ML18100A545
| ML18100A545 | |
| Person / Time | |
|---|---|
| Site: | Salem, Hope Creek  |
| Issue date: | 08/12/1993 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18100A544 | List: |
| References | |
| 50-272-93-19, 50-311-93-19, 50-354-93-18, NUDOCS 9308190037 | |
| Download: ML18100A545 (28) | |
See also: IR 05000272/1993019
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos. 50-272/93-19
50-311/93-19
50-354/93-18
License Nos. DPR-70
Licensee:
Facilities:
Dates:
Public Service Eleetric and Gas Company
P.O. Box 236
Hancocks Bridge, New Jersey 08038
Salem Nuclear Generating Station
Hope Creek Nuclear Generating Station
June 6, 1993 - July 24, 1993
Inspectors:
T. P. Johnson, Senior Resident Inspector
S. T. Barr, Resident Inspector
J. G. Schoppy, Residen
to
T. H. Fish, Resident
s
/l
Approved:
J. R.
Inspection Summary:
~?!
Date
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 provides an overview of inspection findings and conclusions .
9308190037 930812 I
ADOCK 05000272
.
G
i
EXECUTIVE SUMMARY
Salem Inspection Reports 50-272/93-19; 50-311/93-19
Hope Creek Inspection Report 50-354/93-18
June 6, 1993 - July 24, 1993
OPERATIONS (Modules 71707, 93702)
Salem: The licensee operated the Salem units safely. The NRC issued Confirmatory Action
Letter 1-93-007, identifying PSE&G's commitments affecting the operation of Salem Units 1
and 2 relative to the Augmented Inspection Team review of Unit 2 rod control system
anomalies. Unit 2 was restarted and synchronized to the PIM grid in a controlled,
deliberate, and safe manner. Final resolution of abnormal automatic inward control rod
movement on Unit 2 on July 18, 1993 is an unresolved item pending summator repair and
completion of the licensee's root cause determination. An unusually large amount of debris
from the Delaware River blocked flow to Unit l's circulating water pumps on June 8, 1993.
This condition led to a main turbine trip and consequent reactor trip. Operators responded
very well to the event, and plant systems functioned as designed. On July 10, 1993, Unit 1
declared an unusual event in response to an ammonia leak discovered in Unit l's turbine
building. In response to the leak operators properly implemented the Emergency Plan, and
the cause of the leak was corrected. On July 11, 1993, while shutting down Unit 1 to
comply with a Technical Specification Action Statement for an inoperable solid state
protection relay, the main feedwater regulating valve for the No. 14 steam generator
inadvertently closed as a result of a personnel error. This closure resulted in water level
dropping low enough to cause a reactor trip. The licensee's response to the trip and their
subsequent root cause determination were appropriate. The cause for many of these
emergent conditions involved inadequate supervisory or _management oversight, ineffective
corrective actions, or lack of attention to detail and procedures.
Hope Creek: The licensee operated the Hope Creek unit safely. On July 14, 1993,
thunderstorms in the area caused a transient on one of the off-site transmission lines,
resulting in a full recirculation pump runback on the "B" pump. The operators' response to
the transient was good, and plant systems functioned as designed.
MAINTENANCE/SURVEILLANCE (Modules 61726, 62703)
Salem: Licensee follow-up action to an incident involving a diver inspection of an untagged
service water pump was evaluated as timely and appropriate. Licensee actions following a
lC vital bus trip were determined to be appropriate and well controlled .
ii
Hope Creek: The licensee shipped six fuel pins to a facility for evaluation to determine why
one pin had failed. The activities associated with receipt of the fuel shipping cask, the fuel
transfer to the cask, and subsequent fuel shipment off-site were very well coordinated and
safely executed.
ENGINEERING (Module 71707, 71711)
Salem: The inspectors noted that engineering personnel properly prioritized work activities.
Reactor engineering support during the Unit 2 startups was a notable strength. On July 22,
1993, the licensee initiated a one hour report to the NRC regarding the degraded voltage
protective relays for the 4 kv vital busses. PSE&G determined that the setpoints for these
relays may be set non-conservatively. Pending completion of the facility's corrective actions
and NRC review, this setpoint issue is an unresolved item. The NRC determined that the
service water system did not share the same vulnerability to debris induced trips as the
circulating system. The inspectors followed up on the unresolved item concerning improper
emergency diesel generator fuel injection studs.
Hope Creek: The inspectors noted that engineering personnel properly prioritized work
activities. The inspector followed up on a 10 CFR Part 21 notification, which addressed
_failure of DC powered microswitches. This issue will remain open pending NRC review of
the facility's supplemental report to the notification.
PLANT SUPPORT (Modules 30702, 40500, 71707, 82301, 90712, 93702)
Salem: Periodic inspector observation of station workers and Radiation Protection personnel
noted good implementation of radiological controls and protection program requirements.
Operators responded promptly and properly to address a potential steam generator tube leak.
On June 22, 1993, while chemistry personnel were returning a condensate polishing
demineralizer to service on Unit 2, both feed pumps tripped when air was introduced into the
feed pump suction lines. The auxiliary feed pumps consequently started, and licensee
response to this event was appropriate. The licensee initiated appropriate and timely
corrective measures in response to a condition which rendered the 2R15 condenser exhaust
noble gas effluent process monitor inoperable.
The licensee conducted their annual emergency plan exercise at Salem during June 22-24,
1993 (see NRC Inspection Report 50-272 and 311/93-12 and 50-354/93-08). PSE&G
properly declared and responded to an Unusual Event which was the result of an ammonia
leak at Salem on July 10, 1993.
In the area of housekeeping, the inspector noted a number of material condition discrepancies
at both the Salem and Hope Creek service water system intake structures.
lll
-----
-
On July 22, 1993, a high temperature alarm occurred on the No. 1 Salem diesel driven fire
pump, and the pump was declared inoperable. The No. 2 pump had already been declared
inoperable, and PSE&G properly implemented the necessary compensatory measures until a
Salem fire pump could be returned to service.
Hope Creek: Periodic inspector observation of station workers and Radiation Protection
personnel noted good implementation of radiological controls and protection program
requirements. On July 19, 1993, results of initial smears of an incoming spent fuel shipping
cask were above allowable limits. The facility responded by making the appropriate one
hour notification to the NRC. Subsequent review of the smear results revealed that they
were actually below the allowable limit.
Common: The inspectors determined that the licensee appropriately implemented security
program requirements. Plant management implemented additional security measures in
response to a NRC advisory relative to the increased potential for a terrorist threat.
iv
.*
TABLE OF CONTENTS
EXECUTIVE SUMMARY ...................................... ii
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 . . . . . . . . . . . . . . . . 2
2.2.1 Salem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
2.2.2 Hope Creek . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
3.
MAINTENANCE/SURVEILLANCE TESTING ............ ~ . . . . . . . . 8
3.1
Maintenance Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . 8
3.2
Surveillance Testing Inspection Activities . . . . . . . . . . . . . . . . . . . . . 8
3. 3
Inspection Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
3.3.1 Salem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
3.3.2 Hope Creek . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11
4.
ENGINEERING/TECHNICAL SUPPORT (E/TS)
. . . . . . . . . . . . . . . . . .
11
4 .1
Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11
4.2
Inspection Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11
4.2.1 Salem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11
4.2.2 Hope Creek . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14
5.
PLANT SUPPORT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14
5 .1
Radiological Controls and Chemistry . . . . . . . . . . . . . . . . . . . . . .
14
5 .1.1 Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14
5.1.2 Inspections Findings - Salem . . . . . . . . . . . . . . . . . . . . . . .
14
5 .1. 3 Inspection Findings - Hope Creek . . . . . . . . . . . . . . . . . . . .
16
5.2
Emergency Preparedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17
5.2.1 Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17
5 .2.2 Inspection Findings - Common . . . . . . . . . . . . . . . . . . . . . .
17
5.3
Security . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
5.3.1 Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
5.4
Housekeeping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
5.4.1 Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
5.4.2 Inspection Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
5.5
Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
5.5.1 Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
5 .5 .2 Inspection Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
19
v
TABLE OF CONTENTS (CONTINUED)
6.
LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL
REPORTS, AND OPEN ITEM FOLLOW-UP . . . . . . . . . . . . . . . . . . . . .
19
6.1
LERs and Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
19
6.2
Open Items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
21
7.
EXIT INTERVIEWS/MEETINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . .
21
7 .1
Resident Exit Meeting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
21
7 .2
Specialist Entrance and Exit Meetings . . . . . . . . . . . . . . . . . . . . . .
21
7 .3
Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
22
vi
DETAILS
1.
SUMMARY OF OPERATIONS
1.1
Salem Units 1and2
Unit 1 began the inspection period operating at full power. On June 8, 1993, the unit reactor
automatically tripped from 85 % power when the main turbine tripped as a result of a loss of
condenser vacuum. The sudden accumulation of debris on the circulating water system trash
racks resulted in the loss of all operating circulating water system pumps and, consequently,
the loss of cooling water flow to the condenser. Following corrective actions taken for the
event and modifications made as a result of the Unit 2 rod control system concerns, operators
restarted Unit 1 on June 19, 1993. The unit operated at power until July 11, 1993, when the
reactor again automatically tripped. The trip sequence was initiated when maintenance
personnel accidentally lifted an improper lead during the repair of a solid state protection
system relay which controls main feedwater isolation. As a result, the water level in No. 14
steam generator decreased below the reactor trip low level setpoint. The licensee assessed
the event, implemented corrective actions, and restarted the unit on July 15. The unit
operated at power through the end of the inspection period .
Unit 2 entered this inspection period while in its seventh refueling outage, which had been
extended in order to resolve the unit's rod control system design concerns (see NRC
Inspection Report 50-272 and 311/93-81). Operators made the reactor critical on June 28,
1993, and synchronized the unit to the grid on June 30, 1993. PSE&G operated Unit 2 at
power through the remainder of the period.
1.2
Hope Creek,
The Hope Creek unit operated at power throughout the entire period. On July 14, 1993, an
electrical transient on an off-site 500 kv line, caused by thunderstorm activity, resulted in a
brief power reduction due to a recirculation pump runback.
2.
OPERATIONS
2.1
Inspection Activities
The inspectors verified that Public Service 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 (66 hours7.638889e-4 days <br />0.0183 hours <br />1.09127e-4 weeks <br />2.5113e-5 months <br />) inspections .
.*
2
2.2
Inspection Findings and Significant Plant Events
2.2.1 Salem
A.
Rod Control System Anomaly Conflrmatory Action Letter
On June 8, 1993, the NRC issued PSE&G Confirmatory Action Letter (CAL) 1-93-007,
identifying PSE&G's commitments affecting the operation of Salem Units 1 and 2 relative to
the Augmented Inspection Team (AIT) review of Unit 2 rod control system anomalies. At
the time the CAL was issued, Salem Unit 2 was operating in Mode 3 (Hot Standby). Salem
Unit 2 continued in Mode 3 while the AIT efforts continued on-site. On June 18, 1993, the
licensee's staff presented the results of PSE&G's investigation and assessment of the rod
,
control system problems to NRC management at the NRC regional office. The meeting ~
{,Lt>
.;t'documented in separate NRC correspondence. Additionally, the licensee identified
corrective actions, taken or planned, to support restart activities on both Salem units. On
June 27, 1993, the AIT completed its on-site inspection and investigation efforts. The AIT
determined that the licensee's corrective actions and root cause analysis were appropriate (see
NRC Inspection Report 50-272 and 311/93-81).
The NRC verified that the licensee staff:
Implemented the specifications of a detailed engineering evaluation and operating
commitments to support restart of both Salem units;
Established special Standing Orders relative to the conduct of operations affecting the
rod control system;
Performed rod control system current traces prior to startup of either unit;
Performed increased surveillance testing of the rod control system;
Acted. to assure that procedures were adequate to address abnormal rod movement;
Acted to assure that operators were sufficiently trained to recognize and handle
situations involving unexpected rod movement;
Installed suppression diodes in the rod control systems;
Replaced the rod control logic cards in Unit 2; and
Established improved practices for rod control system card removal and installation.
3
The NRC determined that PSE&G had sufficiently analyzed and corrected the rod control
system problems, and had established sufficient compensatory and corrective measures to
restart Unit 2. On June 27, 1993, the NRC Regional Administrator briefed licensee senior
management of the above evaluation and closed out CAL 1-93-007.
B.
Unit 1 Reactor Trip Due to Loss of Circulating Water Pumps
On June 8, 1993, at 5:45 p.m., the Salem Unit 1 reactor automatically tripped from 85%
power when the unit's main turbine tripped. The cause of the turbine trip was low condenser
vacuum which had resulted from four of the five running circulating water (CW) pumps
tripping off line due to high differential pressure across their travelling screens (the unit's
sixth circulator was out of service to allow divers to clean the pump's trash racks). Due to
the rapid sequence of the four CW pump trips, the reactor operators were unable to reduce
reactor power quick enough to avoid the automatic reactor trip. Subsequent to the reactor
trip, operators entered the appropriate emergency operating procedure and stabilized the plant
in Mode 3 (Hot Standby). At the time of the Unit 1 trip, the licensee was maintaining Unit
2 in Mode 3 pending resolution of that unit's rod control system problems (see NRC
Inspection Report 50-272 and 311/93-81). Unit 2 reactor status was unaffected by the event.
PSE&G maintained Unit 1 in Mode 3 while a Significant Event Response Team (SERT)
investigated the event root cause and, in light of the rod control system concerns, while
engineering prepared a justification for the unit's restart. The SERT found that the cause of
the loss of the CW pumps had been the sudden release of large amounts of debris from the
trash racks and the river bottom. The released debris consequently blocked the flow of river
water through the remaining travelling screens. The SERT determined the root causes of the
event to be: the buildup of debris on the trash racks since the trash rake did not extend to
the bottom of the racks; less than adequate risk assessment for, and control of, the trash rack
cleaning activity; and failure to fully complete the corrective actions following a similar
event in 1989.
Short term corrective actions recommended by the SERT included cleaning the trash racks
and river bottom, as necessary, to restore the operability of the CW system, the repair of the
CW trash rake to enable it to extend and clean the entire length of the trash racks, and the
repair of several other miscellaneous equipment issues. The SERT's long term
recommendations concerned the overhaul or replacement of the entire CW trash rake and
rack system, and the development of enhanced operating and work practices relative to the
CW system to prevent recurrence. Following the necessary repairs to the CW system and
the completion of the engineering justification for Unit 1 restart, operators restarted Unit 1
on June 19, 1993 (see NRC Inspection Report 50-272/93-81 for details of this startup).
The NRC resident inspector responded to the Unit 1 control room immediately after the unit
reactor trip and noted that the Salem operators did an excellent job responding to the sudden
loss of the CW pumps and implementing the appropriate emergency operating procedures.
Subsequent to the trip, the inspector monitored the performance of the SERT, discussed their
4
progress with the SERT team leader, and observed the maintenance performed on the CW
system, including the dredging of the river bottom in front of the CW structure. The
inspector determined that the licensee's response to this event was appropriate and well-
directed. The licensee's failure to adequately follow up on their own findings relative to the
previous 1989 occurrence was a contributing factor indicating weakness in the licensee's
corrective action process.
C.
Unit 2 Startup Following Resolution of Rod Control System Failures
At 12: 16 p.m. on June 28, 1993, the licensee commenced a startup on Unit 2. Operators
pulled control bank "D" to 160 steps and performed a dilution to criticality. Criticality was
achieved at 9: 10 p.m. on June 28, 1993.
At 12:00 p.m. on June 29, 1993, the licensee entered Technical Specification (TS) 3.0.3
since three rods in control bank "B" indicated greater than 12 steps off of the group demand
counter position. The licensee determined the cause to be due to individual rod positiori
indication (IRPI) drift as the plant heats up following a startup. At 12:55 p.m. on June 29,
the licensee commenced a shutdown to comply with TS 3.0.3 and ieveled power at lE-7
amps in the intermediate range. At 1:45 p.m. on June 29, with two of the three affected
IRPI's properly restored, the licensee exited TS 3.0.3 and resumed power ascension. Over
. the next two days the licensee conducted reactor physics testing, main steam isolation valve
(MSIV) testing, turbine overspeed testing, and power ascension to 18%.
The licensee experienced a temporary delay in synchronizing to the PJM grid when a
problem was encountered with main generator field excitation. The licensee identified a
problem with the main generator manual voltage regulatory motor driven setpoint adjustment
potentiometer. The'licensee impleinented a temporary modification to replace the
potentiometer._ . Subsequently, the licensee successfully synchronized Unit 2 to the grid at
4:24 a.m. on July 3, 1993.
The inspectors performed a rotating shift 24-hour coverage of all startup activities. The
inspectors noted that the Operations Department, assisted by the Maintenance and Technical
Departments, conducted the plant startup in a controlled, deliberate and safe manner.
D.
Unusual Event Declared as a Result of Inadvertent Ammonia Release
During a plant tour on the evening of July 10, 1993, the Unit 1 nuclear shift supervisor
(NSS) encountered ammonia fumes in the Unit 1 turbine building, 100-foot elevation (ground
level). The NSS reported the condition to the Salem control room and that he was feeling ill
as a result of his exposure to the fumes. The control room dispatched Site Protection to the
area to assist the NSS, notified Hope Creek of the toxic gas release, and made a page
announcement to warn station personnel to stay clear of the area where the ammonia had
been discovered. Shortly thereafter, at 6:15 p.m., Salem operators declared an Unusual
5
Event (UE) due to the toxic gas release, in accordance with the Salem Event Classification
Guide (ECG), Section 8.A. Due to the UE, all station personnel were required to assemble
at their respective accountability stations.
Site Protection had transported the Unit 1 NSS to Salem County Memorial Hospital, and all
other site personnel were accounted for by 7:17 p.m., forty-nine minutes after the
accountability requirement had been initiated. In the meantime, operators identified the loop
seal on the ammonia hydroxide storage tank as the source of the ammonia gas release. The
loop seal had apparently been blown out by the pressure build-up in the tank which was a
result of the higher-than-normal ambient temperatures (outside air temperatures had exceeded
100°F during the three previous d(iys) and resulted in boiling of the ammonia hydroxide in
the storage tank. Operators restored the loop seal and began ventilating the turbine building.
At 6:59 p.m., the Unit 1 NSS called in from the hospital and reported he was feeling better
and would return to the site. By 7:20 p.m., Site Protection determined the turbine building
atmosphere had returned to normal, and PSE&G terminated the UE at 7:30 p.m.
The licensee notified the resident inspector at home of the ammonia leak and the UE
declaration, and the inspector monitored the licensee's progress via telephone contact. Upon
returning to the site on July 12, the inspector confirmed licensee actions of the evening of
July 10, 1993. Through review of Salem logs and procedures and discussions with the
personnel that had been involved, the inspector determined that PSE&G had properly
implemented the correct procedures (i.e. SC.OP-AB.CR-0003(Q), "Toxic Gas Release," and
SC.FP-EO.ZZ-0003(Z), "Control Room Medical Emergency Response") and complied with
their Emergency Plan. The inspector also confirmed that the Salem operating crew had
satisfied all reportability and shift manning requirements during the event.
The inspector verified that the licensee stores 27 % ammonia hydroxide solution in the tank in
accordance with the Salem licensing basis. This 27% solution has a boiling point of 102°F.
The Salem turbine building has a design temperature of 115 °F. Through discussions with
Salem Chemistry Department and PSE&G Engineering and Plant Betterment personnel, the
inspector found that the possibility of this type of event had not previously been considered,
despite the apparent conflict between the turbine building design temperature and the boiling
point of 27% ammonia hydroxide. As a corrective action, PSE&G committed to reduce the
stored ammonia hydroxide concentration to 15%, which has a boiling point of 136°F.
The inspector concluded that licensee personnel responded well to the events of July 10,
1993; operators quickly determined the cause, subsequently restored the loop seal which
terminated the release, and properly implemented the Emergency Plan. The inspector
determined that PSE&G's intended use of 15% ammonia hydroxide solution is appropriate
and an adequate means of preventing event recurrence .
6
E.
Unit 1 Reactor Trip Due to Mahi Feedwater Isolation
On July 11, 1993, Salem operators were performing surveillance procedure Sl.OP-ST.SSP-
OOlO{Q), "Engineered Safety Feature Solid State Protection System (SSPS) Slave Relay Test
- Train B," when they determined that the relay which controls main feedwater isolation for
the No. 13 and 14 steam generators was inoperable. With this engineered safety feature
inoperable, Technical Specification 3.3.2.1 requires that the unit be in Mode 3 (Hot Standby)
within six hours, and Salem operators commenced a Unit 1 shutdown at 8:30 p.m. on July
11, while technicians initiated repairs of the affected relay. While the repairs to the relay
were being performed, the main feedwater regulating valve for the No. 14 steam generator
inadvertently went closed at 8:38 p.m., resulting in the water level in that steam generator
dropping to a level sufficient to cause an automatic reactor trip. The unit subsequently
entered Mode 3.
PSE&G maintained Unit 1 in Mode 3 while the cause of the main feedwater isolation was
investigated. The licensee determined that the technician who was repairing the SSPS relay
lifted an improper lead and caused the isolation of the No. 14 steam generator. The licensee
additionally determined the root cause of the technician's error was inadequate detail and
direction in the SSPS troubleshooting plan. Subsequent to the cause determination of the
trip, PSE&G repaired the SSPS and commenced a reactor startup on July 15, 1993.
The reactor was made critical on July 16, but during startup testing, operators identified a
problem with the unit rod control system (RCS). Operators maintained the unit critical while
the RCS problem was investigated. The licensee eventually identified and repaired a faulty
circuit card in the RCS power cabinet. With the RCS repaired, operators continued the
startup and synchronized the unit to the grid on July 20, 1993 .
. The licensee properly notified the resident inspector of the reactor trip, and the inspector
monitored the licensee's troubleshooting and corrective actions following the trip. The
inspector determined that Salem management were rigorous in their self-assessment of the
root cause of this event and conservative in the corrective action taken, which involved
procedural revision requiring additional supervisory concurrence of any future
troubleshooting activities to be performed at the Salem station. The inspector reviewed
operator actions taken subsequent to the reactor trip and observed portions of the unit startup
and concluded that the unit operators had performed well in response to the trip and
performed a safe startup of the unit.
F.
Automatic Control Rod Inward Rod Movement
At 5: 12 p.m. on July 18, 1993, Salem Unit 2 Control Bank D (8 control rods) began
stepping inward at a rate of 72 steps per minute, but only moved a few steps before being
detected by operators. At the time, Unit 2 was at 100% power with the control rods in
automatic. The operator, finding no apparent cause for the rod insertion, positioned the rods
in manual control, which stopped the rod movement. The operators performed all actions
7
per their abnormal rod movement procedure (AB-ROD-0003) and were still unable to
positively identify the cause. The licensee installed monitoring instrumentation on the inputs
to the automatic rod control signal summator and at 11:40 p.m. on July 18, returned rod
control to automatic.
At 11:24 a.m. on July 21, 1993, the licensee again experienced the same phenomenon on
Unit 2. As in the previous occurrence, the operator quickly evalua~ the situation and
appropriately placed the rods in manual control. In both cases the rods only moved inward a
few steps (2 and 4 steps respectively). Current traces on the signal summator input revealed
no change from the nuclear instrument (NI) or turbine impulse pressure, but some spiking
from the average temperature (Tave) and reference temperature (T ref) input. Together these
four signals are the input signals to the automatic rod control system. On July 21, the
licensee placed additional monitoring instrumentation on the output of the signal summator,
output of the "rod in output" signal comparator, and individually on all four Tave channels.
- On July 22, 1993, during I&C troubleshooting, the licensee was able to identify a fault in the
- signal summator, which erroneously produced a high rod inward demand output for a
relatively small temperature error input.
The inspector observed the performance of the abnormal rod movement procedure, the
additional instrumentation monitoring, and the I&C automatic rod control troubleshooting.
The inspector noted that the operators and technicians took the appropriate actions to
properly address immediate safety concerns and were methodical in their troubleshooting
approach. This matter remains open pending summator repair and completion of the
licensee's root cause determination (URI 50-311/93-19-01).
2.2.2 Hope Creek
.A.
. Storm Induced Transient
On July 14, 1993, while at 100% power, heavy thunderstorms in the area caused a transient
on one of the off-site 500 kv transmission lines. This transient caused a full runback on "B"
reactor recirculation pump. Power stabilized at 70% power. The operators responded to the
transient and entered the appropriate abnormal procedures and Technical Specification. The
unit was returned to full power over the next two hours.
The inspector followed up on the event by responding to the control room and reviewing the
control room logs, abnormal procedures, and discussing the event with the operators. The
inspector concluded that the operators' actions were appropriate.
8
3.
MAINTENANCE/SURVEILLANCE TESTING
3.1
Maintenance Inspection Activities
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:
Work Order(WO) or Design
Change Package (PCP)
Description
Salem 1
Salem 2
Hope Creek
Hope Creek
IC-8.1.004
DCP-4EC-3407
(package 1)
Various
lSV 4/20ET turbine trip solenoid/install
resistor
Rod position indication signal conditioning
module adjustment
Reactor vessel water level instrumentation
modifications
Fuel rod retrieval
The maintenance activities inspected were effective with respect to meeting the safety
objectives of the maintenance program.
3.2
Surveillance Testing Inspection Activities
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 reviewed the following surveillance tests with portions witnessed by the
inspector:
Procedure No.
Salem 1
OP-ST .SSP-0010
Engineered Safety Features Solid
State Protection System Slave Relay
Test - Train B
Salem 1
OP-ST .AF-0009
Salem 1
OP-ST .MS-0002
Salem 2
RE-ST .ZZ-0002
Salem 2
OP-ST .MS-0003
Salem 2
OP-PT.TRB-0001
Salem 2
OP-ST. TRB-0003
Salem 2
OP-ST .RCS-0001
Hope Creek
Various
Hope Creek
Various
9
Plant Systems - Auxiliary
Feed water
In Service Testing Main Steam and
Main Feedwater Valves Mode 1-6
Shutdown Margin Calculation
Steamline Isolation and Response
Time Testing
Turbine Auto Trip Mechanism
Operational Test
Turbine Mechanical Overspeed Test
Reactivity Control Systems - Rod
Control Assemblies
Shiftly and daily logs
Core thermal limits
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.
Service Water Intake Inspections
On June 8, 1993, contract divers assigned to perform silt inspections at the Salem service
water (SW) intake structure entered the wrong pump bay. Divers inspected No. 16 SW
pump bay, however, the activity was planned for the Nos. 11 and 21 SW pump bays. No.
16 SW pump was not in service at the time, but it was not tagged out. While preparing to
tagout the No. 16 SW pump for inspection, the maintenance supervisor realized the error and
promptly stopped work and informed the senior shift supervisor.
In review, the inspector determined that the maintenance supervisor performed a tagout
reverification of the Nos. 11 and 21 SW pumps and passed the work order to PSE&G
mechanics. The mechanics were assigned to assist the divers in moving equipment from bay
to bay. The mechanics delivered the work package to the divers and directed them to
commence the inspection. The work order summary described the work as "No. 11 through
10
16 SW pump; bay silt level inspection," although the specific work order activity called for
an inspection of the No. 11 SW pump bay. Neither the mechanics nor the divers verified
that the proper SW bay was entered according to tags hanging.
The licensee performed a thorough root cause analysis and attributed the event to poor
communication practices, inattention to detail and inadequate tagout verification. In response
to this event the maintenance engineer and senior maintenance supervisor met with the owner
of the diving company to explain the severity of the incident and to plan appropriate
. correction action. All employees of the diving contractor received notice of the incident and
were given tagout verification training. In addition, a procedure change request was
submitted to SC.MD-GP.SW-0001, "Service Water Silt Survey," to add a precaution to
ensure proper tagging is in place and that the divers enter the correct SW bay. The licensee
reviewed the incident with the Maintenance Department at the June safety meeting. The
inspector met with the responsible maintenance supervisor and the senior nuclear
maintenance supervisor to discuss the event.
The inspector met with the responsible maintenance supervisor and the senior nuclear
maintenance supervisor to discuss the event. The inspector reviewed the work package,
tagout and the licensee's follow-up investigation. The inspector determined that personnel
inattention to detail and less then adequate procedures were a contributing factor in this
situation. The inspector noted that the licensee's corrective actions, taken once they were
aware of the situation, were timely and appropriate.
B.
Trip of the lC Vital Bus
On June 9, 1993, the lC vital bus sensed an undervoltage condition, which resulted in an
automatic start and blackout loading of the lC emergency diesel generator (EDG). At the
time of the event, maintenance personnel were conducting a monthly functional surveillance
test of the lC 4 kv vital bus in accordance with procedure Sl.MD-FT.4kv-0003,
"Engineered Safety Feature Actuation System Instrumentation Monthly Functional Test lC 4
kv Vital Bus Undervoltage." The licensee verified that the EDG started, re-energized the lC
vital bus, and loaded the bus per design. The licensee recovered the lC vital bus, secured
the EDG, and restored the normal electrical lineup.
The licensee identified the root cause to be personnel error attributed to inattention to detail.
The maintenance technician did not self-check as required by station work practices. The
technician inadvertently mispositioned a test signal switch while securing from the monthly
surveillance test, which satisfied the logic for single vital bus undervoltage engineered safety
feature (ESF) mode operation sequence. The licensee reviewed this event, briefed applicable
personnel, and implemented positive disciplinary action for the individual involved .
11
The inspector observed the electrical plant recovery from the control room. The inspector
concluded that the licensee's actions were appropriate and well controlled and that the
licensee's ESF actuation report was timely. The inspector determined that the loss of the lC
vital bus was a result of personnel inattention to detail and failure to adequately follow
procedures. The inspector also noted, however, that all equipment functioned as designed
and that the licensee's follow-up actions were appropriate.
3.3.2 Hope Creek
The inspector concluded that routine observations of maintenance and surveillance activities
were effective.
4.
ENGINEERING/TECHNICAL SUPPORT (E/TS)
4.1
Inspection Activities
The inspector reviewed PSE&G's engineer and technical support activities, including system
engineering performance, Engineering and Plant Betterment (E&PB) support, and BITS
support of operations, maintenance and other activities.
4.2
Inspection Findings
4.2.1 Salem
A.
Reactor Engineering Support
The inspector observed the performance of the reactor engineering group in support of Unit 2
startup over the period May 24 - July 6, 1993. The inspector monitored the approach to
criticality, reactivity computer checkout, isothermal coefficient determination, rod swap
reactivity measurements, flux mapping, and nuclear instrument gain adjustments. In
addition, the inspector reviewed the estimated critical position, shutdown margin calculation
and inverse count rate ratio plot. The inspector determined the reactor engineers to be
extremely knowledgeable of reactor physics, professional in their duties, and in proper
control of the startup. The inspector observed good communication and coordination
between reactor engineering and operations.
B.
Vital Bus Undervoltage (UV) Relays Outside the Design Basis
On July 22, 1993, at 8:33 p.m., PSE&G initiated a one hour report to the NRC concerning a
condition determined to be outside Salem's design basis. The licensee concluded that the
Unit 1 and 2, 4160 volt vital bus degraded voltage protective relays (second level, time
dependent UV) may be set non conservatively. Current Technical Specification (TS 3/4.3.2)
and FSAR (Section 8.3.1.2) requirements are for these relays to actuate at 91.6% of vital bus
voltage with a time delay of 13 seconds.
12
Licensee engineering calculation S-C-4KV-EEE-0836, dated July 27, 1993, determined that
the minimum vital bus voltage to be 93.2 % . Thus, safety related loads (motors, fans,
valves) may be affected by the minimum vital bus voltage never reaching the current relay
setpoint. The licensee concluded that issue was reportable, and subsequently notified the
NRC. Further, the licensee concluded that the Salem 1 and 2 vital buses and power supplies
were operable based on the following: (1) minimum bus voltage at the start of loss of power
and switching scenario is 4300 volts based on current load tap changer setting; (2) vital loads
should be greater than the assumed minimum of 90% voltage; (3) the first level protection of
70% UV is satisfactory; and, (4) the likelihood of voltages between 91.6% and 93.2 is small.
-Further, the licensee intended to modify the existing UV trip setpoint.
The inspector reviewed this issue by discussing it with the senior nuclear shift supervisor
when the NRC notification was made and with licensee engineering and management
personnel. The inspector also reviewed TSs, the FSAR, and the engineering calculation.
The inspector noted that this deficiency was discovered during the licensee's electrical
distribution system functional inspection (EDSFn. Further, the NRC intends to perform an
EDSFI review in the near future. Pending completion of licensee corrective actions and
NRC review, the setpoint of the second level UV relays for the Salem 1 and 2 vital buses is
unresolved (URI 50-272 and 311/93-19-02).
C.
Potential Service Water Vulnerability
The NRC questioned the vulnerability of the Salem service water system to an event similar
to the circulating water debris induced trip of June 8, 1993 (see Section 2.2.1.B). The
service water system serves as the ultimate heat sink to reactor safeguard and auxiliary
equipment in the auxiliary building, containment and turbine building.
The licensee determined that the simultaneous tripping of all operating service water pumps
is extremely improbable and not a viable threat to the safe operation of the Salem units. The
basis for this determination is rooted in the geographic location, engineering design, and
operating history of the service water system. The circulating water intake structure is
located on a bend in the Delaware River, which allows for a greater debris and silt
accumulation on the trash rack than does the service water intake structure. The circulating
water pumps are higher capacity pumps - drawing 185,000 gpm each compared to 10,800
gpm per service water pump. This higher capacity creates a greater suction pressure, thus an
increased propensity for debris intake. During normal full power operation, all six
circulating pumps are operating, whereas only three out of the six service water pumps are
running. A stopped service water pump will "auto" start in the event that pump discharge
header pressure falls to 100 psig. The six service water pumps for each unit are arranged in
groups of three pumps each, and each group of pumps for a unit is installed in alternate
watertight compartments inside the intake structure. Damage or blockage to two adjacent
compartments of the intake can occur without a total loss of service water to either unit.
Due to known high silting deposit rates of the Delaware River at the Salem Generating
Station, checks are made of the actual buildup of silt in the intake area before any service
13
water pump is started after a shutdown period of more than two weeks. In addition, the
Maintenance Department performs checks for silt buildup on a routine basis. Any buildup
greater than two feet at either the screens or the pump suction will be removed. Operating
history has shown that the Unit 1 circulating pumps are most susceptible to debris trips. The
service water pumps have never tripped due to excessive debris buildup.
On June 6, 1993, the NRC conducted a teleconference with the licensee concerning the
above matter. The NRC determined that*service water was not particularly vulnerable to
debris-induced inoperability beyond the design basis.
D.
Open Item Follow-up
(Open) Unresolved Item 50-272 and 311193-15-02. Improper Emergency Diesel Generator
(EDG) Fuel Injector Studs. This item was opened in the last routine resident inspection
report subsequent to the licensee's determination on March 15, 1993, that the fuel injection
tube studs for the No. 9-Left and No. 8-Left cylinders (two studs per cylinder) on the 2A
EDG were made from the wrong material and improperly machined. The inspector left the
item open pending PSE&G's investigation into: the effect the improper stud installation
might have had on past EDG operability; the root cause of the appearance of the improper-
material studs in their inventory; and, the potential applicability and necessity of a 10 CFR
Part 21 Report for the matter.
In May 1993, the licensee discovered that the four improper studs found on March 15, 1993,
had been replaced with four additional improper studs from warehouse inventory. PSE&G
replaced these studs again, this time with the proper studs, and the 2A EDG was restored to
an operable status prior to. the conclusion of the 2R7 refueling outage.
As a result of the recurring problems encountered with obtaining and installing the proper
studs, PSE&G formed an engineering and procurement task team to evaluate the effect of
having the wrong studs installed on an EDG and to determine the root cause of the mis-
procurement and installation of the improper studs. The inspector met with members of the
PSE&G task team several times during this inspection period and determined that licensee
engineering had evaluated the improper studs through calculations and destructive testing and
found the improper studs had been suitable for use in the EDGs over a short period of time
and that EDG operability had not been compromised due to the improper studs. The
improper studs were determined to be stronger than the correct studs, but because of the
differences in material and machining, the improper studs failed through brittle fracture, not
ductile failure, and were therefore more susceptible to high-cycle fatigue failure than the
correct studs. Because the improper studs were not installed in any one EDG long enough to
be exposed to a critical number of cycles, this susceptibility to fatigue failure could never
became evident, and PSE&G concluded that the EDGs had remained operable during the
period even though the improper studs were installed. PSE&G also informed the inspector
that they did not believe 10 CFR Part 21 reporting requirements applied to this case because
14
the task team had determined that the original procurement of the wrong studs had been due
to inadequate specifications given to the new vendor (Cascade Allied Diesels) by PSE&G
when the original vendor (Alco) was no longer available to supply the studs.
Through the discussions with the PSE&G task team and the review of test documents, the
inspector concluded that the licensee's operability and 10 CFR Part 21 determinations were
appropriate. Pending the task team's further investigation into the root cause of this event
and PSE&G's corrective actions, this item remains open.
4.2.2 Hope Creek
A.
10 CFR 21 Notification Regarding Microswitches
On April 29, 1993, the licensee identified a deficiency regarding heat damage to a particular
series of DC powered microswitches (as discussed in NRC Inspection Report 50-354/93-11).
Since then, PSE&G has conducted a review of the switch design and concluded that there
was no immediate safety significance with respect to switch operability. In addition, they
have made a 10 CFR Part 21 notification. A supplemental report describing their findings is
expected to be issued by August 5, 1993. This 10 CFR Part 21 issue will remain open
pending NRC review of the supplemental report.
5.
PLANT SUPPORT
5.1
Radiological Controls and Chemistry
5.1.1 Inspection Activities
The inspector verified on aperiodic basis PSE&G's conformance with the radiological
protection program.
5.1.2 Inspections Findings - Salem
A.
Steam Generator Detectable Activity
On June 9, 1993, chemistry technicians discovered detectable activity (3 x 10-8 microcuries
per milliliter) in the No. 12 steam generator (SG). The licensee attributed the increased
activity to the iodine spike following the trip of Unit 1 on June 8, 1993 (see Section
2.2.1.B). Operations personnel promptly entered an abnormal procedure Sl.OP-AB.SG-
0001, "Steam Generator Tube Leak," and took actions to evaluate and mitigate any potential
leakage. The increased activity in the No. 12 SG was confirmed by a radiation monitor
(1Rl9) alarm on the blowdown line for the No. 12 SG. Operations implemented increased
SG sampling and took additional radiological precautions in handling potentially contaminated
secondary process flows. The activity level initially remained constant and the primary to
secondary leakage rate was determined to be less than one gallon per day (gpd).
15
On June 11, 1993, blowdown was placed in service and within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> the activity level
was less than detectable. The licensee continued to closely monitor the activity in the No. 12
SG with permanently installed radiation monitors on SG blowdown, condensate filter, and
main steam lines and condenser gas effluent exhaust. The licensee has scheduled a special
helium test of the No. 12 SG during the next refueling outage to identify the suspected tube
leakage. In addition, the licensee will conduct routine outage inservice inspection tests on
the tubesheets for all four SGs during the outage.
The inspector observed the implementation of the abnormal operating procedure and follow-
up actions in response to the detectable activity in the No. 12 SG. The inspector discussed
radiological precautions with plant operators and the chemistry supervisor. The inspector
found the licensee's actions appropriate and aggressive in addressing potential radiological
and operational concerns.
B.
Motor Driven Auxiliary Feedwater (AFW) Pumps Auto Start
On June 22, 1993, at 3:26 a.m., Nos. 21 and 22 AFW pumps auto started with Unit 2 in
Mode 3 (Hot Standby) at normal operating temperature and pressure. Chemistry department
personnel were returning a condensate polishing demineralizer to service when a low suction
pressure condition resulted in a trip of the steam generator feedwater pumps (SGFPs). A
loss of SGFPs caused the AFW pumps to start in order to maintain steam generator levels.
The licensee determined that poor control by chemistry personnel of the condensate polishing
system fill and vent operation, combined with a leaking valve, resulted in air introduction
into the SGFP suction lines. The air resulted in suction pressure perturbations and
subsequently caused low SGFP suction pressure and a trip of both SGFPs.
Licensee corrective actions included a review of the event with chemistry personnel,
modifications to appropriate procedures and tagging requirements, development of a
chemistry department troubleshooting procedure, and repair of the leaking valve.
The inspector. discussed the event with plant personnel and concluded that the licensee
appropriately responded to the event. The inspector subsequently reviewed the Licensee
Event Report (LER) which documented the event and determined the LER was well written
and accurate.
C.
2R15 Radiation Monitoring System Inoperability
On July 7, 1993, the licensee removed the 2R15 (condenser exhaust noble gas effluent
process monitor) from service due to observed water in its sample line. The sample line
taps off the discharge from the condensers. The licensee entered Technical Specification 3.3.3.1.b, Action 26, and initiated sampling as the preplanned alternate method of
monitoring. The 2R15 channel is used to provide early indication of a primary to secondary
leak in a steam generator. In the event of a leak in any steam generator with the 2R15
16
- channel inoperable, the 2R19 (steam generator blowdown process monitor), 2R40
(condensate process filter monitor), and 2R46 (main steamline process monitor) would
function to allow identification and mitigation of the leak.
The licensee's investigation determined that stuck open condenser shell ball check float
valves had allowed water to carry over to the condenser waterbox priming tank. The
vacuum pump removes entrained air from the condenser waterbox through this priming tank
and discharges past the 2R15 sample line to the exhaust stack. The licensee determined that
silt and scale, which carried over with the water from the condenser waterboxes, caused
priming tank drainline blockage. The licensee found that river debris caused the ball check
float valves to stick open and attributed the failure to inadequate design.
The licensee drained and dried the 2R15 sample line, and replaced the sample filter. The
licensee cleaned the priming tank drain line and the priming tank. In addition, the licensee
opened and cleaned the ball check float valves. On July 17, 1993, the licensee returned the
2R15 channel -to service upon successful completion of a channel functional test and channel
calibration.
The inspector reviewed the applicable licensee report (Special Report 93-3) and follow-up
actions. On a priming system walkdown, the inspector noted continuous circulating water
flow past several ball check float valves on Unit 2 as well as Unit 1. The inspector
discussed this condition with the system engineer and determined that the flow was due to the
inadequate design of the ball check float valves. The inspector observed that cleaning the
ball check float valves alone does not prevent flow to the priming tank. The licensee was
_ aware of this deficiency and had initiated a design change package (DCP) prior to the July
event to install new loop seals to replace the ball valves to prevent future water carryover.
The inspector determined that water carryover to the priming tank, with proper priming tank
drainage, will not compromise R15 monitor operability and the licensee maintains adequate
indication of R15 operability in the unit control rooms. This modification is scheduled for
the fall of 1993 for Unit 1 and for the fall of 1994 for Unit 2. This item will remain open
(URI 50-272 and 311/93-19-03) pending licensee modification to the existing ball check float
valves and NRC review of DCP adequacy.
5.1.3 Inspection Findings - Hope Creek
A.
Spent Fuel Cask and Shipment
On July 19, 1993, the licensee determined that an incoming spent fuel shipping cask (Model
NLI-1/2, right circular cylinder weighing 49,250 lbs.), was found to have removable surface
contamination levels (26,000 dpm/100 cm squared) that were in excess of the 22,000
- dpm/100 cm squared limit specified in Department of Transportation (DOT) shipping
regulations. The cask was shipped from GE, Vallecitos, CA, on July 15, 1993, and
exhibited contamination levels of about 2,000 dpm/100 cm squared upon departure. The
licensee made a one-hour notification to the NRC as required by 10 CFR 20.205.
17
Subsequent review of the smear sample results by the licensee determined that the results
were conservative and did not consider surface area averaging permitted by the regulations.
In addition, a conservative counting efficiency had been used to analyze the smears. Final
smear results were below DOT limits. The cask was enclosed by a personnel barrier. The
elevated levels upon receipt were attributed to cask weeping. The licensee plans to change
its receipt survey procedures to provide for more accurate smear counting and evaluation of
results.
The inspector discussed the event with licensee personnel and NRC Region I specialists. The
inspector concluded that the licensee acted conservatively and in accordance with regulatory
requirements.
The inspector also reviewed the licensee's fuel handling and shipping activities for six fuel
pins from a fuel assembly that was discharged from the core in 1991. One fuel pin had
failed during that cycle. The inspector concluded that licensee activities on the fuel floor and
relative to this shipment were appropriate.
5.2
5.2.1 Inspection Activities
The inspector reviewed PSE&G's conformance with 10 CFR 50.47 regarding implementation
of the emergency plan and procedures. In addition, the inspector reviewed licensee event
notifications and reporting requirements per 10 CFR 50.72 and 73.
5.2.2 Inspection Findings - Common
A.
Annual Emergency Plan Exercise
The NRC inspected licensee performance during the annual emergency plan exercise
conducted at Salem during the period June 22-24, 1993. The exercise occurred during the
dayshift on June 23. The inspector monitored licensee actions from the Salem Technical
Support Center. NRC Inspection Report 50-272 and 311/93-12 and 50-354/93-08 detail the
results of the exercise.
B.
Unusual Event (UE)
An UE was declared at Salem on July 10, 1993 (see section 2.2.1.A). The inspector
concluded that the UE declaration and subsequent Salem and Hope Creek notifications were
appropriate.
18
5.3
Security
5.3.1 Inspection Activities
PSE&G's verified regularly the conformance with the security program, including the
adequacy of staffing, entry control, alarm stations, response to advisories, and physical
boundaries.
5.4
Housekeeping
5.4.1 Inspection Activities
The inspector reviewed PSE&G's housekeeping conditions and cleanliness controls in
accordance with nuclear department administrative procedures.
5.4.2 Inspection Findings - Common
A.
Service Water Pump Structures
The inspector toured the Salem and Hope Creek service water pump structures (SWPSs)
during the* period. The SWPS's contain the safety related service water pumps, strainers,
travelling screens and related auxiliary support equipment. These systems provide each unit
with its ultimate heat sink requirements (Delaware River).
The inspector noted poor housekeeping and material condition in both SWPSs. Deficiencies
noted included leaks, material adrift, unsecured equipment, water tight doors difficult to
operate, and electrical panel doors opened. The inspector discussed these items with licensee
management personnel, including their expectations. Further, the inspector noted that the
licensee had implemented plans to upgrade these areas.
5.5
Fire Protection - Common
5.5.1 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 .
19
5.5.2 Inspection Findings *
A.
Salem Diesel Driven Fire Pumps (DDFP)
During surveillance testing on July 22, 1993, at 2: 15 p.m., the Salem No. 1 DDFP engine
high temperature alarm occurred. Fire protection operators shut down the engine. Similar
results occurred during a second attempt to run the engine.
The licensee declared the No. 1 DDFP inoperable. The No. 2 DDFP had previously been
declared inoperable, and the licensee is replacing the diesel engine per design change package
(DCP) lEC-3217 package 2. This is a similar DCP that was done for the No. 1 DDFP, and
is scheduled for completion by August 31, 1993.
The licensee implemented compensatory measures per procedure SC.FP-AP.ZZ-0003, which
included verification that the Hope Creek fire water supply cross connect was tagged open
and that both Hope Creek fire pumps were operable. The licensee unclogged the cooling
water strainer, successfully retested the DDFP and declared it operable.
The inspector reviewed the incident report, applicable procedures, and discussed this item
with fire protection personnel. The inspector concluded that licensee actions were
appropriate.
6.
LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS,
AND OPEN ITEM FOLLOW-UP
6.1
LERs and Reports
PSE&G submitted and reviewed for accuracy and evaluation adequacy the following special
and periodic reports.
Salem and Hope Creek Monthly Operating Reports for May and June 1993
Special Report 93-3 (See Section 5.1.2.C)
The inspector concluded that the licensee appropriately issued the above reports.
Salem LERs
Unit 1
LER 89-31, revision 2 concerned high oxygen concentration in the waste gas holdup
system. The licensee's continuing investigation concluded that valve leakage was the
root cause. The licensee repaired the valve, and oxygen levels have been satisfactory.
20
The inspector reviewed the revised LER and concluded that licensee actions were
appropriate. The inspector closed the LER.
LER 93-11 described the Unit 1 reactor trip which resulted from a unit turbine trip
caused by the loss of main condenser vacuum which occurred when debris blocked
the supply of river water to the circulating water system (see Section 2.2.1.B of this
report). The inspector reviewed the LER, found it to appropriately address the event,
and the LER is therefore considered closed.
LER 93-12 described the lC vital bus trip which occurred on June 9, 1993, as a
result of personnel error (see Section 3.3.1.B). The inspector reviewed the LER,
concluded that it adequately reported the event, and this LER is closed.
Unit 2
LER 93-07 described the May 28, 1993, manual reactor trip necessitated by the
inadvertent dropping of the control rod bank C, group 1, rods into the core during a
Unit 2 startup. This event was documented as part of NRC Inspection Report 50-272
and 311/93-81. The inspector reviewed the LER and noted no discrepancies, and this
LER is therefore closed.
LER 93-08 described the rod control system design basis concerns at both Salem
units. This concern was the subject of NRC Augmented Inspection Team Report 50-
272 and 311/93-81. The inspector determined that the LER adequately documented
the issue, and the LER is closed.
LER 93-09 described the automatic start of the Nos. 21 and 22 auxiliary feedwater
pumps on June 22, 1993 (see Section 5.1.2.B). The inspector reviewed the LER,
concluded that it adequately reported the event, and this LER is closed.
Hope Creek
LER 93-003 discussed a partial loss of off-site power, which was caused by failure of
a 13.8 kv pothead on a transformer feeder in the 13.8 kv ring bus. The inspector
reviewed this event in NRC Inspection Report 50-354/93-11 and closed this LER.
LER 93-004 discussed a reactor trip caused by a component failure in the
electrohydraulic control system, which resulted in a scram on reactor high pressure.
The inspector reviewed this event in NRC Inspection Report 50-354/93-11 and closed
this LER.
21
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
Salem
272 and 311/93-15-02
4.2.1.D
Open
Hope Creek
None
7.
EXIT INTERVIEWS/MEETINGS
7.1
Resident Exit Meeting
The iD.spectors met with Mr. C. Vondra and Mr. R. Hovey and other PSE&G personnel
periodically and at the end of the inspection report 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 CFR 2 restrictions.
7.2
Specialist Entrance and Exit Meetings
Date(s)
6/7-11/93
6/5-28/93
6/14-18/93
6/21-25/93
Subject
Security
Augmented
Inspection Team
Radiological
Controls
Operator
Licensing
Inspection
Report No.
50-272 and 311/93-18;
50-354/93-17
50-272 and 311/93-81
50-354/93-19
50-354/93-14
Reporting
Inspector
Albert
Ruland
Nimitz
Florek
22
7 .3
Management Meetings
The inspector attended a management meeting which was held on July 16, 1993, in the
Region I Office in King of Prussia, PA, to discuss a number of issues, involving licensee
performance. Details of the meeting and the meeting handouts are discussed in NRC
correspondence dated July 23, 1993.