ML18152A325
| ML18152A325 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 07/01/1992 |
| From: | Branch M, Fredrickson P, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A326 | List: |
| References | |
| 50-280-92-13, 50-281-92-13, NUDOCS 9207140044 | |
| Download: ML18152A325 (15) | |
See also: IR 05000280/1992013
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION 11
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report-Nos.:
50-280/92-13 and 50-281)92-13
Licensee~
Virginia Electric and Power Company
- 5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
License Nos.:
Facility Name:
Surry 1 and 2
Inspection Conducted:
May 10 through June 6, 1992
Inspectors: ~
~
M. --arn,entorResident Inspector
a~ 2h:::
J. W. York,~t Inspector
a~~
S. G. Tinge~nt Inspector
Approved by: *
M V 5 .J,uk-
P. E. Fredricson, Section Chief
Division of Reactor Projects
SUMMARY
Scope:
D~~
- ~<--
Daeigned
~-d,
D!te1gne
. 7(, [1~
Date Signed
This routine resident inspection was conducted on site in the areas of
operations, maintenance, surveillance, licensee event review, action on
previous inspection items, and safety assessment and quality verification.
During the performance of this inspection, the resident inspectors conducted
review of the licensee's backshift or weekend operations on May 22, 28, and
June 3, 1992.
Results:
In the maintenance/surveillance area, the following items were noted:
Management oversight and controls associated with replacement of
the No. 1 emergency diesel generator governor reflected the
implementation of improvements as a result of corrective action
for previous weaknesses in this area {paragraph 4.a).
9207140044 920701
ADOCK 05000280
G
2
The emergency diesel generator procedure for adjusting scribe'~
marks appeared to need strengthening to eliminate confusion
{paragraph 5.a).
In the safety assessme~t/quality*verification area, the following items were
noted:
The failure to perform safety evaluations for procedures that were
used to operate plant systems differently than that described in
the Updated Final Safety Analysis Report was identified ~s
Violation 280,281/92-13-0l {paragraph 7).
The Management Safety Review Co1R11ittee meeting was thorough and
the discussion of issues were detailed to make
decisions/recommendations {paragraph 8).
1.
Persons Contacted
Licensee Employees
REPORT DETAILS
R. Allen, Superintendent of Operations (Acting}
- W. Benthall, Supervisor, Licensing
R. Bilyeu, Licensing Engineer
- H. BJake, Superintendent of Site Services
- R .. Blount, Superintendent of Engineering
- D. Christian, Assistant Station Manager
- J Demease, Nuclear Oversight Board
J. Downs, Superintendent of Outage and Planning
- R. Gwaltney; Superintendent of Maintenance
- W. Hartley, Nuclear Oversight Board
- M. Holdsworth, Supervisor, Security
M. Kansler, Station Manager
.
- A. Keagy, Superintendent of Materials
- J. McCarthy, Assistant Station Manager (Acting}
- A. Meekins, Supervisor, Administrative Services
- D. Modlin, Supervisor, Shift Operations (Acting}
- J. O'Hanlon, Vice President-Nuclear, Corporate
- E. Smith, Site Quality Assurance Manager
- R. Wells, Supervisor, Maintenante
NRC Personnel
M. Branch, Senior Resident Inspector
- S. Tingen, Resident Inspector
- J. York, Resident Inspector
- Attended exit interview.
Other licensee employees contacted included control room operators,
shift technical advisors, shift supervisors and other plant person~el.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2.
Pl ant Status
Unit 1 began the reporting period in power operation.
The unit was at
power at the end of the inspection period, day 31 of continuous
operation.
Unit 2 began the reporting period in power ope rat i o'n. * The unit was at
power at the end of the inspection period, day 171 of continuous
operation.
3.
- - - - - - -
2
Operational Safety Verification (!1707,42700)
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.
Licensee 10 CFR 72 Reports
On May 11, the licensee made a 10 CFR 50.72 report concerning
operation of Unit 1 since the startup on May 1, 1992, in non-
compliance with the requirements of TS 3.3.B.2 (Safety Injection
System) for alignment of the CH/HHSI pumps.
The control switches
for the CH/HHSI pumps were aligned such that the A CH/HHSI pump
would trip on an undervoltage condition. This CH/HHSI pump
configuration was identical to the condition that resulted in
escalated enforcement action in September, 1991. This event is
covered in detail in IR 280,281/92-12.
b.
Troubleshooting Motor Driven Fire Pump
While securing the motor driven fire pump on June 3, the breaker
for the pump cycled twice and tripped.
The diesel driven fire
pump then automatically started but was secured when the operator
observed air coming out of a vent on the pump's casing. Deviation
report No. S-92-0977 was written and work request No. 800386 was
issued.
The licensee declared both fire pu,mps inoperable and initiated a
one hour clock to establish a continuous fire watch with backup
suppression equipment for Unit 1 and 2 cable vault and tunnels as
required by TS 3.21.B.3. A 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> LCO was initiated to establish
a backup firi suppression wJter system in accordance with TS 3.21.8.2.b. The plant fire truck was designated as the backup
fire suppression water system and it was verified as operable.
The inspectors observed operation personnel coordinating with the
~ystem engineer in the filling and venting of the system and
evaluating the problem.
It was concluded that a check valve
between a hydropneumatic tank and both fire pumps caused the
problem.
The failure of this check valve allowed the pressure to
be lowered in the tank and the air to migrate to the two pumps
causing cavitation. After filling and venting, the pressure was
returned to normal in the hydropneumatic tank.
The check valve
3
appears to be performing normally and an annunciator in the
control room would indicate any return of this problem.
Within the areas inspected, no violations were identified.
4.
Maintenance Inspections (627Q3, 42700,)
During the reporting period, the inspectors reviewed maintenance
activities-to assure compliance with the appropriate procedures.
The following maintenance activities were reviewed.
a.
No. 1 EDG Governor Replacement
On May 19, the No. 1 EDG-did not start during a post maintenance
test and the problem was later attributed to a failed governor.
The EDG was operated on the previous shift; therefore, the EDG
governor failure was quickly identified. The inspectors observed
portions of the maintenance to replace the No. 1 EDG governor;
Procedure O-MCM-0705-01, Emergency Diesel Injector Rack, Governor
Compensation, and Speed Limit Switch Adjustments, dated February
13, 1992, and WO 3800127359 were used to accomplish this
maintenance.
The governor was removed and replaced with a spare
governor.
Prior to installing the new governor it was sent to a local test
facility.
The governor was adjusted and tested. The test
facility was not on the licensee's QA approved vendor list. The
inspectors reviewed ENAP-0004, Procurement Technical Evaluation,
dated May 4, 1992 which allows the use af non-qualified vendors
provided'Virginia Power's QA program is extended to cover the
vendor.
During the test, the licensee's QA program was extended
to cover the vendor with the presence of a corporate QA i~spector
who monitored the test activities~
In addition, an SNSOC approved
procedure was used for adjustments and testing of the governor.
This procedure was incorporated into procedure O-MCM-0705-01.
The inspectors reviewed the PMT requirements for this maintenance
and did not identify any discrepancies.
An EDG fast speed start
was required.
The inspectors also reviewed O-MCM-0705-01 and did
not identify any deficiencies. The inspectors concluded that
management oversight and control functions related to the governor
replacement were successful in satisfactorily accomplishing this*
maintenance.
For example, a formal maintenance procedure was
utilized that specifically addressed governor replacement, correct
PMT requirements *were specified, procedures were followed, and
communications between operation, maintenance, and engineering
were good.
b.
4
Mechanical Equipment Bolting
During the walkdowns of plant areas, the inspectors noted a
questionable condition regarding the mounting of sev~ral safety-
related and nonsafety-related pumps, motors, and engines.
Specifically, the jacking bolts which are normally used only to
align the foundation bolts prior to tightening were found to be.
contacting the foundation of the equipment and had not been backed
off. This condition could mask equipment vibration problems and
did not appear to be addressed by the licensee maintenance
procedures.
The inspectors discussed this condition with the Maintenance
Manager and a walkdown by the licensee indicated that
approximately 30 percent of .the equipment inspected had the same
condition (i.e. jacking bolt tight against the equipment
foundation).
The li~ensee indicated that, although the procedures
do not detail the need to loosen the jacking bolts after equipment
alignment, discussion with mechanics involved with equipment
mounting revealed that they were aware of the need to loosen the
jacking bolts after alignment.
The inspectors did not identify any cases where excessive
equipment vibration was being dampened by the use of the jacking
bolts.
However, the lic.ensee was reluctant to just loosen the
jacking bolts with out measuring the resultant equipment
vibration.
The licensee agreed to verify proper equipment
vibration with t~e jacking bolts loosened during the scheduled
predictive maintenance vibration measurement.
The licensee
proposed resolution of the inspectors concern in this area appears
to be acceptable when combined with the evaluation of possible
procedure enhancements as well.
Within the area inspected, no .violations were identified.
5.
Surveillance Inspections (61726, 42700) *
During the reporting period, the inspectors reviewed surveillance
activities to assure compliance with the appropriate procedure and TS
requirements.
The following surveillance activity was reviewed:
a.
No. l EDG Post Maintenance Testing
On May 20, the inspectors witnessed the testirig of the No. l EDG
following the replacement of the governor.
The testing was
accomplished in accordance with l-OPT-EG-004, *Number l Emergency
Diesel Generator Quarterly Fast Start Exercise Test, dated April
16, 1992. The inspectors attended the pre-job briefing, witnessed
portions of the test, and reviewed the completed test procedure .
The EDG was initially started in slow speed in accordance with
5
step. 5. 2 .17 of operating procedure 1-0P-EG-001, Number 1 Emergency
Diesel Generator, dated April 16, 1992.
The engine increased in
speed and stabilized at approximately 420 rpm versus the desired
470 to 490 rpm value stated in the procedure. A slow speed
adjustment was made in accordance with the procedure.
The inspectors' review of the above operating procedure identified
an area that needed strengthening by the licensee. Specifically,
step 5.3 of 1-0P-EG-001 which was used to shutdown the EOG from
the main control room contained confusing instructions associated
with verification of governor speed control scribe marks after
engine shutdown.
The governor speed control knob and gears had
- been scribed with a distinct marking on all three EDG following
the August 1991 EOG failure as part of the corrective actions.
Procedures were developed to require verification that *these
scribe marks were in alignment locally to ensure that the EDG
would achieve rated speed during emergency starting. The
confusing instructions were contained in steps 5.3.11 and its
preceding note and 5.3.12. Step 5.3.11 requir~d that the
alignment of scribe marks on the gears and the speed control knob
be verified. However, the preceding note stated that, if the
scribe marks are found not aligned during the verification, no
alignment should be attempted. Step 5.3.12 states that if the
scribe marks are not in alignment then notify the shift
supervisor.
It was not clear as to whether alignment of the
scribe marks were an option or whether the operator was not to
make the adjustments and the shift supervisor would recognize the
need to have maintenance adjust the scribe marks.
The potential
for leaving an EOG in an unknown inoperable condition was further
complicated in that there was no other mention of verifying the
scribe marks prior to declaring the EOG fully operable per the
note after step 5.3.19 of the procedure.
The inspectors discussed the above concerns with station
management who indicated that a procedure revision would be
considered to resolve the confusion.
Within the areas inspected, no violations were identified.
6.
Licensee Event Review (92700)
The inspectors reviewed the LERs listed below and evaluated the adequacy
of corrective action.
The inspector's review also included followup on
the licensee's implementation of corrective action.
a.
(Closed) LER 280,281/90-20, Startup and Power Operation With One
Train of Containment Spray System Inoperable Due to Improper
Deletion of Pressure Switch Repair From Outage Work Scope.
This
issue involved the failure of limit switches 1-CS-PS-103A and 1-
CS-PS-103C.
This issue and immediate corrective actions were
previously discussed in IR 280,281/91-06.
long term corrective
actions involved performing a CFE on the failed limit switches,
b.
6
performing an engineering study to evaluate the removal of th~~.
switches, performing a root cause evaluation, review of test
records to determine if other systems may have the same type of
switches, upgrade l&C PM program, and.stre~gthen the ~tartup
assessment process. A CFE has not been performed for th- failed
limit switches; however, this item is being tracked by CTS No.
1212 until completion.
The MOVs that automatically operated in
response to actuation of these limits switches were failed opened,
control power was removed, and stem locking devices were installed
as described in IR 280,281/91-06.
The inspectors walked .down the
system and verified the installation of stem locking devic.es and
that the control room indication for the MOVs were deenergized.
The root cause evaluation ~as performed and is discussed in IR
280,281/91-06.
The startup assessment process was enhanced by
requiring corrective actions, in response to station deviations
which are initiated during a RFO, be tracked and have SNSOC
concurrence if corrective measures were not implemented before
startup of the unit.
In addition, a representative from the
Outage & Planning Department is required to attend SNSOC meeting
during review of station deviations to ensure that outage related
station deviations are scheduled to be worked during the outage.
The l&C PM program was enhanced by incorporating it into the
station PM.program which requires written approval to defer a PM.
In addition, deferred PMs are tracked monthly by the PM
coordinator and are reviewed by the MRB during restart
assessments.
The inspectors consider that the corrective actions
were properly implemented or were being properly tracked.
(Closed) LER 280,281/91-17, Diesel Generator Rendered Inoperable
Due to Personnel Error in Adjusting the Governor.
This issue
involved the No. 3 EDG being inoperable for a period of time*
greater that allowed by TSs due to an improperly adjusted governor
speed control dial. Violation 280,281/91-24-01, Failure to Comply
With the Requirements of TS. 3.16.B.1 with the No. 3 EDG
Inoperable, was issued as a result of this event.
The corrective
actions for this LER and the violation are the same and are
discussed below ..
Within the areas inspected, no violations were identified.
7.
Action On Previous Inspection Items (92701,92702)
a.
(Closed) Violation 280,281/90-36-0l, Low SW Flow Th~ough the
This issue involved inoperable RSHXs in both units due to
reduced SW flow rates. The reduced SW flow rates were caused by
macrofouling of the RSHXs.
Short term corrective actions
involving inspection, cleaning, testing, alternating SW BC supply
headers, and placement of RSHXs SW supply headers in partial wet-
layup were discussed in IR 280,281/90-36.
The licensee responded
to this violation in a letter dated March 14, 1991.
In that
letter, the licensee stated that the following long term
corrective actions would be implemented: (1) chemically treat the
~*
b.
7
48 inch SW headers to the RSHXS in order to control hydroid
growth; (2) monitor 48 inch SW supply headers for temperature,
salinity, PH, conductivity, dissolved oxygen, chlorine and anvnonia
and correlate results with visual inspections; (3) perform flow
testing and post test inspection on a RS SW subsystem and perform
as~found inspection on the remaining RS SW subsystem during the
1991 Unit 2 RFO and 1992 Unit 1 RFO; (4) initiate an ecosystem
study to support a long-term biological control strategy; and
(5) clean, inspect, repair and epoxy coat RSHX supply piping.
The inspectors walked down the SW system and verified installation
of equipment utilized to chemically treat the 48 inch SW headers
to the RSHXs.
Additonally, the inspectors reviewed procedures -
l,2-0P~49.1, Startup and Shutdown of the SW System and Chemical
Injection of Headers, dated August 22, 1991, 1,2-0P-49.7, Draining
RSHX SW Piping in Wet Lay-UP, dated May 31, 1991, and l,2-0SP-SW-
001, Maintenance and Sampling of RSHX SW .Piping in Wet Lay-up,
dated April 23, 1992. These procedures are utilized to add
chemicals, fill, and sample the system.
The inspectors also
reviewed the the monthly PT schedule and verified that the SW BC
headers are alternated on a weekly basis. During the.Unit 1 1992
RFO, the inspectors inspected internal portions of the 48 inch SW
piping and considered the program effective in minimizing hydroid
growth.
During the previous Unit~ 1 and 2 RFOs, the inspectors
monitored flow testing of the RSHXs and inspected the RSHXs
following the tests. Results of these inspections also indicated
that corrective actions have been effective.
IRs 280,281/91-10
and 92-07 discussed these inspections. The Virginia Institute of
Marine Science monitors hydroid growth and makes recommendations
to the licensee for long term control. This item is being tracked
by CTS No. 220 until completion. Approximately 80% of the Unit 1
and 50% of the Unit 2 RSHX SW supply piping has been coated with
epoxy.
Completion of epoxy coating is scheduled during the
upcoming RFOs and is being tracked by CTS No. 1180.
At the end of
the inspection period, the licensee was evaluating the need to
routinely flow test the SW piping to the RSHXs.
The inspectors
consider that the corrective actions were properly implemented.
{Closed) UNR 280,281/91-33-01, Safety Evaluations for Changes in
the Facility. This issue involved three examples in which the
licensee had operated plant systems in a different manner *than
-described in the UFSAR but had not first prepared written safety
evaluations pursuant to lOCFR 50.59.
Based on guidance from Part
9900 of the NRC Inspection Manual and NSAC-125, the inspectors
concluded that a safety evaluation should have been done for each
example.
The licensee disagreed. Because of this disagreement,
the NRC further reviewed this issue and concluded that the
licensee should have recognized these configurations as changes to
procedures described.in the FSAR and therefore, should have
performed safety evaluations to justify these changes.
The basis
for this conclusion is that the UFSAR's description of the
operation of a plant system, including its alignment or
,
8
configuration, constitutes a procedure as described in 10 CFR
50.59~ Thus, proposed procedures for operating a plant system in
a different manner than described in the UFSAR should be evaluated
pursuant to 10 CFR 50.59.
10 CFR 50.59(b)(l) requires records of
changes in procedures as described in the safety analysis report
to include written safety evaluations which provide the basis for
the determination that the procedure changes do not involve
unreviewed safety questions.
The failure to perform safety
evaluations for the procedures that were used to operate plant
systems differently than that described in the UFSAR was
identified as Violation 280,281/92-13-01.
Examples of procedures
that operated plant systems differently than described in the
UFSAR were OP 52.2.1, Administrative Control of 1-FP-36, dated
October 27, 1989, 2-0P-49.7, Filling and Draining RSHX Service
Water Supply Piping, dated September 18, 1991, and OP 6.2.3, *
Administrative Control of 1-EG-15, 2-EG-15 or 3-EG-15, dated
January 20, 1990.
-
c.
(Closed) IFI 2ao,281/90-30-0l, Followup on Licensee Corrective
Action and Testing Deficiencies Identified During RSHX SW Flow
Testing. This issue involved reduced RSHX SW flow rates and
incorrect indication of control room RSHX SW flow identified
during testing accomplished in Unit 1 during the 1990 RFO.
Violation 280,281/90-36-01 was issued as a result of reduced SW
flow rates which was discussed in the previous paragraph. During
the Unit 1 1992 RFO, new RSHX SW flow instrumentation was
installed in Unit 1 and satisfactorily tested. Testing of the new
flow instrumentation was discussed in IR 280,281/92-07.
Installation of new RSHX SW flow instrumentation in Unit 2 is
scheduled for the 1993 RFO.
d.
(Closed) VIO 280,281/91-24-01, Failure to comply with the
. requirements of TS 3.16.B.1 with the No. 3 EOG inoperable. This
issue involved the No. 3 EOG being inoperable for a period of time
greater that allowed by TSs due to an improperly adjusted governor
speed control dial. Immediate corrective actions required to
restore the EOG to an operable status are discussed in IR
280,281/91-24.
The licensee responded to this violation in
letters dated November 20, and December 20, 1991.
In these
responses, the licensee stated that the following long term
corrective actions would be implemented: (1) scribe the governor
gearing and speed knobs at the 900 rpm setting and install a see-
through cover plate on each governor limit switch enclosure so the
the scribed match marks may be observed without cover removal
(2) revise operator logs to verify that match marks are properly
aligned on each shift, (3) revise PMT requirements to specify that
fast start testing requirements following any governor
maintenance, upgrade procedures for governor maintenance and fast
start operation, (4) train select station personnel with vendor
participation on EOG governors in order to increase overall
knowledge level, (5) establish special task teams to review root
causes and review EOG governor and control circuits to ensure
9
reliable operation, and (6} perform a QA assessment on
implementation of the PMT program.
The inspectors walked down all three EDGs and verified that the
governors' gears were matched, marked, and aligned. The
inspectors also verified the installation of see-through cover.
plates on the EDG governors and that plant logs were revised to
require verifiation of the governor match marks.
Procedure No.
IA, Plant Log Readings, dated May 28, 1992, was reviewed to verify
that governor match marks were checked for alignment on each
shift. Review of EDG upgraded procedures and PMT requirements are
discussed in paragraphs 4.a and 5.a and were considered adequate.
The licensee has not completed the governor training but this item
was being tracked by CTS item 1473.
Present licensee plans are to
train station personnel in September 1992.
The inspectors
reviewed CFA*Report 91-1991, dated December 27, 1991, on EOG
governors, and verified that the EOG failure was analyzed and that
EDG governor enhancements were investigated. The inspectors
reviewed the PMT followup assessment, dated Hay 27, 1992. This*
assessment concluded, in general, that the specified PMT assured
equipment was operable before return to service.
The inspectors
consider that the corrective actions in response to the violation
were properly implemented or were being properly tracked ..
e.
(Closed} VIO 280/90-39-01, Failure to Follow Precaution 4.19 While.
Performing Continuity Checks During the Performance of Procedure
l-OPT-ZZ-001. This issue involved the inadvertent automatic start
of the Nos. I and 3 EDGs caused by an electrician improperly
performing a continuity check.
The licensee responded to this in
a letter dated February 25, 1991.
In the letter, the licensee
stated that the following corrective actions would be implemented;
strengthen standards for conducting prejob briefings, include this
. example in training lesson plans for electricians, and revise ESF
test procedures to include precautionary statement alerting
workers to the possibility of voltage being present during
continuity checks of electrical circuits. The licensee formed a
team to develop standards for conducting prejob briefings. Once
these standards were developed, the team issued them via a station
letter to the different departments.
Each department reviewed
these standards and incorporated them into the applicable
department procedures.
The operations department incorporated the
new prejob brief criteria in Revision 2 to VPAP-1401, Conduct of
Operation.
The inspectors reviewed this document and verified
that these instructions were added. The engineering department
incorporated the new prejob brief criteria into Revision 3 of
SUADM-ENG-09, T~st Control, and Revision I of SUADM-ENG-11,
Special Tests. The inspectors reviewed these documents and
verified that instructions were added. The inspectors reviewed
procedures l-OPT-ZZ-001, ESF Actuation With Undervoltage and
Degraded Voltage IH-Bus, dated February 27, 1992 and 2-0PT-ZZ-002,
ESF Actuation With Delayed Undervoltage 2J-Bus, dated August 29,
1991, and ~erified that these procedures were revised to provided
f.
g.
10
a precautionary statement was added to alert workers of the
possibility of voltage being present during continuity checks.
The tnspectors reviewed Revision 2 to the lesson plan titled,
Event Training Using Test Equipment, and verified that it covered
this event; The inspectors consider that the corrective actions
in response to the violation were properly implemented.
{Closed) VIO 280/90-39-02, Failure to Provide Adequate
Instructions for Testing, Resulting in the Unintentional Actuation
of B Train CLS HI {SI). This issue involved inadequate
instructions in an ESF procedure for removal of a test jumper
which resulted in the inadvertent initiation of B train CLS HI
{SI).
The licensee responded to this in a letter dated February
25, 1991.
In the letter the licensee stated that the following
corrective actions would be implemented; revise the ESF procedure
to specify the correct jumper and strengthen administrative
controls governing procedure development by requiring an
additional technical review for complex pro~edures that have the
potential to cause inadvertent ESF actuations. The inspectors
reviewed procedure l-OPT-ZZ-001 and verified that it was revised
to provide adequate instructions for removal of the test jumper.
Station Procedure Directive 001, dated February 13, 1991, which
was revised, instructed procedure writers of the additional
technical review.
The inspectors consider that the corrective
actions in response to the violation were properly implemented.
(Closed) VIO 280/90-39-03, Inadequate Field Change Resulting in
Unreliable Reactor Vessel Level Indication. This issue involved a
field change to a DCP that modified the reactor head vent piping.
The field change was inadequate because it did not recognize that
the standpipe had been turned over to operations for unrestricted
use.
As a result, the reactor vessel standpipe indication was
unreliable while the modification to the reactor head vent piping
was being performed.
The licensee responded to this violation in
a letter dated February 25, 1991.
In the"letter the licensee
stated that the following corrective actions would be implemented;
issue a lessons learned memorandum to Design, System and Testing
Engineering personnel discussing this issue; issue a memor~ndum to
operations personnel emphasizing that a step may be marked as NA
only when specifically authorized in the body of the DCP or EWR
and enhance administrative procedures governing field change
preparation and technical review processes to ensure notification
of shift supervisors and retagging of system boundaries before
working on systems returned to operations under a partial
technical review.
The inspectors reviewed the memorandum to
engineering personnel titled, Lessons Learned-DC 86-15-1 Partial
Technical Review/Subsequent Field Changes, dated December 4, 1990.
This memorandum discussed the event and how to prevent similar
occurrences.
The inspectors reviewed Operations department
memorandum dated January 9, 1991 which explained that steps in
EWRs or DCPs may not be marked NA unless specifically allowed by
the procedure.
The inspectors also reviewed SUADM-ENG-13, DCP/EWR -
h.
11
Implementation and Closeout, dated March 10, 1992 and verified
that it contained instructions that shift supervisor notification,
retagging of system boundaries and review of initial conditions
and precautions are required for continued work or rework on a
system previously released under a partial technical review.
The
inspectors consider that the corrective actions in response to the
violation were properly implemented.
(Closed) VIO 280,281/90-41-01, Failure to Correctly Classify SW
pumps 1-VS-P-IA, 8, and C and CD pumps l-VS-P-2A, 8,.and C in
Accordance With Regulatory Guide 1.26. This issue involved the
improper classification of SW pumps l-VS-P-1A, 8, and C and CD
pumps l-VS-P~2A, 8, and C as non Class 3 components and therefore
erroneously omitted from the licensee's IST p~ogram.
The licensee
responded to this violation in a letter dated March 22, 1991.
In
the letter, the licensee stated that the pumps and valves in the
control-room-envelope air conditioning system were added to their
Section XI program.
The inspectors reviewed Revision 4 to the
Inservice Testing Program Plan and verified that the pumps and
valves in the control room envelope air conditioning system were
in the program.
The inspectors consider that the corrective
actions in response to the violation were properly implemented.
Within the areas inspected, no violations were identified.
8.
Safety Assessment and Quality Verificat1on (40500)
The inspectors attended portions of the June 2 MSRC meeting.
During
that meeting, the plant managers from both stations discussed recent
plant performance and regulatory history. Several proposed TS
amendments were presented and the inspectors determined that an
appropriate level of detailed discussion occurred before approval of
amendments.
The inspectors also monitored the discussion of the CNS
subcommittee report on a new performance monitoring program that was
being proposed. The program was only in the development stage and the
MSRC members had a lot of discussion over the definition of some of the
indicators being monitored. Specifically, there was concern that
indicators such as "nuclear safety" needed to be better defined because
a declining trend may indicate unacceptable performance to one person
but not to another~
The CNS subcommittee chairman indicated that the
comments would be considered and a new draft would be presented during
the next scheduled MSRC meeting.
The inspectors considered the MSRC
meeting was thorough and that discussion of issues at the appropriate
level occurred before decisions/recommendations were made.
9.
12
Exit Interview
The inspection scope and results were summarized on, June 9, with those
individuals identified by an asterisk in paragraph 1.
The following
summary of inspection activity was discussed by the inspectors during
this exit.
Item Number
Status
VIO 280,281/92-13-01
Open
VIO 280, 281/91-24-01
Closed
VIO 280/90-39-01
Closed
VIO 280/90-39-02
Closed
VIO 280/90-39-03
Closed
VIO 280,281/90-36-01
Closed
VIO 280,281/90-41-01
Closed
UNR 280,281/91-33-01
Closed
IFI 280,281/90-30~01
Closed
Description and Reference
Failure to perform safety
evaluations for procedures that were
used to operate plant systems
differently than that described in
the UFSAR.
Failure to comply with the
requirements of TS 3.16.B.1 with the
No. 3 EDG inoperable.
Failure to Follow Precaution 4.19
while performing continuity checks
during the performance of procedure
1-0PT-ZZ-001.
Failure to provide adequate
instructions for testing, resulting
in the unintentional actuation of B
Train CLS HI (SI).
Inadequate field change resulting in
unreliable reactor vessel level
indication.
Low SW flow through the RSHXs.
Failure to correctly classify SW
pumps 1-VS-P-IA, B, and C and CD
pumps l-VS-P-2A, B, and C in
accordance with Regulatory Guide
1.26.
.
Safety evaluations for changes in
the facility.
Followup on licensee corrective
action and testing deficiencies
identified during RSHX SW flow
testing.
13
L(R 280,281/90-20
Closed
LER 280,281/91-17
Closed
Startup and power operation with one
train of containment spray system
. inoperable due to improper deletion
of pressure switch repair from
outage work scope.
Diesel Generator Rendered Inoperable
Due to Personnel Error in Adjusting
the Governor.
10.
Index of Acronyms and Initialisms
CFA
CFE
CLS
CFR
EOG
. FSAR
IFI
- l&C
IR
1ST
LER
LCO
NRC
MSRC
OP
. PMT
RS
.RSHX
SNSOC
TS
BEARING COOLING
COMPONENT FAILURE ANALYSIS
COMPONENT FAILURE EVALUATION
CONSEQUENCES LIMITING SAFEGUARD
CODE OF FEDERAL REGULATIONS
CORPORATE NUCLEAR SAFETY
COMMITMENT TRACKING SYSTEM
DESIGN CHANGE PACKAGE
ENGINEERED SAFETY FEATURE
ENGINEERING WORK REQUEST
FINAL SAFETY ANALYSIS REPORT
HIGH HEAD SAFETY INJECTION
INSPECTOR FOLLOWUP ITEM
INSTRUMENTATION AND CONTROLS
INSPECTION REPORT
INSERVICE TEST
LICENSEE EVENT REPORT
LIMITING CONDITIONS OF OPERATION
MOTOR OPERATED VALVE
MANAGEMENT REVIEW BOARD
NUCLEAR REGULATORY COMMISSION
MANAGEMENT SAFETY REVIEW COMMITTEE
OPERATING PROCEDURE
PREVENTIVE MAINTENANCE
PERIODIC TEST
QUALITY ASSURANCE
RECIRCULATION SPRAY
RECIRCULATION SPRAY HEAT EXCHANGER
STATION NUCLEAR SAFETY AND OPERATING COMMITTEE
TECHNICAL SPECIFICATION
UPDATED FINAL SAFETY ANALYSIS REPORT
UNRESOLVED ITEM
VIOLATION.
WORK ORDER