ML18152A141
| ML18152A141 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 03/08/1988 |
| From: | Jape F, Szczepaniec A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML18152A142 | List: |
| References | |
| 50-280-88-02, 50-280-88-2, 50-281-88-02, 50-281-88-2, NUDOCS 8803280076 | |
| Download: ML18152A141 (19) | |
See also: IR 05000280/1988002
Text
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Report Nos. :
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
50~280/88-02 and 50-281/88-02
Licensee:
Virginia Electric and Power Company
Richmond, VA
23261
Docket Nos.:
50-280 and 50-281
Facility Name:
Surry 1 and 2
License Nos.: DPR-32 .and DPR-37
Inspection Conducted:
February 1-5, 1988
Team Leader:
..
?iz,~ * 9-r< .
F. J~e
.
,,
A. Si"ci~i~ bfs'a'/{'feam feader
Team Members:
W. Kleinsorge
R. Perfetti
S. E. Sparks
P . .Taylor
Accompanying Personnel:
A. R. Herdt
Approved by:
~ *
.~
F. Jape,
1e
Test Programs Section
Division of Reactor Safety
SUMMARY
3/f!KI
Date Signed
o~/e'f,~~
>1J11dr
Date Signed
- scope:
This special, announced inspection was conducted in accordance with
11Balance of Plant Trial Inspection Program (Feedwater System)
11 to
assess the licensee's practices concerning Bala_nce _of_ Plant in programmatic
areas of Operations and Training, Maintenance, Design Control and
Modifications, and Management Support and Quality Assurance.
Outstanding open
items were also inspected.
Results:
In the areas inspected, violations or deviations~were not identified .
8803280076 880315
ADOCK 05000280
Q
BACKGROUND
BALANCE OF PLANT INSPECTION
EXECUTIVE SUMMARY
Recent NRC and industry reports analyzing unplanned reactor shutdowns and plant
trips. have indicated that a majority were caused by transients from failures of
BOP systems and components.
The safety significance of BOP failures can be
related to two aspects of challenges to reactor.safety.
The first concerns
challenges to reactor safety systems caused by BOP failure, such as failure of a
feedwater regulating valve.
The second concerns BOP failures that complicate
the ability of operators and.safety systems to control the reactor given that a
challenge to a safety system has already occurred.
An example of. this would be
the failure of turbine bypass valves which could complicate recovery during a
plant transient.
Looked at from a different perspective, the safety significance of BOP failures
can be related to the probability of reactor core damage. This probability can
be directly related to two separate factors .. The first factor is the frequency
or number of challenges to safety systems; the second is the unavailability of
those systems.
Thus, decreasing the frequency of challenges to safety system
from the BOP can.decrease the risk to public health and safety;
NRC' s Temporary Instruction (TI) 2515/83 was developed as a result of the
growing concern for the safety significance of BOP failures.
Similar
inspections have already been performed at Salem Nuclear Generating Station,
6/15-19/87; Edwin I. Hatch Plant, 7/27-31/87; and Zion Nuclear Station,
10/19-23/87.
Due to -the plant operating history and the number of BOP
failures,. the Surry Power Station was chosen as a fourth site for the special
inspection.*
SCOPE
This inspection was not intended to be compliance oriented. This it primarily
due to the absence of prescriptive requirements applicable to BOP systems.
Rather, the intent was to justify to the licensee concerns about design,
modification, maintenance, operations and testing practices for BOP systems,
specifically feedwater and related components.
The team consisted of six
inspectors with one assigned to the different programmatic areas of Operations
and Training, Maintenance, Design Control and Modification, and Modification
and Quality Assurance.
The* most current events, based on licensee event
reports,were selected for initial review.
These events were.revi'ewed for-root
cause determination and corrective act ions. * Each inspector then reviewed the
events for the attributes of each programmatic area as they applied for each*
event.
When _felt' useful, additional events or failures were reviewed to obtain
a clearer understanding of how the attributes are perceived or handled by the
licensee.
Although the feedwater system was the main focus of the inspection,
other BOP systems which would exemplify actions of the licensee were also
reviewed.
The assessment of the licensee's practices were then based on a.
I I
sampling of events arid actions on the part of the -licensee, including
procedures, reports and programs and selected interviews with plant personnel.
RESULTS
The results of the inspection ar~ detailed within the report and are summariz~d
here and classified as strengths or weaknesses.
Other observations which were
not classified as either strengths or weaknesses are discussed in the
report.
Strengths are those items which the inspection team feel make a
considerable positive impact upon the licensee's efforts to increase
BOP /feedwater system re 1 i abi 1 i ty and decrease safety system cha 11 enges. *
Weaknesses are those areas considered to be needing attention Dr correction to
achieve the same results.
a.
Strengths
1)
Simulator training is conducted on a continuing cycle to enhance the
operators abi_ 1 i ty to contra l feedwater during startups and shutdowns.
2)
Self imposed requirements have recently been added to test feedwater
regulating valves at shutdown and prior to startup.
3)
Work progress on BOP equipm~nt proceeds at approximately the same
rate as* safety-related equipment, once the work item ha*s been
identified.
4)
Establishment and active use of a predictive maintenance program and
a maintenance engineering organization.
5)
Establishment and use of the Quality Maintenance Team concept.
6} - Engineering Work Packages and Design Change Packages are handled the
same for BOP systems as for safety-related.
7)
Good communications . exist between_ key personnel in Technical
Services, Operations and Maintenance associated with regard to design
modifications.
8)
The number of BOP related reactor trips has _reduced from 11 in 1984
to two in 1987, and attention continues to be di -rected toward
reducing the number further.
9)
Extensive management involvement/interest in BOP/feedwater system
problems.
10) * Continued allocation of significant funds toward BOP/feedwater
systems .
11)
There appears to be a* concerted effort by, the 1 i censee to upgrade
equipment, whenever poss i b 1 e, in conjunction with modifications.
Examples include the incorporation of upgraded underv~ltage relay
III
models .in the Main Tran~former work request, and the incorp6ration of
rotary screw air compressors in the IA design change.
12)
When a problem arises at one unit and a design change is initiated,
there appears to be a good effort by the 1 i censee to eva 1 uate the *
. app 1i cabi l ity of the change to the other unit and to fo 11 owup
accordingly.
b.
Weaknesses
1)
Lack of formal programs for root cause analysis, documentation,
trending and centralization of information on station, specifically
for BOP /feedwater system.
Reviewed LE Rs have shown 1 ack of
consistency, thoroughness and relationship to previous events.
2)
- Lack of a formal program for trendin~ BOP deviations, similar to one
in use for safety-related equipment.
3)
Subjective determination of when BOP/feedwater components are to be
repaired, or possibly underg6 design modifications.
This is related
to the lack of formal training and trending programs.
4)
The licensee 1s approach to the repeated problems with the instrument
air system and the main f eedwater va 1 ves appears to be more
prescriptive than preventive.
CONCLUSIONS
Using the guidelines of TI 2515/83, and based upon observations, staff
interviews, and reviews of various_programs, records, procedures, and reports,
the Surry Power Station has been found to have a significant number of the
applicable attributes which are decreasing safety system challenges and
increasing feedwater and their BOP system/component reliability.
L
Persons-Contacted
Licensee Employees
REPORT DETAILS
- J. A.* Bailey, Superintendent of Operations
- D. L. Benson, Station Manager*
.
- R. H. Blount, II, Superintendent of Technical Services
- D. J. Burke, Superintendent of Maintenance
- A. H. Friedman, Superintendent of Training
- E.* S. Grecheck, Assistant Station Manager
- J. B. Logan, Supervisor, Safety Engineering
- H. L. Miller, Assistant Station Manager
G. L. Pannell, Director, Safety Evaluation and Control*
Other 1 i censee emp 1 oyees contacted inc 1 uded engineers, technicians,
operators, mechanics, and office personnel.
NRC Resident Inspectors
- vi. E. Holland
L. E. Nicholson
- Attended exit interview*
2.
Exit Interview
The inspection scope and findings were summarized on February 5, 1988,
with those persons indicated in Paragraph 1 above.
The inspector
described the . areas inspected and discussed in deta i 1 the inspection
findings. . No dissenting comments were received from the 1 i censee.
The *
licensee did not identify as proprietary any of the materials provided
to or reviewed by the inspectors during this inspection.
NOTE:
A list of abbreviations used in this report is contained in
paragraph 11..
3.
Licensee Action on Previous Enforcement Matters
a.
(Closed) Unresolved Item 281/86-36-03, RTD Ca~ibration Records
This matter was reviewed by the NRC staff and it was concluded that
the method used by the. licensee was adequate.
This UNR is closed .
2
b.
(Closed) Unresolved Item 281/86-36-04, RTD Temperature Map
The temperature prof i 1 e map provided by the 1 i censee fo 11 owing the
inspection was reviewed.
The physical location of data points were
indicated.
This resolves the inspector's concern and the item is
closed.
c.
(Closed) Unresolved Item 281/86-36-05, Revise Procedures
The ILRT procedure was revised to require retention and retrie~al of
raw data used in the acceptance criteria.
Test results were
revalidated, therefore, this item is closed.
4.
Unresolved Items
Unresolved items were not identified during this inspection.
5.
Selected Components and Events
6.
Using the guidelines of TI 2515/83, the inspection team selected the most
current events and component failures on which to begin the inspection.
The concept of the inspection was to then use these events and components
as a starting point for a review of each programmatic area.
Results of
the inspection are therefore not only based upon these LERs, but also upon*
p 1 ant operating hi story, post-trip reports, other se 1 ected LE Rs, and
discussions with plant personnel.
The initial LERs reviewed were:
280/86-001
280/86-005
280/87-019
281/86-003
281/86-007
281/87-003
Reactor trip due to loss of instrument air
Isolated phase bus duct arcing
.Manual reactor trip due to failed relay in main
transformer
Turbine/reactor t~ip from high steam generato.r
l~vel
. . .
. * ..
Manual reactor trip due to high steam generator
level
Reactor trip by turbine generator anti-motoring
- turbine trip due to governor valve leakage
The programmatic areas reviewed were Operations and Training, Maintenance,
Design Contra 1 and Modi fi cat ions, and Management Support and Qua 1 i ty
Assurance.
The areas were inspected using the applicable attributes of
TI 2515/83 and the results in each area are presented separately.
Design and Modifications Aspects
An eva 1 uat ion was made of th*e 1 i censee' s fo 11 owup investigations. and .
activities relating to the long-term corrective actions with regard to
design modifications as they applied to the selected components and events
listed in paragraph 5.
3
There were no design medications associated with lER 86-001. _ The root
cause of the reactor trip as outlined in the licensee's LER, appeared to
have been from a -decrease in instrument air *(IA) pressure due to ice
_formation in the condenser-evaporator section of the Unit 1 IA dryer that
resulted in blocking air flow to the IA system.
A hot gas. bypass valve in
the dryer was not properly adjusted to maintain air temperature above
freezing.
Corrective action consisted of proper adjustment of the bypass
- valve by a service representativeand revision of the turbine building logs
to incorporate IA dryer condenser temperature readings.
No design changes
or modifications were instigated by the licensee as a result of this LER.
LER 86-005 involved the manual tripping of Unit 1 from 42% power due
to .arcing on the A isolated phase bus duct.
The root. cause of the *
duct arcing appeared to have been as a result of corrosion product
buildup on the contact surfaces of the lugs of the ground straps that
were used to bridge butting sections of duct.
(The straps carried
less current which led to the duct arcing).
Corrective action
consisted of replacement of the damaged section of duct by welding to
prevent *possible recurrence and modification to other butting
sect ions of duct by we 1 ding such that the probabi 1 i ty of future
occurrences would be reduced as a result of the e 1 i mi nation of the
grounding straps.
No additional modifications or design changes were_
instigated by the li_censee as a result of this LER.
_
.
.
LER 87-019 involved the manual tripping of Unit 1 from* 98% power due
to 1 ass of cooling and oil fl ow for the
118
11 Main Transformer.
Power.
was 1 ost to the cooling fans and oi 1 ci rcul at i ng pumps when an
undervoltage. relay in -the cooling control circuit failed.
In
addition, the transformer local annunicator * panel had failed to
initiate a TROUBLE alarm on the c*ontrol room annunciator panel.
The
- failures of the relay and the annunciator panel were attributed to
aging.
As a result of the event, several modifictions to. the Main
Transformers and their associated alarms in the control room were
outlined in
an
engineering work request
(EWR)
for Unit 1.
Modifications included *the addition of a redundant trouble alarm to
prevent future faulty operations, (Winding Temperature High and Total
Loss of Oil Flow Alarm), installation of fault pressure protection -
(Sudden Pressure Relay trip package), -installation on an insulating
barrier behind some of the re 1 ays in the trans former contro 1 pane 1 s,
and e 1 i mi nation of a 11 automatic throw-overs between the 480V sources
within the Transformer cabinets.
The automatic throw-over switch is
undesirable because it has the potential of transferring any trouble
-on the circuit being transferred. to the second circuit causing all
cooling to the lost.
EWR No.87-329 was reviewed to verify that the
modifications were designed, constructed, and tested in accordance
with appropriate portions of non-nuclear codes and standards that
were the. same as those used for the ori gi na 1 components.
(Vi rgi ni a
Power's Transformer Standard Specification is VEP-3700-86-01).
Due
to the unavailability of some of the necessary materials, all
modi fi cat i ans could not be performed during* the December 1987 Snubber
Outage.
However, the licensee's Control_ Operations staff_ discussed
4
the rema1n1ng modifications* to be perforfued, as well
~s * the
additional improvements to the Unit 1 Main Transformer with the NRC
_inspector.
In addition to the modifications to the Unit 1 Main Transformer,.
similar modifications - were performed under EWR No.87-330 for the*
Unit 2 Main Transformer.
This work request also included the
addition of emergency breakers so that one 480vac source could supply
both cooling groups if necessary.
LER 86-003 involved a Unit 2 turbine trip/reactor trip from high
steam generator level in the "8
11 steam generator.
The high steam
_generator 1 evel occurred during rampdown when the
118
11 main feedwater
bypass valve apparently failed to close on demand.
The failure is
believed to have been caused by a blockage in the air pilot relay
which prevented proper air fl ow to the va 1 ve operator. -The b 1 ockage
was dislodged following the trip and the valve cycled satisfactorily.
LER 86-003 stated that an* engineering review to evaluate the most
effective method of contra 11 i ng contaminants in the IA system was
being conducted.
As a result of this review, design change package
(DCP) number 86-03~3 was initiated.
The compressed air system at Surry originally consisted of a service
air subsystem, - an instrument air subsystem, _and a containment air
subsystem for each uriit.
The service air and instrument air subsystems
were supplied by identical positi.ve displacement, reciprocating type
air compressors which had required continua 1 maintenance, thereby *
reducing the reliability of the compressed air system.
During the
licensee's
Steam 'Generator
Replacement
Outage
appr*oximately
1980-1981, an outage service air compressor (originally dedicated as
the so.urce of outage service air inside containment) and a condensate
po 1 is her instrument air compressor were designated as the primary
source for the. instrument .and service air subsystems.
The original
instrument and service air compressors were used to provide backup air. _
While the outage instrument and service air co~pressor and the condensate
polisher instrument air compres~or were more teliable, the compressors
could not meet all df the station's compressed air requirements.
Therefore,
DCP 86-03-3 dated October 26, 1986 proposed to rep 1 ace the original
service air compressors on a one for one basis with* new oil free,
rotary screw air cooled compressors.
The
rotary screw air
_ compressors are. thought to be more reliable than the* reciprocating
. type air compressors throughout the industry.
The new service air compressors which are double the capacity of the
original service air compressors are designated as the normal source
of ser~ice and instrument air for each unit.
The original instrument
air compressors left installed in their original location are
dedicated for emergency standby service.
_
While the upgrade of air compressors for both units shows a concerted
effort by the
1 i censee to increase system re 1 i abi 1 i ty 1 _ the
5
thoroughness and timeliness of the design change is questionable.
This observation stems from the following information.
LER 86-001, which was previously discussed, concerned the events
surrounding a reactor trip* on* Unit 1 due to loss of instrument air.
The root cause cited in the LER was an improperly adjusted hot gas
bypass valve in the dryer that resulted in ice formation which
subsequently blocked air flow to the IA system.
A similar event
occurred on Unit 1 on November 21, 1985, LER 85-022.
At the time of
the initial report, it was only speculated that the cause of the
event was due to a momentary drop in IA pressure.
The LER was updated
on March 26, 1986.
Although the pressure decrease in IA did not
result in a reactor trip, it did present a challenge to the ability
of the plant personnel
to maintain the unit 1s availability.
Corrective action. outlined in
LER 86-001 consisted of proper
adjustment of :the bypass valve and inclusion of lA dryer condenser
temperature readings into the turbine 1 ogs.
Whi 1 e both LER 1 s cite
the root cause as an improperly adjusted bypass valve,* DCP 86-03-3
dated October 28, 1986, appears to cite a different root cause,
specifically,
11The decrease in instrument air header pressure was
attributed to a mechanical failure in the air dryer which caused
moisture in the compressed air to freeze and prevent air.flow.
11
Not
only does this discrepancy question the licensee 1s root cause
analysis, it *also questions the licensee's desire to update the proper
documentation since it would appear that the true root cause would be
cited in the most recent analysis, (DCP 86-03-3 dated October 28,
1986),
thereby, prompting a correction of affected documents,
LER 85-022 and LER 86-001.
Further, it is questionable as to why the
instrument dryers were not upgraded in conjunction with the air
compressors,
since
DCP 86-03-3 *states that,.
11 In addition to
compressor reliability problems, the instrument air dryers (1-IA-0-1
and 2-IA-0-1) have required continual maintenance
11 *.
With regard to the ti me 1 i ness of the design change, it appears as
though the 1 i censee might have precluded at 1 east the two cited
challenges to the safety sytems, had the recognized deficiencies been
modified sooner.
It would appear that the licensee recognized the
problems with the original compressed air system from an early time
period since DCP 86-03-3 states,
11The instrument and service air
- com~ress,~rs have required cont i n~a 1 mai ~tenan~e and . have. not been
rel 1 ab 1 e!1/~ an.d that a more rel 1 ab 1 e, J ury-r, gged s ubst, tute was
employed after the Steam Generator Outage, approximately in the 1981
time frame.
While the use of the substitute compressors improved the
reliability of the compressed air systems for both units, it is not
evident from the documentation provided for the inspector* s review,
. that the 1 i censee made an effort or commitment to reso 1 ve and modify
the compressed air systems for the station until February 8, 1986,
when a prob 1 em with the IA system resulted in a cha 11 enge to the .
safety systems and a commitment was made to evaluate methods for
contamination in the IA system.
Detai 1 s of this event are out 1 i ned
in LER 86-009, Automatic Start of Auxiliary Feedwater PU.!1JPS, fo.r _
6
Unit 1.
Eight days later, the same problem with IA resulted in a reactor
trip on Unit 2 as previously discussed in LER 86-003.
LER 86-007 details the events surrounding a ~anual reactor trip on Unit 2
due to high steam gene~ator leVel.
The roo~ cause cited in the LER was
failure of Feedwater Control Regulation Valve, FCV-2478 to close.
The
failure was attributed to metal debris between the plug and the valve
seat.
The valve was. disassembled, inspected and the metal debris
preventing the valve closure was removed.
The valve was reassembled,
tested satisfactorily; and returned to.operable status.
the LER concluded
that no further act ion was necessary regarding this event to prevent
recurrences.
The lack of a documented commitment to evaluate possible
methods to prevent this type of FCV failure in the future.as well as other
failure mechanisms might be construed as a weakness in the licensee's
. approach to BOP systems and components given the hi story of the FCV
fai 1 ures for both Units 1 and 2.
During the period from January 1986 to
August 1987, 24 main feedwater control valve failures ,.occured.
(9 for
Unit 1 and 15 for Unit 2).
While some of these failures could be
attributed to poor maintenance procedures and practices, some of these
failures could be attr.ibuted to design weaknesses including (but not
limited to) valve packing._ lifetime, *valve trim (plug and cage or seat)
lifetimes, valve operator adjustment sensitivity, valve operator inability
to withstand their environmental vibration, and valve operator inability
to function with poor quality instrument air.
Design changes initiated to
upgrade the main feedwater control valves (as well as other main feedwater
valves) could be instrumental in making the main feedwater system more
re 1 i able, thereby reducing the probabi 1 i ty of unnecessary cha 11 enges to .
reactor safety systems.
Therefore, the need for possible design changes.
should be evaluated by the licensee.
LER 87-003 details the events surrounding a Unit 2 reactor trip by turbine
trip.
As Unit 2 was ramping down for a maintenance., outage, the turbine
tripped due to a generator anti-motoring s i gna 1 as operators were -
preparing to remove the main generator from service.
The root cause of
the generator anti-motor signal was cited in the LER as leakage past the
governor valves.
The LER committed to inspect the govern valves during
the next outage of sufficient* duration and for repairs to be made
accordingly.
This commitment was verified by the inspector via the
licensee's Commitment Tracking System.
As a result of this event, EWR
No.87-193 was initiated.
The EWR evaluated the need for an instantaneous
alarm circuit to the niain turbine anticipatory motoring trip to possibly
prevent unnecessary reactor trips.
Currently, the main. turbine is
designed to have an anticipatory motoring trip base_d on a low differential
.pressure (LlP) across the High Pressure turbine.
A time delay relay
- circuit is activated upon sensing low LlP.
If this condition does not
clear withih one minute, there is activation of a turbine trip.
The
annunciator in the control room informs the operator of this trip
mechanism after the one minute delay.
Currently, there is no alarm on the
alerting device on a low LlP across the HP turbine to warn that a turbine trip
will result. in one minute, if this signal does not clear.
Therefore, *EWR
No.87-193 proposed to add an instantaneous alarm_ switch to the trip logic
7
for the main turbine anticipatory motoring trip based on low LlP.
Upon
activation of the one minute time delay relay for low LlP turbine trip, an
annunciator window labeled "Generator Motoring Turbine Low LlP
11 would light
up in the control room and would possibly enable operations time to clear
the condition and prevent unnecessary trips.
The EWR package was reviewed
by the inspector and was found to be in accordance with the 1 i censee I s
Technical Specifications, established QA/QC controls and was consistent
with the Updated. Final Safety Analysis Report and Design Basis Document.
The licensee's unreviewed safety question evaluation.was also reviewed and
was found to be in accordance with the requirements of 10 CFR 50.59.
The
incorporation of the. instantaneous alarm circuit was considered as a
strength by the inspector in terms of the licensee's approach to BOP.
systems and components.
7.
Operations
a.
LER Review
The selected LERs were reviewed to determine the appropriateness of
the licensee's actions from an operational standpoint.
The inspector
verified that the 1 i censee I s LER ope rat iona 1 commitments were being
tracked and documented.
Operating Procedure 2-0P-2.1.2, Decreasing
Power from Existing Power Level to 2%, was reviewed to verify the
revision commitment of LER 86-003 concerning the stroke testing of.the
feedwater bypass valve prior to.use.
The inspector. also reviewed Procedure SUADM-LR-08, Licensee Event
Report System, along with the selected LERs to determine the adequacy
of the licensee's root cause analysis.
The r~view revealed that the
licensee's root cau~e analysis was not documented adequately in the
LERs.
In addition, the licensee failed to discuss, as outlined in
SUADM-LR-08, why prior corrective actions did not prevent recurrence
for LERs86-003 (Unit 2) and 86-005 (Unit 1).
- b.
System Valve Lineups and Walkdowns
The inspector reviewed the most recent valve lineups performed by.the
licensee as indicated from operating Procedures 2-0P-30.lA,
Condensate Va 1 ve Checkoff, and 2-0P-31. lA, Feedwater Va 1 ye Sheet
Checkoff.
Feedwater and Condensate system valve positions from the
most recent Unit 2 valve lineup were found to be consistent with
as-bui 1t drawings 11548-FM-68A, Rev. 21 (Feedwater system) and
11548-FM-67A,
Rev. 21 (Condensate system).
In addition, the
inspector noted that drawing 11548-FM-67A, Rev.* 21 re.fleeted a recent
modification to the condensate system (per Design Change 85-26) by
the incorporation of Valves 2-CN-540 and 2-CN-541.
The. inspector performed a wa 1 kdown of the Unit 2 Feedwater and
Condensate system~ to check for proper labeling of v~lves, proper
8
valve positioning, and the general. condition of valves and pumps.
The following valves were verified to be in the correct position in
accordance with the specific valve lineups:
MOV-FW-250A
2-FW-106
2-FW-88
2-CN-142
2-FW-110
2-FW-105
HCV-FW-255C
2-CN-138
2-FW-111
2-FW-104
2-CN-540
2-FW-107
2-FW-103
2-CN-541
The inspector found the housekeeping and general condition of the
Fe*edwater and condensate systems to be adequate.
c.
Operational Controls
The inspector held discussions with operations group management,
contra 1 room supervisors and operators to assess the . 1 i censee I s
methods used to provide operational control of BOP components and
equipment.* The administrative controls used for documenting and
working safety related systems equipment problems such as maintenance
requests, equipment tagout, and design change authorization are the
same as .those for BOP equipment. * In addition to these routine
controls, it is essential that the BOP equipment and ~ystems b~ known
to the contra l room personne 1.
The licensee has a program which
requires the control room operators to maintain BOP equipment checklist
forms which provide ready access to the conditions of these systems.
Entries made to the BOP equipment checklist to provide system status
inc 1 ude abnorma 1 1 i neups, degraded conditions, major components
. tagged aod identified problem areas.
Each shift reviews system
status and signs off on identified items when corrected in order to
maintain the system status current and meaningful.
The inspectors
reviewed items listed on the BOP equipment status checklist and found
the status to be current and identified problems being pursued for
corrective action. . The fo 11 owing BOP contra 1 room copy of operating
procedures were reviewed to verify *that they are consistent with the
as-built drawing, reflect vendor manual recommendations, are-control
copies, current and approved for use.
0
0
0
0
0
0
0
0
l-OP-1.3
1-0P-2.1.2
1-0P-30.0
1-0P-30.1
1-0P-31.1.1
1-0P-31.1. 2
Unit Startup Operations 350/450 psig to* Hot
Shutdown
Increasing Power from 2% to 100%
Placing the Main Condensate System in Service
Removing Main Condensate System From Service
Placing the Main Feedwater System in Service
Placing the Steam Generators in Wet Layup
Loss of Main. Feedwater Flow
Annunciator Acknowledge Procedure:
IF-64, Steam Generator 18 High~Level
IF-67, Steam Generator lC Lo Lo level
d.
9
In addition to thes~ procedures, the inspector noted that in BOP
systems, detailed maintenance operating procedures are used to remove
and restore to service major components such as condensate pumps,
main feedwater pumps, instrument air system compressor.
In addition,
valves and electrical breaker alignment, along with tagout
requirements, are specified in these maintenance procedures.
Operating Experience and Information
The inspectors held discussions with control room supervisors,
operator~, and training supervisors and instructors to dete~~ine the
handling of BOP operating activities and LER related events with
regard to the attention being given to disseminate this information
to plant operators.
The licensee has established procedures
(Administrative Procedure LR-03, Operating Experience Reviews) for
processing operating experience from- several sources such as plant
LERs, NRC notices, bulletins, INPO operating experiences, and North
Anna LERs:
This material is reviewed by the plant training
organization for reviews and inclusions into the licensee's operator
requalification program, system and development training for
non-1 i censed operators.
The inspector examined several 1 es son p 1 ans
for BOP systems and noted the incorporation of the above materials.
In addition to these requirements, the licensee required reading
files for the on-shift operating personnel were examined and noted to.
contain similar material for review.
The licensee has established
procedures requiring post reactor trip review and the dissemination
of this information to the operating staff.
The inspector concluded that the licensee has an adequate program to
ensure event related information is provided to the operating staff.
8.
Maintenance
-
.
The inspectors reviewed procedures and maintenance histories, and
conducted interviews with key plant personnel to assess the licensee's
preventive, corrective, and predictive maintenance programs as they (the
programs) relate to the BOP systems.
a.
The inspectors reviewed the below listed-procedures to assess the
programmatic coverage analyzing, defining, planning, scheduling, *
tracking and implementing co~rective actions for BOP systems.
SUADM-M-02 of
April 30, 1985
SUADM-M-03 of
October 4, 1984
- SUADM-M-09 of
March 11, 1986
"Station Housekeeping"
11Cleanness Control of Plant Systems and
Components"
"Secondary Repair/Replacement Program"
SUADM-M-27 of
. October 8, 1987
SUADM-M-16 of
October 6, 1987
SUADM-M-10 of
August 2, 1984
SUADM-M-11 of
October24, 1985
SUADM-M-12 of
February 19, 1985
SUADM-M-33 of
October 28, 1986
SUADM-M-42 of
August 25, 1987
SUADM-TR-01
SUADM-SP-02
10
"Requests for Repair or Replacement
Follower"
110peration of the Maintenance Department"
"Work Planning and Tracking System"
"Work Request Systems"
"Work Order Planning"
11Secondary Piping Inspection"
"Lubrication Test Program"
"Qualification and Training"
"Quality Maintenance Team (QMT)"
Relative to the administrative procedures defining the licensee'-s
program for the maintenance effort for BOP systems, the inspectors
noted the following:
0
0
0
The
program
is
implemented
by
"should" . statements
(recommendations) and "may" statements (permission), which makes
the program comp] ete ly subjective and dependent on personne 1
experience and judgement.
The program has many undefined initial isms and acronyms, a
potential area for confusion.
The program has many references to uni dent i fi ed superseded
procedures by number only, a potential area for confusion.
b.
The* inspectors reviewed the below listed LERs and their associated
documentation packages to assess the licensee's practices in
programmatic areas that were found to be contributing. factors to
events or component * failures.
Specific areas examined included
whether:
equipment failures. were evaluated for input to the
preventative maintenance program and possible design modification;
maintenance planning has taken into account the possible safety
consequences of concurrent or sequent i a 1 maintenance or testing
activities; procedural steps that must be accomplished correttly in
proper order to avoid malfunction or failure are highlighted to
maintenance personnel; the preventative maintenance program is
11
adequate for ensuring system/component r*eliability; approved
procedures were employed where the activity exceeded the normal
skills possessed by qualified maintenance personnel; replacement
parts and materials were determined and documented to.be of at least
the same quality as the original parts; post maintenance testing
and/or inspection was specified, correct and complete; measuring and
test equipment used was in calibration; maintenance personnel were
appropriately trained and qualified; and inservice inspection/test
activities were periodically performed as appropriate to ensure their
continu~d availability.
1-86-001
Rx trip on SF/FF Mismatch with Low SIG Level Due to MFRV's
Shutting Due to .Loss of IA Pressure Due to Ice Formation in
the IA Dryer Due to Improper Hot Gas Bypass Valve
Adjustment in the Dryer
1-86-010
Rx Trip on Turbine Trip on High S/G Level Due To Difficulty
Controlling 1C1 MFRV Due to Feedback Cam on Valve Operator
Not Adjusted Following Maintenance
2-86-003
Rx Trip On .Turbine Trip on High
1B' SIG Level Due to MFRV
Bypass Valve Failing to* Close Due To Blockage of.Air Pilot
Relay
2-86-007 Manual Rx Trip on High 'A' SIG Level Due to Failure of MFRV
to Seat Due to Metal Debris Between Plug and Seat
2-86-020
Rx Trip Due to Low Level in 1C1 S/G Due to Shrink Caused by
1 C
11
MSTV Shutting Due to Improper Reassembly Fo 11 owing
Maintenance.
Suction Piping to
1A1 MFWP Ruptured Approx.
40 Seconds After Rx Trip.
2-87-003
Rx Trip on Turbine Anti.:.Motoring Trip* Due to Governor
Valve Leakage
With regard to the above, the inspectors noted the following:
0
Of the six LE Rs examined and eight total LE Rs that reported
reactor trips resulting from BOP component degradation or
failure during the period January 1986 - December 1987, four
LERs were attributed by the 1 i censee to 1 ack of maintenance or
improper maintenance (improper valve adjustment, valve operator
not adjusted following maintenance, valve failing to open due to
blockage, testing before use was needed, and improper valve
reassembly after maintenance).
In all of the above cases, the
licensee determined that the existing maintenance procedures or
testing procedures (that *would initiate maintenance) were
inadequate.
Those procedures were all appropriately revised to
i 11 umi nate the i dent i fi ed inadequacies.
LER No. 2-87-003 was
not considered above because the determination of root cause and
actions to prevent recurrence for LER 2-87-003 as stated by the
r ..
0
12
licensee would require disassembly and inspection at
11the next
outage of sufficient duration
11 (most probably the next refueling
outage}. . It should be noted that of the six LE Rs examined in
this area and the eight total LERs (1-86 to 12-87) that reported
reactor trips caused by BOP component degradation or failure,
all four LERs attributed to inadequate procedures were 1986
events; none in 1987.
LER No. 2-86-007 reported that the Main Feedwater Regulating
Valve (MFRV) failed- to close due to metal dehris between the
p 1 ug and the seat.
The 1 i censee indicated that, based on
rememberances of personnel i nvo 1 ved, the debris was a nut.
However, the licensee indicated that they were unable to show
that any review was made to determine the fa 11 owing:
The source of the nut.
If the nut came from within the system~ whether there were
any other nuts or other parts free or potentially free in
the system that could cause a recurrence of this failure or
- a failure of the component missing the nuts or other parts.
c.
In early 1986, the license established a maintenance engineering
organization with the_ responsibility for providing engineering
support for the electrical and mechanical maintenance programs.
Within the maintenance. engin_eering organization, the Predictive
Analysis Group was established, early in 1987, with primary attention
being focused on equipment vibration; lube oil monitoring and
analysis and trending of the vibration and oil analysis data.
These
areas were examined.
Section 5.1 of ADM21-04,
11 Policies and
Procedures -
Maintenance Programs
11 , provides the admi ni strati ve
controls for the program.
The vibration spectrum analysis and oil analysis monitoring programs
currently monitor 118 pieces of plant equipment, of which
approximately 50% are within the scope of BOP.
Lube oil samples and
vibration data is collected monthly from each piece of equipment in.
the program.
The* lube oll samples are sent to a contractor, *
Precision Mechanical Analysis of Brandon, Florida, for analysis.
The
tesults of the oil analysis is electronically transmitted to the site
to assure timely data return.
The vibration data is collected by the
licensee with audio recording tape and analyzed on site by computer.
The data can be viewed as a high resolution signal analyzer in
spectrum form or on a CRT monitor in numeri ca 1 value form.
The data
from both the lube oil and vibration spectrum monitoring is trended.
Case histories were reviewed- for equipment that was repaired based *
upon program recommendations prior to failure, avoiding an unexpected
plant outage.
The Predictive Maintenance Program has the elements in it required
fo*r plant availability improvement.
The s~vings from _the program
13
have already justified its cost.
In the long run, the effect should
be to . reduce cha 11 enges to the reactor system caused by preventab 1 e
equipment failures.
9.
Management Support and Quality Assurance
Management support provided to BOP systems and their operations was
inspected using the guidelines and attributes of TI 2515/83.
It was observed that there was extensive management i nvo 1 vement in
responding to BOP problems most evident when those problems affected the
safe, reliable operation of the reactor plant.
The significance of any
pro_b 1 em is determined by its affect upon the opera ti on of the p 1 ant and
not whether it is part of a safety-related or BOP system.
Consequently,
many of the responses to identified problems are applicable to all areas
of the power plant.
Examples of such responsiveness, which are not just
limited to safety-related systems are establishment of the Quality
Maintenance Team concept, the Human Performance Evaluation System, the
corporate. health ~are p~ogram, and the procedure upgrade program.
The
responsiveness, however, is limited to the extent that management is aware
of current pr.ob 1 ems or conditions based on trending reports.
This wi 11 be
evaluated later in the discussion of management involvement.
Responsiveness
has been found to also be prioritized for specific areas of concern.
For
example, a large *effort was expended in solving the feedwater regulating
valve operation problems during startups/shutdowns by. improving such areas
as training, testing; operational control, and maintenance; yet a BOP area
(feedwater heater) where 1/1 logic exists, has not.yet been modified.
Instead of a modification, *controls are being used, such as signs and
procedures, to prevent recurrence.
No recurrence has occurred s i nee the
original trip.
It was also observed that although a prob.lem with the
instrument air system was i dent ifi ed by the 1 i censee, no permanent
corrective action was taken until after an event occurred.
This item is
addressed more completely in paragraph 6.
Success in reducing the number of plant trips is also used as an indicator
of management support.
Reactor trips at Surry have steadily decreased
from 22 in 1984 to five in 1987.
Of these, 11 were BOP re 1 ated in 1984,
and two in 1987.
Neither of the two BOP trips in 1987 were feedwater
related; nor were they recurrences of previous trips.
The amount of resources being allocated towards BOP was also* reviewed.
From a funding perspective, a considerable portion of ~roposed budgets fof
1987, 1988, and 1989 are being allocated to BOP systems, especially when
compared to the r~latively low number of BOP related trips. Within tbe
five. year pl an, 42% of the 1987 budget was a 11 ocated; in 1988 it is 21%
and in 1989, it is 25%.
From the human resources perspective, it is
observed that there is no dedicated organization for addressing BOP, and
therefore, difficult to access.
The dedicated II system engi neer~1 concept
has not been used at Surry, as elsewhere; however, due to the size of the
station s~aff, it may not be desirable,
~----------
-
~~~
14
The licensee has been found to be participating in and utilizing different
industry initiatives in reduction of the number of BOP related trips.
The
two most notable are the Nuclear Performance Reporting Data System
(NPRDS), and the Westinghouse Owners Group (WOG) Trip Reduction Committee.
The licensee provides input into the NPRDS and also generates its 6wn
reports for use by maintenance and planning.
The chairman of the WOG
trip reduction committee is from Virginia Power..
As mentioned .earlier, upper management involvement in addressing ~OP
problems is very extensive. Other than in areas of responsiveness, there
is upper management participation in plant startups and shutdowns, daily
production meetings,, ahd post trip reviews, for BOP matters as well as
safety related.
Management has app 1 i ed the requi.rements for qua 1 i ty and
safety throughout the plant and, other than for regulating requirements,
basically operates the plant without differentiation between BOP and
safety-related systems.
However, a couple of specific areas where
differences do exist were found.
The degree of detail within maintenance
procedures, deviation reporting and deviation trending is much less thah
required for safety related.
Since there is such intensive personal
m~nagement involvement, and the staff appears to work so closely together,
the 1 i censee be 1 i eves the organization can satisfactorily address any
problem that is discovered:
However, since no formalized program exists
for both documenting and determining ~oot cause* on a centralized basis,
the lack of continuity, source of readily available information, and of
consistency may not give management the best information available to
properly respond to ongoing problems.
This can be of value not only f6r
addressing BOP component failures and related events, but also for safety
re 1 ated components and events.
- .
The management po 1 i ci es and attitudes were found to be understood and
generally implemented at both the worker and first line supervisor levels.
Interviews of plant personnel indicate that an emphas*is on quality of work
is present throughout the station, and that station personne 1 are
responding positively. It was also observed that personnel understand the
importance of finding current root causes of inplant failure an"Cl are
taking the proper steps to prevent recurrence once a root cause has been
properly identified.
In conclusion, it appears that both manag~ment and
the craft share t_he idea of improving quality, determining causes of
problems and preventing recurrences, to keep the plant operating as safely
and reliably_as possible.
Within the Quality Assurance area, no formal program was .found.
specifically for BOP systems.
However, a Quality Assurance review is
required for all procedures, including BOP, prior to procedures
per.formance.
Quality Assurance also reviews all completed work packages.
The emphasis is definitely placed on.safety-related work vice BOP, yet BOP
is not totally ignored.
If there are BOP aspects in an area of a
general periodic audit, these BOP items,are reviewed as we11.
An example
r
15
would be the periodic audit of Mechanical Maintenance and Welding.
A
heavy reliance, however, is placed upon the station personnel and other
programs at the site, such as the Quality Maintenance .Team, to produce
quality work.
10.
Licensee Actions on Previously Identified Inspection Findings (92701)
(Closed) IFI 280, 281/86-40-01, Revise Procedure 112-PT-10 to incorporate
all required parameters.
The subject procedure was revised on October 8, 1987 for Unit 1, and
October 26, 1987 for Unit 2.
The inspector verified that all parameters
have been incorporated into the procedure.
These items are closed.
11.
List of Abbreviations
LER
MFWP
MSTV
QMT
RX
SF/FF
SIG
TI
Balance of Plant
Cathode Ray Tube
Design Change Package
Engineering Work Request
Instrument Air
Institute of Nuclear Power Operations
License Event Report -
Main Feedwater Regulating Valve
Main Feedwater Pump
Main Steam Tri~ Valve
Nuclear Performance Rating Data System
Quality Assurance
Quality Control
Quality Maintenance Team
Reactor
Steam Flow/Feed Flow
-Temporary Instruction
Westinghouse Owners Group