ML13329A178
| ML13329A178 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 08/13/1992 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML13329A176 | List: |
| References | |
| 50-206-92-20, 50-361-92-20, 50-362-92-20, NUDOCS 9208310305 | |
| Download: ML13329A178 (24) | |
See also: IR 05000206/1992020
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos.
50-206/92-20, 50-361/92-20, 50-362/92-20
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 Units 1, 2 and 3
Inspection at:
San Onofre, San Clemente, California
Inspection conducted: June 4, 1992 through July 16, 1992
Inspectors:
C. W. Caldwell, Senior Resident Inspector
D. L. Solorio, Resident Inspector
C. D. Townsend, Resident Inspector
T. Sundsmo, Project
spector
Approved By:
-_<ZJ_ e
___
_____8
H. J. Wong, Cief
Date Signed
Reactor Projects Section 2
Inspection Summary
Inspection on June 4. 1992 through July 16, 1992 (Report Nos. 50-206/92-20,
50-361/92-20, 50-362/92-20).
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,
monthly surveillance activities, monthly maintenance activities, independent
inspection, licensee event report review, electrical maintenance, design basis
document review, emergency preparedness drill, training, and followup of
previously identified items and items of non-compliance. Inspection
procedures 37700, 41701, 60710, 61726, 62703, 62705, 71707, 71710, 82301,
90712, 92700, 92701, 92702 and 93702 were utilized.
Safety Issues Management System (SIMS) Items:
None
9208310305 920813
ADOCK 05000206
G
III2
Results:
General Conclusions and Specific Findings:
Strengths
A new site record of 236 days of continuous operation was set by Unit 1 on
July 12, 1992. The inspector considered that this record was achieved
through the diligence and attention to detail on the part of all personnel
involved with the operation and maintenance of the Unit (Paragraph 2).
The inspector considered that the licensee's efforts to understand and
propose corrective actions for weaknesses in the maintenance process, and to
reduce the backlog of maintenance items to be extensive. The implementation
and effectiveness of these efforts will be reviewed further as part of the
routine inspection effort (Paragraph 9.d).
Weaknesses
The inspector noted two events that were indicative of a weakness in the
interface between Station Technical and Operations to maintain configuration
control of plant equipment during surveillance activities.
In the first instance, the inspector observed that Station Technical (STEC)
personnel did not obtain approval from the Senior Reactor Operator (SRO)
Operations Superintendent to perform an inservice test of a Unit 2 auxiliary
feedwater pump. As a result, the SRO was not involved to the level required
by both Operations and Engineering procedures (Paragraph 5.b).
In the second instance, a Unit 2 salt water cooling (SWC) pump became
inoperable due to a misaligned valve. The event was detailed in licensee
event report (LER) 2-92-009. In that case, Operations personnel failed to
recognize that the Engineering procedure did not comply with procedural
requirements to provide for an Operations sign-off and an independent
verification of equipment manipulation. Thus, proper configuration control
was not maintained.
As a result of these two events, the inspector was concerned that additional
licensee attention was necessary to strengthen the STEC/Operations interface.
Significant Safety Matters:
Summary of Violations:
One violation concerning the failure of Station Technical personnel to obtain
approval to perform a surveillance on an auxiliary feedwater pump from the
SRO Operations Supervisor was identified (Paragraph 5.b).
Open Items Summary:
During this report period, four new followup items were opened and 12 were
closed; one was examined and left open.
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. Zintl, Manager, Emergency Preparedness
D. Herbst, Manager, Quality Assurance
C. Chiu, Manager, Quality Engineering
- J. Schramm, Plant Superintendent, Unit 1
V. Fisher, Plant Superintendent, Units 2/3
- D. Brevig, Supervisor, Onsite Nuclear Licensing
- G. Hammond, Supervisor, Onsite Nuclear Licensing
J. Reeder, Manager, Nuclear Training
H. Newton, Manager, Site Support Services
- R. Plappert, Manager, Technical Support and Compliance
- J. Jamerson, Lead Engineer, Onsite Nuclear Licensing
- D. Axline, Engineer, Onsite Nuclear Licensing
- W. Marsh, Assistant Manager, Operations
- S. Paranandi, Supervisor, Quality Assurance
- N. Maringas, Supervisor, Quality Assurance
- J. Rainsberry, Plant Licensing Manager
- J. Fee, Assistant Manager, Health Physics
- S. Hetrick, Supervisor, Computer Engineering, Station Technical
- N. Quigley, Engineering Supervisor, Station Technical
- D. Roberts, Safety Injection Cognitive Engineer
- W. Conklin, Compliance Engineer, Station Technical
- R. Nielsen, Cognitive Engineer, Station Technical
San Diego Gas and Electric Company
- R. Lacy, Manager, Nuclear Department
- R. Erickson, Site Representative
- Denotes those attending the exit meeting on July 16, 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
2. Plant Status
Unit I
Unit 1 operated at power the entire inspection period and established a
new site record (236) days for continuous operation on July 12, 1992.
Unit 2
Unit 2 operated at power for the entire 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.
Several minor discrepancies were noted and discussed with the Shift
Superintendents for resolution. In addition, the following issue was
noted as discussed below.
Unit 1 Turbine Building
On June 4, 1992, the inspector noted that a pipe draining into a floor
drain was splashing water onto the floor around the drain in the Unit 1
Turbine Building. Because the drain was labeled potentially
contaminated, the inspector contacted health physics (HP) supervision to
determine if the water splashing onto the floor was spreading
contamination.
In response to the inspector's question, HP performed a survey of the
drain and the floor around it. Contamination was found in the drain, but
not on the surrounding floor. The draining pipe provided waste drainage
from the secondary plant chemistry lab. Initially, HP installed one end
of a plastic wrap around the pipe and the other end to the floor around
the drain. This was done to prevent water from splashing out from the
drain onto the surrounding floor. However, with the plastic secured to
the floor, it was not clear to the inspector that the drain would have
functioned properly.
3
The inspector questioned HP management as to whether they were defeating
the purpose of the drain by this modification. HP management responded
that they did not know but would find out. A few days later the
inspector observed that the plastic had been removed from the floor
around the drain. In fact, the plastic had been re-secured to the inside
of the drain.
The inspector noted that the drain in question was located near the 4160
VAC (4KV) and 480V switchgear rooms. The inspector observed other floor
drains in the same area, but was unable to determine if they were
functioning properly. The inspector will evaluate the consequences and
significance of the temporary drain modification as part of the routine
inspection effort.
4. Evaluation of Plant Trips and Events (93702)
a. Temporary Waiver of Compliance From Technical Specification 3.3.1
For Safety Injection Valve HV852B - Unit 1
On May 18, 1992, the licensee was granted a Temporary Waiver of
Compliance (TWOC) from TS 3.3.1, "Safety Injection and Containment
Spray Systems Operating Status," to allow repairs of safety
injection (SI) hydraulic valve (HV) HV852B. The duration of the
TWOC was for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and was initiated on May 19, 1992. At 11:09
p.m. on May 19, 1992, HV852B was restored to service, establishing
compliance with TS 3.3.1.
The waiver was requested to allow for the replacement of the HV852B
accumulator nitrogen addition valves (schrader valves), which had
been identified to be leaking nitrogen. The nitrogen leakage had
resulted in a recharging frequency of the accumulators of
approximately once every three days.
Hydraulic valve 852B is opened with a pneumatic-hydraulic pump, and
closed by two nitrogen-hydraulic fluid accumulators connected at
their hydraulic discharge to the valve actuator. The nitrogen in
the accumulators is separated from the hydraulic fluid by a piston
with seal rings. 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 is added to the accumulators by connecting a
nitrogen high pressure cylinder to accumulator schrader valves with
a charging manifold.
On May 19, 1992, HV852B was removed from service to replace the
schrader valves on both accumulators.
Initially the accumulators
were ultrasonically tested to determine the locations of the
pistons. However, measurements of piston positions were
indeterminate. Upon removal of the schrader valves from the top of
the accumulators, the position of the pistons were measured visually
using reach rods. The pistons were found to be misaligned. One
accumulator piston was found at its uppermost possible location with
II
4
the maximum volume of hydraulic fluid and minimum volume of nitrogen
gas. The other piston was found at its lowest possible location
with the minimum volume of hydraulic fluid and maximum volume of
nitrogen gas.
As corrective action, the schrader valves were replaced, the
accumulators were recharged with nitrogen, and the pistons were
evenly aligned. After measuring the piston locations with the rods,
STEC considered the operability of the valve to be indeterminate and
initiated an evaluation after completion of the corrective
maintenance.
On June 17, 1992, a nonconformance report (NCR) was issued to
document the degraded condition of HV852B as found on May 19, 1992.
Station compliance determined that the degraded condition of HV852B
was reportable under 10 CFR Part 50.73, which required SCE to submit
a licensee event report (LER) within 30 days. On June 23, 1992, the
valve vendor and STEC concluded that HV852B had been inoperable
prior to its repair on May 19, 1992.
Based on the events associated with HV852B, the inspector had the
following concerns:
o
The accumulators were modified in 1986 to use the pistons to
isolate the hydraulic fluid from the nitrogen. Up to two weeks
prior to replacement of the schrader valves, it was not
recognized that leaks from the accumulators could result in
piston misalignment. (The most severe consequence of the
misalignment was the valve becoming inoperable).
Evidence of
this is supported by the absence of a program to monitor the
piston locations concurrent with or independent of accumulator
recharging evolutions.
o
Ultrasonic testing of the other HV accumulators following the
discovery of HV852B piston misalignment would have identified
the ongoing degradation of HV851A prior to June 17, 1992 when
the licensee requested a TWOC (reference section 4.b for
discussion).
o
The NCR documenting the inoperable condition of HV852B was
initiated approximately one month after the valve was found in
its inoperable condition.
This is an unresolved item pending review of the licensee's assessment of
the condition as documented in their LER (50-206/92-20-01).
b. Temporary Waiver of Compliance From Technical Specification 3.3.1
For Safety Injection Valve HV851A - Unit 1
On June 17, 1992, the licensee requested a TWOC from the
requirements of sections A(1) and A(3) of Technical Specification (TS) 3.3.1, "Safety Injection System - Containment Spray Systems -
II
5
Operating Status."
This was necessary for a period of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in
order to facilitate repairs to safety injection (SI) valve HV851A.
This request was granted verbally by the NRC on June 17, 1992 and
formally documented in a June 18, 1992 letter to the NRC. At 11:48
a.m. on June 18, 1992, HV851A was restored to service, establishing
compliance with TS 3.3.1.
The SI valve, HV851A, is a double disc gate valve, with a pneumatic
hydraulic actuator which is similar in configuration to HV852B as
discussed above. The only major difference is that HV851A has one
accumulator instead of two.
The actuator associated with SI discharge isolation valve HV851A
experienced minor hydraulic fluid leakage on the accumulator side.
The leakage had been monitored by STEC. The licensee assumed that a
significant loss of hydraulic fluid could limit the capability of
the valve to stroke to the fully open position upon demand. An
evaluation was initiated, which included the use of ultrasonic
testing (UT) to determine the position of the accumulator piston.
The conclusion from the evaluation was that a loss of hydraulic
fluid had occurred which would prevent the valve from opening beyond
approximately 85% of full stroke. The licensee stated that in this
condition the valve would still perform its required safety function
since analyses had recently been completed which demonstrated that
the required SI flow would occur with HV851A 50% open. However, the
licensee requested the TWOC to remove HV851A from service to
recharge the accumulator hydraulic side in order to regain the full
stroke capability of the valve.
Because the accumulator oil leak was not repaired, (repairs would
have required valve disassembly), the licensee committed to
implement measures that would assure continued operability of
HV851A. Those measures were to trend the frequency of accumulator
nitrogen recharging and perform periodic piston location
measurements using the UT method developed previously.
Because there were questions as to the positions of the other HV
accumulator pistons, the licensee committed to perform UT
measurements on them (with the exception of HV852B, which had been
ultrasonically tested approximately two weeks prior and left with
pistons in their optimum position).
On July 1, 1992, the remaining HVs (8518, 8548, 853B, 852A, 853A,
854A) were ultrasonically tested. All of the HVs were found to be
in an optimum condition except for HV854A. The accumulator pistons
for HV854A were found to be misaligned greater than the V/"
limit
that station engineering had determined was the optimum
configuration for dual accumulator valves. However, the valve was
determined to be operable. The licensee subsequently realigned the
pistons by recharging the accumulators with nitrogen.
6
No violations or deviations were identified.
5. Bi-Monthly Surveillance Activities (61726)
During this report period, the inspectors observed or conducted
inspection of the following surveillance activities:
a. Observation of Routine Surveillance Activities (Unit 1)
SO1-V-2.14.1
"Auxiliary Feedwater Pump, S1-AFW-G1O, Inservice
Pump Test."
S01-II-1.6.20
"Surveillance Requirement Intermediate Range
Channels NIY-1203 and NIY-1204 Neutron Flux
Channel Test."
501-12.4-2
"Operations In-Service Valve Testing."
SO1-II-1.1.2
"Surveillance Requirement Pressurizer Level and
Pressurizer Pressure Channel Test."
SO1-V-3.9
"Isothermal Temperature Coefficient."
b. Observation of Routine Surveillance Activities (Unit 2)
5023-1-2.72
"Fire Detection-Surveillance Testing Of
Actuation Detectors Outside Unit 2 Containment."
S023-V-3.4.1
"Auxiliary Feedwater Inservice Pump Test Monthly
Surveillance 2P140."
On July 1, 1992, the inspector observed surveillance testing on the
Unit 2 and Unit 3 auxiliary feedwater (AFW) pumps, 2P140 and 3Pl41,
required by surveillance procedure S023-V-3.4.1. During the Unit 2
surveillance of 2P140, the inspector noticed that approval to
conduct the test had been received from the Control Operator (CO),
but the procedure directed that approval be from the SRO Operations
Superintendent. The inspector discussed this observation with the
on-shift SRO and determined that he knew the test would be performed
that day, but had not actually discussed it with engineering
personnel.
Step 3.2 of S023-V-3.4.1 stated; "Obtain the SRO Operations
Supervisor approval to conduct the test. Operations should release
pump 2(3)1305MP140 to the Cognizant Engineer for testing at this
point under a verbal approval."
The inspector noted that the
signature block allowed the engineer to document who was informed
including the date and time the individual was contacted. The
engineer had filled the signature block indicating approval from the
CO. When this was discussed with the engineers involved, they
indicated that it was appropriate to gain approval from the CO and
had utilized the CO for approvals previously. However, their
II7
supervisor indicated that the procedure should be adhered to and
that the SRO should have reviewed the scope of the surveillance
before it was performed.
Further inspection revealed that section 6.11, "Plant Manipulations
Using Other Division Procedures" of operations procedure 50123-0-20,
"Use Of Procedures," stated, in part, that it is acceptable to use
other division procedures to manipulate the plant provided the
procedure is reviewed and approved by a SRO Operations Supervisor
(prior to performing work). The procedure also stated that the
Control Room Supervisor is responsible for overall plant safety and
can suspend test activities at any time.
The inspector discussed this issue with licensee management who
agreed that the surveillance procedure was not properly followed.
It is important to consider that there was little safety
significance to this issue as the plant was operating at steady
state with no other related safety equipment out of service and the
surveillance was run successfully and in accordance with other
procedures. However, as shown by the missed procedural requirements
(as identified above), there appeared to be a weakness in
configuration control since the SRO operations supervisor was not
involved to the level required by both the operations and
engineering procedures. Failure to follow procedures S023-V-3.4.1
and S0123-0-20 is a violation, (50-361/92-20-02).
The inspector was concerned with the interface between Operations
and STEC and the impact on configuration control of plant equipment
during the performance of STEC procedures. In addition to the
concern identified above, a Unit 2 salt water cooling (SWC) pump
became inoperable in May 1992, due to a misaligned emergency seal
water supply valve. The event was detailed in LER 2-92-009. In
that case, the Station Technical surveillance procedure, S023-V
3.5.4, "Inservice Testing Of Check Valves," was used to perform a
quarterly test of SWC check valves. A step in the procedure was
signed by the test engineer indicating that he had requested
Operations to open the emergency seal water supply valve. However,
flow data suggest that the valve may have been inadvertently left
closed following the check valve test. Operations personnel failed
to recognize that Engineering procedure S023-V-3.5.4 did not comply
with the requirements in Operations procedure S0123-0-20 prior to
authorizing the test engineer to perform the check valve test. In
particular, the requirements for an Operations sign-off and
independent verification of equipment manipulation were not
contained in the Engineering procedure.
As a result of these two events, the inspector was concerned that
additional licensee attention was necessary to resolve
STEC/Operations interface weaknesses to ensure that plant
configuration control is properly maintained.
8
c. Observation of Routine Surveillance Activities (Unit 3)
5023-1-2.73
"Fire Detection Surveillance Testing Of
Actuation Detectors Outside Unit 3 Containment."
S023-V-3.4.1
"Auxiliary Feedwater Inservice Pump Test Monthly
Surveillance 3P141."
5023-3-3.27.2
"Weekly Electrical Bus Surveillance."
One violation was identified in this area.
6. Monthly Maintenance Activities (62703)
During this report period, the inspectors observed or conducted
inspection of the following maintenance activities:
a. Observation of Routine Maintenance Activities (Unit 1)
92051545000
"Intermediate Range Drawer Channel 1203, SL-NIS-NIY
1203, Channel Test."
92060339001
"Several Relays Have Caused The 'Start Up Rate
Reactor Trips Active' Permissive To Illuminate Upon
Relay Failure."
92061088000
"Bank A Instrument Air/N2 Header Relief Valve, S1
GNI-PSV-301, Is Leaking Through, Resulting In
Lowering Pressure On The Backup Nitrogen Banks For
HV851A."
92061958000
"Readjustment of the Dual Accumulator Pistons. East
Accumulator Piston Is At A Higher Level Than The West
Accumulator Piston."
92061860000
"Support STEC/QC In UT Inspection Of The Accumulator
For HV-851B."
92061867000
"Support STEC/QC In UT Inspection Of The Accumulator
For HV-854B."
92061964000
"Excessive Leakage On Outboard Seal of North
Component Cooling Water Pump. A Small Stream
Approximately 12 Ounces Per Minute."
b. Observation of Routine Maintenance Activities (Unit 2)
92060333000
"Main Steam Relief Valve To Atmosphere, 2P5V8407,
Water Leak Where Relief Valves Downstream Piping
Connects to the Stand Pipe."
9
92060334000
"Main Steam Relief Valve To Atmosphere, 2P5V8408, 30
Drips A Minute Leak Where Relief Valve Downstream
Piping Connects To The Stand Pipe."
92060019000
"Steam Generator, 2E088, Blowdown Vent Valve,
S21301MR800, Has Body Leak Of Steam That Is Getting
Worse."
92010602000
"Diesel Generator, 2G002, Fire Protection Pre-Action
Actuating Detector Surveillance Testing."
90050432000
"High Pressure Safety Injection Pump, S21204MP019,
Train B - P3 -
Inspect Each Cyclone Separator To
Ensure Their 0-Rings Are In Place. If The 0-Rings
Are Missing Replace With Qualified In-Kind Parts."
c. Observation of Routine Maintenance Activities (Unit 3)
92051337000
"Diesel Generator, 3G002, Fire Protection Pre-Action
Actuating Detector Surveillance Testing."
92070060001
"General Isolation PH Bus Potential Transformer,
S31802EPXP1, Cross-tie Generator Potential
Transformer Channel B To A To Provide For Voltage
Regulating, Per TFM 3-92-MAA-002, Revision 0."
92070942000
"125VDC Station Battery 301, S31806E6007, Cell #14
Voltage is 2.066 VDC, Allowable Limit Is 2.07 VDC.
Jumper Out Cell #14, Jumper In Cell #53."
92060813000
"125VDC Station Battery 3D1, S31806EB007, Perform A
Bank Equalize Charge."
92070965000
"125VDC Station Battery 3D1, S31806EB007, Perform
Single Cell Charge On Cell #53, Cell Voltage Is
1.208VDC."
The inspector observed the licensee's actions to jumper out failed
cell #14 and replace it with cell #53 in battery 301.
Failure of
cell #14 resulted in the Unit entering a 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Technical
Specification (TS) action statement to restore the battery to
operable status or to shut down the Unit. As a result of the
licensee's activities, the inspector had a number of questions
related to the performance of the surveillance test that identified
the failed cell and the adequacy of the replacement cell.
The
inspector will further evaluate the licensee's actions related to
this matter as followup item (50-362/92-20-03).
No violations or deviations were identified.
III_
_10
7. Independent Inspection (62705, 37700, 41701, 82301)
a. Electrical Maintenance (62705)
The inspector observed that cell 58 of Class 1E battery 3D3, was
being charged by a non-Class 1E portable single cell battery
charger.
The inspector noted that the use of non-Class 1E individual cell
chargers to charge Class 1E batteries has generally been accepted
when a licensee has demonstrated that adequate equalization of cell
voltages cannot be maintained using a full capacity charger and when
administrative controls have been maintained. Administrative
controls would be required to preclude the masking of data which
would indicate a potentially failing cell. These administrative
controls would typically limit any cell to the following:
o
Perform only one individual cell equalization charge a
year.
o
Limit the equalization charge rate to the battery
manufacturer's limits.
o
Recheck cell parameters two weeks after the charge.
o
Ensure that a 10 CFR 50.59 evaluation had been
accomplished to verify that a fault on the non-1E charger
would not degrade the 1E battery.
o
Provide criteria to demonstrate that adequate equalization
of cell voltages could not be maintained using a full
capacity charger.
The inspector reviewed the following licensee documents concerning
the batteries:
o
Procedure S0123-1-9.301, Revision 1, Temporary Change 6,
"Battery - Spare and Single Battery Cell Inspection and
Testing"
o
S0123-I-2.3, Revision 1, "Quarterly Battery Inspection"
o
A June 11, 1992, 10 CFR 50.59 evaluation for use of the
individual battery charger
o
Current and previous data for cell 58 and for battery 3D3
As a result of the review of the data for the cell 58, the inspector
concluded that cell 58 was not continually failing surveillances and
being individually recharged. Based on this data, the inspector
concluded that there was no immediate operability question for cell
58 in battery 3D3.
However, based on a review of Procedure 50123-1-9.301, the inspector
concluded that administrative controls for individual cell charging
were not in place to preclude use of the individual cell charger to
mask a failing cell.
In response to the inspector's concern, the licensee stated that
maintenance supervisors make the decision on when an individual cell
charge will be performed based on the number of cells which require
charging. The licensee stated that engineering personnel review
Class 1E cell data outside the normal performance characteristics.
As a result of these controls, the licensee stated that no changes
to add additional administrative controls for individual Class 1E
cell charging were planned.
In addition, based on a review of Procedures S0123-1-9.301 and
50123-1-2.3, the inspector concluded that the licensee's battery
procedures did not contain a method for demonstrating that they only
use the single cell charger if the licensee can't maintain voltage
using the full capacity charger.
The inspector noted that the June 11, 1992, 10 CFR 50.59 evaluation
for use of the individual battery charger concluded that the charger
was an isolation device as defined in IEEE STANDARD 384, "Criteria
for Independence of Class 1E Equipment and Circuits," because it was
a current limiting device. The evaluation was based on a Ratelco
Constant Voltage Charger, Type FF8504, Model 102-3617.00. The
evaluation concluded that the charging rate was limited to 80 amps,
based on output fuses in the charger. The evaluation also concluded
that an 89 amp charging rate would not damage the battery.
Based on a review of the licensee's 10 CFR 50.59 evaluation and
Procedure 50123-1-9.301, the inspector concluded that the licensee's
individual cell charger 10 CFR 50.59 evaluation was inconsistent
with Procedure S0123-I-9.301. A charging current limit of 80 amps
assumed in the 50.59 evaluation was not contained in the procedure.
In fact, a note after Step 6.3.7, Procedure S0123-1-9.301, directed
that the craft person performing the charge monitor the charging
operation hourly for charging currents over 100 amps. The inspector
also concluded that the licensee's evaluation that a battery charger
was a current limiting device was generally acceptable in accordance
with IEEE STD 384.
The inspector provided the conclusions discussed above to the
licensee. The licensee agreed that the note after Step 6.3.7 did
not match the 10 CFR 50.59 evaluation. As a result, the licensee
committed to revise the note to match the 10 CFR 50.59 review and
the actual equipment being used.
In addition to the concerns discussed above, the inspector also
questioned the effect of using the single cell charger on the
12
seismic qualification of the vital batteries. The inspector will
further evaluate the licensee's controls for use of the single cell
charger as followup item (50-362/92-20-04).
b. Design Bases Documentation Review (37700)
A Region V inspector performed an informal review of the licensee's
design bases documentation (DBD) program during the weeks of May 18
to 21 and June 8 to 11, 1992. This review primarily focused on
inspection of plant systems to ensure that these systems actually
exhibited selected safety significant design characteristics
documented by the DBD program. The inspector reviewed each system's
DBD, identified several verifiable safety significant
characteristics for each system, and then inspected each system to
verify the characteristics. The inspection was conducted in Unit 2,
and included the following systems:
SYSTEM
DBD DOCUMENT NO.
Class 1E 125 Volt DC
DBD-S023-140, Revision 0
Component Cooling Water
DBD-S023-400, Revision 0
Saltwater Cooling
DBD-S023-410, Revision 0
Instrument Air/Dedicated
Backup Nitrogen
DBD-SO23-540, Revision 0
Emergency Chilled Water
DBD-S023-800, Revision 0
Results of the plant system DBDs inspected during this review
indicated that these documents appeared adequate. Inspection of
additional plant systems will periodically be conducted by Region V
and documented in inspections reports as additional DBD documents
are developed by the licensee.
c. Observation of Emergency Preparedness Drill (41701, 82301)
On June 10, 1992, the inspectors observed an emergency preparedness
(EP) drill being conducted by the licensee for training purposes.
The drill involved a steam generator tube rupture (SGTR) and a
sequential loss of all feedwater on Unit 2. These events required
the operators to perform emergency operating instructions (EOIs) for
reactor trip, SGTR, and finally transition into the functional
recovery procedures (FRPs).
During the drill, the inspector had the following observations:
1) Control room evaluators (controllers) were not prepared to
evaluate operator actions during the drill. The prepared
13
scenario summary emphasized EP actions, but excluded operator
actions except for event classifications. For example, an
inspector informed the lead control room evaluator (operations
department) that the operators were performing actions that
were not contained in the EOI that was being performed
(functional recovery success path HR-2).
The evaluator stated
that he had not reviewed this procedure lately and wasn't sure
if it prescribed the observed operator actions or not. Because
the evaluators were not conscious of required operator actions,
they were not objectively critical of those actions.
The inspector considered that emergency drills are a good
opportunity to perform operator evaluations. This was
discussed with the licensee who indicated that they would
evaluate the inspector's observation.
2) Operators used the E0Is as guidance in certain instances,
rather than as procedures for the scenario given. In
particular, actions taken by the operators to cross-connect
Unit 3 condensate to Unit 2 were not directed by the E0Is;
these actions were improvised on the spot by the operators
without identification that they were deviating from the
prescribed course of action in the EOIs. However, the EOIs
directed use of the (Unit 2) condensate transfer system. Even
though the operator's actions had merit, there was no
indication that the course of action prescribed by the EOIs
would have been unsuccessful when the operators decided to
deviate from the EOIs. The operators continued with prescribed
EOI actions when the improvised actions were unsuccessful.
The inspector noted that the EOIs do not incorporate directions
to cross-connect systems between units in order to mitigate an
accident. The observed drill identified the need for cross
connecting condensate upon a loss of all feedwater event, and
the lack of a procedure to implement it.
The-ability to cross-connect Unit 2 and Unit 3 systems during
an emergency was discussed with the licensee after the drill.
The licensee indicated that they had a "desk top" procedure for
cross-connecting electrical systems between Units 2 and 3, but
did not have an emergency procedure to cross-connect condensate
systems. They indicated that the "desk top" procedure was not
an official procedure since it could not pass a 10 CFR 50.59
evaluation. However, the licensee indicated that this would
only be used when they were in an accident scenario that was
beyond the design basis event and not adequately covered by the
FRPs. In addition, it would be a conscious management decision
to implement it.
The inspector will review use of this "desk top" procedure further.
In particular, the inspector questioned if the "desk top" procedure
should undergo the formal review and approval process, and if it was
I
14
consistent with current methodology for complementing the E0I.
Followup item (50-361/92-20-05).
No violations or deviations were identified.
8. Review of Licensee Event Reports (90712, 92700)
Through direct observations, discussion with licensee personnel, or
review of the records, the following Licensee Event Reports (LERs) were
closed:
Unit 1
91-07, Revision 0
"Large Break LOCA Analysis Nonconservative Due
To Incorrect RCS Volumes."
91-07, Revision 1
"Large Break LOCA Analysis Nonconservative Due
To Incorrect RCS Volumes."
On March 28, 1991, with Unit 1 operating at 20% reactor power, it was
determined that the value for the reactor vessel refill volume used in
the Large Break Loss of Coolant Accident (LBLOCA) analysis performed by
Westinghouse was underestimated by approximately 182 cubic feet. A
supplement to this LER providing a complete discussion of the event,
causes, corrective actions, and safety assessment was to be submitted by
May 10, 1991.
LER 91-07, Revision 1, was issued on June 14, 1991. This LER contained a
discussion of the event, causes, corrective actions, and safety
assessment associated with the volume underestimation in the LBLOCA
analysis performed by Westinghouse.
Immediate corrective actions as stated in LER 91-07, Revision 1,
included:
1) immediately restricting reactor power level to 75%, and
2) administratively restricting Incore Axial Offset (IAO) to allow
for full power operation.
Planned Corrective Actions were to submit an amendment application to the
NRC by June 18, 1991. The amendment was to request a change to Technical
Specification (TS) 3.11, "Continuous Power Distribution Monitoring,"
reflecting the current administratively imposed IAO values and also to
change the basis of TS 3.5.2, "Control Rod Insertion Limits," for the new
values of specific power and peaking factors.
On June 18, 1991, the licensee submitted Amendment Application No. 196,
which consisted of the Proposed Change No. 245, to the Provisional
Operating License, DPR-13, for SONGS, Unit 1. Proposed Change No. 245
was a request to revise Appendix A, TS Section 3.5.2, "Control Rod
Insertion Limits," and Section 3.11, "Continuous Power Distribution
15
Monitoring." The proposed change was to impose more restrictive limits
on core axial offset than those specified in the current Technical
Specifications.
On July 8, 1992 the licensee requested that the NRC postpone issuance of
Proposed Change No. 245 and make it contingent on Unit 1 operating beyond
its current cycle, Cycle XI. Currently, Unit 1 is scheduled to be
decommissioned at the end of Cycle XI.
The inspector verified the implementation of administrative controls
restricting IAO to allow for full power operation and also changes to the
values of specific power and peaking factors as identified in LER 91-07,
Revision 1. These administrative controls were implemented by reactor
engineering procedures S01-V-1.6, "Incore Flux Mapping", and SO1-V-1.16,
"Axial Offset Correlation." The inspector concluded that no further
followup action is required. This item is closed.
Unit 2 92-006, Revision 0
"Reactor Shutdown To Test Safety Injection Pump
Miniflows."
No violations or deviations were identified.
9. Follow-Up of Previously Identified Items (92701)
a. (Open) Followup Item (50-361-362/91-29-02). "IN-88-73, 'Direction
Dependent Leak Characteristics of Containment Purge Valves.'"
Paragraph 4 of Inspection Report 91-29, dated November 6, 1991,
concerned a followup to NRC Information Notice (IN) 88-73,
"Direction-Dependent Leak Characteristics of Containment Purge
Valves." The IN provided guidance regarding the testing of Fisher
Model 9200 valves used for containment isolation. In particular, it
had been observed that these valves, which have tapered seats, had a
direction-dependent leakage characteristic. The valves could seal
in both directions but a test in the preferred direction did not
always verify sealing in the non-preferred direction.
The licensee's Independent Safety Engineering Group (ISEG) completed
a review of IN 88-73 in October 1988, as documented in report 88
ISEG-152. The ISEG review determined that Southern California
Edison's (SCE) containment penetration testing practices were
acceptable. However, the inspector learned from the ISEG Supervisor
that 88-ISEG-152 was not accurate. A design change, in response to
IN 88-73 had occurred, reversing the seating direction of the Units
2 and 3 inside-containment 8-inch purge valves. Further, the
licensee had committed to review other plant valves which had
leakage limits, to determine if the recommendations of Information
Notice 88-73 also applied. In addition, the licensee also committed
to revise 88-ISEG-152 to include this information.
II16
For followup, on May 28, 1992, "Request for Action: NRC Information
Notice 88-73 (Amended Evaluation), 'Direction-Dependent Leak
Characteristics of Containment Purge Valves' RCTS No. 9205022" was
prepared by the ISEG Supervisor with the action request to
"determine administrative or design changes necessary to resolve
direction-dependent leakage of Fisher Series 9200 valves". On June
5, 1992, a Regulatory Commitment Tracking System (RCTS) E-mail
commitment was received by the ISEG Supervisor accepting these
commitments and proposing a due date of June 1, 1993.
The inspector will monitor the licensee's efforts to resolve this
issue. Therefore, this item will remain open.
b. (Closed) Followup Item (50-206/91-13-03). "NCR Not Written For
Failed Sequencer Test."
Following a monthly surveillance test, troubleshooting and a retest
of the Unit 1 sequencer were performed as a result of varying and
conflicting results. The inspector questioned why an NCR had not
been generated for the test failure. At the time there was some
difference of opinion as to whether or not NCR procedure S0123-XV-5,
"Nonconforming Material, Parts, or Components," was clear in its
direction to generate an NCR for the failed surveillance. The
licensee agreed to review the procedure and make enhancements where
necessary as a result of the inspector's concern.
For followup to this issue, the licensee revised procedure S0123-XV
5 on January 29, 1992, to give more detailed information as to when
an NCR would be required. This revision included specific details
that indicated that when results of a surveillance test fail to meet
acceptance criteria, an NCR shall be written. The procedure also
indicated that an NCR shall be written when a component is
determined to have a failure rate significantly higher than the
industry average as determined by existing programs. Based on these
revisions, the inspector considered that the licensee's actions were
appropriate. Therefore, this item is closed.
c. (Closed) Followup Item (50-206/91-13-04). "Maintenance Program
Implementation For Corroded Fasteners."
The inspector observed several components in the plant with
fasteners which were corroded to some degree (as discussed in
inspection report 206/91-13) and also noted that there was no
program to specifically evaluate the condition of fasteners in many
systems. As a result of the inspector's concern, the licensee
stated that they would evaluate the need for a program to inspect
fasteners. In order to do this they would have to gather data
during the Unit 2 refueling outage in the fall of 1991.
As a result of the licensee's assessment on this matter, it was
determined that levels of fastener degradation, resulting from
corrosion, varied from cosmetic to severe. However, most findings
17
were cosmetic in nature and of the large sample taken (536
maintenance orders), only 32 maintenance orders (MOs) were
identified as having potentially corroded fasteners. And of those,
six MOs were found to have corroded fasteners warranting further
inspection.
The licensee tested fifteen fasteners from the six MOs and one
failure was found. The licensee therefore concluded that although
the number of failures was small, more attention should be given to
routine inspection and preservation of fasteners in plant systems.
The licensee has planned a number of actions with regard to this
matter. For example the licensee would do the following:
o
Enhance training for personnel who walk down systems
o
Include fastener corrosion identification in the SONGS
preservation program
o
Include incidents observed of fastener corrosion with the
weekly active leak report
o
Expand the thermography program to cover insulated high energy
systems on a sampling basis
o
Develop a procedure for inspection and further corrective
actions as warranted
The inspector considered that the licensee's efforts and planned
corrective actions appeared adequate. However, the inspector will
continue to monitor the licensee's implantation of corrective
actions as part of the routine inspection effort. This item is
closed.
d. (Closed) Followup Item (50-361/91-13-02). "Material Condition Of The
Units - MO Backlog."
As discussed in inspection report 50-361/91-13, the inspector noted
numerous deficiency tags on equipment in all three units. Although
most of the items appeared to be of relatively low safety
significance, many dated back a few years (to 1987 or 1988).
It was
noted that the backlog of outstanding maintenance items appeared to
have been increasing in recent months, with most items being low
priority (non-safety related). (A backlog is considered as
corrective maintenance items that are safety or non-safety related
that have been in existence for more than 120 days that are awaiting
work that can be done on-line.)
The inspector had noted the slowly
increasing backlog of items awaiting repair and questioned whether
they were being properly prioritized and effectively dealt with.
Discussions with the licensee revealed that they were aware of the
18
backlog and had provided a method of tracking and trending these
items. The licensee also indicated that a Work Authorization Task
Force (WATF) had been formed to review the situation and recommend a
course of action.
The inspector reviewed the licensee's WATF efforts and noted that a
number of recommendations were made. Recommendations included the
implementation of work window managers, a dedicated operator to
interface between Maintenance and Operations for the issuance of
work orders, and a revised prioritization scheme. The inspector
also noted that the licensee's Nuclear Oversight Department (NOD)
also performed an organizational assessment that introduced a number
of recommendations.
The inspector noted that the licensee was in the process of
implementing a Work Process Management Team consisting of the
Operations and Maintenance Superintendents in Units 2 and 3. They
will be responsible for setting a charter and a schedule to further
enhance the maintenance process and implement remaining WATF and NOD
recommendations. The licensee also was very close to implementing
procedures that streamline and enhance the maintenance process by
incorporating all work group responsibilities into a single set of
procedures.
With regard to the maintenance order backlog, the licensee just
recently dedicated significant resources to reduce it. The
inspector noted that some progress has been made, although there was
a long way to go. Discussions with the licensee indicated that they
believed the backlog reduction rate would increase as maintenance
efforts get fully implemented.
The goals for maintenance items were less than 500 items per unit in
Units 2 and 3. Discussions with the Maintenance Manager indicated
that Unit 1 currently met the backlog goal.
However for Units 2 and
3, the level of items was approximately 650 items per unit at the
end of the inspection period.
The inspector noted that some maintenance items were being resolved
by the minor maintenance effort. This process as defined in
procedure S0123-XX-3, "Minor Maintenance Program," consisted of less
paperwork and planning needed to execute the work activity. Minor
maintenance is done on equipment if it meets a number of
requirements (e.g., it is within the skill of the craft, no written
work plan is necessary, it does not involve the disposition of an
NCR, and it does not require any operability testing).
The
procedure also provided examples of work activities that would fit
in the minor maintenance category.
The inspector considered the licensee's efforts to understand and
correct weaknesses in the maintenance process to be extensive. The
effectiveness of these actions and the licensee's efforts to reduce
the backlog of maintenance items including work performed under
19
minor maintenance procedures, will be reviewed as part of the
routine inspection effort. This item is closed.
e. (Closed) Information Notice (50-206/IN-86-99), Supplement 1,
"'Degradation Of Steel Containments' - Inspector Followup On
Licensee ISEG Evaluation For Potential Applicability To Unit 1."
NRC IN 86-99, Supplement 1, "Degradation Of Steel Containments," was
issued in response to the discovery of significant corrosion on the
external surface of the carbon steel drywell in the sand bed region
of the Oyster Creek plant.
On August 26, 1991, the licensee's ISEG organization issued its
evaluation of NRC IN 86-99. The inspector noted that the evaluation
stated that the SONGS Unit I containment is a 140 ft. diameter steel
sphere which extends 40 ft. below grade. It is continuously
supported by a concrete cradle between the steel shell and the
undisturbed soil.
The free-standing steel shell contains a concrete
structure which provides support and shielding for the equipment.
Loads from this structure are transmitted through the sphere shell
and the exterior concrete cradle to the soil.
The exterior surface
of the sphere, below grade, is protected from corrosion by an epoxy
coating and by cathodic protection. The cathodic protection system
is the impressed current type.
The method of verification for containment integrity is an
Integrated Leak Rate Test (ILRT) per 10 CFR 50, Appendix J. The
licensee stated that, as of the date of the ISEG evaluation, no ILRT
data had been obtained that would indicate that containment
integrity had deteriorated.
The inspector considered the evaluation adequate and that no further
followup action is required. Therefore, this item is closed.
f. (Closed) Information Notice (50-361, 362/IN-91-13). "Inadequate
Testing Of EDGs - Applies To 2nd And 3rd Units At Multi-Unit Sites."
This IN was intended to alert licensees to inadequacies in the
testing of emergency diesel generators (EDGs) at nuclear power
plants. In particular, some EDG testing had not adequately verified
the capability of the EDG to carry its maximum expected loads and
other tests had failed to properly verify the operation of the load
shedding logic for the EDG. More specifically, it was noted that
there was no requirement to test the EDG at its reactive load limit
or to compensate for ambient temperature effects.
The inspector reviewed the licensee's evaluation of the conditions
as applicable to SONGS. The inspector noted that the licensee
concluded, after discussions with the vendor, that a requirement to
compensate for ambient temperature variations was not necessary
since the EDG would only be affected by temperatures well above the
design maximum of 100 degrees in the diesel generator buildings.
20
The inspector also noted that the licensee revised procedure S023-3
3.12, "Diesel Generator Monthly Test," to include testing the EDGs
at reactive loads of 3000 to 3200 KVAR which is greater than the
worst case reactive load calculated at 2614 KVAR.
The inspector considered that the licensee's evaluation of this IN
was adequate. Therefore, this item is closed.
No violations or deviations were identified.
10. Follow-Up On Items Of Non-Compliance (92702)
a. (Closed) Violation (206/91-36-01). "Inoperable Halon System In The
4KV Switchqear Room."
This item identified that the Unit 1 4160 VAC (4KV) room Halon
system was inoperable without a continuous fire watch being
available for certain periods of time as required by Technical
Specifications (TS).
The licensee implemented a number of corrective actions following
the inoperability of this event. Those actions included properly
configuring the Halon system, revising procedures to include
drawings and instructions for the system actuation lines, and plans
to provide specific training on proper configuration of the Halon
system. The inspector considered the licensee's actions (both
implemented and planned) to be appropriate. Therefore, this item is
closed.
b. (Closed) Violation (206/91-36-02). "Inadequate Licensee Report
Concerning The Inoperable Halon System In The 4KV Switchgear Room."
This item identified a statement in an LER which was inaccurate.
The inaccurate statement was that a design basis fire in the 4KV
room would not have prevented the Unit from achieving and
maintaining safe shutdown.
For corrective actions on this issue, the licensee revised the LER
to properly reflect plant conditions at the time of the event,
discussed with LER writers the need to ensure that safety
assessments consider all plant conditions, and had all management
personnel review the response to the NOV to ensure that they were
aware of the need for LERs to be complete and accurate. Based upon
these actions, this item is closed.
c. (Closed) Violation (206/91-36-03). "Inadequate Halon System
Testing."
This item identified that the licensee's test program did not
include testing to demonstrate operability of the Halon bottle slave
cylinders.
21
For corrective actions to this item, the licensee revised the Halon
bottle surveillance procedures to include drawings of the system
actuation configuration and to include the fire protection system
manuals in the Vendor Interface Program to ensure that vendor
information is properly incorporated into fire protection
procedures. The inspector considered the licensee's actions
appropriate. This item is closed.
d. (Closed) Violation (50-361/91-13-04). "Followup Of Corrective
Actions Described In Licensee Civil Penalty Response Dated 2/2/91."
As discussed in inspection report 50-361/91-13, three corrective
actions remained to be completed concerning two violations first
referenced in inspection report 50-361/90-37. These violations
involved an auxiliary feedwater pump being inoperable due to a
misaligned steam trap (Unit 2), and the ECCS and containment spray
subsystem being inoperable due to a misaligned emergency sump outlet
valve (Unit 3).
The corrective actions that remained to be implemented from the
licensee's February 2, 1991, response to the Notice of Violation
were the following:
"
Install audible annunciator for engineered safety feature (ESF)
valves when in abnormal positions.
"
Review the administrative workload assigned to operators to
reduce non-operational duties.
o
Perform an AFW pump/turbine overspeed trip analysis to
determine optimum setting.
As of this inspection period, the licensee completed a review of the
administrative workload assigned to the operators. This resulted in
a number of changes to reduce the administrative burdens including
the assignment of a designated operator to interface with
maintenance in the preparation of work authorizations.
The inspector noted that the licensee formulated a work schedule to
install the audible annunciator for ESF valves during the Cycle VIII
refueling outages for Units 2 and 3. This commitment was entered in
the licensee's regulatory commitment tracking system (RCTS) to
ensure completion of the commitment.
The inspector noted that the licensee formulated a schedule to
perform the AFW pump turbine overspeed trip analysis during the
upcoming Cycle VII refueling outages for Units 2 and 3. This action
was also entered in the licensee's RCTS system to ensure completion
of the required action.
The inspector considered that the licensee's proposed and completed
I
22
corrective actions were conservative measures and appeared adequate
to minimize the potential for similar errors. Implementation of
remaining actions will be reviewed as part of the routine inspection
effort. Therefore, this item is closed.
No violations or deviations were identified.
11.
Unresolved Items
Unresolved items are matters about which more information is required to
determine whether they are acceptable items, violations or deviations.
An unresolved item addressed during this inspection is discussed in
paragraph 4 of this report.
12.
Exit Meeting
On July 16, 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.