ML20140C553
| ML20140C553 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 01/10/1986 |
| From: | Butcher R, Caldwell J, Panciera V NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20140C540 | List: |
| References | |
| 50-416-85-45, NUDOCS 8601280339 | |
| Download: ML20140C553 (14) | |
See also: IR 05000416/1985045
Text
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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101 MARIETTA STREET, N.W.
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ATLANT A, GEORGt A 30323
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Report No.:
50-416/85-45
Licensee:
Mississippi Power And Light Company
Jackson, MS 39205
,
Docket No.:
50-416
License No.:
Facility Name:
Grand Gulf 1
Inspection Conducted : November 16 thru December 20,1985
Inspectors: [
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H.~C. sur.cner, Sen;#F
idenEinspector
Uate Signed
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Approvedby:\\>{},1. n , aMJf,&
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W W. PanWeFa', Chief, Project Section 28
Aat4 Signed
Division of Reactor Projects
SUMMARY
Scope:
This routine inspection entailed 202 resident inspector-hours at the
site in the areas of Operational Safety Verification, Maintenance Observation,
Surveillance Observation, ESF System Walkdown, Reportable Occurrences, Operating
Reactor Events, Inspector Followup and Unresolved Items, and License Conditions.
Results:
Violations - failure to close LLRT valves by normal means, failure
to adequately train personnel performing activities affecting quality, and
failure to follow procedures when performing diesel generator maintenance.
Deviation - failure to incorporate periodic test of ESF room coolers.
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REPORT DETAILS
a
1.
Licensee Employees Contacted
J. E. Cross, Site Director
- C. R. Hutchinson, General Manager
R. F. Rogers, Technical Assistant
,
- J. D. Bailey, Compliance Coordinator
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M. J. Wright, Manager, Plant Operations
L. F. Daughtery, Compliance Superintendent
D. Cupstid, Start-up Supervisor
R. H. McAnulty, Electrical Superintendent
- R. V. Moomaw, Manager, Plant Maintenance
- B. Harris, Compliance Coordinator
J. L. Robertson, Operations Superintendent
L. Temple, I & C Superintendent
i
Other licensee employees contacted included technicians, operators, security
force members, and office personnel.
- Attended exit interview.
2.
Exit Interview
The inspection scope and findings were summarized on December 20, 1985, 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
inspectors during this inspection.
The licensee had no comment on the
following inspection findings:
a.
Unresolved Item 85-45-01; Significance of Plugging of ESF Room Coolers.
(Paragraph 5.a)
b.
Deviation 85-45-02; Failure to Incorporate Periodic Test of ESF Room
,
Coolers to Ensure System Operation.
(Paragraph 5.a)
c.
Unresolved Item 85-45-03; Unusable Fuel Oil Tank Volume.
(Paragraph
5.b)
d.
Unresolved Item 85-45-04; I;SIV Accumulator Check Valves Not Addressed
in the IST Program.
(Paragraph 5.c)
e.
Inspector Followup Item (IFI) 85-45-05; Permissible Leakage Rate for
(Paragraph 7)
f.
Violation 85-45-06; Failure to Close LLRT Valves by Normal Means.
(Paragraph 7)
g.
Violation 85-45-07; Failure to Adequately Train Personnel Performing
Activities Affecting Quality.
(Paragraph 9.a)
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h.
IFI 85-45-08; TDI Diesel Generator Intake & Exhaust Valve Spring
Inspection.
(Paragraph 9.c)
i.
IFI 85-45-09; TDI Diesel Generator Air Intake Silencer Defect
Inspection.
(Paragraph 9.d)
j.
Unresolved Item 85-45-10; Licensee Identified Discrepancies in
Environmental Qualification Program.
(Paragraph 9.e)
k.
Violation 85-45-11; Failure to Follow Procedures when Performing Diesel
Generator Maintenance.
(Paragraph 10)
1.
IFI 85-45-12; Excessive Oil Around Diesel Generators and Existence of
Two Valves with Same Identification Number.
(Paragraph 8)
3.
Licensee Action on Previous Enforcement Matters (92702)
Not Inspected.
4.
Unresolved Items
An Unresolved Item is a matter about which more information is required to
determine whether it is acceptable or may involve a violation or deviation.
New Unresolved Items are discussed in Paragraph 5.a, 5.b, 5.c, and 9.f.
5.
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
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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 opera-
tion; 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 onsite, a selected ESF system is 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.
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General plant tours were conducted on at least a biweekly basis.
Portions
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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
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conditions; fire protection equipment; control of activities in progress;
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radiation protection controls; physical security; problem identification
systems; and containment isolation.
The following comments were noted:
a.
It came to the inspectors attention that during the performance of flow
balancing testing of the new Standby Service Water (SSW) B pump the
licensee discovered several Engineered Safety Feature (ESF) room
coolers plugged with sand.
The inspectors questioned the licensee
about the safety significance and reportability of plugged ESF room
coolers.
The licensee responded that they would have the Nuclear Plant
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Engineering (NPE) Department evaluate the flow through the coolers to
determine if flow was sufficient to ensure operation of the associated
ESF equipment during an accident and verify that the plant was not in
Pending NPE's evaluation the question of
safety significance and reportability will be identified as an
Unresolved Item.
(50-416/85-45-01).
Further review by the inspectors revealed a commitment in the FSAR,
paragraph 9.4.5.4, that the ESF room coolers be periodically inspected
,
to ensure that all normally operating equipment is functioning properly
'
and standby components are periodically tested to ensure system
operation.
From a discussion with the licensee, the inspectors
discovered that no program existed to inspect and test the ESF room
coolers as required by the FSAR.
In fact, the only reason the B train
s
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of ESF room coolers were discovered to be plugged with sand was due to
the testing of a new SSW pump.
The licensee has replaced the plugged
coolers and is in the process of testing the A train of the ESF room
coolers.
The failure of the licensee to have a program to inspect and
test the ESF room coolers as committed to in the FSAR will be identified
as a Deviation (50-416/85-45-02).
b.
During a review of one of the plant's Incident Reports (irs), the
inspectors discovered that the minimum level for the Emergency Diesel
Generator (EDG) storage tank appeared to be in error in the
non-conservative direction.
Consequently, the possibility existed that
the plant could have operated with the EDG fuel tank levels below the
limits allowed in Technical Specifications (TS).
This discovery by the
licensee resulted from a review of a TS change that was being imple-
mented ir.to a surveillance procedure to raise the minimum fuel storage
tank level to compensate for new larger Standby Service Water (SSW)
pump motors being placed on the EDGs' busses.
This review revealed a
Bechtel drawing (JK-M-2003) of the fuel oil tanks showing an unusable
fuel oil volume to be approximately 8,200 gallons.
This 8,200 gallons
'
was used to compute the new minimum fuel oil tank levels corresponding
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to 57,200 gallons needed to support the new SSW pump motors.
However
the figure of 8,200 gallons was not used to determine the level which
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corresponded to the previous TS limit of 48,000 gallons.
An unusable
volume of 3,400 gallons was used to determine the minimum level for the
TS limit.
The licensee has stated that conversations with the diesel
fuel transfer pump vendor, some informal calculations and statements in
the FSAR indicate that the value used for the unusable volume. (3,400
gallons) to determine the minimum EDG fuel oil tank level corresponding
to the 48,000 gallon TS requirement is appropriate for this applica-
tion.
The only documentation other than the FSAR which the licensee
can provide is the Bechtel drawing of the tank supplied to MP&L showing
the unusable volume to be 8,200 gallons.
The inspectors asked the licensee if the tank levels had ever dropped
to a level below 48,000 gallons when using 8,200 gallons as unusable
volume.
The assistant to the Operations Superintendent informed the
inspectors that a review of the EDG operations log revealed that the
only times the fuel oil levels were below 48,000 gallons, using 8,200
gallons as an unusable volume, were when the corresponding EDG was
declared inoperable for other reasons.
The licensee has been requested
to provide written documentation from the fuel pump vendor and MP&L's
Engineering organization to support their contention that 3,400 gallons
unusable volume is appropriate for this application.
Since the
possibility existed that the previous surveillance procedures would
have allowed the EDGs to be operated with fuel oil tank level below the
limit of ' Technical Specifications, this will be identified as an
Unresolved Item (50-416/85-45-03) pending the written documentation
supporting the licensee's previous values.
'
c.
A situation similar to that described in IE Information Notice 85-84,
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Inadequate Inservice Testing of Main Steam Isolation Valves, existed at
GGNS.
The instrument air system is a non-safety-related system which
normally supplies operating air for the Main Steam Isolation Valves
(MSIVs).
There are safety related accumulators which provide stored
air for MSIV operation in the event the instrument air system is lost
(i.e. isolated, etc).
Each MSIV has an accumulator with an in-line
check valve from the instrument air system.
The check valves B21F024A,
F0248, F024C,
F024D, F029A, F029B, F029C, and F029D, do not appear to
have been included in the licensee's Inservice Testing (IST) program,
nor in the licensee's type C testing per Appendix J of 10 CFR 50.
The
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instrument air lines just upstream of the noted check valves are
non-seismic piping.
T.S. table 3.6.4-1 requires a maximum isolation
time of 5 seconds for the MSIVs.
The licensee conducted testing with
the instrument air line isolated, the accumulators charged with instru-
2
ment air and no steam flow. The MSIV closure times were within the 5
second requirement.
The licensee is
investigating to determine the
,
reason the accumulator check valves were not included in the IST
program or IST program relief request.
This will be an Unresolved Item (50-416/85-45-04).
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6.
Maintenance Observation (62703)
During the raport period, the inspector observed selected maintenance
activities:
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.
In the areas inspected, no violations or deviations were identified.
7.
Surveillance Testing Observation (61726)
The inspector observed the performance of selected surveillances.
The
2
observation included a review of the procedure for technical adequacy,
conformance to Technical Specifications, verificat. ion 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.
Technical Specifications (TS) 3.6.1.2 states that containment leakage rates
shall be limited to an overall integrated leakage rate of less than or equal
to L where L equals 0.437 percent by weight of the containment air per 24
hourd at P , 71.5 psig.
The Final Safety Analysis Report (FSAR), paragraph
15.6.5.5, ftates that the design basis leak rate of the primary containment
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and its penetrations (excluding the main steam lines) is 0.35 percent per
day.
The Main Steam Line Isolation Valves (MSLIVs) are assumed to leak at
25 SCFH per valve.
The proposed TS for containment leak rate was discussed
in a letter dated December 31, 1981 from Mr. L. Dale, MP&L to Mr. H. Denton,
NRC (AECM-81/510).
Attachment 1 to the letter presented a summary of the
method used to calculate an overall integrated leak rate.
A review of
calculations by a Region II inspector indicated that the TS allowable of
0.60 La for all penetrations and all valves subject to type B and C tests
would equal approximately 325.25 SCFH.
The Licensee's Surveillance
Procedure, 06-ME-1M61-V-0001, Rev 26, Local Leak Rate Test, paragraph 5.11.2
states the overall allowable leakage limit of all type B & type C tests
shall not exceed 0.60 La or 182.5 SCFH.
A review of the licensee's letter
of December 31, 1981 indicates an error in attachment 1, step 1, in that the
204.20 is titled "SCFH" while in fact the 204.20 is "CFH" at accident
pressure, not standard pressure.
Since the licensee's error appears to be
in the conservative direction, the licensee was notified of the error and is
presently reviewing the FSAR to determine the basis for allowable leakages.
The licensee was informed that any change to the 0.437 % per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
presently specified would require a TS amendment.
This will be an
Inspector Followup Item (50-416/85-45-05).
During the performance of the Integrated Leak Rate Test (ILRT) in early
November 1985, the licensee discovered that valve C41F150, the outboard
isolation for penetration 61, was not fully closed.
In order to complete
the ILRT the licensee closed the vent valve down stream of C41F150.
Subsequent to the ILRT the licensee performed a Local Leak Rate Test (LLRT)
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on the two isolation valves associated with penetration 61, C41F150, the
outboard isolation valve and C41F151, the inboard isolation valve.
The
resulting leakage for each valve was so excessive that test pressure could
not be reached.
The inboard isolation valve C41F151 is a stop check valve
and the required position of the handwheel for the ILRT is to be in the open
direction. With the handwheel in the open direction.C41F151 acts as a check
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valve preventing flow in the outboard direction.
The previous LLRT of
C41F151, performed on June 18,1985, indicated zero leakage.
The only
operation connected with this valve since the LLRT was the reclosure of the
handwheel after the June LLRT and the opening of the handwheel in prepara-
tion for the ILRT.
This movement of the handwheel should not have any
affect on the position of the disk.
The licensee has disassembled valve
C41F151 and lapped the disk and seat.
During the disassembly it was
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observed that the packing was loose and the seat was dirty.
The subsequent
LLRT performed in November was satisfactorily.
Af ter the unsuccessful LLRT of C41F150, following the ILRT, the licensee
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attempted to shut the valve.
The operator was able to get approximately one
(1) more turn by hand but the valve still would not pass the LLRT.
Finally
the licensee placed a valve wrench on the valve and was able to get another
one quarter (1/4) of a turn in the closed directi.on.
This time the LLRT was
performed satisfactorily but the zero leakage rate achieved in June 1985 was
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not reproduced.
Since the successful LLRT on June 18, 1985, C41F150 had
only been repositioned one time and that was to perform the LLRT on C41F151
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also performed on June 18,1985.
C41F150 had been closed or verified closed
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on at least six (6) different occasions, including the valve lineup in
preparation for the ILRT, since the repositioning in June 1985.
The
inspectors questioned the licensee personnel, who perform an LLRTs, on the
requirement in Appendix J of 10 CFR 50, that a valve shall be closed by
normal operation prior to the performance of the LLRT.
The licensee
informed the inspectors that they considered the use of excessive force and
valve wrenches to close manual isolation valves for the purpose of passing
the LLRT to be normal operation.
The inspectors informed the licensee that
the use of excessive force and valve wrenches did not constitute normal
operation as required by Appendix J of 10 CFR 50, and requested a list of
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any other valves requiring abnormal operation to pass their respective
The Mechanical Maintenance Superintendent notified the inspectors
that there were no other valves requiring excessive force or valve wrenches
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to pass their LLRTs.
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It is important to note that the piping associated with penetration 61 does
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nnt connect to any system in the plant.
The piping is capped at both ends,
inside and outside the containment.
Consequently operation of the isolation
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valves is not required except for the performance of their LLRTs.
The
licensee however does not know if excessive measures were taken to get
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C41F150 and C41F151 to pass their respective LLRTs with zero leakage in June
of 1985.
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Subsequent to conversations with the inspectors the licensee performed
maintenance on C41F150 and reperformed the LLRT successfully.
The failure
of the licensee to meet the requirement of 10 CFR 50, appendix J to shut
valve C41F150 using normal operation in order to achieve a successful LLRT
>
following the ILRT will be identified as a Violation (50-416/85-45-06).
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8.
ESF System Walkdown (71710)
A complete walkdown was conducted on the accessible por tions of the Division
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The walkdown consisted of an inspection and
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verification, where possible, of the required system valve alignment,
including valve power available and valve locking, where required; instru-
mentation valved in and functioning; electrical and instrumentation cabinets
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free from debris, loose materials, jumpers and evidence of rodents; and
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system free from other degrading conditions.
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During the walkdown of the Division 1 Emergency Diesel Generator (EDG), the
inspectors observed several items of concern. One item deals with a condi-
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tion where several areas on and around the the EDG contained pools of lube
oil which appear to be more than just normal amounts. Another item deals
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with the discovery of two valves on the valve lineup sheet and existing in
the plant with the same identification number. The valve lineup sheet
Attachment 1A of System Operating Instruction (S0I) 04-1-01-P75-1 contains
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two valves with the same identification number of F112A. Even though these
t
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valves appear on the same lineup sheet there was no mention by the operators
,
of this problem in the comments section of the completed lineup sheet.
A
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quick look at Division 2 EDG valves revealed that the same condition exists
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there also. The inspectors have notified the licensee of their concerns and
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will be following up these items to ensure proper resolution. This will be
identified as Inspector Followup Item (50-416/85-45-12).
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In the areas inspected, no violations or deviations were identified.
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9.
Reportable Occurrences (90712 & 92700)
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The below listed Event Reports were reviewed to determine if the information
provided met NRC reporting requirements.
The determination included
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adequacy of event description and corrective action taken or planned,
exirtence of potential generic problems and the relative safety significance
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of each event. Additional inplant reviews and discussions with plant
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personnel as appropriate were conducted for the reports indicated by an
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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 Report (LERs) are closed.
LER No.
Event Date
Event
- 85-039
October 10, 1985
Personnel Error
Causing Loss Of
Power To ESF Bus 12.
- 85-042
November 2, 1985
Incorrect Wiring
Configuration
Caused the Loss of
ESF Transformer 11.
a.
LER 85-039. On October 17, 1985 while moving a relay from a tagged out
feeder breaker to the Engineered Safety Feature (ESF) Division 2
electrical bus for the purpose of calibration, a personnel error caused
the other feeder breaker to trip deenergizing the entire bus.
At the
time of the event the plant was in mode 4 with the safety and shutdown
cooling systems associated with the Division 2 ESF bus declared
inoperable for various reasons.
However as a direct result of the
event the operable mode of
shutdown cooling, Residual Heat Removal
(RHR) system A, was isolated from the vessel. Shut down cooling was
restored and since the reactor had been in cold shutdown since October
13, 1985 the impact on the reactor was minimal.
The personnel error
consisted of an electrician removing a relay from ESF Division 2 feeder
breaker 152-1601 and placing the relay connection plug back in the
empty relay case.
This plug caused the bus lockout relay to sense a
trip signal tripping the other feeder breaker 152-1601 causing a total
loss of power to the Division 11 ESF electrical bus.
The electrician
did understand that the connection plug should not be placed back into
the empty relay case but he did not understand that the protective
relay circuits remained energized even though the breaker was tagged
out.
He, therefore, was not knowledgeable in the protection circuits
relationship between the feeder breakers.
10 CFR 50, Appendix B, Criterion II states in part that the Quality
Assurance Program shall take into account the need for special
controls, processes, test equipment, tools and skills to attain the
required quality, and the program shall provide for indoctrination and
training of personnel performing activities affecting quality as
necessary to assure that suitable proficiency is achieved and main-
tained.
The failure of the licensee to ensure that the electrician was
trained in the protection characteristics and ir.terfaces of feeder
breakers resulting in the loss of power to an ESF electrical bus and
subsequent loss of the shutdown cooling operation of the RHR A system
will be identified as a Violation (50-416/85-45-07).
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b.
LER 85-042.
The event associated with this LER consisted of ESF
transformer 11 output breakers tripping due to a differential protec-
tion relay signal on two different occasions, resulting in loss of
power to
ESF electrical buses.
These two events appear to have
resulted from wiring errors made some years back.
The licensee stated
!
that back in 1979 Bechtel personnel discovered that the differential
relays for each of the ESF transformers were wired backwards.
This
wiring error was corrected on the transformers but the General Electric
(GE) drawing showing this wiring error was not corrected.
Also unknown
~
to the licensee another wiring error existed on a secondary side
current transformer to ESF transformer 11.
The licensee speculates
that this wiring error caused ESF transformer 11 to trip on a
protection
relay signal sometime during the startup or preoperational
testing of Division 3 High Pressure Core Spray (HPCS) Pumps.
Since the,
General Electric drawing had not been corrected and the differential
,
relay would be suspected, the engineers probably discovered that the
differential relay was wired differently than the General Electric
drawing had specified and, therefore, changed the relay to be consist-
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ent with the drawing.
The relay and current transformer, each being
wired backwards, cancelled each other therefore the starting of the
HPCS pump on ESF transformer 11 would not have tripped the transformer
indicating the problem had been solved.
On November 2, 1985, the first trip of ESF transformer 11 occurred
resulting in a loss of power to the Division 2 ESF electrical bus. This
started Diesel Generator 12, and caused several isolations and secured
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This trip uncovered the problem of the
differential relay being wired backwards and the fact that the General
Electric drawing had not been corrected.
However, it did not disclose
the reason why the relay had been changed back to the incorrect GE
drawing configuration.
The reason this wiring error had gone unde-
tected until November 2,
1985, was the current needed for normal
operation of equipment connected to ESF transforn.er 11 was just under
the trip threshold of the differential relay.
However, the licensee
had just replaced the B Standby Service Water (SSW) Pump motor with a
larger one and this was the first time this equipment had been started
and operated off of ESF transformer 11.
This new larger SSW pump motor
caused the current load requirement to just exceed the trip threshold
of the differential relay and tripped the transformer.
The second trip of ESF transformer 11 occurred on November 23, 1985,
when both Division 1 and Division 3 ESF electrical buses were being
supplied off of ESF transformer 11. The trip was caused by starting the
HPCS pump for testing and resulted in the loss of power to both ESF bus
1 and 3. The loss of power started division 3 diesel generator and
caused numerous isolations, one of which was instrument air that
eventually resulted in a reactor scram signal due to a scram discharge
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instrument volume high water level trip signal.
The plant was shutdown
in mode 4 at the time of the event.
The investigation by the licensee
discovered the secondary current transformer wiring problem which had
been masked by the previous differential relay wiring problem.
The
current transformer being wired backwards only became a problem when
the ESF transformer 11 differential relay wiring was corrected after
the trip on November 2,1985, and then only when the secondary side of
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ESF transformer 11 associated exclusively with the Division' 3'ESF bus,
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is lined up to Division 3 and the HPCS pump is started. 'It is
important to note that the Division 3 electrical bus can be lined up to
any of the three ESF transformers and the secondary side of ESF 11
associated with Division 3 can only supply power to Division 3 on
Unit 1.
Therefore, the improperly wired current transformer only comes
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into play when ESF transformer 11 is supplying power to the Division 3
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ESF bus.
The licensee has corrected the current transformer wiring
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problem and the GE drawings were corrected earlier.
The other ESF
transformer differential relays have been verified to be hooked up
properly.
c.
By letter dated November 6,1985, Transamerica DeLaval, Inc.
(TDI)
notified the NRC of a potential 10 CFR Part 21 defect in the TDI Diesel
Generators (DGs).
The defect concerned recently experienced isolated
failures of the intake and exhaust valve springs.
TDI stated that all
springs failed after an extensive operating experience of approximately
5,000 to 7,000 operating hours.
The suspect valve springs are
,
manufactured by Betts Spring Co. , San Leandro, California and are
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identified by a white stripe painted on the spring.
TDI is requesting
all users report the results of their inspection to determine if
corrective action is required.
No action was recommended other than
inspection.
The licensee's inspection of the Division 1 DG indicated
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that all valve springs had a white stripe on the side.
The Division 2
DG will be inspected during the first refueling outage.
No broken
valve springs have been identified at Grand Gulf and the DGs have less
,
than 2,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> operating time.
This will be an Inspector Followup
,
Item (50-416/85-45-08).
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d.
By letter dated September 3, 1985, American Air Filter (AAF) notified
the NRC of a 10 CFR Part 21 defect in the Division 1 and 2 Diesel
Generator (DG) air intake silencers, model TDM or FTDM.
The defect was
a possibility of an internal part not being welded in place.
On a
commercial diesel engine installation identical in most respects to
standby diesel generator nuclear installations, a turbocharger and
diesel engine failure was experienced when an internal part of an AAF
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intake silencer was ingested into the turbocharger shortly af ter
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startup.
The ingested part was found not to have been welded in place
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per design.
Air pressures and vibration existing during engine
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operations were sufficient to dislodge the part and convey it down-
stream into the engine turbocharger.
AAF stated that if the DG has
been in service, the likelihood of the weld not being in place is much
lower and the licensee should schedule an inspection for verification.
The licensee inspected the DGs and visual inspection revealed that the
welds had been made.
This will be an Inspector Followup Item for record purposes
(50-416/85-45-09).
e.
On December 5,1985, Mississippi Power and Light (MP&L) notified the
NRC that they had discovered equipment installed in the plant which
appeared to be in violation
of 10 CFR 50.49 " Environmental Qualifi-
cation of Electric Equipment Important to Safety for Nuclear Power
Plants." This equipment consisted of 17 limit switches, 8 of which had
not been environmentally sealed and 9 had date codes missing.
The
plant was in cold shutdown at the time of the notification and the ,
licensee corrected all of the identified discrepancies prior to
startup.
The investigation by the licensee to determine if these limit switches
are in fact required to be environmentally qualified and if there are
any other discrepant equipment is continuing.
Pending the licensee's
-
final resolution of the scope and extent of the problem this will be
identified as an Unresolved Item (50-416/85-45-10).
10.
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
engineering support personnel as appropriate.
The licensee's investigation
into the Diesel Generator (DG) overspeed that occurred on November 6,1985,
has been completed and the DG has been reassembled.
The cracks in the main
generator base were evaluated by a consulting group, Failure Analysis
Associates, and it was determined that continued use of the existing base
was permissible.
Two meetings were held at the Grand Gulf Plant with NRC
representatives to explain what the licensee's investigation had shown.
On
November 14, 1985, Mr. Carl Berlinger and Mr. Emmett Murphy from NRR were
present and on November 21, Mr. Carl Berlinger, NRR and Mr. Paul Louzecky,
NRC consultant, were on site.
The Division 1 DG was completely disassembled
and the results of nondestructive examinations were available for review.
It appears the DG overspeed was the result of the inadequate refilling and
venting of the Woodward Governor following maintenance that required the
removal and draining of the Woodward Governor (including the booster and
cooler).
This overspeed condition resulted in substantial damage to the DG.
A description of the damage, inspection and repair is provided in the
summary of the meetings noted above.
Also, a meeting was held in the NRC
Region II office on December 13, 1985, where the licensee presented the
results of their investigation.
.
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T.S.6.8.1 requires written procedures be established, implemented and
maintained covering activities recommended in Appendix A of R.G.1.33. R.G.
1.33 requires written procedures for performing maintenance that can effect
performance of Safety related equipment.
The Division 1 DG retest was
performed by Maintenance Work Order (MWO) M57687 dated November 6,1985.
A
review of the MWO indicated the following discrepancies.
(a) Maintenance Section Procedure (MSP) 07-5-09-40, revision 1, Control of
Retest Requirements, Paragraph 6.3.2.d. (1) states" when maintenance
retest (Special Instructions) are required that do not exist, and are
subsequently developed by a Maintenance Planner, an Engineer will
review the maintenance retest and approve, disapprove, or modify
accordingly."
Contrary to the above, the special instruction included
in the MWO does not have the approval signature of the Responsible
Maintenance Engineer (RME).
(b) MSP-07-5-09-40, Revision 1, Paragraph 6.3.2 requires the RME/Respon-
sible Field Engineer (RFE) specify maintenance retests.
Contrary to
the above, maintenance retests were specified by a Mechanical
Supervisor.
(c) Preventive Maintenance Instruction 07-5-24-P75-E001AB-5, Revision 0,
Periodic Oil Change of the Standby Emergency Diesel Woodward Governor
Model #EGB-35-C, paragraph 7.10.1 states "Run engine 15 minutes, stop
engine and drain governor oil and fill with fresh oil."
Contrary to
the above, the retest specified by MWO M57687 did not specify the
draining of governor oil & refill with fresh oil following a 15 minute
run.
The failure to follow procedures as noted above is a violation
(50-416/85-45-11).
The Woodward Governor manual for the EG-B35 and EG-B50 hydraulic actuators,
Grand Gulf (GG) TDI diesels use EG-B35C governors, has a warning that the
engine should be equipped with separate overspeed shutdown devices to
protect against runaway or damage to the engine should the mechanical-
hydraulic governor, or electric controls, the actuators, fuel control, the
driving mechanism, the linkages or the controlled devices fail.
The GG
diesels have a separate overspeed device manufactured by the Woodward
Governor Company. The overspeed trip is set at 15% over the normal governor
speed of 450 rpm (or 517 rpm).
During tests following the overspeed event
the licensee measured the response time of their overspeed trip and found a
2.25 second time delay.
This was on Unit 2.
Also, TDI has stated that the
DGs on an unloaded start from rest will be accelerating at approximately 50
rpm /sec at 350 rpm and accelerating at approximately 100 rpm /sec at 517 rpm.
It can be surmised then that a DG without the benefit of a governor would
probably be damaged to some extent by the time the overspeed trip would take
effect.
The Woodward Booster and Cooler are part of the Woodward Governor
. -- -- - _ ~
- . _ - - - . - - _ _ _ _ - - . - - - . -
. - - - . . _ _ - = - .
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assembly used on the Division 1 & 2 DGs.
The Booster Servomotor Bulletin,
.
36684 B, the latest vendor document that the licensee had available on site,
{
does not have any cautions or warnings about purging air.
However, Bulletin
36684 J, which is a later issue, contains a caution regarding prcper purging
j
of air to prevent possible sluggish governor response.
The licensee
returned the Woodward governor to the manufacturer for testing, and when
tested with an equal amount of oil as found following the overspeed event,
,
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the governor was erratic in operation which would probably explain the loss
]
of governor control.
The licensee's procedure for changing oil in the
Woodward governor is Preventive Maintenance Instruction (PMI) 07-5-24-P75-
E001AB-5, Periodic Oil Change of the STBY.
EMER. Diesel Woodward Governor
3
Model #EGB-35-C. Paragraph 7.9 fills the governor with new clean oil to the
'
top of the gauge glass and then paragraph 7.10 has the operator turn the
governor speed control down to idle speed (300 rpm approximately) and start
!
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the engine (DG) unexcited.
The procedure does not require purging air from
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the governor prior to start. It is not clear that the licensee had adequate
warning that starting the DG and then venting the Woodard Governor could
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result in an overspeed event.
This appears to be a generic issue which the
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licensee has initiated action to inform other DG users of the potential for
'
damage.
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11.
IFI & Unresolved Items (92701)
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a.
(Closed) IFI 50-416/85-39-02.
The licensee has completed the investi-
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gation into the DG overspeed event.
This item is discussed in para-
graph 10 of this report.
This item is closed.
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b.
(Closed) IFI 50-416/85-06-05.
The inspector has received a response
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regarding the adequacy of Technical Specifications.
This item is
4
closed.
c.
(Closed) IFI 50-416/85-14-01.
The licensee has submitted an updated
FSAR.
This item is closed.
d.
(Closed) IFI 50-416/85-14-02.
The inspectors have reviewed the
,
licensee's actions addressing the concerns associated with this
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followup item.
Reviews of subsequent post trip analysis indicate that
I
these actions were adequate to prevent further occurrence.
This item
is closed.
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12.
License Condition
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The Grand Gulf operating license, NPF-29, paragraph 2.C. (9) requires that
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prior to startup following the first refueling outage, MP&L shall complete
i
structural modifications, if required, as a result of the NRC staff's
completion of its review of the licensee's response to IE Bulletin 80-11.
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By letter dated November 4,1985, from Mr. T. Novak, NRC to Mr. J. Richard,
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MP&L, the NRC stated that the GGNS submittals were acceptable and license
condition 2.C.(9) has been fulfilled.
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In the areas Inspected, no violations or deviations were identified.
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