ML18102B550
| ML18102B550 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 08/14/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18102B548 | List: |
| References | |
| 50-272-97-14, 50-311-97-14, NUDOCS 9709020259 | |
| Download: ML18102B550 (49) | |
See also: IR 05000272/1997014
Text
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Docket Nos:
License Nos:
Report No.
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
U. S. NUCLEAR REGULATORY COMMISSION
50-272, 50-311
REGION I
50-272/97-14, 50-311/97-14
Public Service Electric and Gas Company
Salem Nuclear Generating Station, Units 1 & 2
P.O. Box 236
Hancocks Bridge, New Jersey 08038
June 22, 1997 - July 26, 1997
M. G. Evans, Senior Resident Inspector
C. S. Marschall, Senior Resident Inspector
J. G. Schoppy, "senior Resident lnsplctor .
R. K. Lorson, Resident Inspector
T. J. Kenny, Senior Reactor Engineer
F. J. Laughlin, Resident Inspector
James C. Linville, Chief, Projects Branch 3
Division of Reactor Project:
9709020259 970814
ADOCK 05000272
G
.....
EXECUTIVE SUMMARY
Salem Nuclear Generating Station
NRC Inspection Report 50-272/97-14, 50-311/97-14
This integrated inspection included aspects of licensee operations, engineering,
maintenance, and plant support. The report covers a 5-week period of resident inspection.
- In .addition, it includes the results of announced inspections by regional engineering and
emergency preparedness inspectors.
Operations
The inspectors observed professional and safety-conscious operations. (Section 01 . 1)
A control room supervisor's lack of attention to detail resulted in a missed entry into the
Technical Specification limiting condition for operation action statement for the Unit 2
control room intake duct radiation monitor. This was considered a non-cited violation
(NCV 50-311/97-14-01). Plant management promptly identified the operator performance
issue and took appropriate corrective actions. (Section 01.2)
Plant and operations management took timely and appropriate actions to address an
increase in operator errors that occurred in the early to middle part of the report period.
Since July 16, 1997, the number and frequency of operator performance issues has
decreased significantly and the control of activities by the control room supervisors has *
improved. The inspectors will continue to monitor operations performance prior to and
during the Unit 2 startup as part of normal inspection activities. In addition, for those
issues identified which require a Licensee Event Report (LER), the inspectors will further
review licensee corrective actions upon issuance of the LERs. (Section 07. 1)
Maintenance
A retest group operator and a maintenance supervisor demonstrated good questioning
attitudes in identifying that operators failed to perform adequate post maintenance tests of
main steam check valves. The failure to perform an adequate retest was considered a non-
cited violation (NCV 50-311197-14-02). Operators took prompt and appropriate corrective
actions to ensure the turbine-driven auxiliary feedwater pu!Tlp operability after the testing
deficiencies were identified. (Section M1 .2)
The operator's decision not to remove test equipment from the emergency diesel gen.erator
control cabinet during restoration from surveillance test procedure S2.0P-ST.DG-0001 was
improper and a violation of Technical Specification 6.8.1. (NOV 50-311197-14-03) (Section
M1 .3)
The attempt to test the feedwater stop check valves in a manner not defined by the ASME
Code demonstrated a weakness in implementation of the in-service test program.
Operations management's decision to leave these valves isolated while the issue was
under review was appropriate. (Section M1 .4)
ii
Engineering
Operations management implemented adequate interim actions to address the control of
entry into the control room envelope instrument backpanels. Licensee management
indicated that a detailed plan to correct this condition would be available by September 1 ,
1997. (Section E2. 1)
The licensee adequately investigated an unexpected control room ventilation alignment that
occurred during a maintenance activity. (Section E2.1 l
Plant Support
Recent licensee changes to the emergency plan and its implementing procedures did not
reduce the effectiveness of the emergency plan. The plan changes are subject to future
inspection. (Section P3.1)
iii
TABLE OF CONTENTS
EXECUTIVE SUMMARY
ii
TABLE OF CONTENTS .............................................. iv
I. Operations ................ * ...........................
~. . . . . . . . . .
1
01
Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
01 . 1 General Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
01.2 Missed Technical Specification LCO Action for R1 B lnoperability . . . . . .
1
03
Operations Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . . .
2
03.1
(Closed} Inspector Followup Item 50-272&311 /96-0B-09 . . . . . . . . . . .
2
07
Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2
- 07. 1 . Human Performance Issues in Operations
. . . . . . . . . . . . . . . . . . . . . .
2
OB
Miscellaneous Operations Issue
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
OB.1
(Closed) Unresolved Items 50-311/96-B1-01 & 02 and LER 50-
272/96-037-00 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
OB.2
(Closed) Unresolved Item 50-311/96-B1-03 . . . . . . . . . . . . . . . . . . . . .
4
OB.3 (Closed) Unresolved Item 50-311/96-B1-10 . . . . . . . . . . . . . . . . . . . . .
5
II. Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
M 1
Conduct of Maintenance .............. ; . . . . . . . . . . . . . . . . . . . . . . . . 6
M1 .1
General Comments ............................. * . . . . . . . . . 6
M1 .2 Post Maintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
M1 .3 2A Emergency Diesel Generator Post-Test Restoration . . . . . . . . . . . . . 7
M1 .4 Feedwater Stop Check Valve In-Service Testing
. . . . . . . . . . . . . . . . . B
M1 .5 Reactor Coolant System Pressure Isolation Valve Testing . . . . . . . . . .
10
MB
Miscellaneous Maintenance Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10
MB.1
(Closed) Unresolved Item 50-311/96-B1-05 . . . . . . . . . . . . . . . . . . . .
10
MB.2 (Closed} Unresolved Item 50-311/96-B1-06 . . . . . . . . . . . . . . . . . . . .
10
MB.3 (Closed) Unresolved Item 50-311/96-B1-0B . . . . . . . . . . . . . . . . . . . .
11
MB.4 (Closed) Unresolved Item 50-311/96-B1-09 . . . . . . . . . . . . . . . . . . . .
13
Ill. Engineering
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14
E2
Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . .
14
E2.1
Control Room Emergency Ventilation System Design Issues . . . . . . . .
14
EB
Miscellaneous Engineering Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16
EB. 1
(Closed) Unresolved Item 50-311/96-B1-11 . . . . . . . . . . . . . . . . . . . .
16
EB.2
(Closed) Unresolved Item 50-311/96-B1-12 .................... 16
EB.3
(Closed) Unresolved Item 50-311/96-B1-15 . . . . . . . . . . . . . . . . . . . .
17
iv
IV. Plant Support . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
P3
EP Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1 8
P3. 1
In-Office Review of Licensee Procedure Changes . . . . . . . . . . . . . . . .
18
F8
Miscellaneous Fire Protection Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
F8.1
Appendix R Post-Fire Alternative Shutdown; (Closed) Unresolved Item
50-27 2&311 /93-80-08 .......................... ; . . . . . . .
18
V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
X 1
Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
X2
Pre-Decisional Enforcement Conference Summary . . . . . . . . . . . . . . . . . . . .
18
v
Report Details
Summary of Plant Status
Unit 1 remained defueled for the duration of the inspection period.
Unit 2 began the inspection period in Mode 4. On July 3, operators increased average
coolant temperature above 350°F and entered Mode 3. On July 24, operators commenced
a cooldown of Unit 2 and entered Mode 5 on July 26.
I. Operations
01
Conduct of Operations
01 . 1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operations. In general, the conduct of operations was professional
and safety-conscious; specific events and noteworthy observations are detailed in
the sections below.
01.2 Missed Technical Specification LCO Action for R1 B lnoperability
a.
Inspection Scope (71707)
The licensee identified that operators missed a Technical Specification action
requirement for control room radiation monitors for Salem Unit 2. The inspector
reviewed the licensee's corrective actions to address this deficiency.
b.
Observations and Findings
The Salem Unit 1 and Unit 2 Technical Specifications require two operable radiation
monitoring instrumentation channels for each control room ventilation intake. For
the Unit 2 intake duct, the radiation monitor instrumentation channels are 1 R 1 B-2
and 2R1 B-1.
On July 15, 1997, operators failed to complete the action required by Technical
Specification limiting condition for operation (LCO) action statement for the Unit 2
control room ventilation intake duct. Specifically, control room operators allowed
channel 2R 1 B-1 to being taken out of service for a channel count per procedure
S2.IC-CC.RM-0002, while the redundant channel, 1 R1 B-2, was inoperable. On
July 13, 1997, 1R1 B-2 had elevated counts due to a pin hole leak in the Mylar foil
and had been declared inoperable.
Both channels were inoperable for about three
hours. Per Technical Specification 3.3.3.1, with less than the required channels
operable, the control room emergency air condition system (CREASl must be placed
in service. This was not done immediately, because the senior reactor operators
(SROs) did not immediately recognize that both channels were inoperable.
2
The cause of this issue appears to be a weakness in personnel performance on the
part of the control room supervisor (CRS) who did not take the time to fully
understand which radiation monitor channels were already considered inoperable
when he allowed 2R 1 B-1 to be taken out of service. There were also weaknesses
in logging the condition of the radiation monitor channels in the Technical
Specification Action Statement (TSAS) log and the nomenclature for identification of
the radiation monitor channels.
The licensee's immediate corrective action included discipline of the SRO involved
and the addition of independent reviews for all entries and exits from the TSAS log .
. The licensee is developing longer term corrective actions such as changes in the
nomenclature for the radiation monitor channels and additional operator training on
the system. These actions will be detailed in the Licensee Event Report for this
missed Technical Specification action requirement.
The failure to compelte the action required by the LCO action statement is a
violation of Technical Specification 3.3.3.1. However, this licensee-identified and
corrected violation is being treated as a Non-cited Violation, consistent with Section
Vll.B.1 of the NRC Enforcement Policy. (NCV 311/97-14-01)
c.
Conclusions
Although a control room supervisor's lack of attention to detail resulted in a missed
entry into the LCO action statement for the Unit 2 control room intake duct
radiation monitor, the licensee promptly identified the condition and took
appropriate corrective action.
03
- Operations Procedures and Documentation
03.1
!Closed) Inspector Followup Item 50-272&311 /96-08-09: procedures for cross
connecting Salem Unit 1 &2 spent fuel cooling systems.
Section 9.1.3.2 of the Updated Final Safety Analysis Report (UFSAR) states that
the Unit 1 &2 spent fuel cooling systems can be cross-connected if required. In
March 1996 an NRC inspection identified that no operating procedure existed to
operate in this configuration.
The inspector reviewed procedure S2.0P-SO.SF-0002(Z), Spent Fuel Cooling
System Operation, and found that the procedure was revised to provide instructions
for cross-connected operation. Inspector followup item 96-08-09 is closed.*
07
Quality Assurance in Operations
07.1
Human Performance Issues in Operations
On July 16, 1997, plant management implemented actions to address a series of
operational errors that had occurred since May 1997. A majority of the errors
occurred during the period June 30 through July 15, 1997. Although, individually,
3
the issues were not considered significant by the licensee or the NRC, taken as a
whole, they reflected an overall decline in performance in Salem operations
department. For example, in May 1 997; the NRC identified that the operations staff
did not document and pursue the root cause of recurring configuration control
deficiencies (Violation 50-272&311 /97-12-02). During the period June 30 through
July 15, 1997, licensee identified issues included: a Unit 1 effluent release
performed without performing the Technical Specification required independent
verification of the tank valve line-up; the surveillance requirement to perform a
channel check of all 4 loss of power event (LOOP) average temperatures was not
performed as required upon raising temperature above 543 degrees Fahrenheit;
operators failed to perform a required post-maintenance test following a main steam
check valve packing adjustment and did not ensure operability of the 23 auxiliary
feedwater pump (discussed in Section M1 .2 of this report); and a CRS missed a
Technical Specification action requirement for control room radiation monitors for
Salern Unit 2 (discussed in Section 01.2 of this report).
As of July 16, 1997, the corrective actions implemented by licensee management
included: independent verification of all entries and exits from the Technical
Specification Action Statement log; the use of the NAP-5 brief sheet for all
evolutions; and improved control and enforcement of the work schedule. Licensee
management briefed NRC Region I management on these issues, including the
corrective actions, on July 17, 1997. The licensee implemented a level 1 Condition
Report (AR #970717297) to provide additional review of the potential common
causes of these human performance issues following completion of the root cause
evaluations for the individual issues.
c.
Conclusions
The inspectors found that the actions that licensee management took to address the
increase in operations errors were appropriate and very good. Management
responded to the indication of a decline in operator performance in a timely manner.
Since July 16, 1997, the number and frequency of operations human performance
issues has decreased and control of activities by the control room supervisors has
improved. In addition, for those issues identified above which require a Licensee
Event Report (LER), the inspectors will further review licensee corrective actions
upon issuance of the LERs.
08
Miscellaneous Operations Issue
08.1
(Closed) Unresolved Items 50-311 /96-81-01 & 02 and LER 50-272/96-037-00: As
an interim measure, in 1995, PSE&G initiated a policy to ensure that at least two
component cooling (CC) pumps were operable during plant operation, but failed to
appropriately account for a single failure of CC pump room ventilation. The failure
of the 22/23 CC pump room cooler, when the 21 CC pump was out of service,
could have resulted in no available CC pumps during some postulated accident
conditions. PSE&G properly notified the NRC in LER 96-037-00 on
December 26, 1996.
4
The effect of the failure of the 22/23 CC pump room cooler on the operability of the
equipment within the room had not previously been considered. Specifically, the
22/23 CC room cooler failure would result in reduced *air flow for room cooling and
could lead to the failure of the CC pumps, and other equipment, due to unanalyzed
high temperatures. PSE&G implemented the following actions to ensure that
current Emergency Operating Procedures (EOPs) are not adversely affected by
failure of the room cooler to the 22/23 CC pump room:
1 .
The door to the 22/23 CC pump room was removed to allow increased air
flow into the pump room with the room cooler failed.
2.
The air flow to the CC pump rooms was re-balanced to redirect a portion of
flow from the 21 CC room cooler.
3.
Based on new calculations, the 22/23 CC pump room temperature remains
below 130°F under design basis accident conditions, including failure of the
22/23 CC pump room cooler.
4.
Electrical equipment in the 22/23 CC pump room is acceptable to 132°F,
with the exception of seven relays that were subsequently replaced.
5.
Mechanical equipment in the 22/23 CC pump room (e.g. pumps, lubricants,
bearings, MOVs, etc.) was evaluated as satisfactory up to 132°F.
6.
FSAR change request No. 97-05 was approved to revise Section 9.4.2 to
address the room cooler failure.
The inspectors independently reviewed the calculation "CC Pump Room
Temperature Following a Room Cooler Failure" and verified that the adjusted flow
from the 21 CC pump room cooler was included in the calculation. The inspector
verified that an electrical relay evaluation appeared complete, regarding the seven
relays that were not rated to perform at the calculated maximum temperature of
132 ° F and reviewed completed work orders to verify that the seven relays were
replaced. The inspector verified that various components were properly evaluated
for* 132 ° F and visually verified that the doors between the 22/23 CC pump room
and the hallway were removed.
Based on the above, the unresolved items and LER are closed.
(Closed) Unresolved Item 50-311 /96-81-03: Emergency Operating Procedures had
previously allowed a CC pump to operate at flow rates beyond its documented
design limits for a short period of time. The failure to provide a technically sound
basis for operating a CC pump in this manner was unresolved.
An engineering analysis had been prepared by MPR Associates, Inc. that determined
the CC pumps could operate reliably during and after the run-out condition, which
lasts approximately 10 to 15 minutes. The NRC inspector had reviewed the MPR
analysis and questioned the conclusion because ( 1) the evaluated run-out flow of
5
5600 gpm was less than flows being predicted by the current system flow model
(around 6300 gpm) and (2) the pump manufacturer (Goulds Pump Co.) had not
provided input to the evaluation.
PSE&G arranged and conducted two pump tests, one at the manufacturer's test
facility and the other at Salem Unit 1 . The insp.ector reviewed documentation
related to both pump tests and concluded that the test flow rate exceeded the
previously calculated system flow rate for the run-out condition. The testing
confirmed the MPR analysis, that the CC pumps will perform adequately during and
after run-out conditions.
Based on the above, the unresolved item is closed.
08.3 !Closed) Unresolved Item 50-311/96-81-10: This unresolved item was identified
during the review of the technical basis for assuring that adequate CC water flow
will be provided to emergency core cooling system coolers following the initiation of
an accident. The licensee's operations staff indicated that the EOPs would direct
the operators to manually start a CC pump in less than 20 minutes after the
initiation of any accident event. However, PSE&G was unable to provide
documentation to support this assessment.
The inspector reviewed CR 950814345, Condition Report Corrective Action (CRCA)
No. 3 which documented that the operations staff confirmed, through simulator
training scenarios, that a CC pump can be started in less than ten minutes. With an
SI signal and loss-of-power, the CC pump was started by the operators using the
EOPs regardless of the initiating event (i.e. large-break LOCA, small-break LOCA,
etc.) in less than ten minutes. Consequently, under post accident conditions, a CC
pump could be started and provide cooling to emergency core cooling system
(ECCS) seal coolers within the 15 to 20 minute requirement of the 1980
Westinghouse letter. The inspector had discussions with an operation supervisor
and confirmed that several different crews performed the scenarios with the same
acceptable results stated above.
In addition to the above, the inspector noted that the CC pump was started during
the injection phase of a LOCA. In this case, the injection water (from the refueling
water storage tank (RWST)) will typically be 80°F or below (with maximum
temperatures in the mid-90s). Since CC temperatures can approach 100°F under
design basis conditions, the seals are effectively self-cooled (by the cooler RWST
water) throughout the injection phase. Consequently, with a CC pump starting prior
to the recirculation phase (where pumped fluids approach containment accident
temperatures and begin heating the seals), the ECCS pumps are effectively never
without cooling under post-accident conditions.
Based on the above, the unresolved item is closed.
6
II; Maintenance
M1
Conduct of Maintenance
M 1 . 1 General Comments
a.
Inspection Scope (61726)
The inspectors observed all or portions of the following surveillances:
- 52.0P-ST.SJ-0020:
- 52.0P-ST.DG-0003:
- 52.RE-ST.ZZ-0002:
- 52.0P-ST.RC-0008
- 52.0P-ST.AF-0006:
- 52.0P-ST.CBV-0003:
Periodic Leakage Test RCS Pressure Isolation Valves -
Mode 4
2C Diesel Generator Surveillance Test
Shutdown Margin Calculation
Reactor Coolant System Water Inventory Balance
lnservice Testing Auxiliary *Feedwater Valves
Containment Systems Cooling Systems
The inspectors observed that plant staff did the surveillances safely, effectively
proving operability of the associated system.
M1 .2 Post Maintenance Testing
a.
Inspection Scope (71707)
The licensee identified that operators failed to perform a required post maintenance
test (PMT) following a main steam check valve packing adjustment and did not
ensure operability of the no. 23 auxiliary feedwater pump. The inspector reviewed
the licensee's corrective actions to address this deficiency.
b.
Observations and Findings
On July 4, 1997, maintenance technicians adjusted the packing on 21 MS46, "no.
21 main steam header check valve to no. 23 turbine-driven auxiliary feedwater
(TDAFW) pump." On July 6, maintenance technicians adjusted the packing on
23MS46, "no. 23 main steam header check valve to no. 23 TDAFW pump." In
both cases, operators did not perform a PMT to ensure continued TDAFW pump
operability.
On July 14, an operator in the retest group identified that operators did not perform
the PMT following the work on 21 MS46. Operators declared the TDAFW pump
inoperable and entered TS LCO 3.7.1.2.B. Within 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, operators performed
S2.0P-ST.AF-0006, lnservice Testing Auxiliary Feedwater Valves, to demonstrate
operability of 21 MS46 and declared the TDAFW pump operable. Operators initiated
a significance level 1 AR (970714384) to address the root cause of their failure to
perform the required PMT.
c.
7
On July 15, a maintenance supervisor identified that operators failed to perform a
PMT following 23MS46 maintenance on July 6. Operators declared the TDAFW
pump inoperable, performed S2.0P-ST.AF-0006 to restore operability and initiated
another level 1 AR (970715183) to address this failure as some of the contributing
factors appeared different from the 21 MS46 inadequate PMT. The inspector noted
that the retest group operator and the maintenance supervisor demonstrated good
questioning attitudes in identifying the missed PMTs. In both cases, operators
appropriately considered the TDAFW pump inoperable and promptly completed the
applicable surveillance test. The missed PMTs resulted in no safety consequence as
the successful surveillance tests demonstrated continued operability of the TDAFW
pump despite the main steam check valve maintenance. Failure to perform an
adequate PMT is a violation of NC.NA-AP.ZZ-0009, Work Control Process. This
non-repetitive, licensee-identified and corrected violation is being treated as a Non-
Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy.
(NCV 50-311197-14-02)
Conclusions
A retest group operator and a maintenance supervisor demonstrated good
questioning attitudes in identifying that operators failed to perforn:i adequate post
maintenance tests of main steam check valves. Operators took prompt and
appropriate corrective action to ensure turbine-driven auxiliary feedwater pump
operability and root cause evaluation of the identified deficiencies.
M1 .3 2A Emergency Diesel Generator Post-Test Restoration
a.
Inspection Scope (61726/71707)
The inspectors reviewed an observation that electrical test equipment remained
connected to the 2A emergency diesel generator (EOG) for about nine hours on July
2 while the 2A EOG was considered operable.
b.
Observations and Findings
The 2A EOG was tested early on July 2 in accordance with surveillance test
procedure, S2.0P-ST.DG-0001, 2A Diesel Generator Surveillance Test. The
operators completed the test and declared the EOG operable at 0545. The
inspector subsequently observed that the 2A EOG control cabinet door was partially
open and that electrical test equipment installed for the test remained connected
inside the 2A EOG control cabinet.
The CRS indicated that the test equipment had not been removed in order to
support additional EOG testing scheduled for later that day. The CRS also indicated
that the step in ST.OP-ST.DG-0001 that directed removal of the test equipment had
been marked as not applicable, and the second test procedure had been initiated up
to the step that installed the equipment. The operators, however, were unable to
immediately perform this test since the EOG lubricating oil system had to cooldown
in order to meet the initial test conditions.
8
The inspector questioned whether leaving the EOG control cabinet in this condition
affected its operability and also whether this condition had been previously
evaluated. The inspector discussed this question with operations management who
agreed to review the issue and also implemented interim guidance to declare the
EOG inoperable anytime the control cabinet door was opened.
The EOG system manager's initial operability review focused on electrical separation
of the EOG control circuitry from the non-1 E test equipment and associated power
supply, and also on the impact of a seismic event on relays mounted on the EOG
control panel door. The final assessment had not been provided prior to the end of
this report period.
The inspector also reviewed an evaluation that had been performed in 1993 to
justify installation of the test equipment, and noted that it did not provide a basis
for concluding that the EOG could remain operable while the test equipment was
installed. The inspector concluded that the operator's decision not to remove the
EOG test equipment as required by step 5.11.5 of S2.0P-ST.OG-0001 before
completing the procedure and declaring the EOG operable was improper since this
condition had not been previously analyzed.
Technical Specification 6.8.1 requires, in part, that written procedures be
implemented to perform surveillance testing of safety-related equipment. Contrary
to the above surveillance test procedure S2.0P-ST.OG-0001 was not properly
implemented on July 2 since test equipment was not removed from the 2A EOG
control cabinet as required by step 5.11.5 of the procedure. This constitutes a
violation of TS 6.8.1. (VIO 50-311/97-14-03)
c.
Conclusions
The operator's decision not to remove the test equipment from the EOG control
cabinet before completing surveillance test procedure S2.0P-ST.OG-0001 was
improper and a violation of Technical Specification 6.8.1.
M1 .4 Feedwater Stop Check Valve In-Service Testing
a.
Inspection Scope (61726)
b.
The inspector reviewed the licensee's response to the failure of two feedwater stop
check valves (22BF22 and 23BF22) to meet their in-service test (IST) performance
requirements.
Observations and Findings
The BF22 valves are normally open piston stop check valves that have an active
safety function to close for: 1) containment isolation, and 2) to prevent the
diversion of auxiliary feedwater flow through a feedwater line break upstream of
these valves. The BF22 valves are designed to close automatically upon reversal of
flow and are provided with a motor operator to minimize seat leakage through the
valve.
9
Technical specification 4.0.5 requires the valves be tested in accordance with the
American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code
unless granted specific relief. The IST program requires the check valve feature to
be tested to support operability of the auxiliary feedwater system. The applicable
ASME Code provides two methods for testing the check valve function. The first
method involves observation that the valve disc travels to its seat upon the
cessation or reversal of flow. The observation can be either direct (i.e. position
indicator) or indirect such as observing a system pressure change. The second
method for testing the check valve function would be to disassemble and inspect
the check valve.
The BF22 valves were tested on July 1 per test procedure S2.0P-ST.MS-0002,
lnservice Testing Main Steam And Main Feedwater Valves, which involved
establishing reverse flow through the valves while the steam generators were
press1,Jrized to about 90 psig. The valves failed to establish the required 50 psig
differential pressure specified by the test procedure to confirm the valve closure.
The licensee subsequently revised the test procedure to require that the motor
operator be used to shut the check valves during the testing. Salem engineering
personnel stated that use of the motor operator was technically acceptable since
the motor operator developed only about 50% of the seating force that the valve
would experience at full steam generator operating pressures.
The inspector questioned this test method since it was not defined in the applicable
ASME Code or in NUREG 1482 which contained general guidance for testing stop
check valves. The inspector reviewed this issue with a Region I specialist inspector
and with a NRR technical specialist who indicated that use of the motor 'operator to
test the valve had not been defined by the ASME Code or NUREG 1482.
Operations management maintained the 22BF22 and the 23BF22 valves isolated
while this issue was being reviewed.
The licensee reviewed this information and subsequently decided to test the BF22
valves using a reverse flow method with the steam generator at a higher initial
pressure. The BF22 valves were observed to change position by either
establishment of the required differential pressure or by acoustic monitoring.
c.
Conclusions
The inspector concluded that the final BF22 valve test method met the ASME Code
test requirements. The inspector considered the operations management decision to
leave these valves isolated while the issue was being reviewed appropriate. The
attempt to test the BF22 valves in a manner not previously defined by the ASME
Code demonstrated a weakness in implementation of the IST program .
10
M1 .5 Reactor Coolant System Pressure Isolation Valve Testing
The inspector observed the operators test the reactor coolant system pressure
isolation check valves specified by Technical Specification surveillance requirement 4.4.7.2.2d. The inspector noted that the testing was performed in accordance with
surveillance procedure S2.0P-ST.SJ-0020, Periodic Leakage Test RCS Pressure
Isolation Valves Mode 4, and the valve performance satisfied the test acceptance
limits. The inspector also reviewed the test flowpath against the system drawing
and concluded that the test lineup was acceptable.
MS
Miscellaneous Maintenance Issues
M8.1 (Closed) Unresolved Item 50-311 /96-81-05: This item was opened because the
NRC concluded that the computerized model used to predict component cooling
heat ~xchanger (CCHX) performance, based on test data, may not be conservative.
PSE&G was in contact with the heat exchanger manufacturer to resolve this issue.
The NRC concluded that the lack of a specific documented technical basis for the
five percent instrument measurement uncertainty assumption used in CC heat
exchanger performance calculations was an unresolved item.
The inspector reviewed calculation S-C-CC-MDC-1686 Rev 0, performed to .
determine the instrument measurement uncertainty. The calculation documented
the technical basis for instrument uncertainty associated with heat exchanger
performance testing. The results of the calculation showed the instrument
measurement uncertainty for 21 CCHX to be plus or minus 2.42 percent and plus or
minus 4:83 percent for 22CCHX. These percentages are within the acceptance
criteria stated above. Therefore, the inspector determined that the calculation
supported the five percent uncertainty assumption used in calculating the heat
transfer rate.
Based on the above, the unresolved item is closed.
(Closed) Unresolved Item 50-311 /96-81-06: The lack of acceptance criteria for
assessing the as-found condition of the CC room coolers and the lack of criteria for
establishing adequate service water and air flow rates in CC room cooler
maintenance procedures were considered to be unresolved items.
The inspector reviewed the procedures for inspecting service water room cooler
internals and for performing service water biofouling monitoring of room coolers.
The procedure for inspecting service water room cooler internals does not provide
specific criteria for assessing the as found condition of the heat exchanger.
However, PSE&G has taken actions to reduce the amount of material deposited in
the heat exchangers. Through interviews with the system engineer, the inspector
verified that the service water is continuously chlorinated to eliminate biofouling.
Further, the inspector verified through photos that PSE&G had applied an epoxy
lining to the heat exchanger internals. According to the system engineer, this
epoxy lining has* not demonstrated failures and was installed to prevent pitting and
corrosion. The "as found" photos, taken after opening the coolers did not show
11
any excessive debris. Finally, the inspector verified that the room cooler heat
exchangers are scheduled to be cleaned and inspected every refueling outage, and
the cleaning procedure includes both the water and air sides of the heat
exchangers.
The inspector reviewed and verified that the procedure for performing service water
biofouling monitoring of room coolers was revised to include a periodic room cooler
service water differential pressure test. This procedure provides criteria for
determining unacceptable differential pressures by including a methodology for
determining the differential pressure limit. According to the system engineer, the
periodic differential pressure tests for the room coolers are scheduled to be
performed every 90 days, however, this frequency is subject to change depending
on the initial trended data.
In order to verify acceptable air flow rates through the room cooler heat exchangers,
the inspector reviewed the results of the flow balance tests and verified that the
measured flow rates for cooling room ventilation, correlated to the design flow rates
as depicted in the current design basis. Further, in order to ensure proper
ventilation to the CC pump rooms, PSE&G is in the process of establishing a
procedure and recurring task to periodically verify the adequacy of the auxiliary
building ventilation supply and exhaust flows for CC pump room cooling. These
procedures are not considered essential to re-start efforts, and are scheduled to be
completed by August 1, 1997.
Based on the above, the unresolved issue is closed.
M8.3 (Closed) Unresolved Item 50-311196-81-08: This item was identified during the
review of the ventilation system to determine its capability and readiness in
supporting the operability of the CC system.
The NRC had observed three design and configuration deficiencies during plant walk
downs:
1 .
The louvered fire damper in the fire door (Door C8-2) for 21 CC pump room
was closed and design information concerning this damper was not available.
The impact of this closed louvered fire damper on return air flow and room
temperature had not been determined, thus the closed louvered fire damper
may have prevented the CC room coolers from performing their design basis
function.
PSE&G concluded that due to leakage around the damper and the door, the
closed louvered fire damper in the 21 CC pump room did not adversely affect
the flow balance. The fire damper was determined to be inoperable and was
subsequently replaced. The auxiliary building ventilation flow balance for
this area was re-performed.
12
The inspectors reviewed the Performance Improvement Requests (PRs) for
the closed louvered fire damper in Door C8-2 (fire door for 21 CC pump
room). The PRs indicate that the fire protection group performs daily visual
inspections of fire doors, however, inspection of fire dampers on these doors
was not included. The inspector verified that the Fire Protection daily
inspection procedures were revised to include the position of the louvered
fire dampers as part of the daily inspection. In addition, the inspector-
reviewed the results of the flow balance tests and v*erified that the measured
flow rates for the 21 CC pump room ventilation correlated to the design flow
rates as depicted in the design basis.
The inspector questioned PSE&G personnel regarding the available design
information concerning the louvered fire damper in door C8-2. No air flow
calculation existed to determine if the louver in the fire door was adequately
sized. PSE&G determined a calculation was not necessary based on the
results of the flow balance tests, which indicated proper design flows were
achievable. The inspector reviewed the results of the flow balance tests and
verified that the measured flow rates for the 21 CC pump room ventilation,
correlated to the design flow rates as depict~d in the design basis.
In order to ensure proper ventilation to the CC pump rooms, PSE&G is in the
process of establishing a procedure and recurring task to periodically verify
the adequacy of the auxiliary building ventilation supply and exhaust flows
for CC pump room cooling. These procedures are not essential to re-start
efforts, and are scheduled to be complete by August 1 , 1997.
2.
The manual (2-VHE-747) damper, which supplies ventilation air to the 21
and 22/23 CC pump .rooms, and the manual (2-VHE-749) damper, which
supplies ventilation air to the 22/23 CC pump room, were closed.
The inspectors reviewed the Performance Improvement Request that
indicated the room cooler ducts were re-balanced upon verification that the
ventilation dampers were open. The inspector reviewed the results of the
flow balance tests and verified that the measured flow rates for the room
cooler dampers correlated to the design flow rates as depicted in the design
basis. In addition, the inspector visually verified that the ventilation dampers
were in the open position.
3.
PSE&G could not account for the position of the dampers described above
and indicated that there were no existing administrative controls regarding
ventilation damper positions to support equipment operability of safety-
related systems.
The inspectors verified that PSE&G has issued an action request to establish
programmatic controls associated with damper positions. These
programmatic controls were not essential for restart efforts and will be
complete post-restart.
13
PSE&G has completed actions to ensure adequate ventilation air flow to the CC
pump rooms by verifying proper damper and louver positions, and by periodically
performing flow balance tests.
Based on the above, the unresolved item is closed.
M8.4 (Closed) Unresolved Item 50-311196-81-09: This unresolved item was identified
during the review of the maintenance and surveillance test procedures required to
support the CC system. The 125 Volt batteries support control of the CC system
pumps, the on-site power supply, and power the pilot solenoid valves. The EDGs
supply power for the CC system pumps and motor operated valves. The NRC
concluded that the failure to incorporate the latest technical specification
surveillance criteria in the battery surveillance performance test procedure was a
procedure weakness. The NRC also concluded that the licensee had previously
failed to follow their battery performance test procedure for calculating the capacity
of batteries 2A and 2B in 1993 because of the inadequate test procedure.
The inspector reviewed condition report (CR) 961 206169 which indicated that the
1993 testing met technical specification requirements for battery capacity but failed
to provide a reference to determine battery degradation for the test in 1998. The
inspector verified by reviewing the test (1.SC.MD-FT.125-0002(0)) performed in
1993 that the calculation, required by the test, was not performed. This calculation
documents the battery's capacity and should be greater than 80 percent of the
manufacturers rating when subject to a performance discharge test as stated in
Technical Specification (TS) 4.8.2.3.2.g.
Technical Specification 4.8.2.3.2.h requires the current battery capacity to be at
least 80 percent of manufacturer's rating if the battery shows signs of degradation
as compared to the previous test (degradation is defined as ten percent). The
inspector verified that the results have been extrapolated to establish capacities of
115% (battery 2Al and 112.5% (battery 2B) and have been documented as
reference points for the 1 998 test. The extrapolated values are scheduled to be
added to the test procedure in accordance with CRCA No. 1 to CR 961206169 with
a completion date November 11, 1997. The inspector verified that revision 5, to
procedure SC.MD-FT.125-0002(0) has now included additional wording to ensure
compliance with TSs.
Based on the above, the unresolved item is closed.
. '
14
Ill. Engineering
E2
Engineering Support of Facilities and Equipment
E2.1
Control Room Emergency Ventilation System Design Issues
a.
Inspection Scope
The inspector reviewed two issues associated with the design and operation of the
control room emergency ventilation system. The first issue involved an unexpected
system lineup that occurred following a momentary loss of power to the control
room radiation monitoring instruments. The second issue involved the necessity to
.enter TS 3.7.6.c upon opening the control room envelope instrument backpanel
doors.
b.
Observations and Findings
Control Room Emergency Ventilation System Response To An Unexpected Electrical
Transient On July 20
On July 20, a momentary electrical spike occurred on the 1 B vital instrument bus
during a maintenance activity. The electrical spike caused a momentary loss of
power to the control room radiation monitors ( 1 R 1 B-1 (Unit 1) and 1R1 B-i (Unit 2)
that automatically shifted the control room ventilation system to an unexpected
configuration. The resultant ventilation lineup was equivalent to the "accident
pressurized" mode of operation with the exception that both the Unit 1 and the Unit
2 control room emergency ventilation intake dampers were open. The normal
accident pressurized mode of operation would have aligned the control room
ventilation intake to the "non-accident" unit intake dampers while the intake
dampers on the "accident" unit remained shut. The intake dampers are located
external to the auxiliary building of each unit.
The control room operators recognized the abnormal system lineup, aligned the
system to the defined accident pressurized mode of operation, and made the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
non-emergency event notification per 10 CFR 50. 72. The licensee reviewed the
event and determined that the system functioned properly per the installed plant
design, and also that the "as founq" system lineup would not have resulted in
exceeding the 10 CFR 50 Appendix A Design Criterion 19 control room personnel
exposure limits.
The inspector questioned the expected system response to a loss of offsite power
(LOOP). The licensee indicated that the radiation monitors would remain powered
during a LOOP event since they had a dual power supply with a battery backup.
The inspectors concluded that the licensee performed an adequate followup of this
event and that it had minimal significance .
15
Entry Into The Back Of The Control Room Envelope Instrument Panels
The licensee installed magnetic strips to seal the back of the normally shut control
room instrument panels (which form a portion of the control room envelope), and
also cut ventilation openings into the front and tops of the panels. This modification
was required to limit air leakage through the panels to allow the control room
emergency ventilation system to develop the required positive pressure ( + 1 /8 in.) in
the control room envelope relative to the adjacent spaces.
Salem also installed manually operated louvers to seal the front and top ventilation
openings to support transfer of the control room envelope to the front of the
instrument panels when the backpanel doors were opened. Salem operations and
maintenance personnel enter the panels weekly for log readings, and to perform
preventive and corrective maintenance activities. The licensee identified during
post-installation testing that shutting the louvers did not adequately seal the
instrument panels for the limiting design condition. Salem management decided, in
the interim, to declare the control room envelope inoperable and enter TS 3.7.6.c
anytime the back panel doors are open.
The resident inspectors observed this practice and questioned the frequency and
control of entries into the backpanels and also the planned corrective actions to
eliminate the need to enter TS 3. 7 .6.c. Operations management responded to these
concerns by reducing the number of planned entries into the backpanels, and also
by implementing tighter controls for opening the backpanel doors. The control room
envelope can be restored by shutting the backpanel door and by re-installing the
magnetic strips. The licensee is developing permanent corrective actions to address
this problem.
'
The inspectors noted that although the number of planned entries has decreased
there are still frequent entries into the backpanels for corrective maintenance
activities. For instance during a two week period, (June 27 to July 9) the inspector
noted that the backpanels were entered for four different corrective maintenance
activities. The inspector noted improved controls during the recent backpanel
entries. The inspector concluded that the licensee's interim actions were adequate.
This issue was discussed during a conference call between Region I management
and Salem plant and engineering management. Salem management indicated that a
detailed plan to correct this condition would be available by September 1, 1997.
c.
Conclusions
The licensee implemented adequate interim actions to address the control of entry
into the control room envelope back panels. Licensee management indicated that a
detailed plan to correct this condition would be available by September 1, 1997 .
16
Miscellaneous Engineering Issues
!Closed) Unresolved Item 50-311196-81-11 : The NRC concluded that there were
significant weaknesses in the calculation for the selection of the thermal overload
relays (TOLs) for the CC system MOVs. The design change to place the TOLs
inservice resulted in the installation of TOLs without a documented design basis.
The NRC concluded that the licensee had not maintained document control of the
TOLs associated with the CC system and other safety-related systems, because
heater sizes existed in MOV circuits that were not based on the existing calculated
basis. The NRC also concluded the change document to the design calculation did
not provide any documented basis to accept the installed TOL heaters for 30 safety-
related MOVs.
The inspector confirmed that during the process of implementing design change
packC!ge (DCP) 2EC-3249 (design change to remove jumpers from around the TOL
contacts and replace them with resized TOLs), the licensees' storeroom expended
the designated TOLs and issued similar ones in their place. After the design
engineer evaluated the newly issued TOLs and had them installed instead of the
original, the DCP was not properly updated to reflect the change. For example; the
single line diagram was updated to reflect the substituted (C3.01 A) TOL, however,
the revised calculation (E18.006) that showed the substitute relay would perform
the same as the original (C3.56A) TOL was l')Ot placed in the completed DCP
paperwork.
A total of 32 TOLs that were installed in MOVs were not documented properly. The
inspector reviewed design evaluation workbook-5 (1 EA-1260) that was performed
to document the acceptability of the as built configuration. Workbook-5 used the
same method of calculating point of trip for the TOLs that was used in the original
time concurrent characteristic (TCC) curves. The inspector verified that the TCC
curves, developed by workbook-5, showed that the MOVs would be capable of
performing their safety function without experiencing spurious trips with the
installed TOLs. The inspector verified that the Maintenance Management
Information System (MMIS) was updated to reflect the correct as installed TOLs.
The inspector concluded that the licensee took adequate actions to address this
issue. This unresolved item is closed.
E8.2
(Closed) Unresolved Item 50-311196-81-12: The NRC concluded that the design
basis documentation for the CC system radiation monitors was inconsistent. The
NRC also determined that the CC radiation monitor setpoints may be inappropriately
set high. These radiation monitors are not safety-related and are not used to
calculate offsite radioactive releases. The NRC also identified that the design basis
setpoint calculation for the surge tank level alarms contained missing information
identified in the body of the calculation, but had not been included in a system to
track its resolution .
17
The inspector reviewed CRCA No. 2 to CR961125133 that contained a workbook-4
calculation that showed the present R-1 7 radiation monitor set-point was
acceptable. The calculation showed that the R17 alarm setpoint would alarm in less
than 30 seconds with the reactor coolant leakage above one gpm with the worst
case bounding reactor coolant activity concentrations. The inspector reviewed 10
CFR 20 Appendix B table 2 and table 11 .1-8 of the UFSAR, and verified that the
chosen isotope "Iodine 131" was the bounding isotope, because it requires the
most dilution (2E-10 mCi/ml of air and 1 E-6 mCi/ml of water). Therefore, the
inspector concluded that the present setpoint provides an adequate barrier against .
exceeding 10 CFR limits for the limiting isotope Iodine 131, chosen for the
calculation. CRCA No. 2 to CR9611 25133 was issued to update the set-point basis
in the "Radiation Monitoring Configuration Basis Document" (CBD) and the vendor
manuals. The CBD and vendor manuals are scheduled to be up-dated, post-restart.
The scheduled completion date is December 30, 1997.
Based on the above, the unresolved item is closed.
E8.3
(Closed) Unresolved Item 50-311196-81-15: The NRC concluded that providing post
accident sampling system (PASS) heat exchanger cooling water from the
demineralized water system was inconsistent with the UFSAR. This issue was
unresolved pending the completion of the licensee's evaluation and assessment for
using demineralized water instead of CC.
The inspector reviewed UFSAR Section 9.3.6.2 that stated 10 gpm of CC ~ater is
supplied to the sample cooler rack to cool reactor coolant samples. Since CC to the
PASS sample cooler is provided from the Unit 2 CC system and is physically
connected to CC piping feeding the boric acid evaporator coolers, the Unit 2 CC
must be operating and the CC valves to the boric acid evaporator must be open, in
order to supply cooling water to PASS. However, under post-accident conditions,
the boric acid evaporator will* be manually isolated to reduce CC flow to non-safety
related components. Therefore, the alternative method of cooling the PASS sample
cooler was sµpplied from the Demineralized Water System.
The inspector reviewed Procedure SC.CH-AB.CC-1155(0), "Temporary Cooling of
PASS Cooler Rack 811 " that provides the steps necessary to install temporary
cooling (via demineralized water) when Unit 2 CC is not available to the PASS
cooler rack. Previously, this configuration was not delineated in the UFSAR. *
PSE&G initiated an action request, BP 961212177, to track completion of an
UFSAR change notice.
The inspector verified that the appropriate changes to Procedure SC.CH-SA.PAS-
1001 (0) "Pass Start-up" and SC.CH-AB.CC-1155(0) "Temporary Cooling of PASS
Cooler Rack 811" were implemented.
Based on the above, the unresolved item is closed .
P3
f 8
18
IV. Plant Support
EP Procedures and Documentation
In-Office Review of Licensee Procedure Changes
An in-office review of revisions to the emergency plan and its implementing
procedures submitted by the licensee was completed. A list of the specific
revisions reviewed are included in Attachment 1 to this report. Based on the
licensee's determination that the changes do not decrease the overall effectiveness
of the emergency plan, and that it continues to meet the standards of 10 CFR
50.47(b) and the requirements of Appendix E to Part 50, NRC approval is not
required for those changes.
Miscellaneous Fire Protection Issues
Appendix R Post-Fire Alternative Shutdown: (Closed) Unresolved Item 50-
272&311 /93-80-08
NRC Inspection Report 97-09 Section F8.1 discussed several unresolved items
involving Appendix R Alternative Shutdown requirements. Unresolved Item 93-80-
08 should have bee.n closed out in 97-09, but was not included due to an
administrative oversight. Unresolved Item 93-80-08 is closed, based on discussion
in section F.8.1.b of that report.
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 July 31, 1997. 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.
X2
Pre-Decisional Enforcement Conference Summary
On July 8, a pre-decisional enforcement conference was held at the NRC Region I office to
discuss potential enforcement issues identified in Inspection Reports 50-272&311 /97-09
and 97-11. The issues related to Appendix R concerns as discussed in Inspection Report
97-09 and emergency core cooling system operation outside the plant design basis .as -
discussed in Inspection Report 97-11. Slides used in the licensee's presentation at the
conference have been included as Attachment 2 to this report .
18
IV. Plant Support
P3
EP Procedures and Documentation
P3.1
In-Office Review of Licensee Procedure Changes
An in-office review of revisions to the emergency plan and its implementing
procedures submitted by the licensee was completed. A list of the specific
revisions reviewed are included in Attachment 1 to this report. Based on the
licensee's determination that the changes do not decrease the overall effectiveness
of the emergency plan, and that it continues to meet the standards of 10 CFR
50.47(b) and the requirements of Appendix E to Part 50, NRC approval is not
required for those changes.
F8
Miscellaneous Fire Protection Issues
F8.1
Appendix R Post-Fire Alternative Shutdown: !Closed) Unresolved Item 50-
272&311 /93-80-08
NRC Inspection Report 97-09 Section F8.1 discussed several unresolved items
involving Appendix R Alternative Shutdown requirements. Unresolved Item 93-80-
08 should have been closed out in 97-09, but was not included due to an
administrative oversight. Unresolved Item 93-80-08 is closed.
V. Management Meetings
X 1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on July 31, 1997. 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.
X2
Pre-Decisional Enforcement Conference Summary
On July 8, a pre-decisional enforcement conference was held at the NRC Region I office to
discuss potential enforcement issues identified in Inspection Reports 50-272&311 /97-09
and 97-11. The issues related to Appendix R concerns as discussed in Inspection Report
97-09 and emergency core cooling system operation outside the plant design basis as
discussed in Inspection Report 97-11. Slides used in the licensee's presentation at the
conference have been included as Attachment 2 to this report .
19
ATTACHMENT 1
REVIEWED LICENSEE DOCUMENTS
NUCLEAR BUSINESS UNIT
EMERGENCY PLAN IMPLEMENTING PROCEDURES
EPIP 102S
EPIP 103S
EPIP 104S
EPIP 105S
EPIP 201 S
EPIP 202S
EPIP 204S
EPIP 301 S
EPIP 302S
EPIP 309S
Alert - SNSS/EDO
Site Area Emergency - SNSS/EDO
General Emergency - SNSS/EDO
Upgrading Protective Action Recommendations
TSC-lntegrated Engineering Team Response
OSC Activation and Operations
Emergency Response Callout/Personnel Recall
Radiation Protection Technician On-Shift Response
Radiological Assessment Coordinator Response
Dose Assessment
12
13
13
7,8
9
16
35,36
19
20
11
EVENT CLASSIFICATION GUIDE
Section iii
Attachment 6
Attachment 7
Attachment 9
Attachment 1 5
Attachment 18
Attachment 19
Attachment 24
Critical Function Status Trees (CFSTs), Unit 2
22
Primary Communicator Log
1, 2
Primary Communicator Log (GE)
1, 2
Non-Emergency Notifications Reference
1 , 2
Environmental Protection Plan
1
4 Hr Report-Radiological Transportation Accident
1
24 Hr Report-Fitness For Duty (FFD) Program Events
1
UNUSUAL EVENT (Common Site)
1
EVENT CLASSIFICATION GUIDE TECHNICAL BASIS
Section 11 . 2
Section 11 . 7
Document
Section 3
Section 5
Section 8
Section 9
Section 16
Design Basis/Unanalyzed Condition
Security/Emergency Response Capabilities
COMMON SITE
Document Title
Emergency Organization
Emergency Classification System
Public Information
Emergency Facilities and Equipment
Radiological Emergency Response Training
1
1
Revision
8, 9
5
5
6
6, 7
.. {
ADMINISTRATIVE
EPIP 1006
EPIP 1007
EPIP 1008
EPIP 1013
EPIP 1016
EPIP 404
EPIP 602
SECURITY
EPIP 902
20
Emergency Equipment Inventory (Radiation Protection)
EOF/ENC Supply & Locker Inventory
Emergency Communications Drills
Emergency Response Personnel Telephone List
Test Procedures for EOF Backup Generator,
Vent System and HVAC Filter Replacement
Protective Action Recommendations
Radiological Dose Assessment
Accountability/Evacuation
18
17
14
36,37
3
8,9
19
14
EMERGENCY NEWS CENTER
NC.EP-EP.ZZ-0801 (Q)
NC. EP-EP .ZZ-006(0)
EPIP 801
EPIP 802
EPIP 803
EPIP 804
EPIP 805
EPIP 806
EPIP 807
Emergency News Center Operation
0
ENC Evacuation and Activation of Back-up ENC 0, 1
Void
10
Void
9
Void
8
Void
. 6
Void
8
Void
5
Emergency News Center Telephone Directory
9, 10 .
21
INSPECTION PROCEDURES USED
IP 61726:
IP 62707:
IP 71707:
Surveillance Observations
Maintenance Observations
Plant Operations
IP 92903:
Followup - Engineering
Opened
50-311197-14-03
Closed
50-272&311 /93-80-08
50-311196-81-01
50-311 /96-81-02
50-311196-81-03
50-311196-81-05
50-311196-81-06
50-311196-81-08
50-311196-81-09
50-311196-81-10
50-311196-81-11
50-311/96-81-12
50-311196-81-15
50-311/97-14-01
50-311/97-14-02
ITEMS OPENED, CLOSED, AND DISCUSSED
Improper restoration of a diesel generator following testing
Appendix R post-fire alternative shutdown
CC pump room ventilation deficiency prior to 1995
Current EOPs are inconsistent with single CC pump room
ventilation failure
Current EOPs allow CC pump to runout which is not supported
by pump design documentation
No documented basis for CC heat exchanger performance test
assumptions and analysis
Lack of acceptance criteria for CC room ventilation coolers
CC pump room ventilation damper position is not controlled
Battery surveillance test inadequacies
CC supply to pump seal water cooling heat exchangers
Inadequacy in TOL heater calculation and control
Inadequacy in setpoint calculations for radiation monitors and
surge tank level alarm
. PASS operation inconsistent with UFSAR
- Failure to enter Technical Specification Action Statement for
inoperable control radiation monitors
Failure to perform an adequate retest following main steam
system check valve maintenance
CBD
cc
CCHX
CR
CRCA
CREAS
LCO
LER
MMIS
NRC
PR
PSE&G
SR Os
TS
TSAS
22
LIST OF ACRONYMS USED
American Society of Mechanical Engineers
Configuration Basis Document
Component Cooling Water System
Component Cooling Heat Exchanger
Condition Report
Condition Report Corrective Action
Control Room Emergency Air Condition System
Control Room Supervisor
Design Change Package
Emergency Operating Procedures
Limiting Condition for Operation
Licensing Event Report
Loss of Coolant Accident
Loss of Power
Maintenance Management Information System
Motor Operated Valve
Nuclear Regulatory Commission
Post Accident Sampling System
Public Document Room
Performance Improvement Request
Public Service Electric & Gas
Refueling Water Storage Tank
Senior Reactor Operators
Time Concurrent Characteristics
Turbine-Driven Auxiliary Feedwater
Thermal Overload Relay
Technical Specification
Technical Specification Action Statement
Updated Final Safety Analysis Report
Unresolved Issue
- . -
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ATTACHMENT 2
The Power of Commitment
- ,
PUBLIC SERVICE ELECTRIC AND GAS
PREDECISIONAL ENFORCEMENT CONFERENCE
INSPECTION REPORT 50-272/311-97-09
JULY 8, 1997
E. C. SIMPSON
FIRE PROTECTION
REPAIR ISSUES
L
1983
1985
- PSE&G ASSUMES APPROVAL
1987
The Power of Commitment
CURRENT ST_ATUS
&:~~,,~.*.. PS~G
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- Unit 2 Modifications Installed
- Unit 1 Modifications Scheduled
- IN 92-18 Addressed
- Multiple Hot Shorts Addressed
- Procedure Streamlined
No Repairs Needed for Alternate Shutdown
I
4
The Power of Commitment ~
6
The Power of Commitment. ,
UNDERSTANDING THE ISSUE
- Safety Significance
- Generic Issues Throughout the Industry
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The Power of Commitment
NEXT STEPS
.. *. PS~G
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.: ..... * .. *. ' .... *:::--. *.
- ... *: **::*.'.*:: ... *: ..
..
.
- Re-analysis of Safe Shut down
- Identify required cables -
- Develop resolution -
- Implement resolution
8
The Power of Commitment
FIRE BARRIER MATERIALS
USED AT SALEM
_j?:/!fi"!h:.
PS~G
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~.
- Kaowool - About 500 Feet of Cable Trays -
accepted - resolution per 1OCFR50.109
- FS-195 - About 14,000 Feet of Cable Trays -
accepted - resolution per 1OCFR50.109
- E-50 - About 5000 Feet of Cable Trays
9
~
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The Power of Commitment .
TECHNICAL ISSUES
9 RHR Pump Flow During Recirculation
a Net Positive Sucti.on Head (NPSH) for RHR
Pumps
'J Switchover From Injection to Recirculation
- .. ~.
The Power of Commitment
RESIDUAL HEAT REMOVAL (RHR) ISSUES
July 8, 1997
David R. Powell
CURRENT STATUS
J RHR Pump Flows. Acceptable
J NPSH Requirements Met
~ Credit for Containment Pressure
Not Required
.
-
,
The Power of Commitn1ent .
.*. :**" PS~G
~ ECCS Pumps Not Stopped During Switchover
..,_. ___
...,... T.1 SMIN
COLD LEG RECIRCULATION
INJECTION
.,.__v .... o ...
L...,UM
..... E..__. lcm
SWJTCHOVER
....,.._v .... o...,L_UM_E_-t tG'N-lOW
..__ ___
"""'. CONTAJNMENT
SPRAY PUMPS
Sjl
CONTA!NMtNl
s~
SJ44
CS36
I
..,._ _______
_.._ __
_,COLD LEGS (41
CS36
HOT LEGS (1)
I
COLD LfGS (~)
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HOT LEGS (2)
I
COLD LEGS (2)
,
.,_... ___
......,.T .' S MIN
INJECTION
.,..__v_o ....
L.U_M_E...._..,. Lc)w
swrTCHOVER
...__v_o_t_UM_.E-. .... lOVV-lO~'w'
____ .,.
COLD LEG RECIRCULATION
ONE RHR PUMP FAILS
CONTAINMENT
CS36
SPRAY PUMPS
CS36
LOOP AROUND
FLOW---
to-----------__,, COLD LfGS (4~
.,____.,...._.,__-1CHARGING PUMPS
2
Sj2
HOT LEGS (2)
I
COLD LfGS (4,
HOT LEGS (2)
I
(ON'<AJNMcNT
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f
COLD LtGS {I)
SJ44
.,__ ___
... r r S f'"JN
INJECnON
,__v_ol_U_M_E --.LOW'
SWITCHOVER
HOT LEG RECIRCULATION
PRIOR TO 1994 CHANGES
,.__v_oL_U_M_E _..,.LOW'-lOW .-----..-1
CS36
CONTAINMENT
.._ __ _...
SPRAY PUMPS
CS36
I
.----------..,COLD LEGS {4)
t---'f"lll~--.CHARGING PUMPS
~2-... " ...... -
I I
HOT LE.GS (l)
COLD LEGS (4)
I
HOT LEGS (2)
CONTAJNMENT
Slff
I
COLD LEGS {2)
SJ44
HOT LEGS (2)
,. ...
...,._ ___
__..I* S MIN
lhJJECTION
.,__v_o_L_UM_i.= __ LO\\/
S\\VITCHOVfR
VOLUME
, r)'.'~-l0'N
HOT LEG RECIRCULATION
AFTER 1994 CHANGES
____
...,. CONTAiNMfNT
CS36
SPRAY PUMPS
CS36
1--------------.;- COLD LfGS (4l
cor...:1A1t*H1c.-.n
SL."'.'"'
Sj2
r.--....-~1~--tCHARGING PUMPS
2
SI PUMPS
< "I
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HEAD
. (FT.)
Salem Unit 2
RHR Pumps
Original Design Basis (19BO SER)
Available NPSH
(w/ Overpressure)
Available NPSH
(w/o Overpressure)
Required
34.9'
28.7
1
48::10
FLOW (GPM)
I
34.3':
I
I
28.1' :
Current Design Basis
(1994: No Rt-1R He..! Leg)
Maximum Estimated
(Pre*1994: w/ RHR Hot Leg)
Pump Test Data
Vend'Jr
Extension
'I
I
I
...... ~o*
/
,"
4980
5040 5185 5250
5500
- AVAILABLE NPSH GREATER THAN REQUIRED NPSH**
~-------------------- ---
(,_
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p
s
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SEMI-AUTOMATIC SWITCHOVER
rj
1/83
(POST-LOCA)
5/B9 I
1/87
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(l)
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'J/97
5197
I I
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SEMI-AUTOMATIC SWITCHOVER
Time
Training
Issue
Analysis
18 minutes (SER
13 minutes
Non conservative
Did not account for
May 1989
Amendment 69)
basis
Small Break LOCA
8.5 minutes
. and worse case
(submitted for Large
single failure
Break LOCA)
11.8 minutes
March 1996
11.8 minutes (actual
50.59 evaluation
Inappropriate credit
(credited 1.8 min
<11 minutes)
missed USQ
for downcomer flow
downcomer flow
w/o NRC approval
considering SB*
LOCA)
In compliance with
Appropriate reviews
May 1997
11.2 minutes
11.2 minutes (actual
Licensing and Design
performed
(removed credit for
<9 minutes)
Basis
downcomer flow)
EOPs changed
Corrections made to
Amendment 69
SEMI-AUTOMATIC SWITCHOVER
Safety Li1nit
Desired State
--
I
I
Current
Operator
Times
- Current
1996
Training Training
RWST Water Volume
,
'-----------------'
Downcomer Water Volun1e
Peak Clad Temperature Lin1its
--
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The Power of Commitment.
ACTIONS TAKEN
- Improvements to Corrective Action Program
- ~ Integrated Corrective Action Program
-~ Lower Threshold for ldentificatlon
~Improved Rep,ortability Review
3 SORC Expectations for Licensing Basis
,~ Design and Licensing Basis Review Project
7:;) Improvements to 50.59 Program
I~
., ;. '
i:.~ .
'
~
The Power of Commitment,
CONCLUSIONS
u Technical Issues Resolved Timely
-~ Regulatory Compliance - No Safety
Consequences
- 0) Issues Similar to Civil Penalty of October
1995 for Appendix B Criterion XVI
L'