ML20234E778
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| ML20234E778 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 06/30/1987 |
| From: | Butcher R, Dance H, Will Smith NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20234E765 | List: |
| References | |
| 50-416-87-14, NUDOCS 8707070680 | |
| Download: ML20234E778 (12) | |
See also: IR 05000416/1987014
Text
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REGION H
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Report No.: 50-416/87-14
Licensee: System Energy Resources, Inc.
Jackson, MS 39205
Docket No.: 50-416 License No.. NPF-29 ;
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Facility Name: Grand Gulf Nuclear Station
Inspection Conducted: May 16 through June 19, 1987
Inspect s: [/l M
R. C. Butcher, Senior Resident Inspector
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Date Signed I
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b- W.'F. Smith, Resident Inspector Date Signed j
Approved by: b d** - b d//7
H. C. Dance,'Section Chief D4te S'igned I
Division of Reactor Projects
SUMMARY
Scope: This routine inspection was conducted by the resident inspectors at
the site in the areas 3of Licensee Action on Previous Enforcement Matters,
Operational Safety Verification, Maintenance Observation, Surveillance Obser-
vation, ESF System Walkdown, Reportable Occurrences, Operating Resctor Events,
and Inspector Followup and Unresolved Items.
Results: One violation was identified: Failure to provide an adequate
procedure for surveillance testing of the Standby Liquid Control System.
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8707070680 B{go 416
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REPORT DETAILS
1. Licensee Employees Contacted
*J. E. Cross, GGNS Site Director
*C. R. Hutchinson, GGNS General Manager
R. F. Rogers, Manager, Unit 1 Projects
*A. S. McCurdy, Manager, Plant Operations
*J. D. Bailey, Compliance Coordinator i
*M. J. Wright, Manager, Plant Support
*L. F. Daughtery, Compliance Superintendent
D. G. Cupstid, Start-up Supervisor
R. H. McAnulty, Electrical Superintendent
J. P. Dimmette, Manager, Plant Maintenance
W. P. Harris, Compliance Coordinator
*J. L. Robertson, Licensing Superintendent
L. G. Temple, I&C Superintendent
J. H. Mueller, Mechanical Superintendent
L. B. Moulder, Operations Superintendent' !
J. V. Parrish, Chemistry / Radiation Control Superintendent
*S. M. Feith, Director, QA
*R. V. Moomaw, Technical Assistant to Manager, Maintenance
*R. T. Halbach, Administrative Assistant to General Manager
*S. F. Tanner, Manager, Nuclear Site QA
Other licensee employees contacted included technicians, o'perators,
security force members, and office personnel.
* Attended exit interview
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2. Exit Interview (30703) j
The inspection scope and findings were summarized on June 19, 1987, with
those persons indicated in paragraph 1 above. The licensee did not 1
identify as proprietary any of the materials provided to or reviewed by
the inspectors during this inspection. The licensee had no comment on the
following inspection findings:
416/87-14-01, Inspector Followup Item: Correction of deficiencies
found during the Standby Gas Treatment System walkdown inspection
(paragraph 7).
416/87-14-02, Inspector Followup Item: Inspection and/or replacement
of General Electric HFA relays in safety related systems (paragraph 9).
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416/87-14-03, Violation: Failure to provide and implement an adequate
procedure for the surveillance testing of the Standby Liquid Control
System (paragraph 10).
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3. Licensee Action on Previous Enforcement Matters (92702)
(Closed) Violation 416/87-10-04. Failure to identify and document a
condition adverse to quality in accordance with Administrative Procedure
01-S-03-2, Quality Deficiency Reports. The primary cause of this . viola-
tion was failure of Quality Assurance (QA) personnel to recognize that a
deficiency existed when an improperly assembled relief valve in the
Standby Liquid Control System began to leak profusely when pump suction
head was applied downstream of the relief. The inspectors verified
documentation of corrective actions taken, i.e., to train all QA inspec-
tion and audit personnel, and to ensure all GGNS employees are aware
of their responsibility to document any nonconformance at the time it is ,
identified. The actions taken appear to be adequate. No further action I
is required.
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4. Operational Safety Verification (71707, 71709 and 71881)
The inspectors kept themselves informed on a daily basis of the overall
plant status and any significant safety matters related to plant opera-
tions. Daily discussions were held with plant management and various
members of the plant operating staff.
The inspectors made frequent visits to the control room such that it
was visited at least daily when an inspector was on site. Observations
included instrument readings, setpoints and recordings, status of
operating systems,, tags and clearances on equipment controls and switches,
annunciator alarms, adherence to limiting conditions for operation,
temporary alterations in effect, daily journals and data sheet entries,
control room manning, and access controls. This inspection activity
included numerous informal discussions with operators and their
supervisors.
Weekly, when the inspectors were onsite, selected Engineered Safety
Feature (ESF) systems were confirmed operable. The confirmation is made
by verifying the following: Accessible valve flow path alignment, power
supply breaker and fuse status, major component leakage, lubrication,
cooling and general condition, and instrumentation.
General plant tours were conducted on at least a biweekly basis. Portions
of the control building, turbine building, auxiliary building and outside
areas were visited. Observations included safety related tagout verifica-
tions, shift turnover, sampling program, housekeeping and general plant
conditions, fire protection equipment, control of activities in progress,
problem identification systems, and containment isolation. At least
monthly, the licensee's onsite emergency response facilities were toured
to determine facility readiness.
Monthly, the inspectors reviewed at least one Radiation Work Permit (RWP),
observed health physics management involvement and awareness of significant
plant activities, and observed plant radiation controls. At least quarterly
the inspectors reviewed the licensee's program to limit personnel radiation
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exposure As Low As Reasonably Achievable (ALARA). Monthly, the inspectors
verified licensee compliance with physical security manning and access
control requirements. At least quarterly the inspectors verified the
adequacy of physical security detection and assessment aids.
The following comments were noted:
Piping and Instrument Drawing (P&ID) M-1083A, Reactor Core Isolation
Cooling (RCIC) System, identifies the RCIC injection shutoff valve as
E51F013A. It should be E51F013-A. The RCIC pump suction from the
suppression pool valve is identified as E51F031A. It should be
E51F031-A. P&ID M-1100A, Containment Cooling System, zone G2 shows
an air operated butterfly valve upstream of valve M41F037, with no
identifying number, nor is the position specified. Correction of
these deficiencies shall be tracked under Inspector Followup Item
416/87-14-01 which is discussed in paragraph 7 of this report under !
other P&ID deficiencies.
No violations or deviations were identified.
5. Maintenance Observation (62703)
During the report period, the inspectors observed portions of the main- l
tenance activities listed below. The observations included a review l
of the Maintenance Work Orders (MW0s) and other related documents for j
adequacy, adherence to procedure, proper tagouts, adherence to technical
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specifications, radiological controls, observation of all .or part of the
actual work and/or retesting in progress, specified retest requirements,
and adherence to the appropriate quality controls.
MWO 171307, Recirculation valve runback relay card rework (Incident Report !
87-3-7). .
MWO 172538, Investigation of increasing level indication on Reactor vessel
level instruments supplied by condensing pot D004A.
MWO M72688, Chemical cleaning of ESF switchgear room cooler T46-B002A. !
MWO ME1495, Periodic inspection of containment personnel airlock at the
119 foot elevation accordance with Maintenance Procedure 07-S-14-264,
Revision 1.
MWO 172880, Investigate cause of Division 3 diesel generator tachometer -
failure. ,
MWO M72879, Damping of Standby Liquid Control System pressure gauge
1C41-R003.
No violations or deviations were identified.
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6. Surveillance Observation (61726)
The inspectors observed the performance of portions of the surveillance
listed below. The observation included a review of the procedure for
technical adequacy, conformance to technical specifications, verification
of test instrument calibration, observation of all or part of the actual
surveillance, removal from service and return to service of the system or
components affected, and review of the data for acceptability based upon
the acceptance criteria.
06-RE-1J11-V-0001, Revision 30, Power Distribution Limits Verification.
06-IC-1821-M-1004, Revision 24, Reactor Vessel Water Level (PCIS) Level 2
and 1 Functional Test.
06-RE-1C51-0-0001, Revision 25, Local Power Range Monitor (LPRM) Calibra-
tion (APRM Channels A,E,C and G). During performance of the calibration,
the inspector noted that step 5.4.12 of the procedure required adjustment
of the appropriate LPRM gain control to achieve 8.000 DC volts on the i
digital volt meter, and no tolerance was specified. Licensee personnel j
conducting the test accepted from 7.990 to 8.010, which was not allowed by 1
the procedure. The Reactor Engineer at the scene explained that plus or d
minus 10 millivolts was acceptable, and that he would initiate a change to
the procedure to provide for the tolerance. The inspectors have witnessed
other surveillance where a similar circumstance existed and the technicians
spent inordinate amounts of time adjusting potentiometers to exact values
when a reasonable tolerance would have achieved satisfactory results and
perhaps reduce the time safety related equipment is bypassed out of
service for calibration. The licensee is in the process of correcting
procedures to facilitate verbatim compliance, and the problem above is i
typical to many procedures. The inspectors will continue to monitor
surveillance.
06-0P-1C41-M-0001, Revision 26, Standby Liquid Control System (SLCS) )
Operability. See paragraph 10, Inspector Followup Item 416/87-10-05 l
for comments.
No violations or deviations were identified.
7. Engineered Safety Features System Walkdown (71710)
A complete walkdown was conducted on the accessible portions of the
Standby Gas Treatment System (SGTS). The walkdown consisted of an
inspection and verification, where possible, of the required system valve ,
alignment, including valve power available and valve locking where required, '
instrumentation valved in and functioning; electrical and instrumentation
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cabinets free from debris, loose materials, jumpers, evidence of rodents,
and system free from other degrading conditions. The system was found to
be in a satisfactory condition and appeared ready to perform its safety
l function if called upon. The inspectors noted several minor discrepancies
as discussed below:
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a.
Treatment System UnitPiping and Instrument Di
a
accurately
example represent
the
1, grams
contain (P& ids) M-1102A & B
dampers,T48-F015as-built and several errors and , Standby Gas
F016M-11028
condition
of the thus shows do notthe south
ducts
166 foottoelevation.
the northconnectedstai to 6 inch ductsstairwell
For registe
The rwell, corridors, and and isolation
ele, in parallel with
shows the SGTSdirectly to the 16 inchvator
south
duct
reducingactually located at 139 fAtoequipment
stairwell duct is a
adjacent shaft at
room
the stairwell.ctually the
onconnected
eet.
located on the 139 footfitting M-11028on showsthe M-11028
fans
they are
and
building.
dampers T48-F021 119 foot elevationis wheelev
elevation. and F02ann 8it inch to 14 inch
is actually
b.
actually located on 2 thein208 theM-1102A
f ushows
ating the reci
SGTS filter train diffe oot elevation of the a ry
auxilienclo
identified as ton, functioand R003B are not labeledren
c.
as to instrument number
n
s PDI-R002A, R002B, S
The eight inch ducts in t
,
However, they are
auxiliary
upstream
are not building elevatis alled to draw down the f
of water
areposition
labeled, and
they controlled
operated
are
bye th
dampers T48-F019on 208 feet have ma
the of and F020ampers installed
shut.
The li the dampers.not
501.identified on
The inspector
thep ap liThe dampers
verified open.censee cable P&ID nor
fuel handl If was
they werepromptly notifiedThey could appeared
not
y op determineto be full
operation. ing area so that
The
as designed during anshut, the
licensee SGTS
could be would not dthe
the rest ofinstalledoseforexplained the purp
that the manual
not normally shownthe
procedural controls toon the P&ID. g and auxiliary damper n
buildinnf balancing
wa s
d. position when verifying ensure the The licensee committedthat
dampers s are balancing dam
Motor operability of the are in the to implement
system.
F025A and F026B respectioperated butterfly
vely
valve
as-balanced
as F025-A
versus power and F026-B
.
i s T48-F025 and F026 are l b
This ,s
Inspection Report and onexample
another the P&ID they areT48-
a eled id
in paragraph 4 of supply labeling
this 4- 1.
416/86 problemc
whi h
of the entified
Correction report. Another similar problemwas discussed in previous Followup Item of the
was identified
graph 4 will416/87-14 -1 0above deficiencies
be tracked with The P&ID shall
this item. deficienciesbe tracked ounder Inspect
No violations or deviati identified in para r
ons were identified.
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a. Piping and Instrument Diagrams (P& ids) M-1102A & B, Standby Gas Q
Treatment System Unit 1, contain several errors .and thus do not I
accurately represent 'the as-built condition of the system. For i
example, M--1102B shows the south stairwell registers and isolation
dampers T48-F015 and F016 connected to 6 inch ducts, in parallel with
ducts to the north stairwell, corridors, and elevator shaft at the
166 foot elevation. The south stairwell duct is actually connected
directly to the 16 inch duct adjacent to the stairwell. M-11028 )
shows the SGTS A equipment room on elevation 119 feet when it is
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actually located at 139 feet. M-1102B shows an 8 inch to 14 inch
reducing fitting on the 119 foot elevation when it is actually
located on the 139 foot elevation. M-1102A shaws the recirculating
fans and dampers T48-F021 and F022 in the enclosure building when
they are actually located on the 208 foot elevation of the auxiliary
building.
b. SGTS filter train differential pressure instruments PDI-R002A, R002B,
and R003B are not labeled as to instrument number. However, they are
identified as to function. j
c. The eight inch ducts installed to draw down the fuel handling area of
auxiliary building elevation 208 feet have manual dampers installed
upstream of water operated dampers T48-F019 and F020. The dampers
are not labeled, and are not identified on the applicable P&lD nor
are they controlled by the 501. The inspector could not determine
the position of the dampers. They appeared to be fully open or fully
shut. The licensee was promptly notified so that they ' could be
verified open. If they were shut, the SGTS would not draw down the
fuel handling area as designed during an event calling for SGTS
operation. The licensee explained that the manual damper -was
installed for the purpose of balancing the fuel handling area with
the rest of the auxiliary building and that balancing dampers are
not normally shown on the P&ID. The licensee committed to implement
procedural controls to ensure the dampers are in the as-balanced
position when verifying operability of the system.
d. Motor operated butterfly valves T48-F025 and F026 are labeled T48-
F025A and F026B respectively, and on the p&ID they are identified
as F025-A and F026-B. This is another example of the safety train
versus power supply labeling problem which was discussed in previous
Inspection Report 416/86-41. Another similar problem was identified
in paragraph 4 of this report.
Correction of the above deficiencies shall be tracked under Inspector
Followup Item 416/87-14-01. The p&ID deficiencies identified in para-
graph 4 will be tracked with this item.
No violations or deviations were identified.
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8. Reportable Occurrences (90712 & 92700)
The below listed event reports were reviewed to determine if the informa-
tion provided met the NRC reporting requirements. The determination
included adequacy of event description and corrective action taken or
planned, existence of potential generic problems and the relative safety
significance of each event. Additional inplant reviews and discussions
with plant personnel as appropriate were conducted for the reports
indicated by an asterisk. The event reports were reviewed using the
guidance of the general policy and procedure for NRC enforcement actions,
regarding licensee identified violations.
The following License Event Reports (LERs) are closed.
LER No. Event Date Event
*86-019 December 15, 1984 Fire rated penetrations not properly
sealed.
*86-038 October 22, 1986 Secondary containment isolation during
surveillance testing.
*87-006 May 1, 1987 Inadvertent Reactor Core Isolation
Cooling System isolation due to
personnel error.
*87-007 May 1, 1987 Inservice testing of Standby Liquid
Control (SLC) System check valves
inadequate due to procedural error.
No violations or deviations were icantified.
9. Operating Reactor Events (93702)
The inspectors reviewed activities associated with the below listed
reactor events. The review included determination of cause, safety
significance, performance of personnel and systems, and corrective action.
The inspectors examined instrument recordings, computer printouts, opera-
tions journal entries, scram reports and had discussions with operations,
maintenance and engineering support personnel as appropriate.
At 2:20 p.m., on May 27, 1987, an inadvertent downshift of both recircu-
lation pumps to the Low Frequency Motor Generator (LFMG) power supply
occurred. The plant was operating at approximately 100% thermal puwer and
97% core flow. After the downshift the operators stabilized the plant at
approximately 42% thermal power and 35% core flow. Technicians were
working MWO 171307 which affects only the recirculation control valve
runback circuitry. Although recirculation pump ant 1-cav1tation circuitry
(which could cause a recirculation pump downshift) is located in the same
panel as the recirculation valve runback circuitry, and did alarm during
the event, nothing indicated what actually caused the event. The licensee
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investigated to determine the cause of the pump downshift but nothing l
specific was identified. After troubleshooting and verifying operability (
of the circuitry, the plant was taken back up to 100% thermal power. The I
flow control valves and recirculation pumps functioned as designed.
The inspectors reviewed the licensee's administrative controls to deter- )
mine compliance to Technical Specification (TS) 6.2.3, Independent Safety i
Engineering Group (ISEG) requirements. Nuclear Plant Engineering (NPE)
procedure 01-701, Onsite and Offsite Document Review, directs documenta-
tion of evaluations performed by the Operational Analysis Section (OAS)
acting as the ISEG referred to in TSs. The offsite and onsite documents
subject to review are listed and the review process is defined. Also, the
criteria for evaluation and analysis is defined. In report 0A 86-011,
Assessment of the ISEG Function at G3NS, dated July 21, 1986, the licensee
examined the requirements for the ISEG in NUREG-0737, Item I.B.1.2, and in
the TSs. The report concluded that MP&L (now SERI) was satisfying all the
requirements but certain improvements should be made. The inspectors
concur with the conclusions and recommendations in the report. Although
the recommendations have not been implemented at this time, the licensee
stated they intend to implement the recommendations as manpower and budget
constraints permit. The OAS submits a monthly summary of plant operating
experience to management (Vice President, Nuclear Engineering and Support,
and Vice President, Nuclear Operations). The inspectors reviewed report 1
0A-87-011 which covered operational events for the period of April 1,1987 l
through April 30, 1987. Included as an attachment was report 0A-87-010, l
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ISEG Review of the SSW and HPCS Systems, i
In paragraph 9 of NRC Inspection Report 416/87-12, the inspectors reported
, a problem the licensee was having with the reactor vessel water level l instruments. On May 11, 1987, the licensee told the inspectors that a l channel check revealed a 4 inch level differential between certain reactor
vessel water level instruments. This was the licensee's limit for i
initiating an investigation. The condition was corrected by refilling !
the A reactor vessel water level reference leg. Within a few days the
condition reappeared. Troubleshooting was conducted by isolating the
various detectors on the A reference leg and walking down the system to
find leaks. Two minor packing leaks were found, one of which was on the A
reference leg. The leakage was stopped by backseating the valves. The
various detectors were isolated to determine if detector or equalizer
valve leakage existed which would cause reference leg draining in excess
of the makeup provided by the condensing pot. There was no indication of
such leakage. The 1.censee is currently monitoring the levels for any
changes. One theory is that non-condensable gas may have collected in the
condensing pot thus reducing the effective condensing surface area.
The licensee is exploring other possibilities with the assistance of
General Electric. The resident inspectors will conduct routine followups
and report any further developments.
On May 20, 1987, while working on a Design Change Package (DCP) to
upgrade some non-safety related Bailey Model 711 Recorders, Nuclear Plant
Engineering (NPE) personnel discovered that the field mounting configura-
tion of certain Bailey Model 711 Recorders was not consistent with the
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seismic qualification test configuration. Systems affected were Reactor
Vessel, Area Radiation Monitoring, Residual Heat Removal, Suppression Pool
Makeup, Combustible Gas Control, Containment and Drywell Instruments,
Standby Service Water, Standby Gas Treatment System, and Control Room
l HVAC. Most of the recorders are mounted in the Control Room. The test
configuration differed from the installed configuration at GGNS in that a
supplemental restraining device was installed during the test to prevent
the recorders from drifting out of the shelf mounting assembly. Although-
the restraining device was not installed at GGNS, the' licensee determined
by analysis that the device would not be needed because the qualification
test was conducted at excitation levels significantly higher than the GGNS
design basis Safe Shutdown Earthquake (SSE). The test ranged between 10
and 15 gravities compared with the GGNS required level of 2 gravities. ,
Thus NPE concluded that the as-mounted recorders would remain functional !
following a seismic event. General Electric agreed with this determination.
The licensee also sent the same recorders to Wyle Laboratories to confirm
the qualification to GGNS requirements. The results were satisfactory, i
The generic implications of this issue are being reviewed by the licensee i
pursuant to 10 CFR 21. l
At 12:10 p.m., on May 29, 1987, a momentary loss of voltage was experienced
on the 115 kV Port Gibscn power feed. At the time, the Division 3 (High
Pressure Core Spray) ESF bus was being fed by transformer 12 which in turn
was connected to the 115 kV feeder. The momentary loss was sensed by the
Division 3 ESF bus resulting in an automatic start of the Division 3
Diesel Generator (DG). The DG started satisfactorily and all associated
equipment functioned properly. One of the inspectors was in the control q
room at the time and witnessed the event. Orerator actions appeared- 1
appropriate and procedures were referred to and followed. The NRC d
Operations Center was notified at 2:07 p.m., in accordance with 10 CFR
50.72.
On May 29, 1987, the A train Standby Service Water (SSW) pump inadvertently ,
started with no apparent automatic initiation signal present. The reactor !
was at 83% thermal power. Plant operation was not affected. Technicians )
were working Maintenance Work Order E72626 to troubleshoot and correct a l
problem where the SSW A pump and the Residual Heat Removal (RHR) A pump !
room fan coil unit would not shut down after running and then securing the ]
RHR A pump. The technicians found the linkage for auxiliary switch AG in
the RHR A pump control breaker disconnected. This prevented the SSW A -
pump and RHR A pump room fan coil unit from turning off when RHR A was
secured. The technicians replaced the linkage and when the RHR A pump
l control breaker was racked back in the SSW A pump inadvertently started. !
The technicians then adjusted the linkage, checked the auxiliary switch
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contacts, and restored the system to normal operation. ;
On June 2,1987, the Region I Morning Report stated that Boston Edison i
Company (Pilgrim Plant) has deterinined that a significant percentage of
General Electric (GE) type HFA auxiliary relays installed in safety
related applications at Pilgrim are susceptible to mechanical binding of
the armature. The report referred to a GE Service Advice Letter (SAL)
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188.1 which identified this potential problem on November 14, 1986. The
inspectors followed up to see if SERI had knowledge of the SAL and if
actions had been (or were being) taken to determine if the problem exists
at GGNS, and if so, what was done to eliminate the problem. The licensee
did have the SAL and had determined that in the two failure cases
reported, the applications called for AC powered, continuously energized
HFA relays. Their investigation revealed eight similar applications at
GGNS, and all are in the Reactor Protection System in the turbine control
valve fast closure and turbine stop valve closure circuits. The licensee '
is p,reparing MW0s to perform the prescribed relay tests. Due to the :
sensitivity of the system applications and thus the potential for an
inadvertent reactor trip, the work orders were scheduled for the next
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shutdown. The inspectors will follow up and report the results of the
relay tests and any corrective actions taken. This shall be Inspector
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Followup Item 416/87-14-02.
On June 14,1987 the 0400 to 0500 hourly fire watch patrol failed to meet
the requirement of TS 3.7.7.a action statement on each 'of five auxiliary
) building fire doors, in that the hourly patrol was performed from one to l five minutes late. The apparent cause was failure of one individual to
attend to his responsibilities in a timely manner. The licensee
identified the incident on Incident Report 87-6-1, dated June 15, 1987
and took prompt and adeguate corrective action including disciplinary,
action against the individual. The inspectors evaluated the significance
of the event and licensee actions taken, and concluded that the five
criteria listed in Section V. A. of 10 CFR Part 2, Appendix C (1986),
General Statement of Policy and Procedure for NRC Enforcement Actions,
have been met, thus a notice of violation will not be issued.
10. Inspector Followup and Unresolved Items (92701)
(Closed) Inspector Followup Item 416/87-12-02. By letter dated May 15,
1987(AECM-87/0098), the licensee stated that qualification testing of the 1
subjectwirewascompletedonMay 12, 1987, anc the test results indicated '
that the wire would withstand its normal and accident environment and
would continue to perform its function Post-LOCA in the hydrogen analyzers
for a minimum service life of five years. Also, the licensee is
conducting further environmental qualification testing of the wire to l
further extend the qualified life of the wire.
(Closed) Inspector Followup Item 416/87-10-06. .he licensee replaced the
remote start pushbutton for the Standby Diesel Generator 12 under
Maintenance Work Order E71618. The removed pushbutton .was operated
repeatedly while monitoring the normally open contacts with a volt-ohm
meter and no intermittent actions of the contacts were identified. No
conclusive evidence of failure of this switch could be determined. No
further action is necessary.
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(Closed) Inspector Followup Item 416/86-32-06. The inspectors reviewed
the closed Design Change Implementation Package for Design Change Packages
81/5003, 85/3064 and 85/3098. These packages covered the installation of
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electrical isolation switches between the' control room and the Division 1 I
remote shutdown panel, which was required by License Condition 2.C.(22). I
All work appears to have been satisfactorily completed, the appropriate
retests were implemented, and the applicable documents and procedures
updated.
(Closed) Inspector Followup Item 416/87-10-05. The licensee changed SLCS
surveillance procedure 06-0P-1C41-M-0001 to provide better control over s
the quarterly surveillance test, and submitted the revised procedure to i
the inspectors for review prior to the next scheduled test. The l
inspectors noted that the changes did not appear adequate, and suggested
l that the licensee reconsider using the revised procedure as written. The
licensee implemented additional minor changes and then the test was l
attempted on June 10, 1987, with one of the inspectors present. The test i
was unsuccessful, due to both procedural and test equipment inadequacies.
Examples of some of the problems were as follows:
Paragraph 2.3 of the procedure cautions the operator to never permit
the SLC pumps to pump against a shutoff head, but paragraph 5.2.19
directs the operator to stop the pump and close the only open path,
drain valve 1C41-F025. Due to the potential of shutting F025 before
the pump coasts down to a full stop, the operator felt compelled to
open another path, F016, which was not provided for in the procedure.
Paragraph 3.3 specifies Heise test pressure gauges, and paragraph
5.5.5 installs one of the pressure gauges at the SLC pump discharge
test block. The gauge was so sensitive to the violent pressure
oscillations generated by the SLC pump, the snubber had to be
adjusted so tight the gauge did not reflect actual pressure. This
resulted in two lifts of relief valve F029A, which is prohibited by
the procedure in two caution notes. This is an exemple of inadequate
test equipment specified by the procedure.
The individual who monitored and snubbed the discharge pressure test
gauge was not in control of the individuals operating the throttled
valves as directed by paragraph 5.2.4.6, nor should he be.
Paragraph 5.2.7 NOTE requires the operator to verify no in-leakage to i
the test tank. This is not possible in the current system
configuration because there is an orifice bypass around F014 that
continuously and slowly fills the test tank when F031 is open. If
there are any delays during the test (there was a delay on June 10
1987 and another delay on June 16,1987), the tank will overflow (and
it did overflow both times). This is not addressed in the procedure.
Proper sequencing would have prevented the overflow.
Paragraphs 5.2.9 and 5.2.10 required the operator to open F017 and
F201 respectively. These valves would already be open when the
second pump is tested per 5.2.24. If a detailed procedure directs
the operator to open a valve, he should expect to find it shut and
vice versa. Correct wording would be "open or check open". This was
,
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done by TCN to paragraph 5.2.27, which is a similar circumstance, but !
not to all paragraphs where it would have been appropriate.
The above problems and other similar examples were discussed with the
licensee. Technical Specification 6.8.1.c requires that wri,tten proce-
dures shall be established, implemented and maintained covering surveil-
lance and test activities of safety related equipment. Contrary to this )
requirement, the licensee failed to provide and implement an adequate
procedure for the surveillance testing of SLCS, as evidenced by the
deficiencies identified in surveillance procedure 06-0P-1C41-M-0001. This
shall be violation 416/87-14-03.
The licensee subsequently made more changes to the procedure, verified !
that the relief valves were lifting at the correct pressure, and deter-
mined that the check valves downstream of the pumps were not obstructed. 1
On June 15, 1987, SLC A was successfully tested and on June 16, 1987, SLC i
B was successfully tested. As of the end of this inspection period the
inspectors noted that the surveillance procedure still needed minor
improvements. The licensee was informed of this and committed to ensure
that this and all other safety related procedures are written to
facilitate formal, ste,p-by-step implementation. The licensee was
requested to address this in the response to violation 416/87-14-03 above.
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