ML13323B269
| ML13323B269 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 07/15/1987 |
| From: | Burdoin J, Caldwell C, Brendan Collins, Datta A, Eng P, Fiorelli G, Mclaughlin P, Jim Melfi, Richards S, Russell J, Sorensen R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V), Office of Nuclear Reactor Regulation, NRC OFFICE OF NUCLEAR REGULATORY RESEARCH (RES) |
| To: | |
| Shared Package | |
| ML13323B267 | List: |
| References | |
| 50-206-87-05, 50-206-87-5, NUDOCS 8707310138 | |
| Download: ML13323B269 (37) | |
See also: IR 05000206/1987005
Text
U. S. NUCLEAR REGULATORY COMMISSION
REGION V
Report No.
50-206/87-05
Docket No.
50-206
License No.
Licensee:
Southern California Edison Company
P. 0. Box 800
2244 Walnut Grove Avenue
Rosemead, California 91770
Facility Name:
San Onofre Nuclear Generating Station, Unit 1
Inspection at:
San Clemente, California
Inspection con
te
Inspectors:
F. B rd in, Project Inspector
Dfte Signed
C. W. Caldwell, Project Inspector
Date Signed
-7/I
G.- Fiorelli, Resident Inspector
Date Signed
V
F. ef
eactor Inspector
Date Signed
{lP. W.
aughinZ,
Office of Nuclear
Reactor egulation
frvA. a
, Office of Nuclear Regulatory
DitI (hned
Resea h
6e'P.
Ehg,
ident Inspector
Da
B. C
- _
C o nsuZ
adSg
Rus elT, Radiatiab Specialist
Date Signed
R. C.
sen, Team Leader
Dat
8707310138 870717
ADOCK 0500206
DPeMige
-2
Approved By:
87&
-_
S. A. Richards, Chief
Date Signed
Engineering Section
Inspection Summary:
Inspection on June 1 -
June 12, 1987 (Report No. 50-206/87-05)
Areas Inspected:
Announced team inspection of San Onofre Nuclear Generating
Station (SONGS) Unit 1. The inspection focused on determining the
effectiveness of preventive and corrective maintenance practices in
preventing, or detecting and correcting, equipment degradation. The
inspection was conducted for a two week period during a 42-day mid-cycle
maintenance outage in Unit 1.
The following activities were examined:
1)
Procurement Program
2)
Quality Assurance Program
3) Operations
4)
Surveillance Testing
5)
I&C, Electrical and Mechanical Maintenance Practices
6) IST Program and Implementation
7)
Engineering
8)
Health Physics
This inspection was conducted by six NRC Region V inspectors, one NRC staff
engineer from NRR, one NRC staff engineer from the Office of Research, one NRC
inspector from Region III, and one contractor. Inspection Procedures 30702,
30703, 41400, 37700, 38701, 62700, 62704, 62705, 73756, 72701, 83729, 92701
and 92702 were applied to this inspection effort.
Results: Of the areas inspected, two violations of NRC requirements were
identified. One violation was identified in the area of providing adequate
information to permit individuals to take precautions to avoid or minimize
their exposure to radiation (paragraph 11) and one violation (two examples) was
identified in the area of demonstrating 125 volt vital battery no. 1 operable
(paragraph 2).
DETAILS
1.
Persons Contacted
San Onofre Nuclear Generating Station (SONGS)
- H. B..Ray, Vice President and Site Manager
- W*
C. Moody, Deputy Site Manager
- H. E. Morgan, Station Manager
.*D. Heinicke, Deputy Station Manager
D. B. Schone, QA Manager
- R. W.- Krieger, Operations Manager
- D. E. Shull, Maintenance Manager
- P. Knapp, Health Physics Manager
W_ G. Zintl, Compliance Manager
.*J. T. Reilly, Station Technical Manager
- M. A. Wharton, Assistant Technical Manager
- K. E. O'Connor, E&C Field Manager
- H. W. Newton, Material Support Manager
- M. 'P.
Short, Nuclear Training Manager
- ,J.
J . Wambold-, Project.Manager
- W. M. Lazear, A Supervisor
- B. Katz, Manager, Outage Management
- D. C. Stonecipher, QC Manager
- G. D. Bogosian, QA Supervisor
- K.
L. Brooks, Health Physics Supervisor
J. M. Joy, Outage Management Supervisor
- R. D Plappert, Compliance Supervisor
'*K...Johnson, NSSS Engineering.Supervisor
J. Schramm, Operations Superintendent
- L. 0. Cash, Unit 1 Maintenance Manager
- C. A. Couser, Compliance Engineer
W.Denotesthose persons attending the final exit meeting on June 12, 1987.
The inspectors talked with numerous other licensee employees during the
course of the inspection
r
2C
Review of
Station Class 1E Batteries
a.
Battery Surveillance Testing
When the team arrived onsite on June 1, 1987, it was learned that
one of the station Class E batteries had failed a surveillance test
a short time before the team's arrival.
Since the objective of the
team inspection was to evaluate how well the licensee detected and
corrected equipment degradation, it was decided that this would be
an appropriate event to review in light of the team's objective.
The inspectors therefore reviewed, with the licensee, the results of
the service test that.was performed May 29, 1987 on 125 volt vital
battery no. 2. The batteryihad failed its service test since it
2
reached its low voltage limit after approximately 20 minutes of the
90 minute test. The licensee determined that the wrong load profile
values were used to perform the test. These values were from a
calculation sheet that had an extraneous load profile, i.e. a dotted
line on a graph, in addition to the actual load profile. These
extraneous load profile values were the ones used in the service
test.. This extraneous dotted line represented discharge rates that
were approximately twice as great as those of the correct load
profile.. Thus the battery reached its low voltage limit in 20
minutes. The test was halted when the battery terminal voltage
reached its low limit, thereby saving the battery cells from
potential damage due to cell reversal.
The inspectors noted that the calculation was prepared by one
engineer, reviewed by an independent engineer and two supervisors,
and issued by E&C. The calculations underwent various reviews by
Station Technical personnel and were then incorporated into the
service test procedure. However, no one in E&C, Station Technical,
or the maintenance personnel who wrote the procedure, caught, or
questioned the extraneous dotted line with the incorrect values
during the review process. As a result of this review and the
discrepancies identified, the inspectors questioned the values that
were used in the performance.of the service test on 125 volt vital
battery no. 1.
The inspectors reviewed the documentation that the licensee provided
for battery no. 1. This battery was installed on May 18, 1984 to
replace an aging battery. E&C personnel performed a load profile
calculation for this battery so that an acceptance test could be
performed. This load profile calculation, DC-1604 Rev. 0, was
performed on April 23, 1984 and was used in the acceptance test that
was performed on the battery on July 23, 1984.
On April 14, 1986, Rev. 1 to calculation DC-1604 was issued to
analyze the effect of adding 125 volt vital inverter 4A to the load
profile for battery no. 1. Shortly thereafter, Proposed Facility
Change (PFC) 1-86-3400.13 Rev. 0, was issued to add inverter 4A to
the plant. The inspectors reviewed the PFC and the new load profile
calculation along with licensee personnel. This PFC indicated that
the change to the plant had no impact on surveillances, Technical
Specifications, or limiting conditions for operation, as part of the
engineering/safety evaluation. However, that was incorrect, since
it did increase the load profile on battery no. 1 which affected the
service test surveillance procedure. Consequently, the need for a
change in the service test to include the load addition was not
identified and this load addition to the battery and the resulting
change in load profile were not included in the service test
procedure. As a result, on May 7, 1986, the battery no. 1 service
test was completed using the original Rev. 0 load profile
calculation. These values were less than the Rev. 1 values.
Therefore, the battery was not demonstrated operable in accordance
with station Technical Specification 4.4.0.2.d. This is a violation
of Technical Specification requirements (87-05-01). The inspectors
noted that in this case also,, the PFC was reviewed and approved by
3
various independent and supervisory E&C and Station Technical
personnel.
However, nobody recognized that a change to the service,
test procedure was required.
As a further example of missed opportunities, the inspectors noted
that on May 7, 1986, the Independent Safety Engineering Group (ISEG)
issued a report on an evaluation they did of the PFC administrative
procedure. ISEG recommended in their report that the PFC procedure
be revised to require that a new load calculation be performed
whenever it is determined that a load is added to the batteries.
Upon receipt of the new calculation, Station Technical should assess
the need for modification of the battery surveillance procedures and
provide the information to Maintenance as necessary. During the
turnover of vital inverter 4A, it was discovered that an Appendix R
and a seismic qualification evaluation were needed for this
component. Therefore, it was not placed in service until a few
months later. On July 15, 1986, Rev. 1 to PFC 1-86-3400.13 that
added inverter 4A was issued. This revised PFC also indicated that
the calculation had been updated but incorrectly stated that there
was no impact on existing surveillance requirements, Technical
Specifications, or limiting conditions for operations in the
engineering/safety evaluation. Therefore, the service test
procedures were not revised to include the new load.profile. Again,
the PFC underwent various levels of review by E&C and Station
Technical personnel.. The May 7, 1986 ISEG report recommendation
discussed previously, was incorporated as temporary change (TCN) 6-1
to the PFC procedure. The ISEG report was issued 2 months prior to
PFC 1-86-3400.13 Rev. 1 but TCN 6-1 was not added to the PFC
procedure until 6 months later on November 13, 1986. If this change
had been made prior to issue of the revised PFC, it would have
required that an assessment be made of the new calculation for the
need to modify the surveillance procedures and provide the
information to Maintenance as necessary. This could have prevented
the use of the wrong calculation in the service test procedure.
Over the next few months several other changes were made to the
battery no..1 load profile. On September 15, 1986, Rev 2 to
calculation DC-1604 was issued which reflected increases to the
battery no. 1 load as part of a "worst case adjusted load" profile.
On February 12, 1987, PFC 1-87-3465 Rev. 0 was issued to remove the
regulating transformer for inverter 4A. This caused a slight load
reduction on battery no. 1.
On May 22, 1987, the scheduled refueling interval service test was
performed. Again, the load profile values from calculation DC-1604
Rev. 0 were used. These values were still less than the Rev. 2
values. Therefore, the battery was not demonstrated operable for a
second time in accordance with station Technical Specification 4.4.0.2.d. This is a further example of violation (87-05-01).
Ih addition, an extraneous 815 amp discharge rate was included
somehow on page 9 of the DC-1604, Rev. 2 calculation. This value is
labeled as representing the original load duty cycle andas being
superceded by section 7.2 of the calculation. Section 7.2 shows the
4
value as 800 amps. Procedural reviews did not catch or question
this error.
Based on these discrepancies, the inspectors questioned the load
values used in the acceptance test performed on battery no. 1 in
1984. The acceptance test consisted of a service test and a
performance test. The inspectors noted that the service test
portion was performed satisfactorily. However, the inspectors were
concerned about the values used in the performance test portion.
That portion required that the battery be discharged at a value
specified by the vendor for a certain period of time. In this case,
the time period was 90 minutes. The procedure indicated that the
battery be discharged for this period at 1240 amps.
Licensee
personnel evaluated the calculations upon the inspectors' request
and determined that the value that should have been used was 944
amps. Once again, the values that were provided by E&C were
incorrect and were incorporated into station procedures. In this
case however, the test was performed in a conservative manner,
although this still indicates a laxness in the performance of
technical work.
As a result of these problems the licensee took aggressive action
toward resolving the deficiencies identified in past battery service
tests. The license issued several non-conformance reports (NCRs) to
identify the battery service test problems and to propose corrective
action. In addition, the QA organization prepared two CARs that
will be used to perform a generic evaluation of the design control
process. The licensee committed to correct the deficiencies in
accordance with an interim root cause analysis, Rev. 1, dated June
9, 1987, as follows:
1.
Prepare a TCN to battery surveillance procedure S01-I-2.7 to
test per the calculation DC-1399, Rev. 2, documented load
profile for battery no. 2.
2. Add a step to record battery voltage at the end of the 90th
minute, prior to removing the load current, for future
reference.
3.
Require that the Individual Cell Voltages (ICVs) be recorded
during the load test so that any failed cell can be identified
after the first load test. (This should have been done
previously as a good engineering practice).
4.
Revise station maintenance procedures for all 3 units' battery
service tests to:
0
require that the station cognizant engineer document the
revision of the calculation in effect during the last
battery service test, document the current revision of the
applicable battery load calculation and verify that the
load profile within the maintenance procedure correctly
applies to the calculated load profile.
5
Clearly specify the required wait time after an equalizing
charge prior to starting a service or performance test.
5.
Review E&C QA procedures for "Proposed Facility Changes" and
revise as required to ensure that modifications that alter the
battery loading require re-analysis of the battery load
calculations and reperfomance of the battery service test as
necessary. This was completed per TCN 6-1 to the PFC
procedure.
6. A refueling interval battery service test will be performed on
battery no. 1 in accordance with Calculation DC-1604, Rev. 2,
and PFC 1-87-3465 prior to Mode 4 entry.
7. Expand the review of battery calculations and refueling
interval service test procedures to include the remaining Unit
1 batteries and all Units 2 and 3 batteries.
8.
Review and revise, as required, the battery maintenance
procedures and operating instructions for Units 1, 2, and 3 for
uniformity and adequacy and to add specific definitions of
battery operability requirements following maintenance.
9.
Perform further analysis, by the QA organization, of the
problems identified with the design review process.
SO-P-1049 and SO-P-1050 have been issued in order to evaluate
why testing was performed on the batteries with the incorrect
acceptance criteria provided in the procedure and why the
configuration document checklist did not show that there needed
to be a change to the discharge procedure.
As a followup to the discrepancies identified, the licensee
performed service tests of both battery no. 1 and 2 prior to startup
of the unit. Both batteries passed these tests and were
demonstrated operable.
b.
System Physical Walkdown
The inspector conducted observations of equipment and component
rooms to determine if they were being maintained in accordance with
station procedures and regulatory requirments.
In general, components, systems, and areas appeared to be well
maintained and in good physical condition. However, the inspector
identified the following concerns to the licensee for evaluation:
Battery no. 1 battery has styrofoam end spacers located at one
end of each row of battery jars. This could potentially
jeopardize the seismic qualification of the battery. This
concern was identified to the licensee for evaluation. The
inspector will review the licensee's evaluation. This is
identified as inspector followup item (87-05-02).
6
There were two bottles used as portable eyewash stations
located in battery no. 2 room. One of the eyewash stations was
secured to safety related conduit that contained the battery
cables. This was done by using a long chain. This bottle, as
installed, could damage several battery jars or damage the
battery connectors if a seismic event should occur. Station
procedure S0123-1-1.20 Rev 1, denotes the controls that are in
place to ensure that every reasonable effort is made to prevent
impairment of any safety related system
Section 6.1.1
requires that precautions shall be taken to ensure that no
tool, material, or any other item capable of damaging a
safety-related piece of equipment be allowed to impact any
safety-related equipment. The inspector was concerned that
even though there is a procedure in place to protect
safety-related equipment, personnel are not adhering strictly
to the procedure. Similar conditions have been previously
identified in resident inspection report 50-206/87-03. The
licensee's corrective actions on controls over items located
near safety-related equipment will be followed in a future
resident inspector report.
3. Modification Testing
To evaluate the licensee's program for modification testing, several of
the licensee's documents which describe their program for testing were
reviewed. These documents include administrative procedures for testing
and are listed below:
Topical Quality Assurance Manual, Chapter 6-C Construction
Inspection and Testing.
Topical Quality Assurance Manual, Chapter 6-0 Prerequisite,
Preoperational, and Startup Testing.
Retrofit Program Manual, Volume II, Administrative Procedure AP-4
(S0123-AP-004) Preparation, Review and Approval of Prerequisite Test
Procedures.
Retrofit Program Manual, Volume II, Administrative Procedure AP-5
(S0123-AP-005) Preparation, Review and Approval of Preoperational
Testing Procedures.
Retrofit Program Manual, Volume II, Administrative Procedure AP-6
(S0123-XXVI-2.6) Review, Evaluation and Approval of Test Results.
-
Retrofit Program Manual, Volume II, Administrative Procedure AP-7
Test Working Group.
The test procedures that were used during the modification activities
which were reviewed were:
Instrument and Test Procedure, 501-I1-1.32, Pneumatic Valve
0
Cal ibrati on.
7
Instrument and Test Procedure, S0123-I1-9.37, Control Valve
Calibration.
Generic Test Procedure, GT-400-14 (S0123-XXVI-6.4.14), Circuit and
Calibration Tests.
Because of the dates of the inspection, most of the modifications planned
for this-outage were completed prior to the team's arrival.
Most of the
Construction Work Orders (CWOs) which were reviewed had already been
performed, signed-off, and sent to configuration control for final
documentation. Therefore, there were very few opportunities for
observing actual modification testing being performed.
The following CWOs were reviewed during this inspection:
87031251000, S1-RSS-CV-948-ACT, PRT Gas Space Sample Actuator (Valve
Preload Setting)
87060463000, S1-ELE-Y14, 120V Vital Bus 4 (Transfer Switch
Modification)
87030385000, S1-DG1-EO8, L.V. Exciter Cabinet DGI (Conduit and
Cable)
- 86051181000, S1-VCC-2159, Discharge Solenoid Valve from Charging
Pumps Suction Header (Piping)
87020467000, S1-MVS-MSH-4109, A-33 Fan Intake High Humidity Switch
(Switch Installation)
- 87030912000, S1-MVS-A-33, Emergency Makeup Fan for A-31 (Power On
Mechanical Testing)
Two of the CWs were examined in more detail than the others. For an
example of a CWO which had been completed, CWO # 87031251000 was used.
The CWO selected for in-field inspection was CWO # 87060463000.
During the review of the completed CWO (87031251000), it was found that
the test procedure identified to be used in the work package had been
superseded by another procedure. Based on the dates on the CWO for
planning and approval of the work order, the superseding had occurred
prior to the development of the CWO.
However, the technician identified
the proper test procedure when he began working on the task. The
inspector felt that the incorrect test procedure should have been
identified during the approval process. Upon questioning QA personnel,
they stated that the approval dates on the procedure don't always reflect
when the procedure was developed (the procedure is often prepared long
before those dates that appear). They also stated that this is an
example of why the CWOs always include a step for the technician to
assure he has the most recent revision of the procedure.
As a result of'these conversations with QA, several QA Field Surveillance
Reports were reviewed. These reports indicated that minor discrepancies
I
8
similar to the one noted above occur and are resolved by the technicians
per program guidelines.
While observing work in the Unit 1 Control Room, a problem arose
concerning the functional testing required by CWO 87060463000. This CWO,
which affected Vital Bus #4, referenced a generic test procedure for
performing the functional test on a design modification. When the
reactor operator requested clarification as to what the functional test
affected, the technicians and cognizant engineer generated a two (2) page
"back of the envelope" type procedure. After the operator expressed
concern about performing parts of the test, the shift superintendent
interjected and said the work would not be done until the informal
procedure was evaluated and approved by engineering personnel. The CWO
was subsequently revised to include these steps and plans were made to
perform the test.
Startup Engineering's position is that this "back of the envelope"
process is a type of "tailboarding" and takes place all the time. Also,
the Generic Test Procedure for Circuit and Calibration Tests is often
approved and used for modification testing. However, the fact that the
reactor operator requested more information and the shift superintendent
requested engineering approval reflects the inadequacies of using generic
test procedures for performing tests. The inspector contends that the
generic test procedure should only be used to develop a detailed
procedure (similar to the one subsequently generated by Startup
Engineering).
Further, at the QC holdpoint in the CWO, it was not clear
what the QC inspector was specifically required to verify.
Although no violations or deviations were identified, several concerns
were identified regarding this program.
The previous example illustrates a lack of engineering effort in the area
of test procedure preparation and planning for post modification testing.
The test procedure was inadequate and appeared to have no engineering
guidance or management approval.
The "back of the envelope" approach is
not suitable for the testing of safety-related equipment. This less than
rigorous effort by Startup Engineering is another example of a weakness
in the performance of technical work.
4.
Inservice Testing Program
a. Overall Program Status
San Onofre Nuclear Generating Station, Unit 1, is currently in their
first ten year inspection interval which is scheduled to end on
December 31, 1987. The licensee is currently in the process of
updating their Inservice Testing (IST) program in preparation for
the second ten year program. Current valve and pump test programs
are written to comply with the requirements of the 1977 Edition of
the American Society of Mechanical Engineers' Boiler and Pressure
Vessel Code, up to and including the Winter 1979 Addendum.
By letter dated December 22, 1977, the Division of Operating
Reactors advised the licensee to implement the proposed IST program
.
9
until a detailed review of the program was completed. As of the
date of this inspection, the licensee's IST program had not been
approved.
b.
Inservice Testing of Valves Program
The licensee delineates the policies and procedures for inservice
testing of valves in the following procedures:
S0123-IN-1, In-Service Inspection Program
S01-V-2.15, In-Service Testing of Valves Program
S01-12.4-2, Operations In-Service Valve Testing
S0123-V-5.15, Inservice Testing (IST) Coordination and Trending
The inspector reviewed the valve inservice testing requirements.
Based on this review which included the NRC findings related to the
November 21, 1985 loss of power and water hammer event at San Onofre
Unit 1, documented in NUREG-1190, the inspector determined that the
valve inservice program was based on the ASME Boiler and Pressure
Vessel Code,Section XI,.which specifies valve inservice testing
(IST) requirements, and states in part:
Valves shall be exercised to the position required to fulfill
their function unless such operation is not practical during
plant operation....
Valves that cannot be exercised during
plant operation shall be specifically identified by the owner
and shall be full-stroke exercised during cold shutdowns.
Full-stroke exercising during cold shutdowns for all valves not
full-stroke exercised during plant operation shall be on a
frequency determined by the intervals between shutdowns as
follows:
for intervals of 3 months or longer, exercise during
each shutdown; for intervals of less than 3 months, full-stroke
exercise is not required unless 3 months have passed since last
shutdown exercise.
Further review of the licensee's program revealed that Step
6.3.1.2.d of licensee procedure SO1-V-2.15 states that "As a matter
of policy, an initial requirement of 25% (minimum) of all cold
shutdown valves will be tested each Mode 5 forced outage."
Item K
of Attachment 1 to the same procedure states, "Valve testing at cold
shutdown is valve testing which commences not later than forty-eight
hours after cold shutdown and continues until required testing is
completed or Plant startup, whichever occurs first....
Completion
of all required valve testing is not a requisite to Plant startup.
Valve testing which is not completed during a cold shutdown will be
performed during subsequent cold shutdowns...."
The inspector noted that during the only Mode 5 shutdown since the
water hammer event that occurred September 4-28, 1986 (excluding the
current mid cycle outage) 40% of the valves listed on the cold
10
shutdown test list were tested. During the current outage all of
the valves listed on the cold shutdpwn test list will be tested.
The inspector inquired as to the changes made to the valve IST
program resulting from the water hammer event of November 21, 1985.
The licensee stated that 17 check valves in the feedwater system and
the auxiliary feedwater system had been replaced after the event and
that these check valves are full stroked and leak tested at every
cold shutdown. Review of the valve program revealed that although
the valve test requirements had been revised, the valves in question
were still designated as category "C".
The licensee agreed to
revise the valve categories for the 17 check valves in their next
IST program submittal to NRR. Revision of the licensee's valve IST
program to reflect the valve recategorization of the 17 check valves
will be tracked as an open item (87-05-03).
The inspector inquired whether valves which can be controlled from
the licensee's dedicated shutdown (DSD) panel were included in the
valve IST program. The licensee stated that there was only one
valve whose position was indicated on the DSD panel and that the
valve in question, FCV-5051, was not included in the IST program.
IWV-1100 defines the scope of IST testing for valves to encompass
"those valves which are required to perform a specific function in
shutting down a reactor... or in mitigating the consequences of an
accident."
IWV-3300 states that valves with remote position
indicators shall be observed at least once every 2 years to verify
that valve operation is accurately indicated. Although the DSD
panel has been in place for approximately a year, the inspector
noted that FCV-5051 had not been included in the valve IST program
as submitted to the Commission. The licensee's QA organization
initiated a Problem Review Report (PRR) to address this concern.
The inspector will follow the licensee's resolution of this concern
(50-206/87-05-04).
No violations or deviations were identified.
c. Valve Testing
The inspector reviewed selected valve test procedures and noted that
the method to be used for obtaining valve stroke times was not
specified. The licensee stated that a valve stroke time technique
would be added to the appropriate procedures to ensure valve stroke
timing consistency in accordance with the requirements of
IWV-3413(a), by August 1, 1987. Incorporation of a specific valve
stroke timing method to valve test procedures by the licensee will
be tracked as an open item (87-05-05).
Subsection IWV-2300 of Section XI defines valve exercising as "the
demonstration based on direct or indirect visual or other positive
indication that moving parts of a valve function satisfactorily."
IWV-3413 provides for the limiting value of full stroke time as one
of the criteria for test acceptance. Consequently, stroke time
limits for valves must be chosen such that operation within such
limits indicate satisfactory valve condition. Several of the
11
maximum allowable stroke times, as defined by the licensee, are not
adequate for this purpose. For example, several valves that
typically stroke in less than 10 seconds are assigned maximum valve
stroke time values of up to 120 seconds. The inspector noted that
the maximum allowable stroke times have been submitted to'NRR for
review.
The licensee stated that, although they assign maximum stroke times
of up to 120 seconds, they initiate corrective action on valves
based on the criteria delineated in IWV-3417, which is triggered on
significant increases in stroke time from the-last valve stroke time
test.
d.
Inservice Testing of Pumps Program
The licensee delineates the policies and procedures for inservice
testing of pumps in the following procedures:
S0123-IN-1, In-Service Inspection Program
SO1-V-2.14, In-Service Testing of Pumps Program
S0123-V-5.15, In-Service Testing (IST) Coordination and
Trending
The inspector reviewed licensee relief requests for the IST of pumps
and noted that a relief request addressing the expansion of the
allowed full scale range of inservice testing instruments from three
times the reference value to four times the reference value had been
submitted -to the Commission. IWP-4120 states that the full scale
range of each instrument shall be three times the reference value or
less. Since there appears to be no basis for the licensee's relief
request, the licensee's QA department agreed to pursue resolution of
this discrepancy.
The inspector noted that the licensee had not established acceptance
criteria for pump bearing temperatures based on the manufacturer's
recommendations. This item was also identified in a recent QA audit
of the licensee's IST program and will be resolved by June 30, 1987.
e.
Inservice Testing Performance
The inspector witnessed the inservice testing of the G-10W electric
driven auxiliary feedwater pump. The test engineer performed the
pertinent portions of test procedure SO1-V-2.14.1, "Auxiliary
Feedwater In-Service Pump Test" in accordance with the requirements
of the procedure. Prior to and during test performance both the
cognizant engineer and the equipment operator repeatedly inspected
the material condition of the pump and associated piping and valves.
Test.data was obtained in general agreement with the methodology
specified in the Code; however, the inspector noted that neither the
test procedure nor the physical pump installation had provided for
identifying the locations on the pump and motor bearing where
vibration data was to be obtained. IWP-4160 states that instruments
12
that are position sensitive shall be either permanently mounted or
provision shall be made to duplicate the position for each test.
IWP-4520 allows use of a portable vibration indicator that clearly
identifies the probe or measurement reference point to permit
subsequent duplication in both location and plane. The licensee
stated that vibration measurements on pumps in the IST program are
taken by the system cognizant engineer who knows where to take
vibration readings, and several system cognizant engineers stated
that they always measured vibration at the same point from test to
test. Review of pump test data by the inspector could not identify
instances where failure to measure bearing vibration at specific
points per the requirements of the Code was key in determining pump
operability. The inspector stated that should the cognizant
engineer be unavailable to perform IST tests in the future, the
locations for obtaining pump vibration data for IST purposes would
be subject to question. The licensee stated that an evaluation of
an appropriate method to clearly define points where IST vibration
data is to be taken would be performed and incorporated into the
pertinent IST test procedures for all 19 pumps in the IST program by
July 15, 1987. Completion of incorporation of vibration data point
locations into licensee procedures for all pumps in the IST program
will be tracked as an open item (87-05-06).
During performance of the Auxiliary Feedwater pump G-10W test, the
inspector noted that the lubricant in the slinger ring region
appeared to be the consistency of syrup. The cognizant engineer
stated that he would request that the oil be sampled and changed.
The inspector also noticed a lube oil addition log sheet stored on
the side.of the pump motor housing which is subjected to the
prevailing.environment and was becoming hard to read. The cognizant
engineer stated that the copy observed by the inspector was a field
copy and not the official records copy.
f. Quality Assurance Audits of IST Programs
The inspector reviewed the licensee's latest QA audit (SCES-042-86)
of the implementation of the IST program and noted that the audit
was both comprehensive and thorough. Identified findings were
pertinent, appropriate, and similar to violations identified during
typical Commission inspections of IST program implementation at
other facilities. The inspector noted that the items identified
were in the process of being corrected by the technical staff. The
inspector also noted that several comments were made in the audit
text which were not specifically identified as deficiencies in the
audit report, the most notable of which was the lack of
identification of those locations on Unit 1 pump installations where
vibration data for IST testing was to be obtained (see paragraph e).
The inspector also noted that the QA audit recognized that vibration
measurement locations for pumps in the Units 2 and 3 IST program
were identified in the Units 2 and 3 test procedures.
Within the areas inspected, no violations or deviations were identified.
13
5.
Procurement
The inspector reviewed the licensee s program for procurement. This
included a review of procedures, purchase orders, and other documentation
used in the procurement process to determine if the program was being
properly implemented.
The following SONGS' procedures governing the material procurement
process were reviewed.
Material Control Procedure
S0123-XI-1.4
Upgrading an Item's Quality Class
-
Material Control Procedure
S0123-XI-2.0
Procurement Document Control
Material Control Procedure
50123-XI-2.1
The Five-Level Procurement System
Material Control Procedure
S0123-XI-2.3
Verification Test Procedures
Material Control Procedure
S0123-XI-2.5
Substitution Part Equivalency Evaluation Report (SPEER)
Material Control Procedure
S0123-XI-2.6
Critical Characteristics Evaluation
Quality Assurance Procedure
E&C37-26-16
Procurement of Items and Services for SONGS 1, 2, & 3,
Engineering and Construction Projects
In addition, over 200 samples of completed Purchase Orders, Spare Part
Equivalency Evaluation Reports (SPEERS), evaluations for placement of
items on the safety-related commodity list and Stock Upgrade Requirements
Evaluations (SURES) were reviewed. Staff representatives of the Material
Support Division and Station Technical Division were interviewed to
ascertain qualifications and responsibilities concerning their
procurement duties.
The SONGS' material procurement program was evaluated for compliance with
10 CFR 50, Appendix B, the procedures governing the program, and sound
engineering principles applicable to procurement of spare parts for
safety-related equipment.
During this inspection, the inspector identified one significant
programmatic weakness. The inspector noted a pervasive lack of rigor to
fully document engineering evaluations conducted to approve spare and
replacement part substitutions or upgrades. An example of this lack of
rigor is contained in SPEER 87-0071. In this example, the licensee
approved the substitution of a 3" globe valve on the master valve list
with a valve of significantly different configuration. This valve has
many applications in the plant. However, the licensee's documentation of
their evaluation failed to show any consideration of a seismic load
14
analysis performed on safety-related piping runs where the new valve
could be installed. The seismic load analysis could be significant since
the new valve assembly weighs approximately 10 pounds more than the valve
being replaced.
This laxness to fully and professionally document the technical bases
considered during these evaluations could result in possible significant
information being overlooked during any subsequent reviews concerning the
installation of substituted or upgraded parts in the plant. Also, since
SONGS engineering analysis responsibilities for part procurement,
substitution, and installation are split between Procurement Engineering,
Station Technical Engineering, and E&C, the full disclosure of all
information-pertinent to the analysis must be.provided for consideration
by each of these various engineering organizations. Better documentation
of the engineering analyses performed by each engineering organization
could preclude the possible installation of an unauthorized, improper
part in the plant.
Of the areas inspected, no violations or deviations were identified.
6. Quality Assurance
The inspection of this area included the review of the program documents
and procedures governing the conduct of the quality assurance activities
at SONGS. Interviews were held with QA engineers, QC inspectors,
auditors, and supervisors concerning their experience, training,
responsibilities, and activities on site. Six completed audit surveys
were reviewed. The resulting Corrective Action Requests (CARS) and their
subsequent disposition were also reviewed. In-field QC inspections of
ongoing maintenance work were observed. The QA/QC activities of SONGS
incoming inspection of receiving materials were reviewed and observed.
The licensee's performance in this area was evaluated against the
requirements of 10 CFR 50, Appendix B and the guidance contained in
ANSI/ANS 3.2. The completed audits and inspection documents were
reviewed to ascertain if the completed work had been performed in
accordance with the applicable SONGS procedures. The inspector noted
that the completed audits were thorough, professional and in-depth. This
was considered a strength of the QA program. It was also noted that the
average time required to close a Corrective Action Request (CAR) was 66
days. This was based on a 1-year sample of 102 closed CARS. This was
considered to be a satisfactory resolution time for CARs.
No violations or deviations were identified.
7.
Reactor Operations
The inspector reviewed reactor operations related activities associated
with the current midcycle maintenance outage. The plant was in Mode 5
during the inspection period and the following types of activities and
plant configurations were reviewed and observed.
-
System alignments.
15
.Conformance with Technical Specification Limiting Conditions for
Operation for Mode 5.
- Chemical analyses of primary coolant, refueling water storage tank
contents, and diesel generator fuel oil.
Control room and shift superintendent log entries.
Plant housekeeping.
Implementation of temporary modifications.
Implementation of clearance-and tagging controls.
The inspector observed that formal approved procedures existed for the
control of the observed activities. Records contained required
documentation confirming executed activities and configuration control.
Plant staffing was consistent with Technical Specification requirements
and discussions with plant personnel revealed the staff to be
knowledgeable of plant design and operation. The plant was in midloop
operation for the greater portion of the inspection period. Control room
instrumentation was observed to provide the required vessel level
information. Adequate shutdown margin was observed to have been met. An
inspection of control room panel areas revealed housekeeping to be
adequate. No unauthorized jumpers were observed.
While touring one of the emergency diesel generator rooms, the inspector
noted a storage room that contained bottles of fuel oil samples, oily
rags, and spilled fuel oil on shelves. Operations personnel have
exclusive use of this storage room, and it appeared to be used mainly for
diesel fuel oil sample storage.
Discussions with licensee fire protection personnel indicated that the
combustible loading for the diesel generator room in question, of which
the storage room was considered a part, was much greater than that
represented by the materials in the storage room. Therefore, they were
not considered a fire hazard from an Appendix R point of view, since the
licensee has installed a.dedicated shutdown diesel, for Appendix R
purposes, in a different area of the plant. However, the inspector was
still concerned that the combustibles located in the storage room
presented an undue fire hazard to safety related equipment. During a
subsequent tour of the area with the Operations Manager, the inspector
observed that it had been cleaned up noticeably. The Operations Manager
stated he would develop a policy statement to instruct operations
personnel on the storage of combustible material in this room.
No violations or deviations were identified.
8.
Surveillance Testing
The inspector reviewed the licensee's surveillance program for compliance
with established requirements. This review covered the following areas:
16
Observations associated with the local leak rate testing of 3
penetration volumes, Nos. 27, 28 and 32.
Observations associated with the conduct of the Safety
Injection/Loss of Offsite Power test.
The review of twenty completed surveillance tests.
The inspector noted that surveillance tests required by Technical
Specifications had been identified and listed in a controlling document.
The completed tests reviewed were performed using formal approved
procedures. Required test data was documented, prerequisites were
completed, acceptance criteria were met, and test results were approved
by operations supervision. The tests reviewed by the inspector were
completed at the required frequencies.
The inspector noted, during the performance of surveillance test
501-12.8.2, "Cold SIS and Loss of Offsite Power Test," that a thorough
pretest briefing had been held with the staff involved in performing the
test. Communications and direction given during the test were effective
and clear, and the control room personnel were serious and attentive. A
formal approved procedure was written for the test and was checked as
being the most current revision.
The local leak rate testing was performed in accordance with approved
procedure SO1-V-1.12 "Containment Penetration Leak Rate Testing."
Pretest meetings were held with control room operations staff and health
physics personnel.
The inspector observed that a test pressure slightly
in excess of 50 psig was applied to the penetration volumes in accordance
with test procedures. Valving configurations were checked out in
accordance with procedures and test data was properly documented.
Pressure gauges and stop watches had current calibration dates. Test
engineers were knowledgeable of plant design and testing requirements.
In the case of penetration volume 32, a retest was required as one of the
boundary valves would not hold pressure.
One violation was identified in the area of surveillance testing, which
dealt with station vital batteries, and is discussed in detail in
paragraph 2.
9. Observation of Maintenance Activities
The licensee's maintenance program was examined to evaluate the
effectiveness of the program and to determine whether or not corrective
and preventive maintenance were being conducted in accordance with
regulatory requirements and licensee-approved procedures and
instructions. Maintenance for Unit 1 was inspected in four areas:
electrical, instrumentation and control, pumps, and mechanical.
a. Electrical
The electrical maintenance program was inspected by examining the
following procedures that describe the functioning and the
administration of the program:
-
17
Quality Assurance Program Chapter 5-C, "Maintenance Program"
Maintenance Procedure 50123-1-1.6, "Maintenance Section Policy
Guidelines"
Maintenance Procedure S0123-I-1.7, "Maintenance Order
Preparation, Use and Scheduling"
These procedures detail the administrative controls necessary to
identify, plan and schedule routine and nonroutine maintenance.
Instructions for initiating and preparing a maintenance order (MO),
the principal device for accomplishing maintenance work, is
contained in procedure S0123-I-1.7.
The inspector examined the following electrical MOs completed during
this shutdown period to verify that the program for performing
electrical maintenance was being conducted in accordance with
established procedures. These MOs were examined for content, proper
authorization signatures, QC participation, job completion sign-off,
QA review, etc.
86031447000, Perform Disposition of NCR S01-P-5899, Implement
FCN's SI-767E and SI-768E and Perform Movats Test per IEB
85-03.
86052779002, Safety Injection Pump Discharge Check Valve
Miscellaneous Maintenance.
87051345000, Replace Unqualified Butt Splices per Disposition
on NCR SO1-P-6114.
8705148000, Remove Motor Mounting Bolts to Allow for Coupling
Removal on Safety Injection Pump Motor West.
87051479000, Remove Motor Mounting Bolts to Allow for Coupling
Removal on Safety Injection Pump Motor East.
87041416001, HV851A Replace Limit Switch with E/Q Namco EA 180
Limit Switch and Replace Conduit Seal.
87041411001, HV-853A Replace Limit Switch with E/Q Namco EA 180
Limit Switch and Replace Conduit Seals.
-
87041415001, HV-852A Replace Limit Switch with E/Q Namco EA 180
Limit Switch and Replace Conduit Seals.
-
87010075001, Permanently Attach SV-1 Terminal Block to the back
of the J Box per NCR S01-P-6034.
-
87060355001, Feedwater Block Valve Actuator, Repair Motor and
Replace Lugs. Inspect Limit Switch Wiring per Applicable
Drawings.
18
87033305000, Inspect Terminal Blocks, and Check Locknuts
Bushings for Tightness in-all Hoffman J. Boxes on HV-851 A/B,
852 A/B, 853 A/B and 854 A/B.
The above MOs appeared to be in order and appeared to have been
processed in accordance with prescribed procedures.
A field inspection was made of work in progress in the plant
involving main feedwater pumps. The replacement of limit switches
with EQ Namco EA 180 switches on valves HV-853B and HV-854B under
MOs 87041414001 and 87041421001 respectively was taking place. The
work appeared to be progressing in accordance with the description
and instructions in the MOs.
The inspector examined audit SCES-007-86 dated June 23, 1986
performed by quality assurance to verify that documentation,
instructions and controls have been established and implemented in
accordance with topical quality assurance manual, chapters 5-C and
7-D for the station maintenance program. The audit team was made up
of four members and was conducted during a six week period in 1986.
The audit assessment of.root causes of significant deficiencies was
"no significant deficiencies have been identified".
The inspector examined in detail the audit plan items (eight) and
findings for each of these items which were included in the audit
report. The audit, the plan and the findings and conclusions
appeared to be in order..
The inspector concluded that the electrical maintenance appeared to
be accomplished in accordance with the program as described in the
applicable procedures and appeared to be adequate.
b.
Instrumentation Maintenance
The examination of the Instrumentation and Control (I&C) Systems
Maintenance Program at SONGS-1 included a review of the licensee's
program as described in the following licensee documents:
Topical Quality Assurance Manual, Chapter 5-C Maintenance
Program
Maintenance Procedure, 50123-1-1.3, Maintenance Documentation.
-
Maintenance Procedure, S0123-I-1.6, Maintenance Section Policy
Guidelines.
-
Maintenance Procedure, S0123-I-1.7, Maintenance Order
Preparation, Use,. and Scheduling.
After evaluating the overall maintenance program, specific test
procedures were reviewed. Some of the procedures applied to Unit 1
only (SO-), and other procedures were for all of the San Onofre
units (S0123-). The specific I&C procedures that were examined in
detail were:
19
Instrument and Test Procedure, S01-II-1.2, Surveillance
Requirement Reactor Plant Instrumentation Test.
Instrument and Test Procedure, S01-II-1.20, Nuclear
Instrumentation System Detector Replacement.
Instrument and Test Procedure, SO1-II-1.72, Intermediate Range
Compensating Voltage Adjustment.
Instrument and Test Procedure, SO1-II-1.76, Surveillance
Requirement Auxiliary Feedwater System Test.
Instrument and Test Procedure, SO123-II-8.10.1, Electronic Loop
Verification.
Instrument and Test Procedure, S0123-II-9.37, Control Valve
Calibration.
Instrument and Test Procedure, S0123-II-9.82, Pressure Switch
Calibration.
Several MOs were reviewed for conformance to the station
requirements as described in the maintenance program and procedures.
The MOs were-reviewed for the use of correct and current procedures,
adequate instructions and QC "HOLD" points, identification of
prerequisites, description of test requirements, and listings of
required test equipment. The MOs were evaluated at different stages
of the maintenance process. --
Some of the MOs were in planning,. some
were being worked in the field, and some had been completed and
signed off.
The MOs which were in the planning stage were briefly reviewed for
adherence to the program guidelines.
Several of the jobs being performed in the field were evaluated by
observing the I&C personnel performing their assigned tasks. The
work orders were examined to ensure that the technicians were
following the instructions presented in the MOs and properly
documenting the work being performed.
For MOs in which the work had been completed, the documentation was
examined for completeness, to verify that the procedures had been
followed, and that the "HOLD" points had been observed. Special
attention was given to the presence of signatures and comments
concerning the work performed.
The MOs examined in one of these three stages during this inspection
were:
86042580000,S1-72-130, B Train Hi.gh Voltage Control Power
(Agastat Relay Replacement)
-.
86091581000,S1-DEN-1GA2C15-187, DG2 Generator Differential
Relay (Modification to SA-1 Relay)
20
86110753000, S1-RCS-G-2B, 'B' Reactor Coolant Pump
(Instrumentation Removal/Reinstallation)
86111907000, S1-AFW-PT-2010, NPSH XMTR-G-10S (Calibrate
Pressure Transmitters)
86111909000, S1-CVS-PT-1120A, Containment Hi Pressure Train A
(Containment Isolation System Calibration)
87030632000, S1-AFW-PYV-3010, Current to Voltage Converter
(Auxiliary Feedwater System Calibration (Train B))
87031063000, S1-FWS-FCV-457, Main Feedwater Flow Control-SG/B
(Valve Response Data Collection)
-
87032621000, S1-NIS-N-1207, Power Range Channel 1207 (Detector
Replacement)
-
87050552000, S1-AFW-FTL-3453, Differential Pressure Low Flow
Transmitter (Auxiliary Feedwater Full Flow Test)
87051611000, S1-NIS-N-1203, Intermediate Range Channel 1203
Channel Checkout)
As a result of this inspection, implementation of the SONGS-1 I&C
Maintenance Program-was found to be consistent with procedural
requirements.
The personnel responsible for the I&C maintenance had
a good knowledge of the program and systematically tracked and
performed the required tasks.
c.
Pumps
The inspector examined work control documentation, interviewed
licensee personnel involved in pump maintenance and testing, and
examined work in progress on various safety-related and non-safety
related pumps.. The objective was to determine whether modifications
being made to these pumps,.because of problems identified by the
licensee, were reasonable and sound from a technical standpoint.
Also, the inspector observed whether the work was implemented
according to written instructions, and also evaluated quality
control involvement.
1)
Spray Chemical Addition Pumps, G 200 A&B
The inspector examined several In Service Testing (IST) records
of the spray chemical addition pumps. The pumps were rated to
deliver 0.4 gpm at 350 psi to the containment spray system,
when driven at a speed in the range of 77.5 to 155 rpm. In
order to meet the rated discharge, however, the pumps had been
run at considerably higher speeds of up to 193 rpm during
successive ISTs, dating back at least to June, 1986. As
explained in SCE Memorandum for File dated Dec. 1986, gradual
accumulation of "gases" (hydrazine vapor) in the pump cylinders
was- the cause and that running the pumps in the "unloaded"
21
state for some time would resolve the problem. This
explanation of the problem was provided by the vendor, Union
Pump Company. Since the pumps were positive displacement
pumps, it made.sense to the inspector that vapor accumulation
in the cylinders would reduce their discharge capacity, as well
as cause cyclic pressure fluctuations in the discharge piping.
The March, 1987 IST of pump G 200-A appeared to confirm this
diagnosis, during which the rated discharge was met while
running this pump at 143 rpm.
In all of the test documentation examined by this inspector the
reference- pressure has been stated as 315 psig, rather than the
rated 350 psig. The Technical Specifiations do permit
surveillance testing of these pumps at 90% of the rated
pressure. However, Article IWP-3100 of the ASME Boiler and
Pressure Vessel Code,Section XI, specifies 0.93-1.02 dP (where
dPr is the reference differential pressure) as the acceptable
range of suction/discharge pressure differential for IST of
pumps. Surveillance testing of the pumps at 315 psi discharge
pressure falls outside this range. Furthermore, the acceptable
range of flow range according to IWP-3100 is 0.94-1.02 Qr
(where Qr is the reference flow rate). The test flow rates
were slightly outside this range. These questions were raised
with licensee representatives and a verbal commitment was
obtained from the licensee to make a further engineering
evaluation of these pumps.
2)
Steam-Driven Auxiliary Feedwater Pump Modification
The steam-driven AFW turbine has had a history of repeated
tripping on overspeed, both when starting and while running.
The cause was determined to be slugs of condensed steam (low
energy water) from the supply pipe entering the turbine. The
realignment of the 3" steam supply line to give it a slope of
1/8" per 1'-0" to prevent accumulation of condensation appeared
to the inspector to be an adequate remedy.
The work-package contained adequate details of the work to be
performed, along with drawings and quality control hold points.
At the time inspection began, the steam supply line
modification had already been completed. Only the installation
of insulation back on the pipes remained. Interviews with
licensee representatives and those of the contractor (Bechtel),
and examination of the documentation indicated that adequate
quality control of the work had been implemented. No'
deviations or violations were identified.
3)
Charging Pumps, North and South
The inspector toured the charging pump area and examined
maintenance records relating to these pumps. MO No.
86032264000 required: installation of a "chicken feeder" and
associated piping to the south charging pump outboard motor
bearing. The chicken feeder was a gravity-fed oiler and 1/4"
22
supply pipe to the bearing. Under the section titled "Problem"
in the MO, no statement of the cause for malfunction of the
lubrication system was given, only instructions to install.
The licensee stated that the chicken feeder had been
inadvertently displaced by personnel working in the area. The
inspector noted that it is located in a restricted space of the
charging pump area such that it may be displaced down again.
No attempt at guarding against this possibility was apparent.
Installation of a simple wire-mesh guard would seem prudent.
4)
Other Pump Maintenance Activities
The inspector toured other pump areas and examined maintenance
procedures and documentation, including those relating to the
reactor coolant pumps B and C, the safety injection pumps E and
W, the feedwater pumps E&W, the motor-driven auxiliary
feedwater pump and the turbine plant cooling water pumps N and
S.
The inspector was satisfied with the licensee's actions in
these areas.
5)
Lubricant Storage Areas
The inspector examined lubricant storage areas in the Unit 1
Turbine Building and in a common storage area for all three
units. The latter was comprised of outdoor storage of
oil-drums and a large lockable cargo container. The inspection
was motivated by evidence of improper storage and labeling of
lubricants discovered by QA as far back as May, 1983 (CAR No.
S023-P-422, dated 5/1/83). A storage shed for proper storage
of the many types of lubricants used in the plant was planned.
This plan was postponed several times and the CAR is still
open. Meanwhile, licensee representatives stated that proper
labeling and protection measures from the weather has been
taken. The inspector toured the storage area to verify this
and found the conditions of storage, identification, and
labeling of lubricants acceptable. However the inspector noted
that the superior measure of a storage shed originally
proposed, and considered viable for almost 4 years, still
remained to be implemented, but there is no NRC requirement for
this.
6)
Fire Water Pump Diesel Tank Level Indicator
The inspector examined documentation regarding a deficient
Level gauge,.2/3 LG-5653 on the Fire Pump Diesel Tank, Units 2
and 3. The problems associated with this gauge have been cited
in at least 14 documents since July, 1984, including MO Nos.
85030006, 84000153001, 84110999, 85063049,.and 86010020 and
Non-Conformance Report No. 2-1652. While the level gauge has
been inoperable all this time, interim measures have been taken
to fabricate a sounding rod to provide a positive means of
level indication, which appears to increase the risk of
contamination of the fuel.
A Technical Specification violation
23
was avoided by keeping the tanks filled to 75%, vice the
- required 65%. DCP/PFC 6630, dated 8/22/86 has been initiated
to replace the defective level gauge with sight glasses. At
the time of the inspection, the work remained incomplete.
No violations or deviations were identified.
d.
Mechanical Maintenance
The inspector observed mechanical maintenance activities on motor
operated valve (MOV) actuators; diesel generators (DGs); heating,
ventilation, and air conditioning (HVAC); pipe supports; and other
mechanical components. The activities were assessed to determine if
,the mechanical maintenance program is being implemented in
accordance with regulatory requirements and governing procedures and
instructions.
1) Motor Operated Valve Maintenance
Maintenance on motor operated valve (MOV) S1-RCP-MOV-18 was
observed by the inspector. The documentation for S1-RCP-MOV-19
was reviewed. The completed MO numbers for MOV-18 and MOV-19
were 87051647000 and 87051689000, respectively. Both of these
maintenance activities involved replacement of the torque
switch. Although the torque switches were still functional
the switches were replaced with a similar torque switch due to
problems with part availability of the older style of switch.
The switch was tested according to procedure S0123-I.8.313,
"Actuators - Motor Operated Valve Analysis and Testing System,
MOVATS". The procedure was adhered to and the content of the
procedure was found to be acceptable. The valve was observed
to be properly lubricated, with no foreign material observed.
The maintenance personnel were found to be knowledgeable on the
MOVATS system.
2)
Diesel Maintenance on Transamerica Delaval Incorporated (TDI)
Diesels
A portion of the preventative maintenance/surveillance
inspection of the TDI Number 2 Diesel was observed. The MO
number was 86111532000 and the procedure referenced was
S01-I-2.2, "Emergency Diesel Generator Surveillance
Inspection". The portions of the maintenance activity observed
were in compliance with the MO and the procedure.
A suggestion for procedural enhancement of S01-I-2.2 was made
by the inspector to the licensee. During observation of step
6.13.4, "Hot Web Deflection Measurement", it was noted by the
inspector that the gauge was brought to the temperature of the
engine, though the procedure does not make mention of this.
The concern was if the gauge was not brought up to the
temperature of the-diesel, the thermal expansion could cause an
erroneous reading. The inspector also observed that two
deflection gauges were used. The procedure implies that only
24
one gauge will be used. The licensee agreed to take these
suggestions for procedural enhancement and clarity under
consideration.
The inspector also observed tests performed by operations
personnel to verify operability.. Portions of the following
procedures were observed:
-
S01-10-1, "Diesel Generator Operations"
-
501-12.3-10, "Diesel Generator Load Test"
The TDI diesel performed a load rejection test (from 3000Kw)
without overspeeding. At the end of the load test, the
inspector was informed that the diesel was declared functional,
but was not declared operable due to operability concerns over
the vital station battery.
3) Diesel Maintenance on Dedicated Shutdown Diesels (DSD)
The DSD is used to power a third Auxiliary Feedwater (AFW)
Pump. This diesel was installed due to Appendix R (fire
protection) concerns relating to the loss of offsite power.
The observation of the running of this diesel was in
conjunction with an Integrated Surveillance Test on the AF
pump.
The inspector observed.that the startup of the diesel was in
accordance with procedure S01-10.7. The diesel was started and
tripped on low lube oil pressure. The inspector talked with
the craft people present and was informed that this trip was a
fairly common occurrence. The diesel was reset and started on
the second attempt. The inspector had concerns regarding the
operability of the diesel and talked with cognizant maintenance
personnel.. The inspector was informed that the sensing gauge
for the lube oil is at the end of the piping system, and it
takes time for the lube oil pump pressure to be seen by the
sensor. The inspector was also informed that a Startup Problem
Report (SPR) 6577 was written (4/1/87) describing this problem
and Station Technical had recommended some fixes to the problem
and an MO was currently being generated to repair it. The
inspector was also informed that, during emergency starts of
the diesel, this trip is bypassed. The actions taken by the
licensee were appropriate, and the inspector had no further
concerns regarding the operability of the DSD.
The DSD battery was also inspected. The battery was observed
to have 1/2 of a spacer plate missing between cells 58 and 59,
and some of the levels were slightly above the high level mark.
The inspector was informed that the spacer plate would be
replaced, and that procedure (SO1-I-4.14, "Battery Cleaning and
Watering") allows the level to be up to 1/4 inch above the high
level mark. The inspector was satisfied with the licensee's
0
response in
this. regard.
25
4)
HVAC Observations
The inspector walked down the Control Room Heating, Ventilating
and Air Conditioning (HVAC) system at SONGS 1. The purpose of
the control room HVAC is to limit the radiation and toxic gas
exposure to the control room operators during a design basis
accident.
The inspector had two concerns when inspecting the HVAC. One
concern was the covering of the HVAC ductwork by a taped
covering. This covering was to ensure system integrity. The
inspector was informed that this was a temporary measure and
was not a permanent fix to ensure system integrity. Another
concern involved-some HALON bottles secured near the HVAC
system air intake. The concern was that the HALON
concentration could be at unsafe levels if the tanks ruptured.
In discussions with the licensee, the inspector was informed
that the amount of HALON stored near the air inlet was not
sufficient to cause a health hazard. The inspector was
satisfied with this explanation.
5) Pipe Supports and Snubbers
The inspector performed a visual inspection of approximately
-two dozen pipe supports and snubbers on main feedwater, safety
injection, and diesel generator piping. The supports and
snubbers selected appeared to be installed in such a manner
that they could perform their intended function.
6) Other Mechanical Components
The inspector observed work that was being performed on several
mechanical components. The following MOs were observed in
progress:
87041416001, to install Grafoil sealant and place torquing
requirments on Conax connections to NAMCO EA120 limit
switches.
8705140000, to replace a leaking gas valve and 0-ring on
the accumulator for Safety Injection System (SIS) valve
S1-SIS-HV-851A
86110764001, to align "B" reactor coolant pump motor,
install the flywheel cover, and perform a test run with
the motor uncoupled.
The inspector considers that all work activities detailed on
these MOs were being performed in a satisfactory manner by
knowledgeable personnel. In addition, the inspector noted that
there was extensive involvement by QC inspection personnel
during performance of these MOs.
27
-
Configuration Control Procedure(s)
S0123-XIV-4.2, "Site Design Change Administration"
Modifications and design changes once approved by the plant
modification review committee are processed by engineering and
construction as a design change package (DCP). The design criteria
is developed through a series of design review meetings which
finally result in a design change package classified as Revision
"A".
This mile post is the first version of a design but is not yet
approved. In this form (Revision "A"), the DCP is routed to the
various groups such as station, operations, maintenance, quality
assurance, startup, etc. for their review and recommended
changes/input. Following this review, the DCP is revised to
incorporate those changes and issued as Revision "0".
Revision "0",
once approved, is the first working revision from which Construction
Work Orders (CWOs) are written to actually perform the work to
accomplish the modification/design change in the plant.
Following installation of the design change or modification,
component/system testing and preoperational testing takes place.
After preoperational testing is completed, the turnover package,
which includes all of the documentation from Revision "0" of the DCP
through the preopational test results and as built drawings, is
turned over to Quality Assurance (QA).
QA reviews the package to
determine that it is complete and that all QA requirements have been
satisfied. The turnover package is further reviewed by Station
Technical in parallel with station configuration control for
completeness. Following this review the as-built drawings are
released to operations for use in the control room and the package
is forwarded to Corporate Document Management (CDM) where it becomes
a permanent record of the plant.
b.
Review of Design Change Procedures and Construction Work
Orders
The inspector verified that the program for processing design,
design changes and modifications is functioning .in accordance with
prescribed procedures, and examined in detail the following Design
Change Packages (DCPs) which.were in various stages of completion.
Some of the DCPs were in configuration control indicating the
installation was completed and the turnover packages were in the
last review stage. For other DCPs, the installation was still in
process in the field or installation in the field had not yet been
started. The following DCPs were examined for authorization
signatures; safety, engineering, environmental, and ALARA
evaluations; drawing change authorization; QA review; as-built
drawings; completion signatures; etc.:
-
DCP-1-86-3072 Revision 0, Replace Magnecraft Relays In VR
Transfer Scheme With Electro Switch Lockout Relay
-
DCP 1-85-3303.0 Revision 1, Valve Operation Modifications
28
-
DCP 1-87-3391, Provide Duct Heaters for the Control Room
Emergency HVAC System
-
DCP 1-85-3009-1, Install Switchgear Enclosure Foundation Floor
Slab
DCP 1-85-3009.5, Dedicated Shutdown System/Appendix R
Modifications
-~
DCP 1-85-3009.9, Modification and Relocation of Dedicated
Shutdown Panel C-38
-
DCP 1-85-3009.14, Dedicated Safe Shutdown Water and Fuel Makeup
In addition, the following Construction Work Orders (CWOs) for the
field installation of the Design Changes and Modifications, for the
above DCPs, were examined in detail by the inspector for proper
authorizing signatures, QC participation, job completion sign-off,
final QA review, etc.:
-
CWO 87030454000, install roto hammer remote extensions for
valves VCC-324 and VCC-405 in accordance with FIDCN M-4743 and
M-4769.
CWO 87030382000, add two coredrills to concrete roof on reactor
auxiliary building in accordance with FIDCN C-2151.
CWO 87030892000, relocate valve VCC-324, add valve VCC-405 and
delete valve FV-3079 in accordance with FIDCN M-4743.
CWO 87030373000, install cables 1GHED9RP1, C1, I and terminate
them at GEO9RY.
CWO 8703040900, grout any misdrilled holes resulting from
installation of conduit 73471G and relay box GEO9RY.
CW087022396000, install relay cabinet GEO9RY and conduit 73471G
for LV exciter cabinet for DG2.
CW08704298000, replace relay GEO9RY per NCR-S01-P-6104.
CWO8704302300, perform inspection and take baseline data on
replacement LOR/ER relay in accordance with test procedure
S0123-II-11.152.
-
CW087041288000, perform inspections and take baseline data on
new LOR/ER relay as required per instrument and test procedure
50123-I-11. 152.
-
CW087020803000, test LOR/ER relays in E09 Auxiliary Panel
GEO9RY, perform circuit tie-ins INEO9, low voltage excitation
panel, retest circuits in accordance with SO123-II-11.152.
29
The above documentation (DCPs and CWOs) appeared to be in order and
processed in accordance with applicable procedures.
Two DCPs were selected to inspect in the field to verify the
installation of the design changes and modifications. A walkdown
was made in the charging pump area to inspect completed
modifications made to two remote valve operators under DCP
1-85-3303.0, valve operator modifications. The .in
process work of
installation of a switch on a panel in the control room was
inspected. This-installation was being accomplished under DCP
3465.0, Vital Bus No. 4 Transfer. These installations appeared to
have been made or were being made in accordance with prescribed
design and CWOs.
c.
Audit Reports
Further verification of the licensee's program for design, design
changes and modification included examining the following three
audits conducted in this area by the licensee:
1) SCE-2-86/FCR-1-86, conducted February 1986
The purpose of this special audit was to assess the
effectiveness of the application of the quality assurance
program to the design and procurement processes for the Diesel
Generator in the Dedicated Safe Shutdown System for San Onofre
Unit 1.
2)
SCES-027-86, conducted June/July 1986.
The purpose of this audit was to verify Project/Startup
Engineering implementation of the applicable requirements
specified in Chapter 2-A, "Design Development, Review and
Approval" of the Topical Quality Assurance Manual (TQAM), E&C
24-10-16, "Development, Review, Approval and Release of SCE
Design Change Packages (DCPs) SONGS 1, 2 & 3 and Administrative
Procedure (AP) No. 10, "Design Change Process".
3)
SCE-22-86, conducted August 1986.
This audit covered selected review of SCE design change
packages and field generated interim design change notices.
The audits appeared to be comprehensive in the areas examined and
demonstrates the effectiveness of QA's involvement in the licensee's
program for design changes and modifications.
The inspector in his examination of the licensee program for design,
design changes and modifications reviewed the licensee's annual report
dated June 11, 1986 of facility changes including a summary of the safety
evaluation for each change/modification. The report included only two
facility changes for 1986; 1-85-3066.0 and 1-85-3055.1. Both changes
involved replacement of environmentally unqualified containment
electrical penetrations and safety related cables. The report and safety
.
3 0
evaluation summaries appeared to be adequate and to satisfy the
requirements of 10 CFR 50.59(b)(2).
It appears from examination of the above documentation and the field
inspections that the procedures prepared to describe the functioning and
manage the licensee program for design, design changes and modifications
have adequate controls to ensure a proper operating program.
No violations or deviations were identified.
11. Radiological Controls
The inspector reviewed the following areas: audits, changes in
organization and programs, training and qualification of personnel,
external and internal exposure, maintaining occupational exposures ALARA,
and control of radioactive material.
This included reviews of licensee
records and reports, discussions with licensee and contract personnel,
and several tours of the the licensee's facility.
The inspector reviewed Quality Assurance Audit SCES-020-86 and various
Field Surveillance Reports as applicable to the Unit 1 mid-cycle outage.
The deficiencies identified appeared to have been adequately addressed
and corrected. The inspector observed that the audit team included
individuals qualified as lead auditors in the area of radiological
controls as defined in ANSI/ASME N45.2.23-1978, "Qualification of Quality
Assurance Program Audit Personnel for Nuclear Power Plants."
The inspector interviewed the Unit 1 Health Physics (HP) supervisor, the
Unit 1 Radioactive Material Control (RMC) General Foreman, the RMC
Manager, and various HP and RMC leads and technicians in regard to the
preparations made for the.Unit 1 outage and significant changes
implemented since the last inspection. The inspector was informed that
the Unit 1 HP Supervisor had been recently appointed to that position.
The inspector was also informed that a significant effort had been made
at the start of the outage by the RMC organization to decontaminate the
42 and 31 foot levels of the Unit 1 containment building. This resulted
in entry to these levels, as well as a few areas of the 22 foot level, in
street clothes. Several supervisors interviewed by the inspector
commented that the decomtamination resulted in easier access to the work
area and, they felt, more frequent supervisory tours.
The inspector-was informed by the HP Supervisor and the RMC Manager that
30 and 47 temporary technicians had been added to their respective staffs
to support the outage. The inspector examined the resumes of select
temporary contract HP journeyman technicians and all appeared to meet the
requirements of ANSI/ANS-3.1-1981, "American National Standard for
Selection, Qualification and Training of Personnel for Nuclear Power
Plants."
The inspector reviewed several contract HP technician
Qualification Manuals and all appeared to be appropriately complete. The
inspector discussed with the RMC Manager and General Foreman the training
of RMC technicians with regard to the Unit 1 decontamination effort and
outage. The inspector was informed that temporary Unit 1 RMC
decontamination personnel had received on-the-job training at Units 2/3
two weeks previous to the start of the outage to familiarize personnel
31
with the decontamination techniques to be used and that they also had
received "weight" training to familiarize them with the proper methods
for lifting and carrying heavy items.
The inspector made several tours of the Unit 1 containment building and
observed numerous jobs in progress, particularily:
Reactor Coolant Pump Repair andReassembly
Excore Detector Changeout
Reactor Cavity Inspection
Equipment Decontamination
Upender Cavity Sludge Removal Preparations
The inspector observed that the workers were wearing appropriate
dosimetry, anti-contamination clothing, and respiratory protection (as
required by their respective REPs) and appeared to be expeditiously
carrying out their tasks. The inspector reviewed current exposure data
for personnel involved in the outage and noted that there were none in
excess of the 900 millirem whole-body SCE administrative limit but that
five workers had received exposure extensions. The inspector reviewed
the five respective Radiation Exposure Limit Extensions and noted that
they appeared to be complete, properly reviewed and signed, and each
included a correctly completed SCE Occupational External Radiation
Exposure History which had information equivalent to that contained on
Form NRC-4. During the tours the inspector also noted that plant areas
appeared to be appropriately posted and that containment housekeeping
appeared to be in good order. The inspector was informed that there were
no known exposures of personnel to airbourne radioactivity in excess of
the 30 MPC-hr administrative limit nor had there been any positive
whole-body counts attributable to the intake of radioactive material at
the site during the outage.
The inspector was informed that Irradiated Fuel Fragment controls had
been instituted for select jobs but that none had been found in systems
with the exception of one highly radioactive Co-60 particle which had
been removed from the Radioactive Waste Storage Tank. The particle was
noticed when a survey of the outside of the tank, after a flush of a hot
spot on a Reactor Coolant loop drain line, revealed a 1000 R/hr hot spot
on the bottom of the tank. The particle was removed by a special
procedure and was in storage at the time of the inspection. The particle
was observed to be about the size of a grain of sand. Four other
discreet particles had been found during the outage at Unit 1 but were
not associated with.plant systems. The inspector was informed that there
had been 45 personnel contamination events to date during the outage and
that 18 of these had occurred during the containment decontamination
.process.
The inspector reviewed notations of calibration and performance checks on
portable survey instruments and noted some minor discrepancies with the
notation of performance check dates which were pointed out to the
cognizant HP personnel and expeditiously corrected. The inspector
observed personnel frisking with both hand-held friskers and the
beta-booths. Personnel appeared to be frisking properly and personnel
contamination alarms seemed to be properly responded to and documented.
32
The inspector toured radioactive material storage and processing areas at
Units 1 and 2/3. The compressible waste generated at Unit 1 was being
transferred to Units 2/3 for compaction.
During a tour of the radioactive material storage area on the east side
of Units 2/3 the inspector noted eight gray boxes, approximately
3'x3'x5', in the area outside door R3-60. The boxes bore the required
"Caution-Radioactive Material" label but no information was provided on
the label as to what radiation levels were present or what material was
contained in the boxes. The area was posted as a Radiation Area but the
boxes were stored in a housekeeping area separate from the normal RMC
storage. Readings taken by the inspector on June 3, 1987, with an
Eberline model .RO-2 ionization chamber, serial number 897, calibrated on
March 24, 1987, and due for calibration on June 24, 1987, indicated a
maximum contact dose rate of 48 mrem/hr and a general area dose rate
around the boxes of 5-10 mrem/hr. These dose rates were markedly higher
than others in the general area.
The inspector brought this to the attention of the Units 2/3 HP
supervisor and inquired if the noted labelling was sufficient to meet the
requirements of Health Physics Procedure S0123-VII-7.4, "Posting and
Access Control," and 10 CFR 20.203, "Caution signs, labels, signals and
controls."
The supervisor stated that he felt that the current
labelling was not sufficient to meet the requirements. The supervisor
later informed the inspector that the boxes had been surveyed and
appropriately labelled with the box contents and radiation levels. The
supervisor stated that previously made documented surveys of the loaded
boxes were not available. The inspector was informed by the HP Manager
that the boxes contained Reactor Coolant Pump Seals in storage casks.
The Manager stated that the labelling of these boxes with only the
radiation symbol and the words "Caution-Radioactive Material" was not
sufficient to meet the requirements of HP Procedure S0123-VII-7.4, that
the vast number of packages containing radioactive material at the site
were properly labelled and that these must have been missed as the
packaging and movement had been completed at the time of shift turnover
on June 1, 1987.
Technical Specifications, Section 6.11, Radiation Protection Program,
reads:
Procedures for personnel radiation protection shall be prepared
consistent with the requirements of 10 CFR Part 20 and shall be
approved, maintained and adhered to for all operations involving
personnel radiation exposure.
Health Physics Procedure 50123-VII-7.4, paragraph 6.1.2.6, "Radioactive
Materials Container," requires that:
Each container having radioactive material in excess of the amounts
specified in Appendix C of 10 CFR 20 shall bear a durable, clearly
visible label bearing the radiation caution symbol and the words:
0II
33
"CAUTION, RADIOACTIVE MATERIAL"
"DANGER, RADIOACTIVE MATERIAL"
It shall also provide sufficient information to permit individuals
handling or using the containers or working in the vicinity thereof
to take precautions to avoid or minimize exposures.
A similar violation involving the labelling of two 55 gallon drums was
noted in November, 1986, and documented in inspection report number
50-206/86-42. Failure to adequately label the eight Reactor Coolant Pump
Seal boxes is a violation of the requirements of Technical Specifications
(87-05-07).
The inspector interviewed the cognizant ALARA engineers and reviewed the
ALARA program planning and execution for the Unit 1 outage. An outage
goal of 80 person-rem had been set of which 67 person-rem had been
expended by the 27th day of the 45 day outage. The inspector reviewed
select Radiation Exposure Permits, Maintenance Orders, ALARA Job Reviews,
Temporary Shielding Authorizations, Surveys, and the special procedure
for the hot particle removal from the Reactor Coolant Drain Tank. The
inspector noted that there had been a significant increase in the number
of Maintenance Orders issued for the outage over the number planned, an
increase from approximately 400 to approximately 650, and that there had
been an increase in the scope.of work on let-down valves in the vicinity
of the non-regenerative heat exchanger. It appeared that the outage
exposure goal might be exceeded but the level of effort and involvement
of the ALARA group appeared significant. Indeed, the setting of a
seemingly agressive exposure goal and the daily participation of the
ALARA group in work planning and execution appeared to be effectively
maintaining occupational exposures as low as reasonably achieveable.
Within the area inspected, one violation was identified.
12. Followup of Inspector Identified Items
a.
(Closed) 50-206/86-43-01 -
Safety Injection/Feedwater Pump Bearing
Oil Supply
This item dealt with several concerns regarding safety injection/
feedwater (SI/FW) pump bearing oil supply.
1) One aspect concerned the ability of the installed flow meter to
indicate flow at the reduced levels resulting from
reinstallation of flow orifices. The licensee replaced the
flow meter with one more suited to measure the existing flow
levels per Maintenance Order (MO) 8611340000.
2) The inspector requested the licensee confirm the proper
operation of the pump bearing temperature monitor and alarm.
This was completed by the licensee per MOs 93111610002 and
86111207000.
34
3)
The inspector requested the licensee confirm proper oil flow to
the motor bearings. This was completed by the licensee as
specified in MOs 86111166000 and 86111051001.
4) The inboard motor bearing lube oil sight glass appeared cloudy.
The inboard sight glass was replaced with the outboard sight
glass and a new sightglass was installed in the outboard
position. This was accomplished per MO 86100605000.
The inspector found the licensee's actions concerning this item to be
acceptable and it is closed.
b.
(Closed) 50-361/86-25-03 Procedures and Training on AFW
Tappet Relatch
This item involved a finding by the previous Region V team
inspection with regard to the method for resetting the auxiliary
feedwater (AFW) pump turbine overspeed trip.
Procedure S023-2-4 has been revised in accordance with TCN 9-4 to
include resetting of the P-140 turbine overspeed trip by ensuring
actuator HV-4716 is fully closed and pulling the trip lever
connecting rod towards HV-4716.
The inspector briefly interviewed a representative sample of Nuclear
Plant Equipment Operators (NPEOs) to ensure that they had knowledge
of this reset procedure. Also, the inspector observed signs,
located in the area of the AFW pumps, with detailed diagrams as to
how to reset the P-140 turbine overspeed trip.
The licensee appeared to.have addressed this item adequately and it
is closed.
c.
(Closed) 50-206/82-26-01 -
ORMS Low Flow Alarms Unexplained on
Channels 1211 and 1212
This item concerned the background count rate on Operational
Radiation Monitoring System (ORMS) channel 1211 which had a
background count rate of 35,000 CPM. This was 15,000 CPM above the
alarm setpoint specified in procedure 501-1.3-1. Also, channels
1211 and 1212 were selected to monitor the stack instead of
containment. The licensee made this selection because a low flow
alarm was received whenever the channels were selected to monitor
the containment.
Procedure S01-2.2.1 was revised to specify that the alarm setpoints
for these channels are determined by the Chemistry Department and
are periodically reviewed and revised as necessary by Chemistry.
Also, spurious low flow alarms from channels 1211 and 1212 have been
eliminated. The inspector personally inspected these channels in
the control room which were selected to monitor containment and no
low flow alarm was present. Further, in order to ensure that
Technical Specification requirements are met, these channels are
'~
'
'
35
normally selected to monitor containment. The shift superintendent
stated that he has not observed any spurious low flow alarms from
these channels. Therefore, this problem is considered resolved and
this item is closed.
d.
(Open) 50-206/86-11-01:
Safety Analysis and ASME Section XI
Operability Limits for Inservice Testing of Pumps
During this inspection, the licensee provided copies of memoranda
between P. A. Croy and J. L. Rainsberry regarding:
(1)
determination of FSAR design requirements for those pumps tested in
the inservice testing program, and (2) the acceptance criteria
delineated in the inservice testing program. The two sets of pump
requirements were summarized in a memo from P. A. Croy and B. L.
Woods dated December 17, 1986.
However, the methodology used to
assess the appropriateness of the IST pump acceptance criteria was
not clear. The individual who prepared the comparison document was
unavailable for interview during the entire course of this
inspection. Therefore, the validity of the comparison was not
verified by the inspector. This item remains open pending review
and discussion between the cognizant licensee individual and an
inspector.
e.
(Open) 50-361/85-22-03:
Safety Analysis and ASME Section XI
Operability Limits .for Inservice Testing of Pumps
This item is identical to the item discussed immediately preceding
except that it applies to Unit 2. This item remains open pending
review and discussions between the cognizant licensee individual and
an inspector.
f.
(Closed) 50-206/86-34-01:
Evaluate Need for Additional Licensee
Actions on Testing Foxboro Controller Wire Harnesses
While evaluating the I&C maintenance program, the status of this
open item concerning the degradation of Foxboro wiring harnesses was
reviewed. Forty (40) MOs were generated to replace the Foxboro coil
cords. Of these forty MOs, eight (8) were reviewed in detail. The
detailed reviews included field observations of the preparatory
bench work and the in-plant installations of the hardware. It was
found that not all of the MOs had been completed and released to
document-control, but most of the actual work of installing the
replacement cables had been completed.
The eight MOs for performing inspection, testing, or installation of
the Foxboro equipment which were examined are as follows:
86090856000
86090857000
86090858000
86120839000
86120846000
86120853000
36
86120865000
86120869000
Based on the evaluation of the Foxboro related MOs and the work
completed at the time of the inspection, actions are being taken by
the licensee to replace the Foxboro coil cords. Therefore, this
item is closed.
13.
Exit Meeting
On June 12, 1987, an exit meeting was held with the licensee
representatives identified in paragraph 1. The inspectors summarized the
inspection scope and findings as described in this report.