ML18152A351
| ML18152A351 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 03/07/1995 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A352 | List: |
| References | |
| 50-280-95-03, 50-280-95-3, NUDOCS 9503150013 | |
| Download: ML18152A351 (17) | |
See also: IR 05000122/2002011
Text
Virginia Electric and Power Company
Surry 1
Docket No.: 50-280
License No.: DPR-32
During an NRC inspection conducted on January 22 through February 11, 1995, a
violation of NRC requirements was identified.
In accordance with the "General
Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR Part 2,
Appendix C, the violation is listed below:
Technical Specifications 6.4.A.7, 6.4.C and 6.4.D require that detailed
written procedures and instructions shall be provided for corrective
maintenance activities which would have an effect on the safety of the
reactor. They also require that these procedures be reviewed and
approved by the Station Nuclear Safety and Operating Committee and that
they be followed.
Virginia Power Administrative Procedure {VPAP)-0801, Maintenance
Program, revision 4, implements these requirements for maintenance
activities.
VPAP-0801, Section 6.3.3.c requires the safety significance of the
maintenance activity, complexity of the maintenance activity and
experience and training of personnel performing the activity be
considered when determining whether a detailed maintenance procedure or
skill of the craft should be utilized to accomplish a maintenance
activity.
VPAP-0801, Section 6.18.2.a requires that maintenance activities
performed by a vendor at the station be accomplished in accordance with
approved procedures.
Contrary to the above, approved detailed written procedures were not
used to perform complex maintenance and vendor related activities on the
Unit 1 turbine drive auxiliary feedwater pump {TDAFWP) as evidenced by
the following examples:
1.
On December 24 and 25, 1994, and January 11, 1995, the
TDAFWP governor was replaced using Work Orders {WOs) 301919
02, 301919 03 and 306913 08 respectively. Approved detailed
maintenance procedures were not u~ed.
2.
On December 24 and 25, 1994, and on January 11, 1995,
vendors performed maintenance/adjustment/testing on the
TDAFWP governor using WOs 301919 01 and 02, 301919 03 and
306913 08 respectively. Approved detailed maintenance
procedures were not used.
9503150013 950307
ADOCK 05000280
G
POO
ENCLOSURE 1
2
3.
On January 10, 1995, the turbine speed control system
linkage was disassembled and reassembled using WO 306913 01.
An approved detailed maintenance procedure was not used.
This is a Severity Level IV violation (Supplement I).
Pursuant to the provisions of 10 CFR 2.201, Virginia Electric and Power
Company is hereby required to submit a written statement or explanation
to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk,
Washington, D.C. 20555 with a copy to the Regional Administrator, Region
II, and a copy to the NRC Resident Inspector at the facility that is the
subject of this Notice, within 30 days of the date of the letter
.
transmitting this Notice of Violation (Notice). This reply should be
clearly ~arked as a "Reply to a Notice of Violation" and should include
for each violation:
(1) the reason for the violation, or if contested,
the basis for disputing the violation, (2) the corrective steps that
have been taken and the results achieved, (3) the corrective steps that
r
will be taken to avoid further violations, and (4) the date when full
compliance will be achieved.
Your response may reference or include
previous docketed correspondence, if the correspondence adequately
addresses the required response.
If an adequate reply is not received
within the time specified in this Notice, an order or*Demand for
Information may be issued as to why the license should not be modified,
suspended, or revoked, or why such other action as my be proper should
not be taken.
Where gciod cause is shown, consideration will be given to
extending the response time.
Dated at Atlanta, Georgia
This 7th day of March, 1995
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
50-280/95-03 and 50-281/95-03
Licensee: Virginia Electric and Power Company
Innsbrook Technical Center
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
License Nos.:
Facility Name:
Surry 1 and 2
Inspection Conducted: January 22 through February 11, 1995
Inspector:
Other
- Inspectors:
Approved by:
D. M. Kern, Resident Inspector
S. G. Tingen, Resident Inspector
G.6i. ~Wn.chief
Division of Reactor Projects
SUMMARY
Scope:
.s~ ,-rr
Date Signed
¥.1 lfS-
DaeS1gned
This routine resident inspection was conducted on site in the areas of plant
status, operational safety verification, maintenance inspections, surveillance
inspections, onsite engineering review, plant support and action on previous*
inspection items.
Inspections of backshift and weekend activities were
conducted on January 25, 28, and February 3 and 4, 1995.
Results:
- operations
Although operators were challenged by equipment problems, Unit 2 was shutdown
and cooled down in a slow and deliberate manner (paragraph 3.1).
Exceeding the Unit 2 pressurizer heatup rate was identified as an unresolved
item pending a fatigue analysis review (paragraph 3.2).
2
Lowering reactor coolant system level was conducted in accordance with
procedures, equipment response was as expected, and operators properly focused
on safety (paragraph 3.3).
Maintenance
Failure to use approved detailed written procedures for maintenance activities
associated with turbine driven auxiliary feedwater pump (TDAFWP) governor
replacement, turbine speed control system linkage assembly and governor post
installation maintenance/adjustment/testing was identified as a violation
(paragraph 4.1).
The pre-evolution briefing for Unit 2 safety bus logic testing was very good.
Safety focus and communications were clearly emphasized. Operations personnel
safely resolved unexpected occurrences and maintained excellent control of the
evolution (paragraph 5.2).
Engineering
Evaluation and initial corrective actions associated with the Unit 2 C high
head safety injection pump motor power requirements were implemented in a
timely manner and were conservati!e (paragraph 5.1).
Procurement, storage, and handling of TDAFWP model PG-PL governors was
acceptable. Warehouse cleanliness, storage, purchase orders, design change
development, and commercial grade dedication processes were generally good.
Two isolated weaknesses regarding design change development and shelf-life
evaluation were identified (paragraph 6.1).
l .
1.
Persons Contacted
Licensee Employees
- V. Armentrout, Licensing
REPORT DETAILS
- W. Benthall, Supervisor, Licensing
- M. Biron, Supervisor, Radiation Engineering
H. Blake, Jr., Superintendent of Nuclear Site Services
- R. Blount, Superintendent of Maintenance
- B. Bryant, Licensing
- D. Christian, Station Manager
J. Costello, Station Coordinator, Emergency Preparedness
D. Erickson, Superintendent of Radiation Protection
- B. Garber, Licensing
B. Hayes, Supervisor, Quality Assurance
- D. Hayes, Supervisor of Administrative Services
- A. Keagy, Superintendent of Materials
D. Llewellyn, Superintendent of Training
- C. Luffman, Superintendent, Security
- J. McCarthy, Assistant Station Manager
- A. Price, Assistant Station Manager
- S. Sarver, Superintendent of Operations
- R. Saunders, Vice President, Nuclear Operations
- K. Sloane, Superintendent of Outage and Planning
E. Smith, Site Quality Assurance Manager
- T. Sowers, Superintendent of Engineering
- B. Stanley, Supervisor, Station Procedures
J. Swientoniewski, Supervisor, Station Nuclear Safety
- J. Winebrenner, Supervisor, Procurement Engineering
Other licensee employees contacted included plant managers and
supervisors, operators, engineers, technicians, mechanics, security
force members, and office personnel.
NRC Personnel
- M. Branch, Senior Resident Inspector
- D. Kern, Resident Inspector
- S. Tingen, Resident Inspector
- Attended Exit Interview
Acronyms and initialisms used throughout this report are listed in the
last paragraph *
..
2.
2
Plant Status
Unit 1 operated at power for the entire inspection period.
On February
10, power was reduced to 60% to repair the B main feedwater pump. The
unit was returned to full power operation on February 12.
Unit 2 was in end of cycle coastdown up to February 2.
The Unit was
shutdown on February 3, from 84% power, to perform a RFD.
The unit was
in a RFD at the end of the inspection period.
3.
Operational Safety Verification (71707)
The inspectors conducted frequent tours of the control room to verify
proper staffing, operator attentiveness and adherence to approved
procedures.
The inspectors attended plant status meetings and reviewed
operator logs on a daily basis to verify operational safety and
compliance with TSs and to maintain overall facility operational
awareness.
Instrumentation and ECCS lineups were periodically reviewed
from control room indication to assess operability. Frequent plant
tours were conducted to observe equipment status, fire protection
programs, radiological work practices, plant security programs and
housekeeping.
DRs were reviewed to assure that potential safety
concerns were properly addressed and reported .
3.1
Unit 2 Shutdown
The inspectors witnessed selected portions of the Unit 2 shutdown
and subsequent cooldown conducted on February 3. Although
operators were challenged by equipment problems the inspectors
noted that the unit was shutdown and cooled down in a slow and
- deliberate manner.
Communications during plant cooldown were
good.
Pressurizer and RCS cooldown rates were closely monitored
and the inspectors independently verified that TS cooldown rates
were not exceeded.
Unit 2 RCS integrity was good.
Few signs of
leakage were observed during the hot containment walkdown.
The following equipment problems were encountered during the
shutdown:
The steam dump valve master controller stuck at
approximately ten percent demand which resulted in two of
the eight steam dump valves remaining partially open.
This
problem caused operators to deviate from the normal plant
shutdown procedure.
DR S-95-0194 was issued to ensure that
this deficiency was resolved.
Source range nuclear instrument N-31 failed to operate after
being energized. Operators entered 2-AP-4.00, Nuclear
Instrument Malfunction, revision 3, which required that
adequate shutdown margin be verified within one hour and
then every twelve hours.
The inspectors reviewed TS Table
3.7.1, Item 4, Nuclear Flux Source Range, which also
r
'
l
3.2
...
3
required that adequate shutdown margin be verified within
one hour and then every twelve hours.
The licensee verified
the shutdown margin in accordance with TS.
DR S-95-0195 was
issued to ensure that this deficiency was resolved.
Auxiliary spray valve 2-CH-HCV-2311 seat leakage
significantly complicated RCS pressure control. The problem
hampered operators' ability to control pressure throughout
the RCS depressurization process.
The inspectors
independently verified that RCS pressure and temperature
were maintained within the allowable regions of the plant
operation curve.
DR S-95-0206 was issued to ensure that the
spray valve deficiency was resolved.
The inspectors
confirmed that a WO to disassemble, inspect, and repair
2-CH-HCV-2311 was written and scheduled for completion prior
to reactor startup.
The containment particulate radiation monitor indicated an
increased trend in containment radiation level. The
containment gas radiation monitor indicated that radiation
levels were not increasing.
An air sample obtained from
containment indicated normal particulate activity.
Containment sump in-leakage rate was calculated and was
normal. Operators assessed the aggregate indications and
concluded that containment radiation levels were normal. A
deficiency card was issued to investigate and repair the
containment particulate radiation monitor.
Unit 2 Pressurizer Excessive Heatup Rate
On February 4, the licensee degassed the RCS in preparation for
the RFO.
The unit was in cold shutdown with a bubble in the
pressurizer. The evolution required that charging pump flow
rate be increased to compensate for the increased letdown flow
rate. Pressurizer level increased while operators were balancing
RCS inventory during the degas evolution and a decrease of
129 degrees F was noted in pressurizer water temperature.
The TS
allowable cooldown rate is 200 degrees F per hour. Operators were
concerned that they were approaching this limit and adjusted
charging pump flow to slowly decrease pressurizer level. During
the following one hour, water temperature in the pressurizer
increased by 146 degrees F which exceeded the TS allowable heatup
rate of 100 degrees F per hour. The licensee was recording
pressurizer water temperature every 30 minutes and identified that
the TS allowable heatup rate was exceeded.
At the end of the
inspection period, the licensee was performing a fatigue analysis
for the pressurizer. Until the inspectors review the licensee's
fatigue analysis, this is identified as URI 50-281/95-03-01,
Unit 2 Pressurizer Excessive Heatup Rate.
4.
4
3.3
Unit 2 Reactor Vessel Draindown to Flange Level
On February 8, the inspectors witnessed draining the Unit 2 RCS
from a level of 5 percent in the pressurizer (approximately 29
feet) to a level of 17.6 feet on the reactor vessel standpipe.
Draining to this level was required to support refueling
activities. This evolution was accomplished in accordance with
procedure 2-0P-RC-004, Draining the RCS to Reactor Flange Level,
revision 4.
During the initial drain down phase, the pressurizer
level was monitored.
For the three and one-half feet region that
the reactor vessel standpipe level indicator and the pressurizer
level instrumentation do not overlap, an inventory balance was
utilized to monitor the amount drained.
Upon reaching the 24 foot
level, the reactor vessel standpipe was used to monitor level in
the reactor vessel. The inspectors concluded that the draindown
evolution was conducted in accordance with procedures, equipment
response was as expected, and that operators properly focused on
safety.
Within the areas inspected, one URI was identified.
Maintenance Inspections (62703)
NRC Inspection Report Nos. 50-280/94-33 and 50-281/94-33 described the
December 1994 outage work on the Unit 1 TDAFWP and the January Unit 1
reactor trip and failure of the TDAFWP on demand.
At the conclusion of
that inspection the licensee's RCE was not complete and several items
were identified as URI 50-280/94-33-01 for subsequent followup.
The URI
had five parts and this section will address parts 1 and 4, control of
work activities and vendor instructions. Parts 2, 3 and 5 of the URI
are discussed in section 6 of this report.
4.1
Control of Work Activities
Through review of the Unit 1 TDAFWP maintenance activities
conducted on December 24 and 25, 1994, and January 10 through 11,
1995, the inspectors concluded the following:
On December 24 and 25, 1994, and January 11, 1995, the
TDAFWP governor was replaced using WOs 301919 02, 301919 03
and 306913 08 respectively. Approved detailed maintenance
procedures were not used.
On December 24 and 25, 1994, and on January 11, 1995,
vendors performed maintenance/adjustment/testing on the
TDAFWP governor using WOs 301919 01 and 02, 301919 03 and
306913 08 respectively. Approved detailed maintenance
procedures were not used.
On January 10, 1995, the TSCS linkage was disassembled and
reassembled using WO 306913 01.
An approved detailed
maintenance procedure was not used.
I
4.2
5
The inspectors reviewed the station maintenance training program
for the TDAFWP contained in JPM-0-51, Perform Maintenance to Terry
Turbine, revision 4.
The inspectors concluded that details such
as installation of the governor valve lever block and governor
valve control air pressure inlet vent plug were not specifically
addressed. According to the licensee's training department, only
one mairttenance engineer had attended a Woodward governor training
course. The inspectors concluded that TDAFWP governor
installation and TSCS linkage assembly were complex maintenance
activities and that maintenance personnel did not have the
training to perform these activities without detailed procedures.
After reviewing TM 38-W971-00001, Woodward PG-PL Governor,
revision 1, and procedure O-MCM-1403-01, Terry Turbine Overhaul,
l-FW-T-2 and 2-FW-T-2, the inspectors concluded that the TM
instructions for performing governor post installation
maintenance/adjustments/testing were not incorporated into
O-MCM-1403-01.
The inspectors were informed that the post
installation maintenance/adjustments/testing was performed by the
vendor.
The inspectors observed the vendor perform this evolution
on January 11, 1995.
The inspectors concluded that TDAFWP
governor post installation maintenance/adjustments/testing was
performed by the vendor without approved procedures .
TSs 6.4.A.7, 6.4.C and 6.4.D as implemented in part by VPAP-0801,
Maintenance Program, revision 4, require that maintenance
activities which would have an effect on the safety of the reactor
be performed in accordance with detailed written procedures
approved by SNSOC.
VPAP-0801, Section 6.3.3.c requires the safety
significance of the maintenance activity, complexity of the
maintenance activity and experience and training of personnel
performing the ,1ctivity be considered when determining whether a
detailed maintenance procedure or skill of the craft should be
used to accomplish a maintenance activity. VPAP-0801, Section
6.18.2.a requires that maintenance activities performed by a
vendor at the station be accomplished in accordance with approved
procedures.
Failure to use approved detailed written procedures
for maintenance activitjes associated with TDAFWP governor
replacement, TSCS linkage assembly and governor post installation
maintenance/adjustment/testing is identified as Violation
50-280/95-03-02, Failure to Use Approved Detailed Procedures.
Control of Vendor Information
The licensee's initial RCE identified possible concerns with
control of vendor information.
The inspectors reviewed the
control of vendor information that applied to the TDAFWP.
VPAP-0602, Vendor Technical Manual Control, revision 1 and
ENAP-0023, Technical Manual Preparation and Revision, revision 2,
were reviewed and the inspectors concluded that the licensee was
6
maintaining TDAFWP vendor information in accordance with their
program.
Within the areas inspected, one violation was identified.
5.
Surveillance Inspections (61726, 37551}
The inspectors reviewed the following surveillance activities to assure
compliance with appropriate procedure and TS requirements.
5.1
Unit 2 HHSI Pump C Testing
5.2
During a recent engineering review of HHSI pump flow rates, the
licensee identified that Unit 2 HHSI pump C motor power
requirements exceeded the design value of 690 horsepower.
On
January 30 PPR 95-007 was issued documenting this issue.
On
January 31 the PPR was reviewed by the Management Problem Review
Team and DR S-95-0177 was subsequently issued. Unit 2 HHSI pump C
was declared ini>perable and removed from service on January 31.
On February 8 the inspectors witnessed the performance of sections
6.6 and 6.7 of 2-0PT-Sl-006, SI Accumulator Distharge Check Valves
Full Open Test and 2-CH-P-lC Flow Test, dated February 7, 1995.
This procedure was revised to test HHSI pump C.
The inspectors
attended the pre-evolution brief and witnessed the test from the
control and switchgear rooms.
Motor currents and voltages were
measured at seli!cted pump fl ow rates. The 1 icensee calculated
that the motor power requirements were 711 horsepower based on
data obtained during the test.
At the end of the inspection period, the licensee was evaluating
this issue. Resolution of the issue will be addressed during the
unit startup assessment at the end of the RFD.
The inspectors
concluded that the evaluation and initial corrective actions
implemented to resolve this issue were timely and conservative.
Periodic Safety Bus Logic Testing
On February 4, the inspectors observed Unit 2 safety bus logic
testing. Procedure 2-0PT-ZZ-002, ESF Actuation With Undervoltage
and Degraded Voltage - 2J Bus, revision 5, is a complex evolution
which verified proper logic circuit actuation for over twenty
safety related protective signals. A senior operations manager
provided an additional level of test oversight in accordance with
VPAP-0108, Infrequently Conducted or Complex Tests or Evolutions,
revision 0.
Procedure 2-0PT-ZZ-002 had recently been revised to
incorporate TS revisions and eliminate a redundant EOG start. The
test director, a licensed SRO, conducted personal briefings with
over thirty individuals during the prior week specifically
discussing their responsibilities during the test. The pre-
evolution brief emphasized communications and self checking.
7
The inspectors concluded that station preparations for the test
and management oversight were very good.
Two unexpected occurrences were encountered early in the test.
First, during degraded voltage EDG cold start testing, EDG No. 3
did not align to the Unit 2 safety bus as required.
The test
di rector qui ckl:, recognized the cause to be an error in the
recently revised procedure.
The EDG loaded properly for the
switch al i gnmen*: which had been es tab l i shed in the procedure.
The test director temporarily halted the test to ensure the EDG
alignment and p*lant conditions were clearly understood.
Following
discussion with system engineers and the test director, the senior
operations manager directed the test director to proceed with the
test. System engineers initiated an appropriate procedure
revision to correct the EDG alignment problem.
The second problem
occurred when operators experienced difficulty unloading the No. 3
EDG due to an apparent voltage mismatch.
Operations, maintenance,
and engineering personnel conducted non-intrusive troubleshooting
and identified the cause to be a loose connector on a voltage
meter within the remote EDG control cabinet. The connector was
tightened and the test continued. The shift supervisor
appropriately controlled plant activities to ensure operators were
not unduly challenged during conduct of logic bus testing. The
inspectors concluded that operations personnel resolved unexpected
occurrences during the test evolution in a deliberate and safe
manner.
The te;t director maintained clear communication and
oversight throughout the test.
Within the areas inspected, no violations or deviations were identified.
6.
Onsite Engineering Review (37551, 38703)
6.1
Procurement of TDAFWP Governors
On January 8 the Unit 1 TDAFWP tripped on demand due to a turbine
overspeed condition. While the initial licensee's RCE did not
identify a definite cause, degraded governor performance was
postulated to be the most likely cause.
Improved Woodward model
PG-PL governors had previously been installed for Unit 1 (1990)
and Unit 2 {1991) in accordance with DCP 88-16-3, AFW Turbine
Governor Replacement Unit 1&2.
In December 1994, the Unit 1
TDAFWP governor was replaced with a spare governor {serial no.
2435227) which had been stored in the warehouse since procurement
in 1990.
The inspectors reviewed the procurement and CGD of these
governors to determine whether governor quality and performance
had been properly validated for their safety related application.
6.1.1 Purchase Orders and Material Specification
Three PG-PL governors were purchased commercial grade using
PO CNT 299814 and were dedicated by a third party under PO
CNT 301368 for use in safety-related applications. Both POs
8
incorporated material specification NUS-2203/NAP-0007,
revision 3, which detailed the technical and QA requirements
for the fabrication, testing, inspection, documentation, and
shipment of the governors.
The inspectors noted that
responsibility for performing the various specified tests
was not clearly stated in the material specification. Three
tests specified in the POs were not performed by the
vendors.
Project engineers stated that the three tests
which were not performed by vendors were intended to be
post-instilllation licensee tests, not vendor tests. The
licensee *informed the inspectors that responsibility and
scheduling of specific tests were clarified at post award
conferences with the vendors.
The inspectors independently
confirmed that each of the tests listed in NUS-2203/NAP-0007
were satisfactorily completed for the two governors
installed in 1990 and 1991 by DCP 88-16-3.
Both POs were
well writ:en and NUS-2203/NAP-007 was thorough in specifying
governor performance criteria, QA criteria, and support
requirements (i.e., vendor technical manuals, drawings,
material handling information).
6.1.2 Storage and Handling
The inspectors toured material storage facilities,
interviewed personnel, and reviewed receipt records to
determine whether the model PG-PL governors were properly
stored after procurement.
The POs specified Level C
packaging and storage requirements consistent with ANSI
N45.2.2 - 1972, Packaging, Shipping, Receiving, Storage, and
Handling of items for Nuclear Power Plants.
No special
packaging or storage instructions were specified by the
vendor.
Governor 2435227 was stored in a Class B storage
area, which fully satisfied the requirements of Level C
storage, upon receipt in 1990.
The storage warehouses were
clean, dry, and properly monitored for temperature extremes.
In November 1994, governor 2435227 was directly transported
by a company employee to and from a test facility in a
clean, climate controlled vehicle.
The inspectors noted
that the governor had not been packaged in a waterproof
enclosure which would be typical for Level C shipments.
Materials management stated that in this instance, delivery
under the direct control of a company employee provided
equivalent protection from the environment as would have
been obtained by using Level C packaging and shipping the
governor via contract carrier. The inspectors determined
that packaging/handling of the spare governor during
delivery to the test facility was acceptable.
Management
subsequen~ly initiated appropriate action to ensure that
packaging requirements for direct off-site deliveries of
material, which bypass the normal contract carrier shipment
process, are evaluated on a case-by-case basis. The
9
inspectors determined that storage and handling of the spare
governor was acceptable based on licensee's program
controls.
Subsequen~ to the January 1995 TDAFWP failure, the licensee
obtained additional storage recommendations from the vendor
which had not been provided under the original PO.
The
licensee *is reviewing this information for future
applications. Governor 2435227 was disassembled and
visually inspected after the January 1995 failure. Material
condition appeared good with no indications of improper
storage. The inspectors concluded that storage and handling
of model PG-PL governors was acceptable.
6.1.3 Test Records
Test requirements for the PG-PL governors were specified in
NUS-2203/NAP-0007.
Initial vendor testing was performed at
the manufacturer's facility under the oversight of licensee
QA personnel and third party engineers. Seismic testing to
support the third party CGD was performed at an independent
safety related test facility. The inspectors reviewed the
third party CGD test plan performed under PO CNT 301368 and
verified ~hat critical component characteristics such as
dimension:; and testing were identified for model PG-PL
governor and that these had been successfully demonstrated.
Post installation testing of the model PG-PL governor was
performed on Unit 1 and Unit 2 while implementing
DCP 88-16-3.
The DCP was generally well written. However,
the inspectors noted that the Functional Testing
Requirements and Acceptance Criteria section did not include
two of the tests specified in NUS-2203/NAP-0007.
This was a
weakness in the development of the DCP.
The inspectors
discussed this observation with project engineers who stated
that recent improvements in the DCP process have clarified
what items are to be listed as functional test requirements
and there!~ reduced the likelihood of similar omissions.
The inspectors reviewed STD-GN-0001, Instructions for DCP
Preparation, revision 13, and noted that the current
procedure provides good instruction for identifying
functional test requirements.
VPAP-0301, Design Change Processes, revision 4, specifies
that the post modification test plan be developed based upon
the functional test requirements section of the DCP.
System
engineers recognized that although not listed in the DCP, a
post installation system stability test was needed.
Engineers added the speed regulation and maximum speed rise
tests as described in NEMA SM 23-1985, Steam Turbines for
Mechanical Drive Service. These were the same two tests
identified in NUS-2203/NAP-0007 which were not listed in the
~.
..
10
DCP functional test section. The inspectors reviewed DCP
88-16-3 test records and determined that all tests specified
in the original material specification, were successfully
completed by the final post modification test plan.
The
inspectors noted that the post installation stability
testing performed on Units 1 and 2 during implementation of
DCP 88-16-3 was not performed when the Unit 1 governor was
replaced in December 1994.
The inspectors specifically
questioned why the speed rise test was not performed for
governor 2435227.
Project engineers stated that governor
2435227 had been dedicated for safety related use by
PO CNT 301368 and that critical component characteristics of
the governor type were verified. Additionally, engineers
indicated that the post installation testing specified in
DCP 88-16-3 was intended to be a design validation test.
Therefore, similar testing of a l i ke-for-1 i ke replacement
governor was not necessary as part of the PMT.
The
inspectors agreed with the licensee's position.
6.1.4 Governor Shelf-life
The CGD test report from a safety-related vendor recommended
a 10 year PG-Pl governor design life based on the presence
of Buna-N materials internal to the governor.
Project
engineers evaluated the recommendation and determined that
the PG-Pl governor should not be assigned a design or shelf-
life of less than 40 years. This conclusion was based upon
oral communications with the vendor who indicated that the
Buna-N components had most likely been upgraded to Viton
material which has a longer design life. The manufacturer
had begun using Viton in place of Buna-N in the 1990
timeframe.
The material list provided with the governor and
the CGD test report indicated that the components were made
of Buna-N.
The inspectors questioned whether the licensee
had sufficient assurance that the governors were upgraded to
Viton internal components.
The inspectors determined that
absence of documentation to support the governor shelf-life
determination was an isolated weakness.
VPAP-0704, Shelf
life Evaluation and Control, revision 2, provided good
instructions for shelf-life evaluations. Procurement
engineers requested that the vendor provide an updated
governor material list and report the material type
identified during the recent (February 1995} diagnostic
disassembly of governor 2435227.
The inspectors determined
that these actions were appropriate to verify the correct
material composition of the govetnors.
6.1.5 Commercial Grade Dedication
The model PG-Pl governors were commercially grade dedicated
in 1990 by a third party vendor under PO CNT 301368.
The
inspectors confirmed that the licensee had properly
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certified the third party vendor to perform safety-related
services. The governors were received as safety-related
material.
In November 1990 the licensee issued PO BNT 484751 to a
non-safety related vendor to adjust the governor 2435227
high speed stop and perform associated governor performance
testing. The inspectors reviewed procurement documents and
interviewl!d licensee personnel to determine whether vendor
services were appropriately dedicated.
PTE SSEROOI9.002 and
CGIE SSEROOI9.002 were developed to identify critical
performance characteristics to be tested and specify
acceptance criteria. The PTE and CGIE were detailed and
properly \\iritten in accordance with station procedures. The
licensee provided QA and technical oversight at the vendor's
test facility. The QA VFIR properly documented successful
verification of each critical characteristic listed in
CGIE SSEROOI9.002.
No parts were replaced on governor
2435227 at the vendor's facility. Procurement engineers
demonstrated indepth knowledge regarding the CGD processes.
The inspectors concluded that the licensee appropriately
commercial grade dedicated the vendor services provided
under PO BNT 484751 .
6.1.6 Summary
Model PG-PL TDAFWP governors were purchased commercial grade
and were commercially grade dedicated for use in safety-
related applications by a third party.
Procurement
documents including the material specification were
detailed. Isolated weaknesses regarding DCP development. and
shelf life evaluation were identified. Appropriate actions
to addres:; these weaknesses were initiated. Storage,
handling, and CGD of the vendor services were appropriate.
6.2
Effectiveness of RCE Process
The licensee's RCE for the January 8, Unit I TDAFWP failure was
discussed in NRC Inspection Report Nos. 50-280/94-33 and
50-281/94-33.
The licensee's RCE team concluded that the most
probable causal factors were "Equipment Condition" and
"Maintenance/Testing Practices." The team's findings indicated
that governor 2435227, which was in-place during the January 8
overspeed trip was suspect since diverging oscillations were only
experienced with that governor. Additionally, the team determined
that maintenance/testing was a causal factor because of inadequate
vendor TM instructions and PMT instructions.
In this area the
team concluded ~hat the vendor had critical information to set-up
the governor and linkage in the field. This information was not
contained in a written procedure or available to the Virginia
Power personnel who performed governor replacement and linkage
refurbishment during the December 1994 SGCC outage.
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Based on review of the RCE team's log book and meeting with team
members, the inspectors noted that although their efforts were
extensive the RCE failed to determine why governor 2435227 behaved
as it did on January 8.
Within the areas inspected, no violations or deviations were identified.
7.
Plant Support (71750)
The inspectors observed radiological control practices and radiological
conditions throughout the plant. Radiological posting and control of
contaminated areas was good.
Workers complied with radiation work
permits and appropria~ely used required personnel monitoring devices.
The protected area security perimeter was well maintained with no
equipment or debris obstructing the isolation zones.
Within the areas inspected, no violations or deviations were identified.
8.
Action on Previous Inspection Items (92702)
(Closed) URI 50-280/94-33-01, Issues Relating to Unit 1 TDAFWP Failure.
This item resulted from the NRC's review of the January 8, 1995,
overspeed trip of the TDAFWP.
The inspectors identified the following
topics as part of URI 50-280/94-33-01:
1.
Acceptability of controlling work activities using WOs in
lieu of detailed SNSOC approved procedure.
2.
. Possible *impact of CGD process used for governor
procurement, repairs and testing conducted by the vendor.
3.
Storage requirements for the governor in the warehouse.
4.
Control of vendor information and vendor activities.
5.
Effectiveness of root cause process.
The inspectors' review of these items is discussed in sections 4.1, 4.2,
6.1 and 6.2 of this report.
Within the areas inspected, one violation as .discussed in section 4.1
was identified.
9.
Exit Interview
The inspection scope and findings were summarized on February 15, 1995,
with those persons indicated in paragraph 1. The inspectors described
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the areas inspected and discussed in detail the inspection results
addressed in the Summary section and those listed below.
Item Number
URI 50-281/95-03-01
Status
Open
Description/(Paraqraph No.)
Unit 2 Pressurizer Excessive
Heatup Rate (paragraph 3.2).
VIO 50-280/95-03-02
Open
Failure to Use Approved
Detailed Procedures
(paragraph 4.1).
Proprietary information is not contained in this report. Dissenting
comments were not received from the licensee.
10.
Index of Acronyms and Initialisms
ANSI
CFR
CGIE
DR
F
NRC
PO
SGCC
SNSOC
TDAFWP
TM
TS
TSCS
VFIR
VPAP
%
AMERICAN NATIONAL STANDARDS INSTITUTE
CODE OF FEDERAL REGULATIONS
COMMERCIAL GRADE ITEM EVALUATION
DESIGN CHANGE PACKAGE
DEVIATION REPORT
ENGINEERED SAFETY FEATURE
FAHRENHEIT
HIGH HEAD SAFETY INJECTION
NATIONAL ELECTRICAL MANUFACTURES ASSOCIATION
NUCLEAR REGULATORY COMMISSION
POST MAINTENANCE TESTING
PURCHASE ORDER
POTENTIAL PROBLEM REPORT
PROCUREMENT TECHNICAL EVALUATION
QUALITY ASSURANCE
ROOT CAUSE EVALUATION
REFUELING OUTAGE
STEAM GENERATOR CHEMICAL CLEANING.
SAFETY IN,JECTION
STATION NUCLEAR SAFETY AND OPERATING COMMITTEE
SENIOR REACTOR OPERATOR
TURBINE DRIVEN AUXILIARY FEEDWATER PUMP
TECHNICAL MANUAL
TECHNICAL SPECIFICATION
TURBINE SPEED CONTROL SYSTEM
UNRESOLVED ITEM
VENDOR FINAL INSPECTION REPORT
VIOLATION
VIRGINIA POWER ADMINISTRATIVE PROCEDURE
WORK ORDER
PERCENT