ML18100A818
| ML18100A818 | |
| Person / Time | |
|---|---|
| Site: | Salem, Hope Creek  |
| Issue date: | 01/06/1994 |
| From: | Barr S, Todd Fish, Marshall C, Joseph Schoppy, Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18100A816 | List: |
| References | |
| 50-272-93-23, 50-311-93-23, 50-354-93-25, NUDOCS 9401210111 | |
| Download: ML18100A818 (26) | |
See also: IR 05000272/1993023
Text
..
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report* Nos. * 50-272/93-23
50-311193-23
50-354/93-25
License Nos. DPR-70
Licensee:
Public Service Electric and Gas Company
P.O. Box 236
Facilities:
Dates:
Approved:
Hancocks Bridge, New Jersey 08038
Salem Nuclear Generating Station
Hope Creek Nuclear Generating Station
October 17, 1993 - November 27, 1993
Inspection Summary:
This inspection report documents inspections to assure public health and safety during day
and backshift hours of station activities, including: operations, radiological controls,
maintenance and surveillance testing, emergency preparedness, security,
engineering/technical support, and safety assessment/quality verification. The Executive
. Summary delineates the inspection findings and conclusions .
9401210111 940110
ADOCK 05000272
G
1
-1
EXECUTIVE SUMMARY
Salem Inspection Reports 50-272/93-23; 50-311/93-23
Hope Creek Inspection Report 50-354/93-25 *
October 17, 1993 - November 27, 1993
OPERA TIO NS (Module 30702, 71707, 93702)
Salem: The licensee operated the Salem units safely. The licensee initiated appropriate
actions to address procedural shortcomings following an overflow of the Unit 2 spent fuel
pool. Inspectors found that lack of clearly assigned responsibility initially caused- weak
corrective action. Subsequently, the lieensee aggressively and appropriately pursued ,
corrective action. Operators responded well to a fire in a lighting transformer and in
transporting a potentially contaminated worker to the hospital for treatment of respiratory
distress.
Hope Creek: The licensee operated the Hope Creek unit safely. The licensee properly
suspended operation of Hope Creek within the boundaries of a previously established
operating envelope (i.e., the Extended Load Line Limit Analysis region) due to the discovery
of a discrepancy in the General Electric analysis that originally justified operation in that
region'. The inspectors considered tolerance of the discrepancy for nearly six years a
weakness, however, the licensee properly resolved the discrepancy and resumed operation in
the region. The licensee removed and replaced a motor control center feeder breaker
following erratic operation of its trip mechanism on two separate occasions.
MAINTENANCE/SURVEILLANCE (Modules 61726, 62703)
Salem: The inspectors identified a number of examples of failure to adequately control
safety related activities, including a growing number of tagout related incidents. This is a
violation. Examples included ~lectricians cutting into an energized 125 VDC control cable
(though personnel injury did not result), contract maintenance personnel performing outage
maintenance items without detailed maintenance procedures, and plant staff using an
uncontrolled vendor technical manual during work on a service water valve. In the latter two
examples,. workers appeared to use the procedures to document the work activities, but not to
control the performance of these activities. The inspectors identified a violation for failure to
consider the emergency diesel generators (EDGs) inoperable and performing the associated
actions required by Technical Specification 3.8.1.1, Action a. In addition, the inspectors
found that the licensee had performed inadequate monthly EDG surveillances required by
Technical Specifications. The surveillances did not demonstrate the ability of the air start
systems to start the EDGs under the conditions stated in the Updated Final Safety Analysis
Report .
ii
Hope Creek: The licensee inadvertently isolated the high pressure coolant injection system
when a technician failed to properly perform a key step in a surveillance procedure. The
licensee took prompt and appropriate actions in response to this incident. A shorted logic
tester resulted in an inadvertent residual heat removal pump start. A malfunction of the
11A
11
Refueling Floor Exhaust (RFE) radiation monitor, coincident with a surveillance affecting
"C" RFE, caused a spurious primary containment isolation signal. The possible interaction
between redundant safety-related instrument channels is unresolved.
ENGINEERING (Modules 37828, 71707)
Salem: The inspectors noted that engineering personnel properly prioriti7.ed work activities.
The licensee discovered minor fuel rod defects during the Unit 1 fuel inspection. The exact
nature of the observed defects remains under investigation. This item* is unresolved.
Contractor removal of spare positioning cams for auxiliary feedwater control valves without
the proper authorization constitutes an additional example of violation of proper work
controls.
,
Hope Creek: The inspectors noted that engineering personnel properly prioritized wor]:c
activities. The licensee evaluation and final resolution of blue-dyed diesel generator fuel oil
usage was appropriate and timely. Inspectors closed an unresolved item concerning main
steam isolation valve sealing system leakage.
PLANT SUPPORT (Modules 40500, 71707, 90712, 92700, 92701)
'
Salem:* Periodic inspector observation of station workers and Radiation Protection personnel
noted gooci implementation of radiological controls and protection program requirements.
-
Radiological Protection perspnnel failed to follow prescribed work control practices for
releaSe of a valve from the radiologically controlled area .. This is an additional example of
the work control violation discussed in the* maintenance section*.
Hope Creek: Periodic inspector observation of* station workers and Radiation Protection
personnel noted good implementation of radiological controls and protection program
requirements. The licensee utilized thorough pre-job planning, good radiation work
practices, and innovative dose reduction methods to successfully complete a reactor water
cleanup maintenance outage.
Common: The inspectors determined that the licensee appropriately implemented security
program requirements. Despite initially weak inter-departmental communication, the licensee
took comprehensive action to insure readiness for a possible security union labor action ..
Inspectors closed an open item concerning fire watch record discrepancies .
iii
'.
TABLE OF CONTENTS
EXECUTIVE SUMMARY
- * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * *
11
TABLE OF CONTENTS ...................... * ....... ,. . . . . . . . . . IV
1.
SUMMARY OF OPERATIONS ............................. ~ . 1
1.1
Salem Units 1 and 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.2
Hope Creek . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
2.
OPERATIONS .......................... ; . . . . . . . . . . . . . . 1
2: 1
Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
2.2 * Inspection Findings and Significant Plant Events . . . . . . . . . . . . . . . .
1
2.2.1 Salem ................................. *. . . . . 1
2.2.2 Hope Creek .................... *. . . . . . . . . . . . . . 4
3.
MAINTENANCE/SURVEILLANCE TESTING . . . . . . . . . . . . . . . . . . . . . 6
3.1
Maintenance Inspection Activity . . . . . . . . . . . . . . . . . . . . . . . . . . 6
3.2
Surveillanee Testing Inspection Activity . . . . . . . . . . . . . . . . . . . . . . 7
3.3
Inspection Findings . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . 7
3.3.1 Salem ................................... : . . 7
3.3.2 Hope Creek . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13
4.
- ENGINEERING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14
4.1
Salem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14
4.2
Hope Creek . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
16
5.
PLANT SUPPORT................ . . . . . . . . . . . . . . . . . . . . . .
17
6.
5 .1
Radiological Controls and Chemistry . . . . . . . . . . . . . . . . . . . . . .
17
5. 1. 1 . Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17 *
5.1.2 Inspections Findings - Salem . . . . . . . . . . . . . . . . . . . . . . .
18
5 .1. 3 Inspection Findings - Hope Creek . . . . . . . . . . . . . . . . . . . .
18
5.2
Security ................................... ~ . . . .
19
5.2.1 Inspection Activities . . . . . . . . .. . . . . . . . . . . . . . . . . . . .
19
5.2.2 Inspection Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
19
5. 3
Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
19
5.3.1 Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
19
5.3.2
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . .
19
PERIODIC AND S~ECIAL REPORTS, AND OPEN ITEM FOLLOWUP . . .
20
6.1
Reports
. . . . . . . . . . . . . . . . . . . . . . . . * . . . . . . . . . . . . . : . . 20
6. 2
Open Items . . . . . . . * . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
20
IV
Table of Contents
7.
EXIT INTERVIEWS/MEETINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . .
20
7 .1
Resident Exit Meeting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
20
7 .2
Specialist Entrance and Exit Meetings . . . . . . : .- . . . . . . . . ; : . . . .
_20
7.3
Management Meetings ........ *. . . . . . . . . . . . . . . . . . . . . . . .
21
v
DETAILS
1.
SUMMARY OF OPERATIONS
1.1
Salem Units 1and2
The Unit 1 outage continued through the inspection period. Fuel re-load was completed on
November 22, 1993, and the plant entered Mode 5 on November 27, in preparation for
filling and venting the reactor cooling system. The outage schedule slipped four days. in *
early November due to operability problems with one of the two source range neutron
monitors.
Unit 2 remained on line during the inspection period and operated at 100% power except for
small power reductions to suppc)rt cleaning of condenser water boxes and repairing a
traveling screen for the circulating water system.
1.2
Hope Creek -
The unit operated at. full power during the inspection period.
2.
OPERA TIO NS
2.1
Inspection Activities
The inspectors verified that Public Ser\\rice Electric and Gas (PSE&G) operated the facilities
safely and in conformance with regulatory requirements.
The inspectors evaluated PSE&G's
management control by direct observation of activities, tours of the facilities, interviews and
discussions with personnel, independent verification of safety system status and Technical
Specification compliance, and review of facility records. The inspectors performed normal
and back-shift inspections, including deep back-shift (37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />) inspections.
2.2
Inspection Findings and Significant Plant Events
2.2.1 Salem
A.
Overflow of Unit 2 Spent Fuel Pool
On October 22, 1993, the Unit 2 spent fuel pool (SFP) overflowed to the fuel handling
building (FHB) ventilation- exhaust duct work. The exhaust outlets are above the normal SFP
level, but below the top of the SFP. At the time of the event, the*licensee operated with the
Unit 1 and Unit 2 spent fuel pool cooling systems cross-connected, per procedure Sl.OP-SO-:
SF-0002. Unit 1 was defueled, with the off-loaded core located in the SFP, and Unit 2 was
at 100% power. Operators cross-connected the SFP cooling systems since they had tagged
out the Unit 1 component cooling system, which cools the SFP, for maintenance. Operators
followed the SFP cross-connect procedure verbatim, however, leakage past the Unit 2 SFP
heat exchanger outlet valve (2SF901) and a Unit 2 SFP pump discharge valve (22SF68)
---
~--
2
caused an unexpected transfer of water from the Unit 1 SFP to the Unit 2 SFP. The SFP
low level alarm annunciated in the Unit 1 control room alerting operators to the abnormal
condition. Operations dispatched auxiliary ope~tors to check both the Unit 1 and Unit 2
lineups and SFP levels; The operators closed the cross-connect and determined that valve
leakage back to the Unit 2 SFP Ca.used the unanticipated fluid transfer. Operations
determined that approximately ~500 gallons overflowed from the Unit 2 SFP to a radiological
waste holdup tank through FHB ventilation duct work. They isolated the valve leakage,
initiated work orders for the leaking valves, and restored the SFP cross-connect operation.
Operations observed no further leakage to the Unit 2 SFP.
The inspector subsequently determined that there was no safety consequence of the event,
however, considering the contents of the Unit 1 SFP, the potential existed for a more severe
radiological event. The inspector judged the cross-connect procedure deficient in that it
allowed an abnormal condition, rising level in no. 2 SFP, to go undetected. The procedure
required filling the no. 2 SFP to the high level alarm prior to cross-connect operation, thus
masking a rising SFP level and removing a warning to the operators. Licensed operators
noted the weakness and submitted a procedure change request on October 24, 1993. The
inspector noted that the procedure did not require increased monitoring of SFP levels during
cross-connect operation. Additionally, less than adequate level indication existed for
determining actual level locally at the SFP.
The inspector determined that the licensee's corrective measure may have been less than
adequate, since the licensee did not elect to document the event via the established Incident
Report system (in aecordance with Nuclear Administrative Procedure NC.NA-AP.ZZ-0006)
which would have better assured appropriate followup of this particular abnormal condition.
For example, personal are responsible for reporting off-normal events to their supervisor. In
turn, the supervisor is responsible for initiating the IR forms, coordinating incident followup,
and ensuring corrective actions are identified and completed. In this event, the inspector
found that the Radiation Protection staff considered that Reactor Engineering had
-responsibility for corrective action. However, the inspector learned that Reactor Engineering
only investigated certain aspects of this event, relative to SFP level and temperature; and that _
the FHB ventilation system engineer was not event aware of the magnitude of the overflow
condition.
-
On November 17, 1993, the inspector met with the FHB ventilation engineer -to discuss the _
event and the licensee actions. Following the discussion, the system engineer aggressively
pursued resolution of the issues and initiated a full investigation of the event. The engineer
verified that a procedure change was being reviewed by management, and that plant staff
planned additional procedure and system enhancements. The enhancements include an
improved method of SFP level indication. On November 19, a health physics technician
performed a contamination survey on the FHB ventilation filters and found no significant
contamination. The system engineer inspected the FHB- ventilation filter units and found no
3
signs of excessive water damage. The inspeetor concluded that the overflow did not damage
the FHB ventilation system, or cause radiological contamination~ Despite the initially weak
.
.
response, the licensee initiated sufficient corrective action to prevent recurrence.
.
.
B.
Salem Unit 2 U~usual Event - Fire in Lighting Transformer
On November 2, 1993, at approximately 12:39 p.m., a fire was reported in a 230 volt
lighting transformer in the turbine building. The fire brigade responded to the scene and
extinguished the fire. The fire lasted about 14 minutes. The unit remained at 100% power
throughout the event. The operators declared an Unusual Event at 1:00 p.m., based on the
event classification of a fire lasting more than 10 minutes. At 1:57 p.m., the operators *
terminated the event.
In response to the fire, operators stripped loads from the non..:safety related bus. , As a
consequence, normal lighting in the turbine building arid at the radiological controls check
point was de-energized. This condition lasted about 30 minutes until operators re-energized
the loads from an alternate source. As a precautionary measure, operators directed
evacuation of the turbine building. No personnel injuries occurred.
The plant suffered minimal fire damage. No safety-related equipment_ was affected,
however, electrical leads, associated with a temporary feeder from the lighting panel,
sustained some burned insulation.- Though root cause is still under review, a loose electrical
conm~ction appears to have caused the fire.
The inspectors observed the licensee response from the control room and inspected the
lighting panel after the event was terminated. The inspectors determined that operators took
appropriate actions, including the notification process.
C.
Salem Control Room Conduct
.r
On October 26, the Salem Plant Manager received a report that operators had listened to the
World Series baseball games while on shift in the control room. The Plant Manager
immediately initiated an investigation into the accuracy of the report. Preliminary findings
indicated that an operator trainee had used control room telephones to relay radio broadcasts
. of several baseball games between two site locations. The preliminary findings indicated that
control room operators had transferred the call for the trainee on several occasions. In
addition, two licensed operators had listened to the baseball games on the control room
telephones on one or more occasions. At the end of the inspection period, the licensee had
taken disciplinary action for the trainee, and planned constructive disciplinary action for the
control room operators involved, and for a supervisor that failed to inform management of
the problem. The licensee will present the investigation findings to NRC management during
a meeting in December 1993.
D.
4
Salem Unit 2 Unusual Event -- Potentially Contaminated Worker Transported
Off site
On October 26, the Salem Senior Nuclear Shift Supervisor (SNSS) declared an Unusual
Event when an ambulance transported a patentially contaminated worker to the Salem
Hospital. Site medical personnel determined that the worker, suffering from difficulty in
breathing, vomiting, and possible heat stress, should be taken to the hospital for treatmept
without delay. Emergency medical staff and a health physics technician accompanied the
worker to the hospital. At the hospital, the health physics technician determined that the
anti-contamination clothing, worn by the worker, retained a small amount of fixed
contamination. The health physics technician placed the anti-contamination clothing in a
plastic bag,. and returned the bag to the Salem site for proper disposal. The *technician did
not find any additional evidence of contamination. The worker remained in the hospital for
several days for treatment and observation. The inspectors determined that plant staff acted
appropriately and according to procedure to manage the medical emergency and control the
potential contamination.
2.2.2 Hope Creek *
A.
Hope Creek Operating Envelope Restrictions
In November 1987, the General Electric Company (GE) issued document NEDC-31487,
"Increased Core Flow (ICF) and Extended Load Line Limit Analysis (ELLLA) for Hope.
Creek Generating Station Unit 1 Cycle 2," which presented the evaluation of, and
justification for, the operation of ~ope Creek in a modified operating envelope called the
ELLLA region. NEDC-31487 allowed plant operation in the ELLLA region provided that'
the plant's standby liquid control system (SLCS) used a two-minute time delay initiation
following an anticipated transient without a scram (A TWS) with a main steam isolation valve
(MSIV) closure. However, the Hope Creek SLCS has been using a 230 second time (about
4 minutes) delay*. This discrepancy was not discovered by PSE&G until September 8, 1993,
when a Nuclear Fuels engineer was reviewing NEDC-31487 for an unrelated matter. When
Hope Creek Operations* was notified of the discrepancy, they immediately suspended any
operation of the plant in the ELLLA region and notified the resident inspector.
PSE&G subsequently requested GE to re-analyze the A TWS event using a SLCS timer
setting of four minutes. When the 1987 analysis had been done, A TWS analyses used a peak
suppression pool temperature of 190 degrees F. GE's re-analysis ooncluded that, with a
four-minute SLCS timer, the peak suppression pool temperature which would be reached at
Hope Creek is 197 degrees F. GE further concluded that, although this value is above the
190 degree F evaluation criterion, the real limit for an ATWS is containment design
pressure, and this limit would still be met with substantial margin (peak analyzed pressure is
12:8 psig vs. design pressure of 62 psig). Based on the result of the GE re-analysis, on
5
November 2, 1993, the licensee concluded that operation with a SLCS four-minute time
.delay was safe and determined that operation of the plant within the boundaries of the
established ELLLA region was acceptable.
The inspector monitored the licensee's resolution of this matter and discussed the
compensatory measures taken and the GE re-analysis with members of the Hope Creek
Operations and Nuclear Engineering staff. The inspector identified to the licensee a
discrepancy in the assumed initial operating conditions used by GE in their re-analysis, and
PSE&G satisfactorily resolved the matter with GE, determining that the conclusions of the .
re-analysis were not affected. The inspector concluded that the existence of the SLCS timer
discrepancy for nearly six years was a weakness on the part of the PSE&G engineering staff,
but noted that the licensee's compensatory actions and resolutions of the matter were
- .conservatively and effectively performed. Currently, a four-minute time delay is maintained
on the SLCS.
.
B.
Motor Control Center Breaker Tripping .
On November 16, 1993, an electrician shorted a test lead in 480 VAC motor control center
(MCC) bucket (a breaker enclosure) 10B212211 from phase to ground, resulting in a,
temporary loss of the bus. The electrician was. taking the voltage reading in support of
motor operated valve (MOV) testing. The MCC bucket was damaged by the short. The
electrician received minor bums to the face, hands and forearm.
An I&C technician inspected the feeder breaker to this MCC bucket and found the breaker
- closed with two trip indicator buttons (ground fault/over current) on the solid state trip (SST)
device in the trip position. The licensee believed that the feeder breaker should have tripped,
and explored various causes to explain why it did not trip. General Electric, the vendor, was
consulted and agreed that the breaker should have tripped. The licensee scheduled a planned
outage for the feeder breaker for November 23, 1993. The damaged MCC bucket was
replaced. The electrician's minor injuries were treated on site. The licensee's initial
findings indicated that the electrician had followed the appropriate procedures, but had
inadvertently allowed the lead to touch the bucket while taking a voltage reading on the
supply side of the breaker.
The inspector observed the loss of the vital 480 volt bus from the control room. The
inspector noted that shift personnel operated in a safe and professional manner in responding
to the event. Operators ensured the plant was in a stable configuration, took the appropriate
actions per their procedures, and acted in a controlled manner to fully restore the plant.
On November 18, 1993, I&C technicians remove4 a trip signal from the high pressure
coolant injection (HPCI) jockey pump during surveillance HC.IC-Ff.BJ-0005, which allows
the pump to start. Simultaneous with the pump start, the MCC feeder breaker noted above
tripped. This resulted in the Joss of many safety related loads and required the plant to be
shutdown within eight hours in accordance with Technical Specification 3.8.3.1. Operations
,
6
found the MCC feeder breaker tripped in the" A" channel switchgear room. However,
operations also reported that no loads were tripped at the MCC itself, and no cause was
identified. Thus, in the span of two days a safety-related MCC breaker failed to trip when it
should have, and tripped once when no apparent cause was evident.
At 7: 13 a.m. on November 18, the licensee re-energized the loads on the MCC with the
exception of HPCI jockey pump, and exited the Technical Specification action statement
before the end of the eight hour period. On the afternoon of November 18, the MCC feeder
breaker was replaced. The licensee fully investigated the HPCI jockey pump and its breaker,
including* cycling the pump at the MCC with both the old and new MCC feeder breaker .in
place. No problems were found with the HPCI jockey pump. On November 19, the
licensee performed an "as found" inspection of the removed MCC feeder breaker using
- procedure HC.MD-ST.ZZ-0006, "LOw Voltage Type AKR Air Circuit Breaker Inspection
. and Preventive Maintenance." This procedure tests all the breaker's solid state trips
(overload/short circuit/ground). The breaker trips functioned as designed. At the end of the
inspection period, electrical engineers continued to investigate the abnormal behavior of this
particular MCC breaker.
The inspector examined the damaged MCC bucket and the MCC feeder breaker from the
November 16, 1993 event. The inspector observed the electrical testing of the MCC feeder
breaker. The inspector discussed the initial root cause determination and subsequent
investigation of the two events with Operations and Maintenance supervisors. Although a
feeder breaker outage was -scheduled for November 23, operations recognized that they could
have been more responsive in followi9-g up the potential problem involving the safety-related
feeder breaker. The inspector considers this item unresolved pending engineering evaluation
and NRC assessment of the adequacy of licensee corrective actions. (URI 50-354/93-25-01). * *
3.
MAINTENANCE/SURVEILLANCE TESTING
3.1
Maintenance Inspection Activity
_ .The inspectors observed selected maintenance activities on safety-related equipment to
ascertain that the.licensee conducted these activities in accordance with approved procedures,
Technical Specifications, and appropriate industrial codes and standards.
The inspector observed portions of the following activities:
Salem 1
Salem 1
Work Order(WO) or Design
Change Package <PCP)
Description
Rem/Repl No. 12 Serv Wtr Hdr Crossover
PPG
1 CC31 Prev. Maint and Inspection
Salem 2
Hope Creek
Hope Creek
7
1ZSW356/SPL eroded - replace spool
during lRl 1
HPCI booster pump bearing replacement
The maintenance activities inspected were effective with respect to meeting the safety
objectives of the maintenance program.
3.2
Suneillance Testing lnspectfon Activity
The inspectors performed detailed technical procedure reviews, witnessed 'in-progress
surveillance testing, and reviewed completed surveillance packages. The inspectors verified
that the surveillance tests were performed in accordance with Technical Specifications,
approved procedures, and NRC regulations.
The inspector review~ the following surveillance tests with portions witnessed by the _
- inspector:
Salem 2
Hope Creek
Procedure No.
S2.0P-ST.DG-0001
HC.OP-IS.BJ-0001
2A DG Surv Test
HPCI Main and Booster Pump Set -
Inservice Test
. The surveillance testing activities inspected were effective with respect to meeting the safety
objectives of the surveillance testing program.
,
3.3
Inspection Findings
3.3.1 Salem
A.
Tagout Deficiencies
On October 21, 1993, a PSE&G nuclear maintenance supervisor noticed a contract employee
guarding a racked-out circuit breaker for an electro-hydraulic pump that was being worked.
Though the circuit breaker was observed to be racked-out, it was not tagged out in
accordance with the appropriated system control procedure. The supervisor stopped the job
and had the pump breaker tagged. Nuclear Administrative Procedure NC.NA-AP.ZZ-0015
(NAP-15), "Safety Tagging Program," Section 4.1 requires that prior to the performance of
the work activity' the equipment be prepared, cleared and tagged, and independently verified
when applicable; by tht? Operations Department. In addition, Section 4.1 requires job
8
supervisors ensure equipment has been* appropriately tagged and is safe to work on before
beginning the work activity .. Contrary to this procedure .contract maintenance personnel
conducted maintenance on an electro-hydraulic pump without the proper tagging.
On October 22, 1993, operators removed tags and subsequently opened valves in an incorrect
order allowing steam to blow out drain fittings and a drain hose to whip about due to steam
pressure. This event occurred while releasing tags for maintenance on the No. 22 bleed
steam coil drain taiik pump. An operator was forced to jump from the top of a ladder to
avoid injury due.to the steam and whipping drain hose. Section 5.4.5.b.6 of NAP-15
requires that prior to releasing tags all vents and drains within the tagging boundaries be
verified to be in the proper position for equipment operation. Operation of the No. 22 bleed ,
steam coil drain tank pump requires the vent and drain valves to be closed. Contrary to the
above, the assigned Nuclear Equipment Operator (NEO) did not position the vent and drain
valves to the closed position prior to releasing the remaining tags.
On October 29, 1993, while maintenance personnel removed a service water valve from the
system, an operator opened an upstream isolation valve causing pressurized water to be
emitted from the valve while it was being prepared for removal. The job supervisor had
walked down the tagout the day before and verified the tagout on the upstream isolation
valve. At the time of the incident the operator was releasing tags for another service water
tagout. Section 5.4.5.a of NAP-15 requires the NEO to verify that the Components being
released are the proper components as specified on the Tagging Release Worksheet.
_
Contrary to the above, the NEO removed the wrong tag from the 11 SW52 valve and opened *
this isolation valve while maintenance was still in progress on a downstream valve.
-
On October 31, 1993, a contract electrician cut into an energized 125 volt DC distribution
cable. The electrician believed he was cutting excess cable from a de-energized line and that
. the associated breaker for the cable was tagged open based on an earlier observation.
-
However, the associated breaker was previously tagged open to support another work activity
unrelated to the electricians task Consequently, when that other task was completed on
October 30, . the breaker was closed and the tag removed.
As a result, the cable that the
electrician cut into was*actually energized. The electrician did not suffer any injury due to
the condition. -
-
Section 5 .1. 8 of NAP-15 requires job supervisors with i}ersonnel working on tagged
equipment under their supervision, to tag that equipment in their narrie or in accordance with
a Group Tagging Request. Through a secles of communication, management control, and
work practice deficiencies, the assigned job supervisor failed to ensure that the equipment for
the assigned work activity was properly tagged and controlled in accordance with the
requirements of NAP-15, "Safety Tagging Program".
9
All of the above incidents occurred during the outage at Unit- 1, with the exception of the
steam venting and hose whipping event of October 22, which occurred at Unit 2. The
inspector noted that the licensee initiated investigation of these abnormal events with
scheduled completion in December or January. However, since Unit 1 remained in a
refueling outage, the inspector was concerned about timeliness of addressing the common
cause of the above events. The inspector met with the plant manager on November 17,
1993, to discuss the concern that safety tagging program weaknesses played an increasingly
significant part in recent events. In addition, on November 19, 1993, the inspector met with
members of the Reliability and Assessment Organization to discuss safety tagging concerns.
Operating Experience Feedback (OEF) functions within Reliability and Assessment to trend
incident reports for long and short term common causal factors. The OEF group noted the
increase in tagout-related events and brought the issue to the attention of plant management at
a weekly OEF meeting. .
The inspector noted that the events themselves -lack individual nuclear safety significance and
that no injuries had yet occurred; however, the potential exists for a more serious incidents
with continued safety tagging weaknesses. These examples of failure to adequately control
work as required by NAP-15 constitute an apparent violation of NRC regulatory
requirements. Additional examples-of. inadequate control of work, which also contributed to
this apparent violation, appear in sections 3.3.1.B, 4.1.B, and 5.1.2.A of this report. This
matter remains unresolved pending NRC assessment. (UNR 50-272 and 311/93-23-01).
B.
Maintenance on Service Water Valve 23SW58
On the morning of November 4, 1993, the resident inspectors entered the radiologically
controlled area (RCA) to observe maintenance on valve 23SW58, service water inlet isolation
valve for the No. 23 Containment Fan Cooler Unit (CFCU). During routine surveillances,
operations staff had determined that the valve did not properly isolate service water to the
CFCU. Valve 23SW58 is an air operated butterfly valve manufactured by
Masoneilan/Dresser.
Maintenance staff removed the valve, but the inspectors were not able to find the valve in the
hot shop. The inspectors checked the radiological controls checkpoint to determine if
radiological .controls technicians had released the valve from the RCA. The radiological
controls technicians could not find any entry in the release log indicating that they had
released the valve. (Refer to section 5.1.2.A for further discussion of the radiological
controls aspects of the work on 23SW58.)
The inspectors later found maintenance staff working on the valve in the cold shop.
Maintenance staff showed the inspectors that the pins holding the valve disc to the shaft were
missing, and the holes in the shaft had elongated. The mechanics found small cracks in the
disc where the pins had been located. At the* instruction of their supervisor, the mechanics
had begun the process of pinning a new disc to a new shaft in a new valve body. The
inspectors reviewed work order (WO) 931103095. The mechanics used a vendor technical
10
manual (VTM) *to provide technical guidance. for pinning the disc to. the shaft. The
inspectors noted that the WO did not provide any specific guidance for installation of the new
valve, nor did it reference the VTM. The inspectors found no indication that the licensee
, had reviewed and approved the VTM used by the mechanics ..
In response to inspector questions concerning control of the valve maintenance, the licensee
informed the inspectors that they considered the valve replacement controlled by the work
order, since the replacement valve was identical to the failed valve. The licensee
subsequently showed the inspectors an approved copy of the VTM identical to the manual
used by the mechanics. The inspectors concluded that use of the uncontrolled VTM did not
adversely affect the preparation of the new valve in this instance, since the licensee verified
after the fact that the work met the requirements of the* approved VTM. The inspectors also
concluded that the licensee did not obtain properly controlled copy of the VTM before
performing the work. The inspectors determined that use of an uncontrolled VTM did not
- comply with the requirement of NAP-9, section 5.7, that work be performed in accordance
with instructions in the work package. This is an additional example of the violation
discussed in section 3.3.1.A.
C.
Control of Contractor Maintenance
On November 9, 1993, the inspector _noted the following examples of contractors performing
outage maintenance items without detailed maintenance procedures: *
(1)
A contractor was tasked with the removal and replacement of the No. 12 service
water header crossover piping. This activity was performed without a step-by-step
plan of action. The successful completion of this activity relied heavily on the skill of
the responsible foreman and in his ability to properly coordinate all pipe removal and
replacement, valve maintenance, and QA weld inspections without a written plan
describing }),ow and when this was to happen.
(2)
Contract workers were found to be engaged in the removal of service water piping for *
a component cooling heat exchanger without a work package at the job site.
However, the inspector noted the job foreman was able to fully describe the planned
removal and replacement of the service water piping.
(3)
Contract workers were found performing wiring changes in a fuel pit heat exchanger
motor operated valve (MOV) using a generic procedure covering preventative
maintenance and* inspection of environmentally qualified valves (PM/EQ procedure). *
The MOV (1CC31) was a component cooling valve which provided cooling to the
spent fuel pit heat exchanger. The contractors were sent out to perform maintenance,
on this EQ valve without written guidance relative to portions of the- extensive
PM/EQ procedure they were required to complete'. The workers, when questioned by
the inspector, indicated that they used PM/EQ procedure only to document the work
performed. The inspector encountered the workers just as they completed their
11
maintenance ,activity, and at that time the inspector noted that the PM/EQ procedure
- was completely blank, i.e., none of the accomplished steps had been signed-off as
completed. The inspector noted that application of the EQ and wiring requirements
were largely left to the skill of the workers without the benefit of written procedures.
Nuclear Administrative Procedure NC.NA-AP.ZZ-0009 (NAP-9), "Work Control Process,"
requires that maintenance affecting the performance of safety-related equipment be performed
using approved written instructions. While performing a task requiring written procedures,
the procedure shall be present and followed step-by-step while the task is being performed.
Prior to commencing the work, the person(s) involved with the work should reView the
procedure and be familiar with each step and the sequence of work. A note in NAP-9 allows
some jobs, performed with skills normally posse~sed by qualified personnel, to be performed
without a detailed step-by-step procedure.
The inspector found no problems with the work performed in any of the above maintenance
activities, However, the inspector questioned the manner in which i~ was performed. The
inspector found that licensee contractors relied heavily on the skill of the craft and much less
on detailed work procedures. The workers put more emphasis on properly documenting the *
maintenance activity than properly controlling the process. The inspector concluded that
contractor use of procedures to control work was a weakness .
D.
Control of Salem Emergency Diesel Generator Maintenance and Surveillances
During the inspection period, the inspectors learned that the licensee periodically isolated an
air start system on one of the emergency diesel generators (EDGs) for maintenance .. During
the maintenance, the licensee continued to consider the EDG operable. By this action, the.
licensee demonstrated the belief that the EDG could be started by the remaining two motors.
The Salem Updated Final Safety Analysis Report (UFSAR), section 8.3.1.3 states that three
EDGs are available to supply emergency eleetrical power for each Salem unit; two are
required for each unit in the event of a LOCA with loss of off site power .. The UFSAR,
section 8.3.1.3, also states that each EDG has dual air start systems. Section 9.5.6 of the
UFSAR states that each EDG has four air start motors and that, if *necessary, the diesel can
be started by any pair of motors. The inspectors found that the monthly EDG surveillance
procedure demonstrated that the EDG started on all four air start motors. The surveillance
procedure did not demonstrate the EDG ability to start on any pair of motors, as stated in the
UFSAR. Although an annual surveillance demonstrated the functional performance of each
air start motor individually, the licensee had not demonstrated the EDG ability to start on any
pair of air start motors and reach 900 rpm in 10 seconds or less, since the original EDG
acceptance tests before plant licensing. As a result, the inspectors concluded that, during
periods when an air start system was .unavailable, the licensee did not have a basis for
considering the EDG operable, since they had not demonstrated operability of the air start
system with only two air start motors available .
12
In addition, the TS definition of operability requires that, in order for the EDGs to be
operable, all necessary attendant auxiliary equipment required for. the EDGs to perform their
function are also capable of performing their related function. Since the UFSAR states that
the EDG will start on any two air start motors, isolation of any air start system required
entry into TS 3.8.1.1, Action a., even if the licensee had performed surveillances
demonstrating the EDG capability to start on any two motors.
Technical Specification 3.8.1.1.b for each unit requires that for modes 1, 2, 3, and 4, three
separate and mdependent diesel generators shall be operable.
Technical Specification 3.8.1.1, Action a. requires that with one diesel generator inoperable, PSE&G shall
demonstrate the operability of the remaining A. C; sources by performing Surveillance
Requirements 4.8.1.1.1.a and 4.8.1.1.2.a.2 within one hour and at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />
thereafter. In addition, PSE&G shall restore at least two off site circuits and three diesel
generators to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least hot standby within the next 6
hours, and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. On April 9, 1993, the licensee
isolated an air start system for the 2C EDG under WO 930402056, and failed to declare the
diesel inoperable or take the actions required by TS 3.8.1.1, Action a. On May 13, 1993,
the licensee isolated an air start system for the lB EDG under WO 930508092, and failed to
declare the diesel inoperable or take the actions required by TS 3.8.1.1, Action -a. On
August 5, 1993, the licensee isolated an air start system for the IC EDG under WO 930722139, and failed to declare the diesel inoperable or take the actions required by TS.
3.8.1.1, Action a.* On September 12, 1993, the licensee isolated an air start system for the
2B EDG under WO 930819114, and failed to declare the diesel inoperable or take the actions
required by TS 3. 8. 1.1, Action a.
The inspectors also found that the licensee performed inadequate surveillances required by
Technical Specification 4.8.1.1.2.a.2, in that they failed to demonstrate the capability of the
EDGs to start on any pair of air start motors, as required by the Technical Specification*
definition of operability and the UFSAR description of the air start system. Failure to take
the actions required by TS 3.8.1.1, Action a.; and by TS 4.8.1.1.2.a.2 is a violation (VIO -
50-272 and 311/93-23-02).
In response to inspector concerns, the licensee initiated changes to the monthly EDG
surveillance procedure. The operations manager stated that plant staff would change the
surveillance procedure to demonstrate the capability of a pair of air start motors to start the
EDG as required by TS 4.8.1.1.2.a.2. After plant staff completed the change to the
surveillance procedure, the surveillance will test pairs of air start motors each month on an.
alternating basis .
'*
- -*
13
3.3.2 Hope Creek
A.
Inadvertent High ~re
Coolant Injection (HPCU Isolation
On November 1, 1993, an I&C technician caused an inadvertent HPCI system isolation
during the performance of surveillance procedure HC.IC-FT.SK-0004, "HPCI Steam Leak
Detection Temperature Monitor." The technician placed a key into an "auto isolation _
bypass" switch, but failed to properly position the switch as required by the surveillance
procedure. During the isolation relay timing portion of the surveillance, the isolation signal
was allowed to process completely through and caused the HPCI inboard steam supply
isolation valve to go closed. The technician realized the error. at this point in the procedure
and notified the control room. Operators* reopened the valve. The valve had been closed for
approximately two minutes. The technician was counselled concerning attention to detail in
the performance of his duties.
The inspector noted that an existing overhead annunciator alarm condition masked a HPCI
isolation indication which would have alerted control room operators to the deficient
condition sooner.
On August 14, 1993, operators opened and tagged a breaker for the HPCI Inboard Warmup
Isolation Valve (lFDHV-FlOO) to address valve stroking concerns. This condition resulted
in the "HPCI Out-of-Service" annunciator alarm. The licensee pl~s on repairing the FlOO
valve at the next outage of sufficient duration. Meanwhile, other inputs to this alarm are
masked.
Operations realized that an important indication was unavailable to operators and took action
to correct this condition. On November 3, operators bypassed the alarm input caused by the
FlOO valve using procedure HC.SA-AP.ZZ-0113, "Annunciator Bypass Program." This
action restored the alarm to respond to the remaining "HPCI Out-of-Service" alarm inputs.
- The inspector determined that the licensee took prompt and appropriate actions in response to
the HPCI isolation.
B.
Residual Heat Removal (RHR) Engineered Safety Feature Actuation
On November 9, 1993, an I&C technician caused an inadvertent start of the "B" RHR pump
while performing Surveillance Procedure HC.IC-FT.BB-003, "Reac Level 1 -
CS/RHR/ ADS. " The licensee exited the surveillance, reset the initiation logic, and secured
the RHR pump. The inspector determined that the licensee responded_ to the event
appropriately. The initial licensee investigation revealed technicians used a shorted
Emergency Core Cooling System Logic Tester for the surveillance, thus satisfying the pump
start logic when the technician placed it across contacts in the initiation logic. The inspector
questioned whether logic testers could be checked for faults prior to performance of
14
surveillances requiring their use. The licensee has committed to performing continuity
checks on ECCS logic testers prior to use. This item remains open pending NRC assessment
of licensee corrective actions (URI 50-354/93-25-02).
C.
Spurious Engineered Safety Feature (F.sF) Actuation
On November 21, 1993, an I&C technician was engaged in troubleshooting activities on the
"C" channel of the reactor building exhaust (RBB) radiation monitor. The technician
removed' a card in the common control module for ihe
11C" channels of refuel floor exhaust
(RFB) and RBB monitors, which placed the "C" RFB and "C" RBB in the tripped condition.
Coincident with the module removal was an uptrending of the "A" channel of RFB. The
11 A" RFB reached the trip setpoint and resulted in a primary containment isolation signal
(PCIS) on a high refuel floor exhaust_ radiation signal as designed. No actual refuel floor
exhaust high radiation condition existed. The technician returned one
11C
11 channel module to
the panel, and one *
11A
11 RFB alarms cleared, allowing the PCIS to be reset.
On November 22, operations returned the
11C
11 RBB to an operable condition following a
preamplifier replacement and subsequent channel check and calibration. The.licensee's initial
investigation revealed no wiring deficiencies involving the
11A" and
11C
11 RFB channels. On
November 25, the
11A
11 *channel of RBB failed high. Technicians determined the cause to be
a failed preamplifier in the
11A
11 channel circuitry. The licensee replaced the preamplifier and
restored the "A
11 channel of RFB to operability. The inspector discussed
11 A
11 and
11C
11
channel separation requirements with the licensee in light of the upward trending on the
11 A"
channel of RFB, which occurred simultaneously with the module removal on the
11C"
channel. The inspector noted that the I&C technician performed the iriitial troubleshooting
on the "C
11 RBB channel without a work order or a written troubleshooting plan. *The
inspector had no concerns with the actual troubleshooting work performed, however, proper
written guidance was not provided to the technician prior to troubleshooting. This item will
remain .unresolved pending review of the licenSee's corrective actions and determination of
' the adequacy of channel separation (URI 50-354/93-25~03).
4.
ENGINEERING
4.1
Salem
A.
Salem Unit 1 Fuel Rod Defects
During the inspection period, the licensee informed the inspectors that they had detected
Salem Unit 1 fuel rod defects during the current eleventh refueling outage. *During the
previous cycle, Salem Unit 1 operated with a higher than normal dose equivalent iodine.
(DBI) value of 5.0 B-03 microcurie per gram. (Normal DBI is approximately 1.0 - 2.0 B-03
microcurie per gram.) The licensee would normally expect to find a small number of rod
defects based upon this DBI value. However, due to the discovery of an apparent grid-to-rod
fretting failure during the Unit 2 seventh refueling outage in March 1993 (See _Inspection
15
Report 50-272 and 311/93-15), the licensee realized the potential existed for more fuel
defects in the core periphery near the assembly grid area. This was not the case. After
completing core fuel assembly/rod inspections (ultrasonic test and visual), the licensee noted
four fuel rod defects in four different assemblies in no particular location or pattern. ~e.
fuels group is still evaluating the defects involving the four Unit 1 rods. Preliminary
indications are that secondary hydriding played a.large part in those defects.
Of some significance is the fact that Salem 1 (Westinghouse Vantage 5H fuel - third cycle of
core exposure) did not experience the same fuel failure mechanism as Salem 2 (Westinghouse
- Vantage 5H fuel - second cycle of core exposure). The licensee's initial analysis of the
failures indicated that Unit 1 experienced a different flow past the peripheral assemblies and
was thus out of the regime of the flow - induced vibration found in Unit 2. The licensee was
prepared for Unit 1 grid-to-rod fretting failures as seen in Unit 2 and had initiated Vantage *
5H fuel assembly modifications to address potential flow-induced vibrations. These
modifications included a 90° grid rotation and a damper rod assembly. Rotation of the grid
assemblies through 90° _has been shown to provide mitigation of fuel assembly vibration.
The licensee evaluated the impact of this rotation on pressure drop, departure from nucleate
boiling and cross flow and dete~ined that it had no impact since the basic grid design was
unchanged and rotation would have no impact on fluid turbulence and direction. A damping .
device is designed for use in fuel assemblies without rotating grids that may be required to be
- place4 along the baffle. The purpose of the damper assembly is to reduce the flow induced
vibration to acceptable levels when the fuel assemblies are located at the core periphery.
The licensee determined that the damper does not affect the results of the thermal-hydraulic
and structural analyses performed for Vantage 5H fuel assemblies. The ability of the
assembly to accept control rod insertions, incore instrumentation, accommodate existing
reactor refueling equipment, and to be _inspected is not affected. The inspector reviewed the
safety evaluation for these modifications and found them acceptable. These modifications
were made to the Unit 1 core, which was reloaded on November 22, 1993.
The inspector concluded that the resolution of the fuel defects is not a startup issue for Salem
Unit 1. This item will remain open pending licensee's evaluation and assessment, arid will
be reviewed with the results of the Unit 2 fuel defects evaluation under a previously opened
item URI 50-272 and 311/93-15-03.
B.
Auxiliary Feedwater (AFW) Modification and Cam Removal
During October, the licensee made several modifications to the AFW system, a safety
system. While reviewing the modifications the inspectors learned that two positioner cams,
installed spares in* the Bailey controller for one of the AFW control valves, had been
removed, without using a work order. The inspector also learned that licensee management
had initiated an investigation, based on an employee concern .
16
The investigation consisted of interviews with the people working on the AFW modification,
with. the contractors assigned to the modification, and with craft supervisors. The
investigation revealed that the station work order procedure did* not address what may or may
not be performed under an "engineering inspection" activity. . Because of perceived personal
conflicts between the AFW project manager* and several installation engineers, management -
removed the project manager from all project activities for the duration of the outage. The
licensee did not find examples of procedure non-compliance.
As a result of their investigation, the licensee initiated several corrective actions, including:
issuance of an interim memorandum defining an engineering inspection; review of
Administrative Procedure NAP-9, "Work Control Process," to determine if revision or
clarification was required relative to actions involving engineering inspections; and certain
management changes in the affected project organization.
The inspectors determined that, by itself, this event had minimal safety significance. This
conclusion was based on the AFW system being shutdown for the outage and the fact that the
two spares were simply fastened to the inside of the Bailey cover and not installed in the
system. However, the inspectors were concerned with the lack of control over the work
process.* To resolve this issue they reviewed procedure NAP-9 and determined that there
was no clear guidance for what an "inspection" entailed. However, the inspectors found that
NAP-9, section 1.0 states that work orders are designated to support component history.
The failure, by the_ project manager, to use a work order violated the intent of NAP-9,
section 1.0 .. In addition, NAP-9, section 2.0 states that the work control process shall be
applied when work is performed on Q systems. Failure to use the work control process for
removal of components from the Auxiliary Feedwater System, a Q system, violates section
2.0 of NAP-9. The inspectors concluded that this is an additional example of the violation
discussed in section 3.3.1.A.
-
The inspector also concluded that the licen~'s response to the event was aggressive and
thorough; and that the licensee's chain of command worked well to communicate the initial *
repoit of non-compliance with the work order process through the senior management.
4.2
Hope Creek
A.
Diesel Generator Fuel Oil Blue-Dyed
Effective October 1, 1993, the U.S. Environmental Protection Agency (EPA) has specified a
maximum sulfur content of .05 Wt% for all on-highway fuel nationwide to control exhaust
. emissions. However, fuels with higher sulfur oontent may still be used in applications such
as stationary power sources and backup generators. Such fuel for off-highway use must
contain 1,4 - dialkylamino-anthraquinone, which is intended to give the fuel a blue
appearance. The licensee concern in using this "blue-dye" fuel in the diesel generators (DG)
is the cetane rating (similar to octane in gasoline). The lower the cetane value, the greater
17
. the tendency for the fuel to pre-ignite on compression. The fuel oil supplier speculated that
changes in refinery methods t~ produce the low-sulfur fuel might affect the blue fuel qrnµity.
To date the licensee has noted no degradation in the cetane rating.
Licensee *research into the fuel oil options presented advantages and disadvantages. The low
- sulfur fuel meets the minimum cetane rating, however, refinery practices intended to remove
sulfur and aromatic compounds also reduces the fuel lubricity. Lubricity is the ability of the
fluid to prevent wear through the formation of a very thin chemically reacted surface film .
. A U.S. Army sponsored faboratory-scale test indicated that fuel-lubricated wear increases
while* load-carrying ability decreases with decreasing sulfur content. However, primarily due
to a lack of test fuel, it has not been conclusively shown that fuel containing .05 Wt% sulfur
will promote unacceptably severe wear. The blue-dye fuel has higher sulfur content, thus no
lubricity concern exists. However, the use of this higher sulfur fuel can place the plant in a
shutdown action if the cetane number specification is not met as required by the Technical
Specification analysis for diesel fuel oil.
The licensee decided to purchase the blue-dye fuel, but will have the fuel analyzed for cetane
number prior to unloading. The inspector discussed this issue with the system engineer and
with operations personnel. The inspector reviewed test results found in U.S. Army Report,
11 Side Effects of Recent Fuel Specification Changes to Reduce Sulfur Content," published
October 14, 1993. The *inspector determined that licensee took appropriate actions in
response to recent fuel oil changes to preclude future DG operability concerns.
B.
Open Item Follow-up
(Closed) Unresolved Item (50-354/93-20-01); Main Steam Isolation Valve (MSIV) Sealing
System Leakage. The licensee performep a 10 CPR 50.59 review and safety evaluation to
evaluate the effect of leaving the outboard MSIV sealing system isolation valve
11 failed open
11
until the next outage of sufficient duration. The licensee determined that it was a change to
the facility as described in the FSAR, but that it did not involve an unreviewed safety
question. The inspector determined that the safety evaluation adequately addressed the issue.
The inspector found the licensee implemented sufficienrmeasures to ensure MSIV sealing
system operability and to preclude inadvertent venting of high pressure steam to the reactor
building. The inspector also determined that the licensee complied with all aspects of 10
CPR 50.59. This item is closed.
5.
PLANT SUPPORT
5.1
- Radiological Controls and Chemistry
5.1.1 Inspection Activities
The inspector verified on a periodic basis PSE&G's conformance with the radiological
protection program .
18
5.1.2 Inspections Findings - Salem
A.
Release of Items from the Radiologically Controlled Area (RCA)
On November 4, 1993, maintenance personnel removed the 23SW58 valve (service water
inlet isolation valve to the No. 23 ct>ntainment fan coil unit) from the system and transported
it from the RCA to the "cold" maintenance shop outside the RCA. Salem Radiation
- Protection Procedure SC.RP-TI.ZZ-0209, "Release of Items From The RCA," section 5.1.3
requires that items released from RCA aceess points shall be recorded in an active RCA* Free
Release Log. Contrary to the above requirement, the inspectors found no Free Release Log
entry for the valve. Licensee inquiry into the 23SW58 release path revealed that a technician
had taken an appropriate survey, but he failed tO properly document the release in the log as
required~ The survey indicated that the valve was uncontaminated and available for free
release from the RCA. (See section 3.3.1.C for more details on the 23SW58 maintenance.)
5.1.3 Inspection Findings - Hope Creek
A.
Reactor Water Cleanup Outage
On November 16-18, 1993, the licensee removed reactor water cleanup (RWCU) from
service to perform a weld repair to a regenerative heat exchanger diaphragm. The licensee
utilized thorough pre-job planning, good radiation work practices, and innovative dose
reduction methods to successfully complete the outage with minimal RWCU downtime while*
maintaining radiation exposure as low as is reasonably achievable (ALARA).
The inspector observed the maintenance activity while outside the regenerative heat
exchanger room and discussed the radiological controls with workers and supervisory
personnel. The inspector determined that the licensee exercised good control of the higli
exposure area and proper contamination control work techniques. The inspector noted that
the use of a "shield wheel" on the welded heat exchanger, maintained water shielding in the
other RWCU heat exchangers, and "low dose area" shield wall are all indicative of the
licensee's strong effort to ensure that occupational radiation exposures are maintained as low
as possible. The inspector observed that the workers are aware of the ALARA program and
are actively involved. The inspector also noted strong Radiation Protection management
involvement in the pre-job planning, actual radiation work activities, and post-job ALARA
review. The inspector determined that this activity was properly planned and well-
controlled.
19
5.2
Security
5.2.1 Inspection Activities
-
.
The NRC verified PSE&G's conforman_ce with the security program, including the adequacy
of staffing, entry control, alarm stations, and physical boundaries. The inspectors observed
good performance by Security Department personnel in their conduct of routine activities.
5.2.2 Inspection Findings - Common
A.
Preparations for Expiration of Security Labor Contract
On November 12, the inspectors determined that the existing labor agreement between the
security workers and Wackenhut Corporation, the contractor supplying security services to
PSE&G, expired on November 14, 1993, at midnight. The inspectors reviewed the * *
licensee's contingency plans in the event of a strike. The inspectors found that security
management had trained clerks to issue security badges, and had identified sources of
additional guard force members. However, Security management had not taken any actions
in anticipation of possible labor action after the contract expired on November 14.
In response to inspector questions, security and plant management for Salem and Hope Creek
took measures to insure safe operation, and adequate plant support and security coverage.
The inspectors concluded that while some cominurucations were weak, the licensee's
implementation of existing plans provided good coverage of key operations, security and
support functions.
5.3
Fire Protection - Common
5.3.1 Inspection Activities
The inspector reviewed PSE&G's fire protection program implementation in accordance with
nuclear department administrative procedures. Items included fire watches, ignition sources,
fire brigade manning, fire detection and suppression systems, and fire barriers and doors.
5.3.2 Open Item Followup
(Closed) Unresolved Item (50-272 and 311/92-09-01; 354/92-09-01); Fire watch record
discrepancies. A letter from Thomas T. Martin, Regional Administrator, NRC~ Region I, to
Steven E. Miltenberger, Vice President and Chief Nuclear Officer, PSE&G, dated October *
15, 1993, the NRC issued a Notice-of Violation for falsification of plant records. The NRC
concluded, based on licensee identification of the violation, implementation of corrective
-action, -disciplinary action taken, and actions to improve log keeping, that no further licensee
response was required. This item is closed .
,,
~
20
6.
PERIODIC.AND SPECIAL _REPORTS, AND OPEN ITEM FOLWWUP
6.1
Reports
PSE&G submitted and reviewed for accuracy and evaluation adequacy the following special
and periodic reports.
0
Salem and Hope Creek Monthly Operating Reports for September
The inspector concluded that the licensee appropriately issued the above reports.
6.2
Open Items
The inspector reviewed the following previous inspection items during this inspection. These
items are tabulated below for cross reference purposes.
Report Section
50-272 and 311/92-09-01
5.5.2.A
Hope Creek
50-354/92-09-01
50-354/93-20-01
5.5.2.A
4.2.B
7.
EXIT INTERVIEWS/MEETINGS
7 .1
Resident Exit Meeting
Closed
Closed
Closed
The inspectors met with Mr. C. Vondra and Mr. R. Hovey and other PS~G personnel
periodically and at the end of the inspection repc)rt period to summarize the scope and
findings of their inspection activities.
Based on NRC Region I review and discussions with PSE&G, it was determined that this
report does not contain information subject to 10 CPR 2 restrictions.
7 .2
Specialist Entrance and Exit Meetings
Date(s)
10/25-29/93
Subject
In service
Inspection
Inspection
Report No.
50-272/93-25
Reporting
Inspector
Patnaik
21
7.3
Management M~tings
A.
On November 23, 1993, E. Wenzinger, Chief, Projects Branch No. 2, NRC, Region
I, met with PSE&G representatives onsite to discuss the Comprehensive Performance
Assessment Team (CPA T) findings. The licensee presented the preliminary results of
CPAT investigations and their tentative plans to address the issues identified.
Further discussion of the final results of these activities are planned for February
1994 .
J