ML18106A636
| ML18106A636 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 05/22/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18106A630 | List: |
| References | |
| 50-272-98-03, 50-272-98-3, 50-311-98-03, 50-311-98-3, NUDOCS 9806030294 | |
| Download: ML18106A636 (29) | |
See also: IR 05000272/1998003
Text
Docket Nos:
License Nos:
Report No.
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
U.S. NUCLEAR REGULATORY COMMISSION
50-272, 50-311
REGION I
50-272/98-03, 50-311 /98-03
Public Service Electric and Gas Company
Salem Nuclear Generating Station, Units 1 & 2
P.O. Box 236
Hancocks Bridge, New Jersey 08038
March 16, 1998 - May 3, 1998
S. A. Morris, Senior Resident Inspector, Salem
S. M. Pindale, Senior Resident Inspector, Hope Creek
F. J. Laughlin, Resident Inspector, Salem
H. K. Nieh, Resident Inspector, Salem
G. S. Barber, Project Engineer
T. H. Fish, Operations Engineer
N. T. McNamara, Emergency Preparedness Specialist
E. B. King, Physical Security Inspector
R. L. Fuhrmeister, Reactor Engineer
K. Young, Reactor Engineer
James C. Linville, Chief, Projects Branch 3
Division of Reactor Projects
9806030294 980522
ADOCK 05000272
G
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EXECUTIVE SUMMARY
Salem Nuclear Generating Station
NRC Inspection* Report 50-272/98-03, 50-311 /98-03
This integrated inspection included aspects of licensee operations, engineering,
maintenance, and plant support. The report covers a seven-week period of resident
inspection; in addition, it includes the results of announced inspections of the emergency
preparedness programs by regional inspectors.
Operations
Overall, Salem plant management and staff controlled the Unit 1 reactor startup and power
ascension test activities well. The operating crews were attentive, used excellent
communication skills, and responded appropriately to planned and emergent events and
issues. Reactor engineering and chemistry department support, a*s well as pre-evolution
briefings, were usually of good quality although some deficiencies were observed during
low power physics testing. Strong management and quality assurance oversight was
indicated by continuous on-site management presence during restart activities and the
willingness to halt further plant evolutions following the identification of emergent issues.
Good self-assessment capability was evident during hold point release discussions with the
NRC Salem Assessment Panel. (Section 01 . 1)
Operators responded promptly and effectively to an unexpected loss of the 21 steam
generator feed pump while a 100% power. All plant equipment functioned as designed
during the-transient. (Section 01.2)
The 1 25 volt DC electrical distribution system was properly aligned for existing plant
conditions at Unit 1 and 2. Material condition and housekeeping were acceptable.
Adequate survejllance test procedures were implemented to verify system operability.
(Section 02.1)
PSE&G's actions to address and correct the cause of missing service water (SW) strainer
filter disks and cracked filter disk retaining rings were appropriate and promptly
implemented. Unit 2 control operators responded promptly to the clogging of two SW
pump discharge strainers in the SW same loop. PSE&G management's decision to take
Salem unit 2 off-line for strainer repairs was appropriate, and corrective actions were
adequate. (Section 02.2)
Maintenance
PSE&G determined that the lack of clear ownership for and coordination of recent
emergency diesel generator (EDG) on-line maintenance outages resulted. in unnecessary
delays in work completion, extending the overall equipment unavailability time. Inadequate
tagging controls during the 28 EDG outage resulted in an electrical breaker blocking tag
being released while personnel were actively working on equipment supplied by that
breaker. (Section M1 .2)
ii
PSE&G implemented appropriate corrective actions to repair degraded auxiliary feedwater
piping revealed by a through-wall leak on a pump minimum-flow orifice line. Technical
specification and ASME code class 3 requirements were satisfied. However, this event
revealed a weakness in scope of the flow-accelerated corrosion program in that only the
steam-driven pumps were included for monitoring. (Section M2.1)
Engineering
PSE&G restored the 22 steam generator steam flow channels II and Ill to an operable
status in a slow and deliberate manner, meeting all technical specification requirements
during the process. (Section E1 .1)
Plant Support
Based upon a review of selected items and procedures, the inspectors concluded that
PSE&G's method for tracking Emergency Preparedness corrective actions was very good
and that the self-assessment program provided good feedback to the staff. The timeliness
of resolving some identified issues was weak. (Section P1)
The emergency response facilities and equipment were in a good state of operational
readiness. Surveillance tests and inventories were performed as required and discrepancies
were resolved in a timely manner. Expenditure of resources to improve equipment.and
facilities demonstrated PSE&G's commitment to support and maintain the emergency
preparedness program. Overall, the inspectors considered this area to be very good.
(Section P2)
PSE&G emergency plan changes were adequately reviewed in accordance with 10 CFR
50.54(q). PSE&G planned to review, evaluate/rewrite the emergency plan implementing
procedures for conformance to other station procedures and to improve the review
process. The inspectors also concluded that letters of agreement with offsite agencies
were in place. (Section P3)
PSE&G conducted emergency response training and drills as required. Based upon overall
good performance during the drills and the March 1998 biennial full-participation
emergency exercise, the inspectors concluded that training for the ERO was effective.
(Section P5)
The department reorganization and hiring of a manager with extensive EP experience
enhanced the EP program. The inspectors concluded that the positive findings during this
inspection were an indication that the program had significantly improved since the last
inspection. (Section P6)
Quality Assurance audits of the emergency preparedness (EP) program were thorough and
- the reports were useful to PSE&G management in assessing the effectiveness of the EP
program and providing enhancement recommendations. This area was assessed as
excellent. (Section P7)
iii
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TABLE OF CONTENTS
EXECUTIVE SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii
TABLE OF CONTENTS .............................................. iv
I. Operations
01
02
OS
...................................................... 1
Conduct of Operations ..................................... 1
01 . 1 Unit 1 Reactor Startup and Power Ascension . . . . . . . . . . . . . . . . 1
01.2 Unplanned Unit 2 Load Reduction ........................ 4
Operational Status of Facilities and Equipment ..................... 5
02.1
125 Volt DC (VDC) Distribution System Walkdown ............ 5
02.2 Update on Service Water Biofouling ....................... 6
Miscellaneous Operations Issue ............................... 7
OS.1
(Closed) Inspector Followup Item 50-311197-03-02 ............ 7
OS.2 (Closed) Violation 50-311/97-07-01 ....................... S
OS.3 (Closed) LER 50-272/9S-002-00,9S-002-01 ................. S
II. Maintenance .................................................... 9
M 1
Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . ................ 9
M 1 . 1 General Comments ................................... 9
M1 .2 Emergency Diesel Generator On-line Maintenance ............ 10
M2
Maintenance and Material Condition of Facilities and Equipment . . . . . . . 1 3
M2.1
11 Auxiliary Feedwater Pump Minimum Flow Line Leak ........ 13
MS
Miscellaneous Maintenance Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
MS.1
(Closed) VIO 50-272&311 /96-0S-02,96-0S-03, 50-311 /96-1 S-02
............................................... 14
MS.2 (Closed) LER 50-272/97-013-00 ........................ 15
Ill. Engineering ..................................................... 16
E1
Conduct of Engineering .................................... 16
E1 .1
22 Steam Generator Steam Flow Transmitter (Update) ... : ..... 16
IV. Plant Support .................................................. 17
P1
- Conduct of Emergency Preparedness (EP) Activities . . . . . . . . . . . . . . . . 17
P1 .1
Effectiveness of Licensee Controls in Identifying, Resolving and
Preventing Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 7
P2
Status of EP Facilities, Equipment, Instrumentation and Supplies . . . . * . . 18
P3
EP Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
P5
Staff Training and Qualification in EP . . . . . . . . . . . . . . . . . . . . . . . . . . 19
P6
EP Organization and Administration ........................... 20
P7
Quality Assurance in EP Activities ............................ 21
Miscellaneous Security and Safeguards Issues ................... 22
SS. 1 Operational Security Response Evaluation for Hope Creek and Salem
............................................... 22
FS
Miscellaneous Fire Protection Issues .......................... 22
FS.1
Fire Protection Inspection for Hope Creek and Salem .......... 22
iv
V. Management Meetings .......... : ................................. 22
X1
Exit Meeting Summary .................................... 22 ,
INSPECTION PROCEDURES USED ...................................... 23
ITEMS OPENED, CLOSED, AND DISCUSSED ............................... 23
LIST OF ACRONYMS USED ........................................... 24
v
Report Details
Summary of Plant Status
Unit 1 began the period in Mode 4, and transitioned to Mode 3 on March 17, 1998.
Reactor startup began and criticality was achieved on April 7, 1998. The unit reached
Mode 1 on April 12, 1998 and 100% power on May 3, 1998.
Unit 2 began the period at approximately 50% power during a power ascension following a
unit forced outage. 100% power was achieved on March 17, 1998. Power was reduced
to 60% on March 24, 1998 in response to an unplanned loss of the 21 steam generator
feed pump, and later restored to full power the next day. On April 18, 1998, operators
reduced power and removed the unit from the offsite electrical network following the
unplanned inoperability of a service water cooling loop. Following resolution of the service
water issues, the unit. was synchronized to the offsite network on April 11, 1998. 100%
power was reached on April 13, 1998, and remained at that level for the balance of the
inspection period.
I. Operations
01
Conduct of Operations .
01 .1
Unit 1 Reactor Startup and Power Ascension
a.
Inspection Scope (71707. 71715)
On April 1, 1998, based on the recommendation of the Salem Assessment Panel
(SAP), the NRC modified Confirmatory Action Letter .(CAL) 1-95-009 to permit*
PSE&G to restart Salem Unit 1 . NRC resident and regional inspectors conducted
augmented inspection coverage of the Unit 1 reactor startup and low power physics
testing from April 7 - 11, 1998 .. Additionally, the resident inspectors closely
monitored subsequent power ascension activities through the end of the report
period, including the "hold point" testing and assessments at 25%, 50%, and 90%
power, as dictated by the CAL.
b.
Observations and Findings
Salem operators entered Mode 2 and achieved criticality at Unit 1 on April 7, 1998,
and then raised power to 1 o-s amperes in the intermediate range in order to conduct
low power physics testing. During this period, the inspectors observed that the
control room operators exhibited good use of procedures and, clear
c*ommunications. Additionally, good managerial and quality assurance department
oversight was noted, and control room distractions were kept to a minimum. Pre-
evolution briefings frequently incorporated lessons learned from the Unit 2 startup in
August 1997.
Several problems were noted during the reactor physics testing, largely stemming
from weak operations support from other departments. For example, the inspectors
2
witnessed a "control rod swap" reactivity measurement pre-evolution briefing
conducted by reactor engineers which lacked clarity and caused confusion among
reactor operators. The control room supervisor frequently stopped the briefing to
ensure that all questions and concerns were properly addressed. Additionally, an
equipment deficiency associated with an out-of-calibration pure water flow
integrator caused operators to over-dilute the reactor coolant system during the
test; which necessitated a subsequent unplanned boration to compensate for the
error. However, the boric acid volume recommended by the reactor engineer on
shift was incorrect because it was based on a faulty interpretation of control rod
worth tables. Because of a conservative operational practice to borate and dilute in
increments that were half the recommended volumes, the effect of this boration
error was minimized.
The inspectors also observed a weakness in operations support during the execution
of a boron endpoint determination test. This test, conducted in accordance with
procedure 51 .RE-RA.ZZ-0005 (0), required three separate attempts in order to be
successfully completed~ Specifically, operators experienced difficulty preventing
power from exceeding 95 % of the indicating scale on the reactivity computer during
the test. This issue was due primarily to coordination problems between the
operator performing the required reactivity manipulations and the reactor engineer
directing the evolution.
A final example involved a chemistry department recommended lithium hydroxide
addition to the reactor c;:oolant system to adjust plant pH levels. While Unit 1 was
still at 1 o-s amperes for physics testing, operators approved the chemical addition.
In order to understand the impact this addition would have on reactivity, chemistry
technicians informed the operators that approximately 10 gallons of pure water
would be added to the plant. After the addition was completed, operators promptly
identified that reactor power was increasing at a rate greater than expected, and
added boric acid to reduce power back to the desired level. Based on volume
control tank level changes, operators computed that nearly 90 gallons of pure water
had been injected during the chemical addition. The discrepancy between the
expected and actual water volumes, which caused a greater than anticipated
reactivity excursion, was later attributed to insufficient system operating knowledge
by the involved chemistry technicians.
Because of the self-revealing nature of the above .issues, PSE&G operations
management and quality assurance inspectors were promptly aware of the
concerns, and responded appropriately to each. Corrective action requests were
initiated both to document each of the discrete issues and to integrate all of the
concerns associated specifically with reactivity management into a single
comprehensive review. As each issue was identified, plant supervision placed a
hold on further Unit 1 evolutions until the causes were understood and interim
corrective measures were implemented. Additionally, these and other issues were
discussed at length at the PSE&G management review committee meeting
conducted at the 25 % power hold point .
_i
3
Following completion of the reactor physics testing, operators slowly and
deliberately raised reactor power to 25% in accordance with procedure TS1 .SE-
SU.ZZ-0001 (0), Startup and Power Ascension Sequence, and S1 .OP-IO.ZZ-
0003(0), Hot Standby to Minimum Load. Unit 1 achieved Mode 1 on April 12,
1998, and was later synchronized to the offsite electrical network on April 17,
1998. Several emergent secondary plant issues were promptly and effectively
addressed during this period, including minor steam and water leaks, a small fire,
and an inadvertent CARDOX initiation in the main generator exciter housing. The
inspectors observed main turbine overspeed trip testing, generator loading, and
reactor core flux mapping during this period. All of these evolutions were
thoroughly briefed, properly supervised, and implemented with successful results.
On April 18, 1998, members of the SAP held a conference call with PSE&G
management to review the station's request for release from the 25% power hold
point. During the call, the SAP discussed PSE&G's internal assessments of Unit 1
startup issues and test results, including all of the issues described above. During
the post-call caucus, the SAP concluded that PSE&G's assessment was sufficiently
self-critical and that adequate plans were either completed or in place to implement
needed corrective actions. As a result, the.SAP recommended and the Regional
Administrator subsequently approved a release from the 25 % hold point.
On April 23, 1998, with Unit 1 at 47% power, operators successfully completed a
planned 10% load swing test. This test verified that the newly in$talled dig.ital
feedwater control system was capable of properly responding to small load
changes. No problems were noted during this test. On April 24, 1998, the SAP
held another conference call with PSE&G management to discuss release from the
50% power hold point. With the exception of a status update of recent service
water system biofouling concerns (see Section 02.2 of this report), no significant
equipment or human performance issues were raised during the conference call. As
such, later that day, the Regional Administrator approved a release from the 50%
hold point .
. On April 30, 1998, the inspectors witnessed the conduct of a 25% load rejection
test from an initial 88 % power level, again conducted to verify the performance of
the digital feedwater control system. Operators prepared for this evolutions by
conducting dynamic training in the Unit simulator. While the feedwater controls
responded appropriately to the planned transient, operators observed apparently
abnormal control rod speed fluctuations with the rod control system in "automatic."
Upon recognition of this issue, operators promptly placed the control rods in
"manual" until the cause of the unexpected response could be understood and
corrected. During the following week, the inspectors observed maintenance
technicians and engineering personnel implement a well controlled and
comprehensive rod control system troubleshooting plan and transient response
evaluation.
On May 1, 1998, the NRC SAP members held another conference call with PSE&G
management, this time to discuss a requested release from the 90% power hold
point. Discussions during this call primarily centered on the apparent rod control
c.
4
system anomalies experienced during the 25 % load rejection testing. Based on
PSE&G management's planned actions to promptly evaluate and correct this
apparent rod control problem, and to discuss the final assessment of this issue with
the SAP prior to commencing a planned 40% load reduction and feed pump trip
test, the NRC released Unit 1 from the 90% power hold point and permitted PSE&G
to raise power to 100%. On May 3, 1998, Salem operators achieved 100% power
at Unit 1.
At the conclusion of the report period, only the 40% load reduction and feedwater
pump trip test from 90% power remained outstanding in the Unit 1 restart and
power ascension test plan. The modified NRC CAL 1-95-009 remained in effect
until PSE&G successfully completed these tests and performed a comprehensive
assessment of the startup test plan and any "lessons learned." The inspectors
independently concluded that overall, PSE&G's implementation of the Unit 1 restart
plan was an improvement over the Unit 2 restart (see NRC Inspection Report 50-
311 /97-15), as indicated by fewer emergent equipment deficiencies and test
coordination errors.
Conclusions
Overall, Salem plant management and staff controlled the Unit 1 reactor startup and
power ascension test activities well. The operating crews were attentive, used
excellent communication skills, and responded appropriately to plcmned and
emergent events and issues. Reactor engineering and chemistry department
support, as well as pre-evolution briefings, were usually of good quality although
some deficiencies were observed during low power physics testing. Strong
management and quality assurance oversight was indicated by continuous on-site
presence during restart activities and a willingness to halt further plant evolutions
following the identification of emergent issues. Good self-assessment capability
was evident during hold point release discussions with the NRC Salem Assessment
Panel.
01 .2 Unplanned Unit 2 Load Reduction
a.
Inspection Scope (93702)
b.
The inspectors reviewed Salem Unit 2 operators response to a March 24, 1998
event involving an electrical power transient affecting steam generator feed pump
(SGFP) controls.
Observations and Findings
An unexpected electrical power spike resulted in the momentary partial loss of non-
vital 115 volt AC power. This event in turn caused a shutdown of the 21 SGFP,
which lost governor control power. Operators acknowledged the associated
overhead alarm, observed that the 21 SGFP speed was lowering, and initiated a
manual main turbine generator load reduction to 60% power. Based on operator
interviews and a review of narrative logs, the inspectors determined that plant
c.
5
operators correctly followed alarm response and abnormal operating procedures to
stabilize the plant. The inspectors found the impact of this event on plant safety *
minimal, in that all plant systems responded as designed to the transient and no
safety systems were challenged as a result. Operators returned Unit 2 to full power
on March 25, 1 998 after Jesting all affected equipment to verify continued proper
operation. At the conclusion of the report period, PSE&G had not determined the
root* cause for this electrical transient event, but also concluded that all plant
equipment functioned as designed in response to the transient.
Conclusions
Operators responded promptly and effectively to an unexpected transient associated
with the 21 steam generator feed pump while a 100% power. All plant equipment
functioned as designed during the transient ..
02
Operational Status of Facilities and Equipment
02.1
125 Volt DC (VDC) Distribution System Walkdown
a.
b.
Inspection Scope (71707)
The inspectors conducted a comprehensive wal!<down of the accessible portions of
the 125 VDC electrical distribution system. The inspectors reviewed the Updated
Final Safety Analysis Report (UFSAR), Technical Specifications (TS), Configuration
Baseline Documentation, and TS surveillance procedures for background
information.
Observations and Findings
Material condition and housekeeping of 125 VDC batteries and associated busses
were acceptable at both Salem units. System configuration was consistent with
UFSAR system descriptions, and was properly aligned for existing plant conditions.
The inspectors reviewed procedures S1 (52).0P-ST.125-0001, "Electrical Power
Systems 1 25 VDC Distribution," and determined that the procedure adequately
verified system operability requirements specified in plant TS at the appropriate
frequency. Some minor discrepancies were noted and brought to the attention of
system engineering. For example, two cells on the 28 125 VDC battery had plates
which were slightly bowed. Actions taken to address these items were timely and
appropriate.
c.
Conclusions
The 125 volt DC electrical distribution system was properly aligned for existing
plant conditions at Unit 1 and 2. Material condition and housekeeping were
acceptable. Adequate surveillance test procedures were implemented to verify
system operability .
6
02.2 Update on Service Water Biofouling.
a.
Inspection Scope (40500. 92901, 92902, 92903)
b.
The inspectors reviewed PSE&G's response and actions taken to address degraded
service water system (SW) strainers. Related SW brofouling issues were previously
discussed in NRC Inspection Report 50-272 & 311/98-01.
Observations and Findings
On April 3, 1998, maintenance technicians identified one missing filter disk and five
cracked filter disk retaining rings during an internal inspect.ion of 23 SW pump
discharge strainer (Unit 2). A similar inspection of 14 SW strainer (Unit 1) also
revealed one missing disk and approximately forty cracked retaining rings. No
adverse temperature trends were identified in any SW cooled heat exchangers.
PSE&G engineers attributed the cause of the cracked rings to excessive torque
during installation. The plastic retaining rings were installed using an air impact
wrench, with no specific torque requirement. Strainer manufacturer, S. P. Kinney
Engineers, Inc., indicated that factory installation of the rings is "hand tight plus an
additional one half of one turn." Maintenance procedure SC.MD-PM.SW-0003,
"Service Water Auto Strainer Adjustment, Inspection, Repair, and Replacement," did *
not specify a particular method of ring installation. Air wrenches were used to
expedite the task, since hand installation requires several days to complete. PSE&G
management decided to overhaul each Unit 1 and 2 SW strainer ( 12 total) and
install each new retaining ring by hand. The inspectors verified that the noted
maintenance procedure was modified to specify hand installation of the retaining
rings.
On April 8, 1998, with Salem Unit 2 at 100%, operators declared one of the two
service water (SW) loops inoperable due to both the 24 and 25 SW pump strainer
motors tripping on overload. This rendered the associated pumps inoperable.
Technical Specification 3. 7.4 requires two operable SW loops, and the action
statement allows 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to restore the inoperable SW loop to an operable status
before a unit shutdown is required. At the time of event, one of the. three strainers
in the opposite SW loop was also unavailable due to pre-planned corrective
maintenance. An NRC inspector was in the control room at the time of this event
and observed. that plant operators acted appropriately in response to the observed
conditions. At the time of the event, Salem Unit 1 was in Mode 2 with low power
physics testing in progress; no effects on the Unit 1 SW system were observed.
_ Within three hours of this event, PSE&G management elected to reduce power and
take Unit 2 off-line for further investigation and repairs of the strainers, well before
the expiration of the 72-hour TS allowed outage time. Subsequent inspections of
the affected strainers revealed that they were clogged with excessive amounts of
grass and debris. Though the root cause evaluation for this event was not yet
completed by the end of the report period, several corrective actions were
implemented, including: overhauling the SW strainers, replacing the strainer motor
overload heaters, and adjusting all of the traveling screen spraywash nozzles. By
c.
7
the* end of the report period, all of the Unit 1 and Unit 2 SW strainers had been
overhauled, and most overload heaters were replaced with higher capacity
overloads. The remaining overload heaters have been scheduled for replacement.
The inspectors reviewed the overload sizing calculations, and no problems were
noted. The inspectors also determined that the overload modification would not
negatively impact electrical loading during accident conditions.
Conclusions
PSE&G's actions to address and correct the cause of missing service water (SW)
strainer filter disks and cracked filter disk retaining rings were appropriate and
promptly implemented. Unit 2 control operators responded promptly to the clogging
of two SW pump discharge strainers in the SW same loop. PSE&G management's
decision to take Salem unit 2 off-line for strainer repairs was appropriate, and
corrective actions were adequate.
08
Miscellaneous Operations Issues
08.1
(Closed) Inspector Followup Item 50-311 /97-03-02: Management Commitment
Process
a .
b.
Inspection Scope (92702)
The inspectors reviewed and assessed a recent revision to the commitment
management program procedure as a follow up to a similar review performed while
evaluating Salem Unit 1 and Unit 2 for restart readiness.
Observations and Findings
As part*of the restart action plan, Salem staff evaluated the commitment
management process and subsequently instituted corrective actions to correct
program deficiencies. One of these tasks, a revision of the commitment
management program procedure, was not completed at the time NRC staff was
inspecting the commitment process for restart readiness, and was therefore left
open pending a review and assessment of the final procedure. PSE&G issued the
revised commitment management procedure, NC.NA-AP.ZZ-0030(0) in May 1997.
The inspectors reviewed the document and determined that the procedure and
program modifications were acceptable. This item is closed.
c.
Conclusions
PSE&G appropriately revised the process by which license commitments are tracked
and managed .
8
08.2 (Closed) Violation 50-311197-07-01.: Failure to establish containment integrity
within eight hours
a.
Inspection Scope (92702)
The inspectors performed an on-site review and verification of PSE&G's corrective
actions for the subject Notice of Violation.
b.
Observations and Findings
In the violation response letter dated June 13, 1997, PSE&G management
attributed the event cause to inadequate tracking of i.noperable equipment. In
response, PSE&G provided electrical systems technical specifications refresher
training to licensed operators, and enhanced the technical specifications action
statement tracking log. The inspector reviewed the refresher training and the
- revised tracking log and determined these corrective actions were reasonable and
complete. This item is closed.
c.
Conclusions
The PSE&G staff developed and implemented timely and reasonable corrective
actions for a Notice of Violation involving a failure to promptly establish
containment integrity .
08.3 (Closed) LER 50-272/98-002-00,98-002-01: Auxiliary building ventilation excess
flow damper found wired open with spring removed
a.
Inspection Scope (90712. 92700)
The inspectors performed an on site review of LER 50-272/98-002-00. LER 50-
272/98-002 Supplement 1, which documented the results of an evaluation
performed to determine the safety significance of this issue. The inspectors
reviewed and discussed the noted evaluation with PSE&G design engineers.
b.
Observations and Findings
The circumstances surrounding the initial discovery and corrective actions related to
this issue were previously discussed in NRC Inspection Report 50-272 & 311 /97-
21 . No new issues were identified in this LER and all stated corrective actions have
been completed. As such, this LER is closed.
Based in part on a discussion with PSE&G design engineers, the safety significance
evaluation completed for this event was deemed to be reasonable. Specifically, this
event had limited safety significance since the control room and offsite dose
consequences were bounded by the loss of coolant accident and steam line break
analyses. This LER supplement is closed .
c.
9
Conclusions
Corrective actions for LER 50-272/98-002-00were reasonable and complete. The
safety significance evaluation performed for this event, documented in LER
Supplement 1, was also acceptable.
/
II. Maintenance
M 1
Conduct of Maintenance
M 1 . 1 General Comments
The inspectors observed all or portions of the following work activities and technical
specification surveillance tests:
- * * *
- *
- * * * * *
- * * * * * * * * *
WiO 980311218:
W/O 980315118:
W/O 980315129:
W/O 971005022:
W/O 990131032:
W/O 971228015:
W/O 980331158:
W/O 910529001: *
15 Service water strainer - inspect and check clearness
Ultra-sonic test of 12 AFW minimum-flow orifice area
Ultra-sonic test of 22 AFW minimum-flow orifice area
22 Charging pump lube oil heat exchanger - open, clean
and inspect
22 Charging pump gear box heat exchanger - open,
clean and inspect
22 Charging pump, clean and repack couplings
16 Service water strainer inspection/retaining ring
replacement
12 Containment hydrogen analyzer - replace hydrogen
sensor
W /0 980408061 :
25 Service water pump strainer backwash valve -
W/O 980408059:
W/O 971216022:
W/O 970605093:
W/O 980312302:
W/O 980320186:
w /0 98051 6040:
inspect
24 Service water pump strainer - open and inspect
28 EOG lube oil heater - remove, clean, and inspect
28 EOG switch replacement
14 SW strainer grass and clearance inspection
13 SW strainer grass and clearance inspection
Radiography test of 11 SW53 ( 13 CFCU inlet check
valve)
W /0 980328091 :
Repair 25 SW strainer (seized)
W/O 980312297:
23 SW strainer grass and clearance inspection
W /0 98041 2104:
2A EOG fuel oil leak repair on 9R fuel pump
W /0 960513198:
2C EOG oil leak repair on 6L cylinder
S1 .RE-RA.ZZ-0005: Boron endpoint determination
51.IC-FT.NIS-0014: 1N36functional test
S 1 . IC-CC. RCP-0018: 1 PT546 (pressurizer pressure channel 2) calibration
S1 .IC-CC.RCP-0023:1 PT474(pressurizer pressure channel 4) calibration
S2.MO-FT.4KV-0002:2Bvital bus undervoltage testing
S2.0P-SO.OG-0002: 28 EOG 15-minute post-maintenance run
10
The inspectors observed that the plant staff performed the maintenance activities
effectively and in accordance with the standards defined by the station maintenance
program. Salem plant staff also completed the noted surveillance tests safely, and
effectively proved the operability of the associated systems. Minor deficiencies
noted by the inspectors were referred to and promptly corrected by the PSE&G
staff.
M1 .2 Emergency Diesel Generator On-line Maintenance
a.
Inspection Scope (71707,62707 ,92901 ,92902)
The inspectors reviewed the limiting condition for operation (LCO) maintenance plan
for the April 14, 1998 28 emergency diesel generator (EOG) planned maintenance
outage, observed implementation of associated work activities, and interviewed
PSE&G management concerning the plan. The inspectors also reviewed
documentation for the March 13, 1998 1 B EOG outage, and the April 21, 1998 2C
EDG planned maintenance outage.
b.
Observations and Findings
1 B EOG Outage:
At 4:41 a.m. on March 18, 1998, the 1 B EDG service water inlet i.solation valve
failed to open within its allowed time period during a technical specification
surveillance test. Operators appropriately declared the diesel inoperable and
initiated a work order to troubleshoot the problem. The work order was finalized
and tags were hung at 3:31 p.m. to commence work. However, the work was not
authorized to begin until 10:40 p.m., a delay of about seven hours. Additionally,
after work completion, the tag release was authorized at 11 :53 p.m., but the tags
were not cleared until 2: 12 a.m. the next morning, resulting in another two-hour
delay. The EOG retest was completed at 3:19 a.m. on March 19.*
The inspectors agreed with PSE&G's subsequent assessment that oversight of this
emergent work item was weak. PSE&G documented this issue in a corrective
action request and concluded that the primary cause for the ineffective management
was the lack of an established single point of contact to coordinate the work.
Additionally, operations and maintenance personnel were insensitive to the urgency
of returning safety equipment to an operable status, and the need to minimize
unavailabi.lity time for maintenance rule requirements.
28 EDG Outage:
At 5:47 a.m. on April 14, 1998, operators removed the 28 EOG from service for
planned on-line maintenance. PSE&G developed an LCO maintenance plan for this
outage in accordance with procedure SC.SA-SD.ZZ-0011 (Z), "Work Management
Manual (WMM)." The inspectors noted that the content of the plan was thorough
and met the standards of the WMM, including an assessment of the plan's impact
on both overall plant risk and maintenance rule performance criteria.
11
PSE&G planning personnel recognized about 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> after the on-line outage
began that EOG service water (SW) valves were inappropriately tagged and the heat
exchanger drained. Plant operators were promptly informed after discovery of this
issue. Specifically, a biofouling inspection of the SW jacket water/lube oil heat
exchanger was originally planned as part of EOG outage work scope, but was later
removed from the scope three weeks prior to the work. This change in scope was
not effectively communicated to the operations department staff, and as a result,
the EOG SW system was unnecessarily tagged out and drained, delaying the
implementation of other necessary work. Additionally, the Salem staff also
determined that appropriate fire protection impairments had not been prepared for
the SW outage, nor was there a scheduled activity for a required jacket water
chemistry sample. These issues further delayed the completion of this non-required
work activity.
The inspectors observed various individual maintenance activities conducted during
the outage and noted that workers used approved procedures, had copies of work
orders and prints at the work site, and maintained work areas in a neat and orderly
manner. Temporarily installed scaffolding was structurally sound and had the
required permit attached! The inspectors observed that work supervisors frequently
toured the work area.
On April 15, PSE&G personnel identified an equipment tagging "near miss" during
the 28 EOG outage. Specifically, the day shift l&C supervisor rec~ived a turnover
from the night supervisor that a partial tag release could be executed for a diesel
control power breaker. This breaker had a red blocking tag attached due to various
electrical work being performed. The supervisor authorized the temporary release
without reviewing all activated work orders that were in progress. At the time, l&C
technicians were performing maintenance activities which were protected by this
tag. An alert electrical supervisor monitoring work in the 28 EOG room observed
the l&C work in progress and stopped the operator from releasing the tag.
The inspectors noted that PSE&G's administrative procedure NC.NA-AP.ZZ-0015,
"Safety Tagging Program," requires that "responsible individuals ensure that
personnel protected by safety tags are notified and clear of the equipment when
authorizing a tag release." The inspectors concluded that the failure to implement
this step of the procedure was a violation of TS 6.8.1, which requires that
procedures be implemented for control of safety-related equipment. PSE&G
corrective actions for this event included counseling the individuals involved in the
improper tagging release, and re-emphasis on the need for tagging process
adherence to craft personnel during a weekly department meeting. This self-
identified and corrected violation is being treated as a Non-Cited Violation consistent
with Section Vll.8.1 of the NRC Enforcement Policy. (NCV 50-311/98-03-01 ).
All pre-planned 28 EOG maintenance was completed at 1: 12 a.m. on April 16, yet
blocking tags were not removed until about 9:00 a.m., resulting in another eight
hour delay. The inspector noted that there was no clearly designated coordinator of
the LCO plan to ensure its timely completion. Also, operators were not sufficiently
sensitive to the priority of returning the 28 EOG to an operable status, and as such
c.
12
did not pursue blocking tag removal. in a timely manner. This unnecessarily delayed
post-maintenance testing, and resulted in the 28 EDG not being returned to
operability until 5:18 p.m. on April 16. The actual overall outage duration was 59
hours, or 82% of the 72-hour TS allowed outage time (AOT), while the planned
duration was 60% of the AOT. PSE&G management understood and recognized
that this on-line maintenance would result.in exceeding the 28 EDG maintenance
rule performance criteria, however, the noted delays unnecessarily extended the
diesel's unavailability. The 28 EDG will now be classified category a(1) under the
maintenance rule, which requires that specific performance goals be established and
monitored.
PSE&G management also recognized the poor execution of the 28 EDG planned
outage and aggressively implemented corrective actions. A level two action request
was initiated to evaluate the inadequate preparation for and execution of the work.
An outage critique was held on Friday, April 17, to capture lessons learned,
especially since the 2C EDG was scheduled for a similar outage the following week.
Additionally, the planning supervisor issued a memorandum with specific
expectations for the preparation and implementation of LCO maintenance plans,
including the formation of work week teams to oversee LCO maintenance, deadlines
for plan and prerequisite signoffs, and specific guidance concerning tagging
implementation.
2C EDG Outage:
Operators removed the 2C EDG from service at 5:46 a.m. on April 21, 1998 for
planned on-line maintenance. "Critical path" for the outage was equipment
calibration by l&C personnel. This work was turned over to the "12-hour shift"
maintenance crew so that the work could be pursued around the clock. However,
the 1 2-hour crew was not familiar with the scheduled instrument calibration
procedures and required assistance from day shift l&C technicians who were.
Additionally, the 12-hour shift technicians were diverted from the critical path work
to assist in maintenance on a boric acid transfer pump, for which there was no TS
limiting condition for operation. Further, the commencement of work was delayed
about three hours due to tagging inefficiencies. Overall PSE&G determined that
these delays resulted in a 2C EOG outage duration of 59 hours6.828704e-4 days <br />0.0164 hours <br />9.755291e-5 weeks <br />2.24495e-5 months <br /> instead of the
scheduled 42 hours4.861111e-4 days <br />0.0117 hours <br />6.944444e-5 weeks <br />1.5981e-5 months <br />.
PSE&G management recognized the noted deficiencies during the conduct of a
critique of the 2C EOG planned maintenance and initiated an action request to
- document the assessment. Corrective actions were still being developed at the
conclusion of the inspection report period.
Conclusions
PSE&G determined tha.t the lack of clear ownership for and coordination of recent
emergency diesel generator (EDG) on-line maintenance outages resulted in
unnecessary delays in work completion, extending the overall equipment
unavailability time. Inadequate tagging controls during the 28 EDG outage resulted
in an electrical breaker blocl<ing tag being released while personnel were actively
working on equipment supplied by that breaker.
-1
. -I
13
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1
11 Auxiliary Feedwater Pump Minimum Flow Line Leak
a.
Inspection Scope (92902, 92903)
On March 14, 1998, an equipment operator identified a through-wall leak on the
discharge weld of the 11 auxiliary feedwater (AFW) pump minimum-flow line orifice.
The inspectors reviewed PSE&G's actions to correct this degraded condition and
ensure that redundant trains of equipment were not similarly degraded.
b.
Observations and Findings
PSE&G determined that the leak from the 11 AFW orifice was approximately 25-30
drops per minute on the outlet of the minimum-flow orifice, where a stainless steel
coupling is welded to the downstream carbon steel pipe. When the leak was
discovered, the 11 AFW pump was in service, but was not required to be operable
in accordance with technical specifications (TS). Engineers determined that the root
cause of the leak was cavitation at the discharge of the minimum-flow orifice.
Technicians repaired the 11 AFW orifice weld and examined the equivalent piping
for the 12 AFW pump by using ultrasonic testing. Since these re~ults were
acceptable, Unit 1 operators proceeded with a mode change from mode 4 to 3, an
operating condition which requires AFW to be operable. Subsequently, engineers
recommended a radiographic test of the 12 AFW line to provide a clearer picture of
the affected area of pipe. This test revealed that the wall thickness on the 1 2 AFW
pipe was .085 inches, less than minimum wall thickness of . 14 7 inches, contrary to
the earlier ultrasonic examination. Operators declared the 12 AFW train inoperable
and entered the 72-hour TS 3. 7 .1.2.a action statement to initiate repairs.
PSE&G technicians also performed an ultra-sonic test of the same piping for the 22
AFW (Unit 2) pump. This inspection revealed an acceptable wall thickness of .235
inches, and no cavitation damage like that found on the Unit 1 pumps, likely due to
the fact that the Unit 2 AFW pumps are newer and have less run time than the Unit
1 pumps. Also, PSE&G design engineering performed a calculation which showed
that .040 inches of wall thickness was sufficient to withstand the design pressure
at the orifice outlet. Based on this information, inspections of the 21 and 23 AFW
pumps were scheduled for August and September 1998, respectively.
Based on the activities associated with the 11 AFW pump orifice leak, PSE&G
determined that only the steam-driven AFW pump (13 and 23) discharge piping was
included in the FAC program. However, the motor-driven pumps had greater run
times since they are normally operated during unit shutdowns. PSE&G revised the
FAC program scope to include monitoring all the AFW pumps discharge and
minimum flow line piping .
c.
14
Conclusions
PSE&G implemented appropriate corrective actions to repair degraded auxiliary
feedwater piping revealed by a through-wall leak on a pump minimum-flow orifice
line. Technical specification and ASME code class 3 requirements were satisfied.
However, this event revealed a weakness in scope of the flow-accelerated corrosion*
program in that only the steam-driven pumps were included for monitoring.
MS
Miscellaneous Maintenance Issues
M8.1 (Closed) VIO 50-272&311/96-08-02,96-08-03,50-311 /96-18-02
a.
Inspection Scope (92702)
b.
Based on an on-site review and verification of corrective actions, the inspectors
assessed PSE&G's response to the previously-cited violations described below ..
Observations and Findings
VIO 50-272&311 /96-08-02: failure to perform post maintenance testing (PMT). In
a letter dated September 9, 1996, PSE&G attributed the cause of this violation to
personnel error and improper procedure use for controlling PMT work. In response,
Salem staff reviewed the event with maintenance personnel and r.evised the work
management desk guide, SC.MD-DG.Z-0001 (Z), to clarify PMT requirements. The
inspector reviewed the revised desk guide and determined that the corrective action
was implemented. This item is closed.
VIO 50-272&311 /96-08-03: inadequate safety-related material storage. In a letter
dated September 9, 1996, PSE&G attributed the cause of this violation to a failure
to follow procedures and inadequate implementation of management expectations.
In response, Salem staff revised the material handling procedure, NC.NA-AP.ZZ-
0018(0), to add sufficient detail regarding the proper storage of material. The staff
also completed a follow up self assessment in October 1996, which verified that
personnel were properly storing material. The inspector reviewed the results of the
assessment and the noted procedure revision and determined that these corrective
actions were reasonable. This item is closed.
VIO 50-311/96-18-02: lack of containment closure during refueling. In a letter
dated March 20, 1997, PSE&G attributed the cause of this violation to inadequate
implementation of outage scheduling and risk management requirements. In
response, PSE&G staff implemented a continuing training program on outage risk
management, to be administered to outage management and planning and
scheduling personnel. The staff also revised the containment closure procedure,
S1/S2.QP-ST.CAN-0007,to incorporate the posting of penetration areas to restrict
work in those areas during core alterations, and to provide clarification of criteria for
determining that a system is intact. The inspector reviewed the training program
and procedure revisions and determined that these corrective actions were
. appropriate. This item. is closed.
c.
15
VIO 50-311197-14-03: failure to follow technical specification 6.8. 1 procedure.
The inspectors reviewed PSE&G's response to the Notice of Violation (NOV), dated
September 12, 1997, regarding test equipment left installed on the 2A emergency
diesel generator. Licensee Event Report 50-272/97-013-00,also describes the
circumstances and corrective actions associated with this issue. See section M8.2
below for the inspector's review and assessment.
Conclusions
PSE&G responses to the previously-identified issues were timely arid reasonable.
The inspectors verified that all committed actions were completed.
M8.2 (Closed) LER 50-272/97-013-00:failure to meet technical specification 3.8.1.1
action b
a.
Inspection Scope (92700, 92901, 92902. 92903)
b.
On July 2, 1997, following surveillance testing, the 2A emergency diesel generator
(EOG) was inappropriately declared operable with electrical test equipment still
installed in the EDG control cabinet. This issue was discussed in NRC Inspection
Report 50-272 & 311/97-14and dispositioned as a cited violation. The inspectors
performed an on-site review the corrective actions specified in this licensee event
report (LER) .
Observations and Findings
After this issue was identified, a follow-up surveillance test was performed
satisfactorily, and the test equipment was removed. PSE&G attributed the cause of
this event to human error. Operators did not perform the surveillance test
restoration completely, in that they left test equipment connected to support
subsequent work. Station administrative procedures allow omitting procedure steps
(i.e. marking them "not applicable"), if the partial performance does not change the
intent of the procedure. In this case, the intent of the procedure was changed
because the pre-test condition was not fully restored. Following this event, Salem
management re-emphasized the expectations concerning procedure use to all plant
personnel. The inspectors determined that the operations department guidance for
procedure use was revised to require the concurrence of two operators, at least one
of whom shall be a supervisor, before a procedure step is determined to be "not
applicable."
Additionally, the EDG surveillance test equipment was modified by installing safety-
related fuses to separate the Class IE equipment from the test equipment. The
inspector reviewed and discussed the fuse selection calculation with Salem design
engineering personnel and did not note any problems. Adequate controls were
established for maintaining safety-related fuses in the test equipment. The
inspectors also reviewed the 10 CFR 50.59 safety evaluation for considering the
EDG system operable with temporary test equipment connected. The safety
evaluation was adequate. This LER is closed.
c.
16
Conclusions
Corrective actions taken to address the deficiencies identified following the improper
restoration of a Unit 2 emergency diesel generator were adequate. Associated
design calculations and safety evaluations were thorough.
Ill. Engineering
E 1
Conduct of Engineering
E1. 1
22 Steam Generator Steam Flow Transmitter (Update)
a.
Inspection Scope (92902, 92903)
b.
c.
The failure of the 22 steam generator (SG) steam flow transmitter for channels II
and Ill was documented in NRC Inspection Report (IR) 97-18 and updated in IR 97-
21 . The inspector followed up on subsequent licensee actions to correct this
persistent problem.
Observations and Findings
PSE&G technicians replaced the low side sensing line during the recent Unit 2
forced outage. Inspection of the old sensing line revealed that the drain hole which
carries condensation back to the main steam line was plugged with debris. PSE&G
concluded that this was evidently the root cause for the high steam flow indications
which these channels had been exhibiting. Operators monitored these channels
after returning Unit 2 to power operation and noted normal indications, consistent
with other steam flow channels. The channels were successfully tested by a
special test procedure to ensure that they would respond appropriately to power
changes. PSE&G then restored the channels to operation, and removed the forced
values to the digital feed water system.
Conclusions
PSE&G restored the 22 steam generator steam flow channels II and Ill to an
operable status .in a slow and deliberate manner, meeting all technical specification
requirements during the process .
P1
a.
17
IV. Plant Support
Conduct of Emergency Preparedness (EP) Activities
Effectiveness of Licensee Controls in Identifying, Resolving and Preventing Problems
Inspection Scope (82701)
The inspectors reviewed PSE&G's process for identifying, tracking and resolving EP-
related items.
b.
Observations and Findings
c.
The EP staff utilized an automated corrective action tracking system maintained by
the Quality Assurance group. PSE&G used the system as a mechanism for
reporting conditions requiring corrective action, program enhancement and
drill/exercise issues. The program was maintained by the EP Corrective Action
Coordinator who tracked items and ensured corrective actions were timely and
adequate. This was a good initiative because prior to mid-1997, the EP staff used
several different tracking systems. It was evident during this inspection that having
one system with a dedicated coordinator provided continuity and immediate
attention, and provided EP management with continual oversight of EP-related open
items .
While reviewing past action item reports, the inspectors noted that some of the
issues discussed in the previous NRC inspection had not been resolved in a timely
manner. For example, a lapse in respirator qualifications was identified by the NRC
in late 1996 and the issue, although improved, was not ye~ fully resolved. The
backup diesel generator located in the Emergency Operations Facility (EOF) has
been found to be inadequately maintained in the past two internal audits. Also,
Emergency Action Level (EAL) charts were not adequately updated to reflect the
NUMARC EAL classification scheme because of a burdensome review and approval
process. PSE&G personnel acknowledged these had to be coordinated with other
departments for resolution, and planned to better prioritize issues that required
resolution.
Additionally, PSE&G's EP Self-:assessment program had improved and was deemed
effective. Since January 1, 1997, PSE&G completed nine self-assessments. A
review of the corrective actions associated with the self-assessment findings
indicated that they were properly tracked and trended, and that corrective actions
were being effectively implemented to resolve programmatic weaknesses.
Conclusions
Based upon the review of selected items and procedures, the inspectors concluded
that PSE&G's method for tracking EP corrective actions was very good and that the
EP self-assessment program provided good feedback to the staff. The timeliness of
resolving some identified issues was weak.
18
P2
Status of EP Facilities, Equipment, Instrumentation and Supplies
a.
Inspection Scope (82701}
The inspectors conducted an audit of emergency equipment in the control room, the
operations support center (OSC), the technical support center (TSC), and the
emergency operations facility (EOF) to assess facility readiness. Also, the
inspectors reviewed documentation of equipment surveillance tests conducted since
the last EP program inspection for completeness and accuracy.
b.
Observations and Findings
EP equipment checklists were main.tained accurately. Radiological survey
instruments at the facilities were all within the designated calibration period. The
inspectors reviewed equipment surveillance tests and inventory checklists and
determined that they were completed as required, and that any discrepancies were
resolved in a timely manner. The inspectors reviewed the monthly communication
test records and determined that Emergency Response Organization responders
were timely and that EP management was proactive in retrieving station badges if a
responder failed to reply. PSE&G recently switched pager vendors and problems
have been identified in which not all the pagers activated when required. PSE&G
staff indicated that in these cases PSE&G verified that PSE&G would be able to
minimally staff the emergency facilities if activated at that time. flesolution of this
issue was being actively pursued.
The inspectors toured the new combined Hope Creek/Salem OSC and EOF. The
facilities were enlarged and the layout was much improved for accommodating the
needs of the emergency responders. PSE&G plans to combine the Hope
Creek/Salem technical support centers in 1999. These enhancements demonstrated
PSE&G's commitment to support the EP function.
Additionally, the inspectors determined through document reviews and discussions
with EP staff that the siren system was properly maintained and tested as required
by the Emergency Plan (E-Plan) and applicable procedures. Work orders generated
due to equipment malfunctions were tracked to completion and once a work request
was initiated, repairs were completed within 24-48 hours.
c.
Conclusions
The emergency preparedness facilities and equipment were in a good state of
operational readiness. Surveillance tests and inventories were performed as
required and discrepancies were resolved in a timely manner. Expenditure of
resources to improve equipment and facilities demonstrated PSE&G's commitment
to support and maintain the EP program. Overall, the inspectors considered this
area to be very good .
19
P3
EP Procedures and Documentation .
a.
- Inspection Scope (82701 l
The inspectors assessed the process which PSE&G used to review and change the
E-Plan and implementing procedures (EPIPs). The inspectors also reviewed recent
EPIP/E-Plan changes to assess the impact on the effectiveness of the EP program.
Further, the inspectors verified that appropriate letters of agreement were in place
with offsite emergency agencies.
b.
Observations and Findings
The inspectors assessed the 10 CFR 50.54(q) (effectiveness review) process for E-
Plan changes and the annual E-Plan review process performed by the licensee. The
reviews were thorough, and met NRC requirements as well as commitments made
in the Updated Final Safety Analysis Report (UFSAR) and the E-Plan.
The inspectors conducted an in-office review of recent EPIP/E-Plan changes and
found the EPIPs lacked detail and clarity, and that paragraphs had been
inadvertently removed during the revision process. Also, the inspectors determined
that PSE&G was not routinely reviewing the EPIPs to ensure they were consistent
with E-Plan requirements and adequately described the current program. In*
addition, the inspector often found it difficult to determine the ad~quacy of changes
because the changes were not always identified and the basis for the change was
not easily understood. The EP Manager stated that an action item had been
initiated to completely rewrite the procedures for improving understanding and for
conformance with other station procedures. Also, PSE&G added an item to the
corrective action system to ensure that procedures will be reviewed on a biennial
basis. Also, changes would be prominently identified and explained when sent to
the NRC for review. The inspectors had no further questions.
The inspectors verified that agreement letters '(Vith offsite agencies and support
organizations were valid or were updated as required per the E-Plan.
c.
Conclusions
P5
a.
PSE&G emergency plan changes were adequately reviewed in accordance with 1 0
CFR 10.54(q). PSE&G planned to review, evaluate/rewrite the emergency plan
implementing procedures for conformance to other station procedures and to
improve the review process. The inspectors also concluded that letters of
agreement with offsite agencies were in place.
Staff Training and Qualification in EP
Inspection Scope (82701 l
The inspectors reviewed EP training records, training procedures, and the E-Plan
training requirements to evaluate PSE&G's emergency response organization (ERO)
training program.
b.
c .
20
Observations and Findings
The inspectors determined through a review of training lesson plans, training record
reviews, and discussions with ERO members, that the required EP training was
conducted in accordance with PSE&G's E-Plan and applicable procedures. The*
inspectors randomly selected 60 training records for the ERO staff and found that
the qualifications were current. Additionally, the inspectors reviewed the initial and
requalification EP lesson plans for fire brigade and security personnel and
determined, by a review of test documentation, that both organizations conducted
EP training in accordance with applicable procedures.
The inspectors verified that the required drills were conducted to evaluated medical,
radiation monitoring, and fire response. Since the last program inspection, PSE&G
increased the number of quarterly drills to 12, in addition to monthly tabletop
training for the operators. The PSE&G staff stated that the additional drills allowed
them to focus more on teamwork, and critique documentation indicated an overall
improvement in ERO performance. Also, the inspectors interviewed several Senior
Reactor Operators from both Hope Creek and Salem, and found that they spoke
positively of the additional table top drills because the repetitiveness provides them
with more confidence in making emergency classifications using the new NUMARC
Emergency Action Level (EAL) scheme, implemented in January 1997.
Conclusion
PSE&G conducted emergency response training and drills as required. Based upon
overall good performance during the drills and the March 1998 biennial full-
participation emergency exercise, the inspectors concluded that training for the ERO
was effective.
P6
EP Organization and Administration
a.
Inspection Scope (82701)
b.
The inspectors reviewed PSE&G's EP department staffing and management to
determine what changes had occurred since the last program inspection and
whether those changes had any adverse effect on the EP program.
Observations and Findings
Since the last NRC EP program inspection in August 1997, the EP program was split
from the radiation protection department and combined with corrective actions and
instructional technology departments. In March 1997, PSE&G hired a new EP
manager who has a broad knowledge of EP. Recently the EP section was fully
staffed with nine individuals. This included the addition of a supervisor for handling
offsite agency i~sues and two coordinators for corrective actions and training
oversight. This initiative was deemed to be good because it provided better
program ownership. Each supervisor was given a staff to support their mission .
Also, the Director of EP/Training, reports directly to the PSE&G Chief Nuclear
c.
21
Officer and President who appeared to be very supportive of the EP program and its
management.
Conclusions
The department reorganization and hiring of a manager with extensive EP
experience enhanced the EP program. The inspectors concluded that the positive
findings during this inspection were an indication that the program had significantly
improved since the last inspection.
P7
Quality Assurance in EP Activities
a.
Inspection Scope (82701)
b.
c.
The inspectors reviewed the 1996 and 1997 Quality Assurance (QA) audit reports
of EP to assess the effectiveness of the audits of the EP program.
Observations and Findings
During an interview with the lead QA auditor for the last EP-evaluation conducted
from November 3 to December 5, 1997, the inspectors determined that PSE&G had
expended significant resources to conduct the audit. Specifically, the audit
consisted of several person-weeks of effort and included an .independent technical
specialist. The inspectors reviewed the 1997 audit plan and checklists, which
covered 10 CFR 50.54(t) requirements, commitments in the E-Plan, and the
guidance in NUREG-0654, "Criteria for Preparation and Evaluation ~f Radiological
Emergency Response Plans and Preparedness in Support of Nuclear Power Plants".
The checklist used to implement the audit plan for the 1997 audit was thorough.
The 1996 and 1997 audit reports were of sufficient scope and depth to assess the
EP program, and addressed the areas specified in 10 CFR 50.54(t). Numerous
recommendations for program enhancement resulted. The recommendations were
not indicative of programmatic weaknesses and were incorporated by the EP
department. The inspectors verified that offsite officials were provided copies of
the audit report section pertaining to PSE&G's interface with offsite agencies and
that the reports were distributed to the appropriate licensee management.
Conclusions
Quality Assurance audits of the emergency preparedness (EP) program were
thorough and the reports were useful to PSE&G management in assessing the
effectiveness of the EP program and providing enhancement recommendations.
This area was assessed as excellent .
22
Miscellaneous Security and Safeguards Issues
S8.1
Operational Security Response Evaluation for Hope Creek and Salem
NRC headquarters and regional inspectors conducted an on-site Operational Security
Response Evaluation at both the Hope Creek and Salem generating stations from
April 20, 1998 to April 24, 1998. The findings of this inspection will be
documented in NRC Inspection Report 50-272, 311, and 354/98-201.
FS
Miscellaneous Fire Protection Issues
F8.1
Fire Protection Inspection for Hope Creek and Salem
Region-based inspectors performed an inspection of the adequacy of the fire
protection program at the Hope Creek and Salem generating stations from March
23, 1998 to March 27, 1998. The findings of this inspection were documented in
NRC Inspection Report 50-354/98-02 for Hope Creek.
V. Management Meetings
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on May 11 , 1998. The licensee acknowledged the findings
presented.
The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified .
IP 37551:
IP 40500:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 82701:
IP 90712:
IP 92700:
IP 92702:
IP 92901:
IP 92902:
IP 92903:
IP 92904:
IP 93702:
23
INSPECTION PROCEDURES USED
Onsite Engineering
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing
Problems
Surveillance Observations
Maintenance Observations
Plant Operations
Plant Support Activities
Operational Status of the Emergency Preparedness
In-office Review of Written Reports of Nonroutine Events at Power Reactor
Facilities
On-site Followup of Written Reports of Nonroutine Events at Power Reactor
Facilities
Followup on Corrective Actions For Violations and Deviations
Plant Operations Followup
Maintenance Followup
Engineering Followup
Plant Support Followup
Event Followup
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened/Closed
50-311/98-03-01
50-272&311/98-81-01
50-272&311 /98-81-02
Closed
50-272&311 /96-08-02
50-272&311 /96-08-03
50-311 /96-18-02
50-311 /97-03-02
50-311 /97-07-01
50-311 /97-14-03
50-272/97-013-00
50-272/98-002-00
50-272/98-002-01
Failure to implement procedure step in safety
tagging program
NOV Failure to implement action request procedure
NOV Failure to implement corrective action procedure
Failure to perform post maintenance testing.
Inadequate safety-related material storage.
Lack of containment closure during refueling.
IFI
Management of commitment process.
Failure to establish containment integrity within
eight hours.
Improper restoration of emergency diesel
generator following testing.
LER
Failure to meet TS 3.8.1.1 Action B
LER
Auxiliary building excess flow damper found
wired open with spring removed
LER
Auxiliary building excess flow damper found
wired open with spring removed
CFCU
EOG
LCO
LER
NRC
osc
PSE&G
RATI
TS
voe
WMM
24
LIST OF ACRONYMS USED
Allowed Outage Time
Confirmatory Action Letter
Containment Fan Coil Unit
Emergency Action Level
Emergency Preparedness Implementing Procedure
Emergency Response Organization
Flow-Accelerated Corrosion
Limiting Condition For Operation
Licensee Event Report
Nuclear Regulatory Commission
Operations Support Center
Public Document Room
Post Maintenance Testing
Public Service Electric and Gas
Quality Assurance
Restart Assessment Team Inspection
. Salem Assessment Panel
Steam Generator Feed Pump
Technical Specifications
Updated Final Safety Analysis Report
Volt DC
Work Management Manual