ML13329A191
| ML13329A191 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 09/29/1992 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML13329A189 | List: |
| References | |
| 50-206-92-23, 50-361-92-23, 50-362-92-23, NUDOCS 9210230020 | |
| Download: ML13329A191 (53) | |
See also: IR 05000206/1992023
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos.
50-206/92-23, 50-361/92-23, 50-362/92-23
Docket Nos.
50-206, 50-361, 50-362
License Nos.
Licensee:
Southern California Edison Company
Irvine Operations Center
23 Parker Street
Irvine, California 92718
Facility Name:
San Onofre Nuclear Generating Station
Units 1, 2 and 3
Inspection at:
San Onofre, San Clemente, California
Inspection conducted: July 17, 1992 through August 26, 1992
Inspectors:
C. W. Caldwell, Senior Resident Inspector
D. L. Solorio, Resident Inspector
C. D. Townsend, Resident Inspector
Accompanying Inspector: M. Fields, Project Manager
Approved By:
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H. J. Wong,thief
Date Signed
Reactor Projects Section 2
Inspection Summary
Inspection on July 17 through August 26, 1992 (Report Nos.
50-206/92-23, 50-361/92-23, 50-362/92-23)
Areas Inspected: Routine resident inspection of Units 1, 2 and 3 Operations
Program including the following areas: operational safety verification,
radiological protection, security, evaluation of plant trips and events,
engineered safety feature walkdown, plant modifications, licensee self
assessment, calibration, electrical maintenance, falsification of plant
records, monthly surveillance activities, monthly maintenance activities,
independent inspection, licensee event report review, followup of previously
identified items, and a meeting held in Region V. Inspection procedures
37700, 37701, 37828, 40500, 56700, 60710, 61726, 62703, 62705, 71707, 71710,
90712, 92700, 92701, 93702, TI 2515/115 were covered.
Safety Issues Management System (SIMS) Items:
None
9210230020 920930
ADOCK 05000206
0
Results:
General Conclusions and Specific Findings:
Strengths
During simulator observations, the inspectors noted that there were
weaknesses in command and control, and communications during scenarios
involving the emergency operating instructions. The inspector noted that
licensee management had also identified these weaknesses and was actively
involved in enhancing operator performance in these areas (Paragraph
3.b).
The inspector reviewed the licensee's temporary facility modification
(TFM) to the Unit 2 containment purge system. This TFM was implemented
due to leakage across the outboard mini-purge valve. In general, the TFM
appeared to be well designed and implemented (Paragraph 7).
A number of strengths were noted in the licensee's self-assessment
program. The 10 CFR 50.59 safety evaluation program appeared to be
effective in assessing plant changes and deficiencies (Paragraph 13.a).
The licensee's Nuclear Oversight Division (NOD) performed a number of
audits that were critical of licensee performance and that provided
recommendations that were insightful.
One example, concerning operator
performance issues during a recent Unit 3 refueling outage, was
considered valuable in focusing on enhanced performance (Paragraph 13.b).
In addition, a stop work order was issued for welding operations as a
result of a NOD surveillance that identified program weaknesses in the
control of weld filler material (Paragraph 13.c).
Weaknesses
The inspector noted that Maintenance and Station Technical personnel did
not understand the significance of nitrogen leakage from the accumulators
of Unit 1 valve HV852B. The inspector also noted that there was no
formal program to check the sub-components of the accumulators. With the
absence of knowledge as to the impact of nitrogen leakage and the lack of
a surveillance program to monitor accumulator piston location, HV852B was
in a degraded condition when nitrogen leakage occurred over a three month
period. On June 23, 1992, the valve was determined to have been
inoperable based on the results of the significant piston misalignment
identified on May 19, 1992 (Paragraph 15.e).
The licensee performed an evaluation of plant record keeping and found
several examples where log entries were made for areas in which the plant
operator did not enter. The licensee initiated a program to perform
periodic surveillances to ensure that log readings are properly obtained
(Paragraph 12).
The inspector reviewed the licensee's measuring and test equipment (M&TE)
control program. The inspector found that the program was very difficult
to audit. In addition, the inspector considered that the M&TE program
2
was poorly defined and that proper implementation of the program relied
heavily on the M&TE supervisor (Paragraph 11).
The NRC considered that, in general, the licensee correctly assessed
plant problems and effected timely resolution. However, several
weaknesses in timely and thorough assessment of plant problems or in
effective communication of proposed corrective actions to the NRC were
observed. In one instance, prompt visual assessment of pressurizer
instrument line leakage in Unit 3 would have resolved questions that
arose when unidentified leakage from the pressurizer vapor space was
considered to be occurring. In another case, a detailed assessment of
vital battery cracks in Unit 3 took more than a week (the NRC considered
that the licensee's evaluation was still inconclusive).
In addition,
with regard to HV852B, the licensee was not correct in their technical
assessment of the safety significance of the nitrogen leakage. Based on
these examples, the NRC stressed the importance of timely and accurate
assessment of emerging plant problems and encouraged continued licensee
emphasis in this area and effective communications of these problems with
the NRC (Paragraph 8).
Three examples of weaknesses in the interface between Station Technical
and Operations personnel were observed in this report period. Examples
involved performance of an in-service test in Unit 1 (Paragraph 4.b) and
a thermographic test that resulted in a Unit 2 reactor trip (Paragraph
4.a).
The third example involved a discrepancy between the simulator and
the Units 2 and 3 control panel. A change made to the control panel in
1988 was not properly reflected in design documents or in the simulator
due to a poor interface between Engineering and Operations that resulted
in the design change being a backlog item for more than four years
(Paragraph 10).
A similar organizational weakness was also identified in
NRC Inspection Report 50-206/92-20.
During plant tours, the inspector noted that operators were attaching
non-qualified equipment on the Unit 1 safety injection piping without any
evaluation. Further review indicated that there was no specific guidance
for placing temporary non-qualified equipment on or near safety-related
equipment (Paragraph 3.a).
Significant Safety Matters:
Summary of Violations:
One violation was identified during this inspection period which involved
inadequate corrective actions for Unit 1 valve HV852B (Paragraph 15.e).
A non-cited violation is identified in paragraph 14 and is related to the
misalignment of a Unit 2 saltwater cooling pump emergency cooling water
supply valve (LER 50-361/92-09).
Open Items Summary:
During this report period, 4 new followup items were opened and 5 were
closed; I was examined and left open.
3
DETAILS
1. Persons Contacted
Southern California Edison Company
H. Ray, Senior Vice President, Nuclear
- H. Morgan, Vice President and Site Manager
- R. Krieger, Station Manager
- J. Reilly, Manager, Nuclear Engineering & Construction
B. Katz, Manager, Nuclear Oversight
- R. Rosenblum, Manager, Nuclear Regulatory Affairs
K. Slagle, Deputy Station Manager
- R. Waldo, Operations Manager
- L. Cash, Maintenance Manager
- M. Short, Manager, Station Technical
- M. Wharton, Manager, Nuclear Design Engineering
P. Knapp, Manager, Health Physics
W. Zint], Manager, Emergency Preparedness
- D. Herbst, Manager, Quality Assurance
Chiu, Manager, Quality Engineering
J. Schramm, Plant Superintendent, Unit 1
V. Fisher, Plant Superintendent, Units 2/3
- G. Hammond, Supervisor, Onsite Nuclear Licensing
- J. Reeder, Manager, Nuclear Training
H. Newton, Manager, Site Support Services
- R. Plappert, Manager, Technical Support and Compliance
- R. Borden, Supervisor, Quality Assurance
- J. Jamerson, Lead Engineer, Onsite Nuclear Licensing
- J. Travis, Maintenance Manager, Unit 1
- J. Fee, Assistant Manager, Health Physics
- M. Herschthal, Assistant Manager, Station Technical
- A. Thiel, Supervisor, Station Technical
- C. LaPorte, Supervisor, Maintenance
- M. Motamed, Nuclear Safety Group
San Diego Gas and Electric Company
- R. Erickson, Site Representative
City of Riverside
- C. Harris, Site Representative
- Denotes those attending the exit meeting on August 26, 1992.
The inspectors also contacted other licensee employees during the course
of the inspection, including operations shift superintendents, control
room supervisors, control room operators, QA and QC engineers, compliance
engineers, maintenance craftsmen, and health physics engineers and
technicians.
2. Plant Status
Unit 1
Unit 1 operated at power for the entire inspection period.
Unit 2
Unit 2 operated at power until an automatic trip occurred on July 31,
1992. The trip was due to a sensed undervoltage condition created when a
potential transformer drawer was opened (Paragraph 4.a).
The Unit
restarted on August 2, 1992, and operated at power for the remainder of
the inspection period.
Unit 3
Unit 3 operated at power for the entire inspection period.
3. Operational Safety Verification (71707)
The inspectors performed several plant tours and verified the operability
of selected emergency systems, reviewed the tag out log and verified
proper return to service of affected components. Particular attention
was given to housekeeping, examination for potential fire hazards, fluid
leaks, excessive vibration, and verification that maintenance requests
had been initiated for equipment in need of maintenance. The inspectors
also observed selected activities by licensee radiological protection and
security personnel to confirm proper implementation of and conformance
with facility policies and procedures in these areas.
a. Non-Qualified Components Tied To Safety-Related Equipment
During a plant tour on August 13, 1992, the inspector noted that
operators were installing an airhorn (used for cooling) on safety
related equipment in Unit 1. In particular, the operators were
tying the airhorn between a vertical run of safety injection piping
and an associated snubber.
The inspector discussed this with an on
shift senior reactor operator (SRO) who agreed that the action did
not appear to be appropriate.
Discussions with the Unit 1 Operations Superintendent indicated
that, historically, they have allowed operators to hook up cooling
equipment (such as this) to safety-related components on a temporary
basis. In addition, operators were free to make the judgment as to
where to put the equipment. However, this has not been done per the
work authorization process and as a result, installation of the
equipment has not been evaluated in such cases.
The inspector considered that this condition did not appear to be
safety significant since the weight of the airhorn was small in
relation to the size of the piping and supports involved. However,
the inspector was concerned since this could be construed as a
2
modification to the system. As such, it should undergo the
- 0
appropriate reviews. Further review revealed that there was no
direct guidance in any procedure to control this activity.
Procedure S01-7-2, "Main Feedwater System," alluded to the potential
dangers to equipment during a seismic event, but it did not give any
specific guidance for temporary equipment being installed on or near
safety-related equipment.
The inspector discussed this concern with the Unit 1 Operations
Manager who indicated that he would revise documents to provide
better guidance. The inspector will review the licensee's actions
as part of the routine inspections.
b. Simulator Observations
The resident inspectors conducted a number of observations of Units
2 and 3 simulator activities for the period of May to July 1992.
During those observations, the inspectors noted several weaknesses
in crew performance. In particular, weaknesses in command and
control, and communications were observed during simulator scenarios
involving the emergency operating instructions (E0Is).
The
continuation of these types of difficulties was not expected by the
inspector since some crews had been operating together for a long
time; however, the inspector noted that none of the weaknesses
resulted in improper implementation of the EQls.
During the observations, the inspector noted that the licensee was
effectively dealing with these communication and command/control
weaknesses. The shift superintendent (SS) debriefed the crew after
each scenario and the simulator instructors critiqued the SS's
debriefing as well as the crew's performance. The inspector
considered that these critiques were detailed and self-critical.
In
addition, they emphasized the need for better communications and
team work. The licensee's critiques appeared to be valuable in
working through the difficulties observed. The inspector also noted
a considerable amount of management presence at the simulator.
The inspector concluded that, although there were weaknesses in the
performance of several crews, the licensee appeared to be
effectively dealing with them. The inspector encouraged the
licensee's efforts and will continue to monitor the licensee's
performance in this area as part of the routine inspection effort.
No violations or deviations were identified.
4. Evaluation of Plant Trips and Events (93702)
Automatic Trip Due To Opening Potential Transformer Drawer - Unit 2
On July 31, 1992, Unit 2 automatically tripped from 100% power after a
loss of two of the four reactor coolant pumps (RCP's).
The RCP's tripped
on a sensed undervoltage condition when a potential transformer (PT)
3
drawer was opened for thermographic inspections. The reactor trip was
generated from the core protection calculators on a low departure from
nucleate boiling ratio (DNBR) due to the low flow condition on the loss
of two RCP's. In addition, the auxiliary feedwater system automatically
started due to the decrease in steam generator level following the trip.
Both of these automatic functions were expected and performed as designed
for the conditions present.
The thermographic inspections were being performed by Station Technical
(STEC) personnel as part of a routine surveillance in accordance with
STEC procedure S0123-V-2.4, "Thermal Inspection Of Plant Components."
The fact that the RCP's would trip and therefore cause a reactor trip was
not commonly understood, and was not identified either in the procedure
or by the personnel involved in the testing.
The licensee reported in Licensee Event Report (LER)92-012 that the root
cause was attributed to inadequate positive controls in the work package
and an inadequate warning sign on the PT drawer. The licensee is taking
corrective actions to develop positive controls in the work package and
install improved signs. The inspector considered the licensee's
corrective actions to be appropriate. However, this event appears to be
another example in which a STEC program was not adequate to maintain
proper configuration control in the plant. NRC Inspection Report 50
206/92-20 discussed two instances of a weak interface between STEC and
Operations which led to configuration control problems. The licensee
will address the concerns raised in Inspection Report 92-20 in their
response to Notice of Violation from that report.
The inspector noted that Operations personnel had an opportunity for more
effective communications with Station Engineering during a Unit I main
feedwater pump inservice test (IST) in July 1992. In this case, the
engineer was utilizing procedure SO1-V-2.14.10, "Feedwater Inservice Pump
Test," to perform the IST of the west feedwater pump, G3B. Earlier in
the year (on January 2, 1992), an instrument drift problem occurred in
conjunction with the same feedwater pump test (see NRC Inspection Report
92-06).
In the January occurrence, the east feedwater pump discharge
pressure gauge had drifted low. This resulted in the pump being
inoperable (according to the IST program) until the gauge was
recalibrated. In the July case, while it was not Operations
responsibility to assure an accurate gauge was used for the test,
Operations had the opportunity to alert Engineering of the past problem
which resulted in unnecessarily declaring a piece of plant equipment
No violations or deviations were identified.
5.
Monthly Maintenance Activities (62703)
During this report period, the inspectors observed or conducted
inspection of the following maintenance activities:
4
a. Observation of Routine Maintenance Activities (Unit 1)
92071359000
"'Y' Channel SIS Block LED Is
Extinguished on Card 11
LED#3 'X'
Channel Corresponding LED Is Illuminated."
90060431000
"Adjust/Rework N2 Regulators For Train 'B' SIS Valves
As Required."
b. Observation of Maintenance Activities (Unit 3)
CWO 92090192
"Install a Temporary Battery Rack Adjacent to Battery
Rack 3EB007 per Temporary Facility Modification
(TFM)."
No violations or deviations were identified.
6. Engineered Safety Feature Walkdown (71710)
Unit 2
An evaluation of the safety alignments was performed on the Unit 2
Component Cooling Water (CCW) system with no significant findings. The
following drawings and procedures were utilized: Piping and Instrument
Drawings 40126, 40127, 50127, and Procedures 5023-2-17 and SD-S023-400-1
3.
An evaluation was also performed of the Unit 2 Auxiliary Feedwater (AFW)
System safety alignments with piping and instrument drawing 40160. No
significant findings were identified.
No violations or deviations were identified.
7. Plant Modification and Refueling Activities (37700 and 37828)
Temporary Facility Modification On Unit 2 Mini-Purge Line
The inspector reviewed a temporary facility modification (TFM) to the
Unit 2 containment purge system. The TFM was implemented because the
outboard containment mini-purge valve leaked after the completion of
containment venting on four occasions in June and July 1992. The leakage
was determined to be due to buildup of small pieces of debris under the
seat of mini-purge valve 2HV9825.
The scope of the design change was to install one-inch diameter tubing to
the containment air sampling line outside of containment. The tubing was
routed from radiation monitor 2RT7804 to the inlet ducting for normal
containment mini-purge fan flow. The containment purge isolation (CPIS)
contacts in the control circuits for mini-purge isolation valves 2HV9824
and HV9825 were moved to the containment atmosphere sample line isolation
valves HV7800 and HV7801. Due to the reduced purge flow diameter (from
eight inches to one inch), the time to complete a containment purge was
substantially increased.
The inspector noted that a probabilistic risk assessment (PRA) is not
required when performing a 10 CFR 50.59 review. However, the inspector
questioned if the licensee had evaluated the potential impact of having
this line open much longer than when using the eight inch mini-purge line
(almost continuously versus four hours every 20 days).
The licensee
indicated that they had assessed the impact of having the purge line open
continuously. However, as a result of the inspector's question, a
limited PRA assessment was performed in which it was calculated that
there was an insignificant increase in core damage or off-site release
probability as a result of this TFM.
In general, the TFM appeared to be well designed, implemented and within
program requirements. However, the inspector was concerned that there
were no corrective actions other than to blow the debris away from the
seat of HV9825 when the valve was found leaking. This had been done four
times between June 9 and July 2, 1992. Thus, during that period, when
the valve was opened, it could not perform its leak tight function.
However, the inspector considered that this was of minor safety
significance; the licensee assured that the valve was leak tight before
they left it, leakage through the penetration was less than TS allowable,
and the inboard valve appeared to be relatively leak tight.
No violations or deviations were identified.
8. Independent Inspection (40500)
Weaknesses in Timely and Thorough Assessment of Plant Problems or In
Effective Communication of Actions to the NRC
The inspector monitored the licensee's performance in assessing events
and plant problems that had recently occurred. In general, licensee
performance has been adequate in implementing timely and effective
corrective action for plant problems. However, there were several
examples where the NRC considered that performance could have improved or
that more effective communications of assessments and corrective actions
could have been provided to the NRC. In addition to past issues (e.g.,
Unit 1 refueling water storage tank leakage discussed in Inspection
Report 206/92-12), recent examples concerned pressurizer instrument line
leakage in Unit 3, 125 VDC vital battery cracking in Unit 3, and valve
HV852B accumulator nitrogen leakage in Unit 1. The concerns were as
follows:
a) Pressurizer Instrument Line Leakage in Unit 3
On July 20, 1992, the licensee determined that there was a
problem with one of the pressurizer level instruments. The
licensee sampled the containment normal sump and found high
levels of tritium which indicated pressurizer steam space
leakage. The licensee concluded that the steam space leakage
was linked to the problems noted with the pressurizer level
instrument.
6
The small amount of leakage (.076 gpm) was evident by a 5.5%
high deviation in level in Channel Y, transmitter 3LT01102, in
comparison to the redundant channel. It was believed that such
a deviation could be caused by a leak in the reference leg of
the transmitter. As a result, the licensee initiated non
conformance report (NCR) 92070079 to assess the implications of
the leak on the operation of the Unit.
During discussions with the licensee, they were not able to
exclude the possibility that the leak was from the reactor
coolant system pressure boundary. However, they believed that
the leak was most likely from the reference leg isolation valve
(e.g., body to bonnet canopy weld), the flexible hose
connecting the transmitter tubing to the isolation valve, or
the connections between the tubing and the flexible hose. The
licensee also believed that the leakage source was downstream
of a loss-of-coolant-accident (LOCA) limiting orifice. Thus, a
break would be limited to within analyzed values.
The NRC staff was concerned that a crack in small bore tubing
or piping such as this could lead to small break LOCA event.
Data suggested that a leak before break scenario with slow
propagation was not as credible in small bore tubing as it was
in large diameter piping. Subsequent discussions with the
licensee revealed that they were not aware of this concern, but
would consider it in future situations.
Subsequent observations indicated that the licensee's technical
judgement of the situation was correct. However, the NRC was
concerned that they did not perform a visual inspection of the
plant equipment until questioned by the NRC, even though
discussions failed to disprove the presence of pressure
boundary leakage. The NRC considered that, given that the
leakage was unidentified leakage, and that it was possible that
it may not have been isolable, it would have been prudent for
the licensee to conduct a visual inspection without NRC
involvement.
b) Vital Battery Cracks in Unit 3
On July 14, 1992, the licensee identified that cell # 14 of
vital battery 3D1 (125 VDC) had a terminal voltage less than
required by Technical Specifications (TS).
As a result, the
licensee initiated NCR 92070043 to assess the implications of
jumpering out that cell and jumpering in cell 53.
Cell 53 had been jumpered out of the battery with its adjacent
cell, number 54, in May 1992, as a result of several cracks
that radiated out from one of the posts on the top of cell 54
(cells 53 and 54 are located in the same jar).
Since the
licensee was in a short duration action statement (two hours)
with cell 14 inoperable, they performed a quick evaluation of
7
continued operation with cell 53 jumpered in and determined
that it would not adversely impact battery operability. This
was then supported by the licensee's evaluation of the
applicability of a Wyle Laboratory test report for similar
cells with cracks from batteries at Palo Verde Nuclear
Generating Station. Portions of the test report were received
by the Nuclear Engineering Design Organization (NEDO) on July
14 and evaluated. However, the entire test package was not
received until July 17 and the NEDO review was not completed
until July 23, 1992.
The inspector was concerned with the licensee's evaluation of
the condition as detailed in NCR 92070043 as follows:
0
The NCR gave the impression that the licensee had looked
at the issue in more detail than they really had, given
that it was a 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> TS action statement. In fact, the
licensee did not have the opportunity to review the
partial Wyle test results until a day later, and the full
Wyle test package several days later. For example, the
licensee indicated in the NCR that no additional cracking
resulted during the Wyle test of the Palo Verde battery
cells. However, if they had reviewed the preliminary test
package in more detail, they would have found that some
additional cracking took place during the seismic shake
test. It appears that the licensee reached some
conclusions based on a limited review of the information.
The licensee indicated that the mechanism causing the
existing seal nut and jar lid cracking was corrosion
induced. The licensee indicated that a qualitative
assessment by the site materials specialist concluded that
it was not expected that the existing jar lid cracks in
cell 54 would propagate into the jar wall or the other
cell.
However, there was no justification documented to
support this assessment.
The NCR indicated that a seismic test of several cells
with existing jar lid cracks was conducted by Wyle Labs.
The tests (of similarly designed cells used at Palo Verde)
showed that the cells remained operable after a seismic
event. The licensee's NEDO organization completed their
evaluation of the Wyle report and considered that it was
applicable to SONGS. However, the NRC reviewed the Wyle
test report and had a number of questions regarding the
acceptability of the test. For example, the NRC staff
questioned whether or not capacity tests for the cracked
jars were required to demonstrate that the cells could
perform their safety function after a seismic event (in
accordance with American Nation Standards
Institute/Institute of Electronic and Electrical Engineers
(ANSI/IEEE)
Standard 535).
8
The NRC also questioned the lack of acceptance criteria
and requirements for monitoring electrical functions such
as current and voltage during and after the seismic tests.
As a result of the above observations, the NRC was concerned
that the licensee made their judgements without having a
detailed assessment that was applicable to SONGS until nine
days after the problem was identified. In addition, several
questions remained unresolved as of the end of this inspection
period. The inspector noted that additional corrective actions
were implemented after the close of this inspection period. In
particular, the licensee added a temporary battery rack and
jumpered in four new cells (in place of cells with existing
cracks).
Discussions with the Vice President and Site Manager indicated
that the licensee agreed that they did not do a complete
analytical evaluation, but they believed that their engineering
judgement at the time was satisfactory. The NRC is still
reviewing this matter.
c) Nitrogen Leakage from Unit 1 Valve HV852B
As discussed in Paragraph 15.e, the inspector was concerned
that the knowledge of the personnel evaluating the condition of
HV852B was insufficient to identify that the excessive nitrogen
leakage could.affect piston positions and valve stroke timing.
In this case, the technical judgement of the condition was not
adequate and a more timely and thorough assessment of the
problem could have prevented further degradation of the valve.
In addition, ultrasonic testing of similar valves would have
been appropriate to ensure operability when the problem with
HV852B was first identified.
The NRC considered that, in general, the licensee correctly assesses
plant problems and effects timely resolution. A recent example was
noted when the licensee entered Unit 2 containment to verify
adequate reactor coolant pump (RCP) 2P003 oil sump level when
anomalies were noted with the sump level transmitter. Although the
licensee was correct in their assessment, as discussed in the first
example, a visual assessment of the instrument leakage would have
left no doubt as to the condition of the pressurizer instrument
line. In the second example, a detailed assessment of the battery
cracks took a week and the NRC considered that it was still
inconclusive. In the third example, the licensee was not correct in
their technical judgement of the significance of nitrogen leakage in
HV852B. As a result, the NRC stressed the importance of timely and
accurate assessment of emerging plant problems and encouraged
continued licensee emphasis in this area, accompanied by more
effective communications of these problems to the NRC.
No violations or deviations were identified.
9
9. Electrical Maintenance (62705)
The inspector continued with a review of electrical maintenance issues.
In particular, the licensee's performance of battery surveillance testing
was reviewed during this inspection period. In general, surveillances
were performed adequately. However, one concern was identified as
discussed below.
On the morning of July 14, 1992, the licensee identified that cell 14 of
125 VDC vital battery 3D1 had an individual cell voltage (ICV) reading
less than required by TS. As a result, the licensee initiated NCR
92070043 to assess the implications of jumpering out that cell and
jumpering in cell 53 as discussed in paragraph 8b.
The inspector noted that as soon as the problem with cell 14 was
identified, maintenance personnel stopped, as required by procedure, and
contacted appropriate personnel for resolution of the inoperable cell.
As a result, the inspector was concerned that the licensee did not check
the specific gravities of the cells after the ICV measurements revealed
that cell 14 was inoperable. Apparently, the assumption in the procedure
was that there was no reason to believe that there might be multiple cell
failures.
The inspector noted that approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> passed before
the surveillance testing of the battery was continued. Engineering
evaluations had been performed assuming only one inoperable cell.
The inspector noted that cell 29 in battery 3D1 had been a poor performer
for several years. During performance of the July 14 surveillance test,
the specific gravity of cell 29 was greater than 20 points below the
average of the rest of the cells. However, the specific gravity of the
cell was greater than 1.195 (a TS limit).
Thus, the cell was operable
although degraded. The inspector was concerned that if the cell had been
inoperable on low specific gravity, it would not have been noticed until
the evening of July 14, long after the two hour TS action had expired.
The inspector discussed with the Maintenance Manager the concern that
current battery surveillance test methods could prevent detection of
multiple inoperable cells for periods of time exceeding TS allowable.
The Maintenance Manager indicated that he would evaluate the inspector's
concern. This evaluation will be reviewed as part of the routine
inspection effort.
No violations or deviations were identified.
10. Discrepancy Between Simulator And Control Room Panel (71707, 37700,
37701)
On June 3, 1992, the inspector was observing simulator training
activities when a difference between the simulator and the Units 2 and 3
control panels was noted. The inspector discussed this condition with
the control operators and the simulator instructors and noted the
following discrepancy.
10
In 1988, an NRC safety system functional inspection of several safety
systems identified a concern with operation of the component cooling
water (CCW) system. The concern was that the CCW surge tank outlet
valves would shut on a low-low level in the tank to prevent air binding
of the CCW pumps. However, it was postulated that this isolation feature
could result in a loss of net positive suction head for the pumps during
a seismic event concurrent with a break in the non-critical CCW loop. As
a result, the licensee removed the surge tank outlet valve thermal
overloads.
The change to the physical configuration of the plant was such that
removal of the thermal overloads would prevent operation of the valve
from the control room or on a low surge tank level.
The valves had to be
shut locally by manual operation. However, this design change was not
reflected in the simulator as observed during the scenario when the valve
closed automatically.
The inspector discussed this concern with the licensee who had performed
an assessment of the situation. Surveillance report SOS-235-92
documented the licensee's review. The licensee found that the change to
the valve control circuitry was assessed through the disposition of an
NCR, and it was to be implemented by a maintenance order (MO) and a
proposed facility change (PFC).
The licensee determined that
implementing the change in this manner was allowed by procedure. The
evaluation revealed that the MO was implemented, but, the PFC was not.
Instead, a retrofit problem report (RPR) was written in 1989. The
Construction Organization (also referred to as "Projects") was unable to
implement the PFC due to disagreements between Operations and the Nuclear
Engineering and Design Organization (NEDO)
as to what the full scope of
the change would be. The RPR remained unanswered since 1989 and went
into the backlog of items awaiting attention by the licensee.
The licensee determined that Units 2 and 3 operated in a plant
configuration that was not reflected in the appropriate design documents
or in the simulator for over 4 years. The licensee considered that there
was no programmatic or procedural non-compliance with this concern.
However, the root cause was that existing programs did not make
supervision and upper management aware when due dates were not met,
allowing a backlog of documents to accumulate.
In addition to the concern with the backlog of items, the inspector noted
that in this instance, a poor interface between and within organizations
existed. In particular, Operations did not like the PFCs, the Station
Technical engineers were not aware of the status of their assigned system
configurations, and it appeared that STEC was expecting NEDO to do all of
the design corrections and changes without NEDO being aware of that
expectation.
Corrective actions included revising the appropriate design documents to
correctly reflect that the thermal overloads (for the respective CCW
surge tank outlet valves) had been removed. The simulator was brought up
to date on June 12, 1992. In addition, the licensee was in the process
11
of modifying procedures to require higher levels of management review to
ensure that each backlog item received an adequate evaluation.
The inspector considered that the effort by the Nuclear Oversight
Division to determine the scope and the root cause of this problem to be
critical and thorough. The inspector also noted that the licensee has
been aggressively pursuing the reduction of backlog items so that items
such as this should be identified and resolved in a more timely manner.
No violations or deviations were identified.
11.
Review Of Licensee's Measuring And Test Equipment Program (56700)
The inspector performed a review of the licensee's measuring and test
equipment (M&TE) program to determine if the portable equipment was
properly controlled and capable of ensuring the operability of installed
plant equipment. The inspector found that the control of M&TE equipment
was very difficult to audit. In addition, the inspector considered that
the M&TE program was poorly defined and that the proper implementation of
the program relied heavily on the M&TE supervisor.
The inspector noted that the program was difficult to audit since
portions of the documentation were located at the site and the remainder
were at the licensee's Shop Services and Instrumentation Division (SSID)
facility in Westminster, California. In addition, much of the
documentation had to be indexed and cross-referenced manually. Equipment
"travelers" (used to monitor the use of M&TE as discussed below) was one
type of document that was particularly difficult to retrieve.
The inspector considered that the poor program definition could lead to
installed plant instrumentation being out of tolerance for long periods
of time based on the following observations:
o
M&TE used in performing a maintenance activity was recorded in the
Maintenance Order (MO). It takes many months for the MO and M&TE
information to get recorded in the computer database. As a result,
the licensee had implemented a document called a "traveler" which
was provided to the technician with each piece of M&TE issued from
the tool room. The user recorded on the traveler (not a controlled
document) which maintenance/surveillance activities the piece of
M&TE was used in. When the M&TE was returned, the traveler
information was loaded into a database for tracking its use. Thus,
if a calibration failure notice (CFN) was issued on that M&TE, the
plant equipment that it was used on could be easily tracked.
This system places heavy reliance upon individuals to properly fill
out this paperwork and return all pages to the tool room upon
completion of use. This was complicated somewhat by the fact that
procedures allowed different individuals to use the same piece of
test equipment (M&TE). Therefore, the person responsible for the
accuracy of the traveler would change. If a page was lost or
information was improperly recorded, then usage of the M&TE on plant
12
equipment could not be established until the MO was loaded into the
database some months later. If no usage was shown in the computer
(e.g., a lost traveler), then the CFN would not get evaluated for
potential impact on installed plant equipment. The only exception
was M&TE used by the Quality Control (QC) organization, which has
its own program for dealing with CFNs.
o
Approximately one-third of the time, CFNs went unanswered or
unassessed for more than 30 days.
o
The requirements for what to do when a piece of M&TE had sequential
calibration failures were not well defined in the SSID or site
procedures.
o
Procedural guidance was weak in defining the situations when
technicians needed to verify the accuracy of test equipment before
or after using it on installed plant equipment. Thus, if a piece of
M&TE had gone out of calibration during the interval, this fact may
not be identified until it was sent to SSID for a calibration check.
This could result in a long interval in which the calibration status
of plant equipment could be in question.
o
There was no easy way to find a detailed history of calibration
failures in the measuring and test equipment data base. Thus, a
technician would not know if there had been a history of problems
with the equipment being used.
o
When a CFN was received from SSID, the first line supervisor was
responsible for evaluating the condition and the M&TE supervisor
verified the first line supervisor's assessment. The inspector
noted that the resolution of the M&TE supervisor's comments
contributed to the excessive time used to respond to CFNs.
o
It took greater than 30 days (40% of the time) for the M&TE to be
calibrated and returned to the site after being sent to SSID. This
could lead to excessive periods during which plant equipment could
be out of calibration.
The inspector discussed these concerns with licensee management. To the
licensee's credit, a quality action team (QAT) was assembled to address
other M&TE issues (such a temperature sensitivities of M&TE) as a result
of a Nuclear Oversight Division audit. The inspector noted that the QAT
was aware of the extensive time to return M&TE after it was sent off-site
and the excessive time to respond to CFNs. The licensee indicated that
the QAT would factor the inspector's concerns into their evaluation of
the M&TE program. The inspector also noted that the licensee was in the
process of implementing a program to track the history of calibration
failures of equipment.
As of the end of this inspection period, no operability issues were
identified. However, the inspector was in the process of performing
documentation reviews to determine if personnel practices were adequate
13
to compensate for the weaknesses in program definition. The inspector
will continue a review of M&TE activities as a Followup Item (50-361/92
23-01).
12.
Verification Of Plant Records
Temporary Instruction (TI) 2515/115 to the NRC Inspection Manual was
issued to provide guidance for evaluating each licensee's ability to
obtain accurate and complete log readings from either licensed or non
licensed personnel.
The inspector reviewed the licensee's program to
determine if SCE had implemented a self-monitoring program which could
detect plant mechanics, technicians, or operators whose practices might
have included falsifying logs.
The inspector discussed this issue with the licensee in June 1992. At
the time, the licensee did not have a program to verify plant records.
However, after review of the issue, as discussed in NRC Information
Notice 92-30, "Falsification Of Plant Records," the licensee elected to
implement such a program. In August 1992, the licensee issued quality
assurance guideline (QAG)-005 to provide a periodic surveillance program
for comparative analysis between documented division surveillance
requirements and security access records data.
The inspector reviewed the QAG and considered that it would be effective
in detecting personnel practices which might lead to falsified log
readings. The inspector also noted that the Vice President and Site
Manager issued a memorandum to all nuclear organization personnel on May
21, 1992, dealing with the issue.
The licensee also performed an assessment of log keeping practices of
plant equipment operators for the period of April 4 to April 7, 1992.
Several inconsistencies with operator round sheets were noted and
documented in surveillance report SOS-195-92, "NRC Information Notice 92
30:
Falsification Of Plant Records." In particular, the following
concerns were identified:
O
A non-licensed nuclear plant equipment operator (NPEO) did not make
the required vital area entries to perform shiftly surveillances on
three occasions, but signed the surveillance indicating that he had.
According to the licensee's surveillance, on March 8 and April 4,
1992, the night shift Radwaste NPEO (commonly referred to as the 43
position) was required to enter the Units 2 and 3 control element
drive mechanism control system (CEDMCS) vital area by procedure
S023-0-9, TCN 0-29, "Routine Rounds and Inspections." The NPEO was
required to make a general area inspection of equipment (e.g.,
panels, motor-generators, relays, etc.) in the Unit 2 CEDMCS room as
required by the rounds sheet and document any abnormalities.
However, contrary to the requirement of the operator rounds sheet,
the assigned responsible NPEO did not enter the area as reflected by
plant security data. In addition, on March 18 the same operator did
not enter the Unit 2 main steam isolation valve area on March 18,
1992, as required by the (23 position) operator round sheet. In
14
this case, the NPEO was required to make a general area inspection
and take specific readings of instrumentation associated with the
atmospheric dump valves, main steam isolation valves, and other
safety-related equipment.
In the cases discussed above, there did not appear to be any safety
significance to the failure to make the appropriate area entries
since subsequent operator rounds indicated that the equipment was
functioning properly. The licensee took disciplinary actions
against the equipment operator. Failure to take and record
information that is complete and accurate in all material respects
is an Unresolved Item pending the NRC's determination of the policy
for handling these types of record discrepancies (Unresolved Item
50-361/92-23-02).
Three examples were identified in which two NPEOs allowed their
trainees to enter an area without the assigned responsible NPEO in
attendance to perform rounds required by S023-0-5, TCN 0-1, "Plant
Equipment Operator's Responsibilities and Duties."
In particular,
on April 6, 1992, the responsible NPEO (turbine building 24
position) did not enter the Unit 2 non-1E uninterruptible power
supply (UPS) vital area or the Unit 2 salt water cooling (SWC) pump
room. On April 7, 1992, the (24 position) NPEO did not enter the
Unit 2 non-1E UPS vital area. In addition, on April 8, 1992, the
(24 position) NPEO did not enter the Unit 2 non-1E UPS area or the
Unit 2 SWC pump room. Instead, on these occasions, non-qualified
trainees entered these areas to take readings.
This practice is contrary to the licensee's procedural requirements.
In particular, procedure S0123-0-20, "Use Of Procedures," Revision
0, TCN-6, specified that, "Only qualified operators are permitted to
obtain readings required by Operating Instructions unless
specifically allowed otherwise by the procedure." In addition, the
procedure specified that the assigned responsible NPEOs sign for
performance of the surveillance. In the cases discussed, the NPEO
was required to make a general area inspection of pumps, motors,
piping etc. There did not appear to be any safety significance
since subsequent operator rounds indicated that the equipment was
functioning properly. The licensee counseled the individuals
involved on the inappropriate use of trainees in these instances.
This is an Unresolved Item pending the NRC's determination of the
policy on handling these types of record discrepancies (Unresolved
Item 50-361/92-23-03).
Two unresolved items were identified.
13.
Licensee Self Assessment (40500)
a. 50.59 Program Assessment
A resident inspector and the Nuclear Reactor Regulation (NRR)
project manager reviewed the licensee's 10 CFR 50.59 evaluation
15
program to determine its adequacy for performing effective safety
evaluations.
Attachment 3 to Nuclear Engineering, Safety, And Licensing (NES&L)
procedure 24-10-15, "Preparation, Review, And Approval Of Facility
Change Evaluations (FCEs) for SONGS 1,2 & 3," was reviewed to
determine the adequacy of the program in implementing 10 CFR 50.59
requirements and its conformance with Nuclear Safety Analysis Center
(NSAC)-125 recommendations. The inspector also reviewed the
licensee's training program and several completed 50.59 evaluations.
In general, it was considered that the program was adequate and
conformed to NSAC-125 recommendations. The project manager reviewed
a number of safety evaluations and considered that they were
adequate. However, the project manager considered that the process
by which SCE identifies licensing criteria and their impact on the
safety evaluation could be enhanced. In particular, there were
examples noted in which the safety evaluations did not list all the
licensing criteria considered in the 50.59 evaluation. The project
manager attributed the weakness of some safety evaluations to the
following observations:
o
There was not a formal process for verifying that the proper
licensing design bases were chosen by the engineer performing
the 50.59 evaluation.
0
10 CFR 50.59 evaluations sometimes did not list the licensing
design bases of the components under consideration (e.g.,
backup nitrogen supply for the CCW surge tank simply stated
that CCW performs heat removal from accidents in Chapter 15 of
the FSAR).
It was not discussed in the safety evaluation which
accidents were actually being considered.
The inspector concluded that the licensee's program was adequate and
should result in sound, justified safety evaluations. However, the
inspector discussed the observations noted above with the
appropriate licensee management for evaluation. The licensee's
evaluation will be reviewed as part of the routine inspection
effort.
b. Operator Performance Issues During The Unit 3 Refueling Outage
As a result of the inspector's concern over the number of operator
errors during the Unit 3 Cycle VI refueling outage, the licensee
reviewed selected events to determine if there was a common cause.
The results of the review were addressed in a memo from C. Chiu to
R. W. Waldo and J. L. Reeder, dated August 24, 1992. In that
evaluation, the licensee considered that these events were primarily
the result of individuals performing tasks that were only done
infrequently or individuals performing routine tasks under
infrequently occurring plant conditions or system lineups.
In
addition, the licensee considered that there were weaknesses in the
.16
operation and method of controlling operations for the spent fuel
pool cooling system.
As corrective actions, the Nuclear Oversight Division recommended
that the licensee form a QAT to address improvements in the
operation of the spent fuel systems. In addition, prior to future
refueling outages, training should develop a lessons learned
training course to heighten awareness of things to look for during
off normal conditions.
c. Stop Work Order For Welding Operations
On August 25, 1992, the Maintenance Manager issued a stop work order
for all welding as a result of a Quality Assurance surveillance that
found uncontrolled weld filler material.
The order was applicable
to all work except that specifically approved by the Maintenance
Manager. The majority of the filler material (rods) was found at
the Mesa facility and at the Administrative Warehouse & Supply/Shop
Building (AWS) machine shop. However, some was found in the plant.
For corrective action, the licensee planned on retaining tight
restrictions on the use of filler material and performing a
maintenance incident investigation report. As of the end of this
inspection period, there were no indications that there was impact
on plant safety. The inspector will monitor the licensee's actions
to resolve this issue as followup item (50-206/92-23-04).
No violation or deviations were identified.
14.
Review of Licensee Event Reports (90712, 92700)
Through direct observations, discussion with licensee personnel, or
review of the records, the following LERs were closed:
Unit 1
91-14, Revision 0
"Entry Into 3.0.3 Technical Specifications Due To
Inoperable Volume Control Tank Level Transmitter."
92-01, Revision 0 "HV852B Inoperable Due To Hydraulic Accumulator
Piston Level."
92-02, Revision 0
"Shift Supervisor And Control Room Supervisor Both
Left Control Room."
Unit 2
88-15, Revision 1 "Operator Error Causing Fuel Handling Isolation
System Response."
91-08, Revision 0
"Erratic Ammonia Analyzer Caused Toxic Gas Isolation
System To Actuate."
17
92-02, Revision 0
"Inadvertent Control Room Isolation System
Actuation."
92-04, Revision 0
"EFAS Manual Actuation After Loss Of One Main
Feedwater Pump."
92-09, Revision 0 "Saltwater Cooling Valve MU019 Out Of Position
(Closed) Greater Than 72 Hours."
This LER describes the licensee's failure to maintain a pump
cooling water valve open and is considered a violation of
Technical Specifications 3.7.4. This violation will not be
subject to enforcement action because the licensee's efforts in
identifying and correcting the violation meet the criteria
specified in Section VII.B of the Enforcement Policy.
Unit 3
92-03, Revision 0 "Reactor Coolant Pump Trip Due To Faulted Surge
Capacitor."
One non-cited violation was identified.
15.
Follow-Up of Previously Identified Items (92701)
a.
(Closed) Open Item (50-361, 50-362/91-01-05) "Temperature
Sensitivity of Excore Nuclear Detectors"
The NRC instrument and control (I&C) setpoint team noted that the
excore nuclear instrument detectors could be subject to elevated
temperatures during certain accident conditions. The licensee did
not have information on the affect of elevated temperatures on
excore detector uncertainty calculations.
As a result of the concern, the licensee obtained vendor
certification that the excore nuclear instrument detectors would not
be effected by elevated containment temperatures.
The inspector reviewed the vendor information and concluded that it
supported the conclusion that excore nuclear instrument detectors
would not be effected by elevated containment temperatures. Based
on the inspector's review, this item is closed.
b. (Closed) Unresolved Item (50-361, 50-362/91-01-06) "Inaccurate
Calculation of Instrument Uncertainties for Emergency Operating
Instructions"
The licensee prepared and submitted to the NRC, for approval, a TS
amendment requesting that certain transmitter surveillance intervals
be changed from 18 months to 24 months. One of the supporting
documents for the amendment was Functional Analysis M-89068,
18
"Accident Monitoring System and Remote Shutdown Panel." An NRC I&C
setpoint inspection team reviewed Function Analysis M-89068 and
found errors in the document. Based on the number and types of
errors identified, the team questioned the validity of the document
as a supporting document for the TS amendment.
Based on the findings, the licensee:
o
withdrew the TS amendment request,
o
committed to review the implications of the inaccuracies in
M-89068 on their emergency operating instructions, and
o
committed to perform a review of the technical validity of
M-89068.
The licensee review concluded:
o
Calculation M-89068 did not receive the proper engineering and
quality assurance review required for engineering documents.
o
The results of M-89068 did not support the extension of
surveillance intervals.
Based on the NRC findings and the licensee review, the licensee
performed new calculations for instrument uncertainties. These new
calculations showed that instrument uncertainties were larger than
had been previously utilized in certain emergency and abnormal
procedures. Based on the results of the new calculations, the
licensee concluded that no safety limits would have been exceeded in
emergency or abnormal operating procedures. However, the licensee
found that conditions such as the lifting of safety relief valves
might occur, even when the operators were in compliance with
abnormal operating limitations. The licensee concluded that
emergency and abnormal operating procedures required revision to
incorporate the revised calculated instrument uncertainties. The
licensee committed to make these changes.
The inspector reviewed the licensee's administrative actions and
found them adequate; therefore, this item is closed.
Review of the new calculations and changes to emergency and abnormal
operation procedures will be accomplished as part of Unresolved Item
(50-361, 50-362/91-01-09).
c.
(Closed) Unresolved Item (50-361, 50-362/91-01-08) "Validation of
Study M-89047"
The NRC I&C setpoint team noted that Study M-89047, "Instrument
Drift Study," was performed during the same time frame as Functional
Analysis M-89068. The team was concerned that the type of errors
found in M-89068 were contained in M-89047.
19
The team noted that in a TS Amendment request, the licensee had
stated that M-89047 was based on worst case instrument drift. The
team noted that only 1/2 the data was analyzed to determine worst
case. Data was available for both increasing data points and
decreasing data points. The licensee had only considered the
increasing data, which did not always include the worst case drift.
The team concluded that the licensee had not used the worst case
drift values as stated in the TS amendment request. Based on the
problems with M-89068 and the team's finding that the worst case
drift data had not been used as stated, the licensee agreed to
determine if M-89047 was a valid study.
The licensee acknowledged that the wording of the TS amendment may
have been misleading. The licensee hired an independent contractor
to validate study M-89047. The contractor, Tetra Engineering Group,
concluded that study M-89047 contained valid data. In addition, the
licensee refined the study to use all the increasing data points.
The inspector questioned the omission of the decreasing data points,
and pointed out that many instrument safety functions occur on
decreasing data points.
The licensee stated that use of only increasing data points was
acceptable because the uncertainty associated with the decreasing
data points was covered by a separate uncertainty, hysteresis. The
licensee stated that customizing the drift analyses to match the
safety function (increasing or decreasing) for each transmitter was
an unnecessary complication. The licensee noted that study M-89047
was only for long term drift and not for evaluation of the
performance of an individual transmitter.
The inspector reviewed the study validation done by Tetra
Engineering Group and the licensee's evaluation of the use of only
increasing data for drift studies. The inspector concluded that the
study provided acceptable technical information to track long term
instrument setpoint drift at SONGS. This item is closed.
d.
(Open) Unresolved Item (50-361, 50-362/91-01-09) "Instrument
Uncertainties for Emergency Operating Instructions"
The NRC I&C setpoint team determined that the uncertainties for a
number of instruments associated with Emergency Operating
Instructions were incorrectly calculated in Functional Analysis
M-89068. The licensee agreed to recalculate the instrument
uncertainties and change the EOIs as required.
As noted in Section 15.b above, the licensee performed new
calculations associated with M-89068 and determined that some
procedural changes would be required.
NRC review of the new calculations and modified procedures will be
accomplished under this Unresolved Item.
20
e. (Closed) Unresolved Item (50-206/92-20-01) Temporary Waiver of
Compliance From Technical Specification 3.3.1 For Safety Injection
Valve HV852B
On May 19,
1992, while Unit 1 was at 92% power, main feedwater (MFW)
pump discharge/safety injection (SI) isolation valve HV852B was
removed from service for corrective maintenance (reference NRC
Inspection Report 92-20, paragraph 4.a for further discussion).
Maintenance was performed on the valve accumulators to replace the
nitrogen addition valves (schrader valves) since the valves were
leaking nitrogen. The nitrogen leakage had increased until
recharging of the accumulators was performed approximately once
every three days.
The design of hydraulic valve (HV) HV852B is to open with a
pneumatic-hydraulic pump, and to close (its safety-related function)
by two nitrogen-hydraulic fluid accumulators connected to the valve
actuator. The nitrogen in the accumulators is separated from the
hydraulic fluid by a piston with seal rings. The accumulators were
modified in 1976 to use pistons to isolate the hydraulic fluid from
the gaseous nitrogen. The nitrogen in the accumulators provides the
motive force necessary to displace the hydraulic fluid from the
accumulator, which is used to move the valve to its closed SI
position. Nitrogen was added to the accumulators by connecting a
high pressure nitrogen cylinder to accumulator schrader valves
(located on top of accumulators) through a charging manifold.
On May 19,
1992, upon removal of the schrader valves from the top of
the accumulators, the positions of the pistons were measured using
reach rods. The pistons were found to be mis-aligned, one at the
top-most position of its stroke and the other at the bottom-most
part of its stroke. Operability of the valve was indeterminate at
that time. Station Technical (STEC) initiated an evaluation, but an
NCR (which was required for conditions of this type) was not
initiated until approximately one month later, on June 17, 1992.
The inspector reviewed the NCR procedure and noted that there were
no requirements with respect to timeliness of issuing NCRs for non
conforming conditions. The mis-alignment of the pistons had
occurred due to leakage from one of the accumulator schrader valves
being greater than the other.
Immediate corrective actions consisted of replacing the schrader
valves, restoring the pistons to an even alignment, recharging the
accumulators with nitrogen, and returning HV852B to service on May
19, 1992.
On June 23, 1992, STEC, in conjunction with vendor calculations,
concluded that HV852B was inoperable in the as-found condition on
May 19, 1992. Calculations performed by the vendor indicated that
with the nitrogen and hydraulic fluid volumes as found, HV852B would
have stroked closed only 95% of its required travel.
With HV852B
inoperable, Unit 1 Technical Specifications (TS) 3.3.1, "Safety
21
Injection, Recirculation, and Containment Spray Systems" required
entrance into TS 3.0.3 because TS 3.3.1 did not provide an action
statement for the inoperability of HV852B. Technical Specification 3.0.3 required HV852B to be returned to operable status within one
hour or commence a reactor shutdown. On July 23, 1992 the licensee
submitted Unit 1 Licensee Event Report (LER) 1-92-01 describing the
events surrounding the inoperability of HV852B.
Failure of valve HV852B to fully close (there is one valve per SI
train) was not a safety significant issue because downstream main
feedwater (MFW) regulating, bypass, and motor operated isolation
valves also receive a signal to close on safety injection
initiation. These downstream valves were designed to close against
full system pressure, were incorporated into the valve inservice
testing program, were safety-related valves, and would close in a
time frame similar to HV852B. The inspector reviewed records for
previous stroke time testing of these valves and found them to be
satisfactory. Therefore, in the event of a failure of the HV852
valves to fully close, flow to the SGs would have been isolated by
the MFW regulating, bypass, and motor operated isolation valves.
The inspector noted that valves HV854A,B and HV852A,B (four valves
total) are of the dual accumulator design. Without a surveillance
program to monitor the piston position in the accumulators, there
was a potential for all four valves to be affected similarly by
continued nitrogen leakage. Valves HV854A,B and HV852A were
verified in June 1992 to have the accumulator pistons in such a
position that valve operability was not affected. In addition,
there had been no excessive nitrogen leakage noted by licensee
personnel of the accumulators for these valves.
The inspector noted that had one of the HV854 valves been found not
able to fully close (one HV854 valve per SI train), this would have
been much more significant.
The HV854 valves close on SI actuation
to preclude injecting unborated water from the condenser into the
reactor coolant system (RCS). A failure of the HV854 valves to
fully close would have prevented injection of borated water from the
refueling water storage tank to the RCS.
This was because the HV851
(SI outlet valves to RCS) valves were interlocked such that they
would not open until the HV854 valves were fully closed.
Based on the events associated with HV852B and the review of LER 50
206/92-01, the inspector had the following concerns:
o
Vendor manuals and maintenance procedures did not provide
adequate information for on-line charging of the HV
accumulators (HV851, HV852, HV853, and HV854) in that the
information provided was based on maintenance being done in the
maintenance shop rather than in the field.
"
Even with vendor assistance, when developing the initial
accumulator recharging procedures in 1986, the potential for
22
piston mis-alignment as the result of accumulator leakage was
not recognized.
The knowledge level of the personnel evaluating the condition
of HV852B was insufficient to identify that excessive leakage
could affect piston positions and stroke time, and therefore
valve operability. The inspector noted that early discussions
with personnel indicated that the repeated charging was
considered to be acceptable.
o
The potential impact of the increased accumulator charging
frequency was not discussed with the vendor until May 1992.
o
Neither vendor nor SCE instructions identified the importance
of checking accumulator piston location, especially regarding
frequent accumulator recharging. There were no programs, such
as routine surveillances, to check piston locations.
Such
activities would have clearly identified degrading conditions
(i.e., accumulator pistons changing locations).
Further, the
inspector noted that the licensee had no formal program to
check sub-components of equipment to ensure that they will
function properly.
o
On June 17, 1992, a Temporary Waiver of Compliance was
requested to regain lost margin for the HV851A accumulator
piston due to leakage from the hydraulic oil side of the
accumulator (for further discussion reference NRC Inspection
Report 92-20, paragraph 4.b).
Prompt verification of other
accumulator piston locations, after HV852B was discovered in an
inoperable condition, would have identified that HV851A was
degrading due to hydraulic oil leakage earlier.
The inspector concluded that the increased accumulator leakage and
repeated charging was not recognized by SCE as a condition which
could affect valve operability. In addition, an NCR to evaluate the
as found condition of HV852B was not written for almost one month.
Also, other MFW and SI accumulator piston locations were not
determined until over one month after discovering HV852B in its
degraded condition. While the actual safety significance of the
valve inoperability is low as described above, the inspector
considered that the inoperable condition of HV852B as found on May
19, 1992, was a violation in that the licensee actions were
inadequate to quickly identify and correct the degraded condition of
HV852B (50-206/92-23-05).
Additionally, the inspector noted that there was not a formal
program to check the sub-components of the accumulators. In the
absence of knowledge as to the impact of nitrogen leakage and in the
lack of a surveillance program to monitor accumulator piston
locations, HV852B continued to degrade over a three month period.
One violation was identified.
23
16.
Follow-Up of Items of Non-Compliance (92702)
(Closed) Violation (50-361, 50-362/91-01-07) "Inaccurate Technical
Information in a Technical Specification Amendment Request"
The NRC I&C setpoint team found that the licensee had submitted TS
Amendment requests based on incorrect engineering calculations.
These calculations were contained in Functional Analysis M-89068.
The licensee subsequently withdrew the amendment request. The
licensee determined that Functional Analysis M-89068 had not
received the normal engineering and quality review required for
engineering calculations.
The licensee issued changes to Engineering, Safety and Licensing
Department Procedures 24-7-15, Revision 7, PCN 3, "Preparation and
Verification of Design Calculations, and 24-10-9, Revision 3, PCN 2,
"Design Process Flow and Controls SONGS 1, 2 & 3."
These changes
specified that studies and analysis used as official documents shall
have formal engineering and quality reviews.
The inspector reviewed the administrative document changes and
concluded that the changes required adequate engineering and quality
review; therefore, this item is closed.
Technical issues associated with the errors in Functional Analysis
were discussed in Paragraph 15.b, Unresolved Item (50-361,
50-362/91-01-06).
Final NRC review of new calculations and
operating procedures associated with Functional Analysis M-89068
will be performed during review of Unresolved Item (50-361,
50-362/91-01-09).
17. Meeting with Southern California Edison (SCE)
Managers in Region V Office
On August 18, 1992, SCE managers, M. Short, R. Rosenblum, B. Carlisle,
and G. Hammond, came to the NRC Region V Office to discuss some recent
technical issues occurring at San Onofre. The NRC personnel present for
the discussions were K. Perkins, H. Wong, and D. Chaney. The issues
discussed included the Unit 3 pressurizer level instrument line leak, a
temporary modification to the containment purge system, and re
organization of the Station Technical engineering organization. The SCE
handouts used in this meeting are attached.
Mr. Perkins discussed the need for making conservative operating
decisions and encouraged continued open exchange of information between
all groups. Mr. Perkins also emphasized that early discussion of issues
was important in order for the NRC to be able to completely understand
the development of the issue. The SCE personnel agreed and to the extent
possible would do so. Mr. Perkins stated that the meeting was beneficial
in understanding more fully the technical issues and also the SCE thought
process in dealing with these issues.
24
18. Unresolved Item
Unresolved items are matters about which more information is required to
determine whether they are acceptable items, violations or deviations.
Unresolved items addressed during this inspection are discussed in
paragraph 12 of this report.
19.
Exit Meeting
On August 26, 1992 an exit meeting was conducted with the licensee
representatives identified in Paragraph 1. The inspectors summarized the
inspection scope and findings as described in the Results section of this
report.
The licensee acknowledged the inspection findings and noted that
appropriate corrective actions would be implemented where warranted. The
licensee did not identify as proprietary any of the information provided
to or reviewed by the inspectors during this inspection.
25
SAN ONOFRE UNIT 3 PRESSURIZER INSTRUMENT
VALVE CANOPY SEAL LEAK
INTRODUCTION:
o
on 6/14/92, Pressurizer Level Anomoly in Y Channel
o Transmitter Replaced and Channel Returned to Service
o
On 7/20/92, Pressurizer Level Control Anomoly in Y
Channel
o
Performed:
Loop Check/Calibration -
No Problems Identified
ECAD -
No Relevant Problems Identified
o Attempts to Re-Calibrate Transmitter In Containment
Identified Feedback Coil Misaligned
o Replaced Transmitter
o
5.5% Deviation Still Present
o
Suspected Deviation Due to Leak In Reference Leg
STATION TECHNICAL DIVISION
SHORT, M. P.
Manager,
Technical
PENSEYRES. P. H.
HERSCHTHAL. M. A.
Assistant Technical
Special Projects
Manager
PLAPPERT, R. D.
HIRSCH, J. F.
NIEBRUEGGE, D. A.
HETRICK. S. J.
Technical Support
Power Generation
NSSS Engineering
Computer & Reactor
& Compliance
Engineering
VANDENBROEK, J.
CLARK. R.
SIMPSON. J.
RAMENDICK, D.
NRC Reporting Group
Turbine Cycle
Electrical
Reactor Engineering
POWERS, D.
TUTTLE. D.
LYLE, J.
HARALSON. P.
Balance of Plant
Nuclear Systems
Information Systems
WATTSON, P. C.
BLAKESLEE, P.
QUIGLEY. N.
MITCHELL, R.
Technical Support
Heat Removal
Mechanical
Control Systems
STEPHENSON, J. 1
SCHOFIELD, P.
IRVINE, D.
KURTZ, A.
FREY. D.]_______
___
Oug
C
Dit
Performance Monitoring
Codes & Welding
Computer Tech.
Outage Coordination
9
CAROSSINO, C.
WINSLOW, J.
Special Projects
OL7/
7192
TYPICAL PRZR. INSTR. NOZZLE CONFIGURATION
PRZR SHELL
In. 690 NOZZLE
CONDENSING POT
LOCA LIMITER
MR043: ROOT VALVE
LOCATIONS
ASMEIII, CLASS2
ASMEIII, CLASS2
3/4" COUPLING
6000# SW
BRAIDED FLEXIBLE
CONNECTOR
EQUALIZING
VALVE
MRO41: ROOT VALVE
110/1
LT
ISOLATION
TRANSMITTER
@
VALVES
UNIT 2 CONTAINMENT PURGE EXHAUST INTRODUCTION
BACKGROUND
TEMPORARY FACILITY MODIFICATION
PLANS TO CORRECT CAUSE OF LLRT FAILURE
LONG TERM CORRECTIVE ACTIONS
Containment
Blank Flanges
To Plant Purge Stack
Inside
l Outside
Installed
Radmonitor and Stack
Close on
CPIS
_
_
_
_
_
_
_
_
HV-9950HV-9951
HV-9950
42911
Exhaust Fan Unit
-
19
-i
n
42"
HV-9824
-9825
Exhaust Fan Unit
Close on
Cone Diffuser with
I
CPIS CIAS, SIAS
Debris Screen
Containment Purge Exhaust System
0a
BACKGROUND - APPLICABLE TSs
(Modes 1 through 4)
Technical Specification
Limiting Conditions
Action Requirement(s)
for Operations
3.6.1.7, Containment Ventilation
a.
42" purge valves maintained
a.1
Close / blind flange in 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, else
System
closed
Mode 3 in next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 in
next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
b.
8 " mini purge valves closed to
a.2
If open for other than allowable, close or
the maximum extent practicable
blind flange in 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, else Mode 3 in
next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 in next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />
b.
If a 42" or 8" isolation valve leakage
exceeds 0.05 L. at P. during LLRT, fix or
blind flange in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, else Mode 3 in
next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 in next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />
3.6.3, Containment Isolation
Maintain Valves Operable
Restore to operability or isolate penetration in
Valves
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, else Mode 3 in next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and
Mode 5 in next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />
3.6.1.2, Containment
Combined leakage < 0.75 L. at P.
Prior to RCS temperature exceeding 200 F (i.e.,
Leakage
LLRT Leakage < 0.6 L. at P.
if exceeded in Modes 1 - 4, enter TS 3.0.3 - Fix
in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, else Mode 3 in next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode
5 in next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />)
3.6.1.1, Containment Integrity
L, < 0.6 at P.
Fix in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, else Mode 3 in next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and
Mode 5 in next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />
Containment Wall
Inside
Outside
HV-9950
O
42"
0
HV-9951
HV-9824
HV-9825
8-Inch
8-Inch
-4---- Pressure Assisted Shutoff Side of Valve
--
Side Pressurized For Quarterly LLRT
Special LLRT with Blank Flange Installed
Performed Each Refueling Outage
Containment Purge Exhaust Penetration
42" VALVES
T - RING
COMPRESSION RING
ALVE BODY
ADJUSTION
SETSCREW
ALVE DISC
RETAINING RING
RETAINING RING SCREW
42 INCH VALVE T-RING DETAILS
8" VALVES
T - RING
SINGLE FLANGE
VALVE BODY
BUTTWELDING END
0
-RINGCONNECTION
RTINING -7
RING
COMPRESSION
.VV
DIS
RING,
.DISC
STOP WITH
ADJUSTING SET SCREW
RETAINING
RING SCREW
ADJUSTING
SETSCREW
8 INCH VALVE T-RING DETAILS
LLRT History Summary - Purge Supply and Exhaust Penetrations
o
Prior to March 30, 1992, Only Sporadic LLRT failures
o
Most Common Cause of LLRT Failures:
Valve stroke problems
T-Ring wear and adjustment problems
Particulates on valve sealing surfaces (mostly exhaust penetration)
BACKGROUND
PURGE EXHAUST PENETRATION 1992 LLRT HISTORY
3/30
Routine Quarterly LLRT Failed
Entered Penetration to Adjust Outboard 42-inch Valve T-Ring
Apr/May
Vented Containment Through Exhaust Penetration Seven Times.
6/9
Routine LLRT Failed.
Corrected by blowing particulates from mini-purge valve seats.
BACKGROUND
PURGE EXHAUST PENETRATION 1992 LLRT HISTORY - Continued
6/16-17
Performed special LLRTs on Penetration
Performed as Found LLRT, With Virtually No Leakage.
Vented Containment.
Performed As-left LLRT.
Leakage Exceeded 3 Times 0.05 La
Blew Particulates From HV-9825 and HV-9824 Seats.
Probable Cause of Valve Failure Determined To Be Particulates
BACKGROUND
PURGE EXHAUST PENETRATION 1992 LLRT HISTORY - Continued
7/2
Performed Pre-venting LLRT, With Virtually No Leakage Found.
Containment Vented.
Post-Venting LLRT Found Excessive Leakage.
Blew Off Valve Seat of HV-9825 - LLRT Satisfactory.
Postulated That Particulates Originated Within The Penetration
And Not Within Containment.
7/10
7/2 Test Repeated At Reduced Pressure And Flow.
Confirmed That Failures Caused By Particulates From Inside The
BACKGROUND
PURGE EXHAUST PENETRATION 1992 LLRT HISTORY - Continued
7/30-31
Implemented TFM To Bypass Purge Penetration In Order To
Vent Containment For Pressure Control.
8/2
TFM Placed Into Service
TFM
PRA RESULTS
CASE#
SYSTEM
OPERATING
SIGNIFICANT
TIME
OFF-SITE
RELEASE RISK
1
MINI-PURGE
4hrs/20days
7.6E-1 1/yr
2
MINI-PURGE
1 000hrslyr
1.OE-9/yr
3
MINI-PURGE
CONTINUOUS
9.OE-9/yr
4
TFM
4days/20days
1.OE-1 0/yr
5
TFM
CONTINUOUS
5E-10/yr
Containment
Blank Flanges
To Plant Purge Stack
Close on
Inside
Outside
Installed
Radmonitor and Stack
CPIS
HV-9950
(~HV-9951
42.
Exhaust Fan Unit
42"
2
HV-9824
E
F
18"
8.
~N
Close on~
Close on Hi Plant Purge Stack Radiation
Cone Diffuser with
Close on
Debris Screen
CIAS SIAS, (CPIS)TFM
Close on
i
CIAS, *CPIS
Rad Monitor 704
>308
S3J
Close on
HV-7801
i
HV-7800
CIAS
s
Signals Added by TFM
RSignals
Removed by TFM
Containment Venting After TFM Implementation
NUCLEAR REGULATORY AFFAIRS DIVISION
uIoitrI
-DI~S
MIS : i. V .L
GOMfN E, ?A
BlEILLbsK.
ht
KLAf'KA, R .1
MfAWR.lE. r.
OiUBSON, G,. 7.I
AI.IMoaIfl
a. F..
KIE
J -ING. F-S.
IISFIYJ.
Suporv.sof,
14muagoe,
UR
V10,
G 0.oyur
uooor
lwIi~rlwjMrlo
a
.ms-u111.-o
Env~nngan~1
Enr~~ji~cy 'iiiim N~o~r~~n
l~gtn~tii nuconjr C;umrnwimfcvtnn
GOI-McIng lUiiili nso ijucloaf icomiuiU
l~ibi 1)
UI2d
MISSION STATEMENT
The mission of Station Technical (STEC) is to provide
expert engineering support in the day-to-day operation and
maintenance of San Onofre Nuclear Generating Station
(SONGS). This support ensures that plant systems,
components, structures (hereafter termed "systems"), and
programs achieve a level of performance meeting or
exceeding those requirements in Technical Specifications,
the FSAR, other rules and regulations, the approved design
basis, and management goals.
Deviations from these requirements are identified in the
day-to-day operation and maintenance of SONGS. STEC's
mission is to assess the impact and determine the causes
of these deviations. When necessary, STEC performs
temporary or minor modifications to the systems and
programs in support of SONGS day-to-day operations and
maintenance.
Many of the system and program requirements are not
easily understood and usable by operations and
maintenance. STEC's mission also includes interpreting
the system and program requirements and providing
usable guidance to support SONGS operations and
maintenance.
Manager
Station Technical
Connie Shelton
Secretary
Mark A. Herschthal
Allen J. Thiel IllJh
.HishDnldN*Ivn
Nuclear Systems
.
Electrical Systems
Engineering
Engineering
Power Generation
Technical Services
Dave A. Niebruegge
Jim C. Winslow
Dave W. Tuttle
Paul E. Schofield
I&C Engineering
Balance of Plant
Performance Mon.
Neal J. Quigley
Joe Simpson
Paul P. Blakeslec
Vacant
NSSS Mechanical
- Electrical Engineering J
Heat Removal
Codes & Welding
Jim M. Lyle
Steve J. Hetrick-
Ransey C. Clark]
D. Frey/J. Stephenson
NSSS Aux,.
Computer Engineering
Turbine Cycle
Outage Support
Vacant
Roger V. Mitchell
Patrick C. Wattson
Nuclear
Control Systems
Technical Support
S Danny K. Powers
Percy B. Haralson
Carlos A. Carossino
Sta. Tech. Advisors
Info. Systems
j
Prog ra ms
-David J. Ramendick
A. Kurtz/D. Meiner
Reactor Engr.
Computer Maint.
Pete H. Penseyres
Integ. Plant Ops
08/17/92
TECHNIC
IVISION
NUCLEAR SYSTEMS ENGINEERING
SOUTHERN CAUFORNIA EDISON
Mark A. Herschthal
Manager
Nuclear Systems Engineering
89301
San Onofre Nuclear Generating Station
Dave Niebruegge
Vacant
Pete H. Penseyres
NSSS Systems Supervisor
Reactor Engineering &
Integrated Plant
86103
STA Supervisor
Operations
FI
Neal J. Quigley
Jim M. Lyle
David J. Ramendick
Danny K. Powers
NSSS Mechanical
NSSS Auxillary
Reactor Engineering
Sta. Tech. Advisors
86746
89425
88704
89155
Bob Conoscenti
86807
Joe Blake
89159
Jay Iyer
RE 89156
UNIT 1
UNITS 213
Paul Leibowitz (5)
89074
David Brenner
86696
Greg Keney
RE 88734
John IV. Ryder
86859
Wayne Marsh
88701
Pete Bruno
86903
Bill Lilly (5)
RE 89096
Randall T. Benson
89802
Russ Nielsen
89214
Sal Dolcemascolo (5) 89317
Robert Margolis (5) RE 88703
Dean R. Goodwin
89129
Robin I. Baker (6)
86790
Kieth Reeser
86138
Kevin Flynn
89212
Aaron Smookler (1) RE 89096
Mark B. McKinley
89170
Michael L. Barr (6)
86839
Dwayne Roberts
89206
Dan Higgins
89211
Rogelio Soto
RE 89592
Steven E. Ross
86154
Gary L. Johnson Jr. (6) 89160
Jim Rudolph
89791
John E. Hughes
87022
Vacant (1)
Kevin C. Wood
89316
Calvin Meddings (6)
85153
Jo Tore
(1) 89493
7
Joe Toffes (1)
89493
Dale Wickman
86152
John W. Perkins (6)
89178
Beatle Tran (1)
89493
Rick Zbavitel
89135
Charlie Eischen (5)
86159
Mike Vezzuto
86759
(1) Part Time
(2) Temporary
Don Steannan 87303
(3) Cross-training
Division Office Administrator
(4) Leave Of Absence
Approve
PARL
LRS(5)
Contractor
M~ark A. flerschithal
PAYROLL CLERKS
Rosle Razo
(187) 89542
(6) Sta Trainee
Sharon AnDlaott (189) 88272
RE
M
Reactor Engineer
SDI
n
8/17/92
TECHNI MFIVISION
POWER GENERATION ENGINEERING
SOUTHERN CAUFORNIA EDISON
John Hirsch
Supervisor
Power Generation
86278
1San
Onofre Nuclear Generating Station
jean Gomez
Vacant
-.......
Secretary
Special Projects
89318
Ransey Clark
David Tuttle
Paul Blakeslee
Turbine Cycle
Balance of
Heat Removal
89169
8674989215
Juan Armas
89233
Aeri Daniels
86090
Marco Ahunada
86360
Russ Chetwynd
89703
G. Gwiazowski (3)
89985
Don Ashcraft
86210
Danny Lowenberg
86755
Henry Jones
89704
Johnson Cheng
89793
Antonio Molina
89153
Ty Kent
86205
Keith Chong
89017
Mark Mountford (1) 89479
Al Ockert
89828
Russ Cobb
86664
Dan Nougier
86742
Judy Peck (1)
85170
Bruce Friedberg (1) 86083
Bernie Phillips
89381
Tom Peterson
89706
Bill Hines (1)
89362
Guy Shelton
89783
Bill Poirier
89198
Murray Jennex
86787
Eric Schoonover (1) 85119
Jerome Marr
86041
Del Smith
86743
Steve Roberts
89139
Kevin Trout (1)
86289
Jorge Valdivia
86218
John Watkins
89829
(1) Part Time
Don Stearman 8730s
(2) Temporary
Division Office Administrator
(3) Cross-training
PAYROLL CLERKS
(4) Leave Of Absence
Rosle Razo
(187) 89542
(5) Contractor
HShift
Technical Advisor
DB 8/1792
TECHNIC
IVISION
TECHNICAL PROGRAMS SUPPORT
SOUTHERN CALIFORNIA EDISON
Donald N. Irvine
Supervisor
Technical Programs Support
89368
.San
Onofre Nuclear Generating Station
SeDaneleEaFre
Paul Schofield
Vacant
Patrick C. Wattson
Carlos A. Carossino
Daniel E. Frey
Performance Monitoring
Codes and Welding
Station Technical
867032
I
86752
89634
Jerry L. Stephenson
Chuck Elliott
86747
Jorge Blanco (1)
85114
Sean D. Baker (1)
89036
Outage Representative
Chuck
Ellot
864oreSaio
n T echn'ical
JimHedeson
8924
Letci Bambla
8960
Julius L. Bognar
86586
Seanio
TecBker(i)c903
Jim Henderson
89324
Leticia Brambila
89560
James M. Davison
89119
Jonn R. Beeson
89906
86702
Vic Herrera
89154
Dan Brown
86221
Cary L. Johnson Sr. 89037
Sarah J. Cobb (5)
85127
Sue Knowlton (1)
85179
Ken Collins (5)
89869
Marie L. Tarango
89165
Vacant (1)
Mike O'Halloran (5) 89985
Roger Holmes
89103
Mike Schwaebe
86744
Bill Lazear
89010
G. Winterscheid (1)
89985
Al Meichler
89210
Clerical Support:
Richard G. Allen
Les Ousley
89588
eCc
Support
Robert Sears
89104
RCM Support
Ramona S. Berry
89813
89604
In Service Testing
Jerry Valsvig
88953
James N. Hess
86885
Paul Croy
86386
Clerical Support:
Sherry M. Kunz
89483
David Chiang (5)
89013
Vacant
Clerical Support:
Shirley Wright
89164
(1) Part Time
Jeanine Smith
89140
Steanan
IrSs
(2) Temporary
Approved_
eanSt 84Dvuubon
Office Admnistarator
(3) Cross-training
Donald N.rvine
PAYROLL CLERKS
(4) Leave Of Absence
Rosle Razo
(187) 89542
(5) Contractor
Sharon Anstaett (189) 88272
SDB 8/17/92
TECHNIM DIVISION
S~tER
CUFRNA
DIONELECTRICAL
SYSTEMS ENGINEERING
SOUTHERN CAUFORNIA EDISON......
Allen J. Thiel
Manager
Electrical Systems Engineering
87048
87048_
_
San Onofre Nuclear Generating Station
Jim Winslow
Vcn
tv
erc
Instrumentation &
Vaetrcanirn
g
Soptee Hneeri
Controls Engineering
SystrmslEninerig0oter
EngMne
86584873
Usoalii Afaese
Secretary
88720
Roger V. Mitchell
Percy B. Haralson
Allen Kurtz 89833
Control Systems
Information Systems
Dan Meiner 86425
89801
F
88723
Computer Maintenance
__________
___________
_________
__________Lowell
Skinner Plan186982
Bud Bostian
88724
Paul Battish
89067
Joe Aguirre
86345
Steve Atkins
88415
Operator PAX 86410
Steve Foglio
89137
Bill Brush
89131
Mike DePano (1)
85165
Bob Boyer
89848
Tech PAX 87644
Don Frapwell
87411
Tom Graham
89179
Gale Generoso (1)
85165
G. Castellanos
88719
Shreyas Gandhi (1) 89557
Susan Hower (1)
89342
Ken Hooper
86994
Timothy Ford
88702
Lorraine Holmes
Oper
Chuck Hallett (5)
85125
Charles Kim (1)
89342
Wayne Thomas
89665
Chuck Kluz (1)
88721
Debra Knights
Oper
Gerry Lear
86703
Larry Mueller (5)
89493
Dave Knights
88728
Lani Majchrowicz
Oper
Russ Neal
89681
Ami Samanta
86705
Rory Job (1)
85165
Mark Tomlinson
Oper
Mike Root (5)
86656
Gary legich
89072
Frances Williamson
Oper
Lance Rushing (1)
85171
Paul Anderson
Tech
(1) Part Time
Mike Chandler
Tech
(2) Temporary
Ed Collins
Tech
(3) Cross-training
Charles H-ardin
Tech
(4) Leave Of Absence
Jeff Headlee
-Tech
(5) Contractor
LaryH')
Tc
Don Stearman 87303
N Shf T
l
Division Office Administrator
Approved
Tony Moreno
Tech
PAYROLL CLERKS
Oper-Computer Operator
Alle i J. Thiel
Mirk Nowak
Tech
Rosle Razo
(187) 89342
Tech-Computer Technician
Steve Schultz
Tech
SharB Anstiell (1B9) 88272
MDB
8/17/92
Bob Sorge
Tech
O ROOT VALVE MR043
'
in Carbon
Steel
Canopy
,_
I
I
Class:
1500
Design
Pressure:
2485 psig @ 700 deg F