ML18153B281
| ML18153B281 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 07/30/1993 |
| From: | Belisle G, Branch M, Tingen S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18153B280 | List: |
| References | |
| 50-280-93-15, 50-281-93-15, NUDOCS 9308100037 | |
| Download: ML18153B281 (21) | |
See also: IR 05000280/1993015
Text
Report Nos. :
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
- ATLANTA, GEORGIA 30323-0199
50-280/93-15 and 50-281/93-15
Licensee: Virginia Electric and Power Company
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
License Nos.:
DPR~32 and DPR-37
Facility Name:
Surry 1 and 2
In~pection Conducted:* June 6 through July 3, 1993
Inspectors:
Approved by:
Scope:
. W. ~ibrResident
Inspect r
a.-~&
_S. G~ Ting~ e dent Inspector
G. ~c..:;:chief
Division of Reactor Projects
SUMMARY
7/w.3
Da't~gned
This routine resident inspection was conducted on site in the areas of plant
status, operational safety verification, maintenance inspections, safety
assessment and quality verification, Technical Specification review program,
Updated Final Safety Analysis Report improvement program, Level I project
tracking, and licensee event review. During the performance of this
inspection, the resident inspectors conducted reviews of the licensee's
backshifts, holiday or weekend operations on June 20 and 25.
Results:
In the operations area, the following items were noted:
URI 50-280,281/93-15-0l, Use of probalistic risk assessment (PRA) for
Unreviewed Safety Question Determination, pending further review by the
NRC (paragraph 3.c).
9308100037 930730
ADOCK 05000280
G
PDR~
2
Failure.to test the low pressure carbon dioxide fire protection system
per Technical Specification 4.18.D.l.b.2 was identified as part 1 to
Non-Cited Violation 50-280,281/93-15-04 (paragraph 9). Failure to
establish a continuous fire watch in accordance with Technical
Specification 3.21.B.4 was identified as part 2 to Non-Cited Violation
50-280,281/93-15-04 (paragraph 9).
In the maintenance/surveillance functional area, the following items were
noted:
Non-Cited Violation 50-281/93-15-02, was identified- for failure to
perform minor maintenance in accordance with VPAP-2002 (paragraph 4.a).
Non-Cited Violation 50-280,281/93-15-03 was identified for failure of
personnel to sequence tie-in cleanliness and fit.up/tack inspections in
accordance with VPAP~0903 (paragraph 4.b).
In the safety assessment/quality verification area, the following items were
noted:
The licensee's multi-tiered self-assessment programs collectively
incorporate various levels of corporate and station management in
ensuring safe operation. These programs are effective in contributing
to problem prevention by monitoring and evaluating plant performance and
following up with corrective action recommendations (paragraph 5).
The Corporate Nuclear Safety Independent Review Group provided effective
safety evaluaiton independent review (paragraph 5.d)!
The Integrated Trend Report identified recurring problems through
adverse trends, provided various problem/event in-depth reviews and
provided valid recommendations for corrective action (paragraph* 5.d).
The Station Nuclear Safety Operating Committee was effective in
evaluating proper substitution of manual operating action for automatic
actions and consequently ensuring that corrective actions prevented
recurrence of specific problems (paragraph 5.g).
Station Nuclear Safety's station deviation*and trending review have
improved identifying and correcting recurring problems (paragraph 5.h).
Although the Updated Final Safety Analysis Report improvement program is
progressing, a date has not be determined for completing the program
- (paragraph 7).
The Level I Corporate and Station Project Tracking programs demonstrated
management's involvement in activities critical to station performance*
and also provided an additional method for ensuring that adequate
corrective actions are implemented (paragraph 8).
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- J. Artigas, Supervisor Quality Assurance
- R. Bilyeu, Licensing Engineer
R. Blount, Superintendent of Engineering
- D. Christian, Assistant Station Manager
- J. Costello, Station Coordinator, Emergency Preparedness
- D. Erickson, Superintendent of Radiation Protection
R. Gwaltney, Superintendent of Maintenance
- R. Gardner, Outage and Planning Department
- H. Hay, Supervisor, Quality Assur~nce
- R. Hayes, Supervisor, Corporate Quality Assurance
- M. Kansler, Station Manager
- A. Keagy, Supervisor, Nuclear Materials
- C. Luffman, Superintendent, Security
- R. MacManus, Acting Superintendent, Engineering
- J. McCarthy, Superintendent of Operations
- A. Price, Assistant Station Manager
- R. Saunders, Assistant Vice President, Operations
- E. Smith, Site Quality Assurance Manager
- D. Sommers, Supervisor, Corporate Licensing
- J. Swientoniewski, Supervisor, Station Nuclear Safety
NRC Personnel
- M. Branch, Senior Resident Inspector
- S. Tingen, Resident Inspector
- Attended Exit Interview
Other licensee employees contacted included control room operators,
shift technical advisors, shift supervisors and other plant personnel.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2.
Plant Status
Unit 1 began the reporting period in power operation. The Unit was at
power at the end of the inspection period, day 143 of continuous
operations.
Unit 2 began the reporting period in power operation.
On June 20, the
unit tripped during a manual turbine runback from 100% power that was
initiated due to the A MFWP failure. This transient is discussed in
detail in section 3.b. The unit was restarted the same day and since
only one MFWP was available, the unit operated at reduced power
(i.e., 65%} for the remainder of the inspection period.
2
3.
Operational Safety Verification (71707, 42700}
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 operations *safety and
compliance with TSs and to maintain awareness of the overall operation
of the facility.
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.
Deviation reports were reviewed to assure that potential
safety concerns were properly addressed and reported.
a.
June 20, Unit 2 Reactor Trip on Loss of the A MFWP
At 4:14 a.m., on June 20, Unit 2 tripped during a manual turbine
runback initiated from 100% power as required by procedures when
the A MFWP tripped. The MFWP tripped when one of the 2 electric
driving motors shorted to ground causing the feeder breaker to
trip. The reactor tripped on feed/steam flow mismatch consistent
with a low SG level initiated from the A SG channels. A
combination of steam dump actuation, SG shrink and swell from
pressure swings, the loss of the MFWP, and the cold AFW injection
caused the SG level instability. The licensee notified the NRC as,
required on this event.
The inspectors monitored the licensee's recovery actions
subsequent to the trip and performed an independent review of
plant transient and recorder charts. Based on this review, the
inspectors determined that the plant responded as expected and
that the ECCS and reactor protective systems actuated as designed.
There were some plant equipment problems that required
investigation and repairs ~ri-0r to unit restart. The equipment
problems and licensee's corrective actions included the following:
The !RPI for rod M-10 indicated approximately 25 steps off
of the bottom and the rod bottom light was not lit after the
reactor trip. Approximately 40 minutes later after the RCS
temperature stabilized the rod bottom light illuminated and
the !RPI indication drifted toward 0.
DR S-93-0799 was
submitted and the licensee's research indicated that the
!RPI for this rod had previously experienced sluggishness
and this condition had been evaluated by engineering.
The
licensee performed a calibration of this IRPI prior to unit
restart. All rods fully inserted into the core on the
The B RCP high/low oil alarm annunciated.
DR S-93-0804 was
submitted and was resolved by draining a small amount of oil
from the reservoir.
b *
3
Following the reactor trip the intermediate range Nls
decreased off-scale low.
DR S-93-0798 was submitted and the
detectors were calibrated.
Several additional BOP equipment problems were experienced
during the transient and they were evaluated and resolved
prior to unit restart.
The inspectors attended the MRB and SNSOC post trip*review prior
to unit restart. The inspectors also attended the operating crew
debriefing after the trip and prior to their leaving the site.
The licensee's post trip process appeared to be effective in
evaluating and resolving important plant equipment issues prior to
unit restart.
The unit was restarted at 6:47 p.m., on June 20 and was back
on-line at 10:33 p.m., that same day.
The unit operated at
reduced power (approximately 65%) for the remainder of the
inspection period.
Plants Readiness to Cope With Adverse Weather Conditions
The inspectors reviewed the licensee's procedures and programs to
cope with adverse weather conditions if they should arise. The
inspection considered the design basis of equipment and structures
that would be exposed to wind forces from either a tornado or a
hurricane to include emergency response and event assessment
equipment.
The inspectors held meetings with both site and
corporate personnel knowledgeable in wind loading design.
The
inspectors used Surry drawing 11448-FY-lD Revision 17, Plot Plan
Surry Power Station, as the basis for discussing the wind loading
design for the major structures and equipment.
Equipment and structure design is described in sections 2.2.2 and
15.2 of the UFSAR.
Table 15.2-1 list structures and equipment and
their design basis. A tornado wind speed of approximately 300 mph
and a hurricane wind speed of 137 mph were assumed in the UFSAR
analysis. However, the design wind loading basis for all
equipment and structures located at the plant are not described.
New buildings such as the administration building and the new
radwaste facility are also not included.
From the UFSAR review and discussions noted above, the inspectors
determined that many structures and equipment exposed to the
maximum winds from a hurricane or tornado could be damaged and may
not survive.
For example, non-safety related structures and
equipment are generally designed to the BOCA code, which for the
location and function of Surry as a power station would be
designed to withstand a wind force of approximately 100 mph .
4
Examples of BOCA designed structures and equipment include but are
not limited to the following:
New Security and Administrative Building
CAS/SAS
New Radwaste Building
Switchyard and Transformers
Fire Tanks
Above Ground EDG Fuel Oil Tank
Meteorological Towers and Emergency Sirens
Environmental Monitoring Stations
In addition to the above, the roofs and siding of several other
buildings are also only designed for BOCA code winds.
For
example, the Auxiliary Building roof and some above ground siding
are designed for 100 mph winds.
There is also semi-permanent installed equipment such as hydrogen
tanks, water processing trailers and Sea-Vans that may not survive
design basis wind forces.
In addition, loose low level rad waste
is stored in a metal storage shed within the protected area. This
shed is designed for BOCA code winds.
The inspectors also reviewed abnormal operating instruction
ADI O-AP-37.01 revision 1, Abnormal Environmental Conditions,
which provides guidance for operations to ensure safe plant
conditions in the event of impending adverse weather conditions.
This procedure established the licensee's philosophy for unit
conditions based on weather forecast, time before land fall,
emergency plan implementation, and management's heightened
awareness or degrading conditions. The licensee's emergency
declaration is described in EPIP-1.01 Attachment 1, Emergency
Action Level Table (TAB L) Natural Events.
The inspectors also held meetings with the corporate EP manager
and an OER person to discuss the status of the licensee's review
of lessons learned from Hurricane Andrew and any corrective
actions being implemented.
The licensee's lesson learned review
is being conducted through their normal OER process.
The licensee
indicated that the OER report will be finalized and issued to
management in the mid-summer timeframe.
The inspectors also
reviewed an informal checklist that contained, in bullet form,
many significant "What-To-Dos" but there was little or no "How-To-
Dos".
The licensee indicated that the checklist could be used if
needed in the event of adverse weather.
The inspectors concluded
that although the licensee's program has not been completely
formalized, the modifications that have been made represent
improvement over their previous program.
c.
5
Feedwater Isolation System Review
During a station deviation review, the inspectors became aware of
DR S-93-0774 which described a possible unreviewed safety question
associated with isolating the feedwater system.
isolation is needed to protect against the consequences of a steam
line failure that could cause a pressurization of the containment
or a RCS cooldown with a loss of reactor shutdown margin.
The feedwater isolation function. is described in the UFSAR,
section 14.3.2. A detailed description is not provided but the
system consists of a safety related protective system that is
actuated by an SI signal which causes automatic closure of all
three pairs of air operated FWRVs and bypass FWRVs and the
tripping of the MFWPs.
Additionally, the tripping of the MFWPs
through non-safety related breakers causes the non-safety related
discharge valves (1 or 2-FW-MOV-150 or 250A&8) which are powered
from non-safety electrical busses to close.
In the past, Surry has disabled (jacked) a FWRV in the open
position to a specific SG; therefore, it would not automatically
close on -an SI signal. The licensee performed SEs (i-.e.,
10 CFR 50.59) reviews for this evolution since 1989. Recent SEs
determined that jacking the valve open to perform maintenance on
the control or feedback circuitry was an acceptable practice as
long as the redundant tripping of the MFWPs was operable and
compensatory actions were in place to close another non-safety
feedwater isolation MOV (1 or 2-FW-MOV-154 or 254A, 8, C) just up
stream of the FWRV, from the control room if necessary.
DR S-93-0774 was issued because of the licensee's independent
review group's assessment of the SE 92-173, dated September 24,
1992, which addressed placing a FWRV on its jack. The package
reviewed included administrative control form (AC S2-92-807) and
TS interpretation (TSI-014), including safety evaluation
(SE 92-1738):
The independent review group's report to the
station, attached to the DR, indicated that for certain postulated
cases, termination of feedwater flow during a steam line break
accident may not be achievable with current compensatory actions
and within the time frame assumed in the steam break accident
analysis. The following information was taken from that report:
isolation will occur within 30 seconds through closure of the
For a total LOOSP, the MFWP and
condensate pumps will shutdown due to a loss of electrical power
thereby terminating feedwater within the required time.
However,
the SE did not address the impact of a partial loss of station
service electric power. A potential scenario is that a loss of a
4160V station service bus with one FWRV jacked open could result
in continuous feedwater flow to the SG that has experienced a
MSL8.
The combination of a feedwater isolation MOV and MFWP
6
discharge MOV loosing power, MFWPs tripped on the SI signal, and
the condensate pump continuing to run (from the unaffected station
service busses), results in continued feedwater flow.
This
scenario assumes a MSLB upstream of the MSTVs and the single
failure being a loss of a 4J60V station service bus.
flow would continue until the operators locally closes the
feedwater isolation MOV or trips the condensate pump.
The time
required to perform these compensatory actions would be greater
than the 30 seconds assumed in the safety analysis.
After being informed of the above potential unreviewed safety
question item, the plant initiated actions to~evaluate the
condition and determine reportability. The station's review
resulted in generating another SE.(93-14i) and a TS interpretation
that allows plant operations to continue with an administrated
8-.hour AOT for an inoperable FWRV (i.e., jacked open).
The new SE
was based on reliability and probability considerations which the
licensee considered acceptable by NSAC-125, Guidelines for
10 CFR 50.59 Safety Evaluations.
The licensee also considered
that manual operator action to trip the FWRV off the jack and
allow it to close within the 30 second time limit would be
achievable and acceptable.
The inspectors questioned the use of probability assessment in
making the decision that the modification (i.e., loss of automatic
isolation of main feedwater) does not constitute an unreviewed
safety question.
It is clear that the inability to automatically
terminate feedwater flow was not considered in the safety ~nalysis
describ~d in the UFSAR.
Therefore, the probability of occurrence
or consequences of an accident or.malfunction of equipment
important to safety previously evaluated in the safety analysis
report may be increased.
The licensee's calculation (S-896)
reviewed by the inspectors indicated that the combined increase in*
probability for the event described was insignificant if an AOT Of
8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is used.
The licensee, therefore, considered it
acceptable to operate with the FWRV on the jack if an AOT did not
result in an increase in probability of occurrence.
The licensee's recent SE (93-142) also indicated that the
operators could close the jacked open FWRV within the 30 seconds
needed to terminate feedwater flow-for the steam break accident.
However, the SE contained statements that the basis was limited
risk associated with operating on the jack and not dependent on
strict operator performance to close the FWRV within the 30
seconds assumed.
If it could be demonstrated that manual action
was addressed by a procedure and could be reliably performed
within the values bounded by the accident analysis, it appears
that the guidance of GL 91-18 could apply for future occasions~
The inspectors held discussions with NRC staff and were informed
that the use of NSAC-125 has not been endorsed by the NRC.
Therefore, the use of a probability assessment is in question.
4.
7
This item is identified as URI 50-280, 281/93-15-01, Use of PRA
for Unreviewed Safety Question Determination, pending further
review by the NRC.
d.
Housekeeping
In an effort to upgrade station housekeeping, the Assistant
Station Manager is walking down areas of the station with the
supervisors responsible for housekeeping in the area.
On June 9,
the inspectors accompanied the Assistant Station Manager and l&C
Supervisor on a housekeeping tour of the auxiliary building 45
foot level. _During this tour, general materi-al condition and
cleanliness were monitored and out of the way places such as under
. and behind equipment were inspected.
Examples of items noted
during the tour were red tape on cable tray covers, coat hanger
wire dangling from conduit, damaged label plates, loose junction
box covers, and loose fasteners on ventilation equipment.
The
inspectors noted that during the inspection period, the Vice
President of Nuclear Operations conducted a similar walkdown of
the auxiliary building basement.
The inspectors concluded that
housekeeping has improved and management walkdowns have
contributed to the improvement .
Within the area inspected, one URI was identified.
Maintenance Inspections (62703) (42700)
During the reporting period, the inspectors reviewed the following
maintenance activities to assure compliance with the appropriate
procedures.
a.
Leak Repair at Mechanical Joint
On June 14, the inspectors witnessed the licensee repa1r1ng
a leaking mechanical joint in the piping/tubing to charging pump
2-CH-P-lB suction pressure gage 2-CH-399.
The mechanical joint
was disassembled, inspected and reassembled. This maintenance was
considered minor maintenance and accomplished in accordance with
deficiency card IC-93-0175.
The maintenance was isolated
utilizing operator standby and the joint was leak tested when
placed back into service.
The inspectors reviewed Attachment 13
of VPAP-2002, Work Request and Work Order Tasks, dated
January 1, 1993.
The attachment describes criteria for
determining which tasks are considered minor maintenance and can
be performed with deficiency cards. Maintenance accomplished per
deficiency cards is generally simple in nature and does not
require a WO or written instructions.
Item (d) of Attachment 13
states that minor maintenance shall not effect the integrity of
safety related components and disassembly of a safety-related
component is not a minor maintenance activity. The inspectors
concluded that disassembling the mechanical joint in the
b.
8
piping/tubing to pressure gage 2-CH-399, a safety related system,
per a deficiency card IC-93-0175 was not in accordance with
Item {d) of Attachment 13. This was ide~tified as
NCV 50-281/93-15-02~ Failure to Perform Minor Maintenance in
Accordance With Administrative Procedure VPAP-2002.
This NRC
identified violation is not being cited because criteria specified
in Section VII.B of the NRC Enforcement Policy were satisfied.
As
corrective action, a change to VPAP-2002 was initiated to allow
disassembly of components in safety related systems in some
instances.
Welding a Service Radiation Monitor
The inspectors reviewed part of a modification for the Unit 2
radiation monitor for the RS heat exchanger SW cooling lines.
This radiation monito'r's function is to detect any tube leak in
the RS heat exchanger. The review was conducted on the
documentation for welding on the line going to the C radiation
monitor, mark numb'er 2-SW-P-5C.
There are approximately 16 welds
in this piping section.
During the inspector's welding and inspection documentation
review, the licensee stated that a contractor employee had
questioned whether a hold point was being bypassed when the tie-in
cleanliness inspection and the fit up/tack inspections were both
performed at the same time.
The licensee concluded that this was
an acceptable practice. The inspectors performed an independent
assessment of this conclusion.
The inspectors reviewed the weld data sheet and the appropriate_
procedures that were associated with welding and QC hold points.
A typical data sheet review shows that the first QC hold point is
the tie-in cleanliness and the second QC hold point is the one for
fit up/tack.
The inspectors reviewed administrative procedure
VPAP-0504, Technical Procedure Writers Guide, revision 1.
In the
definition part of this procedure {paragraph 4.5), a required QC
hold point is defined as a pre-selected location written in a
procedure that identifies a portion or portions-of the procedure
which requires witnessing by the QC department personnel or the
maintenance QMT personnel.
The procedure also states that work
shall not progress beyond the established hold point until the
required inspection is performed.
Attachment number 14 of this procedure gives the criteria for QC
hold points in procedures.
Paragraph 6 of this attachment gives
the required QC hold points for welding procedures pertaining to
safety-related and seismic items.
Part 6.d states in part that
cleanliness inspection of piping and piping components may be a
part of the fit up/tack inspection. This would allow the QC
inspectors to perform both of these inspections at the same time.
However, the statement that the cleanliness inspection may be a
part of the fit up/tack inspection was not part of the procedure
-*-
5.
g-
VPAP-0903, Control of Welding, revision 0, which was being used
for the weld inspection.
Administrative procedure VPAP-0903 was reviewed for a description
of the attributes to be inspected for the welding process.
_ -
Attachment 2 to that procedure states that the tie-in cleanliness
inspection is intended to insure that nothing is left in the pipe
before fit up.
The cleanliness inspection as part of the fit
up/tack inspection was not included in the procedure. Discussions
with some of the licensee's QC inspectors revealed that they
perform both inspections at the same time on occasions when no
adverse affects are possible. The decision a~ to when to perform
both of these inspections at the same time is made by the
_individual QC inspector.
The insp~ctors discussed this decision with the QC inspector that
made the decision relating to the contract employee's fit up.
The
QC inspector stated that there would be no problem inspecting the
attributes reql,lired by the cleanliness hold point since the length
of the two inch diameter pipe was two inches with an open end.
The inspectors agree that technically the inspection for
cleanliness could have b_een performed at the time of the fit
up/tack inspection, but VPAP-0903 did not have the words that
would authorize the performance of both inspections at the same
time.
The inspectors disagreed with the licensee's original
conclusion that it was acceptable to perform the tie-in
cleanliness and fit up/tack inspections simultaneously when
performi.ng these inspections in accordance with VPAP-0903.
Failure of personnel to sequence tie-in cleanliness and fit*
up/tack inspections in accordance with VPAP-0903 was identified as
NCV 50-280, 281/93-15-03. This NRC identified violation is not
being cited because criteria specified in Section VII.B of the NRC
Enforcement Policy were satisfied.
The licensee is currentiy changing VPAP-0903 to include the option*
.for performance of both the cleanliness and tie in/tack
inspections at the same time as it is authorized in the VPAP-0504.
Within the areas inspected, two NCVs were identified.
Safety Assessment and Quality Verification (40500)
The inspectors reviewed the licensee's activities associated with
safety policy implementation, station performance, safety review
committees, and feedback from self assessment programs and QA
activities. A multi-tiered program utilizing corporate and station
resources are utilized to accomplish these activities; The specific
areas reviewed were the Nuclear Business Plan, NOB, MSRC, CNS, Nuclear
Quality Assurance, MRB, SNSOC, and Station Nuclear Safety.
Some of
-these functions.are specifically required by TS and other areas are
performed in addition to TS requirements.
. I
a.
b.
c.
10
Nuclear-Business Plan
The inspectors reviewed the Virginia Power Nuclear Business Plan
. Goal Performance for May 1993.
The purpose of this report is to
assess the performance of Surry and North Anna in meeting their
established goals. The report assesses plant performance,
nuclear/industrial safety, cost management and regulatory
compliance.
Items assessed in the report were categorized as
significant strengths, satisfactory, improvement needed or
significant weakness.
Non-outage corrective maintenance back log
and EOG reliability were examples of significant strengths. *
Several areas were considered needing improvement.
was an area needing improvement.
The goal for Surry-is to have
two or less unplanned reactor trips per year and, as of May 1993,
the units have already had two reactor trips with over half a year
in the assessment period remaining.
The report did not identify
any areas as significant weaknesses.
Nuclear Oversight Board
The purpose of the NOB is to provide an independent review and
oversight role of nuclear activities at the senior managem~nt
level. The Board advises the Senior Vice President, Nuclear and
the eight members consist of senior nuclear utility executives and
consultants.
Board review and recommendation results are
presented to the Virginia Power Pre~ident and Chief Executive
Officer.
Management Safety Review Conunittee
The MSRC function and activities are specified in TSs.
The
inspectors reviewed MSRC member qualifications and MSRC meeting
minutes for 1992 and 1993.
The inspectors concluded that MSRC
committee members were well qualified and experienced and that
meeting frequencies met TS requirements.
IPE flooding and the
increase in number of precursors to *significant events in 1992
were examples of MSRC concerns.
The inspectors verified that MSRC
issues were being tracked and properly closed.
d.
Corporate Nuclear Safety
CNS is divided into three groups, independent safety, review, OER,
and independent review.
CNS also has general responsibilities
that are shared between the three groups. These responsibilities
include coordinating involvement with WOG, integrated performance
trending, root cause evaluation, and DR/COE data base.
The primary responsibilities of the CNS independent safety review
group are to review events that occur at the station which
includes identifying root causes and corrective actions, perform
assessments of various station activities, and independently
monitor station performance. The inspectors reviewed CNS event
11
reviews or assessments*associated with tagging events, contractor
events, shutdown ~anagement, and administrative controls of
. radioactive materials and radiation exposure.
The inspectors
concluded that these reports were comprehensive in that root
causes and corrective .act i ans were i dent i fi ed.
In addition, to
reviewing the actions associated with a single event, similar
types of events are also reviewed in order to identify common or
repetitive causes.
The primary responsibility of the CNS OER group is to evaluate
industry events for significance and applicability to Virginia
Power and recommend action to avoid similar o~currences.
Examples
of sources of industry events monitored by the CNS OER group are
INPO SOERs and Nuclear Network, NRC Information Notices and
Generic Letters, and Vendor 10 CFR 21 Notifications. The group
- also monitors Virginia Power LERs and NRC violations for common
applicability and recommends corrective actions.
In 1993, the
group began to monitor NRC violations issued to other utilities
.
for applicability at Virginia Power stations. During the previous
SAlP assessment period, a weakness was identified in the area of
CNS follow up on corrective action for recommendations from older
event reviews.* This issue was reviewed during this inspection
period and the inspectors concluded that this wea~ness was
corrected in that CNS verified that these corrective actions were
completed.
During a previous inspection, a weakness was
identified in that CNS closure summaries were not being completed
with the suggested 90 day program guidelines. This issue was also
reviewed during this inspection period and considered corrected in
- . that there were no l anger any overdue closure surnmari es.
The primary responsibility of the CNS independent review group is
review SNSOC activities and to manage the Virginia Power
10 CFR 50.59 SE Program which includes reviewing all SEs prepared
by the Surry site engineering group.
The group has reviewed
approximately 450 Surry SEs throughout the current SALP assessment
period.
Of the 450 SEs the group had written comments on 20 SEs,
and 5 SE's were considered inadequate.
Four of these five SEs
were considered inadequate because they did not properly address
- contaminated systems and had minor safety significance. The fifth
SE identified a potential unreviewed safety question associated
with placing a FWRV on its jack. This issue was previously
discussed in paragraph 3.c and was identified as a URI.
The
inspectors noted that SEs associated with placing FWRVs on their
jacks were reviewed on four other occasions since. 1989 prior to
the recent review and did not identify any problems. * The
inspectors questioned why the potential unreviewed safety question
was not identified on the previous reviews and were informed that
in the past reviews the most severe events and most bounding
analyses in determining the acceptability of this activity were
considered *. In this case, the most severe event considered, total
loss of off site power, did not have the most sever consequences.
The inspectors concluded that overall, the CNS independent review
-'
12
group provided effective independent review of SEs.
As a result
of the comments generated during the CNS independent review of
SEs, the station is in the process of developing a task team to
develop methods for improving SEs. _
One of the general responsibilities of CNS is to develop quarterly
Integrated Trend Reports.
The purpose of _this report is to assess
station issues and events at Surry and North Anna to determine if
adverse trends exist and identify any adverse trends to senior
management.
If adverse trends are identified the report provides
recommendations for corrective actions. The inspectors reviewed
the Integrated Trend Report dated June 1, 1993.
The report
identified areas with sustained improving trends and areas with
adverse trends.
Examples of areas of improved trends were
reactivity control, radiation releases, and overall human
performance.
Example of areas with adverse trends were radiation
monitor failures, relay failures, and work practices. The report
also identified and trended significant and precursor events.
The
report indicated that in the first quarter of 1992 the number of
significant events associated with plant transients was abnormally_
high due to two reactor trips that occurred during that period.
The inspectors verified that recommendations were tracked until
completed. The inspectors concluded that the Integrated Trend
Report identified recurring problems through adverse trends,
provided in-depth reviews of various problems/events, and provided
valid recommendations for corrective action.
e.
Nuclear Quality Assurance
TS 6.2.h specifies audits and frequencies that are required to be
routinely performed.
In 1992, 20 audits were performed and 15
audits are scheduled to be performed in 1993.
The inspectors
verified that audit open items were being tracked and pursued.
The QA audit tracking report listed four open 1991 audit items, 27
open 1992 audit items, and 11 1993 open items. The inspectors
reviewed the 1991 items and concluded that audit items corrective
actions were effectively implemented.
The QA department routinely performs assessments that are beyond
TS requirements. The purpose of these assessments are to evaluate
performance in specific areas. Approximately thirty assessments
were performed in 1992 and twenty-one assessments have been
performed or are in the process of being performed in 1993.
Assessments are performed in areas where performance problems or
need of enhancement have been identified on recently implemented
programs, on followup on previous assessement findings, or on
concerns in areas expressed by corporate or station management.
Assessment findings are reviewed with station management and are
tracked as open items until closed. The QA department also
routinely observes maintenance activities at the station.
Findings from these observations are documented and discussed with
the Superintendent of Maintenance. These observations are also
f.
g.
h.
13
utilized to trend station performance in the CNS integrated trend
report.
Station QA personnel are encouraged to visit counterparts at other
nuclear plants to compare programs and identify possible
improvements.
Corporate and North Anna personnel are utilized to
perform Surry audits. Also, Surry personnel are used to perform
North Anna audits. Assessments also utilize North Anna and
corporate personnel.
The department participates in an auditor
exchange program with other utilities, participates in a utilities
group that independently audit QA programs, and supervisors are
required to visit INPO 1 or SALP 1 rated site~ on a yearly bases.
Management Review Board
The MRB members are the Station Manager, two Assistant Station
Managers, and Station QA Manager. The overall function of the
- board is to overview and coordinate station activities. The
inspectors reviewed the 1992 and 1993 MRB meeting minutes.
Typical items reviewed at the weekly MRB meetings were temporary
modifications, JCOs, and compensatory actions. Other areas
reviewed were deferred maintenance items, RCEs, plant equipment
problems, plant events, Nuclear Safety Assessments Reports,
station assessments, and DR Trend Reports.
The MRB also
determines the ratings of the quarterly Performance Annunciator
Program windows.
The MRB has been effective in reviewing station
activities.
Station Nuclear Safety Operating Committee
TS 6.1.C.l specifies the requirements for the SNSOC composition,
meeting frequency, responsibilities, and authority. Throughout the
current SALP assessment period the inspectors have monitored SNSOC
performance.
The inspectors concluded that TS were met with
respect to SNSOC composition, duties, and meeting frequencies.
The inspectors observed SNSOC meetings and concluded that the
overall, in-depth review of areas important to safety were being
performed and that the members were qualified and experienced in
diverse disciplines. The SNSOC was especially effective in
evaluating proper substitution of manual operating action for
automatic actions and ensuring corrective actions prevented
specific problem recurrence~
Station Nuclear Safety
Tracking and trending DRs is the SNS department's responsibility.
The inspectors reviewed the results of the Station Deviation Trend
Report for the first quarter of 1993. This report trended the
failure mode/mechanism associated with DRs processed from January
through March 1993.
SNS issues a DR trend reports quarterly. The
four major trend categories were human performance, system
14
performance, component performance and specific equipment
performance.
The DR trend report identified five recommendations
based on the trend results. For example, one recommendation was
associated with recurring spiking problems on the ventilation
system Kamen radiation monitors. This recommendation included
corrective action. Recommendations are assigned CTS numbers that
are tracked until closure.
SNS also reviews DRs daily for recurring problems, and if the DR
is associated with a recurring problem it is discussed during the
morning supervisor meeting.
During the previous SALP assessment
period, examples were identified where the licensee indicated a
willingness to live with several recurring problems.
The SNS's
review of DRs and DR trending has improved identifying and
correcting recurring problems.
During this SALP assessement
period, recurring problems have been identified, components
declared inoperable if applicable, and corrective action
initiated. However, in some cases such as control room chillers
and station radiation monitors, corrective actions are long term
and problems will continue to occur until these long term
corrective actions are fully implemented.
Preparing the quarterly Nuclear Safety Assessement Report is
another responsibility of the SNS department.
The inspectors
reviewed the Surry Nuclear Safety- Assessment Report for the first
quarter of 1993.
The report assesses plant performance in the
following areas: past and current performance in key safety areas,
events that challenge the operator and the plant, significant
events and precursors, RCS and SG integrity, and material
condition.
Key INPO performance indicators are utilized to
compare the performance of Surry performance to the industry. The
report indicated that the state of nuclear safety in Unit 1 was
considered degraded when compared to previous reports.
Two
reactor trips, safety injections, and forced power reductions
contributed to the degraded performance.
The state of nuclear
safety in Unit 2 was considered high for the period. Three events
that occurred in the first quarter of 1993 were considered
reductions in the margin of safety.
Two events were associated
with turbine driven AFW pumps tripping due to degraded steam traps
which was previously discussed in NRC Inspection Report Nos.
50-280, 281/93-07.
The third event was associated with two main
control room chillers being inoperable which was discussed in LER
50-280, 281/93-05.
The inspectors concluded that the multi-tiered programs discussed above
collectively incorporate various levels of corporate and station
management in ensuring safe operation. The licensee's self-assessment
programs are effective in contributing to preventing problems by
monitoring and evaluating plant performance and following up on
corrective action recommendations.
Within the areas inspected no violations were identified.
15
6.
TS Review Program (40500)
7 *
The inspectors assessed the licensee's TS review program results. The
licensee implemented this program in September 1992, and the program is
scheduled for completion in October 1993.
This program reviews TS
surveillances and verify that the surveillances were being properly
performed.
This review identified examples where components important to safety
were not being tested.
In most cases TSs did not require testing. It
was identified that the circuitry that prevents the--RHR inlet MOVs from
opening at a high RCS pressure as not being functionally tested. It was
also identified that the manual SI actuation logic was not being fully
tested. These findings are being tracked by the licensee and will
remain open until resolved.
The inspectors reviewed the applicable TSs
and concluded that these components were not specifically addressed by
TSs to require routine testing.
This review has identified the following components that were not being
tested as required by TSs:
-
TS Table 4.1-1, Item 28 requires that turbine trip inputs to
reactor protection be tested prior to each startup. The review
identified that the turbine trip signals were tested prior to
startup but that the turbine trip signal to the reactor protection
system was not being tested prior to startup. The input to
reactor protection was being tested on a monthly basis after the
units were at power.
LER 50-280/93-07 was issued as a result of
this finding.
TS Table 4.1-1, Item 32 a, requires a refueling calibration of the
steam generator lo-lo level AFW auto start signal. This
calibration includes functional testing of the motor and turbine _
driven AFW pumps.
The review tdentified that the turbine driven
auto-start circuit was not being fully tested in Unit 2.
When
this was identified, a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> LCO was entered in accordance with
TS 4.0.3. The testing was completed satisfactorily within the
24-hour period.
Addendum I to LER 50-280/93-07 is scheduled to be
issued as a result of this finding. This testing had been
satisfactorily accomplished in Unit I.
Other less significant procedural errors have been identified and are
also being tracked as open items until resolved.
The inspectors will
continue to monitor this review.
Within the areas inspected no violations were identified.
UFSAR Improvement Program (40500)
During the previous SALP assessment period, a weakness was identified in
that the UFSAR was not accurate.
The inspectors discussed the UFSAR
l
,,
8.
16
Improvement Program status with the corporate UFSAR coordinator for
Surry. According to the coordinator, review of plant operation
described in the UFSAR has been completed and appropriate revisions
made, the UFSAR was reviewed and verified that there were no unresolved
safety questions, and UFSAR changes have been incorporated such that
there is no longer a backlog.
The licensee has identified chapter 2,
Site Description, as the current priority for review and is in the
process of revising the chapter. Chapter 2 is currently scheduled to be
completed by April 1994~ The licensee currently plans to assign the
remaining UFSAR chapters to various Virginia Power organizations for
review and revision. Although the program is progressing, a date has
not been determined for completing the UFSAR Improvement Program.
Within the areas inspected, no violations were identified.
Level I Project Tracking (40500)
The Level I Project Tracking Program establishes process for management
to track activities critical or essential to the success of the nuclear
program.
Corrective actions for INPO and NRC SALP deficiencies are
examples of items tracked under Level I. The inspectors reviewed the
open projects on the Corporate Level I Report dated June 21,1993.
The
CNS Integrated Trend Report, Maintenance Backlog Monitoring Data,
Station Staff Visits to other plants to observe Industry Good Practices,
and developing a Leadership Program for first and second line
supervisors-were examples of corporate Level Is. The inspectors also
reviewed the open projects on the Station Level I Report dated
June 29, 1993.
TS review project, TPUP completion, 1993 INPO
preparation, ground water intrusion program, and Post Trip review
process were examples of station Level Is. The inspectors concluded
that the Level I Corporate and Station Project Tracking Programs
demonstrated management's involvement in activities critical to station
perf9rmance and also provided an additional method for ensuring adequate
corrective actions are implemented.
Within the areas inspected, no violations were identified.
9.
Licensee Event Review (92700)
The inspectors reviewed the LER listed below .and evaluated the adequacy
of the corrective action. The inspectors' review also included followup
of the licensee's corrective action implementation:
(Closed) LER 280/92-11, Incomplete Low Pressure Carbon Dioxide Fire
Protection System Nozzle Testing Due to Procedure Deficiency and Lack of
TS 4.18.D.l.b.2 requires that operability of the
low pressure carbon dioxide fire protection system be demonstrated every
18 months by verifying flow from each nozzle during a puff test. During
the performance of a QA Fire Protection audit, it was identified that
flow was not being verified at all discharge nozzles.
As immediate
corrective action, the low pressure carbon dioxide fire protection
system was declared inoperable and a continuous fire watch was
established in accordance with TS 3.21.B.4. Failure to test the low
'
'
17
pressure carbon dioxide fire protection system per TS 4.18.D.l.b.2 was-
identified as part 1 to NCV 50-280, 281/93-15-04. This violation will
not be subject to enforcement action because the licensee's efforts in
identifying and correcting the violation met the criteria specified in
Section VII.B of the Enforcement Policy.
As corrective action, the
licensee revised l-PT-24.3b, Fire Protection Low Pressure Carbon Dioxide
System Puff Test, on September 22, 1992, to require that flow from each
nozzle be verified. The inspectors reviewed the procedure and verified
that the corrective action was implemented. Also as corrective action,
the licensee was in the process of performing a TS surveillance review
to ensure that they are being properly performed. This review is
discussed in paragraph 6.b.
-
When this condition was identified, a continuous fire watch was
stationed per TS 3.21.B.4. During a subsequent fir~ watch turnover, the
fire watch was inadvertently changed from continuous to hourly due to
erroneous communication between shifts. When this was identified, a
continuous fire watch was reestablished. Failure to establish a
continuous fire watch in accordance with TS 3.21.B.4 was identified as
part 2 to NCV 50-280, 281/93-15-04. This violation will not be subject
to enforcement action because the licensee's efforts in identifying and
correcting the violation meet the criteria specified in Section VII.B of
the Enforcement Policy.
As corrective action, the licensee revised the
fire watch assignment sheet to clearly specify continuous or_ hourly fire
watch inspection requirements.
The inspectors reviewed the fire watch
assignment sheet and verified the corrective action was implemented.
Within the areas inspected, one NCV was identified.
10.
Exit Interview
The results were summarized on July 12,- 1993, with those individuals
identified by an asterisk in Paragraph I.
The following summary of
inspection activity was discussed by the inspectors during this exit:*
Item Number
Status
URI 50-280, 281/93-15-01
OPEN
NCV 50-280/93-15-02
CLOSED
NCV 50-280, 281/93-15-03
CLOSED
Description
(Paragraph No.)
Use pf PRA for Unreviewed
Safety Question Determination
(paragraph 3.c).
Failure to Perform Minor
Maintenance in Accordance
With VPAP-2002 (paragraph
4.a).
Failure of Personnel to
Sequence Tie-in Cleanliness
and Fit Up/Tack Inspections in
Accordance With VPAP-0903
(paragraph 4.b).
,I
. '
NCV 50-280, 281/93-15-04
18
CLOSED
Failure to Test Fire
Protection System and Failure
to Establish a Continuous Fire
Watch in Accordance with TSs
(paragraph 9) ..
LER 50~280/92-11
CLOSED
Incomplete Low Pressure Carbon
Dioxide Fire Protection System
Nozzle Testing Due to
Procedure Deficiency and Lack
(paragraph 9).
Proprietary information is not contained in this report. Dissenting comments
- were not received from the licensee.
11.
Index of Acronyms and Initialisms
AOI
BOCA -
CFR
DR
ECCS -
EPIP -
FWRV
-
l&C
INPO -
IRPI -
JCO
LCO
LEOF -
LER
LOOSP -
MFWP -
-
MSTV -
MSRC
-
NI
NOB,
ABNORMAL OPERATING INSTRUCTION
ALLOWED OUTAGE TIME
BUILDING OFFICIALS AND CODE AUTHORITIES
BALANCE OF PLANT
CENTRAL ALARM STATION
CAUSE DETERMINATION EVALUATION
CODE OF FEDERAL REGULATION
CORPORATE NUCLEAR SAFETY
COMMITMENT TRACKING SYSTEM
DEVIATION REPORT
EMERGENCY PLAN IMPLEMENTING PROCEDURES
FEEDWATER REGULATION VALVE
INSTRUMENTATION & CONTROL
INSTITUTE OF NUCLEAR POWER OPERATION
INDIVIDUAL PLANT EVALUATION
INDIVIDUAL ROD POSITION INDICATION
JUSTIFICATION FOR CONTINUED OPERATION
LIMITING CONDITION FOR OPERATION
LOCAL EMERGENCY OPERATIONS FACILITY
LICENSEE EVENT REPORT*
.
MAIN FEEDWATER PUMP
MOTOR.OPERATED VALVE
MANAGEMENT REVIEW BOARD
MAIN STEAM LINE BREAK
MAIN STEAM TRIP VALVE
MANAGEMENT SAFETY REVIEW COMMITTEE
NUCLEAR INSTRUMENTATION
NON-CITED VIOLATION
NUCLEAR OVERSIGHT BOARD
I
..
,)
NRC
osc
QMT
RS
SNS
SNSOC -
SOER -
TPUP* -
TS
UFSAR -
VPAP -
19
NUCLEAR REGULATORY COMMISSION
OPERATIONAL EXPERIENCE REVIEW
OPERATIONS SUPPORT CENTER.
QUALITY ASSURANCE
- QUALITY CONTROL
QUALITY MAINTENANCE TEAM
ROOT CAUSE EVALUATION
REACTOR COOLANT PUMP
RECIRCULATION SPRAY
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE
SECONDARY ALARM STATION
SAFETY EVALUATION
SAFETY INJECTION
STATION NUCLEAR SAFETY
SURRY NUCLEAR SAFETY AND OPERATING COMMITTEE
SIGNIFICANT OPERATING EVENT REPORT
TECHNICAL PROCEDURES UPGRADE PROGRAM
TECHNICAL SPECIFICATION
UPDATED FINAL SAFETY ANALYSIS REPORT.
UNRESOLVED ITEM
VIRGINIA POWER ADMINISTRATIVE PROCEDURE
WORK ORDER
WESTINGHOUSE OWNERS GROUP