ML20036C343
| ML20036C343 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 05/26/1993 |
| From: | Christnot E, Skinner P, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20036C336 | List: |
| References | |
| 50-321-93-06, 50-321-93-6, 50-366-93-06, 50-366-93-6, NUDOCS 9306160139 | |
| Download: ML20036C343 (26) | |
See also: IR 05000321/1993006
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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REGION 11
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101 MARIETTA STREET, N.W.
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ATi.ANTA, GEORGI A 30323
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Report Nos.: 50-321/93-06 and 50-366/93-06
Licensee: Georgia Power Company
P.O. Box 1295
Birmingham, AL 35201
Docket Nos.:
50-321 and 50-366
License Nos.: DPR-57 and NPF-5
Facility Name: Hatch Nuclear Plant
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Inspection Conducted: April 11 - May 08, 1993
Inspectors:
O/2,
_f
f. 20 4 3
Leon rd D.
Wt
Jr., Sr. Resident Inspector
Date Signed
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af
6- 26 *9 3
Edward F. L
tpt,ResidentInspector
Date Signed
Accompanying Inspecto . Bob Ho broo,'C
Approved by:
N<
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I' N b
Pi6rce H. Skinner Chief, Project Section 3B
Date Signed
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Division of Reacto,r Projects
SUMMARY
Scope:
This routine, announced inspection involved inspection on-site in
the areas of operations including a Unit I loss of shutdown
cooling flow and continued review of activities associated with
Unit 2 fuel leakage, surveillance testing, maintenance activities
including a walkdown of drywell conditions, Unit I refueling
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outage activities including modifications, Temporary Instruction
2515/119 (Water Level Instrumentation Errors During and After
Depressurization Transients), and review of open items.
Results:
Two violations and one non-cited violation were identified:
The first violation addressed a loss of shutdown cooling flow
during loading of fuel into the Unit I reactor vessel.
Maintenance activities in a control room panel resulted in a short
circuit and subsequent blown fuse. The blown fuse resulted in
isolation of the injection valve in the operable shutdown cooling
loop. Both loops of shutdown cooling were inoperable for
approximately two hours. A minimal decay heat load and the
availability of numerous other cooling systems resulted in the
safety significance of the particular event being small. Several
concerns were noted regarding the length of time required before
the loss of flow was identified. The licensee's immediate
corrective actions after the problem was identified were
9306160139 930601
ADOCK 05000321
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appropriate (Violation 50-321/93-06-01:
Failure to Comply With
Shutdown Cooling Technical Specification Requirements, paragraph
2b.).
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The second violation involved a failure to comply with emergency
diesel generator alarm response procedures during testing. The
generator outboard bearing temperature increased to above the
value at which the procedure directed that the diesel was to be
shutdown. The inspectors identified the violation during
observation of TS required testing (Violation 50-321/93-06-02:
Failure to Follow Diesel Generator Alarm Response Procedures,
paragraph 3.b.).
The non-cited violation involved a dosimetry technician who failed
to perform portions of a testing procedure on a pocket ion chamber
but recorded in the procedure that the test had been performed
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satisfactorily (NCV 50-321,366/93-06-03: False Documentation of
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Portions of a Dosimeter Calibration Test, paragraph 2.c.).
Two examples of incidents in which a more aggressive questioning
attitude on the part af operating personnel may have reduced the
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significance of or prevented an event were noted.
During the loss
of shutdown cooling flow, an operator observed indications of a
possible short circuit but failed to report or follow up on the
information. During attempts to start a reactor water cleanup
pump, an unexpectedly closed discharge valve was not adequately
pursued before additional pump starts were attempted. Other
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examples involving insufficient questioning of indications by
operators have been noted in recent months (paragraph 2.b.).
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REPORT DETAILS
1.
Persons Contacted
Licensee Employees
J. Betsill, Unit 2 Operations Superintendent
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C. Coggin, Training and Emergency Preparedness Manager
D. Davis, Plant Administration Manager
- P. Fornel, Maintenance Manager
- 0. Fraser, Safety Audit and Engineering Review Supervisor
- G. Goode, Engineering Support Manager
J. Hammonds, Regulatory Compliance Supervisor
- W. Kirkley, Health Physics and Chemistry Manager
- J. Lewis, Operations Manager
C. Moore, Assistant General Manager - Plant Operations
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- D. Read, Assistant General Manager - Plant Support
- P. Roberts, Outages and Planning Supervisor
- K. Robuck, Manager, Modifications and Maintenance Support
- H. Sumner, General Manager - Nuclear Plant
J. Thompson, Nuclear Security Manager
- S. Tipps, Nuclear Safety and Compliance Manager
- P. Wells, Unit 1 Operations Suparintendent
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Other licensee employees contacted included technicians, operators,
mechanics, security force members and staff personnel.
NRC Resident Inspectors
- L. Wert
- E. Christnot
Accompanying Inspector
B. Holbrook
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- Attended exit interview
Acronyms and abbreviations used throughout this report are listed in the
last paragraph.
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2.
Plant Operations (71707) (92701) (93702)
a.
Operational Status
Unit I remained in the cycle 14 refueling outage during the entire
reporting period.
Unit 2 was returned to RTP on April 6, 1993 following a forced
outage due to leaking fuel bundles. On April 13, 1993, plant
management directed that unit power be decreased to approximately
75 percent RTP. Although offgas radiation levels were still
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within TS limits, the levels had increased to above expected
values, apparently due to continued problems with fuel leakage.
Reactor power was subsequently decreased to approximately 55
percent RTP. Reactor engineering conducted flux tilt testing
activities and determined that one of the four fuel bundles
associated with control rod 46-23 was the most probable location
for the leaking fuel. Control rods insertions were performed to
provide flux suppression for the suspected leaking fuel bundle (s).
On April 28, 1993, reactor power was slowly increased to just less
that 75 percent RTP. Additional monitoring and evaluations of the
offgas levels was conducted. At the end of this reporting period
Unit 2 reactor power was being maintained at approximately 74
percent RTP. Offgas sampling and analyses are being conducted at
12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> intervals. The inspectors will continue to monitor the
licensees actions associated with the reactor power increase and
offgas monitoring activities.
Paragraph 2.d of this report
contains additional details of the activities.
The inspectors reviewed plant operations throughout the reporting
period to verify conformance with regulatory requirements, TSs,
and administrative controls. Control room logs, shift turnover
records, temporary modification logs, LC0 logs and equipment
clearance records were reviewed routinely. The inspectors
periodically monitored activities on the refueling floor
associated with the movement of irradiated fuel and in-vessel
maintenance activities. Discussions were conducted with plant
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operations, maintenance, chemistry, health physics, I&C, reactor
engineering, and NSAC personnel.
Activities within the control rooms were monitored on an almost
daily basis.
Inspections were conducted on the day and night
shifts, during weekdays, and on weekends. Observations included
control room manning, access control, operator professionalism and
attentiveness, and adherence to procedures.
Instrument readings,
recorder traces, annunciator alarms, operability of nuclear
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instrumentation and reactor protection system channels,
availability of power sources, and operability of the SPDS were
monitored.
Control Room observations also included ECCS system
lineups, containment integrity, reactor mode switch position,
scram discharge volume valve positions, and rod movement controls.
Numerous informal discussions were conducted with the operators
and their supervisors.
Several inspections were made during shift
change in order to evaluate shift turnover performance. Actions
observed were conducted as required by the licensee's
administrative procedures. The complement of licensed personnel
on each shift met or exceeded the requirements of TS.
The inspectors performed additional reviews regarding the
operability of the SPDS. The system engineers and STAS have been
collecting data and monitoring the online times of the system. A
review of the data indicated that the reliability of the SPDS was
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considered as being very high by the licensee. The inspector
reviewed NUREG 0660 (Item I.D.2) and various correspondence in
attempts to identify a specific SPDS reliability requirement.
Discussions with licensee personnel indicated that the
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installation of the SPDS, in accordance with NUREG 0660, was
adequate. Discussions were held with other NRC personnel familiar
with SPDS and NUREG 0660 requirements.
No regulatory requirements
for SPDS reliability were identified. The system is maintained in
an operable status by continuous monitoring and when a problem or
potential problem is identified corrective action is initiated to
restore the system. The inspectors concluded that the current
system meets the requirements committed to by Hatch. The licensee
has recently discontinued collection of SPDS performance data and
reliability assessments.
On April 21, 1993, during monitoring of CR activities, an
inspector observed operator actions during a decreasing fuel pool
level incident. The Unit 1 CB0 noted that the spent fuel pool
cooling pump 1G41-C001B had tripped on low level. The inspector
noted that the CB0 immediately contacted an operator and ordered
that the draining down of the volume between the reactor cavity
gate and the Unit I spent fuel pool gate be stopped. The
inspector observing the control room activities then proceeded to
the refuel floor and observed some of the recovery activities
there. The inspector immediately noted that the spent fuel pool
level indicated 22 feet. This is above the TS minimum of 21 feet
above the fuel.
Inspection Reports 321,366/90-26 and 92-18 both
contain discussions involving previous spent fuel pool water level
problems.
Both incidents involved pool overflows and problems
with the level indication / alarm systems. The inspectors had
concluded that repetitive problems with the alarms were a
contributing factor to the overflows. Additional review of this
instance identified that the air supply hose used to inflate the
spent fuel pool gate bladder (at the gates between the pool and
the cavity) was not connected properly and resulted in the bladder
not being inflated. The " snap in" connection on the air supply
line had not been fully engaged.
Because the supply air pressure
gage was sensing pressure on the supply side of the connection,
the gage did not indicate the depressurized lines to the bladder.
This in turn allowed water to leak past the gate and into the
volume area being drained down.
The inspector concluded from reviews, observations, and
discussions with licensee personnel that the control room operator
was aware of the plant conditions as well as ongoing evolutions
and took immediate effective action to stop the fuel pool drain
down. The method of connection of the air supply line and location
of the pressure gage contributed to this issue.
It was also noted
that no TS violation occurred. An ongoing followup review by the
inspector involves the status of the fuel pool skimmer tank alarm
system. The pump has a 9 psig low suction pressure trip setpoint.
The skimmer tank low level alarm set point is 222 feet and the low
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alarm set point is 219 feet. At the close of the inspection
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period, the inspectors and the licensee were reviewing the
incident to determine if the alarms should have actuated before
the pump tripped. The inspectors will continue their review of
this issue.
Plant tours were performed throughout the reporting period on a
routine basis. The areas toured included the following:
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Reactor Buildings
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Station Yard Zone within the Protected Area
Turbine Building
Intake Structure
Diesel Generator Building
Fire Pump Building
Unit 1 Drywell
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Unit 1 Torus (area) and Torus (proper)
During the plant tours, ongoing activities, housekeeping,
security, equipment status, and radiation control practices were
observed. No significant problems were noted. Minor housekeeping
and personnel safety issues were resolved as they were identified.
During tours of the lower torus area of the Unit 1 RB, the
inspectors noted several indications of tobacco expectorant
beneath areas of maintenance activities. The inspectors informed
the RB coordinator and outage and planning management of the
observations.
Emphasis was placed on adherence to radiological
work practices during meetings with supervisory and craft
personnel over the next several days. During several tours inside
the torus (proper) area, the inspectors noted that excellent
housekeeping controls and a high level of overall cleanliness
existed in the torus. Some of the ECCS strainers were also
examined with no problems noted.
b.
Hatch Unit 1 Loss of Shutdown Cooling Flow
On April 14, 1993, RHR system shutdown cooling flow was lost on
Unit 1 for a period of almost 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.
Reloading of irradiated
and new fuel bundles had been initiated at about 6:00 am EST. At
the time that the loss of SDC flow was identified, fuel movement
was in progress with 20-25 bundles having been placed into the
vessel. The refueling cavity was flooded up and one train of the
fuel pool cooling system was providing cooling of the cavity
water.
During modification work on a CR panel (the PCIS display panel),
manipulation of wiring in that panel resulted in fuse 1A718-F22
blowing. This fuse powers logic circuitry which provides input to
several valves including IE11-F015B (the "B" loop of SDC injection
. valve). When the fuse blew, valve IE11-F015B closed.
Since the
Qinimum flow valve is shut during SDC alignment (to prevent a
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flowpath from the cavity to torus), this shut off the discharge
flowpath of the "B"
and "D" RHR pumps ("B" SDC loop).
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The problem was identified by a CR operator performing a required
surveillance procedure.
In accordance with procedure 34GO-0PS-
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015-1S: Maintaining Cold Shutdown or Refuel Condition, cold
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shutdown parameters are monitored at least once every four hours.
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One of these parameters is reactor coolant flow, which under these
conditions, is obtained by reference to the RHR system flow chart
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recorder. The flow was identified as indicating zero flow. The
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operators then observed that IE11-F015B was shut and attempted to
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reopen it. The valve traveled open and then reclosed. The SS
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directed that the "D" RHR pump be secured (it had been running-
with the "B" pump in standby). Fuel movement was stopped. This
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was about 10:10 am EST.
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After investigation, replacement of the fuse, and other recovery-
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actions, the pump was restarted at 11:43 am EST. A PE0 was
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stationed at the pump during restart and maintenance personnel
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obtained vibration indications on the running pump.
No problems
were noted. The licensee contacted the pump vendor for additional
information. The vendor' recommended that the pump's performance
be checked against the head curves furnished for the pump. This
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was completed and it was concluded that the pump was not damaged.
The inspectors performed independent reviews 'of the associated
chart recorder indications for flowrates and temperatures.
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Additional discussions were held with the operators-involved in
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the event. The following information was obtained:
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From the time that the F015B valve shut until SDC flow was
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restored was almost three hours total.
For just under one
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and a half hours, the pump was running with the discharge
path secured (before identification). Approximately one and'
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one half. hours were required to restore SDC after the
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situation was identified.
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The inspectors examined the temperature transient in-detail.
Additional information was obtained by correlating the time
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that valve IE11-F015 was stroked open (obtained from the RHR
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flow chart) to the temperature chart. At the time the valve
was stroked, the temperature chart (RHR HX inlet temp)
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showed a " spike" in temperature from 95 degrees F to about
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110-115 degrees F and then a-decrease over about 5 minutes
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to about 105 degrees F.
The inspectors concluded that this.
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is indicative of the warmed pump discharge fluid (no flow
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conditions for about I hour) flowing through the line as the
valve was opened. The temperature sensor (E11-N0048) is
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located in the RHR pump discharge about 50 feet from the
pump and 15 feet before the inlet to the RHR HX. The
temperature trace was steady for the next 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, then-
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decreased to just under-100 degrees F very rapidly as the
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RHR pump was restored. After the immediate drop, the
temperature decreased to 95 degrees in less than 15 minutes.
The inspectors concluded that the reactor vessel water may
not have increased in temperature at all during the event.
Since there is no direct indication, it is difficult to-
determine exactly what the vessel temperatures response was.
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The inspectors also concluded that the licensee had neither
neglected preplanning nor took inappropriate risks regarding
the modification that was in progress that caused the 1 Ell-
F015 valve to shut. The circumstances which resulted in the
problem were not reasonably foreseeable. Care was being
exercised in handling of the CR panel. A wooden support
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frame had been constructed to facilitate the work.
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There is no annunciator or alarm to warn the operators of
such an occurrence. By procedure, the checks of cold
shutdown parameters are only required once every four hours.
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Additionally, the inspectors noted that the personnel
working on the panel probably partially blocked the
operator's view of the RHR system mimic where the IE11-F015B
valve position is indicated. During initial follow-up
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discussions some information indicated that the modification
workers had noted an electrical spark (apparently when the
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wires were shorted) and reported it to a nearby operator,
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but did not report this to onshift management.
The safety significance of this particular event is very small.
Numerous backup systems to cool or maintain the inventory of the
cavity were available. 'These included: FPC system (one train was
in service to the cavity during the event, the other was aligned
to the spent fuel pool),
"B" CS system, an alternate (temporary)
fuel pool cooling system, PSW, demineralized water, CRD system,
and CST makeup. Attachment 2 of 34AB-Ell-001-IS:
Loss of
Shutdown Cooling, provides a graph of " vessel and cavity boil-off
time" (the amount of time required for boiling to cause reactor
level to decrease to the ECCS setpoint) vs number of days since
core last critical. The graph assumes all fuel is still in the
core, all cooling is lost, and initial temperature is 150 degrees
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F.
In this case, only 20-25 bundles were loaded, and all cooling
had not been lost. The reactor had been scrammed on March 16,
1993. Using 30 days as an entry point on the graph, the
inspectors noted that it would require at least 150 hours0.00174 days <br />0.0417 hours <br />2.480159e-4 weeks <br />5.7075e-5 months <br /> to reach
boil-off to the ECCS setpoint, even without accounting for the
numerous conservatisms of this example. Approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
would be required before boiling would start to occur in the core
area. The inspectors also noted that 2 of the 3 EDGs were
operable and both offsite power sources were operable during the
event.
Information provided in draft NUREG 1449:
Shutdown and
Low Power Operation at Commercial Nuclear Power Plants in the
United States, was used to assess the safety significance.
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Additional followup reviews and observation by the inspector
indicated that when the short circuit occurred, an operator,
(acting as an assistant plant operator and performing ECCS status
checks) and the modification implementing crew had noted
indications that a circuit had been shorted (a small arc).
However, aggressive action was not taken to investigate possible
problems that might have occurred. The CBO, plant operator, or
shift management was not informed that a potential grounding of a
control panel circuit had occurred. The inspectors noted that
step 8.11.5.2 of procedure 30AC-0PS-003-0S:
Plant Operations,
states that the Assistant Plant Operator is required to keep the
SS and Plant Operator informed on plant problems and activities.
Although more aggressive pursuance of the observed indications may
have reduced the time required to identify the loss of flow, the
inspectors concluded that the failure to report this particular
observation was not a violation of these procedural requirements.
While it was not unreasonable for this operator, given the ongoing
activities, to characterize the observed "small electrical spark"
as not a " plant problem," it would have been more prudent to
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inform the CB0.
The inspectors noted that another incident which did involve a
clear failure to conduct proper followup of an observed problem
occurred on April 28, 1993. Operators attempted to start the "1A"
RWCU pump after it had been secured for the reactor vessel
pressure test.
The pump tripped and the discharge valve was found
shut. The valve was reopened and the pump was restarted and
tripped again. Subsequent-investigation indicated that the pump,
which the shift had considered to be in a " standby" condition, had
been fully secured. Cooling water had been isolated. The
inspectors' review of the incident indicated that the problem was
not caused by any direct failures to follow procedures.
Miscommunications and a lack of questioning on the part of the
operators were the primary causes.
The inspectors concluded that
the lack of additional followup after the discharge valve was
found unexpectedly closed was a weakness on the part of the
involved operators. As noted in the loss of the SDC flow
incident, more aggressive followup actions may have prevented or
reduced the significance of the problem. The inspectors noted
that operations management issued a memo which addressed the role
that a lack of a questioning attitude played in these events.
Other examples of inadequate followup actions have been noted in
the recent months, some identified by the licensee, others
identified by the inspectors. The Senior Resident Inspector
discussed these examples of inadequate questioning and
insufficient followup with the General Manager.
While the loss of SDC flow situation was not considered to be of a
large safety significance, the event did highlight a vulnerability
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of Hatch (and similar BWRs) due to the unavailability of a strong
indication of a loss of SDC system flow. The inspectors noted
that the licensee had placed the plant in more limiting
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circumstances during the reactor vessel disassembly prior to
unloading the core. One train.of RHR was available, the cavity
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was not flooded, and decay heat-loads were considerably higher.
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If this loss of cooling had occurred under these conditions, the
safety significance could have been much more significant.
Several other differences were noted between the plant conditions
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during the actual cooling loss and those during vessel
disassembly. The plant computer was operable during vessel
disassembly and a increasing temperature indication should have
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been more noticeable. The outage " safety assessment" had listed
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decay heat removal as a " red" condition (primarily due to the
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unflooded cavity) so more attention may have been focused on the
SDC system. Under those conditions, if SDC flow had been lost for
almost 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />, a significant. temperature increase would have
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occurred. The licensee is considering stricter monitoring
requirements on the SDC system under certain conditions.
In addition to the restoration actions, the licensee initiated an
operations crder requiring more frequent control room panel
walkdowns. The event was reported to the NRC Operations Center
due to the actuation of the Group 2 isolation valves. A detailed
review of the event was conducted by the licensee, and additional
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corrective' actions are being considered. This issue is identified
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as Violation 50-321/93-06-01:
Failure to Comply with Shutdown
Cooling TS Requirements.
c.
Failure to Perform Dosimetry Leakage and Calibration Test.
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During an investigation performed in an effort to resolve a
discrepancy between an individual's TLD and PIC dose recordings,
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portions of a calibration check of the PIC were documented as
completed, when in actuality, they had not been performed.
Section 7.5 of 62RP-RAD-001-OS: Dosimetry Issuance and Tracking,.
contains requirements associated with assessment of a worker's
exposure. One of the requirements is to initiate an investigation
when the difference between the TLD and PIC measured exposures'is
greater than 25 percent.
In this case, the difference was-greater
than the allowable amount and an assessment was required. A " Dose
Discrepancy Investigation" form (Attachment 17 of the procedure)
was completed and the " investigation finding" of "possible drift"
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of the PIC was indicated. The next step is typically to
investigate / test the PIC to identify any problems.
Section 7.3 of 62HI-0CB-012-OS:
Pocket Dosimeter Use and
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Performance Test, provides guidance on calibration. -In accordance
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with this procedure, a " Charge-Leakage" test was performed
satisfactorily by a dosimetry technician. Another technician was
then supposed to perform the " Dosimetry Calibration" (Section
7.3.2).
This test involves exposure of the PIC to a source.- The
test was not performed. The technician falsified portions of the
" Dosimetry Leakage and Calibration" form by recording data that
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indicated the test was performed. Another worker in the
department informed the foreman of suspicions that the test had
not been performed. Checks of RWP records and source check-out
records supported the accusation. When confronted, the worker
admitted falsifying the test. Subsequently, a test of the PIC was
satisfactorily performed.
The involved worker has been assigned to these " dosimetry" duties
since 1987. Typical duties are primarily administrative and
include whole body checks and dosimetry records maintenance. This
worker was not involved in activities such as surveys or HP
coverage of activities. Most of the tasks that were performed by
this worker are routinely reviewed by additional personnel.
During discussions with licensee supervision, the inspectors were
informed that this worker has a very good work record.
The inspectors noted that the involved procedures are safety
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related. Administrative TS requirements address this type of
testing and documentation. The inspectors noted that the licensee
promptly informed the inspectors of the event, conducted
investigations, and interviews and disciplinary actions were
taken. The importance of honesty and accountability was re-
emphasized to all plant personnel. A memo on this subject
recently written by the Hatch Vice President was recirculated.
After review of the licensee's corrective actions in this matter,
the inspectors concluded that.the actions were appropriate. This
issue will not be subject to enforcement actions because the
licensees's efforts in identifying and correcting the violation
meet the criteria in Section VII.B of the Enforcement Policy, for
non-cited violations. After discussions with NRC management, it
was determined that this issue is a violation of 10 CFR 50.9.
This issue is identified as NCV 50-321,366/93-06-03:
False
Documentation of Portions of a Dosimeter Calibration Test.
d.
Hatch Unit 2 Continuing Fuel Leaking Incident
Unit 2 power was increased to RTP on April 9,1993, following a
forced outage to conduct fuel sipping and inspection to identify
possible leaking fuel. The unit remained at nearly RTP until
April 13,1993. As expected, during the power increase, offgas
radioactivity levels increased. However, a chemistry sample
conducted on April 12, 1993, indicated the " sum of the sixes" (TS
required noble gas samples of Xe-133, Xe-135, Xe-138, Kr-85, Kr-
87, and Kr-88) indicated possible fuel leakage. The offgas levels
were well below the regulatory limits but were increasing to a
level greater than expected for the current plant conditions. On
April 13, 1993, plant management directed that unit power be
decreased to approximately 75 percent RTP.
Reactor power was
eventually decreased to approximately 55 percent RTP.
Reactor
Engineering began flux tilt inspection activities of the reactor
core. The licensee determined that one of the four fuel bundles
associated with control rod 46-23 were the major suspects for fuel
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leakage.
Control rod 46-23 and two adjacent control rods, 46-19
and 50-23, were intentionally inserted to "00" (full in). One
additional control rod, 42-23, which was at "00" due to the
existing control rod pattern, was being maintained at the "00"
<
full in position. These control rods serve as shielding or
neutron flux suppression for the suspected leaking fuel bundles.
At 6:40 p.m. EST, on April 28, 1993, the licensee decided to
-
slowly increase reactor power to just below 75 percent RTP, and
conduct additional monitoring and evaluations of the offgas
levels. Written instructions were provided to the operating
shifts as to the methodology to be used in power ascension.
Sampling of the offgas continued, and the value of the " sum of the
sixes" appeared to be satisfactory for the power increase. This
power level will be maintained until the licensee collects
additional data and conducts further evaluations of the offgas
releases. At the present reactor power level (74 percent) the
offgas levels for gross gamma radioactivity rate of noble gases is
well below the TS limit. Currently the value of the " sum of the
sixes" is approximately 13 percent of the TS limit. At the end of
this reporting period Unit 2 reactor power was being maintained at
approximately 74 percent RTP and offgas sampling and analysis are
being conducted at 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> intervals.
The inspectors have reviewed the TS requirements, monitored the
day to day activities in the CR, and completed some independent
reviews of the offgas sampling results.
The inspectors will
continue to review the licensees actions associated with the
reactor power increase and offgas monitoring activities.
.
e.
Unit 1 Reactor Water Level Instrument Anomalies
At 1:15 p.m. EST, May 1, 1993, during the heat up and
pressurization stage of the reactor vessel pressure test, the unit
received a full scram and a 1/2 group 2 isolation signal from low
reactor water level. The reactor temperature was approximately
180 degrees F and pressure was 100 psig.
Following the scram the
operators verified reactor water level at approximately +175
inches and steady.
Following further investigation it was
determined that all level instruments attached to reference leg
D004A were reading low. This would usually be indicative of a
problem associated with the variable leg.
Operators were dispatched to the reactor building to inspect the
instrument racks and tubing associated with these level
instruments. No discrepancies were identified.
Personnel were
then dispatched into the DW to walkdown the instrument tubing,
from the DW penetration to the reactor vessel, and investigate for
leaks. No leaks or other problems were identified. Various
trouble shooting activities were initiated. This included
lowering reactor water level to verify the accuracy of the other
available instruments (IB21-R605 and IC32-R655).
I&C connected
digital differential pressure gauges to check the response of the
.
f
.
11
instrument legs and theorized that air bubbles must be in the
i
instrument lines. The instrument lines were then back filled.
Further investigation found that the equalization valve for
instrument 1821-N035 was slightly cracked open.
It was postulated
that this could allow air from the pressure test to be injected
into the variable legs and produce the level responses that were
being observed. The equalizing valve was closed and the reactor
vessel pressure test was resumed.
When the reactor recirculation pumps were used to increase core
flow (as part of the reactor vessel heatup process) the level
-
instruments in question again began to read low. Once the core
flow was stopped, the instruments would trend back up to .
.'
approximately normal position. The reactor vessel pressure test
was again stopped and further investigation was conducted.
checked the various instruments that could be leaking-by, either
through the equalizing valve or through a ruptured diaphragm. The
following instruments were checked for possible leakage:
1821-
N085, NO38, N070, and NO36. The instruments were isolated and
returned to service individually while the instrument and level
responses were monitored.
Following this investigation, it was
concluded that instruments N085 and NO38 were not the cause of the
,
problem. However, N070 and NO36 showed signs of some leakage.
With N070 and NO36 isolated, the shift began the reactor vessel
pressure test again. The level instruments displayed the same
anomalies. The test was again terminated.
Following additional discussions with I&C, it was determined the
variable legs of the instruments had not been properly back
filled. At 11:57 a.m. EST, May 2, 1993, a manual scram was
initiated (to aid in the filling of the instrument legs) and I&C
proceeded to back fill both the reference and variable legs of the
instruments.
I&C technicians reported that during the process of
back filling the reference legs (using a hydro pump) the reference
leg pressure increased to approximately 350-400 psig, and then
suddenly decreased. This response indicated that there had been
some type of blockage in the reference leg.
Instruments N070 and
NO36 were calibrated by I&C and placed back in service, and all
water level instruments indicated normal. At 1:40 p.m., May 2,
1993, the reactor vessel test was continued. The licensee
conducted further investigation and review of outage work that
could have affected the reactor water level instruments.
During the outage, a DCR was completed to correct the slope of the
instrument legs associated with condensing chamber D003A and
D004A. These lines did not have the specified minimum slope. As
discussed in GL 92-04, the modification would have decreased the
probability of erroneous water level indications. This
modification required cutting out and rewelding sections of the
reference leg piping.
In order to complete this work, a temporary
plug was installed in reactor vessel penetration N12A. Apparently
the plug did not provide a completely water tight seal and the
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12
i
reference leg could not be completely drained and maintained dry.
In order to perform a dry weld on the reference leg, the welding
.
supervisor directed the welders to plug the reference leg (near
the weld location) with " rice paper."
The rice paper was rolled
up (approximately a five inch roll) and forced up into the
reference leg. This " rice paper" is actually soluble purge dam
material referred to as "Dissolvo WLD-35."
It is designed to
i
absorb a liquid, and after a time period, completely dissolve into
t
the liquid.
It is commonly used as a dam during inert gas welding
evolutions. Discussions with plant management indicated the use
of rice paper was standard practice. The inspectors noted that
the use of rice paper had been recorded on the modification work
i
package.
It was learned that the rice paper had been in place for
'
approximately 21 days prior to the reactor level anomalies.
The ERT investigating the event theorized the rice paper had not
I
dissolved completely (due to the length of the roll) and perhaps
air had been trapped on the downstream side of the roll which
prevented the paper from becoming saturated. When the I&C
technicians had pressurized the reference leg with the hydrostatic
test pump, the roll was forced through the reference leg into the
reactor vessel. The investigating team had a model of the
reference leg piping fabricated, plugged the leg with rice paper
and with a high pressure air supply and a hydrostatic test pump
'
simulated back filling the leg.
It was determined the rice paper
could be moved up through the reference leg and could provide the
same type of response as was seen during the back filling
evolutions. Additionally, a standing water column was placed on a
tightly rolled section of the paper which was jammed into a
transparent column. The inspectors observed that over a period of
6 days, the water had migrated through less than half of the
rolled paper mass.
It was concluded that the dissolution of the
paper depends on sufficient exposure to water. Tightly packed
large accumulations of the paper prevented some of the paper from
being dissolved. The inspectors also noted that chemistry samples
of the reactor coolant (after the hydrostatic pump was used)
supported the postulation that the rice paper had been discharged
into the reactor water and had dissolved (an increase in
sulfates).
One of the inspectors closely followed the licensee actions
dealing with the reactor water level anomalies. Two different
phone conversations were held late in the evening of May 1, and
onsite review was performed early in the morning of May 2,1993,
to follow up on the actions. The inspector observed that there
were adequate reactor water level indications and that the
operators were closely monitoring the level. No TS violations
occurred. The inspector verified that the reactor scram was reset
and the group isolation was reset and valve positions were
correct. The operations shift management, STA, 1&C technicians
and the hydro test engineer were actively pursuing the level
.
.
13
problem.
P&ID's and procedures were being utilized for guidance
during the trouble shooting.
During discussions with plant management and ERT personnel, the
inspectors noted that there are no specific guidelines as to how
much or how large a quantity of rice paper should be used during
maintenance activities. The requirements of the job being worked
generally would dictate how much would be used.
Skill of the
worker was relied upon for installation. The inspectors concluded
that the licensee actions dealing with the reactor water level
anomalies were appropriate. At the close of the inspection
report, the licensee's ERT was still reviewing the issue for
further corrective actions. More controls on the use of the paper
are being considered to preclude recurrence of such an event.
One violation and one non-cited violation were identified.
3.
Surveillance Testing (61726)
a.
Surveillance tests were reviewed by the inspectors to verify
procedural and performance adequacy. The completed tests reviewed
were examined for necessary test prerequisites, instructicns,
acceptance criteria, technical content, authorization to begin
work, data collection, independent verification where required,
handling of deficiencies noted, and review of completed work. The
tests witnessed, in whole or in part, were inspected to
determine that approved procedures were available, test
equipment was calibrated, prerequisites were met, tests were
conducted according to procedure, test results were acceptable and
systems restoration was completed.
The following surveillances were reviewed and witnessed in whole
or in part:
-
1.
2.
421T-C11-001-05: Control Rod Drive Friction Testing
3.
Loss of Site Power / Loss of Coolant
Accident Test
4.
Primary Containment Integrated Leak Rate
Test
On April 15, 1993, the inspectors observed portions of the EDG 1A
22.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> post maintenance run (after cylinder liner replacement).
The inspector was present when a leak occurred due to the failure
of the flexible hose in the cooling water system between the
expansion tank and coolers.
The hose was replaced and the post
maintenance test was completed.
The licensee determined that the
'
hose failed due to age and will inspect the hoses of the other
'
.
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,
.
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14
EDGs. This test included loading the EDG and maintaining 3550 KW
for one half hour. There were no other discrepancies identified.
'
The inspectors monitored Unit 1 Control Rod Drive Friction Testing
activities. The monitoring included observations of operator
activities in the CR.
Procedural usage, control rod
'
manipulations, work practices, communications between the various
test personnel, and administrative activities were observed. The
inspectors also monitored activities locally in the reactor
building and discussed test results with the test engineers and
I&C technicians. There were no discrepancies identified.
The inspectors also observed and reviewed the activities
associated with the Unit 1 CILRT. This included independent
reviews of the preparation, initial pressurization and
stabilization. The inspector noted that test personnel
demonstrated awareness of the minimum and maximum pressurization
requirements for the test, the parameters necessary to declare
stabilization, and the verification requirements. The inspector
will perform additional reviews of the final data. The test was
performed in accordance with the approved procedure.
b.
IA EDG Outboard Generator Bearing High Temperature
During the performance of the Diesel Generator IA 24-Hour Run/LOSP
LSFT surveillance test, conducted on April 21, 1993, the
inspectors observed the pre-job briefing, procedure review, and
discussions which were conducted by two system engineers for the
operations group. The control board operator (to start and
-
monitor the EDG from the CR) and two PE0's (to locally monitor the
EDG and record data during the EDG run) were present. The
inspectors observed the initial starting and loading of the 1A EDG
from the CR and observed EDG operations and data taking activities
locally at the EDG building. One of the inspectors, after
reviewing the data that was being recorded by the PEO, observed
that the EDG outboard bearing temperature was greater than the
expected band (100-170 degrees F) as indicated on the surveillance
data sheet. The inspector verified locally (temperature indicator
1R43-R767A) that the EDG outboard temperature was 184 degrees F
and increasing. The inspectors determined that the alarm response
procedure, 34AR-652-Il3-IS: Diesel Generator IA Inboard /0utboard
Bearing Temperature High, states that an alarm actuates upon high
temperature. The inspectors verified that this alarm had actuated
in the CR at 180 degrees F.
The operator actions of the alarm
response procedure directed personnel to confirm that a high
bearing temperature condition existed on temperature indicators
1R43-R767A or 1R43-768A, and if IA EDG was in " test," to shutdown
the diesel per the system operating procedure or applicable
surveillance procedure. After observing that the EDG was still in
operation, and following discussions with operations personnel in
the CR, it was determined that the SOS had directed that the 1A
EDG not be shutdown until the bearing temperature reached 190
.
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15
i
degrees F.
Additionally, the inspectors verified that instrument
setpoint or procedure change requests that would allow the EDG to
be operated with elevated bearing temperatures had not been
implemented. The inspectors discussed their observations with
operations management (above the SOS level) who indicated that
they were not aware of the present bearing temperature problem.
However, they did state that they were aware of a previous problem
that had occurred during a similar EDG run and vaguely remembered
that a vendor representative stated a bearing temperature of 205
degrees F or less would be satisfactory. When the bearing
temperature reached 190 degrees F, the operators shutdown the EDG.
The inspectors determined that, prior to shutdown, the EDG was in
operation for approximately two and one half hours with the
outboard bearing temperature greater than 180 degrees F.
Failing
to shutdown the 1A EDG with the outboard bearing temperatura
greater than the value indicated in the alarm response procedure
l
was discussed in a meeting with plant management.
Plant
management at this time stated they expected the operators to
comply with the written procedures or use the correct
administrative process to have the procedures changed. The
following is a brief account of the EDG runs and maintenance
activities initiated after the outboard bearing high temperature
indications:
,
On April 22, 1993, following the initial outboard bearing
high temperature indication, the 1A EDG bearing oil system
was flushed. The 1A EDG was run and again was required to
be shutdown due to an outboard bearing temperature reaching
180 degrees F.
Maintenance activities were initiated to
replace the outboard bearing.
It was also determined that
the thermocouple sensing this bearing temperature was of the
wrong type.
The type of thermocouple that was installed
("J" type) resulted in indicated temperatures being 10
degrees F higher than values indicated by the correct type
of thermocouple ("S" type).
On April 23, the 1A EDG was run again and was required to be
-
shutdown due to the outboard bearing high temperature
problem.
It was learned during the subsequent maintenance
activities (to again replace the bearing), that during the
first bearing replacement the oil port to the bearing had
been partially blocked. A metal gasket had been rotated
such that the oil port did not align with the oil supply
system.
On April 24, 25, and 26, additional testing of the 1A EDG
was conducted, and additional shutdowns were necessary due
to the outboard bearing temperature approaching or reaching
180 degrees F.
Activities following the unsuccessful runs
included maintenance inspections by plant maintenance
personnel and vendor representatives and coupling alignment
i
adjustments.
>
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.
a
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16
.
On April 27, the licensee initiated a temporary procedure
change to the EDG post maintenance procedure, procedure
42SV-R43-030-IS: Diesel Generator IA 24-Hour Run/LOSP LSFT,
and alarm response procedure 34AR-652-113-IS: Diesel
Generator IA Inboard / Outboard Bearing Temperature High.
These temporary procedure changes allow operation of the EDG
with an outboard bearing temperature increase to 205 degrees
F.
The 1A EDG was again run and the outboard bearing
temperature increased to between 195-196 degrees F.
The
inspectors observed that during subsequent post maintenance
test runs and during the required 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run, the EDG
bearing temperature indicated between 164 and 168 degrees F.
.
Additional reviews and observation by the inspectors, as well as
discussions with licensee personnel, indicated the following:
-
-
A total of six EDG runs were made on a daily basis, observed
periodically by the inspectors, between April 21-28, 1993.
Each run indicated outboard generator bearing high
temperatures.
-
The April 15, 1993, liner replacement maintenance activities
and maintenance run of the EDG had been completed with no
deficiencies identified.
-
The wrong type thermocouple was replaced with a correct type
and the other four EDG were verified as having the correct
type.
.
A discussion with the EDG vendor indicated that a grounded
-
thermocouple could contribute to a high temperature due to a
heating effect.
Licensee personnel insulated the bearing
'
thermocouple.
-
The generator bearing was changed out two times with two new
bearings.
-
The rotation of the metallic gasket that blocked the oil
supply to the bearing housing did not contribute to the
bearing high temperature experienced on April 23, 1993. The
oil level in the bearing oil sump was maintained at a high
level .
Consequently the oil ran through the bearing and
into the bearing housing. However, this activity did
demonstrate a poor work practice.
-
The licensee formed an engineering team to review the
circumstances involved with the bearing high temperature
problem.
-
The EDG completed a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> TS run on May 2, 1993.
No
bearing high temperature problems were observed.
.
.-
17
The inspectors will continue to monitor and review the licensee's
activities in this area. The principle issues involved correct
placement of the thermocouple sensors in relation to the bearing
races. Additional review of this aspect is being conducted by the
licensee.
It appears that the situation could have been resolved
by more realistic temperature limits in the procedures. An
additional factor in this issue is that, due to work completed on
the EDGs during the outage, the EDGs were being run with reactive
loading in excess of previous testing. While considerable
troubleshooting and maintenance activities were required to
correct the problems, the inspectors concluded that the problems-
did not involve operability of the EDGs. The inspectors also
questioned if indications of a failed or failing bearing had been
precluded by the thermocouple sensors being placed too far away
from the bearing surface.
The failure to shutdown the 1A DG when the outboard bearing
temperature exceeded 180 degrees F, as required by the alarm
response procedure, is identified as Violation 321/93-06-02:
Failure to Follow EDG Alarm Response Procedures.
>
One violation was identified.
4.
Maintenance Activities (62703)
a.
Maintenance activities were observed and/or reviewed during the
reporting period to verify that work was performed by qualified
personnel and that approved procedures in use adequately described
work that was not within the skill of the trade. Activities,
procedures, and work requests were examined to verify; proper
authorization to begin work, provisions for fire hazards,
cleanliness, exposure control, proper return of equipment to
service, and that limiting conditions for operation were met.
The following maintenance activities were reviewed and witnessed
in whole or in part:
1.
MWO 1-93-1906: Replace Outboard Bearing on IA EDG
Alternator
2.
MWO 1-92-5048:
1A Diesel, Alternator and Accessories
Inspection
3.
MWO 1-93-309:
1A EDG Major Internals Components Inspection
4.
MWO 1-92-6685:
IST Leak Rate Test of Valve 1E41-F005 (HPCI
Discharge Check Valve)
The inspector reviewed and observed the licensee's activities
involved with the 1A EDG. Additional discussion is provided in
paragraph 3.a of this report. The inspector noted effective use
of two procedures, 51GM-MNT-032: Component Alignment of Rotating
.
-
.
-
.
.
18
Equipment, and 52CM-R43-002-OS: Alternator Major
Inspection /0verhaul. The local leak rate testing of the HPCI
check valve was conducted in accordance with the IST procedure.
The licensee informed the inspectors that during EQ qualification
testing of MSIV solenoids (three solenoids attached to a housing
block), Wyle laboratories reported finding a small (1/8 inch)
particle of non-magnetic metal in one of the solenoid blocks.
These solenoids had not been installed in the plant. Wyle
laboratories then proceeded to dissemble and inspect five
additional solenoid blocks and no discrepancies were noted.
Additionally, four other solenoid blocks were inspected and again
no discrepancies were noted. The licensee stated that the small
piece of nonmetallic metal in one solenoid block seemed to be an
isolated incident and, after reviewing the results of the
additional testing that was performed, was confident about the
qualification and operability of the solenoid valves. The newly
inspected solenoid valves have been installed on each of the eight
MSIV's and have been tested satisfactorily. The inspectors
completed an independent review of procedure 34SV-B21-002-IS:
Main Steam Isolation Valve Trip Test, the regulatory requirements,
acceptance criteria and test results. There were no discrepancies
identified. The inspectors will continue to monitor the
performance of the solenoid valves.
b.
Drywell Inspection
,
'
Due to some deficiencies noted during previous outage DW tours and
the significant amount of insulation material that the inspectors
,
had noted removed for work during the outage, the inspectors
examined conditions in the DW at the end of the outage. The
inspectors reviewed General Electric specification 21All82:
" Standard Requirements For Reactor Vessel Insulation" and the
associated drawings for the insulation installation and procedure
52GM-MME-007: Drywnll Closeout.
Even though the DW was not ready
for official closeout, the inspectors conducted an inspection of
the Unit 1 DW to assess the general conditions and observe work
activities associated with closecut preparation. The inspectors
viewed the general areas for cleanliness and assessed the amount
of scaffolding, tools and equipment yet to be removed.
Additionally, the inspectors inspected piping, valves and
connections for apparent deterioration, damage or leakage; and
observed the general condition and installation of the reactor
vessel insulation. The general areas were relatively clean and
most of the tools, equipment and scaffolding were removed. There
were no apparent valve or component leakage or damage identified.
,
The inspectors observed that, except for three or four pieces of
insulation around the main steam line penetrations, the reactor
vessel insulation was in place.
It was noted that several of the
fasteners used to hold the insulation in place were either damaged
or missing. The areas of insulation that were to be secured by
the damaged or missing fasteners were held together by wire.
It
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19
was also noted that a metal band which would. aid in holding the
insulation in place encircled the reactor vessel on the outside of
the insulation. The insulation showed many signs of dents and
scrapes, but these did not appear to affect the serviceability of
the insulation. There were some small gaps observed, but none
that seemed to be in excess of the specification guidelines.. It
3
was noted that three of the four pieces of insulation that were.
not installed were either placed on the grating or leaning against
l
the reactor vessel. Step 5.7.8 of GE specification 21A1182:
" Standard Requirements For Reactor Vessel Insulation," indicates
?
that the pieces of removable insulation would be placed on
I
hangers. Discussions with licensee personnel and a review of
procedure 52GM-MNT-018-OS: Removal, Storage'and Installation of
Reflective Insulation, indicated that insulation removed at Hatch
is not normally placed on hangers.
Instead, the procedure directs
i
establishing temporary storage a: close to the work area as-
.
practical. The three or four pieces of insulation observed by the
!
inspectors were placed very near the location where they would be
-
reinstalled. The procedure also requires that barricades or signs
!
be installed to prevent personnel from climbing over.or standing
'
on the removed insulation while it is in temporary storage. .The
inspectors did not. observe any signs or barricades erected to
'
protect the pieces of insulation that were not installed. The
inspectors were informed that management is reviewing this issue-
!
and considering other storage methods which would reduce the
,
!
probability of damage to removed insulation.
'
5.
Outage Activities and Modifications (37701) (37828) (62703)
The inspector continued to review, observe and discuss specific
modifications completed, started and tested for the Unit 1 outage and
for Unit 2.
The specific modifications involved were :
1
DCR 89-278:
SBGT Hardened Vent Pipe Bypass
DCR 91-135:
SRVs Electrical Overpressure
i
DCR 92-011:
EHC System Logic Modifications
DCR 92-170:
Refueling Floor HVAC, Unit.2
3
The review consisted of the DCR packages, including the 50.59 reviews,
.i
individual design drawings within the DCR packages, and applicable
design drawing notes. The observations included the installation work
procedures of the Unit 2 refueling floor HVAC and post modification
testing of DCR's92-170 and 89-278. The discussions included attendance
at meetings, interfacing with licensee personnel and contractors,. and
discussing field observations and reviews with cognizant personnel.
j
!
The inspector closely reviewed DCR 92-011:
EHC System Logic
Modifications. This modification was implemented to remove the one of
one logic for turbine trips on low EHC fluid pressure, shaft low oil
j
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20
pressure, and stator cooling high outlet water temperature. The
implemented logic is 2 out of 3 for the parameters. The inspector
i
concluded that this modification did not impact the RPS trips from the
main turbine. The inspector was informed that this DCR was initiated
and sent to the field for implementation by the A/E, and not the vendor.
The inspector was also informed that the vendor has a modification
available which would provide the same 2 out of 3 logic. The vendor's
modification has a feature that the current modification does not have.
This feature would ensure that the system would fail in a safe
direction. Modifications management indicated that the DCR, as
implemented, would remain, and that during a future outage the
modification would be changed to incorporate the vendor's features.
The inspector reviewed modification, DCR 92-144:
Intake Structure
.
Ventilation Fans. This modification was initiated to eliminate a' single
failure vulnerability of the intake structure ventilation fans.
Fan
IX41-C009C was to be powered from a Unit 2 electrical source and fans
'
IX41-C009A and B were to remain powered from a Unit 1 power source. The
modification also required that each fan have their own control station,
consisting of a control switch and positions HAND-0FF-AUTO, and RED and
GREEN indicating lights, and a thermostat. The inspectors follow up
actions will consist of a review of the installation and testing of the
-
DCR.
One Unit 2 modification was reviewed.
DCR 92-170 was implemented to
eliminate the ability to use four control switches for dampers, 2T41-
F023A/B and 2T41-F023A/B, to override the automatic closure of these
refueling floor ventilation system dampers. Control switch logic for
the dampers was modified to eliminate the OPEN position of the switches.
The positions were changed from AUTO-0 PEN to CLOSE-AUTO.
If the
switches are moved from the normal position AUTO they will be placed in
the safe position of CLOSE. The inspector reviewed the DCR package,
observed installation of the modification, and post maintenance testing.
The inspectors also attended several of the post Unit I refueling outage
training classes which discussed the modifications implemented on both
units during the Unit 1 outage. The inspector noted that the classroom
discussions and the handout information indicated that for DCR 92-051,
,
the internals of PSW valve IP41-F363 had been removed. This
modification was performed as a result of IPE information.
The
inspectors had noted that the entire valve was removed and replaced with
a spool piece. The inspector discussed this with the Unit 1 operations
manager to ensure that correct information was being provided to the
plant operations personnel.
All modification activities observed were carried out in accordance with
procedures, instructions and drawings and with adequate engineering
support.
No violations or deviations were identified
.
O
,
21
6.
Reactor Water level Training (GL 92-04, TI 2515/119)
The inspector followed up on the licensee's response to GL 92-04,
" Resolution of the Issues Related to Reactor Vessel Water Level
Instrumentation in BWRs Pursuant to 10 CFR 50.44 (f)." The inspector
used Appendix A of TI 2515/119 as a checklist of licensee activities.
Additionally, the inspection consisted of review of classroom attendance
records, shift briefing records and discussions with licensed operators.
The discussions with licensed operators indicated the operators had
attended training, were aware of the water level issues and were
familiar with the Emergency Operating Procedures that dealt with the
uncertainties associated with reactor water level indications. The
inspector conducted discussions with operator licensing training
instructor and reviewed lesson plan LR-IH-50002-01:
Noncondensible Gas
Effects on Reactor Water Level Indication. The lesson plan contained
interim policies to follow following rapid reactor depressurizations
(less that 450 psig at greater than 100 degrees F per hour) to verify
that the cold-reference leg instruments had not been affected.
Basically, this consisted of comparing the different level recorders and
verifying that the difference in indication was less that 10 inches.
If
the difference in the level recorders indication was less that 10
inches, it could be assumed that non-condensible gases had not evolved
in the reference legs
The inspector determined that training had not
developed a specific simulator scenario to exercise these particular
anomalies. Since the issue was still under investigation by the BWROG,
the licensee had not developed simulator software to model .the
phenomenon. However, the inspector verified that there were 3 or 4
other simulator scenarios that would require the operators to evaluate
the operability of level indications. The scenarios consisted of events
that caused rapid reactor depressurization, high DW temperatures, and
complete or partial loss of reactor level indications.
Based upon these-
events, the operators would be required to perform reactor pressure
vessel flooding, and/or containment flooding.
The inspectors have also walked down the physical arrangement of most of
the reactor vessel level indication piping in both DWs during previous
outages. Discussions were held with the engineer responsible for the
licensee's overall actions in response to the GL. Several modifications
have been completed and additional work is under consideration.
Information indicates that Hatch has not observed the level indication
" notching" effect, although some level oscillations have been noted
under low pressure conditions.
The inspectors concluded, based upon the areas inspected, the actions
taken by the licensee were adequate and met the criteria of GL 92-04 and
No violations or deviations were identified.
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6.
Inspection of Open items (92700) (90712) (92701)
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The following item was reviewed using licensee reports, inspections,
record reviews, and discussions with licensee personnel, as appropriate:
a.
(Closed)
IFI 50-321/92-29-02:
Inspection of Unit 1 Shroud Access-
Hole Covers.
During the recent outage, DCR 93-002 was
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implemented. This design change replaced the welded Inconel Alloy
600 circular access hole covers, located in the core shroud area,
with bolted covers. This item is closed for Unit 1 and remains
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open for Unit 2.
7.
Exit Interview
The inspection scope and findings were summarized on May 12, 1993, with
those persons indicated in paragraph 1 above. The inspectors described
the areas inspected and discussed in detail the inspection findings.
Dissenting comments were received in two areas. The licensee took israe
with the statement "that if the loss of SDC flow would have occurred
under certain conditiont which existed earlier in the outage, a more
significant safety concern could have resulted." The licensee also
questioned the appropriateness of citing the dosimetry calibration issue
under 10 CFR 50.9 instead of 10 CFR 50.5.
The licensee did not identify
as proprietary any of the material provided to or reviewed by the
inspectors during this inspection.
Item Number
Status
Description and Reference
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321/93-06-01
Open
VIO - Failure to Comply With
Shutdown Cooling TS Requirements,
paragraph 2.b
321/93-06-02
Open
VIO - Failure to Follow EDG Alarm
Response Procedures, paragraph 3.b
NCV 321,366/93-06-03
Open and
NCV - False Documentation of
Closed
Portions of a Pocket Dosimeter
Calibration Test, paragraph 2.c
8.
Acronyms and Abbreviations
ADS - Automatic depressurization System
A/E - Architect Engineer
AGM-P0- Assistant General Manager - Plant Operations
AGM-PS- Assistant General Manager - Plant Support
AHC - Access Hole Covers
Air Handling Unit
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APRM - Average Power Range Monitor
ATWS - Anticipated Transient Without Scram
BWR - Boiling Water Reactor
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BWROG- Boiling Water Reactors Owners Group
CB0 - Control Board Operator
Code of Federal Regulations
CFR
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CILRT - Containment Integrated Leakrate Test
CR
- Control Room
CRD - Control Rod Drive
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Condensate Storage Tank
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- Deficiency Card
DCR - Design Change Request
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- Drywell
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ECCS - Emergency Core Cooling System
EDG - Emergency Diesel Generator
EDT - Eastern Daylight Time
Electro Hydraulic Control System
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- Equipment . Qualification
ERT - Event Review Team'.
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ESF - Engineered Safety Feature
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EST - Eastern Standard Time
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F
- Fahrenheit
Fire Hazards Analysis
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FPC - Fuel Pool Cooling
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FSAR - Final Safety Analysis Report
- General Electric Company
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Generic Letter
GL
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GPM - Gallons per Minute
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- Health Physics
HPCI - High Pressure Coolant Injection System-
HVAC - Heating, Ventilation and Air Conditioning
Heat Exchanger
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I&C -
Instrumentation and Controls
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IFI - Inspector Followup Item
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IN
- Information Notice
1
IPE - Individual Plant Examination
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IRM -
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IST - Inservice. Testing
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Kilowatt
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KW
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LC0 - Limiting Condition for Operation
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LER - Licensee Event Report
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LOCA - Loss of Coolant Accident
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LOSP - Loss of Site Power
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LPRM'- Local Power Range Monitor
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LSFT - Logic System Functional Test
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-MFP - Main Feed Pump
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MSIV - Main Steam Isolation Valve
MWE - Megawatts Electric.
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MWO - Maintenance Work Order
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Non-cited Violation
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NRC ' - Nuclear Regulatory Commission
NRHX - Non Regenetive Heat Exchanger
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NRR - Office of Nuclear Reactor Regulation
NSAC - Nuclear Safety and Compliance
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PCIS - Primary Containment Isolation System
PE0
Plant Equipment Operator
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PIC - Pocket Ion Chamber
P&ID - Piping and Instrumentation Drawing
- Preventive Maintenance
psig - Pounds Per Square Inch Gauge
PSW - Plant Service Water System
- Reactor Building
RBM - Rod Block Monitor
RCIC - Reactor Core Isolation Cooling System
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RFP - Reactor Feed Pump
RFPT - Reactor Feed Pump Turbine
RHRSW- Residual Heat Removal Service Water System
RPS - Reactor Protection System
RTD - Resistance Temperature Detector
RTP - Rated Thermal Power
RWCU - Reactor Water Cleanup System
RWM - Rod Worth Minimilar
RWP - Radiation Work Permit
RX
- Reactor
SAER - Safety Audit and Engineering Review
SBGT - Standby Gas Treatment System
SBLC -
Standby Liquid Control System
SCS - Southern Company Services
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SER - Safety Evaluation Report
SFP - Spent Fuel Pool
SNC - Southern Nuclear Company
SOR - Significant Occurrence Report
SOS - Superintendent of Shift (Operations)
SPDS - Safety Parameter Display System
SR0 - Senior Reactor Operator
-
- Shift Supervisor
SUT - Startup Transformer
TI
- Temporary Instruction
TLD - Thermal Luminescent Dosimetry
TS
- Technical Specifications
- Unresolved Item
WPS - Work Process Sheets
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