ML18095A957
| ML18095A957 | |
| Person / Time | |
|---|---|
| Site: | Salem, Hope Creek  |
| Issue date: | 05/21/1991 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18095A954 | List: |
| References | |
| 50-272-91-09, 50-311-91-09, 50-354-91-08, NUDOCS 9106030314 | |
| Download: ML18095A957 (81) | |
See also: IR 05000272/1991009
Text
.
. .
U.S. NUCLEAR REGULATORY COMMISSION
Report Nos.
50-272/91-09
50-311191-09
50-354/91-08
License Nos. DPR-70
REGION I
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 27, 1991 - May 7, 1991
Inspectors:
Approved:
Inspection Summary:
-f-~1 f
~v
Inspection 50-272/91-09; 50-311/91-09; 50-354/91-08 on March 27, 1991 - May 7, 1991
Areas Inspected: . Resident safety inspection of .the following areas: operations, outage
controls, unit startup from refueling, radiological controls, maintenance and surveillance
testing, emergency preparedness, security, engineering technical support, safety
assessment/quality verification, and licensee event-reports_ and open item followup ..
Results: An executive summary follc:>ws.
TABLE OF CONTENTS
EXECUTIVE SUMMARY ............ *.: ......................... iii
1.
SUMMARY OF OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
1.1
Salem Units 1 and 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
1.2
Hope Creek .................... *. . . . . . . . . . . . . . . . . ..
1
.
.
2.
OPERATIONS .. * ................................... *. . . . . . . . 1
2 .1
Inspection Activities . ~ . . . . . . . . . . . . . . . . . . '. . . . . . . . . . . . . .
1
2.2
Inspection Findings and Significant Plant Events ......... : . . . . . .
2
2.2.1 Salem .................... * ..... * ... * ........... * .
2 .
. 2.2.2. Hope Creek* .. .-.......... * ......... -. ............ * 6
3..
RADIOLOGICAL CO:t-..1TROLS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7
3.1
Inspection Activities .................. *. . . . . . . . . . . . . . . * 7
3.2.1 Salem .......... * ............ ." . . . . . . . . . . . . . .
7
3.2.2 Hope Creek * ...................... *. . . . .. . . . . . . .. . .
9
4.
MAINTENANCE/SURVEILLANCE TESTING . . . . . . . . . . . . . . . . . . . . .
10
4.1
. Maintenance Inspection Activity .................. : . . . . . . .
10
4.2
Surveillance Testing Inspection Activity . * ..... ; . . . . . * . . . . . . . .
10
4. 3
Inspection Findings . . . . . . . . . . . . . . . . . . . . . . . . . * . . . . * . . . .
11
4.3.1 Salerri : ........ *. . . . . . . . . . . . . . . . . . . . . . . . . . . .
11
4.3.2 Hope Creek ....... * .. ~ .......... *. . . . . . . . . . . . . . 16
4.3.3 Common ........... : . . . . . . . . . . . . . . . . . . . . . . .
17
5.
EMERGENCY PREPAREDNESS ...................... ~* ........ 17
- 5 .1
Inspection Activity . * . . . . . . . . . . . . . . . . . . . . * . . . -; . . *. . . : . . .
17
5. 2
Inspection Findings . . . . . . . . . . . *. . . . . . . . . . . . . . *. *; * . . . . . . 17 .
6.
SECURITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17
6.1
Inspection Activity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17
6.2
Inspection Findings ...... : . . . . . . . . . . . . . . . . . . . . . . . . . .
18
7.
ENGINEERING/TECHNICAL SUPPORT . * . . . . . . . . . . . . . . . . . . . . . . .
18
7. 1 *
Salem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .* . . . . . . . . .
18
7.2
Hope Creek ........ ~ .*............... * ......... *. . . 20
8.
SAFETY ASSESSMENT/QUALITY VERIFICATION . . . . . . . . . . . . . . . . 20
8. 1
Salem . . . . . . . . . . . . . . . ." . . . . . . . . . . . . . . . . . . . . . . . . . . ~
20
8. 2
Hope Creek . . . . . . . . . . . .. .. . . . . . . . . . . . . . . . . . . . . . . . . . 23
Table of Contents (Continued)
9.
LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS,
AND OPEN ITEM FOLLOWUP * . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
9.1
LERs and Reports_ .................................. *. 24 *
9.2
Open Items .................... * ........ *. . . . . . . . . . 25
10.
EXIT INTERVIEWS/MEETINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
10.1
Resident Exit Meeting ....... * ...... ~ . . . . . . . . . . . . . . . . . . 26
10.2
Specialist Entrance and Exit Meetings . . . . . . . . . . . . . . . . . . . . . . 26
10.3
Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
11
. EXECUTIVE SUMMARY
Salem Inspection Reports 50-272/91-09; 50-311/91-09
Hope Creek Inspection Report 50-354/91-08.
March 27, 1991 - May 7, 1991
OPERATIONS -(Modules 60710, 71707, 71710, 71711, 93702)
.
.
Salem: The Salem units were operated in a safe manner. Unit 1 was returned to service
from its ninth refueling outage in a safe and controlled fashion. The licensee adequately
evaluated and responded to a heating steam system gasket rupture, which resulted in
rendering both Unit 1 safety injection pumps inoperable. A radiation monitoring system
actuation was properly evaluated and reported. *Licensee response to the No. 2C safeguards
equipment control system failure was prompt and conservative.
Hope .Creek: The unit was operated at power in a saf~ manner and in accordance with
license conditions. One emergency safety feature (ESF) actuation occurred. The event was *
appropriately investigated and adequate corrective actions were established .. An independent
walkdown and inspection of the Residual Heat Removal (RHR) System determined that the
system was operable and capable of performing its design functions. Discrepancies in the
computer-generated valve lineup sheets for RHR were promptly addressed by the licensee.
RADIOLOGICAL CpNTROLS (Modules 71707, 93702)
Salem:. Periodic inspector observation and evaluation identified that the licensee's
radiological controls and protection program requirements were properly implemented.
Radiation protection coverage for a Mode 3 containment tour of Unit 1 was good. Licensee
actions to change radiation monitor alarm/warning setpoints and to establish admin,istrative. *
controls for previously identified steam generator tube leak concerns were timely and
- effective. A personnel error resulted in leaving a high radiation area door uncontrolled for
about eight hours and is a non-cited violation. The licensee's response and followup was
appropriate. Response to a high oxygen concentration in the waste gas system was adec:iuate.
Hope Creek: Periodic inspector observation of station workers and Radiation Protection
personnel implementation of radiological controls and protection program requirements did
not identify any deficiencies. Licensee response to the occurrence of high conductivity water
in the floor drains associated with waste collector tanks was aggressive and appropriate.
iii
MAINTENANCE/SURVEILLANCE (Modules 61726, 62703, 70307, 70313)
Salem: The failure to restore a chemical and volume control system valve*following
surveillance testing, and the failure to establish proper tagout boundaries and obtain the
necessary permission prior. to starting work were identified as two of of three examples of a
violation of Unit 1 Technical Specification 6.8.1. Activities to identify, test and repair safety
related air system deficiencies were accomplished in a timely fashion. The Unit 1.
containment integrated leak rate testing was accomplished in a safe and well controlled
manner. An out-of-specification degraded voltage relay unresolved item, previously
identified at Unit 2, remains open and is also applicable to Unit 1. Licensee investigation of
a Unit 1 manual safety injection test failure was conducted in a thorough .and competent
. fashion.
Hope Creek: Routine- observations did not identify any deficiericies~ . The discovery of
mathematical errors pertaining to the 125 VDC battery surveillance of specific gravity
resulted in declaring the system inoperable until corrective actions were established. The
licensee instituted an industry initiative to improve the effectiveness relative to arranging. and
scheduling planned equipment outages.
Common: The licensee's evaluation for and approach in applying a 25% allowable extension
interval for Technical Specification Action Statement required surveillances and grab samples
was determined to be appropriate.
EMERGENCY PREPAREDNESS (Modules 71707, 93702)
No significant findings were identified. *
SECURITY (Modules 71707; 93702)
No significant findings were identified.
ENGINEERING/TECHNICAL SUPPORT (Modules 37700, 71707, 71711) .
Salem: Review of the day-to-day management of engineering work determined that activities
were performed in accordance with appliq:ible procedures; and were properly prioritized and
executed. Two open items were appropriately addressed and closed. The licensee's actions
for an open item pertaining to stud thread engagement deficiencies are considered incomplete
since similar deficiencies continue to be identified. A common failure rendering two ESP
radiation monitors inoperable was adequately evaluated and appropriately resolved.
lV
Hope Creek:' Review of the day-to-day management of engineering work determined that
activities were performed in accordance with applicable procedures and were properly ,
prioritized and executed. Errors were found in the equation for determining control rod
scram times associated with operation with an adequate _minimum critical _power ratio
(MCPR). The licensee reanalyzed the scram timing anruysis using the new constants.
provided by the nuclear fuels vendor. Subsequently, the licensee demonstrated that
operation during cycles two, three and four had been conservative and within the limits
stipulated in the Core Operating Limits Report and Technical Specification 4.2.3.
SAFETY ASSESSMENT/ASSURANCE OF QUALITY (Modules 30702, 71707, 90712)
- Salem: A Unit 2 planned entry into Technical Specification 3.0.3 .was effectively arranged
and executed. A previously unresolved item, regarding tagging release deficiencies that
resulted in a Unit 1 charging pump being run with the suction valve closed was identified as
one of three examples of violation of Technical Speeification 6.8.1. A trend of station
performance weaknesses were noted relative to personnel errors, procedure noncompliance,
and inattention to detail. The quality of the LERs reviewed during this inspection was good.
Hope Creek: The licen~ee aggressively pursued the investigation into the cause of the .
November 17, 1990 scram, and concluded that the event was caused by a defective drain line
check valve and sluggish level control system response. The licensee's actions in this area
exhibited a safety-conscious and conservative attitude towards safe plant operation. *
- V
' ' I
i *.
..
DETAILS
1.
.SUMMARY OF OPERATIONS
1.1
Salem Units 1and2
- Unit 1 was shutdown. at the beginning of the period for its ninth refueling outage, which
began on February 9, 1991. The reactor was made critical on April 23, 1991. Full power
operation was achieved on April 29, 1991, and continued for the.remainder of the inspection*
period.
Unit 2 operated at or near full power for the entire inspection period, with the exception of.
two brief power reductions due to an inoperable safeguards equipment control system (72 % ) .
and boron injection tank relief valve planned maintenance (60% ). At the end of this.
inspection period the unit had operated coni:inuously for 241 days.
1.2
Hope Creek
The unit operated at or near full power for the entire inspection* period. At the end of the
period the unit had operated continuously for 64 days.
Power reductions were initiated each
weekend for turbine control valve testing. At 9:02 p.m., on May 7, 1991, the unit
automatically scrammed from 100% power due to low water level caused by a feedwater
- control malfunction.
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 obsrrvation 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. These inspection activities were
- conducted in accordance with NRC inspection procedures 60710, 71707, 71710, 71711, and
93702. The inspectors performed normal and back-shift inspections, 'including deep back-
shift (27 hours3.125e-4 days <br />0.0075 hours <br />4.464286e-5 weeks <br />1.02735e-5 months <br />) inspections as follows:
Salem
Hope Creek
Inspection Hours
7:00 a.m. :.. Noon
8:30 a.m. - '2:30 p.m.
7:00 a.ni. - 4:00 p.m.
7:00 a.m. - 3:00 p.m.
March 29, 1991
April 20, 1991
April 21, 1991
March 29, 1991
2
2.2
Inspection Findings and Significant Plant Events
2.2.1 Salem
A.
Preparations for Unit 1 Startup from the Ninth Refueling Outage
Salem Unit 1 shutdown for its ninth refueling outage on February 9, 1991, (see NRC
Inspection Reports 50-272/91-01 and 91-05). During the period April 18-21, 1991, and prior
to the unit startup, the inspectors evaluated the licensee's readiness for restart in accordance
with NRC Inspection Procedure 71711.
The inspectors performed a walkdown of the high-head safety injection system, the service
water system, and the emergency diesel generators (EDGs). These system walkdowns were
performed after the licensee had completed maintenance, modification, testing, and system
restoration activities. The inspector determined that all three systems inspected were
appropriately aligned and prepared to perform their safety. related functions.
The inspectors also performed the following activities:
Performed control room tours and board walkdowns,
Reviewed the Technical Specification Action Statement, Lifted Leads and Jumpers,
and Tagout logs,
Toured the auxiliary, turbine and service water buildings, as well as the penetration
and electrical relay rooms,
Accompanied the licensee during the closeout inspection of the containment building,
Observed portions of the simulator startup training,
Reviewed design change package and temporary modification status,
Reviewed selected operations and surveillance testing procedures associated with
startup, and
Reviewed the licensee's progress towards attainment of outage goals.
The inspectors observed that PSE&G had conducted an effective outage and had successfully
met most of their outage goals. Two exceptions noted were (1) two personnel error events
occurred compared to a goal of none, and (2) the outage lasted 75 days compared to a goal of
58 days. The inspectors concluded that Salem Unit 1 was adequately prepared for startup
based on inspection results.
~~
--- --------- --
3
B.
Unit 1 Startup and Power Ascension * ,
Salem Unit 1 was returned to service following its ninth refueUng outage on April 27, 1991.
The startup was commenced over the weekend of April 20-:21, "1991, and criticality was
achieved on the morning of April 23, 1991. Over the four days immediately following
criticality, the Ucensee conducted reactor physics testing, main steam isolation valve (MSIV)
testing, turbine overspeed testing, and power ascension. The unit was synchronized to the
PJM grid at 12:32 a.m. on April 27, 1991, power ascension continued, and full power was
achieved on April 29, 1991.
The inspectors observed portions of startup, power ascension and surveillance activities in
accordance with NRC Inspection Procedure 71711. During the period April 20-:22, 1991, the
resident inspector staff initiated deep back-shift plant coverage, and over that period and
- through the following week, the inspectors monitored the following activities:
--
Plant heatup and entry into Mode 3 (Hot Standby),
Individual R~ Position Indication (IRPI) calibration and control rod time testing;
Reactor coolant system re~istance temperature detector (RTD) cross calibration and
time response testing, .
Reactor startup and initial criticality, i.e. entry into Mode 2 (Startup),
-Reactivity computer checkout, isothermal temperature coefficient determination, and
rod swap reactivity measurements,
. Entry into Mode 1 (Power Operation), and
Secondary plant startup, MSIV testing, and turbine testing and synchronization.
The inspectors noted that the Operations Departmen_t, assisted by the Maintenance and
Technical Departments, conducted the plant startup in a controlled, deliberate and safe .
manner. All startup activities were observed to have been- well planned and executed.
Though the outage extended 17 days longer than planned, the inspectors did not observe any
compromise of safety to meet schedular commitments. *
.
.
.
.
C.
Steani Leak Affecting Both Unit 1 Safety Injection (SI) Pumps
On March 31, 1991, licensee personnel discovered a steam leak from the overhead piping in
the Unit 1 SI pump room. The unit was in Mode 5 (Cold Shutdown) at the time of the
event. Unit 2 was operating at a reduced power level (60%) in preparation for valve
corrective maintenance. The leak was determined to be coming from a steam trap in the
hea6ng steam (HS) system due to a ruptured gasket. The leak was stopped when plant
4
operators isolated the affected portion of HS piping. The licensee estimated that steaµi had
sprayed in the SI pump room from the 3/4 inch pipe for less than five minutes. In that time
period, both Unit 1 SI pumps were sprayt:?d by the*steam. Sub_sequently, the licensee
immediately declared the pumps to be inoperable; and placed the plant in the Action
requirements of Technical Specification (TS) 3.4.1.4.
TS 3.4.1.4, Reactor Coolant System - Cold Shutdown, requires that two residual heat
removal (RHR) loops be operable and at least one RHR loop be in operation. The
specification allows RHR support systems to be inoperable, such as the service water (SW)
system, provided that specified minimum equipment combinations are available. The No. 12
SI pump was. required to be available per the above TS Action because one of the two SW
headers was inoperable for maintenance. TS 3.4.1.4 states that with less than the required
RHR loops operable, immediately initiate corrective actions to return the required loops to an
operable status as soon as possible.
Both SI pumps were declared inoperable at 12:30 a.m. on March 31, 1991, due to the steam
spray. The No. 12 SI pump was tagged out of service and the motor was meggered
satisfactorily. The pump was restored to an available status.and the TS Action Statement was
exited at-3:24 a.m. on March 31, 1991. The megger check for the No. 11 SI pump motor
was initially unsatisfactory, however, the motor was subsequently dried, tested satisfactorily
and restored later that day.
The licensee conducted an investigation for this event and determined that the ruptured gasket
occurred when an equipment operator (EO) identified and opened a HS system valve (2HS4),
causing a pressure surge and resulting in gasket rupture in the HS system. The valve is
reverse acting and provides main turbine extraction steam for process and heating needs to the
HS system. The EO on the previous shift reported that he had opened the valve as directed
by shift supervision. However, the oncoming BO noticed that HS pressure was low.because
2HS4 was actually closed. Be did not report this abnormal finding to shift supervision prior
to opening the valve and did not properly warmup the system when placing it back into
. service.
The licensee concluded that the root cause of this everit was a general unfamiliarity with the
operation of 2HS4, and the failure ofthe EO to report his findings to shift supervision and to
properly warmup the system flowpath. License corrective actions included: 1) issuing
- guidance to all shift personnel regarding proper operation of 2HS4 and other similar reverse
acting valves, 2) counselling the oncoming EO for not properly warming-up the HS header
when placing it in service, and 3) implementing a procedure change (in draft at time of event) .
to provide specific guidance on proper system warmup.
The inspector reviewed the event and the licensee's response. At the valve, the inspector
noted that there were two separate, but similar indicator scales near the valve stem; one for
actual position, and one for instrument technician use. However, neither scale was clearly
identified. On April 3, 1991, a caution tag was hung on the position indicator scale .
5
identifying it as the proper scale for valve position verification. The inspector also reviewed
the revised HS warmup prOcedure (No. OP-V-10.3.1, "Heating Boiler Cold Startup") and did
not identify any deficiencies. The inspector concluded that the* licensee's actions in response
.
.
- to this event were appropriate.
D.
Radiation Monitor Engineered Safety Feature (ESF) Actuation
Radiation monitor 1R41C spuriously actuated at Unit 1 and this ESF actuation was reported
by the licensee on March 29, 1991. The inspector noted that this spurious event is indicative
of the previously identified degraded radiation monitor system (RMS), and is intended to be
resolved in the licensee's RMS upgrade plan. The inspector had no further questions.
E.
- Unit 2 Shutdown Due to .Inoperable Safeguards Equipment Control Channel
On the afternoon of April 8, 1991, a self test fault alarm on the No. 2 Safeguards Equipment
Control (SEC) system cabinet annunciated. Upon investigation, the control room operators
determined that one of the three SEC channels (No. 2C) was inoperable. The SEC system
initiates'various engineered safeguards loads upon receipt of an engineered safety feature
actuation signal.
With any SEC channel inoperable, Salem Unit 2 Technical Specification (TS) 3.3.2.1, Action
B-J3, requires the unit to be in the Hot Standby mode within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to be in Cold
Shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. Within one hour of the discovery of the faulted .
SEC channel, thelicensee determined that this TS was applicable, notified the NRC, and
began reducing power to shut down Unit 2 . While the unit was being shut down, the Salem
Instrumentation and Control Group (I&C) investigated the channel failure and determined the
problem to be with the electrical circuit cards within the SEC cabinet. Due to the history of
this type of problem with the Salem SEC system, I&C maintains a spare SEC electronics
chassis warmed up (energized) on a test stand, ready to replace a failed chassis. The failed
chassis was removed and replaced with this spare chassis. A functional surveillance test was
performed on the affected SEC cabinet with satisfactory results. The. channel was
subsequen~ly declared operable, and the TS Action Statement was exited. Within three hours
of the initial SEC alarm, the Unit 2 power reduction was stopped, at 72 % , and a power
ascension was conducted to return the unit to full power.
The resident inspector responded to the Unit 2 :control room when notified of the event by the
licensee. The inspector noted that the plant operations staff response to the channel failure
was appropriate and conservative, and the unit shutdown was being performed in a safe and
controlled manner. The inspector also concluded that the I&C group performed well in the *
prompt identification and repair of the problem with the SEC system.
Despite the effective licensee response to this event, the inspector remained concerned with
the performance and reliability of the SEC system and discussed the matter with the
responsible system* engineer. The inspector was informed of measures being taken to monitor
6
and compensate for SEC system performarice (such as maintaining a spare chassis warmed up ,
and ready for use) and of a design change package (DCP) being prepared to provide for
replacement of the current SEC hardware.. The inspector had ~o further questions in this
area.
2.2.2 Hope Creek
A.
Engineered Safety Features (ESF) Actuation While Venting Reactor Water
Cleanup (RWCU) Flow Instrumentation
Following completion of a scheduled maintenance outage for the RWCU system on April 5,
1991, the system was being restored to normal operation. At 11:15 a.m. an ESF actuation
occurred due to a high RWCU differential flow* signal closing the RWCU suction vaives BG-
HV-F001 and F004. The operators determined the actuation signal to be spurious, reset the
isolation and opened the isolation valves.
The licensee determined the root cause of the event to be procedural inadequacy associated
with the venting of the system differential flow transmitters during the performance of the .
restoration procedure. The procedure did not require defeating the isolation logic prior to
venting. Contributing to the actuation potential were inaccuracies in the RWCU suction. flow
nozzle calibration. The licensee had began discussions with the system vendor, General
.Electric. (GE), concerning the inaccuracies in the flow calibration curve. However, resolution
of the issue had not yet been obtained when the isolation occurred. The inspector observed
that the licensee's actions appeared appropriate, noting that the flow calibration inaccuracy
- was conservative with minor safety significance. No inadequacies were noted in LER 91-06"
which discussed this event. The inspector had no further questions regarding this event.
B.
Engineered Safety Feature (ESF) Systein Walkdown
The inspector independently verified the operability of the Residual Hear Removal (RHR)
System by performing a walkdown of the accessible portions of the system to confirm that
system lineups and procedures matched plant drawings and the as-built configuration," and to
identify equipment conditions which could degrade performance. This inspection was
conducted in accordance with NRC inspection procedure 71710.
The inspector walked down the RHR system and concluded that the system was fully
functional and appropriately aligned in the standby mode. Valves were positioned and locked
(as appropriate) as indicated by the computer-generated (TRIS) valve lineup sheets.
However, a number of deficiencies were noted when comparing the TRIS printout with the
RHR piping and instrumentation diagrams (P&ID) M-51-1. For example, two valves shown
locked in a throttled position (V205 and V259) on the P&ID, b.ut not locked on TRIS. The
. TRIS lineups were divided into two groups, (1) a "masters" listing all the valves, components
- and breakers in the system; and (2) a specific listing for each RHR loop (A, B, C and D).
7
Numerous cases of duplication existed between loops; and some instances were rioted where
valves necessary to assure .the proper lineup of a loop were either not listed in that loop's*
TRIS printout or were only included on the master list. Since_ the inspector had been
.
- * informed by* the licensee that, in general, only the individual RHR loop lineups were used in
the field, the potential existed for significant valve mispositioning, particularly with one loop
out of service.
-
When these discrepancies were brought to the lieensee's attention, the licensee immediately
initiated a complete review and update of the TRIS priritouts using a dedicated senior reactor
operator (SRO). The licensee acknowledged the potential for erroneous valve lineups and
stated that eacii*RHR loop lineup would be configured on a '.'stand-alone" basis with all
relevant equipment included. This effort was ongoing when the report period ended. The .
. adequacy ofthe revised TRIS lineup sheets wiHbe assessed when completed and noted in a
future report.
The inspector noted that the material condition of the RHR system appeared good.
Housekeeping in areas inspected was determined to be adequate although a few areas were.
not yet 'up to the level existing before the refueling outage. Efforts to improve those areas
were ongoing.
Based on the above, the inspector concluded that the RHR system appeared fully operational .
and capable of performing its designed functions with regard to safe operation of the facility.
3.
RADIOWGICAL CONTROLS
3 .1
Inspection Activities
PSE&G's conformance with the radiological.protection program was verified on a periodic *
basis. These inspection activities were condµcted in accordance with NRC inspection
procedures 71707 and 93702.
3.2.l Salem
A.
Unit 1 Containment Tours*
As part of the Unit 1 outage recovery plan and post-refueling activities, the licensee
performed several containment walkdowns and closeciut inspections. These inspections were
performed prior to entry into *Mode 4. (Hot Shutqown) and Mode 3 (Hot Standby), and while
at normal operating temperature and pressure in accordance with procedure Pl/S-CONT-1.
The inspector accompanied an inspection team on April 16, 1991, prior to Mode 3 entry.
The unit's reactor coolant system was pressurized. to 1000 psig and temperature was 345
degrees F. Prior to the containment entry, a briefing was held for the team. The team ,
included representation from operations, maintenance, radiation protection, and contract
8
laborers. This briefing was thorough and included expected radiological hazards.
The tour was professionally .conducted and the licensee appropriately identified and
documented minor deficient conditions.
~adiation protection c_overage was appropriate and in
accordance with station procedures.
B.
Radiation Monitoring For Steam Generator 1,'ube Leaks
In response to steam generator tube crack indications (reference NRC Inspection 50-272 and
311/91-05), the licensee initiated changes to their leak monitoring program. These items
were discussed during a conference call between the NRC (region and headquarters) and
PSE&G. The licensee committed to the following:
Lowering the alarm/warning setpoints for the air ejector condenser monitors (1R15
and 2R15) and the steam generator blowdown monitors (1R19A-D and 2R19A-D).
These setpoints are approximately two to three times background which would
correspond to a leak of about 20. gallons per day (gpd).
Establishing administrative controls and operational actions to monitor for a fast
moving leak/rupture event to shutdown the unit at a leak rate of 140 gpd. The
licensee revised procedures AOP-SG-1, CH-3.3.018 and RP-Tl.RM-0067.
The inspector verified these actions were completed on Unit 1 prior to startup and attended
training sessions given to operators. No unacceptable conditions were identified.
.
C.
High Radiation Area (HRA) Found Uncontrolled Due to Personnel Error
,
,
On February 20, 1991, the Unit 1 regenerative heat exchanger room access door was found
by the licensee to be closed, but unlocked and unguarded. The licensee initiated .an
investigation and found that the HRA key was obtained by a Radiation Protection (RP)
technician to support work in the area. The area had accessible radiation levels of up to 2
Rem/hour (at 18 inches from source). Technical Specification 6.12.2 requires that areas
accessible to personnel with radiation levels greater than 1 Rem/hour shall be provided with
locked doors to prevent unauthorized entry. The licensee determined that the condition had
existed for approximately eight hours prior to the discovery, and that no inadvertent entry
into the HRA was made. The cause of the event was determined to be personnel error by the
RP technician, in that the individual did not ensure the door was locked after the personnel
performing the work had vacated the area. Licensee corrective action included 1) locking the
HRA door, 2) taking disciplinary action with the RP technician involved, 3) reviewing the
event with applicable RP Department personnel, and 4) inspecting all other locked HRA
doors. No other similar concerns were identified. The inspector reviewed the licensee event
report associated with this event (LER 91-11), including licensee assessment, root cause and
corrective actions and determined them to be acceptable. The inspector concluded that this
licensee identified violation of TS 6.12.2 is not being cited beeause the criteria specified in
Section V.G.1 ofthe NRC Enforcement Policy were satisfied (NON 50-272/91-09-02).
-
L
9
D.
High Oxygen Concentration in Waste Gas System
On March 29, 1991, Unit 1 Technical Sp~dfication (TS) 3.11.;2.5 Action Statement was
entered due to an elevated oxygen concentration in the waste gas holdup (WGH) system. The
TS specifies that oxygen concentration in the WGH system be limited to less than or equal to
2% by volume, and to reduce the oxygen concentration to.within limits within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> (if
between 2% and 4%). On March 29, 1991, the oxygen concentration was 2.3%. Due to a
prior failure of radiation monitor 1R41C.(plant vent monitor), the WGH tank discharge valve
could not be opened for holdup tank discharge in order to reduce the oxygen concentration.
1R41 C provides an electrical interlock with the tank discharge valve. Therefore, the oxygen
concentration was not reduced to within limits within the 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> and this event was
properly reported by the licensee to the NRC per 10CFR50. 73 reporting requirements
(Licensee Event Report - LER 91-16).
Radiation monitor 1R41C was restored to an operable status on April 2, 1991, at which time
the appropriate 'discharge and purge activities were accomplished by April 3, 1991. The
maximum oxygen concentration reached was 2. 7%. All affected holdup tanks were
subsequently sampled and analyzed with satisfactory results, and the TS Action Statement was
exited on April 8, 1991. The inspector reviewed the associated LER and did not identify any
deficiencies. The root cause of this event was determined to be equipment failure (1R41C).
The source of the elevated oxygen concentration was due to excess oxygen entrained in the
reactor coolant system during recent Unit 1 refueling outage activities. The inspector had no
further questions and concluded that the licensee's actions were appropriate.
3.2.2 Hope Creek
A.
Waste Collection Tank High Conductivity
011 April 20, 1991, radwaste operators transferred resin from the anion tank to the cation
tank in preparation for maintenance on the anion tank. The waste water from the transfer and
tank draindown was collected in the "B" waste collector tank (WCT). Prior to processing the
"B" WCT, the tank was sampled and conductivity was measured as 1950 micro-
siemens/centimeter (uS/cm). On April 27, 1990, samples of the floor drain collector tanks
"A" and "B" showed conductivities of 2000 uS/cm and 2400 uS/cm respectively. While the
cause ofthe relatively high conductivity in the "A" floor drains was believed to be due to the
resin transfer, no reason could be determined for the high conductivity measured in the "B"
floor drains.,
.
The licensee was concerned that the processing of such high conductivity water would quickly
exhaust the clean-up beds and potentially aff~t plant operation. Plant management noted the
similarity between this occurrence and the river water intrusion in the summer of 1990 (NRC
Inspection Report 50-354/90-14), which created significant water storage problems and
degraded conditions in the radwaste facility. Consequently, the licensee initiated action to
immediately dilute and process the high conductivity water.
10
The inspector monitored the licensee's assessment and corrective actions regarding this
occurrence and concluded that the licensee responded aggressively and with an appropriate
degree of expediency due to the recognition of the potential im_pact on plant operation. The
performance of the licensee in this effort will continue to be monitored by the resident staff.
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. The inspectors also
eva1uated the adequacy of the appropriate maintenance procedures, presence/availability of
maintenance supervision, personnel qualification, radiological controls, and post-maintenance
testing requirements. These inspections were conducted in accordance with NRC inspection
procedure 62703.
Portions of the following activities were observed by the inspector:
Wotk Request (WR)/Order
(WO) or Procedure
Description
Salem 1&2
Salem 1
Salem 1
Hope Creek
Hope Creek
IC-14.2.001
Various
WOs 910411112/
910412141
Maintenance and Calibration of the
Redundant Air System
Troubleshoot and Rework: No Voltage for
No. 11 Steam Generator Feed Pump Trip
Service Water System Pipe Replacement
Repair of "B" Core Spray Testable Check
Valve 1BEV032
"C" Emergency Diesel Generator
Troubleshooting (governor control and
sticking fuel rack)
The inspectors did not identify deficiencies associated with the observed activities, and
concluded that the safety objectives of the maintenance program were satisfied.
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
- ,,._.
-*
11
that the surveillance tests were performed in accordance* with Technical Specifications,
approved procedures, and NRC regulations. These inspection activities were conducted in
accordance with NRC inspection procedui:e 6~ 726.
-
The following surveillance tests were reviewed, with portions witnessed by the inspector:
Procedure No.
Salem 1
Sl.OP-ST-SJ-0013(Q)
Salem l
M9-ILP-CT-01S.
Hope Creek*
OP-ST. GK-001
Hope Creek
OP-ST.KJ-002
-Throttle Valve Flow Balance Test
Containment Integrated Leak Rate
Test
11A
11 Control Room Emergency
Filter Monthly Surveillance
"B" Emergency Diesel Monthly
Surveillance
The inspectors did.not identify deficiencies associated with the observed activities, and
concluded that the safety objectives of the surveillance testing program were satisfied.
4.3
Inspection Findings
4.3.1 Salein
A. *
Chemical and Volume Control System (CVCS} Valve Misaligned During Testing
On March 30, 1991, the licensee iden~ified that a Unit 1 CVCS valve (1CV122) w~s *
misaligned. The unit was in Mode 5 (Cold Shutdown), and plant operators were attempting
to pressurize the reactor coolant system (RCS) for the first time since the outage began on
February 9, 1991. The valve is the reactor coolant pump (RCP) seal water return filter outlet
isolation Yalve. During the RCS pressurization, control room operators noted unusual RCP -
seal leakoff flows and an.elevated pressure (about 150 psig) in the seal water return line.
Diaphragm leaks were also noted on several related valves. Unit operators subsequently -
determined that the .observed anomalies were due to valve 1CV122 being closed and therefore /
isolating the RCP seal water return flow. The operators opened 1CV122; and the RCP seal
water return prf'.ssure Jeturned to normal. An in-line relief valve, set at 150 psig; actuated
and relieved pressure/flow to the pressurizer relief tank as per design.
The licensee initiated an investigation to ascertain why 1CV122 was in the closed position.
From this effort, the licensee determined that the valve was initially closed on March 26,
1991, to support. testing of the No. 12 charging pump, but was not restored to the open
12
position, as required by the associated test procedure, PI/S-CV-2, "Charging Pump Flow.
Test". The licensee identified the causes of this oversight to be: l) *the failure of the test
personnel to complete the requirements of PI/S-CV-2; and 2) circumvention of the established
.method for verifying that procedures are proi)er1y*completed. The licerisee based this
- conclusion on the following information.
The test*personnel were aware that another charging pump test procedure was to be* *
performed immediately following the completion of PI/S-CV-2. Accordingly, the individuals
elected to put PI/S-CV-2 aside, intending to complete the procedure following performance of
Sl.OP-ST.SJ-0013(Q) ,;Throttle Valve Flow Balance Test". The individuals incorrectly
assumed that both procedures utilized the same test flowi)aths.
I
Following completion of the second charging pump test (Sl.OP-ST.SJ.;0013(Q), the.
associated restoration lineup was performec! in accordance with that procedure. However,
that lineup did not cause valve 1CV122 to be restored to open position, as was required by
PI/S-CV-2. In the interim, due to miscommunication, PI/S-CV-2 was forwarded for
administrative processing without being completed. As a result, 1CV122 was not properly
restored prior to RCS pressurization.
The inspector reviewed the licensee's response to this occurence and determined that the
initial followup actions were satisfactory. The licensee verified that there was no significant.
damage to safety related equipment, and that other valves that may have been similarly
affected, were *properly*positioned. Valves which experienced minor diaphragm leaks were.
repaired. Operations management counselled the involved test personnel.
The inspector identified that Technical Specification (TS) 6.8.1 requires that written
procedures be established, implemented and maintained covering sur\\ieillance test activities.
The failure to implement the restoration portion of surveillance test PI/S-CV-2 is an 'example
of a violation of TS 6.8.1 (50-272/91-09-01).
B.
Redundant Air System. Failures
...
The licensee informed the inspector of recent failures of their redundant control air system.
This system provides control air to safety related components including air operated valves,
dampers, and control systems. The Salem station has two independent control air headers.
Each unit has a primary designated air header and an alternate (backup) header. Two
einergency air compressors powered from each unit can supply either header. Thus
redundancy and diversity exists in this system. In addition, numerous control air users have a
redundant air panel which directs control air from the designated (normal) header; and on a
Joss of this header, automatiCally backs up the control air from the alternate header.
The redundant air panels consist of two Lunkenheimer supply valves and one Fisher three-
way switching valve. The system normally operates at 110 psig. As pressure decreases in
the normal air supply to approximately 82 psig, air will start venting from a port of the
I
I
II
. 13
Fisher three-way switching valve. This will align the normal air supply to the alternate air
supply. At approximately 77 psig, venting will cease from the Fisher valve. Upon return of
normal air supply pressure to approximately 84 psig, the alternate air supply will shut off artd
normal air supply will resume.
-
The licensee determined that both the Fisher and Lunkenheimer valves failed to respond to
these pressure changes due to dry and- brittle parts, including ."0" rings, gaskets and
diaphragms. This is apparently due to the lack of preventive maintenance/periodic testing
due to unavailability of spare parts. (The valve manufacturer was unable to supply these
parts.) The licensee has since began manufacturing their own spare parts. *
The licensee evaluated these failures and concluded that this condition is neither reportable
nor affects systems operability. This is not a condition outside the design basis (UFSAR
9.3.1) as the plant was designed for a total loss of control air. Components fail in a "safe"
condition and the licensee has emergency procedures to address this failure (e.g. AOP-CA-1 .*
and 2). The licensee has also stated that this condition is consistent with their response to
Generic Letter 88-14. An engineering evaluation (S-2-CA-MEF-0567 dated April 25, 1991)
was performed and approved by the station operation's review committee ..
Licensee corrective actions included:
Completion of testing/maintenance on all Unit 1 panels prior to restart from refueling,
Completion of testing/maintenance on the priority Unit 2 panels,
Informing operators of this situation by use of a memorandum, and
Establish periodic surveillance and preventive maintenance on these panels,
The inspector reviewed appropriate documentation and procedures; discussed these failures
with engineering and maintenance personnel; verified knowledge of operators regarding a loss
of control air; and observed field maintenance/testing activities. The inspector concluded that
licensee actions were appropriate and had no further questions at this time.
C.
Salem Unit 1 Integrated Leak Rate Testing
During the week of March 25, 1991, the inspector performed a review of the Type A
Integrated Leak Rate Test (ILRT) procedure and preparations for Salem Unit 1. During the
period April 3-5, 1991, the inspector observed the performance of portions of the ILRT test.
The inspector reviewed the test procedure in accordance with NRC inspection procedure
70307 and conducted the test surveillance in accordance with NRC inspection procedure
70313.
I
14
'
Review of the test procedure indicated _no deficiencies. The procedure was adequately
prepared and addressed appropriate prerequisites, precautions and directions for the conduct
of testing. The leak rate determination portion of the test wa.s observed by the inspector and
was conducted in a conservative and controlled manner.- Licensee personnel involved were
knowledgeable ,in test performance, precautions, and acceptance criteria .. Operations were
- observed at the Data Acquisition Center and the Testing Control Station. Licensee activities
'were reviewed during containment inspections 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. It was noted that personnel were oompetent and had a thorough knowledge of the test
procedure, data obtained, and plant systems inspected. Test equipment observed complied
with the testing requirements; and equipment calibration was current.
The inspector concluded that the test procedure preparation and the conduct of the test were
well controlled and exeeuted in a conservative, safe manner.
D.
Vital 4KV Bus Undervoltage Relay Setpoints Found Out-of-Specification (UNR
311/91-05~01)
During performance of a maintenance surveillance test on April 13, 1991, on the Unit 1 three
4KV vital buses, all nine undervoltage (UV) relay (three per bus) trip setpoints were found to
be low and out-of-specification. The minimum 3.llowed setpoint is 91 %. The lowest UV
.. relay, on Bus "A", was set at 90%. Unit 1 was shutdown at the time of the discovery. The
event was reported to the NRC via the Emergency Notification System on April 14, 1991.
Prior to completing the maintenance surveillance procedure, all UV relay setpoints were
restored to the proper Technical Specification value. The inspector noted that the UV relays
were last tested January 1991, prior to plant shutdown.
The licensee had previously detected this type of deficiency on the Unit 2 vital 4KV bus UV
relays on February 26, 1991,. while that plant was at full power (see NRC Inspection
50-311/91-05). As a 'result of that finding, the licensee had initiated an investigation, which
is still in progress. Accordingly, the licensee intends to include this latest Unit 1 finding
within the scope of that effort.
This unresolved item was first opened in NRC Inspection Report 50-272 and 311191-05. The
item remains unresolved pending the cqnclusion of the licensee's investigation, and
assessment by NRC
E.
Unit 1 Manual Safety Injection Test Failµre Due to Equipment Problem.
On April 10, 1991, while performing a Unit 1 manual safety injection (SI) test, several
components did not actuate as per design. Specifically, after manually initiating the Train
"B" SI, the No. 11 main feedwater (MFW) pump, and the associated MFW isolation valves
(Nos. 13BF13 and i4BF13) did not receive a trip signal. The Unit was in Mode 5 (Cold
Shutdown) during the conduct of the test.
15
A* subsequent investigation identified a loose wire connection in the solid state protection
system (SSPS) output test cabinet. The licensee properly connected and secured the loose
wire, and inspected all other wire connections in both the Train "A" and Train "B" SSPS
ouq)ut test cabinets. No additional deficiencies were found, and the manual SI test was.
satisfactorily completed. The licensee reported this issue to the NRC vfa the Emergency
Notification System. The inspector reviewed this event, including maintenance
troubleshooting activities, event evaluation and reportability, and corrective actions, and
concluded that the licensee's response was good.
F.
Breach of a Pressurized Unit 1 Service Water (SW) Line
Early on the evening of March 29, 1991, as part of tlle Salem Service Water Replacement
Program, contracted workers were preparing to replace piping in the Unit 1 Mechanical
Penetration Ar~ .. As the pipefitters cut into the existing spool, part of the No. 11 SW
Nuclear Header Chiller Condenser Supply, they discovered that the line was still pressurized.
Consequently, water began to spray from the pipe at a rate of approximately three gallons per
minute. The chiller header was immediately isolated, and the flow of water was stopped.
No serious equipment damage nor any personnel injuries resulted from the event. The header
- was subsequently properly tagged and isolated, and the spool piece was replaced.
Following the event, the Salem Maintenance Engineer was aggressive in requiring the Salem
Service Water Project Manager to submit a report (and an additional follow up report)
explaining the details of how the event occurred, the root causes of the event, and the
corrective actions taken or plannt'!d to prevent recurrence. The Project Manager's report
explained that the night shift craft foreman did not receive a proper turnover for the
applicable work package. Consequently, the foreman directed the craft workers to install the
- riew pipe without verifying that a signed work order or the appropriate equipment tagging
was in place.
Corrective actions included additional training of workers to stress adherence to procedures
and the establishment and implementation of the requirement that supervisors (PSE&G and
contractors) perform a direct "hands-on" turnover prior to initiating work to assure
'
cognizance of the status of th~ system or component.
The inspector discussed the event and the corrective actions with the Salem Maintenance
Engineer, and reviewed the reports submitted by the Salem Service Water Project Manager.
The inspector determined that licensee management understood the potential serious
consequences of an event of this type and that positive corrective actions were bei~g taken.
The inspector further observed that the licensee already .had adequate controls in place that
should have prevented this event. Station procedure NC.NA-AP.ZZ-0009(Q), "Work Control
Process," states that the job supervisor shall "verify tagging boundaries are established in *
accordance with the Safety Tagging Program" and "obtain the Nuclear Shift Supervisor/Work
Control Center permission on the Work Activity prior to starting the work." Technical
Specification (TS) 6.8.1 requires that written procedures be established, implemented and
16
maintained covering the control of maintenance, including the work control process. The
failure of the personnel involved in this event to adhere to NC.NA-AP.ZZ-0009(Q) is another
example of a violation of TS 6.8.1 (50-272/91-09-01).
4.3.2 Hope Creek
A.
Incorrectly Calculated Battery Performance Parameters
On April 15, 1991, during a review of the quarterly surveillance test results for 125 VDC
battery 1AD411, the licensee determined that the average specific gravity had been
miscalculated. The initial satisfactory value was 1.217. However, when correctly calculated,
the average specific gravity for the battery was 1.202. Technical Specification Table 4.8.2.1-
1 requires an average specific gravity of all cells of greater than 1.205 with an allowed value
of equal to or greater than 1.195 for each cell. The licensee immediately declared the battery
inoperable and entered the applicable seven day action statement. The battery was placed on
an equalizing charge, after which the surveillance was reperformed satisfactorily and the
battery was declared operable.
Licensee corrective actions included a surveillance review of the incident with the technicians
involved, and enhancements to the surveillance procedure [HC.MD-ST.PK-002(Q)] to make
the data collection/computation table easier to use and understand. The inspector discussed
this event with maintenance supervision, reviewed the revised surveillance procedure, and
concluded that the actions taken were appropriate. The inspector observed, however, that the
licensee had not yet initiated similar enhancements to a nearly identical surveillance procedure
for the 250 VDC batteries (MD-ST.PJ-002(Q)). This matter was brought to the attention of
the licensee. The licensee initiated review of this matter at the end of this report period.
B.
Implementation of Enhanced Equipment Outage Activity Control
The licensee recently instituted a new approach to equipment/system maintenance activities.
When a component or system is to be taken out of service for scheduled corrective and
preventive maintenance, the component or system is placed in service and walked down in
order to identify any additional repairs which might be needed. * The walkdown is conducted
sufficiently ahead of the scheduled outage to allow for processing the possible resultant
documentation. The concept promotes improved planning and scheduling of work activities
by reducing the potential for problems not being discovered until a component or system is
operated for post-maintenance testing. The licensee has used this approach on a limited scale
to date, notably on the emergency diesel generators. Initial reactions on the part of work
center and maintenance personnel appear favorable .
i.
-*-
17
4.3.3 Common
A.
Recurring* Surveillance Requirem.ents Required By ~echnical Specification
. Actions Statements* (TSAS)
The licensee discussed with the inspector an interpretation issue associated with both Salem
and Hope Creek Station Technical Specifications (TS). The issue deals with the
- appropriateness of the 25% allowable extension interval (per TS 4.0.2) for TSAS required
surveillances and grab samples. The licensee stated that they had received conflicting
guidance in the past.
The inspector reviewed a licensee memorandum (NLR-1 91136) dated March 25, 1991. This
memorandum concluded that. the 25 % .allowable extension applies if the TSAS addresses a
recurring surveillance requirement. However, required initial actions (that may include
testing) should be performed within the required time period.* For example, a TSAS may
require redundant trains to be tested (proven operable) within one hour and every eight hours
thereafter. The interpretation would be that the recurring eight hour surveillance interval
could be extended up to two hours (25%). This would likewise apply for a periodic required
The inspector also reviewed standard, Hope Creek, and Salem TS sections 3.0/4.0; and
reviewed NRC Inspection Manual guidance. The inspector also.discussed this item with NRC
regional and headquarters personnel. Based on this, the inspector concluded that the
licensee's approach was appropriate.
5. *
5.l
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 10CFR50. 72 and 73 were reviewed.
-
5.2
Inspection Findings
No noteworthy findings were observed.
6.
SECURITY
6.1
Inspection Activity
.PSE&G's conformance with the security program was verified on a periodic basis, including
the adequacy of staffing, entry control, alarm stations, and physical boundaries. These
inspection activities were conducted in accordance with NRC inspection procedure 71707.
18
6.2
Inspection Findings
No noteworthy findings were observed.
7.
ENGINEERING/TECHNICAL SUPPORT
7.1
Salem
A.
Open Item Followup
1.
(Closed) Deviation (272/89-18-01; 311/89-16-01) Failure to use No. 2 diesel fuel in
accordance with UFSAR commitments. The licensee determined that the UFSAR
diesel fueL oil reference to No. 2 diesel fuel was in error and the- existing building
heating oil used for the emergency diesel generators (EDG) is adequate. A UFSAR
change has been processed to indicate that fuel oil (not No. 2 diesel fuel), meeting
modified ASTM D396 criteria is to be used for the EDGs. The inspector reviewed
the licensee's associated procurement process, EDG fuel oil specifications, the EDG
vendor fuel recommendations and the related UFSAR proposed change and evaluation,
and did not identify any deficiencies. This item is closed.
2.
(Closed) Unresolved Item (272/89-18-02; 311/89-16-02) Dedication and control of
emergency diesel generator (EDG) fuel oil. The licensee developed, and currently
implements, Detail Specification No. S-C-M255-NDS-0181-0, "Specification
Requirements for the Purchase of Fuel Oil." The inspector reviewed this document
and found that analyses are formally performed for the appropriate critical fuel
parameters. The document is to be used for the procurement of fuel oil in bulk
shipment for off-loading into the main fuel oil storage tank. The inspector confirmed
that samples are taken, analyzed and dedicated in a timely fashion, and that proper
contingency/corrective actions are planned in the event that fuel oil test results are
negative. This item is closed.
B.
Thread Engagement Problems
On March 22, 1991, the inspector conducted a tour of the Unit 1 containment building and
identified a concern relative to the pressurizer relief tank (PRT) support studs and nuts. -
Specifically, about four of the ten threaded studs did not fully engage the associated nuts.
The inspector notified the system engineer, who initiated action for resolution. That action
included initiating an Incident Report (IR) and a Discrepancy Evaluation Form (DEF), and
visually inspecting both the Unit 1 and Unit 2 PRT. Additionally, a modification package
was developed and implemented to tack or plug weld the PRT bolts at Unit 1. A preliminary
as-found seismic calculation was performed by the Engineering organization, which indicated
that the Unit 1 PRT would not have overturned or otherwise caused damage to other safety
related equipment during a seismic event. The inspector verified that the DEF was properly
19
prioritiied as a potential safety concern, and that a formal and complete evaluation was
scheduled. The inspector reviewed the licensee's response to this concern and concluded that
their actions were appropriate.
The inspector noted that a. similar issue was previously identified by the NRC Maintenance.
Team Inspection (Reference - Violation 50-272/90-200-03), in which specific valves were
noted. as having insufficient thread engagement. The licensee corrected the two valves
initially identified as being deficient and took action to prevent future similar problems.
However, personnel were apparently not made aware of the problem or instructed to identify
similar problems, as the inspector (in this inspection period) identified several other valves
that did not meet minimum thread engagement specifications. The inspector concluded that
this area required further management attention. The licensee agreed with the inspector's
observations and committed to evaluate the implementation of the corrective measures applied
to this matter. Accordingly, this violation remains open.
C.
Two Radiation Monitors Rendered Inoperable to Common Equipment Failure
On March 22, 1991, ail event occurred at Unit 1 in which a single cause resulted in two
radiation monitors, each of which provide an engineered safety features (ESF) system
actuation signal, to become inoperable. Specifically, upon the failure of a radiation
monitoring system (RMS) common sample pump, radiation monitors lRllA (containment
particulate) and 1R12A (containment gaseous) both were r~ndered inoperable. A redundant
RMS channel (1R4 i C) was available for containment isolation ESF actuations. The plant
was in Mode 6 (Refueling) at the time of the failures. The licensee determined that the event
was reportable per 10 CFR 50. 73 reporting requirements because both radiation monitors are
required to be operable to generate an ESF function in Modes 1-6.
The licensee determined that the pump had failed due to vane damage. The pump was
replaced, and both monitors were declared operable after about ten hours. The lieensee had
previously identified a concern relative to the pump's application, and the pump was
scheduled for periodic replacement on a six month interval. In response to this recent event,
the licensee changed the replacement interval to three months. Additionally, the pump is
scheduled to be replaced with a more reliable model as part of the RMS Upgrade Project (See
Section 10.3.A).
The inspector reviewed this event, including licensee response, Technical Specification
Compliance, corrective actions, and the associated licensee event report (Unit 1 LER 91-14).
The inspector concluded ~at the licensee's actions were acceptable .
20
7.2
Hope Creek
A.
Minimum Critical Power Ratio (MCPR) Tau Equation Constant Change
On April 15, 1991, in response to questions from the licensee concerning control rod scram
timing tests, General Electric (GE) Company, the reactor fuel supplier, advised the licensee
that the value of two constants used in the MCPR "tau equation" as specified in Technical
Specification (TS) 4.2.3 had been changed. A switch from the GENESIS analysis method to
the GEMINI method had occurred and both methods are used to develop the TS control rod
scram time limits. GE also stated the*new constants had been derived for cycle two fuel and
were applicable to cycles three and four as well.
The lfcensee was initially concerned that Hope Creek may have been operated for an
extended period of time with non-conservative MCPR operating limits. The scram timing
analysis for cycles two, three and four was reanalyzed using the new constants in Tau. (The
GENESIS values for the two constants, mu and sigma were 0.688 and 0.052 respectively.
The GEMINI values are 0.67 and 0.016.) The current TS values for Tau were in all cases
less than zero. Even with the new constants, the reanalysis indicated that the value of Tau
remained less than zero in all cases, albeit with smaller absolute values. Since a change in
the MCPR operating limit as specified in the Core Operating Limits Report would not be
required until a positive Tau value was obtained, the licensee concluded that the unit had not
been operated with an improper MCPR operating limit.
The inspector reviewed documentation supplied by GE and the results of the licensee's
analysis and written incident report. The inspector also interviewed shift and reactor
. engineering personnel about this event and its possible consequences, and concluded that the
licensee's actions in this matter were appropriate and sound. The licensee will pursue the
apparent communications breakdown between the station and GE regarding the Tau constant
change. The inspector had no further questions regarding this issue.
8.
SAFETY ASSESSMENT/QUALITY VERIFICATION
8.1
Salem
A.
Technical Specification (TS) 3.0.3 Entry
An increasing Unit 2 reactor coolant system unidentified leak rate continued during this
inspection period. The leak rate increased from approximately 0.3 gpm to 0.8 gpm .. The TS
limit is 1.0 gpm. The licensee attributed this leakage to the boron injection tank (BIT) relief
valve 2SJ10 (reference NRC Inspection 50-311/91-05).
On March 30, 1991, the leak rate increased to a value greater than 1.0 gpm. TS 3.4.7.2.b
was appropriately entered and the leak rate was reduced by securing the positive displacement
(number 23) charging pump. The licensee found an internal leak in the No. 23 charging *
21
pump which was causing the total leak rate to be greater than 1.0 gpm .. The licensee
- subsequently made the decision to replace valve 2SJ10 with the identical Unit 1 valve, as
Unit 1 was in the refueling mode.
An operations troubleshooting procedure per SC.OP-DD.ZZ"-AD.46(Q) was developed to
control the m~ntenance evolution and the required entry into TS 3.0.3. This TS entry was
nec.essary due to the isolation of the BIT which affected both high head safety injection trains.
The inspector was notified per administrative procedure NC.NA-AP.ZZ-0005(Q). Reactor
power was lowered to 60%. At 10:32 -p.m. on March 30, 1991, TS 3.0.3 was entered and
was subsequently exited at 11: 18 p.m. Thus, the BIT was isolated for 46 minutes. The post
maintenance leak rate was 0.3 gpm.
.
.
The inspector reviewed the troubleshooting plan and procedure, and discussed its
- implementation with licensed operators and management personnel. The inspector concluded
that licensee proactively and effectively planned and carried out this maintenance evolution.
Licensee senior management was involved during the decision process and implementation
~a~s.
.
- B.
Unit 1 Charging Pump Operation With Its Suction Valve Closed
. (Closed) Unresolved Item (272/91-05-03) Safety injection charging pump operated with its
suction valve is closed. Inspector review of this event identified multiple deficiencies,
including personnel errors and programmatic weaknesses. The inspector reviewed Operations
procedure OD-8, "Tagging Request and Inquiry System (TRIS) Tagging Operations," and
determined that there were three examples in which the procedure was not complied with
resulting in the pump's suction valve being left closed. Specifically, Operations personnel
-failed to 1 )-release the associated tag and reposition the No. 12 charging pump suction valve
in accordance with the Tagging Release Worksheet, 2) verify that the number of tags
removed agrees with the Tagging Release, and 3) confirm that Tagging Release in the TRIS: .
The failure to follow procedure OD-8 constitutes ano_ther example of a violation of Technical
Specification 6.8.1, which requires that procedures be established, implemented and
maintained. Therefore, Unresolved Item 50-:272/91-05-03 is administratively closed, and this
issue will now be tracked as Violation 50-272/91-09-01.
-
C.
Station Performance Weaknesses
During the last inspection period (February 13, 1991 - March 26, 1991) and the current
inspection period (March 27, 1991 - May 7, 1991), there have been a high number of
personnel- errors and procedure compliance and/or adequacy problems among the various
station groups, resulting in numerous plant events or concerns. In addition to the three
instances of procedure noncompliance noted in the Notice of Violation in this report, some
other examples are as follows:
-
22
Department/SALP Area
Event
Cause
Radiological Controls
Spread of ra<;lioactive
Poor radiological work
contamination on 3/19/91
practices
Radiological Controls .
High Radiation Area left
Personnel error
uncontrolled on 2/20/91
Operations
Spraying of safety injection
Personnel error
pumps with steam rendering
both pumps inoperable on
3/31/91
Maintenance/
Technical Spedfication
Personnel error
Surveillance
3.0.3 entry during
troubleshooting on 2/9/91
Mainte11ance/
Personnel error
Surveillance
Actuation on 2/ l 7 /91
Maintenance/
Component Cooling System
Inadequate procedure
- -
Surveillance
valve left unlocked
on 4/25/91
Engineering/
Failure to properly
Personnel error
Technical Support
evaluate and prioritize_
identified concerns relative
to a missing seismic gap seal
on 2/15/91
Safety Assessment/
Incomplete followup of NRC
Inattention to detail
Assurance of Quality
identified violation regarding
proper thread engagement on
safety components
Safety Assessment/
LER quality weaknesses in
Inattention to detail
Assurance of Quality
NRC Inspection 91-05
Each of the above events was discussed in a NRC Inspection Report. The relatively high
number of recent events/concerns may be indicative of a negative performance trend and
warrant increased management attention to effect improved performance. These matters were
discussed with licensee management at the exit interview .
23
,8.2
Hope Creek
A.
. Automatic Reactor Scram Upclat~
The licensee had initi3.lly determined that the root cause of a scram on November 17, 1990,
was a malfunction of the
11A
11 moisture separator level .control system. (For details on the
event, see NRC Inspection Report 50-354/90-21, Section 2.2.2.A). However, answers to
questions raised by the Significant Event Response Team (SERT) report indicated that one or
more as yet unknown factors may have contributed to the event, especially in light of the
- *similarity between this scram and an earlier one in January, 1990 (see LER 90-01). Until
further investigation could resolve the issue, station management directed that the. weekly
performance of turbine valve testing per procedure OP-ST.AC-001 be conducted at no greater.
than 85 % power.
During the refueling outage (from late December 1990 to early March 1991), furihertesting
of the
11A
11 moisture separator valves and controls was conducted .. Additionally, the internals
of associated piping was inspected .. The testing and inspection determined that the moisture
separator's drain check valve, AC-V024, had a broken bushing in its hinge pin. At rated
pressure and flow, such a defect could cause the check valve to stick open, allowing. backflow
from the No. SA, B, and C feedwater heaters into the moisture separator. The ;'B" moisture
separator's drain check valve was subsequently inspected; and no abnormalities were
observed .. Consequently, the licensee concluded that the probable root cause o(the
November, 199,0 scram (and in all likelihood the January, 1990 scram) was the sticking open
of the
11A
11 moisture separator drain line check valve. A probable coritributor was the
sluggish response from the level, control system.
Since the unit has returned to operation, the licensee has continued to perform turbine valve
testing at a lower power level of 85 % ' and has periodically instrumented the level control
system to monitor and trend operational performance.
The inspector reviewed the licensee's responses to this event, including the subsequent
- investigation during the refueling outage and the performance monitoring of the level control
system. The inspector concluded that the licensee exhibited a conservative and safe approach
to resolution of this matter. Though the safety significance of the event was minimal, the
- .-licensee's investigative effort indicated an agressive approach to determining the root cause.
Licensee management indicated that the power level at which turbine valve testing is
.
conducted would not be increased until the results of the ongoing performance monitoring
program bad been analyzed. *Depending on the results of the analysis, the licensee intends to
perform turbine. valve testing at incrementally increased power, while continuing to monitor
the level control system. The inspector also reviewed the licensee's supplemental LER 90-
28-01 and found no significant discrepancies.
9.
24 .
LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS,
AND OPEN IJ'EM FOLLOWUP
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.
Special/Periodic Reports
Salem arid Hope Creek Monthly Operating Reports for March 1991.
Salem and Hope Creek 1990 Annual Environmental Operating Report.
Salem Special Report 91-1-1 (Supplemental Planned F~re Barrier Penetration
Impairments).
Hope Creek Special Report 9t-02 dated April 24, 1991, InoperCJ.ble Seismic
Monitoring Channel. This report discussed the inoperability of one channel of the
triaxial time-history accelorgraph after its related sensor located on the core spray
piping in the drywell failed.
No deficiencies were identified relative to the above reports.
Salem 'LERs
Unit 1
LER 91-05-01 (Revision) concerns degraded heat removal capacities for both Unit *1 and 2
containment fan coil units (CFCUs). The revised report addressed an update to the root
cause of the condition. The licensee concluded that the degraded condition was due to the
lack of a CFCU heat removal capacity test program and therefore, the inability to .detect
degrading performance. No inadequacies were noted relative to this LER.
LER 91-10 concerns two radiation monitor actuations resulting in containment purge/pressure
- vacuum relief system isolation signals. The actuations were reviewed in NRC Inspection
50-272/91-05. No inadequacies were noted relative to this.LER.
LER 91-11 (See Section 3.2.1.C)
LER 91-12 concerns a control room ventilation isolation due to a spurious radiation monitor
actuation. This event was reviewed in NRC Inspection 50-272/91-05. No inadequacies were
noted relative to this LER.
25
LER 91-13 concerns an incorrectly plugged steam generator U-tube. This issue was reviewed
in NRC Inspection 50-272/91-05. No inadequacies were noted relative to this LER.
LER 91-14 (See Section 7 .1. C)
LER 91-15 (See Section 2.2.1.D)
. LER 91-16 (See Section 3.2.1.D)
Unit 2
LER 91-03-01 (Revision) concerns a voluntary LER for two ASME Code 3 piping leaks that
occurred on January 10 and 30, 1991. The revised report included a discussion for an
additional service water system ASME Coce 3 piping leak that occurred on February 25,
1991. The leak was isolated and repaired per the ASME Code 3 requirements. No
inadequacies were noted relative to this LER.
LER 91-05 concerns 4KV sustained degraded voltage relays that were found out-of-
specification. This issue was reviewed in NRC Inspection 50-311/91-05. See also Section
4.3.1.D of this report.
LER 91-06 concerns two control room ventilation isolations caused by spurious radiation
monitor actuations. These isolations were reviewed in NRC Inspection 50-311/91-05. No
inadequacies were noted relative to this LER.
The above reviewed Salem LERs were submitted in a timely fashion and appropriately
described and assessed the subject issues, including root cause and corrective actions*. The
- inspector concluded that the above reviewed LERs were of good quality.
Hope Creek
LER 91-06 (See Section 2.2.2.A)
LER 90-28-01 (See Section 8.2.A)
9.2
Open Items
The following previous inspection items were followed up during this inspection and are
tabulated* below for cross reference purposes;
i
26
Open Item
Report Section
Status
272/89-18-01
7.1.A.1
Closed
272/89-18-02
7.1.A.2
CloSed
272/90-200-03
7.1.B
. Open
272/91-05-03
8.1.B
Closed
311/89-16-01
7.1.A.1
Closed
-311/89-16-02
7.1.A.2
Closed
311/91-05-01
4.3.1.D.
Open
Hope Creek
None
10.
_ EXIT INTERVIEWS/MEETINGS
_ 10.1
Resident Exit Meeting
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 Region I review and discussions with PSE&G, it was determined that this report
does not contain information subject to 10 CFR 2 restrictions.
-
10.2
Specialist Entrance and Exit Meetings
Date(s)
4/15-19/91
4/15-26/91
Subject
Appendix R
Followup; Fire
Protection
Safety System
Functional
Inspection
Inspection
Report No.
272&311/91-12;
354/91-09
272&311/91-80 -
Reporting
Irtspectm
Paolino
Chaudhary
27
10.3
Management Meetings
A.
Salem Management Meeting
A management meeting was held at the Salem Station on April 18, 1991, to discuss status of_
the licensee's activities affecting material condition of the plant, and radiation monitoring
system. Attachment 1 is a list of attendees. Attachment 2 is a copy of the licensee's handout
used during their presentations .
ATTACHMENT 1
LIST OF ATTENDEES
APRIL 18, 1991
NUCLEAR REGULATORY COMMISSION
J. Wiggins, Deputy Director, Division of Reactor Projects (DRP), RI
R. Blough, Branch Chief, Projects Branch No. 2, DRP, RI ,
J. White, Section Chief, Reactor Projects Section No. 2A, DRP, RI
J. Durr, Chief, Engineering Branch, Division of Reactor Safety (DRS), RI
T. Johnson, Senior Resident Inspector
S, Pindale, Resident Inspector
S. Barr, Resident Inspector
K. Lathrop, Resident Inspector
W. Butler, Project Director, PDI-2, NRR
S. Chaudhary, Senior Reactor Engineer, RI
J. Jang, Senior Radiation Speci3.list, RI
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
S. LaBruna, Vice President - Nuclear Operations
T. Crimmins, Vice President - Nuclear Engineering
L. Miller, General Manager - Nuclear Operations Support
C. Vondra, General Manager - Salem Operations
F. Thompson, Assistant to General Manager - Plant Operations
M. Butsztein, Manager - Nuclear Electrical Engineering
R. Brown, Principal Engineer, Nuclear Licensing a'nd Regulation
P. Ga1leshaw, Project Manager - Er_gineering & Plarit Betterment
A .. Orticelle, Maintenance Manager - Salem
J. Carey, Jr. , I&C Engineering Supervisor
.T. Murphy, Project Engineer for RMS Replacement
T. Cellmer, Radiation Protection & Chemistry Manager - Salem
D. Martrano, Materiel Condition Maintenance Coordinator
E. Villar, Station Licensing Engineer - Salem
M. Le Fevre, Lead Engineer, External Affairs
B. Preston, Manager - Licensing and Regulation
M. Morroni, Technical Manager
V. Pollizzi, Manager - Operations
B. Rokes, Staff Engineer
R. Bravo, Project Manager - Materiel Condition Revitalization Project
OTHER
P. Duca, Delmarva Power Site Representative
E. Krufka, Lead Engineer, Atlantic Electric
- T. Kolesnik, NJ Department of Environmental Protection
i.
ATTACHMENT 1
Public Service
- Electric and Gas
Con1pan.y
PROJECT
STATUS
- \\1EETING
April -1a, * 1991
SALEM GENERATING STATION
I
-
-
-
AGENDA
STA.TVS ~IEETING ON THE RADIATION MONITORING
SYSTEi\\! .AND MATERIEL CONDITION PROJECTS
.
'
INTRODUCTION
- SITE WELCOME
- PURPOSE
- AGENDA
APRIL 18.
PROJECT DESCRIPTIONS
- RMS UPGRADE . *
- ENGINEERING/PROJECTS
- STATION
- SALEM MATERIEL CONDITION
REVITALIZATION
- PROGRAM OVERVIEM
- PROGRAM SCOPE
- MATERIEL CONlITI~ PROJECTS
1991
- MATERIEL CotllITION MAINTENANCE
-
SALEM STATION f>R06RE'SS
SUMMARY
PLANT TOUR
T. Crimmins
T. Murphy
M. Morroni
S. LaBruna
L. Miller
R. Bravo
D. Martrano
S. LaBruna
s. LaBruna
s. LaBruna/
D. Martrano
'
.
i
MMi-7
PROJECT STATUS MEETING
R .. ~DL . .\\.TION MONITORING SYSTEM
HISTORY
- UNIT 1
-ANALOG SYSTEM WIIH 53 MONITORS
.A.SYSTEM DESIGN IS APPROXIMATELY 25 YEARS
OLD
.A.EACH MONITOR IS CONFIGURED IN A SINGLE
INDEPENDENT *LOOP
- UNIT 2
- DIGITAL SYSTEM WITH 50 MONITORS
- SYSTEM DESIGN IS APPROXIMATELY 20 YEARS
OLD
- CENTRAL PROCESSING UNIT
(DATA ACQUISITION SYSTEM)
PROJECT STATUS MEETING
R_\\DL~ T.ION 1tf ONITORING SYSTE11
PROBLEMS
- 47 ESF ACTUATIONS IN 1990.
ROOT CAUSE ANALYSIS
SHOWS CAUSES AS:
- BACKPLANE DESIGN
- EQUIPMENT AGING
- EQUIPMENT HEAT
- POWER SUPPLY
- PARTS OBSOLESCENCE
- MAINTENANCE OF SYSTEM IS VERY LABOR INTENSIVE.
- PROBLEMS HAVE BEEN IDENTIFIED ON LER's
MMi-8
PROJECT STATUS MEETING
R_:\\DL!\\ TION MONITORING SYSTErvf
POSSIBLE SHORT TERM CORRECTIVE ACTIONS
- REPLACE BACKPLANES
- UPGRADE BACKPLANES
- REPLACE COMPONENT BOARDS
- CONSULTED WITH OTHER UTILITIES ON THEIR RMS
PROJECTS FOR LESSONS LEARNED
- DIABLO CANYON
- OCONEE
MM1-9
MMi-11
PROJECT STATUS MEETING
RA.DIATION MONITORING SYSTEM
SII ORT . TER1tf CURRENT PROJECTS
- INSTALL A UNIT 2 UNINTERRUPTIBLE POWER SUPPLY
(UPS)
- REPLACE THE MONITOR ELECTRONICS ON MONITORS
THAT ACTUATE ESF SYSTEMS (15 CHANNELS)
PROJECT STATUS Mll'l'ING
RADIATION MONITORING SYSTEM
ESF REDUCTION "PROJECT OR RMS SHORT TERM PROJECT
- THE FOLLOWING MONITOR ELECTRONICS WILL BE
REPLACED:
UNIT 1 CONTROL ROOM INTAKE DUCT MONITOR
-
UNIT 1 PLANT VENT PIG - PART, IODINE, GAS
MONITOR
UNIT 2 CONTROL ROOM - AREA MONITOR
UNIT 2 CONTAINMENT ATMOS. PARTICULATE MONITOR
UNIT 2 CONTAINMENT ATMOS. IODINE, GAS MONITOR
-
UNIT 2 STM GEN SLOWDOWN - LIQUID MONITOR
UNIT 2 PLANT VENT PIG - PART, IODINE, GAS
MONITOR
- ENGINEERING AND INS"TALLATION WILL TAKE PLACE IN
1991
MM1-19
r
I
!
I
!
PROJECT STATUS MEETING
R~~DL.~TION MONITORING SYSTEM
LONG TERM PROJECTS
- FULL RMS REPLACEMENT
MMi-36
r----- -
PROJECT STATUS MEETING
RA'DIATION MONITORING SYSTEM
REPLACEMENT SCHEDULE
SALEM UNITS 1 AND 2
91
92
93
94
95
1R9
1R10
1H12
2H6_
2A7
~RB--,
---
,
- m********~*******~********************
...............*............*..........** *********************~********************
- BIO
EQUIPMENT
...................................................................................
DESISN*
.
- o****************~***********~********
VERIFICATION
UNIT 1 - N/O DCP
UNIT 2 DCP.
~------------
ENGR
UNIT 2 - N/O DCP
--
UNIL1
\\!_f'gJ _2
OUTAGE SUPPORT
OUTAGE SUPPORT
- I*******~************ *......................... ~.*~*********~* 1***m******aaaaaaaa**-~***************~***
INSTALL
UNIT 1 PRE-OUTAGE (CABLE PULL)
IJNIT 1 OUTAGE
UNIT 1 POST OUTAGE (CLOSE TRAYS)
UNIT 1 - N/O
LJt:jIT 2 PHE-OUTAGE (CABLE PULL)
UNIT 2 OUTAGE
UNIT 2 POST OUTAGE (CLOSE TRAYS)
UNIT 2 - N/0
- ****************~*** *******m********~**********~************* ***111****************r*********************
CLOSE
OUT
PHASE 1
PHASE 2
MM1-15
UNIT 1 SAFEtY RELATED/1R11
UNIT 2 SAFETY RELATED/2R8
PHASE 3
PHASE 4
UNIT 1 DCP
. ,
-~
UNIT 1 - N/O
-*-
.
~~I~ 12 DCP
~NIT 2 - N/O
UNIT 1 NON~SAFETY RELATED/NON-OUlAGE
UNIT 2 NON-SAFETY RELATED/NON-OUl-AGE
PROJECT STATUS MEETING
R~'-\\DIATION. MONITORING SYSTEM
CURRENT STATUS
- VERIFICATION OF SYSTEM DESIGN IN PROGRESS
MMi-10
-UNIT 2 UPS - PROJECT SCOPE PROPOSAL (PSP)
APPROVED
-SHORT TERM PROJECT - PSP APPROVED
-FULL REPLACEMENT - PSP APPROVED
-PROJECT IS UNDERGOING FINAL BUDGET APPROVAL
MMi-4
PROJECT STATUS MEETING
RA.DL . .\\.TION ~10NITORING SYSTEM
ST~~TION *ACTIVITIES
- LARGE EFFORT TO MAINTAIN SYSTEM OPERABLE
- INTERIM GOALS UNTIL IMPLEMENTATION OF RMS
UPGRADE
-MAINTAINING THE CURRENT SYSTEM AS A VIABLE.
OPERABLE. SYSTEM
-REDUCING THE FREQUENCY OF INCIDENTS
INVOLVING RMS EQUIPMENT
I
. ,
MMi-5
PROJECT STATUS MEETING
RADLATION J\\10NITORING SYSTE1if
STATION ACTIVITIES
- ACTIONS TO SUPPORT GOALS
- INCREASED PLANT PERSONNEL AWARENESS
ACREATED DATABASE FOR ALL RMS INCIDENTS
AND LEA'S TO CATEGORIZE ROOT CAUSES AND
REPEAT FAILURES
- IMPROVED OPERATIONS PROCEDURES
- *IMPROVED MAINTENANCE PROCEDURES
- PREVENTATIVE MAINTENANCE PROGRAM
- TECHNICIAN TRAINING
- USED TO PRIORITIZE RMS UPGRADE PROJECT
- COMPLETED REVIEW OF VENDOR MANUALS TO
ENSURE PRE'VENTATIVE MAINTENANCE_ IS IN
ACCORDANCE WITH VENDOR RECOMMENDATIONS
- IMPROVED O&M PROCEDURES
& SET UP OF R19 MONITORS
- WEEKLY APO CHECKS
A CAPACITOR REPLACEMENT PMs
ELEMENTS
PROJECT STATUS MEETING
SALEM REVITALIZATION
OVERVIEW
- TECHNICAL SPECIFICATION LICE~SE IMPROVEMENTS
.. MAINTENANCE CM/PM BACKLOG REDUCT_ION
- MATERIEL CONDITION REVITALIZATION UPGRADES
- MATERIEL CONDITION MAINTENANCE
- PROCEDURE UPGRADE PROJECT
- PERSONNEL PERFORMANCE IMPROVEMENT
MMi-53
PROJECT STATUS MEETING
SALEM REVITALIZATION
STR.-\\TEGIC OBJECTIVES
.
.
- ESTABLISH AN EARLY CHANGE OF PLANT PHYSICAL
MATERIEL CONDITION
- LONG-TERM ACHIEVE A ~ATERIEL CONDITION THAT IS
WELL ABOVE INDUSTRY AVERAGE
- ACHIEVE COMPONENT AND EQUIPMENT RELIABILITY
THAT RESULTS IN IMPROVED PLANT SAFETY AND
AVAILABILITY
- ACHIEVE STAKEHOLDER ACKNOWLEDGEMENT OF IMPROVED
MATERIEL CONDITION ANO OPERATING PERFORMANCE
MM1-54
<
PROJECT STATUS MEETING
S_~LE~f REVITALIZATION
- sTR.;\\TEGIC OBJECTIVES
- CONTROL CONTRACTOR ACTIVITIES WITH MINIMAL
EFFECT ON THE PLANT STAFF
- CONTROL INTEGRATION OF UPGRADES WITH NORMAL
STATION WORK ACTIVITIES
- ,
- CONTROL RESOURCES THROUGH CONTINUED PLANNING
ANO MANAGEMENT INVOLVEMENT
- MAXIMIZE PERFORMANCE THROUGH INNOVATIVE
.
,
UTILIZATION OF RESOURCES ANO PROCESSES
- CREATE CULTURE CHANGE TO ASSURE MATERIEL ANO
RELIABILITY IMPROVEMENTS ARE MAINTAINED
- IMPROVE QUALITY OF WORK LIFE FOR PLANT STAFF
MM1-55
.. I
MGIH&R
GM-SO
TECH. SPEC.
MAINTENANCE
LICENSE*
CM&PM
IMPROVEMENTS
REDUCTIONS
o=un
(MAINT. MGR-8Al£M)
SALEM REVITALIZATION
ORGANIZATIONAL REPORTING
SALEM
REvlT ALIZA TION
(MIU£R)
VP-N:
VP-NO
GM-SO
MATERIEL
MATERIEL
CONDITION
CONDITION
UPGRADES
MAINTENANCE
(BRAVO)
(MARTRANO)
GM-HOe
VP-HO
PROCEDURE
PERSONNEL
UPGRADE
PERFORMANCE
PROJECT
IMPROVEMENTS
~NlTAZF.I)
~
I
TECH. SPEC.
LICENSE
IMPROVEMENTS
SCOPE.
. REVITALIZATION LCR
. "MERITS"
DEUVERABL£
ffllP REDUCTION IMPROVEMENTS
- -
MERITS
TARGET
.'I* 'I-I
I
-
I
I
I MAINTENANCE
CM&PM
REDUCTIONS
SCOf'E
//llllNTENANCE WORK ORDERS
- MAJNTC~
RECCURING
TAsa
DELNERABL£
---
- NEAii-TERM llEOucTIONS
LONG-TERll PIA/II
FOR ONGOING PIKJGAM
TARGET
l.';!J .. '
SALEM REVITALIZATION
FUNC,TIONAL DESCRIPTION
SALEM
REVITALIZATION -
.
MATERIEL
MATERIEL
CONDITION
CONDITION
UPGRADES
MAINTENANCE
SCOPE
SCOPE
- '{)Ch
- HOUSEKEEPING
,*.
- PROJECT ENGINEERING
- PAINTING
-.I OE.SIGN
- . INSUlATION
- . INSTALUTION
SIMl'tE W.a :S
- . BUILDINGS/TANKS
DEUVERABL£
DEUVERABL£
- -*-*- -* ---*** -
OESIGN!BUIL T
- NEAR*TCRM
ENGINtERED
PHOJECTS
PROJECTS
_ * . LONG-TERM PLAN
FOR AN ONGOING
PROGHAN!
TARGET
TAHGCT
l:!f~-~
1~*;~:.
i
I PROCEDURE
PERSONNEL
I UPGRADE
PERFORMANCE I
I
PROJECT
IMPROVEMENTS
I.
I
SCOPE
- SCOPE
IMPLEMENTING
VISION
IWOCE:OUHES
. ACC{)(JN I AIJll I TY
- Ht VI T Al U.A TION
PROCEOUHtS
. INll-GHAlt.O SINA fl Gr
OELNERABLE.
DELJVERABLE
HIGHQUALJTYPHOCt.OUHt_-S *
SMETY AS A CUl TUHt:
PHOCEOURC CONTHOl
. IUNDAlllNTAl
SYSTEM
BEHAVIOR CllANIAE
- LlAr TO LlAr SUPPORT
GROUP
-TAllGlT
TAJlGET
l ... '.YL
ON1;tJJN(;
PROJECT STATUS MEETING
~iL.~TERIEL CONDITION PROJECTS
SH ORT *HISTORY*
- JUNE, 1990 - MATERIEL CONDITION STUDY BEGUN
.
.. BROAD SCOPE DEFINITION USED
- SEPTEMBER, 1990 - STUDY CONCLUDED
- B.16 TASK LINE ITEMS IDENTIFIED
-LINE ITEM ESTIMATES RANGED FROM $50K TO 35
MILLION *
-LINE ITEMS INCLUDED ON-GOING PROJECTS
- NOVEMBER, 1990 - PROJECT MANAGER ASSIGNED
- DECEMBER. 1990 - PROJECT TEAM ASSIGNED
- JANUARY, 1991 - STRATEGIC PLANNING DEVELOPED
MMi-37
...
PROJECT STATUS MEETING
- \\IATERIEL CONDITION PROJECTS
MMi-25
MISSION
- IMPROVE HARDWARE WEAKNESSES TO HELP ELIMINATE
PROBLEMATIC.MAINTENANCE ANO -OPERATIONS
CONDITIONS THAT BURDEN NUCLEAR DEPARTMENT
PERSONNEL.
-DESIGN ISSUES (SYSTEM RELIABILIT~ T-MODS,
CONFIGURATION, ETC.)
A DRAWS TECHNICAL ATTENTION
-MATERIEL ISSUES (COMPONENT RELIABILITY,
OBSOLESCENC~ ETC.) :
-
.
- DRAWS MAINTENANCE AND OPERATOR ATTENTION
-WORK LOAD ISSUES (CM/PM BACKLOG, EFFICIENCY,
INDUSTRIAL SAFETY, ETC.)
IA DRAWS MANAGEME-NT ATTENTION
PROJECT STATUS MEETING
MATERIEL CONDITION PROJECTS
OBJE:CTIVES
- ACCOMPLISH MATERIEL CONDITION IMPROVEMENTS
CONCURRENT WITH NORMAL OUTAGE.AND NON-OUTAGE
CYCLES, WHILE:
-MINIMIZING EFFECTS ON PLANT STAFF DURING
PROJECT IMPLEMENTATION
- MAKE A NEAR TERM VISIBLE IMPACT ON PLANT
PHYSICAL MATERIEL CONDITION
- IMPROVE PROJECT PERFORMANCE THROUGH INNOVATIVE
UTILIZATION OF PROCESSES AND RESOURCES
- CONTROL PROJECT COSTS THROUGH IMPROVED PLANNING
AND MANAGEMENT OVERSIGHT
MMi-26
. . .
'
PROJECT STATUS MEETING
MATERIEL CONDITION PROJECTS
-CATEGORIZATION OF LINE ITEMS -
-ELIMINATED
186
-
__.--:----
LARGE SCOPE
505
IMPACT-
125
NOTE:
-
_125 Line 1 teas have been
collbined into 30 Project
Evaiuation Packages (PEPs) -
ra IMPACT
D ELIMINATED
K) LARGE SCOPE
NOTE:
505 Lina iteas have yet
to ba_collbined into PEPs
- STUDY UNCOVERED A TOTAL OF 816 LINE ITEMS OF
POTENTIAL MATERIEL CONDITION TASKS
8 FURTHER REVIEW BY TEAM RESULTED -IN-ELIMINATION
OF 186
-
ALREADY WORKING OR COMMITTED -
-
SPARE PARTS
-
STUDIES
'
-
'
0
1991
1992
1993
1994.
1995
t~o
t
1R~1
t
~ '
.
1R12
2R6
2R7
2R8
- 1-21
PROJECT STATUS MEETING
MATERIEL CONDITION PROJECTS
I.JEVEL OF EFF.ORT PROJECTION
NEAR TERM
IMPACT
2R6 1R10
LARGE SCOPE
1993
1994
1995
+ + + +
2A7
1R11
. 2R8
1R12
PROJECT STATUS MEETING
MATERIEL CONDITION PROJECTS
"
.
.
SLIDES OF SELECT IMPACT. PROJECTS
- REPLACE AUXILIARY FEEDWATER STOP/CHECK VALVES
- UPGRADE LUBE OIL STORAGE FACILITY.
- MAIN CONDENSER MANWAY REPLACEMENT
- PROVIDE PERMANENT DRAINS FOR STEAM TRAPS ON
HEATING STEAM
- REPLACE THE CONTROL AIR DRYERS
- UPGRADE SCREEN WASH PUMP SHAFTS AND COLUMN
PIPES
MMi-30
"
":
PROJECT STATUS MEETING
MATERIEL CONDITION PROJECTS
(
.
OVERVIEW OF. OTHER IMPACT PROJECTS
- ADD 480 V BREAKERS AND CABLE TO CROSS-TIE
BLISSES FOR OUTAGE SUPPORT
- REPLACE REACTOR SUMP PUMPS
- BORIC ACID EVAPORATOR INSTRUMENTATION UPGRADES
- INSTALL PERMANENT PLATFORM A~ LADDER FOR
REACTOR HEAD LIFT RIG
- INSTALL PERMANENT SLUDGE LANCING VALVES
- UPGRADE PAGE SYSTEM TO 5 CHANNELS
- FABRICATE DIESEL GENERATORS LUBE OIL
PURIFICATION SKID
- REPLACE INTER AND AFTER COOLERS OF THE STATION
AIR COMPRESSORS *
MMi-31
p
PEPa
R
0
J
PSPa
E
c
r* . Engineering
p
..
. Inetallatlon
H.
A
- s
E
MMI-33
. ClOHOUt
.PROJECT STATUS MEETING
MATERIEL CONDITION PROJECTS
STATUS* OF. IMPACT PROJECTS
1st
. 2nd.
3rd
.fth
- 1st
2nd.
3rd
Quarter
Quarter
Quarter .
Quarter
Quarter
Quarter
Quarter *
1991
1992
PROJECT STATUS MEETING
MATERlEL CONDITION PROJECTS
. "FLAVOR" OF LARGE SCOPE PROJECTS
- UPGRADE OF TROUBLESOME COMPONENTS, e.g. CONTROL
AIR SYSTEM
- REPLACEMENT/REPAIR OF SMALL BORE PIPING ON
SECONDARY PLANT
- UPGRADE COMPUTER SYSTEMS
- IMPROVE STEAM GENERATOR LEVEL AND FEEDWATER
CONTROL
- REFURBISHMENT ANO/OR
1 LIVE PACKAGING
1 OF SOME
SECONDARY PLANT VALVES
- OVERHAUL OF 4KV SWITCHGEAR BREAKERS AND BUS
ENCLOSURES
- RESOLUTION OF PRESSURIZER CUBICLE HIGK
TEMPERATURES
- ADDRESS MISCELLANEOUS HVAC PROBLEMS
. '
I
tlU.-3-i
L
PROJECT STATUS MEETING
MATERIEL CONDITION PROJECTS
PLANNING, PLANNING, PLANNING
- AVOID CHALLENGING THE PLANT DURING OPERATION
- FULLY SUPPORT FUTURE OUTAGES ANO AVOID
EXTENSIONS
- INTEGRATE PROJECT WORK FOR FUTURE OUTAGES NOW
IMPACT
-2R6 (1991)
-1R10 (1992)
LARGE SCOPE
-2R7 (1993)
-1R11 (1993)
-2R8 (1994)
-1R.12 (1995)
- ADDRESS FUNCTIONALITY, CONSTRUCTIBILITY AND
LOGISTICS CONCERNS IN DESIGN IN MORE DETAIL
DURING THE ENGINEERING PHASE
- ADDRESS RESOURCE ISSUES UP-FRONT TO MINIMIZE
NEGATIVE IMPACTS
I
'
,
PROJECT STATUS MEETING
MATERIEL CONDITIONS PROJECTS
CONCLUSION
-
- DETAILED PLANNING WILL BE USED TO CONFORM THE
AMOUNT OF WORK TO. BE DONE TO OUR ABILITY TO
MANAGE IT SAFELY ANO PRODUCTIVELY
'
!
I
SALEM
,.
, MATERIEL CONDITION
1111-*
MAINTENANCE
PROGRAM
..
, .
,.
.......
"941-39
PROJECT STATUS MEETING
MATERIEL CONDITION MAINTENANCE
PROGRAM* OBJECTIVES
- IMPLEMENT A PROGRAM WHICH WILL INCREASE
THE MATERIEL CONDITION AT SALEM TO A LEVEL
WELL ABOVE THE INDUSTRY AVE~AGE .
- DEVELOP AND/OR REVISE SPECIFICATIONS,
. STANDARDS AND PROCEDURES AS REQUIRED
- PROVIDE AN ORGANIZATION WHICH CAN ASSIST
OTHER PLANT ANO NUCLEAR DEPARTMENT
FUNCTIONAL GROUPS
- SUPPORT AND COORDINATE MATERIEL CONDITION
IMPROVEMENTS AS PART OF SALEM
REVITALIZATION
PROJECT STATUS MEETING
MATERIEL CONDITION MAINTENANCE
PROGRAM SCOPE
MATERIEL CONDITION MAINTENANCE WILL FOCUS ON THE
FOLLOWING AREAS:
- HOUSEKEEPING
- PAINTING
- INSULATION
- BUILDINGS AND TANKS
- MINOR WORK ORDERS AND MINOR MAINTENANCE
- LABELING
MM1--40
PROJECT STATUS :MEETING
MATERIEL CONDITION MAINTENANCE
-
SALEM FACILITIES IN THIS SCOPE
.
.
- UNIT 1 ANO 2 POWER BLOCKS
- CONTAINMENT ..
- AUXILIARY BUILDING
- CONTROL BUILDING
- TURBINE BUILDING
- FUEL HANDLING BUILDING
-CONDENSATE POLISHING BUILDING
o PUMP HOUSE
- HOUSE HEATING BOILER
- UNIT 3
- SERVICE WATER INTAKE STRUCTURE
- CIRCULATING WATER INTAKE STRUCTURE
- NON-RADWASTE BUILDING
- OUTSIDE TANKS
-*
PROJECT STATUS MEETING
MATERIEL CONDITION MAINTENANCE
STRATEGY
- SHORT TERM STRATEGY:
REVITALIZATION PERIOD
-PERIOD DURING WHICH THE STANDARD OF MATERIEL
CONDITION IS RAISED FROM ITS CURRENT LEVELS
TO WELL ABOVE INDUSTRY AVERAGE
- LONG TERM STRATEGY:
MAINTENANCE PERIOD
)041-42
-PERIOD DURING WHICH THE WELL ABOVE INDUSTRY
AVERAGE STANDARDS OF MATERIEL CONDITION ARE
MAINTAINED
STATION
HOUSEKEEPING
I
1
GENERAL
AREA.
PLANT
EQUIPMENT
STATION
LABELING
LABELING
.SUPPORT .
- REVITALIZATION PERIOD
MATERIEL CONDITION
PROJECT ENGINEER
I
STATION
PAINTING
STATION
INSULATION
CONTRACTORS
CONTRACTORS
MINOR
'MAINTENANCE
MINOR
. . MAINTENANCE
CREW
STATION
BUILDINGS
AND TANKS
MAINTENANCE
CREW
CONTRACTORS
PROJECT STATUS MEETING
MATERIEL CONDITION MAINTENANCE
STATION HOUSEKEEPING
RESPONSIBILITY:
- MAINTAINING AND PERFORMING GENERAL CUSTODIAL
DUTIES FOR ALL AREAS ASSIGNED TO THE SALEM
STATION
- CLEANING PLANT EQUIPMENT (EXCEPT ROTATING
EQUIPMENT AND SKIDS - OPERATIONS DEPARTMENT
RESPONSIBILITY)
MM1...:44
STATION PAINTING
RESPONSIBILITY:
- COORDINATION AND IMPLEMENTATION OF ALL SALEM
STATION PAINTING
- DEVELOPMENT ANO IMPLEMENTATION OF THE SALEM
COATINGS PROGRAM
f
,
...
- -
PROJECT STATUS MEETING
MATERIEL CONDITION MAINTENANCE
STATION INSULATION
RESPONSIBILITY:
- COORDINATION AND IMPLEMENTATION OF ALL SALEM
STATION INSULATION
- DEVELOPMENT ANO IMPLEMENTATION OF Tl-E SALEM
INSULATION PROGRAM.
STATION BUILDINGS AND TANKS
RESPONSIBILITY:
- DEVELOPMENT AND IMPLEMENTATION OF THE SALEM
BUILDINGS AND TANKS PROGRAM
- COORDINATION ANO IMPLEMENTATION OF ALL WORK
ASSOCIATED WITH SALEM STATION BUILDINGS AND
TANKS
MM1-45
. .
PROJECT STATUS MEETING
MATERIEL CONDITION MAINTENANCE
MINOR WORK ORDERS AND MINOR MAINTENANCE
RESPONSIBILITY:
- PERFORMING MAINTENANCE ACTIVITIES THAT ARE OF A
LOW PRIORITY, MINOR IN NATURE AND/OR DO NOT
HAVE A DIRECT IMPACT ON THE DAY-TO-DAY.
OPERATION OF THE UNITS
LABELING
RESPONSIBILITY:
- UPGRADING AND IMPROVING THE LABELING AT THE
SALEM STATION
- DEVELOPMENT AND IMPLEMENTATION OF THE SALEM
LABELING PROGRAM
MM1-46
.
' .
PROJECT STATUS MEETING
MATERIEL CONDITION MAINTENANCE
MATERIEL. CONDITION RATING SYSTEM
PURPOSE:
- TO PROVIDE A NUMERICAL ASSESSMENT OF TI£ MATERIEL
CONDITION OF A GIVEN AREA OF THE SALEM FACILITY
. * TO PROVIDE A t£CHANISM FOR FOCUSING MANASEMENT ATTENTION
ANO PLANT RESOURCES *ON DEGRADING AREAS CF TI£ SAIEM
FACILITY
AREAS EVALUATED:
- HOUSEKEEPING
- PAINTING
~ INSULATI~ .
- LIGHTING .
.. EQUIPMENT CONlITION
NUMERICAL RATIN6:
EACH AREA IS WORTH ONE (1) POINT.
TOT AL POINTS ARE FIVE
(5) *
-4.51 TO 5.00 * EXCELLENT
3.51 TO ~.50 * SOOD
2.51 TO 3.50 * ADEQUATE
1.51 TO 2.50 * POOR
- _BLUE
- GREEN
- YELLOW
- ORANGE
0.00 TO t.50 * EXTREMELY POOR * RED
i
.....
PROJECT STATUS MEETING
MATERIEL CONDITION* MAINTENANCE
MANAGEMENT APPROACH
- RED AREAS HAVE HIGHEST PRIORITY FOR FOCUSED
MANAGEMENT ATTENTION AND PLANT RESOURCES
oQRANGE AREAS HAVE 2nd PRIORITY
- YELLOW AREAS HAVE 3rd PRIORITY
- GREEN AREAS HAVE 4th PRIORITY
AREAS IDENTIFIED FOR IMPROVEMENT APPROACHED AS
FOLLOWS:
- HOUSEKEEPING DEFICIENCIES ADDRESSED
- MINOR MAINTENANCE DEFICIENCIES ADDRESSED
- PAINTING DEFICIENCIES ADDRESSED
- INSULATION DEFICIENCIES .ADDRESSED
- LABELING DEFICIENCIES ADDRESSED
MMi-48
. .
PROJECT STATUS MEETING
MATERIEL CONDITION MAINTENANCE
PROGRESS
- 85 AREAS OF THE SALEM STATION EVALUATED USING
THE MATERIEL CONDITION RATING SYSTEM
- LOWEST RATED AREAS RECEIVED HIGHEST PRIORITY*
- AREA IMPROVEMENTS:
- DECON ROOM - HOUSEKEEPING, PAINTING -ANO
EQUIPMENT CONDITION ISSUES ADDRESSED *
- 13 & 23 AUXILIARY FEEDWATER PUMP ROOM -
HOUSEKEEPING, PAINTING AND INSULATION ISSUES
ADDRESSED .
MM1-49
- 11 & 12 AUXL!ARY FEEDWATER PUMP AREA -
PAINTING AND HOUSEKEEPING ISSUES ADDRESSED
- 1A, 2A, 28 & 2C DIESEL GENERATOR ROOMS -
HOUSEKEEPING, PAINTING, INSULATION ANO
LIGHTING ISSUES ADDRESSED
-UNIT 1 & 2 78' EL MECHANICAL PENETRATION
AREA - HOUSEKEEPING, PAINTING AND INSULATION
ISSUES ADDRESSED
. - UNIT 1 88' * EL TURBINE BUILDING - PAINTING
ISSUES ADDRESSED
- UNIT 2 SERVICE WATER VALVE ROOMS -
HOUSEKEEPING, PAINTING, INSt.LATION ANO
EQUIPMENT ISSUES ADDRESSED
)
'
L
I
-
PROJECT STATUS MEETING
MATERIEL CONDITION MAINTENANCE
WORK IN PROGRESS
SHEET 1
- UNIT 1 HIGH PRESSURE TURBINE PIPING
120 FT EL TO 140 FT EL
-REINSULATING ALL PIPING WITHIN THIS AREA ANO
_ PAINTING MISCELLANEOUS STEEL
- 13 AUXILIARY FEEDWATER PUMP ROOM
-ADDRESSED HOUSEKEEPING ISSUES, PAiNTING ROOM
ANO ROOM CONTENTS,
REINS~ATING PIPING
- 1 i" & 12 AUXILIARY FEEDWATER PUMP AREA
-ADDRESSED HOUSEKEEPING ISSUES, PAINTING
WALLS, FLOOR AND PLANT EQUIPMENT UP TO 6 FT
- UNIT 1 88 FT EL TURBINE BUILDING
-STRIPPING OLD PAINT FROM FLOOR ANO
REPAINTING
MM1-50
r
.L
. PROJECT STATUS MEETING
_ MATERIEL CONDITION MAINTENANC*E
WORK IN PROGRESS
SHEET 2
- 2A, 28 ANO 2C DIESEL GENERATOR ROOMS AND
CONTROL ROOMS
-REPAINTING FLOORSr WALLS AND MISCELLANEOUS
STEEL
- UNIT 1 CONTAINMENT
-ADDRESSING INSULATION DEFICIENCIES, PAINTING.
DEFICIENCIES AND HOUSEKEEPING ISSUES
- 11 AND 12 AHR PUMP AND HEAT EXCHANGER AREAS *
MM1-51 .
.
-
- ADDRESSING GROUNO WATER LEAKAGE, PAINTING
ROOM ANO ROOM CONTENTS, REINSULATING PIPING
PROJECT STATUS MEETING
SALEM PROGRESS
e EXTENDED RUNS FOR BOTH UNITS
- TECH SPEC AUDIT PROJECT COMPLETED
- PROCEDURE UPGRADE PROJECT PROGRESSING
(N730 UPGRADED PROCEDURES APPROVED FOR USE)
- MONITORING OF WORK STANDARDS - POSITIVE RESULTS
- OFF HOURS MANAGEMENT TOURS - POSITIVE RESULTS
- IMPLEMENTATION OF
1 HOUSEKEEPING RESPONSIBILITY
BY AREA
1 CONCEPT
- CORRECTIVE ACTION PROCESS STRENGTHENED
-PROMPT DISPOSITION OF FINDINGS VIA STATION
MANAGEMENT MEETINGS
-EFFECTIVENESS REVIEWS UNDERWAY
- >90% IPAT/SALP CORRECTIVE ACTIONS COMPLETED
- 50. 59 PROCESS IMPROVING
(VERIFIED BY RECENT EFFECTIVENESS REVIEW)
- VISIBLE MATERIEL CONDITION IMPROVEMENT
MMi-56
-~'
~,
PROJECT STATUS MEETING
SALEM PROGRESS
ONGOING IMPROVEMENT ACTIVITIES AT SALEM STATION:
- FOCUS ON
I ATTENTION TO DETAIL I
MMi-57
- ADHERENCE TO 'WORK. STANDARDS AND PROCEDURE USE
GUIDELINES'
o RECOGNITION FOR SUCCESS .
- INDIVIDUAL
-TEAM
- STATION
- FOCUS ON PRIDE OF OWNERSHIP
- MAINTENANCE OF A QUESTIONING ATTITUDE
- SOLICIT INPUT FROM EMPLOYEES
- MANAGEMENT INVOLVEMENT
~
- FOCUS ON ACCOUNTABILITY
- PARTICIPATION IN HUMAN RESOURCES TRAINING
- OPTIMIZATION OF PROCESSES*
- CONTINUALLY RAISING STANDARDS AND CLARIFYING
EXPECTATIONS
- STRIVING FOR INDIVIDUAL OWNERSHIP ANO BELIEF IN
THE VISION
PROJECT STATUS MEETING
SU~I~IARY
RADIATION MONITORING SYSTEM
- ROOT CAUSE OF DEFICIENCIES UNDERSTOOD
- NEAR TERM ACTIONS IN PLACE TO MAXIMIZE RELIABILITY OF
CURRENT SYSTEM
- LONG TERM DESIGN CHANGES UNDERWAY
REVITALIZATION
- INTEGRATED REVITALIZATION PROJECT IN PLACE TO
ACHIEVE/MAINTAIN HIGH STANDARDS FOR ALL ASPECTS OF
PLANT OPERATIONS
- MATERIEL CONDITION DEFICIENCIES RECOGNIZED
- MAJOR PSE&G RESOURCE COMMITMENT
- MATERIEL CONDITION REVITALIZATION ADDRESSING HIGH
IMPACT/NEAR TERM Mil LONGER TERM EQUIPMENT UPGRADES
- MATERIEL CONDITION MAINTENANCE GROlP PROVIDING
FOCUSED EFFORT TO lPGRAOE INSULATION. PAINTING,
LABELING
STATION PERFORMANCE
- PERFORMANCE IS IMPROVING IN MANY AREAS
- MULTIPLE INITIATIVES UNDERWAY
MMi-58