ML20197H468
| ML20197H468 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 05/08/1986 |
| From: | Blough A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20197H402 | List: |
| References | |
| REF-GTECI-A-36, REF-GTECI-SF, RTR-NUREG-0612, RTR-NUREG-612, TASK-A-36, TASK-OR 50-219-86-06, 50-219-86-6, IEB-80-16, IEC-79-12, IEC-80-10, IES-79-12, NUDOCS 8605190174 | |
| Download: ML20197H468 (26) | |
See also: IR 05000219/1986006
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-219/86-06
Docket No.
50-219
License No.
OPR-16
Priority
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Category
C
Licensee:
GPU Nuclear Corporation
100 Interpace Parkway
Parsippany, New Jersey
Facility Name: Oyster Creek Nuclear Generating Station
Inspection At: Forked River and Parsippany, New Jersey
Inspection Conducted: March 3 - April 13, 1986
Participating Inspectors:
W. H. Battman, Senicr Resident Inspector
J. F. Wectselberger, Resident Inspector
W. H. Baurack, Project Engineer
Approved by:
l>J O m A 4
rNrt
A. R. Blough, Chief
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Da'te
Reactor Projects Section in
Inspection Summary:
Routine inspections were conducted by the t-esident inspectors and a Region
based inspector (373 hours0.00432 days <br />0.104 hours <br />6.167328e-4 weeks <br />1.419265e-4 months <br />) of activities 1.1 progress including plant opera-
tions, physical security, radiation control, housekeeping, fire protection,
emergency preparedness, and outage preparations. The inspectors also reviewed
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licensee action on previous inspection findt'.igs, made routine tours of the
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facility, participated as observers in the annual emergency drill, observed
licensee action during an Unusual Event declared as the result of a bomb
threat, and reviewed the most recent licensee QA environmental qualification
audit.
In addition, the inspectors visited the GPUN corporate offices and met
with various members of Tech Functions management and also reviewed four
modification packages scheduled to be implem:nted during the 11R outage.
The
inspectors also attended several briefings i.cluding the QA Annual Assessment,
inservice inspection plans for the 11R outag.., PSMS computer system, and the
Maintenance, Construction, and Facilities' Werk Management System.
8605190174 860512
ADOCK 05000219
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Results:
Two violations were identified. One involved failure of Plant Engir.eering (PE)
to maintain the station procedure governing their conduct as described in para-
graph 1, as well as failure of PE to properly prioritize and address a licensee
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self-identified concern regarding failure to address NOREG 0612, movement of
heavy loads, at the Intake Structure as described in paragraph 2; and the other
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involved failure of Tech Functions to follow procedures governing the design
review process as discussed in Paragraph 9.
Plant response to the bomb threat was comprehensive. The annual emergency
drill was termed acceptable.
Plant operations were interrupted twice -- once
due to an unexpected reactor trip and once due to an unplanned shutdown to
replace reactor low water level scram sensors.
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At the end of the report period, the plant was shutdown and the 11R outage had
Commenced.
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Details
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1.
Licensee Action on Previous Inspection Findings
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(Open) Inspector Follow Item (219/84-06-02): Closecut Documentation for
Plant Material (PM) Department Plant Engineering Work Requests (PEWR)
Not Always Available
During NRC Region I Inspection 84-06 it was noted that closeout documen-
tation of PM PEWRs was only occasionally available, there was a lack of
status of PEWRs, and a lack of understanding of the priorities for open
requests. These factors were discussed with plant management who indi-
cated that the matter would be reviewed and appropriate action taken.
During this inspection those actions taken by the licensee to resolve
this item were reviewed.
The PM Department, by memorandum dated January 9,1985, notified Plant
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Engineering (PE) of open PM PEWRs. Also, all outstanding PEWRs were
reviewed and those considered no longer applicable were cancelled.
The
PM Department has setup a program establishing a central departmental
contact for liaison between PE and PM.
All PEWRs are to be handled and tracked by this contact. PM, by memo-
randum dated June 19, 1985, also requested from PE all acknowledgements
of acceptance of PEWRs, all completed PEWRs, and any correspondence with
regard to PM PEWRs.
Based on these actions the licensee's Licensing
Action Item written to resolve this matter was closed.
To verify the effectiveness of the licensee's actions, the PM PEWR log was
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reviewed by the inspect 6r.
This log indicated 30 no longer applicable
open PEWRs had been cancelled, 19 PEWRs have been closed, and 115 remain
open. Of the open PEWRs, 36 were written in 1983, 32 in 1984, 43 in 1985,
and 3 in 1986. Some open items indicated acknowledgements from PE,
however, many are logged with no acknowledgements indicated.
The inspector selected 22 of the items identified in the log as still
open for follow-up in the PE files.
Five of the items were found to have
been closed in PE files. Two of these five had documentation indicating
PM had been informed of the closeout.
Four of the items were closed by
PE-by Technical Functions Work Requests, the status of these items was
not tracked by PE, and PM was not notified of this'closecut.
The status
of these items was not tracked by PE.
Eleven were indicated as open in
PE files.
Information relative to two items was not readily available
and no follow up of these was conducted.
Due to the fact.that some
errors still appear to exist in the PM documentation relative to PEWRs,
this item 84-06-02 remains open.
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Because of the discrepancies noted between PM and PE files, particularly
after an effort had been made to improve tracking of PM PEWRs as a result
of NRC Inspection 84-06, the inspector reviewed Station Procedure Number
125, Conduct of Plant Engineering , as it related to tracking of engineer-
ing tasks. This procedure was written to delineate the functions, respon-
sibilities, authorities, and organizational interfaces of the PE organi-
zation. A review of this procedure indicated the procedure had become
outdated in a number of areas. These areas include:
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Organization: the procedure describes an organization different than
the organization that currently exists.
Consequently, the proce-
durally described responsibilities are for position titles which do
not exist. How these responsibilities are performed within the
existing organization is not clear.
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Performance of engineering tasks: the current method of initial
review of work requests and the issuance of Plant Engineering Task
Assignments (PETA) differs from that described in the procedure.
Copies of PETAs are not always forwarded to the requestor as required.
Also, close-out of PETAs is not always as procedurally required in
that Form 125-2 is not generally completed in closing-out PETAs.
This form requires a close-out response be provided to the originator.
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Records maintenance differs from that described in the procedure.
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The prioritization of PETAs differs substantially from that described
in the procedure. The PE procedure identifies only two priority
classifications. The actual prioritization is done basically in ac-
cordance with a Technical Functions Division procedure which results
in numerous priorities. PM personnel were unaware of the meaning of
the priority numbers assigned to their items.
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The PEWR form being used differs slightly from that attached to the
procedure.
In addition, there are no instructions in the procedure
detailing how this form is to be used, particularly,'the acknowledge-
ment section.
The above are examples of the more significant deficiencies noted in the
Conduct of Plant Engineering Procedure. These and other procedural
problems were discussed in detail with the PE-and PM Directors. The in-
spector noted the failure to maintain the Conduct of Plant Engineering
Procedure current was considered to be a violation (219/86-06-01). The
PE Director indicated a forthcoming reorganization and the change-over to
a new computerized Action Item Tracking System were th> reason the pen-
cedure was allowed to become outdated.
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It should be noted only the portions of the Conduct of Plant Engineering
Procedure dealing with performance of engineering tasks were reviewed.
Other portions of th'e procedure may also be outdated.
(Closed) Inspector Follow Item (219/84-06-0E): Licensee to revise diesel
generator procedure to include certain checks.
The licensee has revised Station Procedure 636.4.003, Diesel Generator
Load Test, to include verification of filter oil level, verification of
DG battery strip heater energization, and acceptable level for DG fuel
oil day tank.
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(Closed) Inspector Follow Item (219/84-06-03): Plant Materiel mechanical
section to provide equipment failure review to the Vice president and
Director.
The Plant Materiel mechanical section has established a Plant Materiel
Mechanical Equipment Trending Program.
Part of this program is to
provide a quarterly report to the Deputy Director.
In addition, a year
end summary is also provided the Deputy Director. The year end summary
summarizes trends, failures, corrective, and preventive maintenance
performed by system and by individual components. The report also
describes problems and experiences and proposes corrective actions.
(Closed) Inspector Follow Item (219/83-25-01): Licensee audit finding
identified inconsistencies in radiation protection procedures.
A subsequent Quality Assurance Audit S-0C-84-17 performed by the licensee
from October 22, 1984 to January 2, 1985 of radiological controls deter-
mined, based upon a review of the 900 series procedures, all previous
discrepancies have been corrected.
In addition, a major rewrite of the
radiation controls procedures was conducted in 1985. During this rewrite
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many outdated procedures were deleted.
. Closed) Unresolved Item (219/83-24-02): Inaccurate response to IE
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Inspection 83-24 identified the installation in the plant-of certain trans-
mitters which the licensees response to IE Bulletin 80-16 indicated were
not used at Oyster Creek. The licensee committed to certain corrective
actions. These included (1) a review of the respense to IE Bulletin 80-16
and the submittal of corrections to the Bulletin response dated July 24,
1980. This was accomplished by licensee letter Fiedler to Murley, dated
November 9, 1982; (2) an audit of IE Bulletins and GE Service Information
Letters (SILs) to assure licensee actions and statements reflect the con-
ditions at the plant.
Licensee Action Item files 83023.02 and 80062.3
contain memoranda which show that these audits have been performed; and
(3) a system will be developed to inform all potential users of the impact
of IE BC.letins and GE SILS to avoid further use of defective components.
The licensee has in place Corporate Procedure 1000-ADM-1216.03, Regulatory
Correspondence Control, which defines and establishes the GPUN system for
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the management of incoming and outgoing regulatory correspondence and the
assignment of tasks associated with that correspondence.
[ Closed) Unresolved Item (219/80-25-03): Review drain time difference of
scram discharge volume (SDV) following two successive scrams.
During Inspection.80-25 a significant difference was noted in the time
for the SDV to drain following an automatic scram and a manual scram (161
sec. vs. 84 sec.).
During the last outage, major modifications were made
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to the SDV system. The existing SDV which had experienced the drain time
difference has been removed and replaced with two separate SDVs. During
startup testing following the modification, SDV drain times were recorded
and no abnormal drain times were noted.
(Closed) Unresolved Item (219/80-09-01): This item deals with the sealing
of electrical connections to limitorque valve operators within the
drywell.
During NRC Region I Inspection 80-09, several concerns were noted. One
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concern dealt with a flexible electrical conduit pulled from its packing
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gland on the solenoid actuator for reactor water sample isolation valve
V-24-29, and the other with the sealing of motor operated valve operator
cable where it exits rigid conduit.
Quality Control Inspection Report 11085 verified that the flexible
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electrical conduit associated with V-24-29 had been repaired. Also, the
licensee performed an evaluation of motor operated valves which might
experience infiltration of steam under accident conditions through cable
exiting rigid conduit. Two valves were identified V-14-36 and 37 for
which sealing at the conduit leading to the valve was recommended.
These
conduits were sealed per Job Order 0450V.
(Closed) Licensee Identified Items (219/81-LO-3E, 81-LO-4E, 81-LO-5E,
81-LO-6E, and 81-LO-7E).
These items deal with Nonroutine Environmental Operating Reports which
were submitted by the licensee. The first four deal with less than the
required number of dilution pumps operating and the last deals with
exceeding the allowable temperature difference between circulating water
intake and discharge due to grass clogging of the intakes.
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By Amendment No. 66 to the Oyster Creek Operating Licensee issued on
May 24, 1983 the non-radiological water quality-related requirements were
deleted from the Environmental Technical Specifications. ' Consequently,
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this type of event is no longer required to be reported to the NRC.
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As a followup to these reports, the inspector verified that certain
improvements have been made to the dilution pumps. These improvements
include changes to the pump seal water and lubricating oil cooling water,
upgrading of piping to more corrosive-resistant material, extensive pump
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maintenance, and the stocking of spare parts. Additional modifications
to improve dilution pump performance are planned for the 1986 refueling
outage. Also, limits associated with the main condenser _ circulating
water system and the thermal dilution pumps are contained in Station
Procedure 323, Main Condenser Circulating Water System, and Procedure
324, Thermal Dilution Pumps, respectively.
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(Closed) IE Circular No. 80-10 (219/80-CI-10): Failure to maintain
environmental qualification of equipment.
This Circular described several instances in which environmental
qualification of equipment was not maintained due to the use of the wrong
class of equipment during maintenance.
The Circular recommended licensees
review maintenance procedures and administrative policies to ensure: (1)
adequate administrative controls exist to ensure that equipment which is
environmentally qualified is identified prior to maintenance; (2) mainte--
nance procedures provide necessary instructions and precautions to ensure
that the environmental qualification of equipment is not degraded when
maintenance is completed; and (3) maintenance personnel are adequately
trained on environmental qualification requirements and the potential for
equipment degradation from improper maintenance.
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The licensee has in effect Station Procedure No. 105.3, Maintenance of
Oyster Creek Environmental Oualified (EQ) equipment.
This procedure has
been prepared to provide administrative control and practices related to
all maintenance performed on EQ equipment and to assure that procurement
of replacement components is in accordance with EQ requirements. The
procedure specifies training of maintenance planning personnel on
requirements to maintain EQ and incorporates appropriate requirements in
tasks on EQ equipment. Also, the procedure requires that maintenance
personnel be trained on requirements to maintain EQ.
The inspector
verified planners received the required training on September 18, 1985,
and the maintenance personnel on September 9, 1985.
2.
Control of Movement of Heavy Loads at the Intake Structure
A review of outstanding Plant Engineering Work Requests (PEWRs) disclosed
a situation wherein a safety concern was identified and submitted to
Plant Engineering (PE) for action that PE had failed to address.
In
particular, a PEWR initiated by Plant Materiel dated 8/19/85 explained
that heavy loads were being moved at the Intake Structure using a mobile
crane in the vicinity of safe' shutdown equipment (four Emergency Service
Water. pumps) without procedural controls.
The PEWR requested that the
movement of heavy loads at the Intake be analyzed to ensure NUREG-0612
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(Control of Heavy Loads) guidelines are met. The NRC inspector determined
that the licensee's response to the NUREG-0612 guidelines for the Intake
stated that since the gantry crane at the Intake had been removed from
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service the Intake was excluded from NUREG-0612 applicability. The
responte also said, "If at some time in the future this crane is placed
back into service, an evaluation will be performed to ensure that
NUREG-0612 criteria are satisfied." The response did not recognize nor
address the use of a mobile crane to move heavy loads at the Intake. The
Plant Materiel group-who identified the issue exhibited a good awareness
of regulatory commitments and onsite conditions.
PE received this PEWR on 8/20/85, assigned it PE Task #512200850635, and
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gave it a priority 2 rating. Paragraph 6.4 of Station Procedure 125,
Conduct of Plant Engineering, Rev. 2, discusses management of PE tasks
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and requires, in part, that tasks which, left undone, would cause a NRC
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commitment deadline to be missed, should be given priority 1 rating.
Although procedure 125 does not explain the significance of a priority 1
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rating, it is implied that priority 1 demands immediate attention. The
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anticipated completion date for this task was listed as 1/1/99, which by
PE definition meant it was unscheduled. The failure of PE to assign the
appropriate priority rating to this PEWR resulted in a nuclear safety
issue not being promptly addressed. This is a violation.
(219/86-06-02)
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Subsequent to identification of this matter by the NRC inspector, the
licensee committed to cease movements of heavy loads at the Intake until
the appropriate evaluations and training are completed.
3.
Surveillance Testing
In Inspection Report 86-04, a summary of events relating to the erratic
performance of Static-0-Ring (SOR) differential pressure sensors was -
presented. During this report period, the erratic. performance continued
and a licensee decision was made to shutdown the plant and replace.the
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reactor low level scram sensors with a slightly different model tisat had
been performing satisfactorily as the reactor low low level sensors. ' SOR
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model number 103 AS-8212-NX-JJTTX6 was replaced with SOR model number 103
AS-BB212-NX-JJTTX6 and some minor modifications were made to the sensor's
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inlet piping. The sensor replacement and piping changes were classified
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as a modification and received a safety evaluation.
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. eekly surveillance of the new sensors was implemented following plant
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startup. Problems with setpoint drift of these sensors was also exper-
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tenced and one. sensor was undergoing daily surveillance the week prior to
plant shutdown for the 11R outage. Neither the licensee nor SOR have.an
explanation for the setpoint drift. At one point it was suspected a
valving sequence to verify reactor vessel communication (referred to as
" bang test") was the cause. However, subsequent evidence has eliminated.
this possibility. The licensee's present plans are to replace the low
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level scram sensors with an analog type-system during the 11R outage and
to delay replacement of other plant sensors that were scheduled to be
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replaced with SOR units.
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other site locations including the site boundary with negative results.
Operations corrected the problem by reestablishing a negative
differential pressure in the turbine building.
During routine surveillance by radcon of trash in dumpsters outside the
RCA, a slightly contaminated piece of an old LPRM box was identified. A
spot the size of a silver dollar was found to read 200 cpm above background.
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The LPRM box was being cut up for disposal and the radiologically clean
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pieces were disposed of as clean trash.
Radcon management discussed the
inadequate survey with the technician-involved and counseled the individual
as to the importance of a thorough survey.
The licensee discussed their man rem exposure goals for 1986 with the NRC
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inspectors. The estimates include outage related exposure. The man rem
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estimate for 1986 without decon of the recirc piping is approximately
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1700. The licensee plans, however, to decon the recirc piping thereby
r2ducing the estimate to 1000. A goal of 800 has been set.
It is note-
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worthy that the chemical decon of the recirc piping will reduce personnel
exposure by approximately 40 man rem per week.
The investment by the
licensee to reduce personnel exposure is noteworthy.
6.
Operational Safety Verification
6.1 Control Room Safety Verification
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Routinely throughout the inspection period, the inspector indepen-
dently verified plant parameters and engineered safeguard equipment
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availability. The following items were observed:
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Proper Control Room manning and access control;
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Adherence to approved procedures for ongoing activities;
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Proper safety systems and emergency power sources valve and
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breaker alignment; and
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Shift turnover.
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6.2 Review of Logs and Operating Records
The inspector reviewed, on a sampling basis, the following logs and
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instructions for the period March 3 to April 13, 1986:
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Control Room and Group Shift Supervisor's Logs;
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Control Room and Shif t Supervisor's Turnover Check Lists;
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Reactor and Turbine Building Tour Sheets;
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The inspectors considered the licensee's efforts to address the problem
of setpoint drift of the reactor low level scram sensors to be sound in
engineering judgement and conservative regarding safe plant operation.
4.
Review of QA Audit of Environmental Qualification
The licensee's QA group performed an audit of the environmental qualifi-
cation of electrical equipment at Oyster Creek.
The audit number was
0-0C-85-08 and was performed November 11-26, 1985. Because of concerns
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raised during discussions with QA management regarding changes to the
audit after initial issue, the inspectors decided to review the audit to
ensure the changes made did not impact the audit findings. A comparison
of the initial issue of the audit with the final issue indicated that two
subjective statements had been deleted but that the audit recommendations
were unchanged. The NRC inspector did not feel the deletion of the GPUN
QA auditor's opinions from the audit detracted from the effectiveness of
tne audit, especially in light of the fact that the audit's final con-
clusicns remained unchanged.
The NRC inspector did, however, request that
he be informed when Tech Function's Engineering Assurance responds to the
audit recommendations. The inspector will review the responses during a
subsequent inspection.
(219/86-06-03)
5.
Radiation Protection
During entry to and exit from the RCA, the inspectors verified that
proper warning signs were posted, personnel entering were wearing proper
dosimetry, personnel and materials leaving were properly monitored for
radioactive contamination, and monitoring instruments were functional and
in calibration.
Posted extended Radiation Work Permits (RWPs) and survey
status boards were reviewed to verify that they were current and accurate.
The inspector observed activities in the RCA'to verify that personnel
complied with the requirements of applicable RWPs and that workers were
aware of the radiological conditions in the area.
As a result of the reactor trip on March 6, 1986, 8 people working in the
turbine building became slightly contaminated with short-lived radio-
isotopes (cesium 138 and rubidium 88). The turbine building became
slightly airborne when sealing steam was lost to the turbine gland seals.
The contamination was not an unexpected event. The maximum level.was 1500
cpm on a worker's hard hat.
Radcon response to the contamination problem
was prompt and thorough.
On March 21, 1986 water vapor was observed escaping from around the roof
plugs on the turbine building heater bay roof.
Because the heater bay
contained airborne contamination from valve and equipment leakage, radcon
was promptly notified whereupon they sampled the space above the heater
bay roof.
Results of one sample indicated a minor unmonitored release .
was in progress.
Immediate action was taken by Operations to correct the
problem. Additional samples were taken above the heater bay roof and at
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Equipment Control Logs;
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Standing Orders; and
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Operational Memos and Directives.
The logs and instructions were reviewed to:
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Obtain information on plant problems and operations;
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Detect changes and trends in performance;
Detect possible conflicts with Technical Specifications or
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regulatory requirements;
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Assess the effectiveness of the communications provided by the
logs and instructions; and
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Determine that the reporting requirements of Technical
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Specifications were met.
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The reviews indicated the logs and operating records were generally
comple'.e. No inspector concerns were identified.
6.3 Review of Key Events
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A.
Reactor Scram
On March 6, 1986 the facility experienced a reactor trip due to
a spurious turbine stop valve closure signal that occurred during
routine turbine stop valve surveillance testing. Approximately
one minute after the trip, the MSIVs isolated due to reactor
pressure decreasing to less than 850 psig with the Mode switch
still in RUN. At nearly the same time, the Reactor Water Clean-
up (RWCU) System isolated.
Electromatic relief valves were
manually actuated to control pressure until reactor water level
was brought back into the indicating range at which time the
isolation condensers were used to control pressure. Several
minor airborne contamination problems resulted in the turbine
building and minor flooding occurred in the steam jet air ejector
room due to an already leaking gland seal exhauster condenser.
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The exact cause of the scram was subsequently determined to be
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a malfunctioning of the position switch on the No. I turbine
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stop valve (TSV). ~Specifically, the contacts on the open posi-
tion switch were not making continuously.
Similar-switches on
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the other TSVs were checked and verified to be functional. The
No. 1 TSV position switch was replaced.
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The plant equipment response was as expected with the only
significant exception that a RWCU system containment isolation
valve, V-16-14, failed to cpen during one of several cycles.
Follow-up testing of V-16-14 to identify the problem did not
indicate a cause. The NRC inspector further pursued this
matter subsequent to plant restart and was informed by PE that
it has been known for some time that the valve motor is
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slightiy undersized for the valve opening operation.
(Note:
The valve closing function is safety-related, but opening is
not.) Previous problems with operability of this valve resulted
in making a Limitorque gearing change in an attempt to correct
the problem. The licensee has stated the problem with V-16-14
will be corrected prior to restart from the 11R outage.
Operator response to the trip indicated that past problems with
reactor water level control during trips has become a major
operator concern. As a result, during this trip recovery, the
control room operator gave his primary attention to control of
water level and neglected to place the Mode Selector switch to
SHUTDOWN. Within one minute of the trip, plant pressure had
decreased to less than 850 psig and, with the Mode switch still
in RUN; a MSIV closure occurred. The closure of the MSIVs
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added additional complications to the scram recovery in that
the EMRVs and the Isolation Condenser system had to be used for
heat sink purposes. A review of Station Procedure
2000-ABN-3200.01, Rev. O, Reactor Scram, indicated the first
two steps an operator should perform after an automatic trip
are to depress both manual scram pushbuttons and place the Mode
switch to SHUTDOWN. However, this procedure is prefaced by the
statement, "If while executing this procedure, any entry
condition for any Emergency Operating Procedure (EOP) occurs,
Then immediately exit this procedure and enter the appropriate
E0P."
One of the peculiarities of Oyster Creek is that a low
level scram signal is received each time a scram occurs. This
is a genuine signal and demands immediate entry into the level
control E0P. This E0P does not address the initial steps
required by the reactor scram procedure.
During past trips
operators have properly positioned the Mode Selector switch but
this time it was overlooked due to concerns for water level
control. The inspector reviewed the licensee's Post Trip
Review of this event and noted that the failure of the operator
to reposition the Mode Selector switch was a major concern.
The licensee committed in their Post Trip Review to evaluate
operator priorities following reactor trips and to make any
necessary procedural changes. The inspectors will follow up
licensee actions in a subsequent inspection.
(219/86-06-04)
B.
Some problems occurred during the subsequent restart from the
3/6/86 reactor trip.
Instrumentation associated with th
'C'
EMRV indicated seat leakage. The licensee operated the
.lve
several times in an attempt to reseat it.
The attempts were
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not successful and the plant continued to operate until
shutdown for the 11R outage with minor seat leakage past the 'C'
EMRV.
Instrumentation associated with the 'D'
and 'E'
EMRV in-
dicated they were also experiencing minor seat leakage through-
out the remainder of the operating cycle.
The EMRVs are
scheduled for overhaul during the outage.
During one of the attempts to reseat the
'C' EMRV, the plant
nearly experienced a reactor low level scram.
Prior to lifting
an EMRV the reactor water level control system is placed in
manual to preclude the system response that would occur if
control was in automatic.
If left in automatic the swell
caused by lifting the EMRV would signal the control system to
throttle down feedwater flow. This action, combined with a
greater feed flow / steam flow mismatch, would result in a rapid
decrease in reactor water level. What apparently occurred
during this attempt was a malfunction of the level control
switch such that, although the switch was in the manual
position, the contacts remained in automatic. The result was a
rapid decrease in reactor water level and a half scram signal
caused by low reactor water level. This switch problem and
other problems with the Mode Selector and IRM Range switches
caused the inspector to express a concern regarding operator
confidence in operation of these switches.
Plant management
plans are to replace the Water Level Control switch and modify
the IRM Range switch prior to restart from the 11R outage.
Actions are also underway to purchase a new Mode switch,
although it is uncertain whether it will be installed prior
to restart.
C.
Throughout the latter portion of the operating cycle, leakage
of condensate from the gland seal exhauster condenser caused
problems.
Each time plant load was reduced, condensate header
pressure increased making the leakage worse, thereby, causing
erratic operation of the gland seal exhaust fans.
Plans are to
repair the condenser during the outage.
D.
During performance of augmented surveillance of the reactor low
level sensors, an ECCS initiation occurred. The initiation
signal was generated when one of the sensors was being valved
back into service following surveillance. The licensee deter-
mined that a slight flow surge and pressure drop in the variable
leg occurred when a test gauge, used to confirm sensor communi-
cation with the reactor vessel, was valved in. This variable
leg also serves the reactor low low water level sensors. The
filling of the empty tubing between the isolation valve and the
gauge caused the transient. This transient was sensed by the
reactor low low level sensor which in turn initiated the ECCS
signal. Two Core Spray main and booster pumps started, both
emergency diesel generators started, and one half an ATWS trip
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signal occurred. All systems responded normally and the oper-
ators recovered from the event without incident.
No actual
ECCS injection to the vessel occurred. The surveillance proce-
dure was subsequently modified to require filling the tubing
between the isolation valve and the gauge prior to opening the
isolation valve.
F.
As mentioned in paragraph 5 above, an unmonitored release of
radioactivity occurred from the turbine building heater bay
roo f.
This rerulted because of gradual degradation of turbine
building exhaust fan 1-7 and subsequent positive pressurization
of the turbine building. Operator response to correct the
problem was prompt. However, follow-up as to why the gradual
change in turbine building to atmosphere differential pressure
(d/p) from nep tive to positive was not detected, disclosed
that the control room instrumentation for this d/p was out of
service and the local instrumentation in the turbine building
was not logged and reviewed. The inspector suggested to the
licensee that when control room instrumentation is taken out of
service that compensatory action be taken to log and review
3
readings from local instrumentation. The licensee agreed.
7.
Scram Reduction Task Force
Based, in part, on the above average number'of plant scrams in 1985, the
licensee formed a scram reduction task force to investigate causes of
trips and make recommendations for reducing plant trips.
The task force
issued a document entitled "0yster Creek Scram Experience" (TDR 724).
The
inspectors reviewed this document to ensure the conclusions reached en-
ccmpassed their concern for balance of p' ant impact on the primary side.
The document analyzed all plant trips from January 1976 to December 1985.
There were a total of 35 scrams during this period. The 6 trips experi-
enced in 1985 were only exceeded by the 7 trips in 1979. Of the 6 trips
in 1985, 4 were attributed to equipment failure and 2 were considered
human related. This is in contrast to 1979 when only one was considered
equipment failure and 6. human related. An analysis of all 35 trips indi-
cated 40% of all scrams were due to human related causes while starting up
or shutting down. Twenty-six percent were due-to human related causes
while performing testing or maintenance activities, and the remaining 34%
were due to equipment failure, mostly in balance of plant systems. The
nuclear industry has set a goal of no more than 3 unplanned trips per
i
plant year for plants with greater than 3 years operating experience. The
1
average for BWRs in 1984 was 3.6.
Oyster Creek was shutdown for all but 2
months of 1984 and experienced 2 trips during the 2 months of operation.
The report was generally well done. Recommendationsweremadethatcould
help in reducing the number of reactor trips. The statement was made
that it was too early to determine if a trend existed regarding balance
of plant equipment failures. Only one scram occurred during the first 3
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months of 1986 and it resulted from a balance of plant equipment failure.
The inspectors had anticipated the report would have recommended more
intensive investigation of the potential impact of balance of plant
components on plant operation.
For example, there was no recommendation
to investigate periodic replacement of equipment that interfaces with the
reactor protection system. This was discussed with plant management who
stated that, even though this was not a specific recommendation of the
i
report, it was being reviewed by Plant Materiel as a separate job action.
The inspectors will follow up the review by Plant Materiel in a subsequent
4
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inspection.
8.
Review of Periodic and Special Reports
,
Upon receipt, periodic and special reports submitted by the licensee pur-
suant to Technical Specification requirements were reviewed by the inspec-
tors. This review included the following considerations: the report in-
cludes the information required to be reported to the NRC;
planned
corrective actions are adequate for resolution of identified problems;
and the reported information is valid.
'
The following reports were reviewed:
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Monthly Operating Reports for January and February 1986
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Annual Exposure Data Report for 1985
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Second 1985 Semi-Annual Effluent Release Report.
The effluent release report stated there were no releases of radioactive
liquids during the period.
No concerns were identified.
I
9.
Technical Function Division Inspection
The inspectors made two separate visits to the GPUN Corporate Engineering
t
offices in Parsippany, N.J.-during this report period. The first visit
involved meetings with various Tech Functions department managers to gain
,
"
an understanding of the organization.
The managers were all very helpful
1
and appeared to have a comprehensive understanding of their department and
~
interfaces with other departments. The spirit of cooperation experienced
during this visit contributed to helping the inspectors gain a rudimentary
4
understanding of the Tech Functions organization.
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The second visit involved a review of the following four modification
packages scheduled for work during the 11R outage:
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.BA 328145 Reactor Head Flange Thermocouples
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BA 402207 Recirculation Valve Interlock
,
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BA 402775 Diesel Generator Lubrication System
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BA 402786 460V USS 1A2, 182 Transformer Cooling Fans
l
The following Tech Functions procedures were referred to during the
package reviews:
'
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EMP-002, Mini-Mods, Rev. 0-00
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EMP-014, Project Reviews, Rev. 1-01
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EP-008, Control, Evaluation and Resolution of Review Comments
on Technical Documents, Rev. 1-00
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EP-009, Design Verification, Rev. 1-00
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EP-016, Nuclear Safety / Environmental Impact Evaluation, Rev.
I
1-00
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LP-009, Independent Safety Reviews, Rev. 1-00
The review of the modification packages included the aspects of environ-
mental qualification and fire hazards analysis considerations, proper
design review implementation, proper safety reviews, specification
completeness, establishment of functional criteria, quality assurance
considerations, and adherence to governing procedures. A summary of the
review follows:
9.A The 460V 1A2 and 182 Transformer Cooling Fans (BA 402786) modifica-
tion was initiated as a result of an electrical load study performed
at Oyster Creek. The study determined that the 460 volt 1A2 and 182
4
buses may be overloaded during a loss of coolant accident with off-
site power available and a loss of either IA2 or 182. A licensee
evaluation determined that the transformers' capacity could be in-
creased by adding cooling fans.
This was reported by LER 85-009.
The following documents were reviewed:
--
Procurement Specification SP-1302-11-21R1
--
Purchase Order (Reg. 5350-85-0158-001; P.O. No. PP-027569)
Statement of Justification
--
--
System Design Description I (0C-732A Rev. 0)
(includes 50DII requirements)
--
GPU drawings
Nuclear Safety / Environmental Impact Evaluation (SE 4027862001)
--
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Preliminary Engineering Design Review (PEDR) comments
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Installation Specification (OCIS 402786-001)
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Fire Hazards Analysis
The following concerns were identified as a result of the review:
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A Memorandum of Concurrence was not submitted by the plant
operations representative to communicate the plant's concurrence
as required by Procedure EMP-014, Project Reviews.
If receipt
of the concurrence memo does not occur within four weeks from
the completion of the PEDR, the project engineer is required to
notify in writing the Plant Vice President and Vice President
Technical Functions that further progress on the specific modi-
fication is terminated pending receipt of plant concurrence.
This was not accomplished.
--
The PEDR chairman for the modification was the Electrical Power
Manager, the responsible manager for this particular modifica-
'
tion. Procedure EMP-014, Project Reviews, requires that the
formal members of the PEDR board, as defined in EMP-14, not be
involved in the engineering or managing the engineering of the
design package being reviewed.
The PEDR was conducted by mail
as allowed by EMP-14, but no distinction is made regarding the
PEDR chairman eligibility if the review is conducted by mail.
EMP-14 was not adhered to regarding the PEDR chairman
eligibility.
--
The Operability / Maintainability /Constructability Review (OMCR)
was conducted on 1/15/86 in accordance with EMP-14.
EMP-14
requires mandatory participation by Plant Operations, Plant
'
Maintenance / Material, Maintenance and Construction (M&C),
Startup and Test, Radiological Engineering, GPUNC Quality
Assurance (QA), and the project and design engineers.
In
'
addition to the project and design engineers the following
organizations were represented: Maintenance and Construction
(contract employee), Startup and Test, and Plant Engineering.
QA was not represented, but did provide written comments after
the meeting. Plant Operations was not directly represented,
although Plant Engineering was in attendance. Plant
Maintenance / Material and Radiological Engineering were not
present.
The PEDR meeting was conducted by issuing the preliminary
--
design package for review and comment in accordance with
EMP-14.
The project engineer received comments from the
following organizations: Plant Operations, Plant Engineering,
and Startup and Test. The preliminary design package received
much wider distribution and Startup and Test, QA Engineering,
System Engineering, MC&F, Planning and Scheduling, Engineering
Projects, BWR licensing, M&C Technical Support, M&C Workload
and Control Support, Engineering and Design, Maintenance
Engineering, Operations Engineering, M&C Planning, Mechanical
Systems, and Quality Assurance and Engineering Configuration.
a
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9.8 The drywell thermocouple modification (BA 328145) was initiated to
improve the drywell temperature sensing capabilities in the reactor
head flange area. Previous thermocouples mounted in this area pro-
vided less than optimum indications as a result of their particular
mounting device. This modification is intended to seismically mount
'
two upgraded thermocouples that will provide accurate drywell temper-
ature readings. The modification was conducted in accordance with
the mini-mod procedure EMP-002 as authorized by a letter from the
Director Engineering and Design dated November 25, 1985. Similar
procurement and design documentation was reviewed for this modifica-
tion as was accomplished for BA 402786.
The following concerns were identified as a result of this review:
.
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An OMCR meeting was conducted on January. 29, 1986 in accordance
with procedure EMP-014. The following organizations were repre-
sented at the meeting: Plant Engineering, Maintenance and Con-
struction, and the project and design engineers. Although not
present at the meeting, Startup and Test did send a "to comments"
memoranda to the project engineer.
EMP-014 requires mandatory
participation by the organizations delineated in EMP-011. Not
all of the required organizations were represented.
--
The drywell thermocouple modification is being conducted as non-
environmentally qualified (EQ).
The licensee considers the
thermocouples associated with the Gemac reactor vessel water
level reference leg as the required instrumentation to measure
j
drywell atmospheric temperature. The water level reference leg
thermocouples' primary purpose is to provide indication of ref-
erence leg flashing and, therefore, an indication of correct
reactor vessel water level readings. The licensee has conducted
some analysis to indicate that these reference leg thermocouples
could provide drywell atmosphere temperature indication.
Regu-
latory Guide 1.97 requires drywell atmosphere -temperature instru-
mentation to be qualified as category 1 under equipment qualifi-
,
'
cation. The licensee document, TDR 528 requires drywell temper-
ature to be qualified to category 1.
The licensee is in the
process of revising their commitment in TOR 528 by developing a
new document that will require drywell atmosphere temperature to
be qualified to category 2.
TDR 528 (June 1984) was written in
response to Generic Letter 82-33. An order confirming this
commitment was issued in June 1984.
TDR 528 indicated that drywell temperature is a direct indication
of approaching design temperature limits which could lead to
violation of the safety function of preserving primary contain-
4
ment integrity. Also, drywell temperature is an entry condition
to the Emergency Operating' procedures and an action level to
initiate containment spray and scram the reactor. The safety
functions are reactor coolant integrity and containment integrity.
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The licensee's revised document states that the reactor water
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level cold reference leg temperatures are indicative of drywell
temperatures. Due to their locations and post accident drywell
conditions, plant analysis indicates that these thermocouples
are representative of drywell temperature. TDR 528 also indi-
cated that drywell temperature was in compliance with EQ require-
ments and that the licensee planned to upgrade the system during
11R.
In addition, the TDR indicated that a system for measuring
i
drywell bulk temperature did not exist. The environmental quali-
fication requirements for drywell atmosphere . temperature elements
will be clarified in further discussions with the licensee.
This
will remain an unresolved item. (219/86-06-05).
9.C The recirculation valve interlock modification (BA 402207) resulted
from corrective action to address a low low low reactor water level
condition that occurred in May 1979. On 5/2/79 an inadvertent
1
reactor high pressure scram occurred during surveillance of the
isolation condenser high pressure initiation switches. The high
1-
pressure signal inadvertently induced during the surveillance also
caused all 5 recirc pumps to trip. Operator action resulted in
isolation of the five recirc loops which broke the continuity
between the core region and annulus region. Because reactor water
level instrumentation sensors connect to the annulus region, there
was no indication of actual water level in the core until the triple
4
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low level alarm occurred.
(Triple low alarm signal is generated
from different instrument lines that sense water ' level in the core
region.) A licensee investigation determined it is necessary to
maintain a minimum of two recirc loops open to preclude this type of
scenario. This was consistent with Tech Spec requirements which
';
also requires a minimum of two loop operation. The decision was
made to install an interlock scheme to prevent isolating more than 3
3
j
loops. Subsequent to the licensee's investigation, the NRC issued
NUREG-0660 and 0626 that also required this type of an interlock to
i
be installed.
Over 6 years later, corrective action will be implemented during the
11R outage when an alarm will be installed to alert the operators
when the fourth recirc loop is isolated. The replacement of an
!.
interlock scheme to prevent less'than 3 loop operation to an alarm
that activates when the fourth loop is . isolated represents a
i
substantial scope change.' The inspector questioned the licensee
!
about the scope change, alarm logic, and the lengthy delay in
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implementation of the corrective action. The licensee referred to
NRC Licensing correspondence that tracked the changes.and delays,
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The following documents, in addition to others, were reviewed:
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Design Criteria 391-80-3 dated 9/12/80
Engineering Evaluation 391-80-1 dated 7/29/80
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Installation Specification 391-80-4 dated 3/20/81
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Modification Proposal 391-80-2 dated 8/18/81
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Installation Specification 391-80-5 dated 12/10/81
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Request for Project Approval dated 2/14/86
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OMCR Meeting Conference Notes No. 59 dated 10/16/85
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TOR 528, Rev. 1, Oyster Creek Reg Guide 1.97 Implementation
Construction Release Checklist dated 11/4/85
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Installation Specification OCIS-402207-001 dated 11/4/85
--
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GPUN Drawing E0447, Rev. 2, Elementary Diagram Recirculating
Loop Annunciator Logic
--
Fire Hazards Analysis Input and Status, FPE No. OC-402207-001,
Rev.0, dated 11/5/85
--
Procurement Release Checklists - various
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Purchase Orders - miscellaneous
--
Burns and Roe Work Order 3731-46
GPUN Tech Spec for A/E Engineering and Design Services,
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SP-1302-56-082 dated 5/9/85
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System Design Description (SDD) Div. 1 for Recirc Valve
Interlock Modification, SDD OC-6278 dated 8/30/85
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SDD OC-6278, Rev. 2, Div. II dated 9/9/85
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Nuclear Safety / Environmental Impact Evaluation Summary Sheet
for Recirc Valve Interlock Modification, SE No. 402207-001,
dated 9/18/85
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Work Authorization 415A-30207
PEDR Review conducted 8/8/85
--
The documentation file on this modification was quite lengthy based
on the long history. Various correspondence documented licensee
commitments to the NRC to implement an interlock scheme.
It was not
until just before the start of the 11R outage that the licensee
~
received relief from NRC Licensing to change the scope of the
modification. The engineering for the alarm modification was
performed by Burns and Roe.
The following concerns were identified as a result of this review:
The inspector questioned the alarm logic in that it would seem
--
more appropriate to alarm when 3 loops are isolated. This
could prevent isolating a fourth loop.
This would appear to be
more consistent with the requirements in the Tech Specs and the
intent of the original requirement for an interlock that would
prevent isolating a fourth and fifth lonp. The NRC inspector
pursued this concern with NRC Licensing who stated they
reviewed the licensee's logic and found it acceptable.
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Paragraph 6.1 of the System Design Description (SDO) stated a
Class IE surveillance and ISI program for the new relays should
be implemented and should be consistent with the existing pro-
gram for similar Class 1E relays in the Control Room. The in-
spector requested a specific procedure be referenced, if there
is one, or the statement be deleted.
The licensee stated they
interded to delete the-statement.
The inspector requested clarification of a-jumper that appears
--
on drawing E0501 in that it was not clear from either the
drawing or the related documentation whether the jumper was
existing or new. The licensee agreed to state in the SDD that
a jumper must be added as part of the circuit to supply 125VDC
control power to the alarm reflash unit.
--
Similarly, as discussed in paragraphs A and B above, not all
participants required by EMP-014 were in attendance at the
OMCR.
--
Based on certain memos in the file, it became apparent that
Plant Operations was not responsive to the PEDR process in that
they did not attend the PEDR nor did they comment within 4 weeks
as required by EMP-014. The inspectors asked Tech Functions
management if this was a chronic problem and were informed it
had been a problem in the past but had recently improved.
--
The inspectors were concerned about the time delay in
implementing the corrective action to the 5/2/79 event.
--
Other potential concerns were raised during the review and were
satisfactorily addressed by the licensee.
9.0 The Emergency Diesel Generator (EDG) lube oil modification (BA 402775)
resulted from a recommendation by both the NRC in. Circular 79-12 and
the manufacturer, GM-EMD, to accomplish improved lubrication capacity
to the turbo charger and main engine components.
The recommended
modifications are intended to:
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Eliminate engine bearing potential failure
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Reduce maintenance by continual oil replenishment of the oil
cooler and filters to full level regardless of oil temperature
and viscosity
Remove restart restrictions imposed on unit surveillance and.
--
,
test schedules
Provide consistent oil circulation through the engine
--
crankshaft bearings
Provide consistent circulation through the turbo charger
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bearings
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Vent trapped air which may impede oil flow through the system.
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Oyster Creek is one of the last owners of turbo charged EMD MP45
diesel generators to accomplish this modification. GPUN considers
the modification an improvement and, therefore, not urgent and, there-
fore, the time delay in implementation. The decision to implement
the modification at this time is most likely due to recent problems
experienced with the #10 bearing on the #1 EDG.
The modification
adds an AC and DC lube oil pump, increases some pipe sizes, adds
vents, and adds an improved design lube oil cooler core. The bulk
of the design and installation work has been contracted to Power
Systems with some electrical work contracted to Burns and Roe.
Power
Systems will provide technical direction of installation including
supervision of crafts and labor.
The following documents, in addition to others, were reviewed:
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Tech Functions Work Request (TFWR) A00642 to evaluate and
implement modifications as recommended by GM-EMD
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Croneberger Memo dated 11/19/85, E&D/0C-2426, invoking mini-mod
,
process for this modification
1
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Oyster Creek Installation Specification 402775-001, Rev. 1,
Oyster Creek EDG Lube Oil Modification
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Request for Project Approval
--
Engineering Services Project Cost Estimate
Project Scope Checklist
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Short Form Specification, SP 1302-12-217, Rev. 1, Lube Oil
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System Modification Equipment for GM-EMD MP 45 Diesel Generator
Units
PEDR/0MCR scheduling memo date 2/14/86 that scheduled combined
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PEDR/0MCR for 2/21/86
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Memo MC-86-3603 issued 2/24/86 documenting OMCR meeting on
2/21/86
Memo 5511-86-034 issued 3/19/86 documenting PEDR meeting on
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2/21/86
Safety Evaluation No. 402775-001, Rev. 1, dated 1/30/86.
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Subsequently updated on 2/26/86 and 3/17/86.
Power Systems Proposal No. 83751
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Fire Hazards Analysis FPE No. OC-402775-001
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Verification General Checklist V-1302-86-001 signed 2/4/86
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The following concerns were identified as a result of this review:
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The Memo dated 11/19/85 stated that in accordance with paragraph
4.3.7 of EMP-002, the simplified documentation requirements of
EMP-002 would be invoked for this project since it satisfies the
technical requirements outlined in paragraph 4.1.1 of EMP-002.
What this memo basically did was invoke the " mini-mod" procedure
'
which streamlines the method of modification review and approval
by eliminating certain documents and reviews.
The inspector
4
reviewed the EDG Lube Oil Modification and the-mini-mod require-
ments discussed in EMP-002 paragraph 4.1.1 and determined that
this modification does not satisfy the stated technical require-
ments.
In discussions with GPUN Tech Functions management
regarding this discrepancy, it was concluded the Director-
Engineering and Design does not need to meet 4.1.1 requirements
to invoke the mini-mod process.
The licensee committed to revise
the standard memo used to invoke the m.ni-mod process to
eliminate confusion in the future.
l
The Project Sccpe Checklist stated no FSAR revision was
--
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required. A review of the modification package made it quite
clear, as well as did the Safety Evaluation, that a FSAR change
is required. Subsequent to inspector identification of this
discrepancy, the Project Scope Checklist was corrected.
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Review of Fire Hazards Analysis FPE No. OC-402775-001 disclosed
that it did not evaluate the impact of the addition of the two
<
new motors. Subsequent to inspector identification of this
'
discrepancy, the licensee committed to amend the analysis to
<
include the two additional motors.
4
EMP-014 requires a Memorandum of Concurrence as a vehicle for
--
communicating the plant's concurrence with operability and main-
tainability of modification. A review of the documentation
.
files indicated no Memorandum of Concurrence (M of C) was
1
written. When the inspector pointed this out to the licensee,
he stated he believed that a M of C did exist and it would be
made available to the inspector for review.
Subsequent to this
statement, the licensee stated a M of.C was not required and,
therefore, was not written because the mini-mod process had been
invoked. A review of licensee procedures did not appear to
preclude the need for a M of C, especially in light of the fact
that a PEDR was conducted.
,
EP-008 discusses requirements for Comment . Resolution Forms.
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These forms are to be used by each organization to transmit
their comments in the PEDR and OMCR review processes. Although
,
the Comment Resolution Forms do not become pa'rt of the permanent
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plant records (except if PEDR is by mail), a review of the per-
manent and non permanent records indicated most organizations
involved in the PEDR and OMCR review processes had no comments
as evidenced by a lack of Comment Resolution Forms. The inspec-
tors asked the licensee if it was the intent that if a reviewing
organization had no comments they should so indicate on the
Comment Resolution Form and return it.
The licensee stated this
was not a requirement and was not generally done. Based on this
methodology for soliciting comments as part of the PEDR and OMCR
processes, the inspectors could not conclude that participating
organizations are actively taking part in the review process.
--
The controlling procedures for the Tech Functions review pro-
cesses do not specify what constitutes a quorum. The procedures
do require that specific organizations be invited to a PEDR and
mandatory attendance at the OMCR.
Reviews of the attendance
sheet for the combined PEDR/0MCR indicated that participation
was less than required by EMP-014. The inspectors asked the
licensee what constituted a quorum as not all required or in-
vitec participants attend the OMCR and PEDR meetings. The li-
censse stated that there was no quorum and that the chairman of
the meeting was responsible for cancelling the meeting if in-
sufficiently attended. The inspectors asked if a PEDR or 0MCR
meeting had ever been cancelled due to insufficient attendance.
The licensee stated they could not recall this ever happening.
Tha lack of enforcement of procedural requirements per EMP-014
fr.r mandatory attendance and the lack of a definition for a
q;orum, led the inspectors t.o conclude that the PEDR and OMCR
eview processes may not be as comprehensive as intended.
The inspector asked the licensee if, after completion of the EDG
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Lube Oil Modification, the lube oil system would be flushed.
The licensee stated they do not intend to flush the system but
will rely on Dermar,ent system filters to remove particulate left
from the construction activity.
Procedures LP-009 and EP-016 direct that the Responsible Techni-
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cal Review (RTR) be completed before the Safety Evaluation (SE)
is performed.
In the case of the EDG Lube Oil Mod, it appears
there were two RTRs -- one before and one after the SE.
The
reason for sequencing the SE after the'RTR is to provide a total
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picture to the individual doing the SE. The-procedures do not
address updating the SE if a RTR held af terwards results in
comments.
Procedure LP-009 states that revisions to SEs are not
appropriate.
It is not clear what constitutes a revision, but
it wo.ild seem appropriate that if a RTR held after the SE
resulted in comments, that the individual who performed the SE
would be informed to determine if there was any impact on his SE.
!
This was not accomplished for this med in that the first RTR and
the SE were dated nearly three weeks before the second RTR (PEDR)
and there was no evidence of a subsequent SE by the reviewer.
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The above concerns contain examples of failure of the licensee to follow
procedures.
In summary the licensee failed to:
(1) Follow the requirements of EMP-014 by not issuing a M of C in
two of the four packages reviewed.
(2) Assign a PEDR chairman who was independent of the engineering
or managing of the design package as required by EMP-014 for
the transformer fan cooling modification.
(3) Enforce the mandatory attendance requirements for the OMCR as
required by EMP-014.
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(4) Properly schedule the RTR prior to the SE as required by LP-009
and EP-016 for the EDG Lube Oil Modification.
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These four examples of failure to follow procedures are contrary to the
requirements of Criterion V of 10 CFR 50 Appendix B and represent a
single violation.
(219/86-06-06)
!
The inspectors were also concerned with the substantial time delay between
identification of the need for a modification and final implementation.
Although the licensee appears convinced that the delays are unavoidable,
the fact remains that six years would appear excessive.
The synergistic effects of a group review of modifications is obviously
appreciated and intended as demonstrated by the procedural requirements
governing the process. However, the lack of total participation would
seem to detract from the licensee's goal.
10. Management Meeting
A nanagement meeting was held to discuss the present status of work as-
sociated with IE Bulletin 79-02 and 79-14 on April 1, 1986 in the NRC
Regional office. GPUN Technical Functions Division presented information
'
providing the status of 79-02 and 79-14, schedule and plans for future
work to be conducted, and analysis regarding current system operability.
,
The licensee stated they had deleted the requirement from their inspection
program to determine as found torque on concrete expansion' anchor bolts.
The licensee is going to submit meeting minutes to the regional office for
Concurrence.
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11. Observation of Physical Security
During daily tours, the inspectors verified access controls were in
accordance with the Security Plan, security posts were properly manned,
protected area gates were locked or guarded, and isolation zones were
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.free of obstructions.
The inspectors examined vital area access points
to verify that they were properly locked or guarded and that access
control was in accordance with the Security Plan.
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A portion of the security system was taken out of service because of an
equipment malfunction. Although compensatory measures were taken, they
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were not in accordance with Security Plan requirements. The discrepancy
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was self-identified by the licensee a short time later and corrected.
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After identification of the problem, a search of various areas of the
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plant was conducted to ensure no security breeches occurred. The inspec-
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tors reviewed licensee response to the event and corrective action to
preclude recurrence. No concerns were identified.
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During this report period, the licensee implemented a drug and alcohol
control program.
It is based on a random sampling technique for most
employees and a 100% check on certain critical employees.
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12. -Unusual Event: Bomb Threat
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At 4:35pm on March 24, 1986 the plant telephone operator reported receiving
a bomb threat on an outside line.
The licensee declared an Unusual Event
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at 4:54pm and responded appropriately in accordance with their procedures.
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A search of the site and plant spaces was completed prior to ending the
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Unusual Event.
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13.
Briefings
During this inspection period, the resident inspectors attended briefings
on the following topics:
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Powershape Monitoring system-
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Quality Assurance Annual Review
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Inservice Inspection schedule for cycle 11 refueling outage
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Work Management System
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The inspectors found the briefings to be informative.
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14. Exit Interview
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A summary of the results of the inspection activities performed during
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this report period were made at meetings with senior licensee management
at the end of the inspection. ..The licensee stated that, of the subjects
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dhscussedattheexitintervf'ew,noproprietaryinformationwasincluded.
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During the telephone exit with, Technical Functions, the licensee indicated
that he might be able to provide additional information.or documentation
,
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to alleviate some of the concerns in Detail 9.
Upon receiving no ad-
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ditional documentation or pertinent information af.er ten days, the inspec-
tor' reconfirmed to the licensee the disposition of the findings.
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