonort
,
e
i
R8 Miscellaneous RP&C losues
i
j R8.1 Plant Access Trainina and Radiation Worker Trainina
i
- '
Inspectors observed the General Employee Training (GET) given by DLC to a group
j of contractor personnel to initially qualify them for unescorted access to the
j Protected Area and Radiologically Controlled Areas (RCA). The training was
! required by DLC for all new employees. GET Level I provided familiarization in
! station organization and administration, an overview of the nuclear plant, and a
i general review of the DLC policies and procedures regarding security, safety, fire
l protection, emergencies, radiation protection, and fitness for duty.' GET Level ll
! provided radiation worker training, including practical factors, for safely accessing
the RCA, minimizing personal radiation exposure, and minimizing the spread of
I
radiological contamination. GET was also very important in indoctrinating new
i employees to management standards and expectations, and familiarizing them with
3
their rights and responsibilities by law. ,
!
The instructor was very knowledgeable, experienced, and enthusiastically presented t
j the subject material. He firmly emphasized management standards and
i expectations. Training aids were effectively used, and the students were given
i hands-on demonstrations when practical, particularly in GET Level 11. Students
l were attentive and displayed a willingness to question and learn. Practical factors,
! such as donning and removing anti-contamination clothing, were practiced until
i performed satisfactorily by all studerts. Comprehensive multiple choice tests were
j given after GET Level I and Level ll to verify satisfactory student knowledge level.
l
'
The inspectors concluded that the GET provided satisfactory initial training to safely
access the Protected Area and the RCA. In addition, management expectations and
i worker rights and responsibilities were clearly stated.
j F1 Control of Fire Protection Activities
F1.1 Plant Housekeepina and Control of Combustible Materials
l
!
l a. Inspection Scooe (71707. 71750) .
I
l During routine plant tours, the inspectors reviewed housekeeping practices to
l determine whether material and tools were properly controlled. The inspectors *
i particularly looked for loose materials and combustibles in the vicinity of safety
] related components.
f b. Observations and Findinas
!
} During area tours within the Units 1 and 2 auxiliary buildings, the inspectors found
a numerous tools, lagging, electrical convertors, ropes, extension cords, clamps,
batteries, paper, and other materials adrift with no indication of ongoing work.
I
- 1S
4
_
i
._ _. - , _ _
_ . _ - _ - . _ , _ . . _ . . , _ . _ _ _ , ._. ._
, -
---.- _.
= . - . - . .- . - ..~.. . - _ -._
.
4
4
Loose material was found both inside and outside cont' aminated areas and in close
proximity to safety related equipment. The inspectors informed the shift supervisor
of the discrepant conditions. Adequate action was taken to remove the loose
materialidentified. Based on observations and personnel interviews the inspectors
determined that adherence to station standards for area housekeeping was weak.
Although the loose materials did not adversely impact safety related equipment, the
potential to do so and to spread contamination was increased. A problem report
was initiated to address this issue. In addition, six additional people were assigned
to housekeeping and preservation activities.
The inspectors observed several carts of wood timbers staged outside the Unit 2
containment access hatch and questioned whether this wood was fire retardant
treated. This wood was intended to be used in containment to support RHR pump
seal repair work. The shift supervisor determined that a significant portion of the
wood was combustible and promptly had it removed. Construction and
maintenance personnel failed to properly control transient combustible material.
The inspectors reviewed a compartment fire loading calculation and determined that
i
the presence of the combustible wood timbers was bounded by the BVPS2
l
Appendix R analysis. Based on further area tours and review of recent area audits
by fire protection engineers, the inspectors concluded this to be an isolated ,
occurrence. However, interviews indicated that station personnel did not
consistently understand the station's program for controlling transient combustible ]
material.
.
l
Problem report 2-96-667 was initiated to evaluate the transient combustibles issue. '
The inspectors discussed transient combustible control with the fire protection
engineer and noted that only two exceptions have been approved to use
combustible wood within the protected area. Initial discussions indicate that
management intends to revise program requirements to eliminate these two and any
future exceptions. The inspectors determined that these actions and the problem
report process were adequate to preclude recurrence.
.
c. Conclusions
Adherence to station standards for area housekeeping was poor. Station personnel
did not consistently understand the station's program for controlling transient
combustible material. Adequate actions were taken to address these issues.
L1 Review of FSAR Commitments
A recent discovery of a licensee operating their facility in a manner contrary to the
Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a
special focused review that compared plant practices, procedures and/or parameters
to the UFSAR description.
20
= . . - .- - _ _ _ - . . _ .
.-
.
-
,
.
While performing the inspections discussed in this report, the inspectors reviewed
the applicable parts of the UFSAR that related to the areas inspected. The
inspectors verified that the UFSAR wording was consistent with the observed plant
practices, orocedures and/or parameters.
V. Manaaement Meetinas
X1 Exit Meeting Summary -
The inspectors presented the inspection results ta membeis of licensee management at the
4
conclusion of the inspection on November 27,1996. The 1.9ensee 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 Management Meeting Summary
On October 21-22,1996, Mr. Hubert J. Miller, Regional Administrator, NRC Region I met
with the resident inspector staff, toured the station, and met with licensee management to
discuss current licensee performance. ;
I
l
l
4
iI
l
21
. __ _ _ _ . . _ _ _ _ ._ . _ _ , ._ _ . _ . . _ _
g I
.
.
,
ATTACHMENT
i
s
PARTIAL LIST OF PERSONS CONTACTED
j QLC i
J. Croso, Senior Vice President, Nuclear Power Division
T. Noonan, Vice Preddent, Nuclear Operations and Plant Manager
,
S. Jain, Vice President, Nuclear Services
,
L. Freeland, Manager, Nuclear Engineering
,
B. Tuite, General Manager, Nuclear Operations
j C. Hawley, General Manager, Maintenance Programs Unit
l K. Beatty, General Manager, Nuclear Support Unit
- R. Brosi, Manager, Nuclear Safety
J. Arias, Manager, Licensing
- K. Ostrowski, Manager, Quality Services
- R. Vento, Manager, Health Physics
M. Johnston, Manager, Security
F. Schuster, Manager, System and Performance Engineering
'
l A. Dulick, Manager, Operations Experience ;
.
R. Hart, Senior Licensing Supervisor
!
J. Maracek, Senior Licensing Supervisor
,
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
3 IP 71707: Plant Operations
IP 71750: Plant Operations
IP 61726: Surveillance Observations
,
'
IP 62707: Maintenance Observations
IP 92901: Follow-up - Plant Operations
lP 92902: Follow-up - Engineering
IP 92903: Follow-up - Maintenance
IP 93702: Prompt Onsite Response to Events at Operating Power Reactors
4
1
- ITEMS OPENED, CLOSED AND DISCUSSED
, Closed
-
50-334(412)/96008-01 NCV Inadvertent Actuation and Isolation of CREBAPS
(Section 04.1)
i- 50-412/96008-02 NCV Steam Generator Level Control and Protection
Interaction (Section E8.1)
,
Discussed
a
i
, 50-334/96007-01 URI Unit 1 Pressurizer (PZR) Power Operated Relief Valve
(PORV) Block Valve Configuration Contrary to UFSAR
] (Section 08.1)
i
-
22
l
i
- . . . - - -
- !
.
.
LIST OF ACRONYMS USED 5
l
ANSS Assistant Nuclear Shift Supervisor '
ARPl Analog Rod Position Indication
ATWS Anticipated Transient Without Scram
BCO Basis for Continued Operation
BVPS Beaver Valley Power Station
,, CDF Core Damage Frequency I
CFR Code of Federal Regulations
CIV Containment Isolation Valve
CREBAPS Control Room Emergency Breathing Air Pressurization System
DLC Duquesne Light Company
EDG Emergency Diesel Generator
ESF Engineered Safety Features
GET General Employee Training ;
IE Inspection and Enforcement !
IEEE Institute of Electrical and Electronic Engineers '
l&C Instrumentation and Control ;
IPE Individual Plant Examination
MWR Maintenance Work Request
NCO Nuclear Control Operator !
NRC Nuclear Regulatory Commission
NSIC Nuclear Safety information Center
NSSS Nuclear Steam Supply System
OM Operations Manual l
OST Operational Surveillance Test
PDR Public Document Room
PM Preventive Maintenance
PORV Power Operated Relief Valve
PZR Pressurizer i
RMS Root Mean Square l
PR Problem Report i
RCA Radiologically Controlled Area i
SGWLC Steam Generator Water Level Control
SRO Senior Reactor Operator
SSC Systems Structures and Components ;
Tave Average Temperature
TS Technical Specification
UFSAR Updated Final Safety Analysis Report
USO Unreviewed Safety Question
l
l
23 l
1
!
l
l
J