ML16127A208
| ML16127A208 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 07/25/1988 |
| From: | Belisle G, Shannon M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16127A206 | List: |
| References | |
| 50-269-88-13, 50-270-88-13, 50-287-88-13, NUDOCS 8808150264 | |
| Download: ML16127A208 (24) | |
See also: IR 05000269/1988013
Text
10
gREGjZq
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report Nos.:
50-269/88-13, 50-270/88-13, and 50-287/88-13
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC
28242
Docket Nos.: 50-269, 50-270,
License Nos.: DPR-38, DPR-47, and
and 50-287
Facility Name:
Oconee 1, 2, and 3
Inspection Conducted:
May 9-13 and 19-27, 1988
Inspectors:
&____________
___
7
'
M. Shannon, Team Lfidir
Date Signed
Team Members
T. Cooper
K. Jury
E. Lea
L. Mellen
Approved by:
G. A. Belisl6, Chief
ate
igned
Quality Assurance Programs Section
Operations Branch
Division of Reactor Safety
SUMMARY
Scope:
This routine, announced inspection of quality assurance effectiveness
was conducted in the areas of operations and surveillance testing, maintenance,
and design control.
Results:
Although a number of violations were identified, the licensee's
various work practice and procedural controls in the areas inspected were
generally acceptable.
Licensee personnel were knowledgeable of their work
activities.
Within the areas inspected, the following violations were identified.
-
Failure to provide accurate IST and firewatch records, paragraphs 3.b
and 3.c.
-
Failure to measure the full stroke time of ASME Section XI valves,
paragraph 3.d.
8806150264 880803
ADOCK 05000269
G
PNU
2
-
Failure to identify valves required to be tested pursuant to ASME
Section XI requirements, paragraph 3.g.(3).
-
Failure to follow procedural requirements of Station Directives relating
to maintenance work requests and cleanliness controls, paragraphs 4.d and
4.e.
-
Failure to document the bases for 10 CFR 50.59 determinations, paragraph
5.b.
-
One unresolved item was identified involving configuration control
inadequacies in the ES and RPS cabinets, paragraphs 4.b and 4.e.
-
A weakness (IFI) relative to acceptance criteria for valves moving freely,
paragraph 3.g.(1).
-
A weakness (IFI) relative to corrective actions for valve 1LP-21 multiple
failures, paragraph 3.e.
Within the areas inspected,.the following observations were noted:
-
The number of value stroke time failures was very small.
-
Maintenance history records did not indicate repetitive failures.
-
Based on the low component failure rate and few repetitive failures the
licensee's corrective and preventive maintenance programs appeared to be
better than average.
-
The licensee's maintenance engineering program,
with emphasis towards
component engineers,
appeared to be a effective method of resolving
component failures.
-
The requirements of ASME 45.2.11 Design Control appeared to be adequately
implemented for most engineering activities.
REPORT DETAILS
1. Persons Contacted
Licensee Employees
J. Bowers, Production Specialist I
- R. Brackett, Station QA Manager
- M. Clardy, Maintenance/P&S Engineer
B. Davis, Nuclear Production Engineer
D. Denard, Performance Supervisor
T. Dwyer, Nuclear Production Engineer
P. Forrester, Nuclear Production Engineer.
B. Foster, Superintendent of Maintenance
E. Frampton, Design Engineer
- A. German, Design Engineering/Site Office
R. Harris, Design Engineer
D. King, Design Engineer
R. Knoerr, Project Services Engineer
R. Ledford, QA Surveillance Supervisor
- T. Mathews, Production Specialist II (Licensing)
W. McAlister, Support Engineer
B. Millsaps, Maintenance Services Engineer
- F. Owens, Regulatory Compliance
K. Rhode, Nuclear Production Engineer
N. Riddle, Project Support Engineer
- D. Sweigart, Operations Superintendent
D. Taylor, Project Support Engineer
R. Todd, Project.Support Engineer
- M. Tuckman, Station Manager
Other licensee employees contacted included engineers, operators,
technicians, maintenance personnel, and office personnel.
NRC Resident Inspectors
- P. Skinner, Senior Resident Inspector
L. Wert, Resident Inspector
- Attended exit interview
Acronyms and initi.alisms used throughout this report are listed in the
last paragraph.
2. Quality Assurance Effectiveness (TI.2515/78)
The objective of this inspection was
to
assess quality assurance
effectiveness.
For this report, quality assurance effectiveness is
defined as the ability of the licensee to identify, correct, and prevent
2
recurrence of similar problems.
The term quality assurance effectiveness
used in this application was not limited to the licensee's QA Department;
it was the total of all efforts needed to achieve quality results.
This was a performance-based rather than a compliance-based inspection.
In.stead of verifying compliance with programmatic
requirements,
the
principal effort was to determine whether results were actually achieved
that the quality assurance program was designed to accomplish.
However,
when problems were identified, appropriate regulatory requirements were
enforced.
The inspection effort was divided into the following areas, each of which
is addressed in separate report details.
Operations and Surveillance Testing
Design Control.
Maintenance
3. Operations And Surveillance Testing
The licensee's quality assurance effectiveness in the area of operations
and surveillance testing was assessed by observing plant operating
personnel, observing surveillance testing, reviewing surveillance results,
reviewing normal and emergency procedures,. reviewing component equipment
histories, and conducting personnel interviews.
a.
Surveillance Testing
The
inspectors
witnessed
Performance
Test
PT/2/A/0150/22A,
Operational Valve Functional Test.
This consisted of stroke time
testing IST categorized valves for Unit 2, while at power. The test
was conducted satisfactorily; however, valve 2-LP-16 failed to stroke
open as required and valve 2-LWD-1 had a stroke time increase. These
and other discrepancies noted during the course of the inspection
will be discussed later in this report.
After witnessing valve stroke time testing, reviewing valve stroke
time histories, and reviewing maintenance histories, the inspectors
concluded that the licensee's program for ASME Section XI valve
testing was above average. There were no indications of repetitive
failures or of common component failures. The preventive maintenance
program and MOVATS testing program appear to have created high
operational reliability for plant power operated valves.
b. Documentation Falsification
While witnessing PT/2/A/0150/22A on May 11,
1988,
the inspectors
noted that on the Reactor Building Normal
Sump Isolation valve,
2LWD-1, stroked closed in eight seconds; its previous stroke time was
five seconds. Acceptance criteria 11.3.3 of the performance test
states that in order to meet the acceptance criteria, valves with
3
previous stroke times equal to or greater than five seconds and less
than or equal to ten seconds must not increase 50 percent from the
previous test. The inspectors then witnessed the recording of the
stroke time into the test data as eight seconds and verified this
time via the control room printer. The performance technician was
unaware that the as-found stroke time did not meet acceptance
criteria 11.3.3, and initialed procedure step 12.16.5 which verified
acceptance. The inspectors were aware that the stroke time did not
meet the applicable acceptance criteria; however,
the inspectors
wanted to ensure this test discrepancy would be identified during the
procedure review and approval cycle. On May 25, 1988, the inspectors
reviewed the completed test procedure for verification that the
stroke time discrepancy had, in fact, been identified by the licensee
during the review cycle. The inspectors identified that the stroke
time of eight seconds (previously entered in the completed procedure)
had been changed to five seconds,
which now met the acceptance
criteria. Upon verification of the original recorded stroke time,
the inspectors asked for documentation of any retest that may have
been performed. Unaware of any retest performance, the licensee then
verified the computer recorded stroke time of eight seconds and
retested the valve on May 25, 1988; the retested stroke time was also
eight seconds. Upon examination by the inspectors, it appeared that
initials on the procedure page in question were not consistent with
the same initials on other test pages. The licensee stated that they
would investigate and determine the cause of the discrepancies and
take appropriate corrective actions.
The licensee contacted the responsible performance technician, who
admitted to replacing the completed page in question and to changing
the measured stroke time from eight seconds to five seconds.
The
licensee also identified that the previous (prior to May 11)
stroke
time for valve 2LWD-1
had been recorded as five seconds and the
computer had shown the actual stroke time to be eight seconds. This
surveillance test was also-performed by the same individual.
The actions of the performance technician in changing the TS
surveillance data violate NRC requirements. 10 CFR 50.9(a),
Completeness and Accuracy of Information,
states that information
required by
the Commission's regulations, orders, or license
conditions to be maintained by the licensee shall be complete and
accurate in all material respects.
Failure to meet the 10 CFR 50.9(a). requirements is collectively
combined with an additional example as discussed in paragraph 3.c and
is identified as Violation 269, 270, 287/88-13-01.
c. Falsification Of Records Associated With Fire Barrier Penetration
Patrols
On May 18,
1988,
the DE group identified that some fire barriers
between the control room,
cable room,
equipment room,
and turbine
4
buildings were inoperable. The fire barriers consisted of 10 inches
of a foaming agent with metal plates on
each side which was
determined by test results to be
inadequate.
The test results
identified that a 12 inch thickness of foam was required. As a result
of the notification by DE, the penetrations were declared inoperable
and the actions of TS 3.17.6.1 were entered.
The TS LCO requires a
fire watch patrol to inspect the affected areas hourly.
On May 19,
the resident inspector reviewed the security print-out of the cable
room card-key doors and identified several periods that exceeded the
specified time
interval required by
TS.
Since the NEOs were
responsible for this surveillance, the inspector also reviewed the
logs maintained by the assigned personnel.
The logs for all three
units indicated the required hourly watches were performed,
even
though the computer listing indicated the individuals had not entered
the prescribed areas
in the required time.
This conflicting
information was provided to Operations management.
Subsequent
licensee investigations identified 5 times in a continuous 28 hour3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br />
period that the fire patrols were not performed in the prescribed TS
time requirements, where as the logs indicated that the patrols were
performed. The licensee concluded that three personnel were involved
in this occurrence. The failure to perform these required activities
resulted in violating TS 3.17.6.1.
This
falsification of
documentation is collectively combined with an additional example as
discussed in paragraph 3.b and is identified as Violation 269, 270,
287/88-13-01.
d. Valve Stroke Time Testing
While witnessing valve stroke time testing, the inspectors noted that
valves were being tested utilizing the time between actuations of the
limit switches, i.e. the "light to light" method. It was also noted
that for certain valves the time delay between valve actuation and
first limit switch actuation was as much as eight seconds.
The
"light to light" method does not measure the full stroke time of the
valve.
The 1980 ASME Boiler and Pressure Vessel Code,Section XI, Rules for
Inservice Inspection of Nuclear Power Plant Components,
Article
IWV 3412,
Exercising Procedure,
requires that valves tested under
this section shall be full-stroke exercised. Article IWV-3413, Power
Operated Valves, defines full-stroke time as that time interval from
initiation of the actuating signal to the end of the actuating cycle;
however, the licensee measures the time between actuations of the
limit switches.
The licensee's failure to meet the
1980 ASME
Section XI valve stroke testing requirements -is identified as
Violation 269, 270, 287/88-13-02.
e.
Valve 1LP-21 Discrepancies
During the equipment maintenance history review, the inspectors noted
that multiple maintenance work request had been completed for valve
5
1LP-21 because it was unable to meet its acceptance criteria. 1LP-21
is the "A" train LPI
system suction valve from the
BWST.
The
following is a failure and repair history for 1LP-21 for the last two
years:
On April 4, 1986, 1LP-21 failed to meet its acceptance criteria
of a maximum stroke time of 15 seconds, in that, it stroked in
16 seconds. The licensee apparently did not recognize that the
valve did not meet its acceptance criteria, consequently, a
discrepancy was not written.
Unit 1 started up on May 6, 1986,
and again on May 27,
1986,
without knowledge of the valve not meeting its acceptance
criteria.
On June 3, 1986,
1LP-21 again failed to meet its
acceptance criteria when it
was found-to stroke in 16 seconds.
At this time the licensee recognized that the previous test did
not meet its acceptance criteria and took corrective actions by
counseling the personnel
involved.
Corrective action was to
reset the limit switch and the valve actuated in 15 seconds.
On
November 17,
1986,
1LP-21 failed to meet its acceptance
criteria and stroked in 16 seconds. The valve stem threads were
lubricated and the valve stroked in 15 seconds.
On May 20,
1987,
1LP-21 failed to meet is acceptance criteria
and Work Request 91757C was written and stated that the valve
had a bent stem, a packing leak, and failed to meet the stroke
time acceptance. A deficiency written on PT/1/A/0150/22A stated
that the 'stroke time was inconsequential and that 1LP-21 would
be repaired during the next Unit 1 outage.
The unit was shut
down
on
September 2, 1987,
and repairs were
completed on
October 8, 1987. These repairs reset the limit switch.
On October 31,
1987,
1LP-21 failed to meet its acceptance
criteria and the threads were lubricated without issuing a work
request.
Work Request 50209F was written to perform MOVATS
testing and called for replacing the torque switch; however, the
torque switch was not replaced.
These identified discrepancies with the 1LP-21 stroke times did not
present an operability concern but they do raise a concern with the
licensee's adherence to acceptance criteria.
The licensee's IST
program acceptance criteria lists the acceptable stroke time as 15
seconds; however,
on May 20,
1987, a work request stated that the
valve failed to meet its stroke time acceptance and repairs were not
performed
on the valve for over three months.
The licensee's
statement that the stroke time was inconsequential,
presented an
attitude that the acceptance criteria is only a guideline and not a
requirement. It was also noted that the limit switch was reset on
two occasions as corrective action for obtaining proper valve stroke
time.
6
The resetting of limit switches as corrective action for stroke
failures, for 1LP-21 is considered to be a weakness and is identified
as Inspector Followup Item 269/88-13-08. This item is applicable to
Unit 1 only.
f.
Valve 2LP-16
While witnessing PT/2/A/0150/22A,
Valve 2LP-16 failed to stroke.
Valve 2LP-16 is the Train "B" LPI System supply valve for HPI pump
suction and RBS system cooling. This valve is opened during various
emergency procedures
by the
RO.
It
is commonly
known
as the
piggyback valve and is opened after the BWST has been drained during
a loss of coolant accident.
After the valve failure, the supply
breaker was verified closed and a work request was written. No other
licensee initiated reviews or evaluations were performed at this
time.
The control room operators were
questioned by the inspectors
concerning HPI and RBS system operability with 2LP-16 being out of
service.
An informal discussion determined that the HPI and
systems were not inoperable and the reasoning used was that: (1) the
valve could be manually opened if required, and (2) the RCS could be
depressurized for the accident condition when this valve is required.
The next shift was also questioned concerning HPI and RBS system
operability with 2LP-16 out of service.
They also stated that the
valve could be manually opened and the RCS could be depressurized.
It was noted that licensee personnel had not verified that the valve
could be manually operated after its initial failure.
There were
also discussions concerning possible area radiation levels during the
accident scenario for which the valve would be required and it
was
determined by the operators that area radiation levels would be
prohibitive for manual operation of this valve.
At this point the
Operating Engineer was contacted in order to determine if any further
action was required.
The following day,
the day shift operators were also questioned
concerning system operability. They also stated that the valve could
be manually operated and the RCS could be depressurized. A shift RO
walked through the emergency procedures with the inspector and
determined that under conditions when 2LP-16 required opening, the
RCS would be saturated and could npt be depressurized as previously
thought.
The licensee was again questioned about HPI and RBS system operabili
ty and it
was stated that the HPI
suction could be manually
cross-tied to supply Train "A" LPI to both trains of HPI and RBS.
Again the licensee did not account for accident radiation levels for
entry to manipulate various valves.
Three different shifts made assumptions that were not valid.
The
valve was not checked for manual operation, area radiation levels
7
during accident scenarios were not considered, and it
was assumed
that the RCS could be depressurized.
The IST Engineer was contacted concerning the valve failure. He, in
turn, contacted ,the
Maintenance
Department
and
personnel
were
assigned to perform the work request.
An electrician physically
lifted the motor starting relay and the valve cycled. The valve was
then cycled from the control room,
the performance group timed the
valve, and the work request was closed.
The root cause for the
failure was not determined,
in that, the failure mechanism was not
identified. At this time the licensee stated that ASME Section XI
allows 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before they were required to declare a non-operating
valve inoperable and thus the HPI
and RBS systems were not
inoperable. The licensee further stated that the HPI pump suctions
were cross-tied and suction flow to all three pumps could be supplied
from the "A" Train LPI pump and therefore the HPI trains were both
During the inspection,
the licensee communicated to the NRC
a
preliminary LER concerning LPI supply to HPI and RBS. The LER stated
an analysis indicated that under certain conditions during the
recirculation phase, both trains of LPI may not be able to provide
adequate HPI pump suction pressure and this could result in the loss
of HPI system capability. It is apparent that if both LPI trains are
unable to supply adequate suction pressure, that only one LPI train
available would be even more restrictive.
The licensee did not take a conservative approach in addressing the
issue of system operability when 2LP-16 failed to open; however, the
valve was repaired, satisfactorily tested, and returned to service
within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. A more desirable action would have been to declare
the HPI and RBS Train "B" systems inoperable, enter the appropriate
TS action statements, make the necessary repairs,
and perform the
appropriate retesting for operability.
g. Miscellaneous Items
(1) PT/1,2,&3/A/0150/22A,
Section 11.0,
Acceptance
Criteria,
Step 11.
1, states that all valves move freely and without
restriction or. binding over a complete cycle.
This acceptance
criteria was not verified during the course of the surveillance
test even though the steps verifying acceptance were signed as
acceptable. This item was considered to be a weakness in the
IST program and needs further management attention. It will be
identified as Inspector Followup Item 269,270, 287/88-13-07.
(2) The inspectors observed the following actions by control room
personnel;
horseplay
(jostling,
joking,
bumping,
etc.)
whistling, backs to panels, feet on desk, crowded conditions,
and the burning of an insect. Most items occurred on one shift.
The licensee was notified by the inspectors that all of these
items conveyed a less than professional appearance. The Station
8
Manager discussed this situation with cognizant operation's
personnel and corrective actions were taken.
During subsequent
observations, this situation did not recur.
This was also
discussed during the management meeting on June 7, 1988.
(3) During a review of various system flow diagrams it
was noted
that certain power operated valves were not included in the IST
program. ASME Section XI, Article IWV 100, Scope, requires that
Class 1, 2, and 3 valves required to perform a specific function
in mitigating the consequences of an accident, are to be tested
to verify operational readiness.
Valves exempted
from this
requirement are valves used for operating convenience, system
control, or for maintenance.
The following valves:
LPSW-772, LPSW-773, and LPSW-774, which
are power operated and are the first isolation valves-outside
containment, were not included in the IST program.
They would
be
used as containment isolation valves for mitigating
radioactive release.
HP-98 is a power operated valve in the HPI suction header. This
valve would be used to provide ECCS HPI train separation on a
suction header fault.
ASME Section XI, IWV-1400, requires that each valve to be tested
in accordance with ASME requirements shall be categorized by the
owner and listed in plant records.
10 CFR_50 Appendix B,Section XI,
Test Control,
states that a
test program shall be established to assure that all testing
required to demonstrate that structures, systems and components
will
perform satisfactorily in service is identified and
performed in accordance with written test procedures.
Contrary to the above requirements, the IST program failed to
assure that components required to be tested were identified.
Valves HP-98, LPSW-772, LPSW-773 and LPSW-774 were not included
in the ASME Section XI valve testing program.
The licensee's
failure to identify valves required to be tested pursuant.to the
1980 ASME Section XI requirements is identified as Violation
269, 270, 287/88-13-03.
4. Maintenance
The inspectors reviewed predictive, preventive, and corrective maintenance
to determine the licensee's ability to identify and correct adverse
trends. This review included field verifying maintenance activities in
progress and reviewing previously completed maintenance activity records.
The maintenance activity review focused primarily on EFW,
FDW,
RPS,
Logic,
HPI,
LPI,
and
RC
system,
although other systems were
included to a lesser extent.
9
a.
Predictive Maintenance
The inspector reviewed plant procedures and station directives to
identify any mechanism used for identifying potential problems that.
could lead to equipment failure.
The inspector also interviewed
responsible personnel and reviewed history files on equipment
identified in the predictive maintenance program.
Engineers in the Maintenance Service section were responsible for
identifying potential problems and for specifying corrective actions.
They reviewed work requests and Nuclear Plant Reliability Data System
information
on a periodic basis to identify potential problems.
Maintenance directives.were used to provide special instructions for
monitoring
specific
equipment.
Maintenance
Directive
5.3.4,
Predictive.Maintenance and Monitoring Program (PM-2),
was used as a
mechanism for identifying problems with rotating and reciprocating
equipment. Maintenance service engineers utilize statistical failure
analysis, oil analysis, and vibration analysis to identify potential
problems per PM-2.
Maintenance Directive 5.3.5, Valve and Valve
Operation Program, provided information
on
the valve program
established at Oconee.
A review of the items identified under the
PM-2
and
the valve operation
program indicated that adequate
monitoring and corrective actions were taken to prevent recurring
problems. The inspector also. noted that those persons responsible
for the vibration and valve program were very knowledgeable of the,
subject matter.
b.
Preventive Maintenance
The
inspector
witnessed
the performance of
IP/O/A/310/12A,
Engineered Safeguards System Logic Sub System 1,, High Pressure
Injection and Reactor Building Isolation, Channel 1, on Line
Instrument Calibration for Channels
1 and 2. The technician
performing the maintenance activity was knowledgeable of the
procedure and the effects of performing the procedure on associated
plants systems.
The procedure was technically correct, however, it
was necessary to perform several steps out of sequence which made its
use somewhat cumbersome.
While witnessing IP/O/A/310/12A, the inspector observed that a jumper
was installed across a power transformer in the cabinet which housed
some of the Channel 1 Engineered Safeguards Instrumentation on Unit 3
(ES Analog Cabinet). The jumper was.not shown on any of the system
drawings.
The jumper was removed by the system engineer when the determination
was made that the jumper served no apparent function.
The system
engineer did not document removing this jumper on a work request or a
modification request, i.e. the jumper was removed without proper
authorization. Several days later, after being questioned by the
inspector, the system engineer documented an evaluation to remove the
10
jumper which included taking meter readings and inspecting similar
cabinets. The licensee believed that the jumper may have been left
in the cabinet after a surveillance, or stored in the cabinet by an
instrument technician rather than returning the jumper to the
appropriate storage location.
The jumper had no effect on system
operability; however, this is considered an example of inadequate
configuration control and is combined with additional examples in
paragraph 4.e. to constitute Unresolved Item 269, 270, 287/88-13-06.
c. Corrective Maintenance
The inspector witnessed licensee personnel performing work requests
55365B, 55366B, and 55367B, performance of PM on the Magnex Valves in
the RVLIS on May 19, 1988. The purpose of the Magnex valves in the
RVLIS is to provide a means of calibrating or replacing a faulty
transmitter with the reactor at elevated pressure. While performing
the maintenance test, the inspector witnessed the technicians
striking the Magnex valves with a nylon hammer and heating the valves
with a portable heater when two valves on Unit 3 could not be
operated manually. This action was in accordance with a hand written
procedure change that was appropriately documented and approved.
The inspector questioned the technicians involved in this activity to
determine how this type of corrective action had been approved. The
inspector was informed that the vendor had recommended this method of
corrective action; the inspector then contacted the vendor.
Vendor
personnel stated that the original request to heat the valves came
from the licensee without mentioning striking or mechanically
disturbing the valves. The vendor concurred with heating the valves;
however,
the licensee did not evaluate the effects of heating or
striking the valves. As a result of the inspector's observations and
discussions with the vendor and licensee, the inspector contacted the
valve manufacturer,
Autoclave,
and spoke with one of the valve's
designers.
He stated that these valves had sensitive internal
components and a light coating of a vacuum grease and were not
designed for the methods of corrective actions taken by the licensee.
The valve manufacturer also stated the preferred orientation of the
valves was in the vertical direction with the operator directly above
the valve body. This allows the ball of the valve to rotate in the
valve cup assembly. The orientation of the valves observed by the
inspector is in the horizontal direction which causes the valve to
rotate against the valve seat. Both valves in question have failed
to close during the last three surveillances.
The first two valve
failures were not identified on the Component Malfunction/Maximum
Tolerance Limit Exceeded sheet as required by the PM procedure and as
such did not receive an appropriate engineering review. The licensee
could not find an evaluation or any objective evidence to justify
their method of corrective action.
There are additional examples of
similar failures and similar corrective actions on Units 1 and 2.
The current method of corrective actions will not ensure the valves
will remain open after the valves that bind are cycled.
Other than
magnetic valve actuator position,
there are
no direct ways to
determine the valves' position.
The valves are not essential to
system operability. The only requirement for the Magnex valves is to
remain open when the RVLIS is required.
Until a satisfactory method of correcting the valve binding problem
can be determined,
the licensee agreed to suspend the practice of
striking and h.eating the valves and pursue a course of corrective
action that will not have the potential of.damaging the valves or the
valves' internals.
d. Work Requests
The inspector reviewed selected samples of the approximately 2900
(1080 open and 1725 closed) QA Condition 1 work requests issued since
January 1, 1987. The review was focused primarily in the area of
retest and functional test requirements, environmental qualification
determinations,
clearances, QA
condition
determinations,
and
adherence to the procedural requirements during the performance of
the maintenance-tasks. Additionally, the inspector reviewed Station
Directive 3.2.1,
Work
Request,
dated February 18,
1988.
Minor
problems were found in the majority of the Work Request packages
reviewed. Selected examples of the discrepancies are as follows:
Work Request No.
12514,
Repack 2LP-76.
On sheet 1 of the Post,
Maintenance Testing section, the inspection for packing leakage
and inspection for general leakage were identified as required
but were not performed. The work request also required Red Tags
to be installed but procedure MP/O/A/1200/01, Valves - Adjusting
and Packing, step 12.1, was marked N/A for the applicability of
clearing the Red Tags.
Work Request No.
14665,
Loop B Feedwater Valve Delta Pressure
Instrument Repair. The QA condition, retest requirements,
and
functional verification were
not correctly identified in
accordance with Oconee Nuclear Station Directive 3.2.1, Sections
6.1, 6.2 and 6.3 respectively.
Work Request No. 03535, 2LP-63. The clearance to begin work was
not given. Sheet 1 of the Post Maintenance Testing section, the
inspection for packing leakage,
and inspection for general
leakage were identified as required but were not performed.
The work requests listed below were for performing
PMs on
Control Rod Drive Breakers:
Not considered EQ related
EQ determination not made
55161B
55154B
55163B
55162B
55155B
55165B
55013A
55156B
55170B
55171B
55157B
55159B
55449A
55158B
55173B
12
The work requests without EQ determinations were not consistent
with the requirements of Station Directive 3.2.1, Work Requests, Section 6.13, Environmentally Qualified Equipment.
Work Request 92265C, Repair 1LPSW-566. The retest requirements
were changed without appropriate initials and date, making it
impossible to determine when or by whom the change was made or
who reviewed the change.
The
following work requests for refurbishing limitorque
operators did not include either determining or documenting that
required retests were performed:
51638G
51659G
51689G
51644G
51687G
51652G
51688G
Note 1
51608G
Note 1
Note
1:
In addition, the appropriate electrical functional
verification test was not specified.
The following work requests involved performance of the Doble
test on 4160 volt breakers and transformers:
57791B
Note 2
58035C
57046C
Note 2
57048C
57044C
Note 2
57045C
57762B
Note 2
.57042C
57435D
Note 2
57033C
Note 3
57043C
52005G
Note 4
57035C
52006G
Note 5
Note 2:
The computer generated retest requirements were
incorrect, however the work planner corrected the work request
prior to commencing work.
Note 3: The clearance for the breaker was not completed and the
systems were returned to service without documentation.
Note 4:
The functional verification test was
incorrectly
specified.
Note 5:
The work request specified a retest which could not
physically be performed. As a result, no retest was performed.
The following work orders had either incorrectly specified
retest requirements or retest requirements were not specified:
96178C
Drain in 2FW-130
53030G
Replace limit switch on 2RC-3
53033G
52922G
15
Work Request 12514C,
Repack 2LP-76,
and Work Request 03535C,
Repack 2LP-63.
On the Post Maintenance Testing sheet, the
inspection for packing leakage and inspection
for general
leakage were identified but were not performed.
The examples noted above were not considered all inclusive and were
considered a programmatic lack of attention to detail in completing
work requests. These examples are collectively combined with another
example of a failure to follow procedures,
paragraph 4.e,
and
constitute Violation 269, 270, 287/88-13-04.
The following work orders were reviewed with no discrepancies noted:
55451A
55449A
52308G
At the licensee's request, the inspector reviewed a sample of work
requests that were not microfilmed or were not completed.
Some of
the same type of problems existed in the additional sample reviewed.
The review results were inconclusive. It was generally not possible
to determine if
the work had been completed correctly since all the
associated paper work had not been finished. Some of the preplanning
work; however, appeared to demonstrate improvement.
The inspector witnessed maintenance activities in progress
and
interviewed selected maintenance personnel to determine the effect of
the maintenance work order discrepancies on actual maintenance work
performed. The consensus of the maintenance personnel interviewed
and the conclusions of the
inspector,
based upon maintenance
activities witnessed,
are that the actual work activities were
performed in accordance with applicable station directives and
applicable procedures. Based on this conclusion, Violation 269, 270,
287/88-13-03
is directed only to the completion of required
documentation and does not indicate a lack of quality in the
maintenance work performed.
e.
Reactor Protection System and Engineered Safeguards Logic
The
inspectors
verified
the
terminated
wiring,
installed
configuration, and logic wiring of selected portions of the RPS and
ES.
A number of discrepancies were identified; the licensee
subsequently reviewed these. discrepancies.
The following are the
specific discrepancies and the licensee's evaluations.
(1) Debris was found primarily in the ES cabinets which included
numerous unattached plastic wiring tags, metal strips, a bag of
termination screws, a box of light bulbs, paper, and a styrofoam
tobacco expectorant receptacle which contained a soiled paper
towel and an apple core. The expectorant receptacle and the
associated contents were wedged in the rear portion of the ES
wiring harness.
14
(2)
Unit 3 ES Analog Cabinet #1, Terminal Block 2, Row 9. A landed
lead from terminal 12 was attached to terminal 9 instead of
terminal 8 as shown on approved drawings or as connected on the
other units.
Licensee evaluation: terminal 8 is the common
ground for the -15 VDC power supply for ES Analog Cabinets 1 and
4. Although the ground was not connected in accordance with the
drawing,
the power supply for cabinets 1 and 4 are operable
based on monthly surveillance results. The licensee stated that
a PIR will be initiated to evaluate the landed lead not attached
in accordance with the termination drawing.
This item was
specifically discussed
on June 14
and June 28,
1988, with
licensee personnel.
The licensee verified that the existing
ground connection to the ES Cabinet would perform the function
of the instrument ground.
(3) Unit 1 ES Analog Cabinet #1, Terminal Block 3, Row 9. Terminals
1 and 2 have landed leads which are not designated on controlled
drawings. Licensee evaluation: although the connections are not
on controlled drawings, they go to the test panel control point.
(4) Unit 2 ES Analog Cabinet #1, Terminal Block 3, Row 9. Terminals
6 and 7 have
landed leads which are not on the ,terminal
drawings. Licensee evaluation:
although the terminations are
not shown
on the appropriate termination drawings,
they are
shown on the test panel control board drawings.
(5) Unit 2 ES Analog Cabinet #1, Terminal Block 3, Row 9. Terminals
1 and 2 have landed leads which are not designated on controlled
drawings. Licensee evaluation: although the connections are not
on controlled drawings, they go to the test panel control point.
(6)
Unit 1 ES Analog Cabinet #1, Terminal Block 3, Row 9. Terminals
6 and 7 have landed leads which are not on the terminal
drawings. Licensee evaluation: although the terminations are
not shown on the appropriate termination drawings, they are
shown on the test panel control board drawings.
(7) Unit 3 ES Analog Cabinet #1, Terminal Block 3, Row 9. Terminals
6 and 7 have landed leads which are not on the terminal
drawings. Licensee evaluation: although the terminations are
not shown on the appropriate termination drawings, they are
shown on the test panel control board drawings.
(8) Unit 3 RPS Channel D-2 cabinet contains a jumper from Terminal
Block 6, Row 8, terminal 2 to Terminal Block 6, Row 9, terminal
3, which is not designated on controlled drawings. The licensee
was in the process of evaluating this discrepancy.
(9) Unit 3 RPS
Channel
A-1 cabinet,
Terminal
Block 3, Row 8,
terminal
12 has a landed lead which is not designated on
controlled drawings. Licensee evaluation: the function of these
15
wires has not been determined and will require tracing the
circuit in the RPS cabinet.
(10) Unit 3 RPS Channel A-2 cabinet, jumper shown on drawing going
from Terminal Block 6, Row 8, terminal 1 to Terminal Block 6,
Row 9, terminal.3 actually goes from Terminal Block 6, Row 8,
terminal 2. Licensee evaluation: this supplies the ground for
the manual bypass switch, and is the result of rolled wires on
the back plane of the terminal strip.
(11)
Unit 3 RPS Channel A-2 cabinet, terminals 9 and 10 have parallel
connections not shown on the termination drawings.
Licensee
evaluation: these wires go to the B&W test panel
and are
reflected on drawing 0-2715 H1.
(12) Unit 3 RPS Channel
B-1 cabinet,
Terminal
Block 5,
Row 9,
terminals 4, 5, 9, and 10 and Terminal Block 6, Row 9, terminals
1, 2, 4, and 5 have parallel connections which are not on the
termination drawing. Licensee evaluation: these wires to the
B&W test panel and are reflected on drawing 0-2715 HI.
(13) Unit 3 RPS Channel C-2,
cabinet jumper shown on drawing going
from Terminal Block 6, Row 8, terminal 3 to Terminal Block 6,
Row 9, terminal 3 actually goes from Terminal Block 6, Row 8,
terminal 2. Licensee evaluation: this supplies the ground for
the manual bypass switch, and is the result of rolled wires on
the back plane of the terminal strip.
(14) Unit 2 RPS Channel C-2 cabinet has a jumper between terminals 10
and
12
that does not appear on the termination drawing.
Licensee evaluation: this supplies the ground for the manual
bypass switch, and is the result of rolled wires on the back
plane of the terminal strip.
(15) On all three units in the A-1, B-1, C-1 and D-1 RPS cabinets, a
metal test jack assembly and the associated test leads were not
considered in the seismic design of the RPS cabinets and were
not shown on the system drawings.
The test jacks are used to
measure RC flow transmitter signals.
(16) Numerous test connections are in the ES and RPS cabinets that
are not shown on the wiring drawings.
Items 2-14 and 16 are examples of configuration control inadequacies
Until these configuration control
inadequacies are resolved by the-licensee, this-is combined with an
additional example of a configuration control inadequacy as discussed
in paragraph 4.b to constitute Unresolved Item 269,
270,
287/88-13-06.
Item 1 contains examples of failure to maintain adequate housekeeping
controls in the
ES cabinets.
The failure to maintain adequate
16
housekeeping is contrary to the requirements of Maintenance Directive
3.2.5, Maintenance Housekeeping Program, and is collectively combined
with other examples of failure to follow procedures, paragraph 4.d.,
and constitutes Violation 269, 270, 287/88-13-04.
Item 15 resulted in portions of the RPS being in a seismic configura
tion which was previously unanalyzed.
After the identification of
the concern
by the inspector,
the licensee performed a seismic
analysis of the cabinets which demonstrated the cabinets were
seismically qualified in their current configuration.
This is
considered as an additional example of Unresolved Item 269,
270,
287/88-13-06. Another example is discussed in paragraph 4.b.
f. Quality Assurance Involvement In Maintenance
To determine the extent that QA was involved in the work request
process the inspector interviewed the QA Work Request Controller.
The Work. Request Controller delineated the work request flow path
through the QA organization. The inspector then interviewed selected
QA personnel and reviewed selected QA audits and surveillances.
The
inspector concluded that while QA only reviewed portions of the work
requests, the work request discrepancies should have been detected by
QA. This area needs additional attention by the
QA audit and
surveillance programs.
To determine the extent that QA was involved in the configuration
the inspector interviewed selected QA
personnel.
The results of the interviews indicated that QA was not
directly involved in modifications that were considered to be
non-safety related and were not part of the decision process to
determine if the modifications were
safety
related.
Since
documentation
did not exist to indicate how the
specific
discrepancies noted in paragraph 4.e occurred,
QA was not aware of
the activities that
may
have
caused the
specific discrepant
conditions. Additionally,
QA does not have a specific audit or
surveillance program which required the field verification of RPS or
ES terminations or system logic. The lack of QA involvement in the
determination of whether a modification is safety related or not and
the lack of a program to verify ES and RPS terminations and logic,
were considered contributing factors which led to the findings noted
in paragraph 4.e. The licensee has agreed to include inspections of
this type in future QA surveillances or audits.
5. Design Control
The inspector reviewed the station modification program and examples of
SPRs, DSs, ECs,-TMs, Alarm and Setpoint Changes, and NSMs.
Interviews
were conducted with personnel in Project Services, Maintenance Services,
Instrument and Electrical, Training, and Compliance.
a. Modification Controls
17
The inspector reviewed a sample of open and closed NSMs,
for the
period since January 1987 and identified that documentation required
by the Nuclear Station Modification Manual, Station Directive 2.3.4,
Nuclear Station Modification Program, revised October 8, 1987,
and
Project Services Manual,'Section 4.6, Nuclear Station Modification,
revised April 8, 1988,
was present.
The station has identified the
open NSM backlog as a problem and established goals to reduce that
backlog. Between April 1986 and April 1988, the number of open NSMs
decreased from approximately 1150 to approximately 450. The goal of
450 was expressed to the inspector as approximately two years worth
of work.
The inspector
reviewed approximately
120
ECs
to assure that
modifications were not being handled as ECs,
which receive a lesser
level
of approval, review, schedule, and documentation.
The
inspector reviewed
OE-1239 which performed
steam generator tube
sleeving and modified the primary system boundary, and OE-1227 which
installed nozzle dams and.nozzle dam hold down rings in the steam
generators. The review of OE-1227 and OE-1228 by the individual NSRB
members resulted in the following concern:
"These exempt change VNs were to install nozzle dam hold down
rings in the "A" & "B" OTSGs for Unit 1.
Why was this done
using an exempt change VN instead of issuing an NSM? What's the
basis for this meeting the exempt change VN criteria?"
The response to this concern stated the following:
"It
was the Superintendent of Maintenance's decision to handle
this
modification
as a VN
rather than
an
NSM.
The
Superintendent is no longer at Oconee, but it.is speculated that
his decision was based on the fact that the modification could
be done quicker."
These examples received what appeared to be complete and technically
accurate reviews and evaluations, but the potential to mistreat the
modification control program appears to exist.
The inspector reviewed approximately 25 TMs from January 1987 to the
present, and identified that all requirements for evaluation, review,
and approval were present.
The three month re-evaluations were
present for TMs open greater than this period.
b.
10 CFR 50.59 Evaluations
10 CFR 50.59(b)(1) states that the licensee shall maintain records of
changes in the facility, including a written safety evaluation which
provides the bases for the determination that the change does not
involve an unreviewed safety question.
The safety evaluation is only required for changes to the facility
which alter the design,
function,
or method of performing the
18
function of a structure, system, or component described in the Safety
Analysis
Report either by text or drawing.
Since structures,
systems, or components which are not explicitly described in the
Safety Analysis Report clearly have the potential for affecting those
systems which are explicitly described, this affect must be
considered in the performance of either safety evaluations or the
screening process utilized in determining if
an unreviewed safety
question is required.
The NSMM, Appendix E, Guidance for 10 CFR 50.59 Evaluations, Section
7.1,
provides the criteria for determining if
a 10 CFR
50.59
evaluation is required.
Among the criteria listed are requirements
for a review of the possibility of degradation of equipment important
to safety during events such as seismic, fire, tornadoes, missiles,
flood, security, etc., and for changes which actually result in a
different physical appearance.
Section 7.1 also provides guidance
for the written justifi.cation which must be provided whenever a
10 CFR 50.59 evaluation has been determined to not be required.
The inspector reviewed Nuclear Station Modifications, Exempt Changes,
Temporary Changes, and Alarm and Setpoint Changes to determine the
adequacy of the attached 10 CFR 50.59 evaluations.
The following
exempt changes pertaining to valve replacements were determined by
site personnel to not involve an unreviewed safety question; however,
they did not have a 10 CFR
50.59 evaluation performed,
nor a
documented basis other than a generic statement that the replacement
component met or exceeded original design specifications and that the
component had been approved by DE (this is not an inclusive list):
OE No.
OE No.
OE No.
OE No.
1341
1347
1190
1355
1359
1360
1312
1313
1606
1607
1608
1609
1620
1621
1622
1609
1658
1344
1200
The licensee determined that the following exempt changes required a
10 CFR 50.59 evaluation and determined that an unreviewed safety
question was not involved, but did not include the bases for the
determination that an unreviewed safety question was not involved.
This list is not intended to be all inclusive.
OE No.
OE No.
OE No.
OE No.
1349
1339
1188
1192
1218
1179
The licensee informed the inspector that since the DE group had
approved the replacement valves, this was justification for not
providing a complete 10 CFR 50.59 evaluation, as the DE group did a
19
complete analysis prior to approving the replacement valves.
The
engineer who
approved the
replacement
valves
stated
that
acceptability of the new valves was based on pressure, temperature,
and application of the valves.
He also stated that the failure
mechanisms of the old valves were reviewed to select a valve less
susceptible to the failure.
The engineer was asked to supply the
records of the evaluations for the valve replacements but he stated
that no records were available and that he had not been told to
maintain them.
The inspector reviewed the NSRB review sheets for NSRB meetings dated
September 21,
1987,
November 20,
1987,
and February 5, 1988.
The
NSRB members continually expressed concern as to the adequacy of the
10 CFR 50.59 evaluations for the ECs used for valve replacements.
The NSMM, Section 9.0, Subsection 9.2.1.3, Exempt Changes for
Electrical and Instrumentation Systems
and Components,
included
instrumentation setpoints as an item to be handled under the EC
process. The site Project Services Manual, revised June 26, 1987,
Section 4.4, Exempt Changes, referenced the NSMM as the source to be
used in determining when a change requires an EC.
Oconee Nuclear Station Directive 2.1.3, revised April 14, 1987, Alarm
and Setpoint Control,
stated that setpoint changes were
made
utilizing the
Procedure Major Change Process Record form.
This
directive did not include the DE group in the development and review
of proposed changes. The Station Directive did not require that a
10 CFR 50.59 evaluation be performed, even though the change form has
a section titled, Safety Evaluation; it
required only that four.
questions be answered yes or no. These questions include:
Involves an unreviewed safety question?
Requires completion of a Nuclear Safety Evaluation Check List?
The
Nuclear Evaluation Check List is a detailed 10 CFR 50.59
evaluation, but none of the changes since January 1987, required that
one
be completed.
This included two changes that required TS
revisions.
The revisions to the TS themselves had 10 CFR 50.59
evaluations attached, but the setpoint change documents did not.
The inspector reviewed the change packages for instrumentation
setpoints generated since January 1987.
Changes to the Alarm and
Setpoint document do not include 10 CFR 50.59 evaluations other than
a statement that an unreviewed safety question is not involved. The
determination of the existence of an unreviewed safety question, as
described in both the NSMM and 10 CFR 50.59, was performed; however,
the bases for the determination that an unreviewed safety question
was not involved was not documented.
The
inspector reviewed procedure
changes
that implemented the
setpoint changes to determine if the 10 CFR 50.59 procedure
20
evaluations would satisfy the requirements for the actual setpoint
changes.
The evaluations addressed the impact of revising the
procedures,
not the impact in changing the actual setpoint.
The
inspector was informed that the Station Directive governing Alarm and
Setpoint Control would supposedly be revised by June 1, 1988,
to
include instructions to complete 10 CFR 50.59 evaluations.
Since early 1987,
the licensee has been working to upgrade their
10 CFR 50.59 program.
The program for procedure revisions is
scheduled to be implemented June 1, 1988; however, the program for
the modification program was implemented in early 1987,
with the
latest revision being implemented December 1,
1987.
The valve
replacement program discrepancies identified by the
inspector
occurred after the implementation of the new program. The alarm and
setpoint changes were handled as procedure revisions; however,
even
the old program would have required a 10 CFR 50.59 evaluation.
While the inspector noted an increase in the quality of the 10 CFR
50.59 evaluations performed for NSMs and
TMs,
the evaluations
performed for the valve replacement ECs and the Alarm and Setpoint
Changes do not satisfy the requirements of 10 CFR 50.59(b)(1).
The
failure to adequately document the bases for the determination that
changes did not involve an unreviewed safety question is contrary to
10 CFR 50.59 requirements and is identified as Violation 269,
270,
287/88-13-05.
6.
Exit Interview
The inspection scope and findings were summarized on May 27,
1988, with
those persons indicated in paragraph 1.
The inspectors described the
areas inspected and discussed in detail the inspection findings listed
below. The licensee did not identify as proprietary any of the material
provided to or reviewed by the inspectors during this inspection.
Dissenting comments were not received from the licensee.
Item Number
Description and Reference
269,270,287/88-13-01
Violation - Failure to provide accurate
IST and fire watch records, paragraphs 3.b
and 3.c.
269,270,287/88-13-02
Violation -
Failure to measure the full stroke
time of ASME Section XI valves paragraphs 3.d.
269,279,287/88-13-03
Violation -
Failure to identify valves to be
tested pursuant to ASME Section XI requirements,
paragraph 3.g.(3).
21
269,270,287/88-13-04
Violation
-
Failure
to
follow
procedural
requirements of Station Directives relating to
maintenance work
requests
and
cleanliness
controls, paragraphs 4.d and 4.e.
269,270,287/88-13-05
Violation -
Failure to document the basis for
10 CFR 50.59 determinations, paragraph 5.b.
269,270,287/88-13-06
URI -
Configuration control inadequacies in the
ES and RPS cabinets, paragraphs 4.b and 4.e.
269,270,287/88-13-07
IFI -
Acceptance criteria for valves moving
freely, paragraph 3.g.(1).
269/88-13-08
IFI
-
Corrective actions for valve 1LP-21
multiple failures, paragraph 3.e.
7. Acronyms and Initialisms
-
American Society of Mechanical Engineers
-
Babcock and Wilcox
BWST
-
Borated Water Storage Tank
CFR
-
Code of Federal Regulations
-
Des'ign Engineering
DS
-
Design Studies
EC
-
Exempt Changes
-
Emergency Feedwater
-
Environmentally Qualified
-
Engineered Safeguard
FDW
-
HP/HPI
-
High Pressure Injection
IFI
-
Inspector Followup Item
-
Inservice Inspection
IST:
-
Inservice Testing
LCO
-
Limiting Condition for Operation
LER
-
Licensee Event Report
LP/LPI
-
Low Pressure Injection
-
Low Pressure Service Water
LWD
-
Liquid Waste Disposal
MOVATS
-
Motor Operator Valve Testing
N/A
-
Not Applicable
NEO
-
Nuclear Equipment Operator
NRC
-
Nuclear Regulatory Commission
NSM
-
Nuclear Station Modification
NSMM
-
Nuclear Station Modification Manual
-
Nuclear Safety Review Board
-
Oconee Exempt Change
-
Once Through Steam Generator
P&S
-
Planning and Scheduling
-
Problem Investigation Report
-
Preventative Maintenance
-
Periodic Test
22
-
Quality Assurance
-
Reactor Building Spray
RC/RCS
-
-
Reactor Operator
-
-
Reactor Vessel Level Indicating System
SPR
-
Station Problem Report
-
Senior Reactor Operator
-
Terminal Block
TI
-
Temporary Instruction
TM
-
.TS
-
Technical Specification
VN
-
Variation Notice
- 0