ML18100A697
| ML18100A697 | |
| Person / Time | |
|---|---|
| Site: | Salem, Hope Creek  |
| Issue date: | 10/31/1993 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18100A695 | List: |
| References | |
| 50-272-93-21, 50-311-93-21, 50-354-93-21, NUDOCS 9311150136 | |
| Download: ML18100A697 (23) | |
See also: IR 05000272/1993021
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos. 50-272/93-21
50-311/93-21
50-354/93-21
License Nos. DPR-70
Licensee:
Public Service Electric and Gas Company
P.O. Box 236
Hancocks Bridge, New Jersey 08038
Facilities:
Salem Nuclear Generating Station
Hope Creek Nuclear Generating Station
Dates:
September 5, 1993 - October 16, 1993
Inspectors:
C. S. Marschall, Senior Resident Inspector
S. T. Barr, Resident Inspector
J. G. Schoppy, Resident Inspector
T. H. Fish, Resident
s
R. J. Sum
, P * t
Approved:
/(J
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 suppt>rt, and safety assessment/quality verification. The Executive
Summary delineates the inspection findings and conclusions .
9311150136 931103
"""-
ADOCK 05000272
G
EXECUTIVE SUMMARY
Salem Inspection Reports 50-272/93-21; 50-311/93-21
Hope Creek Inspection Report 50-354/93-21
September 5, 1993 - October 16, 1993
OPERATIONS (Modules 71707, 93702)
Salem: The licensee operated the Salem units safely. Operator actions in response to
steam generator sodium intrusion was determined to be prompt and appropriate in mitigating
potential consequences. The core offload for the Unit 1 eleventh refueling outage was well-
controlled and safely conducted. An Unusual Event was declared due to a* fire in a service
water bay. Shift personnel took prompt action to distinguish the fire and minimize the effect
on plant personnel and equipment. A fire watch person was present in the area at the time of
the occurrence. An unresolved item was opened pending licensee event investigation and
NRC review. Operations staff appropriately determined that a blowdown valve isolations did
not require a report to the NRC.
Hope Creek: The licensee operated the Hope Creek unit safely. Operations personnel
responded well to the mis-operation of two emergency diesel generator room cooler inlet
valves.
MAINTENANCE/SURVEILLANCE (Modules 61726, 62703)
Salem: The licensee's initial response and follow-up corrective actions concerning a
problem with the auxiliary feed pump trip mechanism was determined to be prompt and
effective.
Hope Creek: Maintenance personnel performed very well during replacement of chain
links in the traveling screen for "C" service water pump.
ENGINEERING (Modules 37828, 71707)
Salem: The inspectors noted that engineering personnel properly prioritized work
activities. A review of the Procedure Upgrade Program concluded that it had been a good
licensee initiative and a very effective program. Inspectors closed Unresolved items 93-08-
01 and 93-15-02 .
ii
Hope Creek: The inspectors noted that engineering personnel properly prioritized work
activities. Engineering conducted a comprehensive root cause determination and an
appropriate 10 CFR 50.59 applicability review associated with the mis-operation of two room
cooler inlet valves.
PLANT SUPPORT (Modules 30702, 71707, 90712, 92701, 92702)
Salem: Periodic inspector observation of station workers and Radiation Protection
personnel noted good implementation of radiological controls and protection program
requirements. Inspectors opened an Unresolved Item pending completion of R-1 lA
troubleshooting activities. During an Emergency Preparedness (EP) practice drill, the EP
staff appropriately identified areas for improvement. The drill provided good practice for the
emergency response participants and the EP staff.
Hope Creek: Periodic inspector observation of station workers and Radiation Protection
personnel noted good implementation of radiological controls and protection program
requirements. Radiation protection personnel detected several leaking main steam line drain
valves, which were causing degraded steam tunnel conditions.
Common: The inspectors determined that the licensee appropriately implemented security
program requirements. The licensee acted to deny access to one contract supervisor due to a
fitness for duty concern. An inspector observed fire fighting training and concluded that the
activity was well done.
SAFETY ASSESSMENT AND QUALITY VERIFICATION (Module 40500)
Common: The inspectors concluded that the onsite Safety Review Groups (SRGs)
adequately perform the function described in Technical Specifications for each unit.
Although line management stated that the SR Gs made positive contributions to plant safety,
the managers could not easily provide specific examples. The inspectors found that while
SRGs made recommendations for performance improvement, the recommendations generally
did not significantly affect or improve safety performance. The line organization considered
greater senior management support necessary to iinprove SRG effectiveness.
iii
TABLE OF CONTENTS
EXECUTIVE SUMMARY ...................................... ii
TABLE OF CONTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv
1.
2.
3.
4.
5.
SUMMARY OF OPERATIONS ............................... 1
1.1
Salem Units 1 and 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.2
Hope Creek . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
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
2.2.3 Common . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
MAINTENANCE/SURVEILLANCE TESTING . . . . . . . . . . . . . . . . . . . . . 6
3 .1
Maintenance Inspection Activity . . . . . . . . . . . . . . . . . . . . . . . . . . 6
3.2
Surveillance Testing Inspection Activity . . . . . . . . . . . . . . . . . . . . . . 6
3. 3
Inspection Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
3.3.1 Salem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
3.3.2 Hope Creek . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
ENGINEERING ........................................ 9
4.1
Salem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
4.2
Hope Creek . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10
PLANT SUPPORT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11
5 .1
Radiological Controls and Chemistry . . . . . . . . . . . . . . . . . . . . . .
11
5 .1.1 Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . * . . .
11
5 .1.2 Inspections Findings - Salem . . . . . . . . . . . . . . . . . . . . . . .
11
5.1.3 Inspection Findings - Hope Creek . . . . . . . . . . . . . . . . . . . .
12
5.2
Emergency Preparedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12
5.2.1 Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12
5.2.2 Inspection Findings - Salem . . . . . . . . . . . . . . . . . . . . . . .
13
5.3
Security . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13
5. 3 .1 Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13
5. 3 .2 Inspection Findings - Common . . . . . . . . . . . . . . . . . . . . . .
13
5.4
Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14
5 .4.1 Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14
5.4.2 Inspection Findings - Common . . . . . . . . . . . . . . . . . . . . . .
14
lV
TABLE OF CONTENTS (CONTINUED)
6.
SAFETY ASSESSMENT AND QUALITY VERIFICATION . . . . . . . . . . . .
14
6.1
Common. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14
7.
LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL
REPORTS, AND OPEN ITEM FOLLOW-UP . . . . . . . . . . . . . . . . . . . . .
17
7 .1
LERs and Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17
7 .2
Open Items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17
8.
EXIT INTERVIEWS/MEETINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
8 .1
Resident Exit Meeting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
8.2
Specialist Entrance and Exit Meetings . . . . . . . . . . . . . . . . . . . . . .
18
v
DETAILS
1.
SUMMARY OF OPERATIONS
1.1
Salem Units 1and2
Salem Unit 1 operated at or near full power until October 1, 1993, when load was reduced to
commence the unit's eleventh refueling outage. The unit was defueled at the end of the
inspection period.
Salem Unit 2 began the inspection period operating at 100% power. Power was temporarily
reduced to 80% on September 17, 1993, for circulator waterbox cleaning. On October 4,
power was reduced to 70% for a station power transformer (SPT) outage. On October 12,
the turbine generator was taken off line and power reduced to 6 % to address steam generator
chemistry concerns. The unit was at 65 % power at the end of the period due to No. 2 SPT
outage.
1.2
Hope Creek
Hope Creek operated at power throughout the inspection period, with the exception of small
power reductions to support scheduled surveillance activities. At the end of the report
period, Hope Creek had been on line 150 days.
2.
OPERATIONS
2.1
Inspection Activities
The inspectors verified that Public Service Electric and Gas (PSE&G) operated the facilities
safely and 1n 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 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> of deep back-shift inspection.
2.2
Inspection Findings and Significant Plant Events
2.2.1 Salem
A.
High Sodium Levels in Unit 2 Steam Generator
At 10:20 a.m. on October 12, 1993, chemistry reported steam generator (SG) blowdown
sodium concentration of 900 ppb. This sodium concentration placed the plant in Action
Level 3 (described below) of chemistry procedure S2.0P-AB.Chem-0001 (Abnormal
Secondary Plant Chemistry). At 10:40 a.m. operators commenced a power reduction at 1 %
2
per minute in accordance with chemistry's recommendation. Operators removed the turbine
generator from the line and stabilized reactor power at 6 % . Operation at low power was
initiated to minimize chloride induced stress corrosion cracking in the SG U-tube crevices.
The licensee had been operating Unit 2 at 90% power prior to the sodium intrusion, while
making repairs to the No. 23 heater drain pump. The licensee replaced the pump due to a
high vibration problem and, in the process, allowed high conductivity (500 ppm sodium)
ground water to seep into the pump well. Chemistry staff discovered the elevated sodium
levels following a two minute run on the No. 23 heater drain pump. Plant staff reduced
power and closely monitored chemistry until sodium levels and conductivity were well below
required specifications. The licensee exited the abnormal chemistry procedure and, at 9:30
p.m. on October 12, commenced a power increase. At the end of the inspection period, the
licensee continued in their repair effort on the No. 23 heater drain pump.
The inspector observed the control room activities following the SG sodium discovery. The
inspector noted that operators took prompt corrective action in response to the SG chemistry
problem and performed a well-controlled and safe power reduction. The inspector observed
good coordination between operations and chemistry in mitigating the potential consequences
of the elevated sodium levels in the SGs.
The inspector noted that the licensee's approach to mitigating the elevated sodium levels
differed somewhat from the guidance provided in the operating procedure. Procedure
S2.0P-AB.Chem-0001 Step 3.34 (for Action Level 3 Chemistry) states, "Initiate actions
within the next four hours to place the unit in hot or cold shutdown as recommended by the
Chemistry Department." The procedure incorporates EPRI/Steam Generator Owners Group
Guidelines for SG chemistry control. The Steam Generator Owners Group developed three
Action Levels that are considered the minimum requirements for protection against secondary
system and SG corrosion. Action Level 3 states: "Regardless of the duration in Action Level *
3, the plant should (emphasis added) be shutdown to hot or cold shutdown, based on the
specific corrosion concern, and the most rapid means of cleanup." During the power
reduction, operations and chemistry discussed the requirements of the abnormal chemistry
procedure and decided to stabilize the plant at 6% power and closely monitor sodium levels
and hideout return. Chemistry determined that, at that power level, sufficient cleanup of the
impurities occurred. Based on the chemistry staff recommendation, operations determined
that a shutdown to hot shutdown was not required. Operations viewed the procedure Action
Level as guidance (a "should" vice a "shall") and relied more on chemistry's
recommendations. The licensee is now in the process of revising the procedure to reduce
power as necessary in accordance with chemistry recommendations vice automatically
requiring a shutdown to hot or cold shutdown. The inspector concluded that the licensee
took prompt and appropriate corrective actions .
3
B.
Unit 1 Core Offload
At 11:24 a.m. on October 13, 1993, the licensee commenced core offload for the Unit 1
eleventh refueling outage. The licensee experienced only minor delays and completed the
evolution at 12:07 a.m. on October 16. The inspector observed fuel handling activities from
the fuel handling building, containment refueling platform and the control room. The
inspector noted effective communication and control by both the licensee and Westinghouse
fuel handlers. The inspector determined that the licensee properly implemented their
refueling procedure and conducted the core offload with full regard for safety and quality
control.
C.
Unusual Event Declared as a Result of a Fire in a Safety Related Area
At 9:58 p.m. on October 13, 1993, the Unit 1 shift supervisor received a report of a fire in
the No. 12 service water piping penetration bay. The shift supervisor notified the PSE&G
Fire Department, which responded to the scene. The fire watch, who was present observing
grinding activities, attempted to put the fire out with a dry chemical extinguisher, but was
unsuccessful. PSE&G Fire Department used two dry chemical fire extinguishers for initial
knock down of the fire, and followed with two pressurized water extinguishers to fully
extinguish the fire. The fire lasted less than ten. minutes .
Salem operators declared an Unusual Event (UE) at 11:08 p.m. on October 13, based on an
assessment that plant conditions warranted increased awareness on the part of State and local
authorities (event of potential public interest). The declaration was in accordance with Salem
Event Classification Guide (ECG), Section 17.A. Operations evacuated the Unit 1 and Unit
2 auxiliary buildings and assembled personnel at the control point for accountability. Salem
operators terminated the UE at 11:57 p.m. on October 13. Following the fire, three
contractor employees were transported to a local hospital in response to chest pains, smoke
inhalation, and nausea. All three were apparently exposed to the dry chemical and smoke
and were treated and released from the hospital later that night.
Sparks from a grinding activity ignited pipe insulation piled in the work area. Contractor
employees were grinding on the upper level scaffolding when grinding sparks dropped to a
lower level of the scaffolding and ignited insulation* from the service water pipe they were
grinding. The fire watch did not notice the fire until it reached the upper level scaffolding,
where he was located. The licensee determined no equipment sustained damage.
The inspector noted excellent response time by the PSE&G Fire Department. Fire
Department and Emergency Medical Services personnel performed very well in mitigating
the potential consequences of the fire. The inspector toured the service water bay post-fire
and post-cleanup. The inspector found no equipment damage and noted that the area was
completely restored following cleanup activities. At the end of the inspection period, the
licensee had not completed the root cause investigation of the fire. This item remains open
pending NRC review of the licensee findings (URI 50-272 and 311/93-21-001).
4
D.
Isolation of Steam Generator Blowdown and Steam Generator Blowdown
Sampling
On September 16, during Salem Unit 1 normal plant operation, plant staff performed routine
maintenance on the no. 11 Auxiliary Feedwater (AFW) Pump breaker. Operators tagged the
AFW pump prior to releasing the breaker for maintenance.
The maintenance activity
resulted in an AFW pump auto start signal, with resultant isolation of steam generator
blowdown and steam generator blowdown sampling. Operators determined the cause of the
isolation, reset the auto start signal, and re-established steam generator blowdown and
sampling. In addition, the operations staff initiated an Incident Report (IR), as required by
procedure NC.NA-AP.ZZ-0006. As noted in the IR, the operations staff determined that the
isolation was not reportable.
During a review of the IR, the inspectors noted that Salem, Unit 1 Technical Specification
Table 3.6-1, Section E., lists the steam generator blowdown and sample lines as containment
isolation valves. The inspectors questioned the basis for determining that the valve isolations
did not meet the reporting requirements of 10 CFR 50.72 or 10 CFR 50.73. The licensee
indicated that actuation of the steam generator blowdown valves as a result of AFW
automatic initiation did not constitute a engineered safety feature actuation, and therefore the
event was not reportable. The inspectors reviewed the Salem Updated Final Safety Analysis
Report (UFSAR), section 6.2.4, Containment Isolation System, and UFSAR Table 6.2-10,
Containment Isolation - Major Piping Penetrations. The UFSAR indicated that a phase A
containment isolation signal initiates the closure of the steam generator blowdown and
blowdown sample valves. The UFSAR further states that a safety injection signal generates
the phase A containment isolation signal. The inspectors concluded that the operations staff
had appropriately determined that 10 CFR 50. 72 and 10 CFR 50. 73 did not require a report
for the isolation of the steam generator blowdown and blowdown sample valves.
2.2.2 Hope Creek
A.
Safety Auxiliaries Cooling System (SACS) Valve Mis-operation
On September 6, 1993, with the unit at 100% power, a licensed operator entered the "D"
emergency diesel generator (EDG) room in preparation for tagging out valve EGHV-2398H.
This valve supplies SACS cooling water to the EDG's room cooler; each EDG has two
redundant room coolers. Upon entering the room, the operator discovered one of the room
cooling fans running (there are two, one per room cooler) blowing ambient air into the room,
instead of the expected cool air. Because this condition was abnormal, the operator
investigated the SACS supply valve (EGHV-2398D) to the running room cooler. The valve
is interlocked such that it opens whenever its respective room fan starts. The operator found
that EGHV-2398D closed.
_________
]
5
Next, the operator checked to see whether the valve air actuator had bled off the air pressure
holding the valve closed against spring pressure. Finding the correct condition (air bled off),
he believed the valve was stuck and contacted maintenance personnel. Once maintenance
personnel agitated the valve, it opened, restoring SACS flow to the room cooler.
The operator returned to his original task, to tag out EGHV-2398H. When he isolated and
vented the actuator, the valve also failed to open. Again, once maintenance personnel
agitated the valve, it opened.
In response to the unreliable performance of both SACS room cooler supply valves for EDG
"D", the senior nuclear shift supervisor (SNSS) directed that at least one room cooler valve
in the other three EDG compartments be failed open. This precautionary measure ensured
that room cooling would be available in the event any EDG started. Also, because this type
of actuator is on valves. for room coolers for other emergency systems, all such room cooler
valves were cycled to ensure their operability. All the valves functioned properly.
The inspector walked down the affected EDG room cooler, discussed the event with the
Operations staff, and reviewed the Licensee Event Report (LER). The inspector noted that
the licensed operator who first investigated the stuck valve demonstrated very good EDG
integrated system knowledge, the SNSS took comprehensive, conservative steps to ensure
operability of not just EDG room coolers, but of all room coolers with similar valve
actuators, and that the LER was accurate and thorough. Based on these observations, the
inspector concluded that the licensee responded well to the event. Further discussion of
follow-up on this finding is discussed in Section 4.2.A.
2.2.3 Common
During the period, the inspector reviewed the use of "night orders" at both Salem and Hope
Creek. The purpose of the inspection was to ascertain whether night orders were being used
to change the intent or use of station procedures. The night order books for both Salem and
Hope Creek were reviewed for all such orders that are currently in effect. It was found that
both Salem and Hope Creek night orders met the requirements of the Nuclear Department
administrative procedure, NC.NA-AP.ZZ-0005(Q), which states that if there is a conflict
between the night order book and any other approved procedure or the technical
specifications, the latter documents shall govern. Additionally, no examples were identified
where night orders were used in a manner that would cause operators to not follow station
procedures. One example was found at Salem where operators were informed of a non-
conservative procedure requirement for diesel generator fuel storage tank minimum level;
however, the appropriate procedures were also changed at the same time, and the night order
was issued to ensure that operators understood the required action since it was a change to
previous practice.
There were notable differences employed at the two stations regarding the format, content
and duration of night orders; however, for the purpose of the inspection both stations were
acceptable.
6
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:
Work Order(WO) or Design
Change Package <PCP)
Description
Salem 2
Salem 2
Hope Creek
Hope Creek
Various
Hope Creek
Various
Hope Creek
Various
No. 23 Auxiliary feed pump
Auxiliary feed pump discharge check valve
22AF8
11 C" service water traveling screen bent
chain link repair
Service water silt survey
11 A
11 emergency diesel generator system
outage
Low pressure coolant injection
11A
11 system
outage
The maintenance activities inspected were effective with respect to meeting the safety
objectives of the maintenance program.
3.2
Surveillance Testing Inspection 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.
7
The inspector reviewed the following surveillance tests with portions witnessed by the
inspector:
Salem 2
Hope Creek
Hope Creek
Hope Creek
Procedure No.
S2.0P-ST.DG-0001
HC.OP-IS.BC-OlOl(Q)
HC.OP-IS.EG-OlOl(Q);
HC. OP-IS.EG-0102(Q)
HC.OP-ST.KJ-OOOl(Q)
2A Diesel Generator Surveillance
Test
Low Pressure Coolant Injection
"A" Inservice Test
Safety Auxiliaries Cooling System
Subsystem A/B Valves Inservice
Test
Monthly Operability 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.
Auxiliary Feed Pump Trip
On September 9, 1993, the No. 23 auxiliary feed pump (AFP) tripped during surveillance
test S2-0P-ST.AF-003, "Inservice Testing - No. 23 Auxiliary Feedwater Pump". Operators
found no apparent cause for the trip as no inadvertent operator action had occurred and no
overspeed condition existed (indicated speed was 3380 rpm and trip' speed is approximately
4032 rpm). The licensee entered the applicable Technical Specification (TS 3.7.1.2.6) and
dispatched maintenance personnel to investigate.
Maintenance and engineering determined that the No. 23 AFP appeared normal and further
investigated the overspeed trip mechanism. The licensee found some play in the trip linkage.
Maintenance determined that proper tappet nut seating in the trip mechanism would ensure
that the No. 23 AFP would not inadvertently trip. Operators ensured that the tappet nut was
flush to the trip lever and successfully operated the No. 23 AFP pump. Operations made an
"on-the-spot" change to the surveillance test to ensure proper trip mechanism engagement
and satisfactory completed the AFP surveillance on September 10, 1993 .
-1
8
The inspector observed the maintenance troubleshooting and determined that the licensee's
response was prompt and effective. The inspector reviewed the change to the surveillance
test and the completed surveillance test. The inspector verified that the required change was
made to the Unit 1 AFP surveillance as well. The inspector determined that the licensee's
actions were appropriate in identifying and correcting this deficient condition.
3.3.2 Hope Creek
A.
"C" Service Water Traveling Screen Chain Link Replacement
In late September 1993, maintenance personnel replaced 18 pairs of chain links (36 liJilks in
all) on the "C" service water pump traveling screen. Normal use caused wear and distortion
of the joints in the links, necessitating the repairs. Originally scheduled to take three full
days, September 22-24, maintenance completed the work by the afternoon of September 23,
more than a day early.
Two initiatives contributed to the early completion. The first involved a new method of
moving the screen. Prior screen work required stationing an extra person at the local screen
control panel, on a headset in direct communication with the crew working out at the screen.
When the crew needed the screen rotated, the local operator energized the traveling screen's
motor. However, in the recent repair, maintenance adapted an electric drill to the screen's
drive shaft and moved the screen using the drill. The new method had two advantages over
the old: 1) It eliminated the need for the extra person at the local control panel, and 2)
unlike local panel control, which allowed only for forward screen motion, the drill could
rotate the screens in the forward and reverse directions.
The second initiative involved a tool modification for the chain link tensioner and de-
tensioner. Prior repair work required manually adjusting the tensioner and consequently was
slow, tedious, and physically very tiring. However, for this work, maintenance designed an
electric threading tool to provide much quicker tensioning or de-tensioning of the links.
The inspector observed the repair work and noted good teamwork within the crew, frequent
visits to the job site by the crew supervisor, and spot-checks of the job by the senior
supervisor. The inspector discussed the work with the crew and noted their clear
understanding of the job scope. The supervisor clearly understood the effect of the work on
service water, a safety system. Lastly, the inspector discussed the time-saving tool
modifications with the supervisor. Based on observations and discussions with maintenance
personnel, the inspector concluded that Hope Creek maintenance staff used innovation and
effectively organized and managed the chain link replacement.
9
4.
ENGINEERING
4.1
Salem
A.
Procedure Upgrade Project Closeout
In July 1989, PSE&G initiated a procedure upgrade project (PUP) in order to perform a
human factors, technical format and content upgrade of approximately 3500 Salem
Operations, Maintenance, Chemistry, and Reactor Engineering procedures. PSE&G intended
the PUP to effectively eliminate procedures as the cause of plant operational or maintenance
incidents and to implement a long-term procedure maintenance program to assure procedure
quality is maintained through the revision process. By September 1993, the PUP had
reached the 99 % complete milestone, and PSE&G closed out the PUP organization and
turned its responsibilities over to the newly created Salem Procedure Maintenance Group
(PMG). The PMG is part of the Salem Technical Department and is intended to have 15
full-time PSE&G procedure writers with responsibility for maintaining procedures applicable
to the department where they originated.
Over the past four years of the PUP's existence, the inspector has noted the positive impact
PUP has had on procedure quality and improved plant performance. During this inspection
period, the inspector met with the PUP manager and the PMG manager to discuss final PUP
results and PMG implementation. The inspector verified that the PUP had completed the
99 % of its intended scope on schedule, and the remaining 1 % of the scope had been
transitioned to the PMG. Overall, the inspector concluded that PUP had been a good
licensee initiative and a very effective program.
B.
Open Item Follow-up
(Closed) Unresolved Item 50-272&311/93-08-01: Inadvertent discharge of a carbon dioxide
fire protection system. This event occurred on April 3, 1993, and the inspector concluded
that PSE&G had properly responded to the event and adequately determined its root cause.
The item was left open pending the inspector's review of the carbon dioxide fire protection
system licensing and design basis and the licensee's corrective actions. Through a
subsequent review of,licensing and engineering design documentation, including PSE&G's
response to NRC Branch Technical Positions and 10CFR50 Appendix B quality assurance
requirements, the inspector determined that the design of the carbon dioxide fire protection
system complied with all necessary requirements and that the system was constructed as
designed. The inspector discussed the licensee's corrective actions with the appropriate
Engineering and Plant Betterment and Salem Technical Department engineers and noted that
all electrical junction boxes similar to the one involved in this event had been caulked to
prevent water intrusion, the initiating cause of the event. The inspector concluded that this
event was not the result of improper design and that appropriate corrective actions had been
taken, and this item is closed.
10
(Closed) Unresolved Item 50-272&311/93-15-02: Improper emergency diesel generator
(EDG) fuel injector studs. This item was opened due to the licensee's determination that the
fuel injection tube studs for two cylinders on the 2A EDG were made from the wrong
material and improperly machined. Further review by the inspector had determined that the
wrong studs did not adversely affect EDG operability, but the inspector left the item open
pending a PSE&G task team's determination of root cause and corrective action
recommendations. PSE&G Quality Assurance (QA) Programs and Audits directed the
PSE&G task team involved in the investigation into root causes, causal factors, and
corrective actions to prevent event recurrence. The task team completed their effort on
September 16, 1993, and forwarded their report to the PSE&G Procurement and Material
Control Manager.
The inspector reviewed the licensee's report and noted that the task team had developed three
root causes for the event: less-than-adequate specification of the studs from the vendor; less-
than-adequate controls over receipt of the studs; and less-than-adequate corrective action
following the first discovery of incorrect studs. The report also included a list of ten
recommendations to provide for corrective actions for the event. The inspector discussed the
reports's conclusions with the QA engineer that had led the task team and determined that the
team had thoroughly investigated and detailed the failure of the barriers which allowed the
event to occur. The inspector also concluded that the team's recommendations properly
addressed the actions needed to be implemented to prevent event recurrence. Based on the
PSE&G task team's performance and the documentation of their results, the inspector closed
this item.
4.2
Hope Creek
A.
Engineering Analysis for Safety Auxiliaries Cooling System (SACS) Valve Mis-
operation
As a follow-up to the event involving mis-operation of SACS-to-room cooler valves
(described in Section 2.2.2.A), Hope Creek engineering conducted a root cause investigation
to determine why two valves failed to open. They initially concluded that, over time, the
valve type (double disk gate valve), combined with its quarterly surveillance frequency, made
it susceptible to mechanical binding. A search of facility historical data revealed that, in past
instances, valves remained closed for the normal three month duration between in service test
stroking requirements and, when stroked, exhibited increased stroke times or binding.
On September 7, 1993, engineering compiled a list of all susceptible valves and requested
they be cycled weekly instead of quarterly. Through the end of the Inspection Report period,
all valves operated properly during the weekly test.
Another contributing factor to valve binding was the amount of air pressure used to stroke
the valve closed (80 psig). Engineering performed tests which indicated that the excessive
pressure allowed the actuator to drive the gates farther into the seat than required. As a
11
result the additional seating force and gate travel reduced the ability of the spring in the
actuator to drive the valve open when air pressure was bled off. Testing showed that 60 psig
was sufficient to provide positive isolation of SACS without affecting the time to opening the
valves. Engineering subsequently reduced air pressure to 60 psig on all affected valve
actuators and returned half of them to their normal three month test interval. Plant staff will
continue to stroke the remaining half each week until the air pressure reduction has been
verified to be satisfactory.
Engineering also completed a 10 CFR 50.59 applicability review since these valves are part
of a system described in the Updated Final Safety Analysis Report. They determined that
reducing actuator air pressure to 60 psig did not require a safety evaluation.
The inspector monitored the Hope Creek's root cause determination, observed actuator
testing, discussed test results with the system lead engineer, and confirmed valve operation
using reduced actuator pressure for a sample number of valves. Based on his observations,
the inspector concluded that the licensee's disposition of the event was thorough and its
corrective actions were appropriate. The inspector also performed an independent 10 CFR
50.59 applicability review and confirmed that a safety review was not required.
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.
5.1.2 Inspections Findings - Salem
A.
Containment Isolations Due to lRllA Radiation Monitor Alarms
On October 11, 1993, and again on October 12, 1993, the Unit 1 lRllA containment
particulate radiation monitor went into alarm and initiated a containment vent isolation
engineered safety function (ESF). On October 14, 1993, the lRllA level spiked and caused
a containment vent isolation, without reaching the alarm setpoint. Salem Chemistry and
Radiation Protection Department review of the lRl lA strip charts and concurrent
containment activities did not reveal an explanation for the elevated radiation levels seen by
the detector on October 11 and 12. The licensee subsequently performed troubleshooting and
functional testing on the detector, and no problems were detected with the lRl lA. The
licensee returned the detector to an operable status .
i
!
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The inspector monitored the licensee's pursuit of the lRllA events and noted that their
initial response to the alarms and the reporting of the ESP actuations were appropriate. The
inspector also questioned the depth of the licensee's troubleshooting and the basis for their
operability determinations, and at the end of the inspection period, the licensee's
troubleshooting efforts were continuing. Pending the completion of the PSE&G
troubleshooting and an explanation of the basis for lRl lA operability, this item will remain
open (Unresolved Item 50-272&311/93-21-002).
5.1.3 Inspection Findings - Hope Creek
A.
Detection of Leaking Steam Valves
In early October, over a period of several days, radiation protection (RP) personnel observed
an increasing trend in radiation levels in the exhaust of the south. plant vent and the reactor
building ventilation system. Levels had reached the administratively-imposed alert level, but
were still below the alarm level. RP informed the operating crew which responded by
closing two main steam line drains. Consequently, radiation levels dropped from 1. 9 E-4 to
6.5 E-5 mrem/hr.
Subsequently, RP used their camera robot to visually check for any additional leaks; the
robot did not detect any. Nevertheless, RP initiated a tunnel entry, coordinating this with a
power reduction for the weekly main turbine surveillance. During the entry RP and
Operations personnel identified a packing leak on another main steam line drain valve.
Radiation conditions due to the small steam plume prevented personnel from approaching and
closing the valve. The valve was therefore scheduled for repair during the next significant
power reduction, at which time conditions would permit working on the valve.
The inspector followed up on the degraded steam tunnel conditions and concluded that RP's
detection of the radiation trend, use of the robot, and timing of the steam tunnel entry to
coincide with a scheduled power reduction reflected both good troubleshooting and judicious
ALARA practices.
5.2
5.2.1 Inspection Activities
The inspector reviewed PSE&G's conformance with 10 CPR 50.47 regarding implementation
of the emergency plan and procedures. In addition, the inspector reviewed licensee event
notifications and reporting requirements per 10 CPR 50.72 and 73.
~
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5.2.2 Inspection Findings - Salem
A.
Emergency Preparedness Training Drill
On September 22, 1993, PSE&G conducted an emergency preparedness (EP) training drill at
the Salem Station, which involved the activation of the onsite emergency response facilities
(the Technical Support Center (TSC), Control Point, Operations Support Center, and the
Salem simulator in place of the control room). The offsite facilities, the Emergency Offsite
Facility and the Emergency News Center, did not participate in the drill. The drill was not
pre-staged, and all licensee drill players were notified by and responded to plant page
announcements, telephone callouts and pager notifications. The drill scenario involved a
terrorist infiltrating the site protected area and damaging several safety-related systems,
culminating in the declaration of a General Emergency.
The NRC resident inspector staff participated in the licensee's drill in the TSC and the
simulator, playing the roles they would in an actual event. The inspectors subsequently
discussed the performance of the drill and the involved players with the PSE&G EP staff and
reviewed the licensee's critique of their own performance. The inspector noted that the
licensee had identified the appropriate areas for improvement and concluded that the drill had
effectively provided a good practice for the emergency response participants and the EP
staff.
5.3
Security
5.3.1 Inspection Activities
The NRC verified PSE&G's conformance 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.
5.3.2 Inspection Findings - Common
A.
Significant Fitness For Duty Event
On September 8, 1993, a Medical Review Officer for the licensee's Fitness For Duty (FFD)
program informed operations management of a significant FFD event. The Medical Review
Officer determined that a licensee contractor supervisor was unfit for scheduled work due to
consumption of alcohol. The licensee denied site access to the individual. The licensee
made the FFD evaluation during a pre-access physical of the contractor supervisor. The
individual was not previously onsite. The inspector reviewed the FFD report and follow-up
investigation and determined that the licensee's report was in accordance with 10 CFR
26. 73(a)(2) and corrective actions were prompt and appropriate.
14
5.4
Fire Protection
5.4.1 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.
5.4.2 Inspection Findings - Common
A.
Site Protection Fire Department Simulator Training
PSE&G maintains a full-time fire fighting staff as part of the Site Protection Department at
Artificial Island. As part of the training program for this staff, PSE&G has contracted with
various local facilities for live-fire simulator training. In September 1993, PSE&G fire
protection personnel began crew training at a new simulator facility at the Camden County,
New Jersey, Fire Academy. The facility uses a computer-controlled propane system to
simulate different class fires, and the computer system extinguishes the fires based on the
effectiveness of the fire-fighting techniques employed .
On September 27, 1993, the inspector visited the Camden County Fire Academy and
observed two shift crews of PSE&G Site Protection personnel participate in various drill
scenarios. The crews effectively extinguished all fires, working both as independent crews
and, at times, in conjunction with one another. The inspector concluded that the Camden
County Fire Academy is a valuable training asset for PSE&G Site Protection and that
PSE&G continues to maintain an exceptional on-site fire-fighting capability.
6.
SAFETY ASSESSMENT AND QUALITY VERIFICATION
6.1
Common
A.
Onsite Safety Review Groups
During the inspection period, the inspectors reviewed the effectiveness of the onsite Safety
Review Groups (SRGs) for Salem and Hope Creek. The SRGs function as Independent
Safety Engineering Groups for Public Service Electric and Gas. The NRC granted the
Salem, Unit 1, operating license prior to the Three Mile Island (TMI) event in 1979. In
1981, PSE&G proposed to add the requirement for an SRG to Technical Specification
Section 6. The NRC approved the change in 1984. Salem 2 and Hope Creek are post-TMI
plants. As a result, the original Technical Specifications for both units required SRGs.
Technical Specification Sections 6.5.2.5.1 for Hope Creek, Salem 1 and Salem 2 state that
the SRG shall function to provide: the review of plant design and operating experience for
potential opportunities to improve plant safety; evaluation of plant operations and
15
maintenance activities; and advice to management on the overall quality and safety of plant
operations. The Technical Specification also states that SRG shall make recommendations
for revised procedures, equipment modifications, or other means of improving plant safety,
to appropriate station/corporate management. Technical Specification 6.5.2.5.2 for each of
the three units state that SRG shall be responsible for :
0
0
0
0
review of selected plant operating characteristics, NRC issuances, industry advisories,
and other appropriate sources of plant design and operating experience information
which may indicate areas for improving plant safety;
review of selected facility features, equipment and systems;
review of selected procedures and plant activities including maintenance, modification
operational problems, and operational analysis;
surveillance of selected plant operations and maintenance activities to provide
independent verification that they are performed correctly and that human errors are
reduced to as low as reasonably achievable. The SRGs are not responsible for signoff
functions of independent verification.
To assess the SRGs, the inspectors reviewed documentation of SRG activities for evidence
that they reviewed day to day activities, significant plant events, industry experience, and
significant modifications to determine their effect on plant safety. The inspectors found that
the SRGs reviewed appropriate documents with the potential for identifying issues. For
example, the SRGs reviewed plant Incident Reports, participated in the Operating Experience
Feedback meetings, and scanned available industry sources of information such as newsletters
and electronic bulletin boards.
The Safety Review Groups have provided monthly reports that summarize the groups'
activities, findings and recommendations. They provided independent reports on specific
SRG activities. The SRGs frequently made recommendations to line organizations for
correcting identified d1screpancies. Line management and the SRGs negotiated agreements
for corrective actions and tracked implementation of the corrective actions in the Action
Tracking System. Line management judged that SRG recommendations were sound and
justified. Line managers stated that SRG performed a useful function, however, line
management had difficulty recalling specific safety significant recommendations made by the
SRGs. Also, line management identified that, at times, SRG identified findings without
making recommendations to resolve the problem. -The inspectors concluded that the form of
the SRG product was usable by line organizations. Based on review of SRG monthly
summaries of findings for the past year, the inspectors concluded that the SRG
recommendations were sound and practical, although generally not very safety significant.
For example, the majority of SRG findings identified minor procedure discrepancies and
process or equipment deficiencies with little or no effect on nuclear safety.
The inspectors determined that PSE&G line organizations have accepted the SRG function.
Some members of SRG were more respected than others as a result of their individual
accomplishments and qualifications. Receptiveness to SRG opinions also varied with the
16
SRG member expressing the opinion and the line manager receiving the opinion. Line
managers judged that greater senior management support for SRG would improve the
effectiveness of the group. The licensee's organizational structure was designed to provide
SRG independence from line organizations. Additionally, licensee Technical Specifications
and procedures did not prescribe or limit the SRG role to one typical of traditional Quality
Assurance and Quality Control organizations. However, plant managers sometimes
compromised SRG independence by using SRG personnel to perform routine activities
normally performed by line organizations.
The inspectors found that SRG did not have detailed guidance how to accomplish their
function as defined by Technical Specifications and had not developed a systematic approach
to providing assessment of the effectiveness of line organization activities. As a result, SRG
chose their review activities on a daily basis, as opposed to long term planning.
Plant organizations occasionally seek out SRG to participate in special activities. The SRG
participates in most, perhaps all, Significant Event Response Teams (SERTs). The SRG
assists SERT reviews of plant trips and significant plant events. The plant managers
frequently request SRG review of events or activities. Some reviews are related to nuclear
safety; many are not.
Prior to the inspection period, licensee senior management initiated a contractor review of
the effectiveness of Offsite Safety Review group, the SRGs, and the quality organizations.
Management intends to improve the effectiveness of these organizations. At the time of the
inspection, the contractor had not completed the review of the review groups and the quality
organizations.
In summary, the inspectors concluded that the SR Gs perform the function described in
Technical Specifications for each unit. Although line management found that the SRGs made
positive contributions to plant safety, the managers could not easily provide specific
examples. The inspectors found that the SRGs made recommendations for improvement,
although the recommendations were generally not very safety significant. The line
organization considered greater senior management support necessary to improve SRG
effectiveness.
..
..
.
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7.
LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS,
AND OPEN ITEM FOLWW-UP
7.1
LERs and 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 August 1993
The inspector concluded that the licensee appropriately issued the above reports.
Hope Creek LERs
0
0
7.2
LER 93-05 discussed the inoperability of the high pressure coolant injection system
due to torque switch roll pin failure on the injection valve motor operator. This event
was described in NRC Inspection Report 50-354/93-20. The inspector reviewed the
LER, determined that it adequately described the event, and concluded the licensee's
actions were appropriate. The inspector closed the LER.
LER 93-06 described the mechanical binding of two safety auxiliaries cooling system
inlet valves for diesel generator room coolers. This event is described in section
2.2.2.A of this report. The inspector reviewed the LER, determined it was well
written, and closed the LER.
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&311/93-08-01
50-272&311/93-15-02
4.1
4.1
Closed
Closed
).
... . .
T'
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8.
EXIT INTERVIEWS/MEETINGS
8.1
ReSident Exit Meeting
The inspectors 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.
8.2
Specialist Entrance and Exit Meetings
Date(s)
9/27-10/1/93
10/4-8/93
10/4-8/93
Subject
Corrective Action
EDSFI Follow-up
Radiological
Controls
Inspection
Report No.
50-272&311/93-24
50-354/93-26
50-354/93-23
50-272&311/93-22
50-354/93-24
Reporting
Inspector
Kenny
Bhatia
Ragland/Nimitz