ML20214L283
| ML20214L283 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 08/22/1986 |
| From: | Butcher R, Dance H, Will Smith NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20214L275 | List: |
| References | |
| 50-416-86-21, NUDOCS 8609100053 | |
| Download: ML20214L283 (9) | |
See also: IR 05000416/1986021
Text
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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REGION 11
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101 MARIETTA STREET.N.W.
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ATLANTA. GEORGI A 30323
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Report No.:
50-416/86-21
Licensee: Mississippi Power and Light Company
Jackson, MS 39205
Docket No.:
50-416
License No.:
Facility Name: Grand Gulf
Inspection Conducted: Jul
15 - August 8, 1986
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Inspe tors:
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R.
s Butcher, Seni<0E.Re'sident Inspector
D&t Signed
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W. F. Sniith, Resident 9(spector
Okt Signed
App ved by:
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H. C. Dance, Section Chief
0%te Sfgned
Division of Reactor Projects
SUMMARY
Scope:
This routine inspection was conducted by 'the resident inspectors at the
site in the areas of Licensee Action on Previous Enforcement Matters, Operational
Safety Verification, Maintenance Observation, Surveillance Observation, ESF
System Walkdown, Reportable Occurrences, Operating Reactor Events, Inspector
Followup and Unresolved Items, Design Changes and Modifications, Performance
Indicator Trial Program, Preparation for Refueling, and Refueling Activities.
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Results: One violation with two examples was identified: 1) Failure to follow a
system operating procedure in that'a Standby Liquid Control (SLC) system pressure
instrument was found isolated and 2). Failure to follow a surveillance procedure
thereby causing an inadvertent start of Standby Diesel Generator (SDG) 12.
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8609100053 860825
ADOCK 05000416
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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 Operaitons
- J. D. Bailey, Compliance Coordinator
M. J. Wright, Manager, plant Support
- L. F. Daughtery, Compliance Superintendent
D. G. Cupstid Start-up Supervisor
R. H. McAnulty, Electrical Superintendent
R. V. Moomaw, 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
Other licensee empioyees contacted included technicians, operators, security
force members, and office personnel.
- Attended exit interview
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2.
Exit Interview (30703)
The inspection scope and findings were summarized on August 8,1986, with
those persons indicated in paragraph 1 above. The licensee did not identify
as proprietary any of the materials provided to or reviewed by the
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inspectors during this inspection.
The licensee had no comment on the
following inspection findings:
a.
416/86-21-01, Inspector Followup Item.
Discrepancies between system
operating procedure requirements, Piping and Instrument Diagram (P&ID)
requirements, and actual valve positions in SLC System (paragraph 7).
b.
416/86-21-02, Violation. First example:
Failure to follow a system
operating procedure in that a SLC system pressure instrument was found
isolated (paragraph 7). Second example: Failure to follow a surveil-
lance' procedure thereby causing an inadvertent start of SDG 12
(paragraph 9).
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3.
Licensee Action on Previous Enforcement Matters (92702)
(Closed) Deviation 416/84-16-02.
Inspection report 416/86-13, paragraph 9,
documents the review cf maintenance personnel training and no adverse
findings were noted. Administrative Procedure (AP) 01-S-07-1 was revised to
require the discipline maintenance supervisor / superintendent to determine
whether special training or direct supervision is required by craft
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personnel to perform specific work. AP 01-S-07-33 was revised to define the
requirements for the qualification and certification of contract personnel.
No further action is required.
(Closed) Violation 416/84-16-03, Maintenance Contractor Certification
Program.
See corrective action for deviation 416/84-16-02 above.
(Closed) Violation 416/84-16-04, Maintenance Personnel Qualifications. See
corrective action for deviation 416/84-16-02 above.
4.
Operational Safety Verification (71707)
The inspectors kept themselves informed on a daily basis of the overall
plant status and any significant safety matters related to plant operations.
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 onsite.
Observations included instrument readings, setpoints and recordings status
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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 or. site, selected ESF systems were confirmed operable.
The
confirmation was made by verifying the following: Accessible valve flow
path alignment, rnwer supply breaker and fuse status, major component
leakage, lubricatior., 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,
radiation protection controls, physical security, problem identification
systems, and containment isolation.
No violations or deviations were identified.
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5.
Maintenance Observation (62703)
During the report period, the inspectors observed portions of the main-
tenance activities listed below. The observations included a review of the
work documents for adequacy, adherence to procedure, proper tagouts,
adherence to technical 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 12C929, Replace Inadequate Conductivity Transmitters and Elements
MWO EL1018, HPCS Pump Room Cooler Motor, Megger Motor and Clean Breaker
52-170117.
MWO ME1648, Inspection and Lubrication of Auxiliary Refueling Platform
and Hoist.
MWO IN3729, Calibration of FPCC Holding Pump Suction Pressure
Transmitter.
No violations or deviations were identified.
6.
Surveillance Observation (61726)
The inspector observed the performance of portions of the surveillances
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
surveillances, 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-IC-SP64-SA-1001, Rev.22, PGCC Halon System Detectors and Supervisory
Panels Functional Test.
06-0P-1T48-M-0001, Rev.26, Standby Gas Treatment Operability.
07-S-53-109, Rev.4, Calibration of United Electric Pressure Switch for
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CRDH Pump Suction Backwash Filter.
06-IC-1821-M-1002, Rev.25, Reactor Vessel Hi/ Low Pressure (RPS/RHR
Isol) Functional Test.
No violations or deviations were identified.
7.
Engineered Safety Feature System Walkdown (71710)
A complete walkdown was conducted on the accessible portions of the Standby
Liquid Control System (SLCS). The walkdown consisted of an inspection and
verification, where possible, of the required system valve and breaker
alignment, including valve power available and valve locking where required;
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instrumentation valved in, functioning, and significant process parameter
values are consistent with normal expected values; electrical and instrumen-
tation cabinets free from debris, loose materials, jumpers and evidence of
rodents; and system free from other degrading conditions.
The SLCS was found to be operational such that it would perform its intended
function should it be called upon; however, there were discrepancies
identified by the inspectors as discussed below:
a.
During the comparison between the SLC System Operating Instruction,
(S0I) 04-1-01-C41-1, Revision 20, and the SLCS P&ID M-1082, Revision
15, the inspectors found that inboard isolation, valve C41-F151, is
required to be locked shut by the valve lineup. However, Attachment I
of the SOI and the P&ID show the same valve locked open. The valve was
properly positioned.
The inspectors also noted during the system
configuration inspection that the outboard stop check handwheel valve
C41-F006 was required to be open by the SOI, but the valve was in fact
locked open.
The valve was in its correct position. The inspectors
informed the licensee of the above discrepancies.
This shall be
tracked for correction under inspector followup item 416/86-21-01.
b.
On July 29, 1986 the inspectors found valve C41-FX001, root valve for
pressure gage R003 and pressure transmitter N004, shut when it should
have been open in accordance with the above SOI.
The pressure gage
indicated 425 psig, which was abnormal for SLC pump discharge pressure
(pressure should be nearly zero when the system is not pumping). The
SLCS pressure indicator in the control room indicated zero pressure.
When the valve was opened, the gage continued to indicate 425 psig. A
work request was initiated and the gage was subsequently repaired.
Technical Specification (TS) 6.8.1 states that written procedures shall
be established, implemented and maintained covering the applicable
procedures recommended in Appendix A of Regulatory Guide (RG) 1.53,
Revision 2, February 1978. Section 4.d in Appendix A of RG 1.33 lists
the SLCS as one of the recommended systems.
Failure to follow SOI
04-1-01-C41-1, resulting in the isolation of SLC pump discharge
pressure instrumentation, is the first example of the violation of
TS 6.8.1 (86-21-02).
8.
Reportable Occurrences (90712 & 92700)
The below listed event reports were reviewed to determine if the information
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.
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The following License Event Reports (LERs) are closed.
LER No.
Event Date
Event
- 83-185
December 1, 1983
Loss of power to Division I ESF
Bus & B0P loads86-008
February 24, 1986
Complete
response
time
of
EOC-RPT System not measured
86-010
April 3, 1986
Inadvertent
isolation
of
Primary and Secondary
Containment
- 86-011
April 7, 1986
TS Shutdown due to open Safety
Relief Valves
- 86-020
June 3, 1986
Non-Qualified Relay could cause
Loss of SGTS
The event of LER 86-020 was discussed in Report 50-416/86-17 and is
inspector followup item 416/86-17-05.
The event of LER 86-011 was discussed in Report 50-416/86-11 and violation
416/86-11-03.
No other violations or deviations were identified.
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, operations journal
entries, scram reports and had discussions with operations maintenance and
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engineering support personnel as appropriate.
a.
On July 11, 1986, while preparing to perform Surveillance Procedure
(SP) 06-0P-1P75-M-0002, Standby Diesel Generator (SDG) 12 Functional
Test, the SDG 12 was inadvertently started.
Paragraph 5.2.2 of SP
06-0P-1P75-M-0002 states to place SDG 12 in maintenance mode and
simultaneously press the remote (located on panel P864 in the control
room) and local (located on panel P401 in the SDG room) maintenance
mode select pushbuttons.
The control room operator inadvertently
pushed the SDG 12 start button instead of the maintenance mode select
button.
The SDG started and was immediately shut down.
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states that written procedures shall be established, implemented and
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maintained covering surveillance and test activities of safety related
equipment. The failure to follow SP 06-0P-IP75-M-0002, resulting in
the inadvertent start of SDG 12, is the second example of the violation
of TS 6.8.1 (86-21-02).
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b.
At 3:20 p.m., on July 25, 1986, with the reactor at 885 MWe the reactor
scrammed on a Scram Discharge Volume (SDV) high-high water level. The
reactor operators carried out the scram procedure and all systems
operated as designed. A few minutes prior to the scram an operator had
noticed residual heat removal train A high conductivity alarm and the
alarm cleared with downscale indication on the conductivity meter.
Shortly thereafter, the plant chiller trip alarmed, circulating water
makeup flow was oscillating, several Division I valves on panel P870
had no valve position indication, plant service water header pressure
was high, and the scram pilot valve header pressure low alarmed on the
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P680 panel. The control room operator started the Unit 1 instrument
air compressor and sent operators to the instrument air compressors to
verify local valve positions.
The operator noticed reactor vessel
water level had dropped to +20 inches and was prepared to manually
scram the reactor when the automatic scram on SDV high-high level
occurred. When investigating the reason for the loss of valve position
indication noted above, the operators found main power breaker
52-153102 on panel 15831 open. Closing breaker 52-153102 restored the
instrument air and plant service water systems. Investigation revealed
several modification workers were working on a panel next to breaker
52-153102 and it appeared that someone inadvertently moved the breaker
to the open position.
The opening of breaker 52-153102 resulted in
various auxiliary building Division I isolation valves going closed
which caused the 1oss of instrument air and plant service water. The
loss of instrument air eventually allowed the scram valves to open
which permitted control rods to start scramming individually. When the
scram discharge volume water level reached the high-high level a scram
signal was generated and all remaining control rods scrammed.
The
operator had armed the manual scram push buttons and was preparing to
manually scram the reactor when the automatic scram occurred.
The
alarm typewriter data indicates that the first rod scram valve opened
at 3:20 p.m., and the automatic scram was initiated 43 seconds later.
Data traces from the General Electric Transient Analysis Recorder
System (GETARS) show a perceptible decrease in power (MWe) approxi-
mately 15 seconds prior to the automatic scram. At that same time the
narrow range water level started trending down while feed water flow
and reactor core flow started increasing.
The cause of the event is
the inadvertent opening of breaker 52-153102 by personnel working in
the area. The operators responded to the event, the plant recovery was
normal and all systems functioned as designed.
The Site Director
stopped modification work in sensitive plant areas and before work can
resume, operations must review the work area with the appropriate
supervisor to ensure proper precautions are in place prior to starting
work. The reactor had been operating approximately 105 days contin-
ucusly at the time of the scram.
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c.
At 9:54 p.m. , on July 30, 1986, the reactor operator was withdrawing
control rod 20-45 from notch 08 to notch 10 in a single notch
withdrawal. Rod 20-45 continued to slowly withdraw past notch 10 and
eventually stopped at full out (notch 48). The operator attempted to
stop rod 20-45 by giving an insert signal.
This appeared to have
momentarily slowed the withdrawal motion but did not stop the
withdrawal. The rod was de-selected and reselected and the rod select
clear button was pushed during the withdrawal with no effect. During
the withdrawal sequence a rod drift alarm occurred and a rod block was
received. Also, the operators reduced reactor power to approximately
62% during the rod withdrawal. The rod withdrawal event took approxi-
mately three minutes. When the rod reached notch 48 a coupling check
was performed and then the rod was placed at notch 46 to verify the
ability to insert.
It was verified that rod 20-45 was separated from
all other inoperable withdrawn control rods by at least two control
cells in all directions which satisfied Technical Specification 3.1.3.1
action statement for an inoperable control rod. To balance core power
distribution the three symmetrical control rods for rod 20-45 were also
pulled to notch 46.
The licensee then decided the most conservative
action would be the alternate action discussed in Technical Specifi-
cation 3.1.3.1, and that was to drive rod 20-45, and the corresponding
symmetrical control rods, to full in (notch 0).
Rod 20-45 was then
hydraulically isolated by shutting valves C11-F103 and C11-F105.
On
July 31, 1986, after discussions with GE, the licensee replaced the
withdraw solenoid valve C11-F422 and cycled rod 20-45 through several
single notch withdraw and insert cycles successfully. The licensee has
subsequently revised emergency operating instruction 05-1-02-IV-1,
Control Rod / Drive Malfunctions, giving operators instructions for
actions to take in case a control rod continues to withdraw with no
withdraw command present.
Inspection of the removed C11-F422 valve did
not reveal the cause of the withdrawal event.
The licensee concluded
that debris trapped under the seat of the C11-F422 valve during the
original notch withdrawal cycle would allow drive water pressure to
hold the collet fingers out, thus allowing rod 20-45 to drift by its
own weight to the full out position, and subsequent cycling of C11-F422
had flushed out the seating surface and permitted normal operation
later.
10.
Inspector Followup And Unresolved Items (92701)
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(Closed) 85-28-03, Inspector Followup Item.
The licensee has installed
redesigned covers on the concrete pits which contain fuel oil fill and drain
valves for the Division I, II & III diesel generators.
The new covers
should prevent excessive water from entering the pits.
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11. Design, Design Changes and Modifications (37700)
The inspectors reviewed Design Change Package (DCP) 84/3516 which replaced
existing time delay relays in the control room heating, ventilating and air
conditioning (HVAC) system with qualified time delay relays. Maintenance
Work Orders (MW0s) P61345 and P61346 were the work control documents used
for this modification. The documentation was properly signed and readily
retrievable. A completed 10 CFR 50.59 safety evaluation was in the package.
The listed drawings were verified to have been updated to reflect this
modification. An appropriate operability retest was accomplished prior to
returning the system to service.
No violations or deviations were identified.
12.
Performance Indicator Trial Program (25580)
NRC Temporary Instruction 2515/80, Data Collection for the Performance
Indicator Trial Program, was issued on June 27, 1986, to provide guidance
for the collection of plant data in support of the performance indicator
trial program.
This data would be used to augment the Systemmatic
Assessment of Licensee Performance (SALP) process and provide a more timely
identification of declining performance.
Grand Gulf was chosen to be
included in this trial program of data collection. The resident inspectors
collected the data requested and forwarded it to regional management.
No violations or deviations were identified.
13.
Preparation For Refueling and Refueling Activities (60705 & 60710)
The inspectors reviewed selected refueling procedures for technical adequacy
and incorporation of technical specification requirements. The licensee has
not completed issuing final versions of many refueling procedures at this
time.
The licensee was interviewed regarding lines of supervision and
responsible people have been assigned in given areas. Also, the licensee
will issue a refueling organization chart which will be available to plant
personnel defining areas of responsibility during the refueling outage. A
refueling outage work schedule has been issued that defines what emergency
core cooling systems or shutdown cooling systems are required during defined
outage work stages, what work will occur in what order / time frame and
assumptions used to construct the schedule are defined in notes.
New fuel
was received and stored onsite several years previously so review of new
fuel receipt and inspection was not conducted at this time.
No violations or deviations were identified.