ML18106A432
| ML18106A432 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 04/02/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18106A426 | List: |
| References | |
| 50-272-98-01, 50-272-98-1, 50-311-98-01, 50-311-98-1, NUDOCS 9804070157 | |
| Download: ML18106A432 (37) | |
See also: IR 05000272/1998001
Text
Docket Nos:
License Nos:
Report No.
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
U.S. NUCLEAR REGULATORY COMMISSION
50-272 & 50-311
REGION I
50-272/98-01 & 50-311 /98-01
Public Service Electric and Gas Company
Salem Nuclear Generating Station, Units 1 & 2
P.O. Box 236
Hancocks Bridge, New Jersey 08038
February 2, 1998 - March 15, 1998
M. G. Evans, Senior Resident Inspector
F. J. Laughlin, Resident Inspector
H. K. Nieh, Resident Inspector
E. H. Gray, Senior Reactor Engineer
L. J. Prividy, Senior Reactor Engineer
L. M. Harrison, Reactor Engineer
James C. Linville, Chief, Projects Branch 3
Division of Reactor Projects
9804070157 980402
ADOCK 05000272
G
EXECUTIVE SUMMARY -
Salem Nuclear Generating Station
NRC Inspection Report 50-272/98-01 & 50-311/98-01
This integrated inspection included aspects of licensee operations, engineering,
maintenance, and plant support. The report covers a six-week period of resident
inspection; in addition, it includes the results of announced inspections by regional
engineering inspectors of the Unit 1 motor-operated valve program and an emergency
diesel generator turbocharger failure.
Operations
In general, the conduct of operations was professional and safety-conscious.
Activities associated with the shutdown of Unit 2 on February 11 and the heatup of
Unit 1 on February 18, were performed in a deliberate manner with clear
communications.
Licensed operators' inadequate monitoring of plant parameters and maintenance of
steam generator levels, combined with inadequate communications and crew
teamwork resulted in an inadvertent automatic start of the auxiliary feedwater
pumps when the 14 steam generator level decreased to 9%. The reactor operator
did not follow procedure requirements to maintain the steam generator levels within
the required band.
The licensee's corrective actions to address the reasons for an apparently fatigued
licensed control room supervisor were acceptable. However, there were some
weaknesses identified in licensee management oversight of individµal employee
work hours which the licensee has initiated actions to address.
Maintenance-
Poor planning and inadequate maintenance practices resulted in an incorrect control
switch being installed on the 12 Diesel Fuel Oil Transfer Pump (DFOTP), which.
rendered the pump inoperable. The licensee ascended to Mode 4 on Unit 1 with
less than the required DFOTPs operable, which was a Technical Specification
violation. The licensee's immediate corrective actions for this event were weak,
including an untimely operability determination for the wrong part being installed on
the 21 DFOTP, and untimely verification of correct part numbers for similar control
switches on the four DFOTP electrical panels.
Procedural adherence for the 2A Emergency Diesel Generator (EOG) post-
maintenance testing was poor. Numerous procedural violations by maintenance and
operations personnel resulted in the improper operation of the diesel. There was
little safety significance to these violations as the diesel was out of service for
maintenance. However, they showed a lack of questioning attitude and attention to
ii
Executive Summary
detail by numerous personnel. Additionally, the engineering actiori plan utilized for
the maintenance effort was not sufficiently detailed to promote smooth transition
between the maintenance and operations procedures used.
The licensee met all Technical Specification requirements for the 2C EDG outage
and the crankcase alarm on the 28 EDG. The operator correctly followed the alarm
response procedure for the 28 alarm. The operability determination for the 28 EDG
after the cause of the alarm was determined was adequate, but the decision to run .
the 28 EDG during the 16-hour 2C EDG outage was not appropriate.
On February 11, 1998, the 2A EDG turbocharger failed during a post maintenance
test. The licensee formed a team to get the relevant facts, find the cause of the
failure, evaluate its significance to the operability of the other EDGs, and establish
corrective actions. The NRC reviewed the team activities to assess the evaluation
scope, methods and results. This NRC inspection did not identify any factors that
would provide a basis for disagreeing with the scope, method of investigation, or
with the preliminary findings.
The licensee had adequately implemented their Technical Specification Surveillance
Improvement Program to support Unit 1 restart.
Engineering
The licensee had adequately demonstrated design basis capability for Salem Unit 1
MOVs to support restart. Justifications for key program assumptions and the
applied valve factors were adequate.
The licensee continued to adequately pursue resolution of issues related to the
control area ventilation system (CAVS). However, long term corrective actions are
still necessary to eliminate the need f6r maintenance mode, a time-consuming,
resource-intensive work around which ensures adequate dp margin between the
control room and the adjacent spaces. When this mode is employed, then any
circumstance which necessitates accident pressurized mode, such as an inoperable
CAVS radiation monitor, would require a unit shutdown to Mode 5 so that the
control room emergency air conditioning system intake could be lined up to a non-
operating unit ..
Elevated grass levels in the Delaware River combined with degraded service water
strainers and lack of service water reliability program oversight resulted in
accelerated rates of service water biofouling. Weak management attention allowed
biofouling to occur at unpredictable rates. Several instances of biofouling occurred
in plant components before strainer degradation was identified and effective
corrective actions were taken. In one instance, the biofouling contributed fo the
inoperability of a Unit 2 safety related chiller. Salem staff failed to take prompt
iii
Executive Summary
corrective actions to determine and correct the cause of service water biofouling
problems. System Engineering and Operations interfaces were weak during the
analysis of those problems. The licensee did not adequately evaluate the extent of
condition at both Salem Units. The inspector also concluded that the corrective
actions taken in response to Licensee Event Report 50-272/96-34 were acceptable .
iv
TABLE OF CONTENTS
EXECUTIVE SUMMARY .............................................. ii
TABLE OF CONTENTS ................................. * ............... v
I. Operations ; . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01
Conduct of Operations ..................................... 1
01 . 1
General Comments ....... *. . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01.2 Unit 1 Inadvertent Automatic Actuation of an Engineered
Safeguards Feature - Auxiliary Feedwater Pumps ............. 1
04
Operator Knowledge and Performance .......................... 3
04. 1
Inattentive Control Room Supervisor ....................... 3
OB
Miscellaneous Operations Issue ............................... 4
O.B.1 (Closed) LER 50-311/9B-04 ......................... * .... 4
O.B.2 (Closed) LER 50-311/9B-05 ............................. 5
II. Maintenance .................................................... 5
M 1
Conduct of Maintenance .................................... 5
M 1 . 1 General Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
M 1 .2 Wrong Control Switch Installed on 12 Diesel Fuel Oil Transfer
Pump ............................................ 6
M1 .3 Post-Maintenance Testing of 2A Emergency Diesel Generator after
Turbocharger Failure .................................. B
M2
Maintenance and Material Condition of Facilities and Equipment ........ 9
M2. 1 High Crankcase Pressure Alarm on the 2B Emergency Diesel
Generator During a Technical Specification Required Run ........ 9
MB
Miscellaneous Maintenance Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
MB. 1 2A Emergency Diesel Generator Turbocharger Blade Failure . . . . . . 11
MB.2 (Closed) LER 50-272/96-05, Supplements 6 through 16 ........ 12
Ill. Engineering .................................................... 13
E 1
Conduct of Engineering ............... : . . . . . . . . . . . . . . . . . . . . 13
E1 .1
Generic Letter B9-10 Motor-Operated Valve Program Review and
(Closed) NRC Programmatic Restart Issue 111.a.23: Adequacy of
Motor-Operated Valve Program (Unit 1) . . . . . . . . . . . . . . . . . . . 13
E1 .2
Update on Control Area Ventilation System Issues ............ 20
E2
Engineering Support of Facilities and Equipment ................... 21
E2. 1
Service Water Biofouling and (Closed) LER 50-272/9.6-34 ....... 21
EB
Miscellaneous Engineering Issues ............................. 24
EB.1
(Closed) Violation 50-272/96-11-01 ...................... 24
EB.2
(Closed) Inspector Followup Item 50-272/96-11-02 ........... 24
EB.3
(Closed) Inspector Followup Item 50-272/96-11-03 ........... 25
EB.4
(Closed) Inspector Followup Item 50-272/96-11-04 ...... ~ .... 25
EB.5
(Closed) Violation 50-272/96-11-05 ...................... 25
EB. 6
(Closed) Inspector Followup Item 50-272/96-11-06 ........... 25
v
E8.7
E8.8
E8.9
E8.10
E8.11
E8.12
(Closed) Inspector Followup Item 50-272/96-11-07 ........... 25
(Closed) Inspector Follow Item 50-272/96-11-08 ............. 26
(Closed) Inspector Followup Item 50-272/96-11-09 ........... 26
(Closed) Unresolved Item 50-272/96-11-11 ................. 26
(Closed) Unresolved Item 50-311/96-80-01 ................. 27
(Update) Violation 50-311 /97-21-05 and (Closed) LER 50-311 I
96-07-02 ......................................... 27
V. Management Meetings ............................................ 27
X 1
Exit Meeting Summary .................................... 27
X2
Management Meeting Summary .............................. 27
vi
..
Report Details
Summary of Plant Status
Unit 1 began the period in Mode 5, Cold Shutdown. On February 18, 1998, the operators
increased the average coolant temperature above 200°F and entered Mode 4. The unit
remained in Mode 4 through the end of the inspection period.
Unit 2 began the period operating at 100% power. On February 11, 1998, the licensee
commenced a plant shut down in order to make repairs to the 2A emergency diesel
generator following a failure of the turbocharger. During the shutdown, the licensee
performed other repair activities which included replacement of two pressurizer code
safety valves and repair of the 22 steam generator steam flow transmitters. On March 3,
the NRC resident inspectors participated in the full participation exercise covered by
Inspection Report 50-272, 311, 354/98-80. On March 14, the unit was returned to
service and was operating at about 50% power at the end of the inspection period.
I. Operations
01
Conduct of Operations (71707, 92901, 93702 & 40500)
01 . 1
General Comments
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operations. In general, the conduct of operations was professional
and safety-conscious. The inspectors observed activities associated with the
shutdown of Unit 2 on February 11 and the heatup of Unit 1 on February 18, and
noted that the evolutions were performed in a deliberate manner with clear
communications. These evolutions were also observed by the NRC Readiness
Assessment Team Inspection (RATI), as documented in Inspection Report 50-272 &
311 /98-81 . Additional specific events and noteworthy observations are detailed in
the sections below.
01.2 Unit 1 Inadvertent Automatic Actuation of an Engineered Safeguards Feature -
Auxiliary Feedwater Pumps
a.
Inspection Scope
On February 21, 1998, with Salem Unit 1 operating in Mode 4 (Hot Shutdown), the
11 and 12 auxiliary feedwater (AFW) pumps automatically started on Lo-Lo steam
generator level in the 14 steam generator (SG). The licensee made a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
telephone notification to the NRC as required to document this automatic actuation
of an Engineered Safeguards Feature (ESF). The inspectors reviewed this event and
the licensee's root cause evaluation and corrective actions which are documented in
Action Request (AR) 980221128 .
.2
b.
Observations and Findings
On February 19, the operators commenced warming the main steam lines in
accordance with procedures being utilized to take the plant from Cold Shutdown to
Hot Standby. Warming the main steam lines requires opening the main steam stop
bypass valves (MS18s). In Mode 4, feedwater is manually supplied to the SGs on a
periodic basis. This is usually accomplished by maintaining operating AFW pumps
discharging against closed SG feedwater supply valves on recirculation and opening
these valves when feedwater is needed. However, in this case the AFW pumps
were cycled on and off because orie of the SG feedwater valves was leaking
through. To avoid frequent starting and stopping of the AFW pumps, the periodic
filling of the SGs was performed on a less frequent basis, and SG level was allowed
to vary over a wider range before refilling. Establishing flow through the MS18
valves increased the steaming rate of the SGs, thereby increasing the required
frequency of providing feedwater to the SGs to maintain water levels. The MS18
valves were opened approximately 1 to 2 % of valve open position. The increased
steaming rate required the starting of the AFW pumps approximately once per 12
hour shift in order to maintain SG levels.
On February 20, the night shift further opened all MS18 valves to approximately
4% valve open position. The SGs were filled to greater than 33% narrow range
level at 4:51 a.m. on the morning of February 21. The additional ste.am demand,
which caused water levels to fall at an increased rate, was not anticipated by the
on-coming day shift. In addition, prior to the event, SG water level narrow range
chart recorders and SG water level program deviation console alarms on control
console 2 were inoperable due to Advanced Ditigal Feedwater Control System
testing which was in progress. The Unit 1 reactor operator (RO) logged 14 SG
narrow range level at 32 % at 7:30 a.m. At 1 :30 p.m., while performing shiftly
logs, the RO noticed 14 SG level to be 12%. The RO was about to start the AFW
pumps and refill the SGs just as the automatic action occurred. At 1 :32 p.m., the
11 and 12 AFW pumps automatically started on Lo-Lo SG level when 14 SG water
level reached 9% narrow range level. Operators promptly established feedwater to
all SGs to restore water levels. At the time of the event, the 11, 12, and 13 SG
water levels were 21 % , 31 % , and 32% respectively. The 14 SG narrow range
. level dropped from 36% to 9% in approximately 8.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.
Licensee evaluation of the event determined that the cause was human error. The
two ROs on duty, and the control room supervisor did not adequately monitor SG
water levels nor did they anticipate the increased feedwater requirements. A
contributing cause was ineffective shift turnover and poor team communication.
Although the additional steam demand on the SGs was discussed during the
individual watch turnovers, the subject was never discussed at the pre-watch shift
brief nor did the Unit 1 control room crew discuss any increased monitoring of SG
water levels. The operating crew also did not discuss what SG water level should
be maintained. The RO was unsure as to what level range was to be maintained in
3
the SGs. Guidance provided in procedure S1 .OP-SO.AF-0001, "Auxiliary Feedwater
System Operation," and S1.0P-IO.ZZ-0002, "Cold Shutdown to Hot Standby,"
required level be maintained between 28-38%. Levels in the 11 and 14 SG were
allowed to go below this level.
The licensee's corrective actions included discussion of lessons learned lead by the
two ROs involved in this event. Also, an emphasis of responsibilities and the
importance of safe operations was reinforced by the Operations Superintendents
and reviewed with the operating crews. Also, the chart recorders and alarms were
returned to operable status on February 21 .
The inspectors discussed this event with the .individuals involved and reviewed the
licensee's corrective actions and found them acceptable. - The safety significance of
this event was minimal because the SGs were not being relied upon for decay heat
removal. At the time of the event, core cooling was being provided by the 11
residual heat removal loop. Therefore, this licensee identified and corrected
violation for failure to follow procedure.s for maintaining SG levels is being treated
as a Non:.cited Violation consistent with Section Vll.B.1 of the NRC Enforcement
Policy. (NCV 50-272/98-01-01)
c.
Conclusions
Licensed operators' inadequate monitoring of plant parameters and maintenance of
steam generator levels, combined with inadequate communications and crew
teamwork resulted in an inadvertent automatic start of the auxiliary feedwater
pumps when the 14 steam generator level decreased to 9%. The reactor operator
did not follow procedure requirements to maintain the steam generator levels within
the required band.
04
Operator Knowledge and Performance
04.1
Inattentive Control Room Supervisor
a.
Inspection Scope
b.
At about 4:30 p.m. on March 11, 1998, during observation of a Unit 2
startup/reactivity briefing which was conducted in the conference room adjacent to
the control room, the inspector noted that a control room supervisor (CRS) was
having difficulty staying awake and appeared inattentive. The inspector informed
the Operations Manager of the observed condition of the CRS. Licensee
management took actions to address this condition, as discussed below.
Observations and Findings
The Operations Manager took prompt corrective action by suspending the briefing
and initiating an investigation (AR 980311292). The CRS was relieved from his
4
duties and tested for Fitness for Duty (FFD). The test results were negative, he
was coached about the serious negative perception of his alleged actions, and
returned to work the following day. Licensee investigation did not confirm that he
was inattentive, but did determine that he was apparently tired at the briefing.
Further licensee review determined that the CRS had worked six - 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts
the previous week and that March 11 was his ninth -12 hour day out of the
previous 10 days. Although, this is within the licensee's overtime guidelines
described in procedure, NC.NA-AP.ZZ-0005, "Station Operating Practices," (NAP
5), as a corrective action, licensee management stated that General Manager
approval would now be required for any individual scheduled to work greater than
60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> in a week and this requirement would be proceduralized in NAP 5. The
intent of these actions was to minimize the impact of working excessive hours on
employee quality of life and fitness for duty ..
The inspectors questioned the extent of other operations personnel working
excessive hours. In response, the licensee initiated an audit of operations
department personnel work hours and identified several instances since January
1998 of licensed senior reactor operator's (SRO's) gate-to-gate times exceeding 72
hours in a seven day period. In addition, long turnovers were resulting in
consecutive 13 to 14 hour1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> work days. NAP 5 guidance is that an individual should
not be permitted to work more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any seven day period, excluding
shift turnover time. The inspector questioned the gate-to-gate times for two SROs,
whose times in a seven day period were 83 and 87 hours0.00101 days <br />0.0242 hours <br />1.438492e-4 weeks <br />3.31035e-5 months <br />. After further review,
licensee management stated that these individuals had met the requirements of
NAP 5, because they had worked 6- 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts during the periods in question,
and that the hours over 72, were the result of long turnovers. The licensee initiated
AR 980318079 to document and evaluate the results of their audit and the
corrective actions taken. Licensee management strongly stated that the results of
this audit did not meet their expectations for individual work hours and that
additional audits were being conducted to further unoerstand the extent of this
condition.
c.
Conclusions
The licensee's corrective actions to address the reasons for an apparently fatigued
licensed control room supervisor were acceptable. However, there were some
weaknesses identified in licensee management oversight of individual employee
work hours which the licensee has initiated actions to address.
08
Miscellaneous Operations Issue
0.8.1. (Closed) LER 50-311 /98-04: Failure to Comply with Technical Specification
Surveillance Requirement 4.1.3.1.1.
On February 4, 1998, the rod position deviation monitor was declared inoperable
when it was determined that the Plant Processing Computer System (P250) was
f
5
not updating the. rod position deviation computer data point "RODD EV". The
"RODDEV" data point provides the input to an overhead alarm window which
automatically alarms when the rods deviate beyond the required number of steps
from the group demand counter. This computer point is the rod position deviation
monitor required by Technical Specification Surveillance Requirement 4.1.3.1.1. On
November 21., 1997, the computer point was disabled, apparently without
informing the control room personnel. Since the operators were not aware that the
rod position deviation monitor was inoperable, control rod positions were not
verified every four hours as required by Technical Specification 4.1.3.1.1, however,
they were verified once per shift. The licensee concluded that the apparent cause
of the event was attributed to human error. Corrective actions associated with this
event consisted of a lesson learned discussion and the implementation of periodic
reviews of the P250 computer points to ensure Technical Specification associated .
points are not disabled.
Based *an the minimal safety significance of this condition, the inspector performed
an in-office review of the information provided in this LER. The inspector found the
licensee's root cause and corrective actions discussed to be acceptable. Therefore,
this licensee identified and corrected violation of Technical. Specification
Surveillance Requirement 4.1.3.1.1 is being treated as a Non-Cited Violation
consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-311/98-
01-02)
0.8.2 (Closed) LER 50-311/98-05: Technical Specification Required Shutdown of Salem
Unit 2 Due to the Failure of the 2A Emergency Diesel Generator Turbocharger.
This LER documents the February 11, 1998 controlled shutdown of Salem Unit 2 as
required by Technical Specification 3.8. 1.1, following the failure of the 2A
emergency diesel generator (EOG) turbocharger. Since the licensee's root cause
analysis and corrective actions for this event were previously reviewed and
documented in Section M8.1 of this report and Section E.7.2 of NRC Inspection
Report 50-272 & 311 /98-81, the inspector performed an in-office review of this
- LER. The inspector found that no new information was provided and that no
additional inspection effort was warranted; Therefore, this LER is closed.
II. Maintenance
M1
Conduct of Maintenance (50001, 62707, 61726, 92902, & 40500)
M 1 . 1 General Comments
The inspectors observed all or portions of the following work activities and
Technical Specification surveillance tests:
W/O 950606013:
13 AFP Overspeed Trip Test
6
W/O 970916012:
21 EDG Lube Oil Heater Clean and Inspection
W/O 971006167:
Replace 2PR3
W/O 970818068:
Replace 2PR4
. W/O 971006167:
Repair 22 SG Steam Flow Channels (2FT523
and 2FA3472)
W/O 980131065:
2C EDG Watt Meter Transducer Replacement
W/O 980205085:
2B EDG Reliability Run While 2C EDG Inoperable
W/O 970120269:
2A EDG Lube Oil Cooler Jacket Water Heat
Exchanger dp Transmitter Work
W/O 980301186:
Inspect 23 Service Water Strainer
W/O 980301188:
Inspect 21 Service Water Strainer For Possible
Bypass
S2.0P-ST.SJ-0001:
Safety Injection Pump lnservice Test
S2.0P-ST.DG-001:
2A EDG Surveillance Test
SC. CH-CA.ZZ-0325:
Boron Sample by Titration of RWST Sample
S1 .RA-ST.SJ-0002:
12 Safety Injection Pump lnservice Testing
The inspectors observed that the plant staff performed the maintenance effectively
- within the requirements of the station maintenance program, and that the plant
staff did surveillances safely, effectively proving operability of the associated
system. Minor deficiencies noted by the inspector during .. the performance of the
refueling water storage tank boron sample and analysis were promptly corrected by
the licensee.
M1 .2 Wrong Control Switch Installed on 12 Diesel Fuel Oil Transfer Pump
a.
Inspection Scope
b.
The licensee discovered during the 31-day surveillance run of the 12 Diesel Fuel Oil
Transfer Pump (DFOTP) on February 19, 1998, that the pump would not start in
automatic when required to do so. Troubleshooting revealed that the wrong control
switch was installed on the pump. The inspector followed up on this self-revealing
event through personnel interviews and documentation review.
Observations and Findings
The licensee replaced a degraded control switch for the 12 DFOTP on January 30,
1998. .On February 19, 1998, while performing the 31-day surveillance run on the
pump, it would not start in automatic control when the fuel oil day tank dropped to
the appropriate level. Troubleshooting revealed that the wrong control switch was
installed on January 30, which prevented the automatic start of the pump,
rendering it inoperable. Unit 1 was in Mode 5 at the time the wrong switch was
installed on January 30. Technical Specification (TS) 3.8.1.2 requires one of the
two DFOTPs to be operable in Mode 5. However, the licensee entered Mode 4 on
February 18 at 8:35 a.m., and TS 3.8.1.1.b.2 requires two DFOTPs to be operable
in Mode 4. The 12 DFOTP was restored to operable status on February 20 at 2:31
c.
7
a.m. The licensee's ascension to Mode 4 with one of two DFOTPs inoperable was
a violation of TS 3.8.1.1.b.2.
(VIO 50-272/98-01-03)
The inspector determined that there were multiple failures which caused this event.
The Planning Department listed the wrong part number for the control switch on the
work order (WO) and staged it for the work. Additionally, the WO listed the wrong
print number for the electrical panel where the switch is located, and listed another
print which does not exist. The post-maintenance test (PMT) was inadequate in
that it did not test the automatic start feature of the pump. The PMT described on
the WO was not specific, and operations and maintenance personnel did not
question its adequacy.
The technician who performed the work did not verify the correct switch part
number when replacing the switch. Also, he did not recall having the appropriate
electrical drawings at the work site per management expectations, and did not
verify proper operation of electrical contacts controlled by the switch after the work
was done. Any of these actions would have revealed that the wrong control switch
was installed.
The licensee's immediate corrective actions for this event were weak. A technician
documented on February 19 that he had verified that the other three DFOTPs had
the correct control switches. However, the 2A EOG was protected at the time due .
to maintenance on another EOG, so he did not verify the 21 DFOTP .. He
remembered this omission on February 27 and checked it for the correct control
switch. He discovered that this DFOTP also had the wrong part number. This
switch had been replaced in January 1994 with the wrong part number, but had
passed all surveillance tests (STs) since then. The licensee did not know how the
21 DFOTP control switch was placed in its present configuration with the wrong
part number. However, the switch appeared to function as designed.
Initially, there was no analysis performed to verify operability of the 21 DFOTP
control switch for this abnormal configuration. Rather the licensee concluded that
the 21 DFOTP was operable since it had passed all STs. The inspector brought this
issue to management's attention on March 12, 1998. The Operations Manager
stated that the 21 DFOTP was operable and the licensee ascended to Mode 1 on
March 14 with no documented operability determination (00). Subsequently, the
licensee performed an OD on March 16, which the inspector concluded was
adequate, but not timely. Additionally, the licensee did not verify correct part
numbers for the remaining six control switches on each DFOTP electrical panel,
three of which have the same control switch as the DFOTP, until questioned by the
inspector.
Conclusions
Poor planning and inadequate maintenance practices resulted in an incorrect control
switch being installed on the 12 Diesel Fuel Oil Transfer Pump (DFOTP), which
- ----
- -* ----------------------------------
8
rendered the 12 DFOTP inoperable. The licensee ascended to Mode 4 on Unit 1
with less than the required DFOTPs operable, which was a Technical Specification
violation. The licensee's immediate corrective actions for this event were weak,
including an untimely operability determination for the wrong part being installed on
the 21 DFOTP, and untimely verification of correct part numbers for similar control
switches on the four DFOTP electrical panels.
M1 .3 Post-Maintenance Testing of 2A Emergency Diesel Generator after Turbocharger
Failure
a.
Inspection Scope
b.
The inspector followed up on licensee post-maintenance testing (PMT) activities on
the 2A EOG following the February 11, 1998 turbocharger failure.
Observations and Findings
On Thursday, February 19, 1998~ maintenance personnel were completing
maintenance activities on the 2A EOG in accordance with procedure SC.MD-ST.DG-
0003, "Eighteen Month Diesel Engine Inspection Maintenance." The maintenance
supervisor ordered technicians to close the EOG petcocks in preparation for
returning the diesel to operation. Although the technicians stated that they closed
the petcocks, this was not documented in step 5.17.4 of the procedure, as
required.
On Friday, February 20, 1998, operations personnel barred the diesel over in
accordance with procedure SC.OP-PT.DG-0001, "Diesel Generator Manual* Barring,"
in preparation for running the engine. This procedure requires the diesel petcocks
to be open for barring and closed for running the engine. Nuclear equipment
operators signed off the procedure indicating that the petcocks were closed ~nd
independently verified (IV'd) as such. But when the diesel was subsequently
started, the petcocks were found open because the operators did not understand
how to properly position the petcocks.
On Sunday, February 22, 1998, at 1 :35 a.m. operators started the 2A EOG in
accordance with procedure S2.0P-ST.DG-0001, "2A Diesel Generator Surveillance
Test" for an operability and 24-hour surveillance run. During the run, a
maintenance engineer noted a strange sound coming from the left side of the
engine. The operator checked engine cylinder temperatures and noted that the 5-
Left cylinder temperature indicated that it was not firing. Further investigation
revealed that the 5-Left cylinder fuel pump was locked out. All other cylinders were
checked with no discrepancies noted. The 5-Left cylinder was restored and the 2A
EOG run was completed successfully.
Step 5.17 .9.M of the above mainten!3nce procedure requires that cylinder fuel pump
racks be checked unlatched (not locked out) and IV'd* as such. Procedure review
9
showed that the IV line was signed off, but not the initial check. Interviews with
the technicians revealed that ttie initial* check was completed but not signed off,
and no IV was completed, but was signed off. Additionally, the maintenance
supervisor signed the procedure without recognizing that the step 5.17.9.M initial
check was not signed off.
The licensee took immediate corrective actions for the open petcock and cylinder
lock-out issues, including stopping work to remediate personnel involved, and
reviewing lessons learned with all maintenance personnel the week following the
errors. The licensee is also planning other long-term corrective actions to address
these issues.
In the above instances, maintenance and operations personnel failed to comply with
station procedures for the control of safety-related systems. These licensee
identified failures are a violation of TS 6.8.1 which requires that written procedures
be implemented for safety-related equipment recommended in Appendix "A" of
Regulatory Guide (RG) 1.33, Revision 2, February 1978. This RG recommends that
written procedures be implemented for control of EDGs. (VIO 50-311/98-01-04)
c.
Conclusions
Procedural adherence for the 2A Emergency Diesel Generator post-maintenance
testing was poor. Numerous procedural violations by maintenance a_nd operations
personnel resulted in the improper operation of the diesel. There was little safety
significance to these violations as the diesel was out of service for maintenance.
However, they showed a lack of questioning attitude and attention to detail by
numerous personnel. Additionally, the engineering action plan utilized for the
maintenance effort was not sufficiently detailed to promote smooth transition
between the maintenance and operations procedures used.
M2
Maintenance and Material Condition of Facilities and Equipment
M2. 1 High Crankcase Pressure Alarm on the 28 Emergency Diesel Generator During a*
Technical Specification Required Run
a.
Inspection Scope
The inspector observed the February 3, 1998 run of the 28 EOG, which was *
required by TS 3.8.1.1.b due to the 2C EOG outage for maintenance. The 28 EOG
was shut down when the "Crankcase Blower Failure" alarm was received. The
inspector followed up on this shutdown, the trouble-shooting of the cause of the
alarm, and the post-maintenance EOG run after the problem was corrected ..
10
b.
Observations and Findings
On February 3, 1998, licensee operators were running the 28 EDG to satisfy TS 3.8.1.1, action b, since the 2C EDG was out of service for maintenance. The 2C
EDG maintenance placed Unit 2 in a 72-hour shutdown action statement and
required running the 2A and 28 EDGs to show reliability. Approximately 13
minutes after the diesel was fully loaded, the "Crankcase Blower Failure" alarm was
received. The operator correctly carried out the alarm response procedure and
attempted unsuccessfully to reset the alarm. Therefore, the 28 EDG was shut
down and declared inoperable by the Control Room Supervisor, who was observing.
the diesel run. This placed the plant in a two-hour shutdown action statement, due
to the inoperability of two diesels.
After the diesel was shut down, the operator again attempted to reset the alarm
and this time was successful. Subsequent investigation revealed that the three-
way root valve for the crankcase pressure switch had apparently vibrated out of
position, porting air manifold pressure to the switch instead of crankcase pressure.
Crankcase pressure is normally at vacuum, while air manifold pressure is at a
vacuum with the diesel unloaded or lightly loaded, but at pressure when the diesel
is loaded. This caused a false high crankcase pressure indication. The three-way
valve was positioned correctly, and the 28 EDG was re-started with a Heise
pressure gage connected to read crankcase pressure. This gage indicated normal
pressure (about -1.2 inches we) for the remainder of the run and no more alarms
were received. The 28 EDG was declared operable approximately 13 minutes
before the two-hour action statement expired.
The inspector questioned the Operations Superintendent concerning his operability
determination. The OS declared the diesel operable after 20 minutes of the one-
hour surveillance run after the pressure switch problem was corrected. He stated
that since the alarm was received 13 minutes after the diesel was fully loaded, and
that he was confident that the problem was corrected, he could declare the diesel
operable after a similar amount of time (20 minutes) of a loaded run, once he had
verified that the crankcase pressure was satisfactory. The Operations Manager
concurred with that decision, and further stated that if other problems arose during
the remainder of the one-hour run, that he would have used the original failure time
(not the time the diesel was declared operable) to calculate time available before
plant shutdown was necessary. The inspector concluded that these actions were
satisfactory.
The inspector also questioned the OS concerning the timing of the 28 EDG
reliability run. At the time of the run, the 2C EDG was out of service for on-line
maintenance, which placed the plant in a 72-hour action statement, and which
required the licensee to run the remaining two diesels within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of declaring
the 2C inoperable. The 2A EDG was successfully run prior to taking the 2C EDG
- out of service. However, the 2C EDG was taken out of service at approximately
6:00 a.m. and was scheduled to be out of service for about 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />. The
11
inspector questioned why the 28 was run at 11 :00 a.m. that same morning instead
of waiting until work was completed on the 2C. The OS stated that he was fully
confident that the 28 EDG was operable and he did not anticipate any problems
with running it. The inspector concluded that, based on the intended outage time
of the 2C EDG, that it would have been more appropriate to run the 28 EDG before
the 2C was taken out of service.
The inspector asked the diesel system manager if the crankcase pressure switch
was required to be calibrated. He stated that it was calibrated every three years,
but that due to the present operational schedule, the calibration had been deferred
from November 1997 to the next refueling outage in January 1999. The system
manager stated that he intended to move the calibration of the switch up to the
summer of 1998. The inspector concluded that since the pressure switch provided
an alarm function only, and not a protective function, that the calibration deferral
was acceptable.
c.
Conclusions
The licensee met all Technical Specification requirements for the 2C emergency
diesel generator (EOG) outage and the crankcase alarm on the 28 EDG. The
operator correctly followed the alarm response procedure for the 28 EDG alarm.
The operability determination for the 28. EDG after the cause of .the alarm was
determined was adequate, but the decision to run the 28 EDG during. the 16-hour
2C EDG outage was not appropriate.
MS
Miscellaneous Maintenance Issues
MS. 1 2A Emergency Diesel Generator Turbocharger Blade Failure
a.
Inspection Scope
b.
Approximately 44 minutes into a post-maintenance test on February 11, 1998, the
Unit 2, 2A emergency diesel generator (EDG) turbocharger failed. The licensee
formed a team to get the relevant facts, find the cause of the failure, evaluate its
significance relative to the operability of the other EDGs, and establish corrective
actions. In the month after the failure, the NRC resident inspector sampled the
work of the team and a regional based engineering inspector met with team
members to review the scope of activities of the team and its conclusions.
Observations and Findings
The turbocharger failure occurred when one rotating blade on the engine exhaust
gas input side of the ~urbocharger broke loose subsequent to fatigue cracking of the
blade where it was mechanically rooted in the rotor assembly.
The team, formed
to evaluate the failure, included in its scope: an examination of the diesel engine
internals to verify that no engine components had been exhausted into the
..
12
turbocharger; review of the history of the turbochargers on each Salem EDG;
review of previous industry turbocharg*er failures; metallurgical and chemistry
analysis on the blades and debris; dynamic factors, event facts, root cause and
change analysis; and turbocharger service life. By March 12, 1998, most of the
evaluation work of the team was complete, but the analysis of the dynamic factors
that may or may not have led to the failure was in progress by an industry expert
on turbines. In summary, the team conducted an extensive evaluation of the
failure.
c.
Conclusions
On February 11, 1998, the Unit 2 emergency diesel generator (EDG) turbocharger
failed during a post-maintenance test. The licensee formed a team to get the
relevant facts, find the cause of the failure, evaluate its significance to the other
EDGs and establish corrective actions. The NRC reviewed the evaluation scope,
methods and results. This NRC inspection concluded that the preliminary root
cause evaluation of the failed turbocharger blade was thorough, detailed, and
accurate~ The inspector concluded that the licensee had properly responded to the
EDG turbocharger failure by initiating a thorough evaluation.
M8.2 (Closed) LER 50-272/96-05; Supplements 6 through 16: Technical Specification
Surveillance Requirement Implementation Deficiencies
These supplemental reports documented additional findings of the Technical
Specification Surveillance Improvement Program (TSSIP), the licensee's long-term
corrective action plan for surveillance testing deficiencies originally described in LER 96-005. The TSSIP project was initiated for Salem station as part of the corrective
actions taken by PSE&G regarding surveillance deficiencies identified at Hope Creek
(reference violation 50-354/95-11-02). Although these reports identified different
surveillance requirements that were not appropriately implemented for ensuring
technical specification requirements were met, the licensee took timely corrective
action, demonstrated operability of the required equipment in each case, and
provided adequate bases that no safety consequences resulted from the testing
inadequacies. The associated root caus'e for these supplemental reports were the
same as for supplemental reports one through five and constituted a violation of
NRC Test Control requirements per 10 CFR 50, Appendix 8, criterion XI. However,
based on licensee identification and action taken to correct these deficiencies, this
violation is being treated as a non-cited violation consistent with Section VII of the
NRC Enforcement Policy. (NCV 50-272 & 311/98-01-05)
These minor issues were closed based on an in-office review of the licensee-
provided information. However, the inspector also reviewed selected testing
procedures to verify the licensee had implemented adequate procedural changes to
address the deficiencies, as detailed in the LER. *No discrepancies were identified .
..
13
The inspector noted that PSE&G prioritized and completed their actions in response
to Generic Letter (GL) 96-01, "Testing of Safety-Related Logic Circuits" as
described in their letters to the NRC dated April 16, 1996, and January 15, 1998,
as part of the TSSIP. As the licensee stated in their letter dated January 30, 1998,
these implementing procedures related to GL 96-01 review were completed for both
Salem Units 1 and 2. Additionally, PSE&G appropriately assigned the next highest
priority to technical specification procedures associated with relatively high risk
surveillances and safety-related systems and the lowest priority to those procedures
with relatively low risk surveillances and nonsafety-related systems. Further, the
inspector noted that the licensee extended their commitment to complete their
review of the remaining procedures from December 1997 to May 1998. However,
the licensee stated that the higher priority procedures would be completed prior to
Unit 1 restart/entry into Mode 2. At the time of this inspection the licensee had
completed their review of 1, 185 of the 1,293 (92%) technical specification
implementing procedures. Based on the minor significance of all of the identified
procedural deficiencies for both Units 1 and 2 as well as those enveloped by the
Hope Creek TSSIP program, the inspector .determined that the risk associated with
restarting Unit 1 without completion of the lower priority procedure review was
minimal and acceptable.
Ill. Engineering
E1
Conduct of Engineering (Tl 2515/109, 37551, 40500 & 92903)
E1 .1
Generic Letter 89-10 Motor-Operated Valve Program Review and (Closed) NRC
Programmatic Restart Issue 111.a.23: Adequacy of Motor-Operated Valve Program
(Unit 1)
a.
Inspection Scope
On June 28, 1989, the NRC issued Generic Letter (GL) 89-10, "Safety-Related
Motor-Operated Valve Testing and Surveillance," requesting licensees to establish a
program to ensure that switch settings for safety-related motor-operated valves
(MOVs) were selected, set, and maintained properly. Seven supplements to the GL
have been issued to provide additional guidance and clarification. NRC inspections
of licensee actions implementing the provisions of the GL and its supplements have
been conducted based on the guidance provided in NRC Temporary Instruction
2515/109. The most recent inspection of MOV activities at Salem was
documented in IR 50-311/97-03, dated April 3, 1997, when the NRC's review of
the GL 89-10 program for Salem Unit 2 was closed (Unit 1 was not inspected).
The purpose of this inspection was to review the actions implemented at Salem
Unit 1 to closeout programmatic restart item 111.a.23 and determine if those actions
were sufficient to warrant closure of the NRC staff's review of the GL 89-10
program. Since the MOVs for both Salem Units are similar, the inspection focused
b.
14
on any performance differences between the Unit 1 and 2 MOVs, and included. the
review of:
1.
Specific MOV issues experienced during the Salem Unit 2 review.
2.
Load sensitive behavior, stem friction coefficient, and degradation margin.
3.
Specific MOV problems encountered at Salem Unit 1.
4.
Thrust margin improvement plans.
5.
Measures to monitor industry actions regarding operator and motor
performance.
6.
Licensee's actions regarding existing MOV open items for Salem Unit 1.
The inspectors reviewed PSE&G'S-l-VAR-NEE-1266, "Generic Letter 89-10 Closure
Summary for. the Motor Operated Valve Program As Implemented at Salem Unit 1,"
Rev. 0, and documents associated with all MOVs in the GL 89-10 program. The
closure summary document was in draft stage during the initial onsite inspection. It
was completed on February 1, 1998, and further reviewed in-office by the
inspectors. In addition to the onsite visit of January 15 and 16, 1998, comments
on the closure summary document were discussed on several instances afterwards
during a conference call on February 4, 1998, and most recently on March 4, 1998.
The findings discussed below refer to Revision 0 of the closure summary document
although PSE&G had issued Revision 1 to address the inspectors' comments. The
inspectors also referred to the similar document, S-C-VAR-NEE-1117, Revision 1,
"Generic Letter 89-10 Closure Summary for the Motor Operated Valve Program As
Implemented at Salem Unit 2," that had been used as a basis for the closeout of
the Salem Unit 2 MOV program.
Observations and Findings
Two main program documents govern MOV activities at Salem. These documents
are (1) Programmatic Standard NC.DE-PS.ZZ-0033(0) which includes many.
appendices providing details for design basis reviews, MOV capability assessments,
etc; and (2) Program Position Papers EE:A-O-ZZ-MEE-0609 which provide licensee
positions on many MOV technical issues such as temperature effects* on motor
- performance. The inspectors confirmed that significant changes had not been made
to these MOV program documents. Essential program elements, such as the
definition of MOVs in the program scope, tracking and trending of MOV
performance, and post maintenance practices, were in place at Salem Unit 1 similar
to that observed during the Salem Unit 2 review. The inspectors verified that the
residual heat removal discharge-to-hot leg isolation valve, 1 RH-26, had been added
to the MOV program scope and had been dynamically tested. The comparable
15
valve, 2RH-26, had also been added to the GL 89-10 MOV program at Salem
Unit 2. There were no other MOV program scope changes.
PSE&G dynamically tested about 50% of the 95 MOVs in the GL 89-10 program at
Salem Unit 1 . PSE&G provided information for the 95 MOVs which were grouped
into 16 MOV families. The inspectors reviewed the following MOV families where
specific issues had been discussed during the closeout review of the Salem Unit 2
MOV program.
Specific MOV Issues Experienced During the Salem Unit 2 Review
Family 6: 14" Copes Vulcan 2500 psi Parallel Double Disk Gate Valves
This family consisted of the reactor coolant system (RCS) hot leg to residual
heat removal (RHR) suction header valves (1 RH1 and 1 RH2). The
- comparable valves (2RH 1 and 2RH2) had been discussed during the MOV
program review at Salem Unit 2. Specifically, PSE&G revised its initial 0.55
valve factor basis for these valves to 0.61 which was based on the
maximum value of valves tested at Salem Unit 2. This was considered
acceptable for GL 89-10 program closure based on PSE&G's commitment to
pursue an improved valve factor basis for these valves as part of their
periodic verification program.
For Salem Unit 1, PSE&G continued to assume a valve factor of 0.61 for
these valves. Using a design basis differential pressure (DBDP) condition of
381 psid, a stem friction coefficient of 0.20, actuator pullout efficiency, and
a 212°F environment for the actuator temperature to determine motor
performance, PSE&G calculated a thrust margin of 16% and 11 % for 1RH1
and 1 RH2, respectively. In pursuing an improved valve factor basis as part
of the periodic verification program, PSE&G agreed to use the Electric Power
Research Institute (EPRI) Performance Prediction Methodology (PPM). Also,
efforts would continue with other reactor facilities to seek valve factor
information regarding these valves. The plan to further assess these valves
was included in the licensee's corrective action program by revising an
existing Action Request 970418119 which had been issued to address the
issues from the Salem Unit 2 MOV program review. The inspectors
considered PSE&G's actions acceptable for restart. An inspector Followup
Item (IFI 50-272/98-01-06) is opened to verify implementation of this action
for GL 89-10 program closure.
Family 9: Power Operated Relief Valve (PORV) Block Valves (1 PR6 and
1 PR7)
PSE&G modified the Salem Unit 2 PORV block valves to operate them based
on limit switch control, and thereby take advantage of full actuator motor
capability for valve closing. A similar modification has been accomplished
16
for the Salem Unit 1 valves. PSE&G calculated the thrust margin to be 19%
and 8% for 1PR6 and 1PR7, respectively, based on a DBDP of 2510 psid, a
0.61 valve factor, a 0.20 stem friction coefficient, and using actuator pullout
efficiency in demonstrating design basis capability. (Note: Similar parameters
were used during the Salem Unit 2 review.)
In following up on an issue discussed during the Salem Unit 2 review,
PSE&G acknow.ledged that they had not fully addressed the NRC request
regarding the adequacy of the valve factor basis and any non-predictability
for these valves. Internal dimensions had been taken for the Salem Unit 1
valves to assist in determining the valve predictability and thrust
requirements at both Salem Units in accordance with the EPRI PPM.
However, since this dimensional information had not yet been translated into
a calculation of a design standard valve factor according to the EPRI PPM,
PSE&G intends to complete these calculations (Action Request 970418119).
PSE&G stated preliminary calculations indicated that there were no
nonpredictability concerns for these valves. The inspectors considered
PSE&G's actions acceptable for restart. IFI 50-272/98-01-07 will include
verification of licensee completion of these calculations for GL 89-10
program closure.
Family 9: Reactor Coolant Pump (RCP) Thermal Barrier Isolation Valves
(1CC131 and 1CC190)
Both RCP thermal barrier* isolation valves reviewed during the Salem Unit 2
inspection demonstrated positive thrust margins, with valve 2CC131 the
least at 8% using torque switch control in the closed direction. While this
was considered acceptable for GL 89-10 closure, PSE&G plans to take
measures to improve the actuator capability for these MOVs. PSE&G also
plans to confirm the adequacy of the valve factor basis and to evaluate any
non-predictability for these valves as part of the Salem Unit 2 periodic
verification program.
Both RCP thermal barrier isolation valves at Salem Unit 1 were modified in
accordance with design change DCP lEE-0368 to operate under limit switch
control to improve their design basis capability. A similar modification will
be implemented at Salem Unit 2 during the next refueling outage. Based on
- a DBDP of 2241 psid, a 0.61 valve factor, a 0.20 stem friction coefficient,
and using actuator pullout efficiency in demonstrating design basis
capability, PSE&G calculated a thrust margin of about 30% for the Salem
Unit 1 valves which was acceptable.
In following up on an issue discussed during the Salem Unit 2 review (similar
to the discussion above for 1 PR6 and 1 PR7), PSE&G acknowledged that
they had not fully addressed the NRC request regarding the adequacy of the
valve factor basis and any non-predictability concerns for these valves.
17
Accordingly, PSE&G plans to complete calculations using the EPRI PPM to
evaluate these issues (Action Request 970418119). PSE&G stated
preliminary calculations indicated that there were no non-predictability
concerns for these valves. The inspectors considered PSE&G's actions
acceptable for restart. IFI 50-272/98-01-07 wiil include verification that the
calculations were completed for GL 89-10 program closure.
Load Sensitive Behavior, Stem Friction Coefficient, and Degradation Margin
The Salem Unit 2 Closure Summary included a statistical analysis of 75 data points
and determined an average load sensitive behavior of 3. 7% with an associated
standard deviation of 9.6%. To properly account for load sensitive behavior,
PSE&G's error analysis added 4% error in thrust calculations directly as a bias
margin, and an additional 21 % error as a random value that was included with
other uncertainties using the square root sum of the squares method. Also, PSE&G
had co.mpleted a comprehensive stem friction coefficient review of the results from
in-plant testing to justify the use of a stem friction coefficient value of 0.20 and
revised their setup methods to include a 5% bias margin to account for
degradations as a part of their standard error analysis. The results of the analyses
for load sensitive behavior, stem friction coefficient, and degradation margin were
included in the Salem Unit 2 Closure Report (S-C-VAR-NEE-1117, Revision 1) as
Attachments 19, 20, and 21, respectively.
The additional data obtained from Salem Unit 1 testing done during the past year
was factored into updated analyses for load sensitive behavior, stem friction
coefficient, and degradation margin. This data supported the Salem Unit 2 data and
did not invalidate any of the conclusions. It was included in similar Attachments to
the Salem Unit 1 Closure Report (S-l-VAR-NEE-1266) where PSE&G concluded that
the margins allocated for load sensitive behavior (4% as a bias and 21 % as a
random value) and degradation (5% as a bias) and the stem friction coefficient
value of 0.20 for the Salem Unit 1 MOVs should be the same as that established
for the Salem Unit 2 MOVs. Where stem friction coefficient values just above 0.20
were experienced for 1CC118 (0.21) and 12CC3 (0.22) during recent differential
pressure testing, PSE&G plans to inspect and correct these conditions. It is noted
that these MOVs did demonstrate positive thrust margins.
The inspectors found this approach for addressing load sensitive behavior, stem
friction coefficient, and degradation margin to be acceptable for Salem Unit 1
restart. Inspector followup item (IFI 50-272/98-01-08) is opened to verify
. completion of the PSE&G actions regarding correction of the high stem friction '
coefficient values of 1 CC118 and 12CC3 as part of the licensee's MOV periodic
verification program being implemented per GL 96-05, "Periodic Verification of
Design-Basis Capability of safety-Related Motor-Operated Valves."
18
Specific MOV Problems Encountered at Salem Unit 1
Family 5: 6" Anchor Darling 150 psi Parallel Double Disk Gate Valves
The RCP bearing cooling water outlet containment isolation valves (1CC136
and 187) are six-inch Anchor Darling, double disk gate valves. (Note: During
the Salem Unit 2 review, PSE&G agreed to improve the thrust margin of
2CC136.) Both 1CC136 and 187 exhibited high closing forces during recent
dynamic testing at Salem Unit 1 .. Each valve failed to close during the initial
dynamic test on December 30, 1997, with the valves set at the as-found
torque switch settings. No similar failure-to-close problems were
experienced with the related 1 CC117 and 118 valves in this family although
1 CC117 did exhibit a higher than expected valve factor of 0.68 based on its
differential pressure test at 73% of design basis conditions. PSE&G plans to
. repeat this test during the next refueling outage.
Since the* component cooling water system had been de-chromated for an
extended period, corrosion products in the valve internals were attributed, in
part, to the poor performance. This parallel disk valve design is intended to
force the disks apart by the sliding action of angled upper (or fixed) and
lower disk (or floating) wedges (sometimes called wedge shoes). Valves
with the upper wedge located downstream of the flow (the non-preferred
direction) can require more thrust to achieve full wedging of the disk into its
seat. To enhance the valve performance, the wedge shoes for these valves
\\
in Salem Units 1 and 2 had been ~odified in the past year with stellite
hardfacing. The performance of 1CC187 was worse because its wedge
shoes were found installed in the non-preferred orientation. The wedge*
shoes for 1 CC 136 were oriented correctly.
Both valves were cleaned and installed correctly. Static and dynamic tests
were performed satisfactorily. The inspectors were concerned regarding the
long term performance of these and related (1 CC117 and 118) MOVs in this
family at Salem Units 1 and 2. To address these concerns, PSE&G plans to
do the following:
Unit 1: Issue action requests to perform differential pressure testing of
1CC117&118 at degraded voltage at the start of the next Unit 1 refueling
outage. Open and inspect the valv1es to verify correct wedge shoe
orientation. Expand the testing scope to 1CC136 and 1CC187 if there is a
significant change in valve performance.
Unit 2: Issue action requests to perform differential pressure testing of
2CC 117, 2CC 118, 2CC 136, and 2CC 187 at degraded voltage at the start of
the next Unit 2 refueling outage. Open and inspect the valves to verify
correct wedge shoe orientation if there is a significant change in valve
performance since the last differential pressure test.
. 19
The inspectors considered PSE&G's actions acceptable for restart. Inspector
followup item (IFI 50-272/98-01-09) is opened to verify completion of these
actions as part of the licensee's MOV periodic verification program being
implemented per GL 96-05.
Measures to Monitor Industry Actions Regarding Actuator Performance
The inspectors reviewed the licensee's measures taken and expected in response to
forthcoming information from Limitorque regarding the modification of previously
published actuator efficiencies. This subject had also been addressed in NRC
Information Notice 96-48, "Motor-Operated Valve Performance Issues."
As explained in Attachment 22, "Actuator Efficiency Evaluation," of the Salem
Unit 1 MOV program summary report, PSE&G has performed many differential
pressure tests at degraded voltage at Salem Units 1 and 2. This was done to better
characterize in plant motor performance under these conditions and to provide
assurance regarding their use of run efficiency in the closed direction for all torque
seated gate and globe valves. PSE&G indicated that it had reviewed the
information in NRC Information N-otice 96-48, it was monitoring industry
information for further developments, and any additional guidance issued on this
topic in the future by Limitorque would be reviewed and appropriate actions taken
in accordance with the Vendor Document and Corrective Action Programs.
Thrust Margin Improvement Plans
Inspector followup item 50-272/96-11-06 had been opened to review thrust margin
improvements needed for MOV 12CC16 (RHR heat exchanger component cooling
water outlet isolation valve) which previously evidenced a negative thrust margin at
design basis conditions. PSE&G has modified the control circuit to close this valve
under limit control. This action acceptably resolved the problem since the thrust
margin for the closing direction is currently about 17%.
The inspectors noted that several Salem Unit 1 MOVs were scheduled for margin
improvements. Although the following MOVs had adequate basis for the applied
thrust requirements, they had low thrust margins and were identified by the
inspectors to ensure that they were included in PSE&G's margin improvement
plans: 1CC118, 1 CC30, 1 PR7, and 1 SJ4.
The licensee was requested to review these MOVs and to include them as part of
their margin improvement program. PSE&G personnel agreed to conduct this
review. Closure of these MOVs under the GL 89-10 program was contingent upon
the licensee's agreement to improve the margin of these MOVs as part of Salem
Unit 1 's periodic verification program conducted per GL 96-05.
20
c.
Conclusions
PSE&G had adequately demonstrated design basis capability for Salem Unit 1
MOVs to support restart. Justifications for key program assumptions and the
applied valve factors were adequate to support closure of Restart Issue 111.a.23 for
Unit 1 . Regarding GL 89-10 program closure, PSE&G was requested to update and
clarify program summary S-l-VAR-NEE-1266, "Generic Letter 89-10 Closure
Summary for the Motor Operated Valve Program As Implemented at Salem Unit 1;"
consistent with the inspector followup items in this report.
E1 .2
Update on Control Area Ventilation System Issues
The Control Area Ventilation System (CAVS) is comprised of two subsystems: the
control area air conditioning system (CAACS) and the Control Room Emergency Air
Conditioning System (CREACS). When one train of CREACS is inoperable, the
CAVS cannot maintain the Technical Specification (TS) required 1 /8 inch water
column differential pressure (dp) between the control room and adjacent spaces.
As a compensatory measure, the licensee aligns CAVS in the "maintenance mode,"
wherein the adjacent spaces are vented* to atmosphere to maintain the required dp.
The licensee addressed two issues which prohibited two-unit operation while in the
maintenance mode. Engineering Evaluation (EE) S-C-CAV-MEE-1285, "Control
Room Ventilation-Radiological Contaminated Air Intrusion," was completed to
address the issue of a radiological cloud potentially entering the control room
adjacent spaces while in maintenance mode, which could affect control room
watchstanders. This evaluation confirmed that positive pressure in the adjacent
spaces from CAVS operation would prevent such an intrusion. Long-term
corrective actions to remove the necessity of maintenance mode are a TS change to
change the dp reference to the outside atmosphere instead of the adjacent spaces,
and ventilation equipment changes to increase the dp margin. The inspectors
concluded that the EE was adequate to address the radiological cloud issue.
The second issue concerned the Unit 2 Radiological Monitoring System (RMS)
inverter (power supply), which has a non safety-related battery backup. The CAVS
radiation monitors are powered from the inverter and would fail high if the inverter
was lost. This would open the CREACS air intakes on both Salem units, placing
control room personnel ;:it risk to adverse radiological conditions. The licensee
completed an operability determination for the inverter and is pursuing a design
change to provide a safety-related battery backup.
The inspectors concluded that these actions were adequate to address the two
issues mentioned. However, the long-term corrective actions mentioned above
were necessary to eliminate the need for maintenance mode. It is a time-
consuming, resource-intensive work around which ensures adequate dp margin
between the control room and the adjacent spaces. When this mode is employed,
then any circumstances which necessitate accident pressurized mode, such as an
21
inoperable CAVS radiation monitor, would require a unit shutdown to Mode 5 so
that the CREACS air intake could be lined up to a non-operating unit. This would
ensure that control room personnel dose limits are not exceeded during accident
conditions. The licensee stated that the TS change would be submitted to the NRC
within the next two weeks, and that ventilation equipment changes to increase the
dp margin are still under evaluation.
E2
Engineering Support of Facilities a_nd Equipment
E2.1
Service Water Biofouling and (Closed) LER 50-272/96~34
a.
Inspection Scope
b.
Several safety related and non-safety related service water (SW) cooled heat
exchangers (HX) experienced accelerated biofouling from marsh grass from the
Delaware River from January to March 1998. As a result, degraded plant.
conditions and in one instance, equipment inoperability occurred. The inspector
analyzed the events and the licensee's response to evaluate the effectiveness of
licensee controls to resolve this problem. The inspector also reviewed the
corrective actions specified for Licensee Event Report (LER) 50-272/96-34: service
water strainer design deficiency potentially outside design basis .
Observations and Findings
During the weeks of January 18 and 25, 1998, operators noted increasing
temperature trends on the Unit 2 turbine auxiliaries cooling (TAC) and main turbine
lube oil (MTLO) HXs. Operators also noted an increasing temperature trend on the
No. 3 station air compressor (SAC). Inspections cif the TAC, MTLO HXs and SAC
identified that the SW inlet tube sheets were clogged with river grass, which
resulted in degraded thermal performance.
On January 21, a differential pressure (D/P) test to monitor SW biofouling revealed
that the gear oil cooler exceeded the D/P limit across the HX for the 21 charging
pump. An internal inspection revealed that the inlet tube sheet was clogged with
river grass. However, SW flow through the HX was still above the minimum
required. The licensee initiated Action Request (AR) 980120280, and performed a
detailed self assessment to review the effectiveness of the SW reliability program.
Weaknesses in the licensee's response to this issue are discussed in NRC RATI
Inspection Report No. 50-272&311 /98-81, Section E4.
The self assessment revealed a lack of SW reliability program oversight that
resulted from the ongoing engineering department reorganization. Procedure
NC.NA-AP.ZZ-0039, Rev. 0, "Service Water Reliability Program," specifies that
Specialty Engineering is responsible for the implementation of the program, and that
a program manager is responsible for oversight, control, and technical. adequacy of
the program. Specialty Engineering no longer exists and no program manager was
22
assigned to ensure proper program implementation. PSE&G's commitments to
Generic Letter (GL) 89-13, "Service Water System Problems Affecting Safety-
Related Equipment," include a test program to verify the heat transfer capability of
all safety-related HXs cooled by SW. Temperature and pressure trending was
established for safety injection pump lube oil coolers, centrifugal charging pump
gear and lube oil coolers, SW pump motor coolers, and diesel generator jacket
water and lube oil coolers. Trending was not continued after the startup of Unit 2
in August 1997, since the SW reliability program manager assumed a new position
within the organization, and a new program manager was not assigned. The
licensee has assigned a new SW reliability program manager, and has delegated
trending responsibilities to the S~lem in-service testing program manager. In
addition to GL 89-13 commitments, the licensee established a SW biofouling D/P
test program in January 1998, based on industry guidance for monitoring of macro
biological fouling. At the time of inspection, only about. one half of the Unit 2
safety related HXs were D/P tested, and no Unit 1 HXs were tested. The licensee
determined, that the biofouling D/P monitoring program was not promptly
implemented.
On February 25, the 22 chiller tripped on high condenser pressure during
realignment of the control room ventilation system to normal operation. The
licensee initiated AR 980225270, and declared the chiller inoperable. Internal
inspection of the chiller condenser found river grass covering the inlet tube sheet.
Grass was also found in the chiller's recirculation pump discharge ch~ck valve,
22SW99, during a surveillance test performed one week earlier. As a result the
check valve failed its surveillance requirement. Further investigation revealed that
the chiller had passed its biofouling D/P test in January. Salem operations initiated
supplemental data logging of SW HX differential pressures after biofouling was
discovered in the 21 charging pump gear oil cooler. The inspector reviewed the
data logged by the equipment operators and noted that the SW inlet pressure
readings for the 22 chiller were being logged as failed due to clogging from river silt
since February 9. The inspector reported the data to system engineering, who were
unaware of the supplemental data. Although no requirement exists for .the logging
and evaluation of this data, the inspector concluded that a weakness existed in the
interface between operations and system engineering.
On March 1, the 21 charging pump gear and lube o'il coolers failed the biofouling
D/P test, after being in service for approximately 14 days following its D/P test
failure in January. Inspection of the coolers revealed that both were completely
clogged with river 'grass. The licensee initiated AR 980301138, which was
subsequently upgraded to significance level one to address all rec_ent SW biofouling
issues. On February 27, the licensee had assmbled an engineering team to
determine corrective actions and root causes. Immediate corrective actions
included additional Unit 2 HX inspections, D/P testing, SW strainer inspections, and
determining apparent causes. Testing and inspection revealed that the 21
component cooling water HX tube sheets were clogged with river grass. However,
SW flow remained above acceptable limits. No other biofouling problems were
23
identified. Each SW strainer consists of a rotating basket with approximately
eleven hundred perforated disks retained in place with a threaded plastic ring.
Strainer inspections revealed that two disks were missing from the 22 SW strainer
basket, and the 21 SW strainer basket internal clearance exceeded the maximum
tolerance.
Each of these conditions results in SW flow bypassing the strainer
media. While troubleshooting high D/P across the 25 SW strainer in January,
maintenance workers found two disk retaining rings partially backed out.
Inadequate maintenance practices were attributed to this condition.
The engineering team determined the apparent cause to be elevated river grass level
compound.ed with degraded strainer conditions, noncontinuous traveling screen
operation, and lack of appropriate HX biofouling trending. On March 12, abnormal
operating procedure SC.OP-AB.ZZ-0003, Rev. 0, "Component Biofouling," was
implemented. SC.OP-AB.ZZ-0003 specifies operator actions to be ta.ken for
excessive river grass loading, such as continuous SW traveling screen operation and
more frequent biofouling D/P testing and data logging. The licensee is also planning
to perform internal SW strainer inspections during the associated SW pump
bimonthly silt inspection. The inspector concluded that the implementation of the
abnormal operating procedure and the more frequent strainer inspections would
adequately detect any significant SW biofouling.
During the previous Unit 1 and 2 refueling outages, SW pump discharge strainers
were modified by design change packages 1 EC-3685 and 2EC-3600..
Strainer disk
hole sizes were increased from 1 /32" to 1 /16", and the backwash setpoint was
lowered from 7 psid to 5 psid. The modification was made to improve strainer
reliability, because the strainer motors were experiencing overload trips that
resulted from high D/P across the strainer disks. Additionally, design calculations
assumed that an average of one SW strainer would operate continuously in
backwash mode during accident conditions. An engineering review determined that
the disks with 1 /32" diameter holes may cause more frequent strainer backwash
cycles resulting in more than one strainer in backwash mode during accident
conditions. 1he licensee reported this condition in LER 50-272/96-034. PSE&G
attributed the cause of this reportable condition to the failure to recognize long term
clogging effects on the strainer disks. The filter disks were replaced along with a
recurring task to inspect the SW strainer disks.r The inspector reviewed the 10 CFR
50.59 applicability review for this modification and did not note any problems. This
LER is closed.
The Salem SW system is susceptible to biofouling from river grass, and
accumulation of grass in components may occur over extended periods of time.
Several indications of accelerated SW biofouling existed before the 22 chiller
tripped. However prompt management actions to determine and correct the causes
were not initiated until the after the chiller tripped. The licensee's corrective
actions were mainly focused on Unit 2 and did not include a detailed evaluation of
SW biofouling effects on Unit 1. The inspector also noted that on January 25,
maintenance identified that the 14 SW strainer had one disk missing, however no
24
AR was initiated until questioned by the inspector on March 13. Failure to promptly
identify and correct SW biofouling problems is a violation of 10 CFR 50, Appendix
8, Criterion XVI, Corrective Action (VIO 50-272 & 311/98-01-10).
c.
Conclusions
Elevated grass levels in the Delaware River combined with degraded service water
strainers and lack of service water reliability program oversight resulted in
accelerated rates of service water biofouling. Weak management attention allowed
biofouling to occur at unpredictable rates. Several instances of biofouling occurred
in plant components before strainer degradation was identified and effective
corrective actions were taken. In one instance, the biofouling contributed to the
inoperability of a Unit 2 safety related chiller. Salem staff failed to take prompt
corrective actions to determine and correct the cause of service water biofouling
problems. System Engineering and Operations interfaces were weak during the
analysis of those problen:is. The licensee did not adequately evaluate the extent of
condition at both Salem Units. The inspector also concluded that the corrective
actions taken in response to Licensee Event Report 50-272/96-34 were acceptable.
Miscellaneous Engineering Issues
E8.1
(Closed) Violation 50-272/96-11-01: In NRC Inspection Report 50-272&311/96-11
violations were identified concerning inadequate test control measures during
dynamic testing conducted on valves 1 &2CV68 and 1 &2CV69 (Charging Header
Stop Valves). The inspectors determined that the differential pressures assumed by
the dynamic test analysis were uncertain because: 1) the upstream pressure
instruments did not account for the presence of pressure control valves located
between the pressure instruments and the test valves and 2) the test procedure
specified the use of a downstream pressure gage with an abnormally wide rarige
which provided insufficient sensitivity for the expected test conditions. More
importantly the questionable test data obtained was used as the valve factor basis
for the PORV block valves (1 &2PR6 and 1 &2PR7).
The inspectors had reviewed PSE&G'S corrective actions to this violation for Salem
Unit 2 and found them to be adequate as documented in IR 50-311/97-03. The
inspectors confirmed that similar corrective actions were taken for Salem Unit 1 .
For example, PSE&G reviewed other Salem Unit 1 dynamic tests to identify if
similar test control mistakes were made. No significant problems were noted.
Also, PSE&G noted that continuous pressure data acquisition was being used where
possible to enhance the accuracy of test results. This violation is now closed.
EB. 2
(Closed) Inspector Followup Item 50-272/96-11-02: Complete load sensitive
behavior study for Salem Unit 1. As documented in Section E1 .1 of this report, for
restart PSE&G _has completed an acceptable load sensitive behavior study to
establish adequate margins to account for this factor for MOVs at Salem Unit 1 .
This item is closed.
,/.
25
(Closed) Inspector Followup Item 50-272/96-11-03: Complete stem friction
coefficient study for Salem Unit1. As documented in Section E1 .1 of this report,
for restart PSE&G has completed an acceptable stem friction coefficient study for
Salem Unit 1. This item is closed ..
(Closed) Inspector Followup Item 50-272/96-11-04: Revise test feedback method
to include margin for valve degradation. As documented in Section E1 .1 of this
report, PSE&G has revised their MOV setup methodology for Salem Unit 1 to
specifically include a 5% margin for potential valve degradations. This item is
closed.
(Closed) Violation 50-272/96-11-05: Incorrect assumptions in the mechanical
design calculations for the residual heat removal suction header valves ( 1 &2RH 1
and 2) resulted in low torque switch settings. The incorrect settings for these risk
significant pressure isolation valves created the possibility that they might not close
under design-basis conditions since the torque switch was wired in series with the
limit switch for these limit-controlled MOVs. PSE&G responded to the Notice of
Violation* by letter LR-N96332 dated November 1, 1996, wherein they stated the
corrective actions to be taken to prevent recurrence for both Salem Units .1 and 2.
The inspector had reviewed PSE&G'S corrective actions to this violation for Salem
Unit 2 and found them to be adequate as documented in Inspection Report
50-311197-03. The inspector confirmed that similar corrective actions were taken
for Salem Unit 1 . For example, PSE&G had corrected the mechanical design
calculations for 1RH1 and 2 and set the torque switches to the maximum allowable
such that the torque switch settings would not prevent full closure of these MOVs.
The inspector also verified that the licensee had checked other limit controlled
MOVs, including butterfly valves, and confirmed that they were not impacted
similarly. The inspector concluded these actions to be appropriate for closing out
this item.
E8.6
(Closed) Inspector Followup Item 50-272/96-11-06: Review thrust margin
improvements needed for MOV 12CC16 (RHR heat exchanger component cooling
water outlet isolation valve) which previously evidenced a negative thrust margin at
design basis conditions. As discussed in Section E1 .1 of this report PSE&G has
modified the control circuit to close this valve under limit control. This action
acceptably resolved the problem since the thrust margin for the closing direction is
currently about 17%. Therefore, this item is closed.
E8. 7
(Closed) Inspector Followup Item 50-272/96-11-07: Request for PSE&G to
increase the capability of marginal MOVs. As discussed in Section E1 .1, PSE&G
has agreed to review measures to improve the capability of certain MOVs in
conjunction with their periodic program verification efforts. The inspectors
concluded that these actions were acceptable for closing this item .
26
.E8.8
(Closed) Inspector Follow Item 50-272/96-11-08: Verify MOV switch setting
requirements for Pratt service water system butterfly valves. Family 16 consisted
of 8" and 24" Pratt butterfly valves. Similar to the final setup of these MOVs at
Salem Unit 2, PSE&G has used the EPRI PPM butterfly model to develop the torque
requirements for the Salem Unit 1 valves. No spring pack modifications were
needed to increase the output capability as was the case at Salem Unit 2. The
inspector concluded that the methodology for setting the torque switches for these
valves was acceptable for closing this item at Salem Unit 1.
E8.9
(Closed) Inspector Followup Item 50-272/96-11-09: An independent assessment of
the Salem MOV program to evaluate its readiness for closure was conducted in
August 1995 by two individuals who were MOV project members at another
nuclear facility. The assessment appeared to be highly constructive with strengths
and weaknesses noted and various recommendations presented for assuring Salem
MOV program closure. However, PSE&G had not established firm management
controls for providing their action plans or addressing the other items in the
independent assessment report.
The inspector had reviewed PSE&G'S corrective actions regarding this issue for
Salem Unit 2 and found them to be adequate as documented in IR 50-311/97-03.
The corrective actions consisted of a formal review of the 1995 independent
assessment findings. No new issues had been identified by PSE&G then and the
licensee indicated that similarly now no new issues were developed from
subsequent reviews. The inspector concluded that this issue was resolved for
Salem Unit 1.
ES. 10 (Closed) Unresolved Item 50-272/96-11-11: PSE&G had submitted an MOV
program closure letter on June 25, 1996, for Salem Unit 1 and March 20, 1995 for
Salem Unit 2 and had not amended these letters. In light of this fact and the nature
and extent of the findings in NRC Inspection Report 50-311 /96-11, a question
regarding compliance with 10 CFR 50.9, "Completeness and Accuracy of
Information" was raised. This issue was identified as an Unresolved Item for both
Units. The issue was discussed at a public meeting held on November 12, 1996,
between PSE&G and the NRC. PSE&G indicated that engineering evaluation A-O-
ZZ-MEE-0926 served as a technical basis for the Salem Units 1 and 2 MOV
program closure letters. PSE&G maintained that there was no significant negative
information that occurred subsequent to the June 25, 1996 or March 20, 1995
letters which would have warranted an amended response. MOV changes that
were made were considered to be minor enhancements to improve performance and
were not significant deviations from the MOV program technical basis.
T_his issue was reviewed and closed out satisfactorily for Salem Unit 2 as
documented in IR 50-311/97-03. The inspector reviewed the reasons for
satisfactorily closing this issue for Salem Unit 2 and concluded that no new
significant factors developed since the Salem Unit 2 review was conducted that
should prevent closure of the issue at Salem Unit 1.
27
In summary, the inspector concluded that the question regarding compliance with
10 CFR 50.9 had been resolved in that there was not a compliance problem. This *
unresolved item is closed.
EB. 11 (Closed) Unresolved Item 50-311 /96-80-01: Single Failure Licensing Basis of Fuel
Handling Ventilation System.
This issue involved determination of the fuel handling ventilation system's original
licensing and design basis with respect to single failure. The NRC Office of Nuclear
Reactor Regulation (NRR) performed a review, and based on the research
conducted, could not conclude that the fuel handling ventilation system for Salem
Unit 2 was required to meet the single failure criterion. Therefore, no violation of
NRC requirements occurred. This item is closed.
EB.12 (Update) Violation 50-311 /97-21-05 and (Closed) LER 50-311 /96-07-02: Missed
Surveillance of Containment Penetration Overcurrent Protection Devices.
This supplement to LER 96-07 was submitted to identify that on January 30, 1998,
one additional containment protection overcurrent device for each unit was
identified as not being tested per the Technical Specification requirements. This
issue was recently discussed in Inspection Report 97-21 and Violation 50-311/97-
21-05 was issued. Therefore, the cause of the condition and the corrective actions
identified by the licensee in this LER will be reviewed as part of the licensee's
response to the violation. This LER supplement is closed.
V. Management Meetings
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on March 24, 1998. The licensee acknowledged the findings
presented. The bases for the inspection conclusions did not involve proprietary
information, nor was any such information included in this inspection report.
X2
Management Meeting Summary
On February 27, 1998, a meeting was held between the management of PSE&G and NRC
Region I and the Office of Nuclea*r Reactor Regulation (NRR), at the Salem Units 1 & 2
- Nuclear Generating Station. The purpose of the meeting was for the licensee to present an
assessment of their readiness to restart Salem Unit 1, as required by Confirmatory Action
Letter (CAL) 1-95-009. Overheads used in the licensee's presentation at this. meeting
were included as Attachment 1 to Readiness Assessment Team Inspection Report Nos. 50-
272,311 /98-81 .
IP 37551:
IP 40500:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 92901:
IP 92902:
IP 92903:
IP 92904:
IP 93702:
Tl 2515/109
Opened
/
.28
INSPECTION' PROCEDURES USED
Onsite Engineering
Effectiveness of Licensee Controls in Identifying, Resolving~ and Preventing
Problems
Surveillance Observations
Maintenance Observations
Plant Operations
Plant Support Activities
Plant Operations Followup
Maintenance Followup
Engineering Followup
Plant Support Followup
Event Followup
Inspection Requirement for Generic Letter 89-10, Safety-Related Motor-
Operated Valve Testing and Surveillance
ITEMS OPENED, CLOSED, AND DISCUSSED
50-272/98-01-03
50-311/98-01-04
50-272/98-01-06
IFI
Wrong control switch installed on 12 OF.OTP.
Failure to comply with procedures for control of EDGs.
GL 98-10; Safety-Related MOV Testing and
Surveillance Program Closure.
50-272/98-01-07
50-272/98-01-08
50-272/98-01-09
50-272&311/98-01-10
Opened/Closed
50-272/98-01-01
50-311/98-01-02
50-272&311/98-01-05
IFI
IFI
IFI
Closeout review re MOV issues of PORV block valves,
RHR/RCS isolation valves, and RCP thermal barrier
cooling valves.
Closeout review re MOV issues of stem friction
coefficient, load sensitive behavior, and stem
lubrication degradation.
Closeout review re MOV issues of RCP bearing water
cooling valves.
Failure to promptly identify and correct SW biofouling
problems.
Failure to follow procedures for maintaining SG levels.
Failure to comply with TS Surveillance Requirement 4.1.3.1.1
Test control violations related to TSSIP.
Closed
50-272/96-11-01
50-272/96-11-02
50-272/96-11-03
50-272/96-11-04
50-272/96-11-05
50-272/96-11-06
50-272/96-11-07
50-272/96-11-08
50-272/96-11-09
50-272/96-11-11
50-311/96-80-01
50-311/96-07-02
50-272/96-34
50-311 /98-04
50-311 /98-05
Discussed
50-311/97-21-05
IFI
IFI
IFI
IFI
IFI
IFI
IFI
LER
LER
LER
LER
29
Inadequate test control and application of MOV test
data
Basis for load sensitive behavior margin used in thrust
calculations
Basis for stem friction coefficient used in thrust
calculations
Basis for valve degradation margin used in thrust
calculations
Inadequate design control of switch settings for MOVs
2RH1 and 2
Improve thrust margin for 12CC16
Request to improve thrust margin for selected MOVs
Evaluate torque requirements for Pratt butterfly valves
PSE&G to evaluate and document response to MOV
program assessment.
Resolve question regarding Salem Unit 2 MOV program
completion in the context of 10 CFR 50.9(b)
Single failure licensing basis of fuel handling ventilation
system.
Missed surveillance of containment penetration
overcurrent protection devices.
Service Water strainer design deficiency potentially
outsid.e design basis.
Failure to comply with TS surveillance requirement 4.1.3.1.1.
TS required shutdown of Salem Unit 2 due to the failure
of the 2A EDG turbocharger.
Missed surveillance of containment penetration
overcurrent protection devices .
r'
CAVS
CREA CS
D/P
DBDP
DFOTPs
EOG
EE
GL
IFI
IV'd
MTLO
NRC
OS
PR
PSE&G
RATI
- RWST
SAC
TS
30
LIST OF ACRONYMS USED
Action Request
Control Area Air Conditioning System
Confirmatory Action Letter
Control Area Ventilation System
Control Room Emergency Air Conditioning System
Control Room Supervisor
Differential Pressure
Design Basis Differential Pressure
Diesel Fuel Oil Transfer Pumps
Engineering Evaluation
Electric Power Research Institute
Generic Letter
Heat Exchangers
Inspector Followup Item
Independently Verified
Motor-Operated Valve
Non-cited Violation
Nuclear Regulatory Commissio.n
Nuclear Reactor Regulation
Operations Superintendent
Public Document Room
Post-Maintenance Test
Power Operated Relief Valve
Performance Prediction Methodology
Primary Relief
Public Service Electric and Gas
Readiness Assessment Team Inspection
Reactor Coolant Pump
Reiactor Coolant system
Regulatory Guide
Reactor Operator
Refueling Water Storage Tank
Station Air Compressor
Senior Reactor Operator
Surveillance Tests
Turbine Auxiliaries Cooling
Technical Specification
- '
TSSIP
Technical Specification Surveillance Improvement Program
Updated Final Safety Analysis Report
Unresolved Item
Work Order