ML18096A759
| ML18096A759 | |
| Person / Time | |
|---|---|
| Site: | Salem, Hope Creek  |
| Issue date: | 06/08/1992 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18096A758 | List: |
| References | |
| 50-272-92-04, 50-272-92-4, 50-311-92-04, 50-311-92-4, 50-354-92-04, 50-354-92-4, NUDOCS 9206150132 | |
| Download: ML18096A759 (74) | |
See also: IR 05000272/1992004
Text
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.
50-272/92-04
50-311/92-04
50-354/92-04
License Nos. DPR-70
Licensee:
Public Service Electric and Gas Company
P.O. Box 236
Hancocks Bridge, New Jersey 08038
Facilities:
Salem Nuclear Generating Station
Hope Creek Nuclear Generating Station
Dates:
March 22, 1992 - May 2, 1992
Inspectors:
T. P. Johnson, Senior Resident Inspector
S. M. Pindale, Resident Inspector
S. T. Barr, Resident Inspector
H. K. Lathrop, Resident Inspector
B. C. Westreich, Reactor
in r
,
J. C. Stone,
ing P
~ect
~
Approved:
Date
Inspection Summary
Inspection 50-272/92-04; 50-311/92-04; 50-354/92-04 on March 22, 1992 - May 2, 1992
Areas Inspected: Resident safety inspection of the following areas: operations, radiological
controls, maintenance and surveillance testing, emergency preparedness, security,
engineering/technical support, safety assessment/quality verification, and licensee event
reports, open item followup and Salem Unit 2 restart activities.
Results: The inspectors concluded that public health and safety was assured. An executive
summary follows .
9206150132 920608
ADOCK 05000272
.... G
.
.
i
EXECUTIVE SUMMARY
- Salem::lnspection Reports 50-272/92-04; 50-311/92-04
Hope Creek Inspection Report 50-354/92-04
. March 22, 1992 - May 2, 1992
OPERATIONS (Modules 60710, 71707, 71710, 71711, 92709, 93702) *
Salem: The Salem units were operated in a safe manner. Radiation monitoring system
actuations were reported, and licensee actions were appropriate. Unit 1 refueling outage
performance to date has been acceptable. Operator response and licensee followup to a Unit
2 reactor trip on low-low steam generator level were appropriate. The licensee appropriately
. responded to and reviewed a Unit 2 water hammer event. Design change package training
for *opefators**waS"thorough**and effective.- Walkdowns of the control room determined that
Unit 2* was ready for restart.. Unit 2 mode changes, reactor startup, and zero power physics
- testing were effectively- and-.conservatively .controlled. The licensee appropriately responded
to noted procedural- deficiencies identified during mode changes and startup.
Hope Creek: The uriit was operated in a safe manner. * Operator response to a reactor
- recirculation pump trip was good- and in accordance with procedures ..
RADIOLOGICAL CONTROLS (Modules 71707, 93702)
-Salem: Periodic inspector observation of station workers and Radiation Protection personnel
- implementation of radiological controls and protection program requirements found that the
licensee's program was acceptably implemented. Periodic tours of both containments
determined that radiation protection personnel were knowledgeable and professional in their
duties.
The-licensee~*s respons~-and evaluation when a worker was found contaminated with a
hotcparticle was reviewed=by a regional specialist and was determined to be a thorough and
sufficient analysis.
- -
Hop_~*Creek: Periodic inspector observation of station workers *and.Radiation Protection
personnel implementation of-radiological controls and protection program .requirements found
that the licensee's program was acceptably implemented .
11
MAINTENANCE/SURVEILLANCE (Modules 61701, 61705-61710, 61726, 62703,
70313, 72700) .
- ,_-Salem:'* Maintenance.activities associatecLwith the Unit 2 outage. and .. restart w.:ere well
planned and conducted. The Unit 2 containment integrated leak rate test was well controlled
and conservatively executed. The inspectors toured. the plant .and examined equipment,. and ..
concluded that Salem Unit 2 was ready for restart. Minor material and housekeeping
deficiencies were appropriately addressed by the licensee.
Hope Creek: * *A personnel error resulted in. an automatic start of a control room. emergency_.
- filtration unit. Improper tagging and isolation of a hydraulic control.unitis.unresolved ..
EMERGENCY PREPAREDNESS (Modules 71707, 93702)
An unresolved item regarding common plant emergency classification guides (action levels)
remains open, and is expanded to include shutdown plant events .
. SECURITY (Modules '71707, 93702)
Routine observation of protected area access and egress showed good control by the licensee.
Licensee response to a loss of the security computer was appropriate and conservative.
ENGINEERING/TECHNICAL SUPPORT. (Modules 37700, 37828, 71707, 71711)
Salem: Maintenance on the studs of a safety injection check valve was performed without
any formal engineering evaluation. Licensee activities associated with design change package
installation and post modification testing were appropriate. Unresolved items associated with
panel fire protection *systems and fire doors were closed. High auxiliary feedwater flow and
containment pressure/spray response unresolved items were.closed. The turbine-generator
modifications were appropriately implemented. PSE&G commitments relative to the turbine-
generator failure event for Unit 2 were completed. Reactor engineering support of restart,
criticality, and zero power physics testing was good. Issues associated with reactor
engineering procedures were appropriately addressed by the licensee. The licensee was
proactive in identifying a potential emergency diesel generator overload .condition. Licensee
short and long term corrective actions were appropriate.
Hope Creek: The inspector did not identify any noteworthy findings.
Ill
SAFETY ASSESSMENT/QUALITY VERIFICATION (Modules 40500, 71707, 90712,
90713, 92700, 92701, 92702, 94702)
- 'Salem: -Both line management and independent reviews concludedJhalSalet:IJ._Unit 2 was
ready for restart. The -inspector concluded that the licensee self-assessment activities were
thorough and effective. Installation of improper detectors in the R46 main steam line
radiation monitor is unresolved.
Hope Creek: Licensee followup to plant events was thorough and effective.
Common: Salem and Hope Creek management demonstrated a proactive and thorough
approach in reviewing* the conduct of non-licensed equipment operator plant tours. The
licensee's strike contingency plans were thorough and demonstrated proactive planning.
iv
TABLE OF CONTENTS
..... ,EXECUTIVE SUMMARY .................................... ~ . . n
TABLE OF CONTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
v
1.
SUMMARY OF OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
- 1.1
Salem Units 1 and 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
1.2
Hope Creek . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
_ l
2.
- - OPERATIONS . . . . . . . . . . .. . . .. * . . . . .. . . . .. . . . . . .. . . .. .. . .. . . . . . 1
2.1
Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
2.2
Inspection Findings and Significant Plant Events . . . . . . . . . . . . . . . .
1
2.2.1 Salem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
2.2.2 Hope Creek . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3
3.
RADIOLOGICAL CONTROLS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4
3~1 ** **-*Inspection-Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4
3. 2
Inspection Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4
3.2.1 Salem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4
3.2.2 Hope Creek . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5
4.
MAINTENANCE/SURVEILLANCE TESTING . . . . . . . . . . . . . . . . . . . .
5
4.1
Maintenance Inspection Activity . . . . . . . . . . . . . . . . . . . . . . . . . .
5
4.2
Surveillance Testing Inspection Activity . . . . . . . . . . . . . . . . . . . . .
6
4. 3
Inspection Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7
4.3.1 Salem . .. . .. . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . .
7
4.3.2 Hope Creek . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7
5.
- EMERGENCY PREPAREDNESS ................................ 8
5 .1
Inspection Activity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8
5.2
Emergency Plan .and Emergency Classification Guide (ECG) . . . . . . . .
8
6.
SECURITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9
6.1
Inspection Activity . . . ~ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9
6.2
Inspection Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9
7.
ENGINEERING/TECHNICAL SUPPORT. . . . . . . . . . . . . . . . . . . . . . . . 10
7.1
Salem . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . .. . .. . . . . . . . . 10
7.2
Hope .Creek . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. .. . . . . . 12
8.
SAFETY ASSESSMENT/QUALITY VERIFICATION . . . . . . . . . . . . . . . . 12
8.1
Common . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . 12
v
Table of Contents (Continued)
9.
LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL
- *-
-REPORTS, AND .. OPEN ITEM FOLLOWUP ......... *.. . . . . . . . . . . . .
13
10.
11.
9 .1
LERs and Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13
9.2
Open Items . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . 14
Salem Unit 2 Restart Preparations and Activities . . . . . . . . . . . . . . . . . . . .
15
10.1
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . .
15
10.2
Maintenance Activities and Design Change Package (DCP)
- Implementation . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . .. . . .. .
15
10.3
Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
10.4
System Lineups/Engineered Safety Features (ESP) Walkdowns . . . . . . . 20
10.5
Containment Integrated Leak Rate Testing (ILRT) . . . . . . . . . . . . . . . 20
10.6
Auxiliary Feedwater Flow and Containment Spray Response . . . . . . . . 21
10. 7
Self-Assessment Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
10. 8
Turbine-Generator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
10~9 .. Training *. _. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
10 .10 Restart Preparations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
10.11 Startup Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
10.12 Procedure Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
EXIT INTERVIEWS/MEETINGS ............................. 28
11.1
Resident Exit Meeting . *. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
11.2
Specialist Entrance and Exit Meetings . . . . . . . . . . . . . . . . . . . . . . 28
11. 3
Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
V1
DETAILS
1.
SUMMARY OF OPERATIONS
1.1
Salem Units 1and2
Unit 1 operated at or near full power until April 4, 1992, when the unit was manually
shutdown for its tenth refueling outage. At the end of the period, the unit was defueled.
Unit 2 continued in its sixth refueling outage; the unit was restarted on April 19, 1992, and
tripped from about 4% power on April 26, 1992. At the end of the period, unit 2 was in
Cold Shutdown to complete valve maintenance.
1.2
Hope Creek
The unit operated at full power during the period. Power reductions occurred due to turbine
valve testing and when the "B" reactor recirculation pump tripped automatically.
2.
OPERATIONS
2.1
Inspection Activities
The inspectors verified that the facilities were operated safely and in conformance with
regulatory requirements. Public Service Electric and Gas (PSE&G) Company management
control was evaluated by direct observation of activities, tours of the facilities, interviews and
discussions with personnel, independent verification of safety system status and Technical
Specification compliance, and review of facility records. The inspectors performed normal
and back-shift inspections, including deep back-shift (28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br />) inspections.
2.2
Inspection Findings and Significant Plant Events
2.2.1 Salem
A.
Unit 1 Shutdown For Refueling
Salem Unit 1 shutdown for its tenth refueling outage on April 4, 1992. The unit entered
Refueling (Mode 6) and completed core offload at 5: 12 p.m. on April 19, 1992.
The inspector observed portions of the outage planning activities, coordination meetings,
mode changes, refueling activities, maintenance, and design change package implementation.
The inspector concluded that the outage was progressing satisfactorily. Refueling activities
were noted as being conservative and consistent with procedures.
2
B.
Salem Unit 2 Reactor Trip
On April 26, 1992 at 2:20 a.m., the Salem Unit 2 reactor tripped from approximately 4%
power. Operators were transferring steam generator feedwater from auxiliary feed water
(AFW) to main feedwater control, when a low-low level condition in the No. 24 steam
generator caused a reactor trip signal. Systems responded normally to the trip. The licensee
made an ENS call and notified the resident at home.
Prior to the No. 24 steam generator low-low level condition, the No. 23 steam generator had
been overfed while in manual control to its high-high water level setpoint. This caused the
only main feed pump operating to trip. Both AFW pumps were running, and the licensee re-
initiated flow to the steam generators. A few minutes later, the licensee restarted the main
feedwater pump and placed it into service. While transferring feed to the main feedwater
pump, the reactor tripped on No. 24 low-low steam generator level.
The licensee entered the reactor trip procedures, Emergency Operating Procedure (EOP)-
TRIP-1 and 2, which required initiation of a manual steamline isolation because a high AFW
flow rate resulted in lowering primary system average temperature. Other plant response
included receiving an automatic AFW pump start signal (although they were already running)
prior to the trip. The licensee cooled down the plant and entered Mode 5 (Cold Shutdown)
while investigating the cause of the trip and performing repairs. A Significant Event
Response Team (SERT) was formed by the licensee to determine causes and corrective
actions for the reactor trip.
The licensee's investigation found that a number of level transients had occurred while
attempting to transfer to the main feed pumps. The suspected cause was due to either
mechanical binding of the feed water control valves or slow response of the steam generator
water level controllers. The licensee confirmed both causes during troubleshooting activities
and repaired the components accordingly.
The inspectors reviewed the operations logs and control room recorders, verified BOP
implementation, interviewed onshift operators, and reviewed and discussed the event with the
SERT team and plant management. The AD-16 procedure, Post Reactor Trip Review, was
also reviewed. Licensee actions were considered appropriate and effective in responding to
the event and determining appropriate causes and corrective actions.
C.
Unit 2 Water Hammer Event
On April 28, 1992, at 5:31 p.m., a water hammer event occurred on the No. 22 residual heat
removal (RHR) loop. -Operators were restoring that loop to service after repairs to the
22SJ43 check valve, which required a freeze seal. The No. 21 RHR loop was inservice,
providing decay heat removal with the reactor coolant system (RCS) at 160 degrees F and
325 psig in Mode 5 (Cold Shutdown). The unit had proceeded to Cold Shutdown after the
April 26, 1992 reactor trip to repair the check valve. Operators in the containment described
3
.. '-the.water hammer as "minor". It occurred when the No. 21 RHR flow to the Nos. 22 and
- ' *24 safety injection-to-RCS cold legs common supply valve was opened from the control
- room. Ail apparent inadequate fill*an.d Vent of the No. 22 RHR:loop *and Nos. 22 and 24
RCS safety injection lines was the cause for the water hammer. As a result of the water
hammer, an RHR system relief valve lifted and failed to reseat. The relief valve lift pressure
was set at 600 psig as per design; however, the maximum *RCS* and RHR.pressures noted
were about 350 psig. The RCS flow through the* relief valve caused the pressurizer level to
decrease from 21 % to 13% (cold calibration). Letdown isolated and normal charging
(makeup) restored pressurizer water,level. *The.No. 21. RHR pump remained in service
during the event and RCS temperature was maintained. Operators entered abnormal
operating procedures and isolated the relief valve by securing the No. 22 RHR loop.
The licensee reviewed reportability for RCS leaks, loss of shutdown cooling (decay heat
removal) and engineered safety features actuations and concluded that the event was not
reportable.
The licensee initiated a Significant Event Response Team (SERT) to review the 22SJ43 freeze
- .*,*' .. seal-removal.and fill-*and vent procedures; cause .of the water .hammer; 22SJ48 relief valve .~ ;*
operation; any*potential piping and supports*damage; and operator actions. Licensee
engineering and inservice inspection personnel performed piping, weld and support
. walkdowns, non-destructive examination, and stress calculations. The licensee did not
identify any problems or damage to the affected RHR, safety .'injection and reactor coolant
systems. The licensee concluded that poor communications between operators performing. the
fill and vent evolution and operators in the control-room resulted in the event.
- The inspector became aware of the.event at the April 29, 1992 morning meeting. The
inspector reviewed logs, emergency classification guides (ECG), abnormal operating
procedures, control room chart recorder traces, computer printouts, and the SERT report.
- ., **The',:irtspector*discussed thee event with the on shift- operators; licensee engineering and
management personnel, and the SERT members. The inspector also performed a walkdown
of portions of the RHR system and observed maintenance of 22SJ48 relief valve, and did not
have any significant observations. The inspector concluded that per the licensee's ECG, the
event was not reportable. However, issues associated with reportability per the licensee's
emergency plan are discussed in Section 5 .2 of this report.
2.2.2 Hope Creek
A.
Reactor Recirculation Pump Trip
At 2:38 p.m .. on April 21, 1992,*the "B" reactor recirculation pump tripped with the unit at.
- 100% power. The licensed operators responded to*the transient, and entered the applicable ..
abnormal and integrated operating procedures. The unit was stabilized at about 60% power.
Reactor engineering* personnel responded to the control room and control .rods were inserted
4
- ' . to .further reduce power. Reactor water level initially increased . from .the normal level ( + 35
- ... .,inches) to .the high'level*setpoint*( +42-inches). The reactor feedwater.level control system
- * ** responded correctly and .. retilmed reactor water level to normal. ""Plant response was normal ..
The licensee's investigation determined that the"B" recirculating motor generator (MG) set -
electrically tripped (motor feeder breaker tripped) due to a blown fuse. caused .by a failed
maintenance personnel also responded to the control room and to the local panel to assess
damage and to provide* assistance to the on-shift operators.
The licensee entered Technical Specification (TS) 3.4.1 for single loop operation and
appropriately implemented those requirements. The unit was maintained at about 50% power
while the failed PT was replaced. The idle recirculation loop was returned to service on
April 23, 1992.
- * * * ;::: * -;./' * l:!Jpoit'}hearing .. the -:page,,-system announcement,-; the inspector -responded to the control room.
The inspector observed licensed operator actions, and procedure *and TS implementation. The
- * --inspector.also noted *prompt,response by reactor and system engineering, and maintenance
personnel. Operations management personnel also responded to the control room. The
inspector concluded that operator response* was appropriate, shift supervisor command and .
control of the transient was good, and station *response was timely and effective.
3.
RADIOWGICAL CONTROLS
3.1
Inspection Activities
PSE&G's conformance with the radiological protection program was verified on a periodic
basis.
3.2
Inspection Findings
3.2.1 Salem
A.
Containment Tours
The inspectors performed tours of both the Unit 1 and Unit 2 containments during the period.
Items checked included radiation work permit implementation, area postings, radiation
protection (RP) technician coverage of jobs in progress, control of exclusion areas, and
control point access~* The inspector concluded that RP personnel were :knowledgeable and
professional .
5
B.
Hot Particle on Salem Worker at Guardhouse
On April 20, 1992, the licensee informed the inspector of a worker who was detected at the
security guardhouse with a hot particle on the back of his head. The individual alarmed the
portable monitor and was detained by Security personnel until radiation protection personnel
could respond. The inspector reviewed the preliminary radiological occurrence report and
concluded that the licensee's actions were appropriate. Further followup was performed by a
NRC regional specialist (see NRC Inspection 50-272 and 311/92-06).
3.2.2 Hope Creek
The inspectors did not identify any noteworthy findings.
4.
MAINTENANCE/SURVEILLANCE TESTING
4.1
Maintenance Inspection Activity
The inspectors observed selected maintenance activities on safety-related equipment to
ascertain that these activities were conducted in accordance with approved procedures,
Technical Specifications, and appropriate industrial codes and standards.
Portions of the following activities were observed by the inspector:
Work Order(WO) or Design
Change Package (PCP)
Description
Salem 2
Salem 2
Salem 1
Salem 2
Salem 2
Salem 1
Hope Creek
Hope Creek
Various WOs
DCP lSC-2267
DCP (various)
Various WOs
DCP lEC-3056 through
3059
Safeguards Equipment Cabinet (SEC)
timing modification
22BF22 and 22SJ43 check valve repairs
SEC electrical chassis upgrade
Main turbine - generator modifications
Feedwater regulating valve troubleshooting
Control Room Human Factors Upgrades
Pressure cleaning of the
11A
11 emergency
diesel generator
Replacement of reactor building lightning
.-
. . ,Hope Creek
Hope Creek
Various WOs
6
Replacement of reactor building lightning
mast
Motor-Generator set potential transformer
replacements
The maintenance *activities inspected were effective with respect to meeting the safety
objectives of the maintenance program.
4.2
Surveillance Testing Inspection Activity
The inspectors performed detailed technical procedure reviews, witnessed in-progress
surveillance testing, and reviewed completed surveillance packages. The inspectors verified
that the surveillance tests were performed in accordance with Technical Specifications,
-
approved procedures, and NRC regulations.
The following surveillance tests were reviewed, with portions witnessed by the inspector:
Unit
Salem 2
Salem 2
Salem 2
Salem 2
Salem 2
Salem 2
Salem 2
Salem 1
Procedure No.
SP(0)4.0.5 .P-AF-23
SP(0)4. 7.1.5
- * S2.RE-ST.ZZ-0002(Q)
2IC-8.1.002
Various
S2. OP-ST. TRB-0001 (Q)
S2. OP-ST. TRB-0002(Q)
PI/S-SJ-4
Hope Creek *Various
Hope Creek OP-ST.KJ-001
- Steam Driven* Auxiliary Feed water Pump
Main Steam Isolation Valve Emergency
Close Response Time Test
Shutdown Margin Calculation
Rod Position Indication Calibration
Initial Criticality and Zero Power Physics
Tests
Main Turbine Valve Testing
Turbine Protection System Full Functional
Test
Safety Injection Pump Flow Test
Single. Loop. Procedures
Monthly Surveillance.Run of the "A"
7
.. -* The surveillance* testing activities inspected were effective with respect to meeting the safety *
.objectives of the surveillance testing program .
. 4.3
Inspection Findings
4.3.1 Salem
See Sections 10.2, 10.3, 10.5 and 10.8 of this report.
4.3.2 Hope Creek
A.
Engineered Safety Feature (ESF) Actuation During Surveillance Testing
On April 15, 1992, during the performance of a monthly functional surveillance test of the
process radiation monitoring system, a technician de-energized the wrong power supply,
resulting~in*'an.:.automatic,:start of the "A" control room emergency filtration (CREF) unit.
After determining that the start signal was spurious, operators returned the control room
ventilation configuration to normal. An ENS call* was made, and the licensee informed the
inspector. Instrument and control (I&C) technicians had been performing a functional test of
the "C" channel of the reactor building and refuel floor exhaust radiation monitor 1SP-RY-
4856C per.procedure IC-FT.SP-031. When directed by the procedure to place the 4856C
power toggle switch in the "off' position, the technician mistakenly performed this step on
1SP-RY-4858C, a channer of the control room ventilation radiation monitoring system, which
initiated a control room ventilation isolation and start of the "A" CREF unit. Licensee
corrective actions included counselling of the technicians involved.
The inspector reviewed this incident, concluding that a lack of attention to detail was an
apparent root cause. While the two panels were relatively close together (about six feet
"apartYon the same wall; .. both were clearly labelled. The surveillance procedure was clearly
written and specific in its instructions. The inspector concluded that the licensee
appropriately followed up on the event and that the safety significance of this event was
minimal.
B~
Improper Isolation of a Control Rod Drive (CRD) Hydraulic Control Unit (HCU)
On March 24, 1992, during maintenance on HCU No. 46-39 related to repairs to directional
control valve No. 123, a large volume of high pressure water sprayed from the valve body
during disassembly. Prompt operator action stopped the discharge. No personnel
contamination; or injury occurred. Areas of theJ02 foot evaluation of the reactor building
were immediately roped off and decontamination was completed in two days. A radiological
occurrence report (ROR 92-22) and incident report (IR 92-072) were issued to document the
event, subsequent investigation and corrective actions. Additionally"station quality assurance
- (SQA) was requested to perform an independent assessment of the event and the reasons for
its occurrence.
8
.The inspector*reviewed this.event with .operations and management personnel. While all the-.
. licensee's investigations were not yet completed when the report period ended, the inspector
noted that a *number of apparent programmatic breakdowns contributed* to the event. The
- . inspector* concluded that the.nuclear safety significance of the incident was small; however,
the potential for personnel injury and/or equipment damage was very significant. Areas of .:
concern included:
The work request (No. 920320291) did not indicate that a system breach would be
needed, and implied that only the solenoid portion of the valves was*-to be worked .. *
The licensee followed a vendor recommendation to maintain cooling water flow to an
isolated HCU if at all possible. However, this fact was not adequately communicated
to on-coming operations personnel or to the maintenance supervisor. The tagging
request was modified in order to provide cooling water flow, but this was not noted
on the work request to alert personnel to the change.
The work control supervisor and job foreman had both signed off that the tagging was
- adequate. As noted above, this was not the case.
This item is unresolved (URI 354/92-04-01) pending completion of licensee followup and
subsequent NRC review.
5.
5.1
Inspection Activity
The inspector reviewed PSE&G's conformance with 10CFR50.47 regarding implementation
of the emergency plan and procedures. In* addition, licensee event notifications and reporting
- ., requirements per lOCFR50. 72 and *'73-were reviewed. , *.
5.2
Emergency Plan and Emergency Classification Guide (ECG)
(Open) Unresolved Item (272 and 311/92-01-01; 354/92-01-02); ECGs for Salem and Hope
Creek. The inspector reviewed reportability of a Salem Unit 2 water hammer and reactor
coolant system (RCS) leak into the residual heat removal (RHR) system on April 28, 1992
(Section 2.2.1.C). The licensee concluded the.event not to be reportable.
For RCS leaks, NUREG 0654 requires declaration*of an Unusual Event when RCS leak rate
exceeds the Technical Specification *(TS) limits and an Alert when the RCS leak rate exceeds
50 gpm. Salem *and Hope Creek ECG Nos. lb.and la, respectively, require an Unusual
- ' -Event when the TS limit for RCS leak rate (mode/operational condition ,dependent) is
exceeded and a plant shutdown is required. **Salem ECG le requires an.Alert declaration if
9
.. *" the .RCS leak rate is greater than 50 gpm. and .. one charging pump cannot maintain pressurizer
level. Hope Creek ECG No. lb requires an Alert declaration ifthe.,RCS leak rate is greater
than 50 gpm as indicated'by a'TS surveillance.
For the Salem Unit 2 specific event,- the inspector concluded that the*RCS leak rate ECGs are
mode/operational condition dependent. Further, the inspector concluded that the licensee
correctly applied their specific requirements to conclude that this event was. neither an Alert*
nor an Unusual Event. However, this Salem and Hope Creek unresolved item will be.
expanded to include a further review of ECGs relative to shutdown plant events.
6.
SECURITY
6.1
Inspection Activity
PSE&G's conformance with the security program was verified on a periodic basis, including
- * .. ,: ._., * - *:";:tfie,adequacy:.ofastaffing;~.entry*control, alarm stations, and physical boundaries.
6.2
Inspection Findings
A.
Loss of Security Computer
An apparent lightning strike at about 3:00 a.m. on April 10, 1992, resulted in a loss of.the
security computer; Eyewitness reports noted a lightning strike near the Salem units.
Operators felt the strike in the Salem control room. Security alarms sounded and the*security
computer failed. Hope Creek also had indications of a lightning strike as they lost several
- outside indicators (e.g., cooling tower basin blowdown monitor).
The licensee initiated .compensatory measures for vital and protected areas. An initial
., .. * .,,_ * *- :**assessment-:* by;'the-licensee: determined *this-.security .event to be reportable. An ENS call was
made at 3:21 a.m. However, subsequent licensee review determined this event to be
recordable and not reportable, and the ENS call was retracted. The licensee made repairs to
the computer system and secured the compensatory posts.
The inspector was informed of the event at home. On the morning of April 10, 1992, the
inspector verified licensee actions, checked selected compensatory posts and discussed the
event with security and plant management personnel. The inspector concluded that licensee_
actions were conservative and appropriate.
B.
Correspondence
- * The inspector*reviewed the following letters and documents:
Safeguards Events Reports (1/31 - 3/31/92), dated April 27, 1992
Protected Area Revision - Centralized Warehouse Project dated, April 27, 1992
10
Security Plan, Revision 2, dated April 27, 1992
- *The inspectors also discussed these.Items with security management-personneL The
inspectors had no further questions at this time.
7.
ENGINEERING/TECHNICAL SUPPORT
7.1
Salem
A.
Safety Injection Check Valve Bonnet Leakage (22SJ43)
During the week of April 6, 1992, while Salem Unit 2 was increasing primary pressure and
temperature in preparation for plant startup, a body to bonnet leak of approximately 1 drop
per minute was observed by the licensee on valve 22SJ43. This is a 6 inch check valve in
the safety injection line, upstream of the No. 24 Accumulator and intermediate head safety
- * >'***f~iiijection::line:tie.-<One check valve;22SJ56, -is located downstream of the leaking valve
before connection with the Reactor Coolant System (RCS) system. At the time, the RCS
- system *was at normal .operating temperature (NOT -: 541 F) and normal operating pressure
(NOP - 2235 psig).
The licensee iriitially hlbricilted the 12 studs holding *the bonnet to the flange. This was
acco~plished by removing one stud at a time~ lubricating and retightening the stud. It was
thought that this may tighten down the leaking flange and stop the leakage. Shortly after this
was accomplished, the leakage rate decreased to 1 drop per 8 minutes. System Engineering
personnel thought *this reduced leakage rate may have been due to the seating of 22SJ56, the
downstream. checkvalve,. after. equalizing temperature at NOT. The licensee subsequently
replaced the 12 bonnet studs with- new stainless* steel studs which would not be susceptible to
boric acid corrosion. After replacement of the studs with stainless steel, the leakage stopped.
Inspector review of the licensee. actions .after the initial stud lubrication, but prior to the
stainless* steel- stud**replacement; revealed that no engineering evaluation had been conducted
to determine if the removal of one bonnet stud at a time on the leaking check valve flange
while at NOP ancLNOT, .. woulctresultin: the loss of safety margin for the piping pressure
boundary. The licensee indicated that this was a common maintenance practice and had not
considered performing an* evaluation. At the inspectors request, an evaluation was
performed. The inspector indicated to the licensee that while performing maintenance which
could potentially- result- in* the loss of.safety' margin of piping integrity isolated by only a
check valve from the Reactor Coolant System, it would be prudent to ensure, .by .. engineering
evaluation, that safety margins were not r~uced.
- The licensee's evaluation showed that the increase in stress in the studs adjacent to the
removed stud would result in a total stress of approximately 60 percent of the allowable yield
stress.- Using the ASME Unified Pressure Vessel Code, it was determined that the minimum
11
bolting requirement was 10 studs. During stud lubrication and replacement, there were 11
--studs present. Although this is greater than the minimum number. of, studs required, it was a
- ,much smaller*margin .than,the:licensee-had anticipated.
- * The inspector concluded that the licensee needed to be more sensitive to specific plant
. *
conditions and specific equipment when performing* maintenance. * This* issue was discussed *
with the licensee, and the inspector emphasized that, based on current plant. conditions, a
similar evaluation should be considered for each job to be accomplished .. The licensee agreed
with the inspector's concerns.
After the April 26, 1992, reactor trip, 22SJ43 was again observed to be slightly leaking.
While in Mode 5 following the trip, action was taken to isolate the valve by use of a freeze
seal, and the valve was repaired prior to startup. The inspector had no further questions at
this time .
. 8 *.... Potential Emergency.Diesel Generator (EDG) Overload Condition at Salem
PSE&G initiated a review at Hope Creek and Salem upon learning of the Calvert Cliffs
- design review finding of March 24, 1992, that under some conditions, the sequential loading *
of emergency safety equipment could cause overloading and damage to the EDGs. The
licensee identified a condition at Salem concerning the potential for an overload of the "A"
and "C" EDGs at Salem Units I and 2. PSE&G concluded that the problem did not exist.at
Hope Creek.
A safety injection concurrent with a loss of offsite power could result in the simultaneous
start of a service.water (SW) pump-and a containment spray (CS) pump. The sequential
loading and automatic start of equipment is performed by the safeguards equipment cabinet
(SEC). This concurrent start could overload the IA and IC EDGs on Unit I, and the 2A and
2C EDGs.on Unit-2 ... The CS. .. pump start permissive is.armed.at 9 seconds into the sequence
and will start if a high-high containment pressure exists. The sequence remains "armed" for 5
seconds and if the high-high signal is received during that time the CS pumps will start. This
allows the CS pump start to occur up to I 4 seconds ( + 3 seconds for SEC response time)
into the sequence. The SW pumps start at I3 seconds into the sequence. A 3 to 4 second
window therefore exists for this potential overload problem.
The licensee implemented the following short term corrective actions: the Unit I (defueled
and in Mode .6) CS pumps were verified to be tagged out of service and were not required to ..
be operable. Unit 2 was at rated temperature/pressure (Mode 3) in preparation for unit
restart. The licensee tagged out the Unit 2 Nos. 2I and 25 SW pump's control power.
These SW pumps are;powered from the 2A and 2C EDGs, respectively. This condition did
not place Unit .2* in a Technical Specification Action Statement because there were four
operable SW pumps including two pumps per bay (header), and,at least.one.pump per vital
bus.
12
',For .longer term Corrective actions, the licensee implemented design change package (DCP) ..
. , 2EC-3149 for the SEC time sequence (i.e. reducing the 5 second arming signal). The DCP *
modified the eXisting* Safeguards Equipment Cabinet (SEC) for the*":A" and "C" vital buses*
- to decrease the 5 second window in which the CS pumps can start to 1 second. This
prevented the overlap of CS and SW starting times .. The modification used a spare timer to
open a normally shut contact at 10 seconds and extinguish the CS pump start permissive until
- the end of the, starting sequence. Another spare timer was used to close a normally open
contact at the end of the sequence to allow the CS pump permissive.
The inspector attended meetings regarding options for the modification of the SEC and
reviewed the 10CFR50.59 safety evaluation. Concerns were identified by the inspector
regarding the evaluation's lack of discussion of the original basis for the 5 second window,
and the adequacy of the 1 second window for completing the intended safety functions. These
concerns were relayed to the licensee, and the 50.59 review was subsequently modified to
address them.
The inspector reviewed the completed DCP, discussed the package with licensee engineers,
- and observed modification. testing. Based on these reviews, it was determined. that.the actions
- taken by the licensee were effective and timely.
7 .2
Hope Creek
The inspectors did not identify any noteworthy findings.
8.
SAFETY ASSESSMENT/QUALITY VERIFICATION
8.1
Common
A/:,; :'-**Licensee:Assessment of Non-licensed Operator Tours
The licensee conducted independent reviews of historical non-licensed equipment operator
(EO) tours at both the Hope Creek and Salem stations. The purpose of these reviews was to
verify that the information obtained by the EOs tours was accurately obtained and recorded.
At both stations, the reviews preliminarily identified that the EOs were properly performing
and documenting their assigned tours and duties. However, some minor discrepancies were
identified, and were properly being addressed at the end of this inspection period.
Hope Creek and Salem management informed the inspectors of the scope,of the investigations
and the preliminary .results. The inspectors concluded that the investigations were ~proactive,
thorough and constituted a representative sample size. Additionally, management
subsequently held briefings with EQs,to delineate management's.expectations relative to EO
tours. The inspector had no further questions.
13
.B.
Licensee 'Plans For Strikes
The inspector reviewed PSE&G's plans for coping with potential strikes. This was
- performed per NRC inspection procedure 92709. The licensee's "Operations Contingency
Manual For Nuclear Generating Stations," dated January 1992, describes the licensee's
Nuclear Department strike contingency plan. The document includes a base document and
attachments for Salem, Hope Creek, Nuclear Services and a pre-strike checklist.
- 'The inspector verified that the licensee adequately addressed minimum shift manning as
required by the facility Technical Specifications and administrative procedures. Discussions
were held with various General Managers at Salem, Hope Creek and Nuclear Services. The
inspector also verified that appropriate plans were in place for security, emergency
preparedness, and other support type functions. The inspector concluded that the licensee's
strike contingency plan was appropriate and demonstrated proactive planning by the licensee.
'9-~* .:Ji,;, ** '.;i~LICENSEE .EVENT REPORTS (LER),. PERIODIC AND SPECIAL REPORTS,
AND OPEN ITEM FOLWWUP
9 .1
LERs and Reports
PSE&G submitted the following licensee event reports, and special and periodic reports,
which were reviewed for accuracy and evaluation adequacy ..
Salem and Hope Creek Monthly Operating Reports for March and April, 1992
Salem Unit 2 Special Reports 92-2 and 92-4 (fire barrier) and 92-3 (2A emergency
diesel generator failures)
Salem and Hope Creek 1991 Annual Radiological Environmental Operating Report,
dated April 27, 1992
No significant observations were made.
Salem LERs
Unit 1
LER 92-02 (See Section 10.6.B)
LER 92-03, Supplement 1; and LER 92-07 concerned radiation monitoring system
(RMS) actuations due to equipment failure and/or equipment design. The licensee's
corrective actions, both short and long term, include RMS .upgrades. The LER's were
acceptable .
14
- LER 92-04 concerned improper radiation detectors installed in the main steam line
radiation monitors (1R46A,C, and D; and 2R46,A,B,C and.E) .. The R46 detectors
- provide indication of a primary to secondary leak. -The installed detector had a range
of 1.0 mr/hr to 100 R/hr. The requirement was a detector with a range of 0.1 mr/hr
to 10 R/hr. The licensee discovered this during I&C Calibrations on Unit 2 on
January 28, 1992. The R46 radiation monitors were installed in 1983 and purchased
as safety related class. lE per Regulatory Guide 1.97. Apparently, the detectors were
incorrectly identified in the spare parts control system.
The licensee is continuing their investigation for root cause(s). The R46 channels
provide an alarm/indication function only. The steam generator blowdown (Rl9) and
condenser air ejector (Rl5) radiation monitors provide additional monitoring for
primary to secondary leakage. No primary to secondary leakage occurred during the
period of improper detector installation ( 1983-1992). The licensee intends to submit a
supplemental LER. This issue is considered unresolved until completion of licensee
- , * * *-- ' .. review*,and,subsequent NRG followup .. .(URI..50-272/92-04-02).
Unit 2
LER 92-04 concerned a radiation monitoring system actuation due to improper vital
bus overcurrent relay installation. This event was reviewed in NRC Inspection
311/92-03. This LER was acceptable.
LER 92-05 concerned an engineered safety features actuation due to a procedure *
inadequacy. This event was reviewed in NRC Inspection 311/92-03. This LER was
acceptable.
LER 92-06 (See Section 10.2.D)
Hope Creek
LER 92-04 discussed an inadvertent emergency core cooling system initiation signal
and subsequent injection to the reactor vessel due to personnel error on March 8,
1992. This event was reviewed in NRC Inspection 50-354/92-02, Sections 2.2.2.A
and 5.2.B. Corrective actions appeared adequate to prevent a similar occurrence
during the completion of the remainder of the design change scheduled in the fourth
refueling outage. This LER was well written.
9.2
Open Items
The following previous inspection items were followed up during this inspection and are
tabulated below for cross reference purposes .
...
Salem
272&311/92-01-01
272&311/91-28-02
272&311/92-01-06
272&311/92-01-03
272&311/90-80-01
272/90-27-01
311/87-29-03
311/91-05-01
Hope Creek
354/92-01-02
Report Section
5.2
10.6.A
10.6.A
10.6.B
10.1.F
10.2.F
10.2.F
10.2.C
5.2
15
Open
Open
Open
Closed
Closed
Closed
Closed
Closed
Open
10.
Salem Unit 2 Restart Preparations and Activities
10.1
Introduction
Salem Unit 2 was shutdown for its sixth refueling outage after the turbine failure event of
November 9, 1991. (See NRC Inspection 50-311/91-81). The licensee performed fuel
offload and reload activities, maintenance and modification work, system and component
testing, and repaired the turbine generator.
The inspectors performed an inspection to ascertain Unit 2's readiness for restart.
10.2
Maintenance Activities and Design Change Package (DCP) Implementation
A.
Service Water Piping Replacement
The licensee continued modifications to the nuclear service water piping at Unit 2. This
included replacing the piping with 6 % molybdenum austenitic stainless steel. Piping replaced
included the Nos. 21 and 22 room cooler headers, the mechanical penetration rooms in the
auxiliary building, the containment piping below elevation 102 foot level, and the No. 2
service water bay. The inspector reviewed the DCPs and related installation in NRC
Inspection 50-272 and 311/92-01. Recent inspection activities included verification of piping
installation, hydrostatic testing, system restoration and testing .. The inspector did not have
any significant findings .
16
B.
- Safeguards Equipment Cabinet (SEC)
The SEC starts and stops safety related equipment due to accident and/or loss of power
signals from the solid state protection system. There are three SECs per unit. Over the last
several years, theJicensee has experienced multiple equipment actuations and unit shutdowns
(CEUs) to increase SEC reliability.* Additional changes were implemented to facilitate
periodic SEC functional testing.
The inspector reviewed the DCP executive summary and safety evaluation. The inspector
periodically observed DCP installation and post-installation testing. Additionally, the
inspector reviewed the associated training material (lesson plans and student handouts) to
support the DCP implementation. The inspector did not have any significant findings.
C.
Undervoltage (UV) Relays
The licensee developed a modification (DCP No. 2EC-3084) to replace the nine Unit 2
~1.6% UV relays that monitor the three 4kv vital buses. There are three 4kv vital buses,
each which use three 91. 6 % UV relays. The existing UV relays have become obsolete and
had experienced problems in maintaining the required tolerance at the relay trip setpoints.
The DCP also relocated the relays to address human factors deficiencies and to facilitate
periodic relay testing.
The inspector reviewed portions of the DCP documentation, including the associated safety
evaluation. Additionally, the inspector witnessed portions of the UV relay installation and
testing, and conducted a *post-installation walkdown of the modification. The inspector
concluded that the modification was effectively engineered and installed. Unresolved Item
311/91-05-01 is closed.
D.
Radiation Monitoring System (RMS) Upgrades
The licensee implemented short term corrective actions relative to the Unit 2 RMS. This
included installation of an uninterruptible power supply (UPS) for the Nos. 21, 22, and 23
RM panels (DCP 2SC-2229); and a modification to replace the following RMS channels
2R1A - control room
2Rl 1A/12A/12B - containment atmosphere
2R19A/B/C/D - steam generator blowdown
2R41A/B/C - plant ventilation
17
- ' ::The*.Jnspector*reViewed the DCPs including the .safety evaluation, executive summary, and
.. associated checklists. The inspector verified in-field installations and testing activities.
- Subsequent to these DCPs, three Unit 2 actuations occurred as follows*(LER 92-06):
Date/Time
March 29, 1992/2:40 p.m.
. March 31, 1992/5:45 p.m.
April 1, 1992/4:23 p.m.
Monitor
2R11A
2R41C
2Rl1A
These all occurred due to monitor downscale abnormalities including a "paper tear alarm" and
a low flow alarm. This was caused by a chart recorder paper malfunction and a momentary
low system ventilation flow. The associated containment isolations occurred as required.
These conditions were associated with the new RMS*electronics. The licensee removed these
'-~*;;,;2.:~Lct:)isolatio1i 1 functions::as:.;they0were determined'..tO be unnecessary ... The alarm remained
functional.
The inspector reviewed these events and the associated LER, and discussed them with
licensee engineering and management personnel. The inspector concluded that the LER was
acceptable.
E.
Control Room
Design change Nos. 2EC3056 through 2EC3059 implemented several Unit 2 control room
- * modifications to address Human :.Engineering* Discrepancies identified during the Salem
Detailed Control Room* Design Review. This final phase of the modification (Phase Ill)
replaced the overhead annunciator (OHA) system, extended the operator control consoles,
- ' inodified' :and'Teconfigured,the * operator.desk 1 area;* and, modified the control room lighting and
pushbutton covers to improve visibility and reduce glare. Additionally, the audible responses
of the annunciator systems were changed, and additional silence, acknowledge, and reset
pushbuttons were added to improve human factors deficiencies. The changes to the OHA
system were the most significant changes, which relocated several OHAs and added several
new OHAs. Also, the OHA windows were all relabelled and renumbered, and were
rearranged so that associated OHAs were grouped by system.
The inspector observed major portions of the control room modification. The inspector also
reviewed the DCP safety evaluation. *Personnel involved *with the workimplementation *were *
- . found to be knowledgeable regarding the .assigned tasks. . The licensee modified the simulator
prior to the outage*completion and trained the operators on the control room modification.
- ,*:- ... ~.~-*The inspector also *reviewed the associated *alarm response procedures,. which. were recently
issued. The inspector found the procedures to be of good quality and consistent with the new
18
<<.OH.A' window layout, demonstrating good _coordination between the procedure writing and
.DCP implementation personnel. The inspector concluded that this DCP. was conservatively
implemented.
F.
10 CFR 50 Appendix R and Penetration Seals
During the Unit 2 refueling outage PSE&G continued to effect changes to the plant to bring it
into further compliance with 10CFR50 Appendix R requirements. Two of these changes
were controlled by*ocPs 2EC-3091 and 2SC-2271. DCP 2EC-3091 involved cutting the
- control cable for* the pressurizer relief valve 2PR7 and installing a new cable and two new
junction boxes. The reason for this change was that this safe shutdown cable could not be
individually fire wrapped due to the way it was configured in the cable tray and needed to be
separated to be properly wrapped. DCP 2SC-2271 involved the installation of a dry pipe
sprinkler system, supplemented by early warning smoke detection for Panel 335, which
contains redundant channels of pressurizer pressure and level instrumentation. The sprinkler
- << ',.'*;.-- 'S:9stem\\was*installed,to.,compensate for the lack-of physical separation of these redundant
channels as required by 10CFR50 Appendix R, Section III.G.2.
Inspector activities included review of the executive summaries and safety evaluations for
both DCPs and inspection of the installation of the DCPs in all areas outside containment. In
addition, the licensee documented closure of the panel 335 DCP in a letter to NRR dated
March 26, 1992. Unresolved items 272/90-27-01 and 311/87-29-03 are considered closed.
The inspector also reviewed the status of fire doors relative to unresolved item 50-272 .and
311190-80-01. The issue* concerned the closure ability of the station fire doors and associated
interim compensatory measures. The licensee responded to these concerns in a letter dated
June 8, 1990. Corrective actions included confirming fire watch patrols, repairing damaged
doors, re-emphasizing to site personnel theimportance of ensuring fire door closure upon
o. 'USe/'3.nd completing ,a survey to review ventilation-caused ;fire door closure problems. The
inspector verified corrective actions, and toured the facility to check on fire door status. The
inspector concluded that corrective actions taken were adequate. The longer term ventilation
balance issue continues to be pursued by licensee personnel. Based on this, the unresolved it
is considered closed.
G.
Reactor Vessel Level Instrumentation System (RVLIS)
Upgrading of the RVLIS was accomplished by design change package (DCP) 2EC-3037.
The old system's electronics were subject to frequent failures and spare parts were often
unavailable. *In addition to providing improved reliability,. the new system (a Westinghouse
RVLIS-8086 unit) .also provided refueling level indication as well as reactor vessel level.
- ** * RVLIS is required for accident monitoring .. It.consists of.two separate.and redundant trains
with remote display in the Unit 2 control room.
19
- *1The inspector's review of the implementation of this DCP included:
- Review of the design change package and associated 10CFR50~59.safety evaluation.
The safety evaluation was well-written, technically accurate and sufficiently detailed to
support the safety determinations.
- A physiCal walkdown of system components outside of*the reactor containment.* The
only discrepancy noted was a lack of component identification, which had already
been identified by the licensee and corrective action was being taken ..
A demonstration of the operation of the remote display panel with its various functions
in the control room by licensee operations personnel.
A review of the familiarization training given to operators and instrument and control
technicians prior to completing the installation of the upgraded RVLIS. The training
.. ,:.<*<:' *.:stmaterials>(e:g. ;Jesson plans) appeared adequate.* Several operators indicated the
training could have been more rigorous, however, they were knowledgeable about the
- system and how it differed from the old systei;n.
A *review of the system operating and surveillance procedures indicated that they .
appeared appropriately upgraded for the new RVLIS .
The inspector concluded that upgrade to RVLIS had been implemented in accordance with the
DCP and that affected licensee personnel were knowledgeable about system operation, testing
and Technical Specification related requirements.
H.
Main Steam Isolation Valves (MSIV)
.;*DCP2EC-~3073*.was'-iniplementedby PSE&G at.Unit2 during this outage and made the same
changes to the Unit 2 MSIVs as made on the Unit 1 MSIVs during that unit's last refueling
outage. These changes included MSIV hydraulic actuator refurbishment and modification,
MSIV internal modifications, MSIV vent valve actuator replacement, and MSIV limit switch
replacement. The purposes of these modifications were to reduce condensate build-up in the
MSIV actuator and thereby improve valve closure performance and to improve the qualified
life of the valve position limit switches.
The inspector verified proper implementation of this DCP through review of the executive
summary and safety evaluation of each package of the DCP, through observation.of the work
performed on MSIV components, and through inspections of the MSIV.,rooms after all ..
modification work had been completed. No deficiencies were identified with the
- implementation of this DCP.
20
10.3
Surveillance Testing
A significant amount of surveillance testing activities were observed by the inspectors both
during the Unit 2 outage and during unit startup activities. Among the tests observed were
several complex surveillances involving coordination of multiple station groups and
disciplines. Listings of the surveillance tests observed can be found in NRC Inspection 50-
272 and 311/92-03 and in Section 4.2 of this report. The inspectors concluded that the
surveillance tests were conducted safely and in accordance with station procedures.
10.4
System Lineups/Engineered Safety Features (ESF) Walk.downs
During the weeks of March 23 and 31, 1992, in preparation for Unit 2 startup following the
refueling outage, walkdowns of the high pressure safety injection (charging) and service water
systems were conducted.
A number of minor discrepancies were identified with equipment and valve position labeling
which were identified to plant personnel. Material condition, housekeeping, and lighting
problems were also identified and were in the process of being addressed by licensee
personnel. System lineups were reviewed in the control room and in the plant, and were seen
to be in the appropriate positions for plant startup as indicated by the Tagging Request and
Information System (TRIS). The inspector concluded that these systems were appropriately
aligned for their intended safety functions.
10.5
Containment Integrated Leak Rate Testing (ILRT)
During the week of March 23, 1992 the inspector performed a review of the Type A
Integrated Leak Rate Test (ILRT) for Salem Unit 2. Review of the test procedure and
performance of the test revealed no deficiencies. The procedure was adequately prepared and
addressed the appropriate prerequisites, precautions and directions for the conduct of testing.
The pressurization and leak rate determination portions of the testing were observed by the
inspector and were conducted in a conservative and controlled manner. Licensee personnel
involved were knowledgeable in the test requirements, performance, precautions and
acceptance criteria. The testing was observed in the control room, the Data Acquisition
Center, and the Testing Control Station. Licensee activities were also observed during
containment inspections while increasing containment pressure, at test pressure, and while in
the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> leak rate determination period. Personnel were competent and had a thorough
knowledge of the test procedure, data obtained, expected results and plant systems inspected.
The test equipment complied with procedural requirements and was appropriately calibrated.
The inspector concluded that the test procedure and the conduct of the test were well
controlled, and executed in a conservative and acceptable manner.
21
10.6
Auxiliary Feedwater Flow and Containment Spray Response
A.
Unresolved Items 50-272 and 311/91-28-02; and 50-272 and 311/92-01-03
The auxiliary feedwater (AFW) flow was found by the licensee to exceed the AFW flow
assumed in the steam line break (SLB) accident analysis. This condition could result in
containment exceeding its design pressure and a potential loss of shutdown margins due to the
overcooling of the primary system. The licensee, with assistance from Westinghouse,
completed their evaluation of this condition. Their evaluation concluded that Salem Unit 1
had sufficient shutdown margin (SDM) to assure that calculated peak containment pressure
remained below the containment design pressure for all SLB events.
For Salem Unit 2, Cycles 5 and 6, the licensee concluded that the calculated peak
containment-pressure remained below the containment design pressure for all SLB events.
However, in order to reach that conclusion, the reactivity associated with the most reactive
control rod was assumed to be available for shutdown. This was based on the fact that
neither stuck rods nor problems with rods were noted during Cycles 5 and 6. Although a
specific calculation for the most limiting case was not performed, the licensee believes that
calculated peak containment pressure for the limiting SLB with the minimum SDM (1. 846 %
delta-klk) would have been less than 10% over the containment design pressure (47 psig).
This spM includes the most reactive rod being stuck out.
The corrective action* taken or proposed for the upcoming Salem Unit 1, Cycle 11 and Salem
Unit 2,- Cycfo 7 included:
AdminiStrativelyincreased the SDM requirements for Modes 1 through 4 to > 1.85%
delta~k/k urrent-Technical Specifications (TS) 3.1.1.1 SDM requirement in > 1.6%
delta; k/k. (This was imposed on Salem Unit 1 for the remainder of Cycle 10, has
been imposed-_ on Salem Unit 2 for cycle~1~ and will be imposed on Salem Unit I for
Cycle IL)
Administratively increased the SDM requirement for Mode 5 to .z. 1.25 % delta k/k.
Current TS 3.1.1.2 SDM requirement is .L 1.0% delta k/k.
-Admiilistratively lowered the containment high-high pressure setpoint to < 15 psig.
The current TS setpoint is < 23.5 psig.
Administratively lowered the instrument response time for containment spray initiation
- to 33 seconds. Current TS response time is 45 seconds.
22
With these changes in place, the maximum calculated containment pressure for Salem Unit 2,
Cycle 7, is 45 .5 psig for the limiting SLB accident.
The permanent solution currently being considered by the licensee is to change the
mechanical trim on the AFW flow control valves. This would limit the flow to the steam
generators. If approved, these modifications would be implemented in 1993 during the
eleventh refueling outage at Salem Unit 1 and seventh refueling outage at Salem Unit 2. The.
licensee is also considering requesting a change to the TS to permanently change the SDM to
> 1.85% delta k/k and the high-high containment pressure setpoint to < 15 psig.
The licensee expects to issue the supplement to Licensee Event Report (LER) 91-36. The
licensee, with Westinghouse assistance, has determined that this issue is not reportable under
10 CFR Part 21 requirements.
The previous unresolved items are currently being reviewed by the NRC.
The licensee
intends to submit permanent TS changes relative to SDM, containment pressure setpoint, and
time response. This was committed to in a letter dated April 22, 1992.
B.
(Closed) Unresolved Item 50-272 and 311/92-01-06
The licensee submitted LER 92-02, dated February 18, 1992, that detailed the results of the
increase in fluid travel time for containment spray system. The original calculation assumed
a 28 second fluid travel time. The recalculated travel time was found to be 47 seconds. The
Technical Specifications (TS) instrument response time for containment spray flow was 45
seconds. The Updated Final Safety Analysis Report assumed a total delay time (instrument
response plus fluid travel time) of 59 seconds. The new calculation results in exceeding the
UFSAR 59 second limitation. A review of instrument response time tests from the last four
refueling outages was used to establish the bounding value for instrument response. This was
determined to be less than 33 seconds. The resulting total delay time value was found to be
80 seconds (instrument response and fluid travel time).
The containment response was re-evaluated using the 80 second total delay time. This
evaluation showed that containment design pressure of 47 psig would not be exceeded. For
loss-of-coolant accidents (LOCAs), the peak containment pressure was calculated to be 45.73,
an increase of 0. 2 psig.
For steam line break (SLB) analysis at Salem Unit 1, Cycle 10, the calculated peak pressure
is 45.93 psig. For Salem Unit 2, Cycle 7, the calculated peak containment pressure is 45.5
psig.
The licensee plans to permanently change the containment spray instrument response time
from 45 seconds to 33 seconds. This will yield a total response time of 80 seconds. Until
the change is approved, the licensee has administratively limited the instrument response time
23
at Salem Unit 1 and 2 to 33 seconds. The licensee committed to this in a letter dated April
22, 1992. Based on review of this event, the UFSAR will be revised by the licensee as
appropriate. This unresolved item is considered closed.
10. 7
Self-Assessment Activities
A.
Line Management
The inspector reviewed licensee line management's self-assessment activities relative to Unit
2 restart readiness. The inspector held discussions with the Plant Manager, Outage Manager
and selected department heads. Line management routinely reviewed restart readiness at the
periodic outage meetings, at the daily accountability meetings, at Station Operations Review
Committee (SORC) meetings, and at other special meetings. Three of the department heads
(Operators, Maintenance and Technical) provided shift coverage during the week prior to
startup. Their function was to provide onshift management presence and activity
coordination.
Startup items reviewed by the licensee included open work orders, design changes, open
issues and commitments, temporary modifications, performance indicators, operator
readiness, surveillance and post-modification testing, system lineups, post trip review and
SERT recommendations from the November 1991 turbine generator failure, and Unit 1
refueling outage impact. The licensee concluded that Unit 2 was ready for startup.
The inspector concluded that line management self assessment activities were thorough and
effectively assessed Unit 2 readiness for restart.
B.
Independent Review Committees
The inspector met with representatives from the Salem onsite Quality Assurance (QA)
organization to assess Unit 2 restart readiness activities. The inspector noted that QA
completed several activities, including final walkdowns of modification field work,
containment walkdown, a review of the Deferred Outage Work List, inservice leakage
examinations, verification of Deficiency .Report tracking and closure, and a review of restart
commitments. QA also provided shift coverage in the control room to monitor unit startup
activities. The inspector reviewed portions of the QA activities and found them to be
thorough and comprehensive, and concluded that appropriate oversight and review was
provided by QA to assure that the unit was prepared for startup from the extended outage.
10.8
Turbine-Generator
In light of the November 9, 1991, turbine-generator overspeed event at Unit 2 and the
findings of the subsequent NRC Augmented Inspection Team (AIT), the inspectors reviewed
the repairs and modifications made to the Unit 2 turbine and generator during this outage,
with special attention paid to those items the licensee had committed to complete prior to unit
24
restart. PSE&G responded to the findings of the AIT, as documented in NRC Inspection
Report 50-311191-81, in a letter dated February 10, 1992, which listed a number of
corrective actions that had been taken or were planned by the licensee.
As a means of assessing PSE&G's performance in implementing the above mentioned repairs
and their compliance with the above mentioned commitments, the resident staff inspected
selected repair and modification work activities, discussed the accomplished and planned
work with members of the Salem Operations, Technical, and Maintenance Departments, and
reviewed changes made in plant procedures and operating practices. The repair work
monitored by the inspectors included the rework of the high pressure turbine, the replacement
of the three low pressure turbines, repair to the No. 22 low pressure turbine casing, the
replacement of the generator stator and rotor, the rework of the generator exciter, and the
repairs made to the_main condenser. Modifications to the turbine and its control systems that*
were inspected included: . the installation of filters on the auto-stop trip system (AST) oil
lines; the replacement of the ET-20 and OPC-20-1 and 2 solenoids; the lowering of the 63-3
AST pressure switch trip. setpoint; the installation of local turbine speed indication at the
Front Standard and a recorder for turbine speed in the control room; the installation of a
back-up AST-20~2 trip solenoid that is not isolated during overspeed testing; and the
installation of two new overspeed trips for turbine protection (an electrical overspeed which
will trip the turbrne at 110% of rated speed, and a reverse power trip that will prevent the
generator output breakers from prematurely opening). The inspectors reviewed the following
newly revised procedures to verify identified deficiencies had been resolved:
IOP:.3~ '~Hor-Standby to Minimum Load"
- OP ill-1.3.7, '_'Turbine Automatic Trip Mechanisms Operational Tests" (S2.0P-
PT.TRB:..:0001)
- -
NC~NA-AP~zz:.oo30(Q), "Commitment Management"
sc~-oM-AP:zz,..OOOl(Q), "Outage Scheduling:
2JC:.6. t~004~ -"Turbine EH Control System Overspeed Protection Channel Calibration"
2IC-18. l.006, "SSPS Reactor Trip Breaker & Permissive P4 Test Prior to S/U - Train
A"
2IC-1-8.l-.007~~,llSSPS Train B Reactor Trip Breaker 7 Permissive P4 Test Prior to
S/U" -
S2.0P-'ST.T-RB-0001 and 2, "Main Turbine Valve Test"
S2.0P-PT.nIB-0002, "Turbine Startup Solenoid Functional Test"
The inspectors' -review of lieensee actions determined that all startup commitments had been
satisfied and that the corrective actions taken by PSE&G, both in the equipment and
procedure areas, were aggressive in their attempt to prevent the recurrence of any similar
events in the future~- _ The inspectors also observed initial turbine roll activities. The
inspectors also noted that PSE&G performed very well relative to repairing the turbine-
generator ancf preparing it for service.
25
,,,.10.9
Training
. The inspector reviewed the operator training performed relative. to. design. changes and
modifications. During the third segment of licensed operator requalification (January 13 -
"March 20, 1992), formal lessons regarding RVLIS, Service Water, RMS *upgrades, and
control room upgrades were given. During the simulator .portion of .requalification training,
- operators were trained on the enhancements made to the control room. This included
modifications to the annunciator system, control board arrangements, operator desk changes
and procedure upgrades. The inspector discussed the training with operators and* training
personnel. The inspector determined that training appeared to be effective based on the
observed operator skill levels noted during control room observations.
10.10 Restart Preparations
A.
Mode Changes
The licensee proceeded from Mode 6 (Refueling) to Mode 2 (Startup) using the Integrated
- *Operating Procedures (IOPs).
The inspector observed IOP-2, "Cold Shutdown To Hot Standby," IOP-3, "Hot Standby to
Minimum Load" implementation, including the prerequisites and the check-off sheets. The
inspector concluded that.these mode changes were acceptable with some noted procedure
issues (see Section 10.12).
B.
Plant Tours
The inspectors performed tours of Salem Unit 2 facility including: containment, auxiliary
and turbine buildings, service water and circulating water structures, and other accessible
- **areas.-*The inspector*checked for material condition of-system, equipment components, and
structures; and housekeeping and cleanliness. The following items were noted:
deficiency tags remaining on recently refurbished systems,
plant areas still contaminated,
housekeeping and material condition deficiencies, and
a few labelling problems.
The licensee also performed plant tours and identified similar type issues. Licensee and
inspector identified items were appropriately addressed and corrected by the licensee. The
inspector concluded that plant and equipment were ready to support restart .
...
26
, ,.c. ... *Control Room Walkdown
The inspectors performed control room walkdowns prior to each*-mode change and
periodically during the startup. Items reviewed included instrumentation, the night order
book, the jumper log, temporary modifications, tagouts, logs; Technical Specification (TS)
. Action Statements, procedures and staffing .. Operators were.interviewed and, ;safety systems.
were verified to operable. TS implementation was acceptable and a few minor control room
- instrumentation issues were either corrected or determined to not affect system operability or
functionality.
D.
Containment Tour
The inspectors toured the Unit 2 containment on April 16, 1992, with the unit in Hot Standby
(Mode 3) at normal operating pressure and temperature. Areas checked included all levels
outside the biological shield, inside the biological shield, the seal table room, and the letdown
- * , .. **
- regenetativedleatt.exchange:r.:room .. The inspector checked for equipment material condition,
housekeeping, leaks, radiological controls (see Section 3.2.1.A), and overall containment
- integrity-and condition. Overall material and housekeeping conditions were good. A.few
damp areas were due to service water piping condensation. A few minor deficiencies were
noted and corrected by the licensee.
10.11 Startup Testing
A.
Criticality and Zero Power Physics Testing
The inspector observed the licensee's approach to achieving. Mode 2 (Startup) and making .the
Unit 2 reactor critical. Per S2.RE-RA.ZZ-0003(Q) and S2.RE-IO-ZZ-000l(Q) the operating
shift had an additional, dedicated senior reactor operator (SRO) assigned to provide direct
- oversight'of the*reactor startup.' AseparaterSRO was* assigned for the remainder of Unit 2
activities. The reactor achieved criticality at 9:50 p.m. on April 19, 1992. The inspector
also observed portions of the following zero power physics tests:
S2.RE-ST.ZZ-0010(Q), "Isothermal Temperature Coefficient"
S2.RE-RA.ZZ-0005(Q), "Boron Endpoint Determination"
S2.RE-RA.ZZ-0008(Q), "Rod Swap Reactivity Measurement Test"
S2.RE-RA.ZZ-0006(Q), "Rod Worth Measurements"
S2.RE-RA:ZZ-0009(Q), "Prediction of Post Refueling Startup NI Currents"
S2.RE-ST.ZZ-0002(Q), "Shutdown Margin Calculation"
The inspector concluded that the control room activities during the approach to criticality and
subsequent to zero power physics testing the reactor engineers were.deliberate and well-
controlled. Additionally, good performance by the reactor operators was noted, and a high
level of SRO and management oversight was evident.
27
.. B.
Power AScension
- *..-
'"The inspectors*witnessed the power*ascension into Mode 1 per IOP-3, :Hot Standby to
'Minimum Load." At 18% power the inspector observed the initial main turbine roll on April
fan. The turbine was shutdown to investigate. Repairs were_ made and the_reactor
.
subsequently tripped during auxiliary feedwater shift to main feedwater (see Section 2.2.1.B).
10.12 Procedure Issues
During the Unit 2 reactor heatup and startup activities, the inspectors reviewed the
performance of procedures being used. These procedures included:
Reactor Plant Heatup, IOP-2;
Reactor Plant Startup, IOP-3 ;
- ;. * -- * '>,.9,:',_.i'M0\\Reactor~Rhysics Testing,- multiple procedures; and.
. .. ___ . .
Main Steam Isolation Valve Emergency Close Time Response Testing, SP(O) 4.7.1.5.
A number deficiencies were identified. during these reviews. _ These included concerns with
prerequisite signoffs, procedure sequencing, category designation, methods of making
changes, numbering designation, and editorial errors. Examples of these deficiencies are
given below.
Some reactor physics procedures which required movement of control rods or other means of
adding positive reactivity were classified as Category II procedures. A Category Il procedure
requires it *be available at the-work site-but does not require step by step performance. A - ....
Category I requires the procedure be followed in a step by step manner and. should be used
for activities which could cause a reactor trip, emergency safeguards actuation, or loss of
- 1*shutdown',cooling: :**The-0inspector concluded*.that the.addition of positive reactivity could
result in these events.
The inspectors found that the requirements for categorizing procedures as Category I, IT or
m, were found only in the Artificial Island Work Standards Handbook. This was an
uncontrolled booklet which provided information that either augments or was not found in
Nuclear Department procedures. This Handbook however, was not a formal procedure and
was not used to replace established Management Directives, *Procedures, Policies or Manuals
of the Nuclear Department. In discussions with the licensee, it. was not clear why -these
requirements were not part of a controlled Nuclear Department Administrative procedure .
... 'In the plant heatup procedure, IOP-2, some prerequisite signoffs.were not completed prior to
starting the procedure. Although administrative procedures allow-prerequisite signoffs to be
-.. signed at the point in the*procedure to which-they apply, there was.no"indication that these
prerequisite signoffs could be delayed.
28
- .. -'** ';Rod-Swap procedure S2.RE-RA.ZZ-0008(Q) required a reference bank of control rods to be
withdrawn while one other bank was inserted in steps to determine rod worth. The procedure
required execution of steps *53;1 ..:*'5:3.14, but 5.3.1 - 5.3.22 was required to complete the
sequence for each bank. Isothermal Temperature Coefficient procedure S2.RE-RA.ZZ-
0005(Q) likewise contained some unclear instructions. In addition, that procedure referenced
the wrong Technical specification sections.
These concerns were identified to the licensee and corrective actions were taken to address
them. All the procedures identified had not undergone a Procedure Upgrade Program (PUP)
review. -The licensee *was making interim changes and indicated that the PUP. process should
also correct these deficiencies. The inspectors determined that no problems were identified
which affected proper procedure performance and expected results.
11.
EXIT INTERVIEWS/MEETINGS
The inspectors met with* Mr. :C, Vondra and* Mr. J. Hagan and other PSE&G personnel
periodically and at the end of the inspection report period to summarize the scope and
findings of their inspection activities.
Based on NRC Region I review and discussions* with PSE&G, -it was determined that this
report does not contain information subject to 10 CFR 2 restrictions.
11.2
Specialist Entrance and Exit Meetings
Inspection
Date(s)
Subject
Report No.
4/6-4/21/92
Surveillance
354/92-03
3/31-4/16/92
Radiological
272;311 ;354/92-05
Controls
4/28-5/1/92
Radiological
272&311/92-06
Controls
11.3
Management Meetings
Reporting
Inspector
Drysdale
Nimitz
Nimitz
A~
Systematic Assessment* of Licensee Performance (SALP) Management Meeting
The SALP Management Meeting was held *onsite on April 15, J992." .Meeting attendance and
the final SALP report will be issued under separate correspondence.
29
- B.
- Enforcement Conference
,,_-_,An Enforcemerif.Coriference*to discuss-on-site storage of ammonia'relative for control room
habitability was held April 9, 1992. Attachment 1 is the meeting .attendance and Attachment
2 is the licensee's handout.
C.
Training Meeting
The inspector attended a* meeting between NRC Region -I Division of Reactor -Safety and
PSE&G Training* Department and Salem/Hope Creek Operations management. Results of the
1991 initial licensed operator examinations and SALP comments were discussed .
ATTACHMENT 1
ENFORCEMENT CONFERENCE
LIST OF ATTENDEES
APRIL 9, 1992
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
S. E. Miltenberger, Vice President and Chief Nuclear Officer
R. T. Brown, Principal Engineer - Licensing and Regulation
A. Pasricha, Supervisor, Chemistry & Process
R. F. Yewdall, Senior Engineer
R. J. Dolan, Principal Engineer
D. J. Jagt, Manager - Nuclear Engineering Design
J. V. Bailey, Nuclear Engineering Sciences Manager
- ""'F~*"X:"'Tliomson.,..-'Manager**..:~Licensing and Regulation *.
C. B. Rokes, Licensing Engineering
T:' * L' Cellmer, Radiation* Protection/Chemistry Manager
R. J. Hovey, Operations Manager - Hope Creek
NUCLEAR REGULATORY COMMISSION
S. F Shankman, Acting Deputy Director; Division of Reactor Projects (DRP), Region I (RI)
A. R. Blough, Chief, Reactor .Projects Branch 2, DRP, RI
J. R. White, Section Chief;* Reactor *Projects Section 2A, DRP, RI
C. L. Miller, Director, Project Directorate 2, Office of Nuclear Regulation (NRR)
J. H. Joyner, Chief, Facilities Radiological Safety & Safeguards Branch, RI
- T. P. "Johnson; .. Seriior Resident Inspector, Salem & Hope Creek, DRP, RI
J. C. Stone, Senior Project Manager, NRR
R. L. Nimitz, Senior Radiation Specialist, RI
D. J. Holody, Enforcement Officer, RI
K. D. Smith, Regional Counsel, RI
OTHER
J. T. Robb, Director, Joint Owner Affairs - PECo
G. J. Beck, *Manager, Licensing Section - PECo
R. W. Oakes, Atlantic Electric Salem Site Representative
T. Kolesnik, Nuclear Engineer~ BNE
K. M. Buddenbohn, Project Engineer, DPL
- ' *
- *
ATTACHMENT 2
Ps~G
Public Service
~
Electric and Gas
Company
NRC
ENFORCEMENT
CONFERENCE
SALEM GENERATING STATION
APRIL 9. 1992
-
~
MEETING OBJECTIVES
- REVIEW REGULATORY CRITERIA DURING LICENSING
EVOLUTION OF ARTIFICIAL ISLAND UNITS
- PROVIDE DISCUSSION OF EVALUATIONS PERFORMED FOR
- DEMONSTRATE NO SAFETY SIGNIFICANCE
- PROVIDE A STATUS OF PSE&G'S CORRECTIVE ACTIONS
- PROVIDE RESULTS OF PSE&G'S ASSESSMENT OF
ACTIONS TAKEN IN RESPONSE TO NRC ORDER DATED
JULY 10, 1981
- DEMONSTRATE THAT ESCALATED ENFORCEMENT IS NOT
WARRANTED
- REINFORCE NRC CONFIDENCE IN PSE&G'S ABILITY TO
ADDRESS DESIGN ISSUES AND PROVIDE CONTINUED
SAFE OPERATION OF SALEM AND HOPE CREEK
GENERATING STATIONS
"
- .
NRC ENFORCEMENT CONFERENCE
AGENDA
INTRODUCTION/MEETING OBJECTIVES
NRC FINDINGS I
SUMMARY OF DEFICIENCY
LICENSING BASIS
ROOT CAUSE
~NGINEERING EVALUATION
SAFETY SIGNIFICANCE
CORRECTIVE ACTION
ENGINEERING IMPROVEMENTS
REVIEW OF NRC ORDER ACTION ITEMS
PSE&G 'S ASSESSMENT OF
POTENTIAL VIOLATION
CONCLUSIONS
S. E. Miltenberger
R. T. Brown
R. T. Brown
J. V. Bailey
J. V. Bailey
J. V. Bailey
J. V. Bailey
D. J. Jagt
F. X. Thomson, JR.
F. X. Thomson, JR.
S. E. Miltenberger
NRC FINDINGS
- POTENTIAL VIOLATION
- FAILURE TO RECOGNIZE ANO EVALUATE THE
IMPACT ON CONTROL ROOM HABITABILITY FROM
THE ON-SITE STORAGE OF AMMONIUM
HYDROXIDE AT SALEM IN ACCORDANCE WITH
NRC ORDER DATED JULY 10, 1981 REGARDING
NUREG-0737 TMI ACTION ITEM III.D.3.4
- ADDITIONAL CONCERNS
- ADEQUACY OF OTHER ACTIONS TAKEN RELATIVE
TO THE COMMITMENTS CONFIRMED BY NRC
ORDER DATED JULY 10, 1981 FOR SALEM
UNIT 1
--34
SUMMARY OF DEFICIENCY
- REQUIRED BY LICENSING-BASES TO MAINTAIN CONTROL
ROOM IN HABITABLE CONDITION UNDER ACCIDENT
CONDITI_DNS
- IDENTIFY AND ANALYZE HAZARDOUS CHEMICALS
STORED ONSITE
-USE R.G~ 1.78 FOR CRITERIA TO ASSURE CONTROL
ROOM TOXICITY LIMITS ARE NOT EXCEEDED
-DEFICIENCY IDENTIFIED RELATES TO IMPROPER
EVALUATION OF ONSITE STORAGE OF AMMONIUM
HYDROXIDE
LICEN*SING BASIS
- IDENTIFY KEY MILESTONES IN EVOLUTION OF
DESIGN AND LICENSING
- DISCUSS REGULATORY CRITERIA AND BACKGROUND
FOR ENGINEERING ASSESSMENTS MADE TO SUPPORT
LICENSING
LICENSING HISTORICAL OVERVIEW
6~
3m
5~
7~
AG 1. 78
ISSUED
.
SALEM UN IT 1
8/76
-
IL ISSlEl_j
TMI 2
NRC
EVENT
AI
ORDER
SALEM UNIT 2
4/80
5/81
*
~------]
t_FSAR SlllMITTED
IL ISIUll _j
~
POMER
HOPE CREEK
4/86
Biii
L
FSAA
Ol. _j
1l Jl 1l
1~ 1l
Js
1~
7~ 1l
Jo
el1
el
J3
el4 el Js J
LICENSING BASIS
SALEM UNIT 1
AUG
I 71 - SALEM FSAR SUBMITTED
- FORMAT AND CONTENT CONSISTENT WITH AEC 1966
GUIDE
- NO- SPECIFIC REQUIREMENT TO IDENTIFY TOXIC
HAZARDS-
- DESIGN CONSISTENT WITH AEC PROPOSED GENERAL
DESIGN CRITERIA -- (GDC) OF 1967
- CONTROL ROOM HABITABILITY DUE TO TOXIC
HAZARDS NOT SPECIFICALLY ADDRESSED IN 1967
GDC
JUNE '74 - REGULATORY-GUIDANCE ISSUED (R.G. 1.78)
- PROVIDED GUIDANCE ON ASSESSING CONTROL ROOM
HABITABILITY- DURING-HAZARDOUS CHEMICAL RELEASE
- AMMONIUM HYDROXIDE NOT LISTED ON TABLE C-1 OR
DOT REFERENCE
- TWO-MINUTE TOXIC LIMIT AMBIQUITY
- NO REQUIREMENT TO IMPLEMENT
HISTORICAL OVERVIEW
REGULATORY GUIDE 1.78JUNE1974
ASSUMPTIONS FOR EVALUATING THE HABITABILITY OF A
C,,.mia1I
NUCLEAR POWER PLANT CONTROL ROOM DURING A
POSTULATED HAZARDOUS CHEMICAL RELEASE
The lili r:I chemlcaa given In Table C-1 la net aJl~nduaive
but lndlcet* the ctiemlc:als molt ccmmaily encountered. See
alao 'G.llde for Emergency SetVicee for Hezardoua Miterials
(1973) *Spille, Flree, Evacuation Are&e" copiee of Wiich may be
ot::taJned rrom the u. s DepErtment or Transportation, omce or
Hazardous mstetials, Waahlngton, D.C.
TABLE C-1
SOME HAZARDOUS CHEMICALS POTENTIALLY INVOLVED IN ACCIDENTAL
RELEASES FROM STATIONARY AND MOBILE SOURCESa
Toxicin Limil'
Toxicity Limir
p,,,,,C
mg/m3d
Chemic*/
ppm
Acetaldehyde
200
360
Ethylene oxide
200
Acetone
2000
4800
2
Acrylonitrile
40
70
Formaldehyde
10
mg/m:J
180
4
12
Anhydrous ammonia
100
70
asphyxiant
Aniline
10
38
Hydrogen cyanide
20
Benzene
50
160
Hydrogen sulfide
500
Butadiene
0.1%e
2200
Methanol
400
Butenes
asphyxiant
Nitrogen (compressed
Carbon d1ox1de
1.0%e
1840
or liQuifiedl
Carbon monoxide
0.1%e
1100
Sodium oxide
-
15
45
Sulfur dioxide
5
Ethyl chloride
10000
26000
Sulfuric acid
-
Ethyl ether
800
2400
Vinyl chloride
1000
Ethylene dichloride
100
400
Xylene
400
a This list is not all-inclusive but indicates the hazardous chemicals most commonly encountered.
b Adapted from Sax's "Dangerous Properties of Industrial Materials."
22
750
520
asphyxiant
2
26
2
2600
1740
c Parts of vapor or gas per million parts of air by volume at 25°C and 760 torr (standard temperature and pressure!.
d Approximate milligrams of particulate per cubic meter of air, at standard temperature and pressure, based on
listed ppm values.
e Percent by volume.
tp2EC2-55
LICENSING BASIS
SALEM UNIT 1
APR '76 FSAR UPDATED
- REFLECT AMMONIUM HYDROXIDE FOR FEEDWATER PH
CONTROL
- NO ASSESSMENT REQUIRED RELATIVE TO CONTROL
ROOM HABITABILITY
AUG '76 SALEM UNIT 1 OPERATING LICENSE ISSUED
- CONTROL ROOM DESIGN MET 10CFR50 APPENDIX A
LICENSING BASIS
SALEM UNIT 1
DEC '80 - PSE&G TMI ACTION STATUS PROVIDED
- LETTER PROVIDED STATUS OF TMI ACTIONS FOR
SALEM UNITS
- CONTROL ROOM HABITABILITY (III. D. 3. 4)
REVIEW WAS COMPLETE AND CONCLUDED NO
MODIFICATIONS REQUIRED
- BASIS WAS RESPONSE TO SALEM UNIT 2 FULL
POWER LICENSE REQUIREMENT
JULY '81 - NRC ORDER
- ORDER ISSUED CONFIRMING TMI COMMITMENTS
MADE PER DEC '80 LETTER FOR SALEM UNIT 1
CONTROL ROOM HA6ITA6ILITY
LICENSING BASIS'
SALEM UNIT 2
- SEP '77 EVALUATED ONSITE STORAGE OF CHEMICALS
LISTED IN A.G. 1.78, TABLE C-1
- IDENTIFIED AMMONIUM HYDROXIDE
-QUALITATIVE JUDGEMENT OF AMMONIUM HYDROXIDE
PERFORMED TO DISCOUNT IMPACT ON CONTROL ROOM
HABITABILITY
-CONCLUDED NO IMPACT ON CONTROL ROOM
HABITABILITY USING CHEMICALS IN TABLE C-1
- JULY 'BO SUBMITTED RESPONSE TO TMI ACTION ITEMS
- ITEM III .D.3.4 RELATED TO CONTROL ROOM
HABITABILITY
-DISCUSSED RIVERBORNE HAZARDOUS CHEMICALS
- IDENTIFIED SULFURIC ACID AND NITROGEN
APPLICABLE TO SALEM AS DISCUSSED IN UFSAR
- JAN '81 NRC ISSUED SER SUPPLEMENT 5 FOR SALEM
UNIT 2
- MAY '81 FULL POWER LICENSE ISSUE
LICENSING BASIS'
HOPE CREEK
MAR '83 HOPE CREEK SUBMITTED FSAR
- EVALUATED ONSITE TOXIC HAZARDS PER R.G. 1.78
-AMMONIUM HYDROXIDE NOT STORED AT HOPE CREEK
- REFERENCED APPROVED SALEM FSAR FOR STORAGE
OF TOXIC HAZARDS AT SALEM
- CONCLUDED NO IMPACT ON CONTROL ROOM
HABITABILITY
APR *as HOPE CREEK OPERATING LICENSE ISSUED
LICENSING BASIS
- IEN 83-62 FAILURE OF TOXIC GAS DETECTORS
-ENGINEERING REVIEW CONSIDERED HAZARD
ASSOCIATED WITH AMMONIA STORAGE
-REVIEW CONCLUDES NO IMPACT ON CONTROL ROOM
AS A RESULT OF DISPERSION FACTORS DESCRIBED
IN THE UFSAR
. .
LICENSING BASIS
SUMMARY
- CONTROL ROOM HABITABILITY WAS EVALUATED
USING R.G. 1.78 GUIDANCE
- AMMONIUM HYDROXIDE WAS IDENTIFIED AND
QUALITATIVELY EVALUATED
-NOT SPECIFICALLY LISTED ON TABLE C-1
-SOME AMBIGUITY IN INTERPRETATION OF R.G.
1.78 FOR CHEMICALS NOT LISTED
- OTHER APPLICABLE CHEMICALS CONTAINED IN
TABLE C-1 WERE QUANTITATIVELY EVALUATED AS
DISCUSSED IN THE UFSAR
ROOT CAUSE
ALTHOUGH A QUALITATIVE EVALUATION WAS PERFORMED,
PSE&G AGREES THAT THE EVALUATION WAS INADEQUATE
AND NOT PROPERLY DOCUMENTED
ROOT CAUSE IS
- INADEQUATE DEPTH OF EVALUATION FOR CONTROL ROOM
HABITABILITY
- CONTRIBUTING CAUSES
-AMBIGUITY IN APPLICATION OF A.G. 1.78
- INSUFFICIENT DOCUMENTATION OF ANALYSIS
- - - - - -----------------
~
ENGINEERING EVALUATION
PRELIMINARY EVALUATION (FALL '91)
- EVALUATED POSTULATED NH40H STORAGE TANK FAILURE
WITH EPA ACCEPTED COMPUTER MODEL "CHARM*
-ADDRESS IMMEDIATE OPERABILITY CONCERN
-ADDRESSED A.G. 1.78 CRITERIA (100PPM FOR
AMMONIA)
-RESULTS DID NOT EXCEED A.G. 1.78 TOXIC
LIMITS AT CONTROL ROOM INTAKE
-CONTROL ROOM HABITABILITY WAS NOT IMPACTED
ENGINEERING EVALUATION
--- *---------
-*
-*
-*
-*
-
-
DETAILED EVALUATION
- EVALUATED POSTULATED NH40H STORAGE TANK
FAILURE WITH COMPUTER CODE *vAPoR*
- ADDRESSES R. G. 1. 78 CRITERIA (100PPM)
-RESULTS PROVIDED TOXIC CONCENTRATIONS IN
EXCESS OF A.G. 1.78 LIMITS
-CONTROL ROOM HABITABILITY POTENTIALLY
IMPACTED
- FURTHER EVALUATION IDENTIFIED VERY
CONSERVATIVE ASSUMPTIONS USED
.....
ENGINEERING EVALUATION
CONSERVATISM IN *vAPOR* COMPUTER MODEL
- INST ANT ANEOUS PUFF
-TOTAL TANK CONTENTS ARE RELEASED
INSTANTANEOUSLY
- STRAIGHT LINE FROM SOURCE TO RECEPTER
- NO VERTICAL RISE
- -SOLAR AND RADIATION HEAT EFFECT
- TREATS SOURCE _SPILL AS IF OUTSIDE
- CALCULATION DONE AT TURBINE BUILDING
MAXIMUM DESIGN TEMPERATURE OF 115 F
- TANK ASSUMED TO BE- AT MAXIMUM DESIGN VOLUME
- NO CREDIT TAKEN FOR:
- THERMAL RISE -
- BUOYANCY EFFECT
- FAN- JET EFFECT
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COMPARISON OF OBSERVED VERSUS
- ~VAPOR
11
COMPUTED EVAPORATION RATE
Edgewood #6
Edgewood #10
LPG-CS37
LPG-PL68
EVAPORATION RATE COMPARISON
l§§j VAPOR * Obs. Data
REFERENCE:
MODELING THE IMPACT OF AN
ACCIDENTAL HAZARDOUS CHEMICAL RELEASE
by
S. A. VIGEANT and C. A. MAZZOLA
ENGINEERING EVALUATION
COMPARISON OF MODELS
CHARM
- PLUME RISE
- JET EFFECr
- INDOOR
--
VAPOR
- STRAIGHT LINE SOURCE
TO INTAKE
- NO CREDIT FOR RELEASE JET
- SOLAR/RADIANT HEAT
EFFECT ON SOURCE
- SEQUENTIAL PUFF RELEASES - SINGLE PUFF RELEASE
INSTANTANEOUS
2-47
ENGINEERING EVALUATION
- MODIFIED CHARM
-RE-ANALYZED PER R.6. 1.78 CRITERIA
(CONSISTANT WITH CURRENT LICENSING
REQUIREMENTS)
- NEW RESULTS CONCLUDE NO IMPACT ON
ENGINEERING EVALUATION
SUMMARY
- BASED ON
-CONSERVATISM OF VAPOR COMPUTER MODEL
- MODIFIED *cHARM* RESULTS
- CONTROL ROOM HABITABILITY CRITERIA IS MET
SAFETY SIGNIFICANCE
- ENGINEERING EVALUATIONS INDICATE CONTROL
ROOM HABITABILITY LIMITS HAVE NOT BEEN
EXCEEDED .
- NO SAFETY SIGNIFICANCE
CONTROL ROOM HA6ITAEILITY
CORRECTIVE ACTIONS
SHORT TERM
- ESTABLISHED LIMITS ON CONCENTRATION
- ESTABLISHED LIMITS IN STORAGE VOLUME BASED ON
TEMPERATURE
- CHANGED ROUTING AND ACCESS OF TANKER THROUGH
AUXILLARY GUARDHOUSE
- CONTROL ROOM AT HOPE CREEK TO BE IN
RECIRCULATION WHEN TANKER ENTERS THROUGH MAIN
GUARDHOUSE
- CONTROL ROOM AT SALEM TO BE IN RECIRCULATION
WHEN TANKER IS ON-SITE AND UNLOADING
- COMPLETED OLFACTORY TEST ON AMMONIA FOR ALL
LICENSED OPERATORS
- NEW PROCEDURE IN PLACE FOR SALEM CONTROL ROOM
OPERATORS ON DETECTION OF AMMONIA
CORRECTIVE ACTIONS
LONG TERM
- LETTER ISSUED REVISING PROCUREMENT
PROCEDURE (GM NUCLEAR SERVICES TO GM
PROCUREMENT MATERIAL CONTROL)
..
- REVISING PROCUREMENT PROCEDURES
..
(NAP-19) TO LIMIT QUANTITIES OF NEW
CHEMICAL TO <100 LBS. CONTAINERS UNLESS
ANALYZED
- REVISING PROCEDURE ON CONTROL OF
CHEMICALS (NAP-38) TO REQUIRE REVIEW
FOR CONTROL ROOM HABITABILITY BEFORE
USE
-CURRENTLY IN PRACTICE
- '
CORRECTIVE ACTIONS
LONG TEAM
-REVISING DCP PROCESS TO REQUIRE EVALUATION
FOR POTENTIAL IMPACT OF CHEMICALS ON CONTROL
ROOM HABITABILITY
- REVIEWED ALL ONSITE CHEMICALS
- SPILL PLAN
- RIGHT TO KNOW LAW
- OTHER CHEMICALS EVALUATED
- HYDRAZINE
- SODIUM HYDROXIDE
- ENGINEERING DEPARTMENT PROCEDURES HAVE BEEN
STRENGTHENED TO ENSURE MORE COMPREHENSIVE
REVIEWS
- - - - - - - - - - - - - -
J
(.. .
.;
CONTROL ROOM HA8ITA8ILITY
ENGINEERING IMPROVEMENT INITIATIVES
SAFETY EVALUATIONS AND DESIGN CHANGES
- SAFETY EVALUATIONS (50. 59)
-ARE MORE DEFINED AND COMPREHENSIVE TODAY TO
INCLUDE NONSAFETY SYSTEM INTERACTION ON
SAFETY SYSTEM
- DESIGN CHANGES
-FORMALIZED DESIGN BASES/INPUT
&USE OF DESIGN CONSIDERATIONS AND
SPECIALTY REVIEW CHECKLISTS
- INTERFACE RECORD SHEET
- MULTIPLE REVIEWS
&PEER REVIEW (IN ADDITION TO INDEPENDENT
DESIGN VERIFICATION)
&CROSS DISCIPLINE AND SPECIALTY
(PROGRAMMATIC) REVIEW
!-
'.
cNGlNttRING IMPROVEMENT INITIATIVES
j::.-.: .. *
- _
- PROJECT MANAGEMENT/ORGANIZATIONAL RESPONSIBILITIES
- A PROJECT TEAM CONCEPT
-NUCLEAR DEPARTMENT RESOURCE ALLOCATION PROGRAM
(NDRAP)
- INTEGRATED MANAGEMENT SYSTEM
& PROJECT EVALUATION PACKABE (PEP)
. & PROJECT SCOPE PROPOSAL (PSP)
- EXPANDED PROJECT TEAM MEMBERSHIP
& SYSTEMS ENGINEERS
&QA
- A DEDICATED DCP CLOSllE 6ROUP
- ENGINEERING ASSESSMENT GROUP
- PAA GROUP
- INSTALLATION ANl TEST GROUP
- IN-HOUSE CONSULTANTS
&THERMODYNAMICS/HYDRAULICS
& NUCLEAR ENGINEERING
&ELECTRICAL ENGINEERING
&METALLURGY/MATERIALS
&CHEMISTRY
ENGINEERING IMPROVEMENT INITIATIVES
- CHANGE PACKAGE IMPROVEMENTS
- PREASSEMBLED DCP WORKBOOKS
- EXECUTIVE SUMMARY
-MODIFICATION DOCUMENTS VS. CHANGE DOCUMENTS
-STATION DEPARTMENT CHANGE PACKAGE CHECKLIST
- CLOSEOUT CHECKLIST
- ADDITIONAL IMPROVEMENTS
- CONFIGURATION BASELINE DOCUMENTS (CBDs)
- DIMS
-COMPUTER AUTOMATED ENGINEERING DRAWING
(CAED) FACILITY
-PROCEDURE REVISION REQUEST PROCESS
- PERFORMANCE INDICATOR SYSTEM
CONTROL ROOM HA6ITAbILITY
REVERIFICATION OF
TMI COMMITMENTS (PER 7/10/81 ORDER)
PURPOSE:
TO REVERIFY ADEQUACY OF ACTIONS TAKEN
RELATIVE TO COMMITMENTS CONFIRMED BY JULY 10,
1981 ORDER
- TEAM OF FIVE (5) ENGINEERS FORMED TO ADDRESS
CONCERN
- A SAMPLING OF 10 OF 33 ITEMS REVIEWED
-SELECTED ENGINEERING - RELATED ITEMS JUDGED
TO BE MOST SUSECPTIBLE TO PROBLEMS
- AREAS REVIEWED INCLUDED:
-EVALUATION/ANALYSIS ORIGINALLY PERFORMED TO
ADDRESS ITEM
- VERIFICATION THAT SPECIFIC COMMITMENTS WERE
PROPERLY IMPLEMENTED
-VERIFICATION THAT FIXES ARE STILL IN PLACE
-ANY SUBSEQUENT CHANGES/EVALUATION THAT
IMPACT ISSUE
REVERIFICATION OF.
TMI COMMITMENTS (PER 7/10/81 ORDER)
j::.-~ .. .... .
- TYPICAL ISSUES REVIEWED
-LICENSING CORRESPONDENCE ON ISSUES
-REQUIRED TECH. SPEC. AMENDMENTS
-REQUIRED PROCEDURE REVISIONS
-DESIGN CHANGE PACKAGES/SUPPORTING
ANALYSIS
- REQUIRED TESTING, DCP CLOSEOUT
-FIELD CHECK OF INSTALLED EQUIPMENT
1'
...
REVERIFICATION OF
TMI COMMITMENTS (PER 7/10/81 ORDER)
TMI ITEMS REVIEWED
- I I . B . 1 REACTOR COOLANT SYSTEM VENTS
- II. B. 3 POSTACCIDENT SAMPLING
- I I . D . 1 RELIEF AND SAFETY VALUE TEST
REQUIREMENTS
- II. D. 3 VALVE POSITION INDICATION
- II.E.1.1 AUXILIARY FEEDWATER SYSTEM EVALUATION
- II.E.1.2 AUXILIARY FEEDWATER SYSTEM INITIATION
AND FLOW
- I I. F. 1 ACCIDENT MONITORING
- II.F.2 INSTRUMENTATION FOR DETECTION OF
INADEQUATE CORE COOLING
- III.D.1.1 PRIMARY COOLANT OUTSIDE CONTAINMENT
- III. D. 3. 3 INPLANT RADIATION MONITORING
~
REVERIFICATION OF
TMI COMMITMENTS (PER 7/10/81 ORDER)
JI 7.
RESULTS
- ALL ORIGINAL COMMITTED MODIFICATIONS
INSTALLED, EVALUATIONS COMPLETED AND
PROCEDURES REVISED
~ DCP CLOSURE DOCUMENTATION WAS NOT
PROPERLY COMPLETED
-TECH SPEC NOT PROPERLY UPDATED TO
REQUIRE ANNUAL VERIFICATION OF AUX FEED
SPOOL PIECE
PSE&G ASSESSMENT OF POTENTIAL VIOLATION
...
.
.
o.1-
-
- -
-**
NRC FINDING:
PSE&G'S FAILURE TO RECOGNIZE OR EVALUATE THE
POTENTIAL IMPACT ON CONTROL ROOM HABITABILITY
FROM THE: ON~SITE STORAGE OF AMMONIUM
HYDROXIDE
- PSE&G BELIEVES THAT THE PRESENCE OF
AMMONIUM HYDROXIDE AT SALEM WAS RECOGNIZED
DURING THE REVIEW OF CONTROL ROOM
HABITABILITY PER REG GUIDE 1.78
- ALTHOUGH A QUALITATIVE EVALUATION WAS
PERFORMED, PSE&G AGREES THAT THE EVALUATION
WAS INADEQUATE AND NOT PROPERLY DOCUMENTED
CONTROL ROOM HA8ITA6ILITY
PSE&G ASSESSMENT OF POTENTIAL VIOLATION
- SEVERAL MITI6ATIN6 FACTORS APPLY
- FESUL.TS OF ENGINEERING EVALUATIONS DEMONSTRATE THAT
CONTROL ROOM HABITABILITY HAS ALWAYS BEEN MET
- PSEC& HAS BEEN IN COMPLIANCE WITH SALEM LICENSIN6
REQUIREMENTS
- DEMONSTRATED NO SAFETY SI6NIFICANCE
- SOME AMBIGUITY DID EXIST ON THE NEED TO PERFORM A
THOROUGH EVALUATION OF AliltONIUM HYDROXIDE DUE TO ITS
EXCLUSION FROM TABLE C.1 (RES GUIDE 1.78)
-COMPREHENSIVE COFIECTIVE ACTIONS TAKEN/UNJERWAY
- PROMPT REPORTING OF POTENTIAL DEFICIENCY TO NRC (PER
50. 72)
-NOT LIKELY TO BE IDENTIFIED BY ROUTINE SURVEILLANCES
- SIGNIFICANT IMPROVEMENTS HA VE BEEN MADE IN
ENBINEERING PEFFORMANCE OVER THE PAST SEVERAL
YEARS/CONTINUING FOCUS ON MAINTAINING AN IMPROVING
TROO
-PAST PERFORMANCE ON IDENTIFICATION AND RESOLUTION OF
DEFICIENCIES HAS BEEN 6000 *
- OPEN, PROACTIVE AND COMPREHENSIVE INVESTIGATION OF
DEFICIENCY
- PSE&6 BELIEVES THAT ESCALATED ENFORCEMENT SHOULD NOT BE
APPLIED TO THIS ISSUE
.
. ~. .
~
.;.1.::. ; -* -**.
CONCLUSIONS.
- PAST CONTROL ROOM HABITABILITY EVALUATIONS
DOCUMENTED IMPROPERLY
- CBC PROJECT PREVIOUSLY ESTABLISHED TO
ADDRESS KNOWN DEFICIENCIES IN DESIGN BASIS
DOCUMENTATION
- IN COMPLIANCE WITH CONTROL ROOM
HABITABILITY LICENSING REQUIREMENTS
- OVERALL PERFORMANCE HAS BEEN IMPROVING
-SEVERAL INITIATIVES UNDERWAY TO ENSURE
CONTINUED IMPROVEMENT
- ESCALATED ENFORCEMENT NOT WARRANTED