ML20134D377
| ML20134D377 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 10/11/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20134D372 | List: |
| References | |
| 50-321-96-11, 50-366-96-11, NUDOCS 9610220090 | |
| Download: ML20134D377 (38) | |
See also: IR 05000321/1996011
Text
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U.S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-321, 50-366
License Nos:
Report No:
50-321/96-11, 50-366/96-11
Licensee:
Georgia Power Company (GPC)
Facility:
E.
I.
Hatch Units 1 & 2
Location:
P.
O.
Box 439
Baxley, Georgia
31513
Dates:
August 4 - September 14, 1996
Inspectors:
B.
Holbrook, Senior Resident Inspector
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J.
Moorman, Senior Resident Inspector
(Acting)
E.
Christnot, Resident Inspector
G.
Salyers, Emergency Preparedness
Specialist (Sections P2, P3, PS, P6,
P7, P8)
J.
Canady, Resident Inspector
Approved by:
P.
Skinner, Chief, Projects Branch 2
Division of Reactor Projects
Enclosure 2
9610220090 961011
gDR
ADOCK 05000321
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EXECUTIVE SUMMARY
Plant Hatch, Units 1 and 2
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NRC Inspection Report 50-321/96-11, 50-366/96-11
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This integrated inspection included aspects of licensee
operations, engineering, maintenance, and plant support.
The
report covers a 6-week period of resident inspecticn; in addition,
it includes the results of an announced inspection ay a regional
emergency preparedness specialist.
Operations
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The inspector concluded that operator response to the
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Reactor recirculation pump tr p on August 20, was excellent.
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Actions taken were prompt, deliberate, and in accordance
with plant procedures.
The immediate observations by the
Shift Technical Advisor to assist the operators in use of
the power / flow operating map was excellent (Section 01.2).
The inspector reviewed a special report dated July 30, 1996,
involving an inoperable reactor vessel water level flood-up
range instrument.
The report did not clearly indicate how
to compensate for the lack of monitoring capability above
+60 inches should this be required during post accident
conditions.
However, the lack of clarity was not considered
significant.
The licensee is considering a TS amendment to
address this issue (Section 02.1).
The license conditions required for the Technical
Specification Improvement Program (TSIP) implementation for
Unit 1 and Unit 2 are complete with the exception of the
ten-year surveillance requirements for the emergency diesel
generators (Section 03.1).
A Safety Review Board (SRB) meeting was attended on
September 12.
The inspectors concluded that the meeting met
the applicable requirements and that the SRB is providing
adequate review and auditing functions (Section 07.1).
The licensee activities involving the river conditions
demonstrated a , pro-active attitude on the part of plant
management and is considered a strength (Section 01.1).
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Operation and Maintenance Department personnel routinely use
a risk matrix to perform an assessment of the total plant
equipment out of service to determine the overall effect on
performance of safety functions per' 10 CFR 50.65 (a) (3) ,
" Requirements for monitoring the effectiveness of
maintenance at nuclear power plants" (Section 01.1).
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Maintenance
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Maintenance and surveillance activities were performed
thoroughly and professionally.
The inspectors observed that
personnel were knowledgeable in the assigned task;
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procedures were in use; activities were well documented; and
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administrative controls were implemented.
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GPC
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Encineerino
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VIO 50-321/96-11-02:
Failure to Perform an ASME Code-
Required VT-3 Inspection on High Pressure Coolant Injection
(HPCI) Valve 1E41-F006, was identified.
The failure to
perform an American Society of Mechanical Engineers (ASME)
Code-required VT-3 inspection on a safety related component
was considered significant (Section E2.2).
The inspectors conducted followup inspections on licensee
activities with respect to the Unit 2 Station Service
battery.
No immediate operability concerns were identified.
Onsite engineering was taking appropriate pre-installation
measures to ensure replacement battery cells remained in the
proper condition (Section E7.1).
Plant Support
A Non-Cited Violation (NCV), 50-366/96-11-03, for failure to
follow valve line-up procedures when performing a torus
water sample was identified (Section R1.2).
Poor sampling technique was the most likely cause for the
stored fuel oil analysis results that were out of
specification on August 8.
Attention to detail during the
sample analysis collection process may prevent similar
problems.
This was identified as an area for improvement in
the chemistry sampling process (Section R4.1) .
The Emergency Preparedness (EP) facilities and equipment
were at a satisfactory level for operational readiness;
Emergency Operating Facility (EOF) ventilation was tested
and maintained adequately; and the tone alert radio system
was reliable, tested and maintained (Section P2).
The licensee's review process for EP procedures and
documents was satisfactory and met the requirements of
The declaration of the Notification Of
Unusual Event (NOUE) on March 20, 1996, was properly
classified and the applicable Emergency Implementing
Procedures (EIP) were implemented (Section P3).
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The licensee maintained a satisfactory EP training program
and satisfactorily met their drill requirements
(Section PS).
No significant personnel changes were made since the last
inspection (April, 1995) that would effect the performance
or maintenance of the EP program (Section P6).
An audit was not conducted in accordance with the Audit
Planning Matrix, however, the aggregate of the audit
elements satisfied 10 CFR 50.54 (t) (Section P7).
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Enclosure 2
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Quality Assurance (QA) auditors were qualified and EP issues
were satisfactorily trackei. and resolved in a timely manner
(Section P7).
Tne inspectors' review of the status of plant security
f acilities and equipmer.t did not identify any deficiencies
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(Section S2).
Enclosure 2
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Report Details
Summary of Plant beatus
Unit 1 began the report period at 100% rated thermal power (RTP).
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On August 20, power was reduced to about 30% RTP due to a trip of
a reactor recirculation pump motor generator (MG) set and a
subsequent runback.
The trip occurred when the air high
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temperature switch was bumped during housekeeping activities and
the runback was due to the quick opening of a reactor feed pump
minimum flow valve (paragraph 01.2).
Power was returned to RTP
and the unit operated at 100% RTP for the remainder of the report
period except for routine testing activities.
Unit 2 operated at 100% RTP throughout the report period except
for routine testing activities.
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Ooerations
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01
Conduct of Operations
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01.1 General Comments
a.
Insoection Scoce (71707)
Daily reviews of plant operation were conducted using
Inspection Procedure 71707, Plant Operations.
The conduct
of operations was generally professional and safety-
conscious.
Specific events and noteworthy observations are
detailn: in the section below.
b.
Observations and Findings
The inspectors discussed the electrical harmonics observed
on the Units 1 and 2 Emergency Diesel Generator (EDG) 4160
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volt (V) switchgear (Reference paragraph E2.1) with licensee
personnel.
The inspectors reviewed the EDG surveillance
procedures.
The operators are instructed by the procedures
to quickly load the EDGs once they are in parallel with the
grid.
The inspectors observed that there was no discussion
in the procedure about the harmonics and the possible effect
on the reverse power trip.
The inspectors also observed
that there was no discussion about the possibility of a
reverse power trip while unloading the EDGs in preparation
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for removal from the grid.
The inspectors were informed
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that the Engineering Department was performing a review of
the effects of the electrical harmonics.
The inspectors monitored the licensee's activities involved
with the river water level, temperature, and the debris
being pulled into the cooling water systems.
The licensee
contracted to have the area in front of the intake structure
Enclosure 2
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dredged.
Divers were also contracted to clean sediment and
debris from the bottom of the intake water bays.
The
inspectors were informed that algae and floating moss were
clogging various chiller systems and cooling water heat
exchangers.
The inspector attended meetings at which these
problems were discussed.
The licensee developed an action
plan to better cope with the algae and the floating moss.
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Parts of the plan called for closer monitoring'of chiller
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systems and cooling water heat exchanger performance.
One portion of the maintenance rule, 10CFR50. 65 (a) (3 ) ,
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states, in part, "an assessment of the total plant equipment
that is out-of-service should be taken into account to
determine the overall effect on performance of safety
functions."
On several occasions the inspectors observed
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licensed' operators using a matrix governed by Procedure
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90AC-OAP-002-OS, Scheduling Maintenance.
The matrix
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provides Technical Specification (TS) and risk-informed
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guidance to be used when removing combinations of equipment
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from service.
The matrix indicated that if a Control Rod
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Drive (CRD) pump was out-of-service it would be a medium
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risk to take the HPCI out-of-service and it would be a low
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risk to take out a loop of core spray.
The matrix also
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high risk to remove a loop of Low Pressure Coolant Injection
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indicated that if the HPCI was out-of-service, it would be a
(LPCI) from service and a medium risk to remove a Residual
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Heat Removal Service Water (RHRSW) pump.
The instructions
on the matrix indicated the.following:
For a high risk removal from service (Required Action
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Statement (RAS) 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or less, or Risk Achievement
!" orth (RAW) equal to or greater than 10), a risk
evaluation was required, and approval by the operations
manager was required.
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For a medium risk (Limiting Condition for Operation (LCO)
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less then 7 days, or RAW more than 5 but less then 10)
the approval by the operations manager was required.
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For a low risk (LCO equal to or more then 7 days, or RAW
1ess then or equal to 5) the approval by the
Superintendent On Shift (SOS) was required.
Two laminated copies of the matrix were available in the
Control Room.
c.
Conclusions on General Comments
The inspectors considered the EDG harmonic item to be a
potential for possible erroneous reverse power trips, which
could lead to operator confusion.
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The licensee activities involving the river conditions
demonstrated a pro-active attitude on the part of plant
management and is considered a strength.
Use of the matrix to evaluate risk associated with removing
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various combinations of equipment from service is consistent
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with the maintenance rule.
This and other aspects of the
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licensee's implementation of the maintenance rule will be
inspected further in the near future.
01.2 Transient Due to Recirculation Pumo Trio and Runback (Unit
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a.
InsDection Scoc? (71707)
At 9:12 a.m. on August 20, with Unit 1 operating at 100%
RTP, the 1A Reactor Recirculation (RR) Pump tripped.
An
inspector responded to the control room to assess operator
actions and unit response.
The inspector observed operator
monitoring of annunciators and parameter trends.
Communications, supervisory control, and the use of
procedures were also observed.
Among the procedures used by
the operators were:
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Reactor Power Instabilities, Rev. 3
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Jet Pump and Recirculation Flow
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Mismatch Operability, Rev.
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Edition 1
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Reactor Recirculation System, Rev.
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Attachment 6,
Power Versus Flow Map
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Control Rod Movement, Rev. 14
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Power Changes, Rev. 18
b.
Observations and Findinos
The operators immediately implemented and appropriately used
applicable procedures in response to the transient.
At
about 9:16 a.m. the Shift Technical Advisor (STA) identified
and reported to the crew that the unit was within the region
of potential instability.
Reactor power had decreased to
69% RTP with 49.8% core flow.
At STA and Shift Supervisor
(SS) direction, flow was increased slightly on the 1B RR
pump.
At 9:21 a.m.
the STA informed the shift that the
region of potential instability had been exited.
In preparation to start the tripped pump, control rods were
inserted to get below the 55% load line, as required by
procedure.
As operators prepared to place the 1A Reactor
Feed Pump Turbine (RFPT) in standby, a runback on the 1B RR
pump occurred due to low reactor water level.
The operators
noted that the runback occurred in conjunction with the 1A
Reactor Feedwater Pump (RFP) minimum flow valve opening.
The region of potential instability was again entered.
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Enclosure 2
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Control rods were inserted and the region was exited in
about eight minutes.
The licensee determined that the 1A RR pump trip was caused
by a painter performing work in the recirculation pump Motor
Generator (MG) set room.
A high MG set air temperature
switch was bumped and caused a trip of the MG set.
Maintenance personnel tested the switch to verify proper
operation and no deficiencies were observed.
Systems were placed in service and unit RTP was reached at
about 7:45 p.m.
c.
Conclusions
The inspector concluded that operator response to the
transient was excellent.
Actions taken were prompt,
deliberate, and in accordance with plant procedures.
The
immediate observations by the on-shift STA to recognize the
reactor was in the area of potential instability was
excellent.
The RFP minimum flow valve problem continues to
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contribute to unplanned plant transients.
The inspectors
will review additional information on the minimum flow
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valves.
02
Operational Status of Facilities and Equipment
02.1 Inocerable Reactor Flood-Un Rance Reactor Water Level
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Instrument Unit i
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a.
Insoection ScoDe (92901)
The inspector reviewed a special report dated July 30, 1996,
involving the reactor vessel water level flood-up range
instrument, 1B21-R605.
b.
Observations and Findinas
On July 21, 30 days had elapsed since flood-up range reactor
vessel water level instrument 1B21-R605 was declared
The inspectors reviewed the licensee's special
report dated July 30, 1996, submitted to meet Technical
Specification (TS) requirements.
The TS required that a
report be submitted within the following 14 days.
The
inspectors found from this review that the report was
submitted within the time frame of the specifications.
The
TS further states that the report shall outline the
preplanned, alternate method of monitoring, the cause of the
inoperability, and the plans and schedule for restoring the
instrumentation channels of the function to operable status.
The inspectors observed that the report stated the cause of
the inoperability appeared to be the result of a reduction
in the instrument reference leg water level.
This was due
Enclosure 2
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to a packing leak on the equalizing valve for the
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transmitter of instrument 1B21-R605.
The leak was repaired
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and the condensation in the reference leg condensing pot was
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expected to refill the leg.
This did not occur and proper
instrument function was not restored.
The licensee did not determine why the condensing pot failed
to refill the reference leg.
The report further stated that
to refill the reference leg by injecting demineralized water
would impose a risk to the instrumentation that could cause
a plant transient.
The report contained plans and a schedule for restoring the
instrument channel to operable status.
The inspectors found that the report did not directly
address the preplanned alternate method of monitoring.
The
report stated that the flood-up instrument was indicating 29
to 30 inches higher than actual level as measured by other
instruments.
The method discussed in the report involved
other instrumentation that only indicate up to +60 inches.
This indicated to the inspector that for post accident
monitoring purposes, water level can only be monitored up
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+60 inches.
The report did not clearly state that between
+60 inches and +400 inches no alternate method of monitoring
was available.
The inspectors discussed the report with licensee personnel.
The inspector observed that the licensee issued a temporary
change to the Unit 1 scram procedure, 34AB-C71-001-1S,
Revision 6,
that reduced the required Main Steam Isolation
Valve (MSIV) closure on high level from +100 inches to +60
inches.
This would help protect Emergency Core Cooling
Systems (ECCS) steam-driven turbines.
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The licensee informed the inspectors that, even though the
instrument was listed as a TS post accident monitoring
instrument, the non-redundant instrument was not intended to
be used during post accident conditions.
The instrument was
to be used only during refueling conditions when water level
is raised to flood the refueling cavity.
The inspectors
reviewed licensee-supplied documentation that supported the
intended use of the instrument.
The licensee was evaluating
this problem for a TS amendment.
c.
Conclusions
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The inspectors concluded that the report did not clearly
indicate the lack of monitoring capability during post
accident conditions above +60 inches.
However, the lack of
clarity was not considered to be significant.
The
inspectors viewed a proposed TS amendment as appropriate.
The revision to the scram procedure was also appropriate.
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Enclosure 2
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03
Operations Procedures and Documentation
03.1 License Conditions for TSIP Imolementation Units 1 and 2
a.
Inspection ScoDe (92901).
License condition 2.C. (2) for Units 1 and 2 states, in part:
The Surveillance Requirements (SRs) listed are not required
to be performed immediately upon implementation of
Amendments No. 195 for Unit 1 and No. 135 for Unit 2.
The
SRs listed shall be successfully demonstrated prior to the
time and condition specified for each.
b.
Observations and Findinos
The inspector observed that license condition 2.C.(2)a)
stated that the listed SRs shall be successfully
demonstrated prior to entering MODE 2 on the first plant
startup following the sixteenth refueling outage for Unit 1
and the twelfth refueling outage for Unit 2.
The license
condition listed the SRs for both units, Unit 1 only and
Unit 2 only as follows:
Listed for both units:
- 3.3.2.2.2
Perform channel calibration for the Feedwater
and Main Turbine Trip High Level
Instrumentation.
- 3.3.2.2.3
Perform logic system functional test for the
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Feedwater and Main Trip High Level
Instrumentation.
- 3.3.3.2.2 Verify each required control circuit and
transfer switch is capable of performing the
intended function for the Remote Shutdown
System.
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- 3.3.8.1.4
Perform logic system functional test for Loss of
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Power Instrumentation.
- 3.7.7.2
Perform a system functional test for the Main
Turbine Bypass System.
- 3.7.7.3
Verify the Main Turbine Bypass System response
time is within limits.
Listed for Unit 1 only:
- 3.3.1.1.15
Perform logic system functional test for
Reactor Protective System Instrumentation.
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- 3.3.1.1.16
Verify the RPS response time is within
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(Function 9)
limits for the turbine control valve fast
closure, trip oil pressure - low.
- 3.3.6.1.6
Perform logic system functional test for
(Function 1.f)
Turbine Building Area Temperature - High.
Listed for Unit 2 only:
- 3.6.2.4.2
Verify each spray nozzle is unobstructed for the
Residual Heat Removal (RHR) Suppression Pool
Spray System.
License condition 2.C.(2)b) stated that the listed SRs shall
be successfully demonstrated at their next regularly
scheduled performance.
The license condition listed the SRs
for both units and Unit 2 only as follows:
Listed for both units:
- 3.8.1.8
Verify each EDG operating at or less than a
specific power factor and does not trip and
adequate voltage is maintained following a load
reject of a specified kilowatt (kw) load.
- 3.8.1.10
Verify on an actual or simulated ECCS' initiation
signal that each EDG auto-starts from the
standby condition and in a specified time after
auto-start achieves adequate voltage and, after
steady state conditions are reached, maintains
an acceptable voltage; in the same time after
auto-start achieves adequate frequency and after
steady state conditions are reached, maintains
an acceptable frequency; and operates for at
least 5 minutes.
- 3.8.1.12
Verify each EDG operating at a specified power
factor for at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; for at least 2
hours loaded at a high kw; for the remaining
hours of the test loaded at lower kw.
- 3.8.1.13
Verify that each EDG starts and achieves, in
equal to or less than 12 seconds, voltage equal
to or greater to 3740 V and frequency equal to
or greater than 58.8 hertz (Hz); and after
steady state conditions are reached, maintains
voltage between 3740 V and 4243 V and frequency
between 58.8 Hz and 61.2 Hz.
- 3.8.1.18
Verify, when started simultaneously from standby
condition, that all of the Unit 1 and all of the
Unit 2 EDGs achieve, in less than or equal to 12
seconds, voltage greater than or equal to 3740 V
and frequency greater than or equal to 58.8 Hz.
Enclosure 2
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Listed for Unit 2 only:
- 3.8.1.9
Verify on an actual or simulated loss of offsite
(for EDG 2C) power signal: De-energization of emergency
busses; load shedding from emergency buses; the
EDG auto-starts from standby condition and;
energizes permanently connected loads in a
specified time, energizes auto-connected
emergency loads through automatic load sequence
timing devices, achieves adequate steady state
voltage, achieves adequate steady state
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frequency, and supplies permanently connected
and auto-connected emergency loads for at least
5 minutes.
3.8.1.17
verify that on an actual or simulated loss of
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(for EDG 2C) offsite power signal in conjunction with an
actual or simulated ECCS initiation signal that
the EDG meets the same requirements as that of
the above listed SR 3.8.1.9.
License condition 2.C.(2) c) stated that the listed SRs will
be met at implementation for the secondary containment
configuration in effect at that time.
The SRs shall be
successfully demonstrated for the other secondary
containment configur4tions prior to the plant entering.the
LCO applicability for that configuration.
The license
condition listed the SRs for both units as follows:
- 3.6.4.1.3
Verify required Standby Gas Treatment (SGT)
subsystem (s) will draw down the secondary
containment to greater than or equal to 0.20
inches of vacuum water gauge in less than or
equal to 120 seconds.
- 3.6.4.1.4
Verify required SGT subsystem (s) can maintain a
greater than or equal to 0.20 inches of vacuum
water gauge in the containment for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> at a
flow rate greater than or equal to 4000 cubic
feet per minute (cfm) for each subsystem.
The inspectors observed that the license conditions for both
units covered a total of 32 SRs.
To determine the
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compliance to the license conditions 2.C.(2) a) and b) the
inspectors were provided information in the form of two
matrices, one for each unit.
The matrices listed the TS
surveillance requirement, commitment number, responsible
group, procedure (s) performed to meet the requirement (due
by plant condition, such as prior to Mode 2), date completed
and any comments.
For license condition 2.C.(2) c), which
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involved the secondary containment, the inspectors were
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provided with dates on which the applicable surveillances
were performed.
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Enclo.3ure 2
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The inspectors reviewed the matrices and observed that the
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surveillance requirements for license conditions 2.C.(2) a)
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and b) corresponded to the applicable plant procedures.
The
requirements for Unit 1 were performed during spring 1996
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refueling outage and for Unit 2 during the fall 1995
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refueling outage.
The inspectors observed that the
completed procedures were_the applicable procedures for the
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license conditions.
However, SR 3.d.1.18, a simultaneous
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start of all the respective EDGs for both units was not
performed.
This SR has a frequency of 10 years.
The due
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date for Unit 1 is March 1,
2003 and for Unit 2 is
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February 1,
1997.
The inspectors observed that the required
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surveillance for the license condition 2.C. (2) c) were also
performed as required for both units.
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The inspectors documented SR activities associated with the
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TSIP and sections of the license conditions in irs 50-321,
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366/95-08, 95-22, and 95-23.
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c.
Conclusions
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The inspectors concluded that license conditions 2.C.(2).a)
and c) are fully closed for both units.
License condition
2.C. (2) b) will be fully closed when SR 3.8.1.18 is
performed for the respective units.
07
Quality Assurance in Operations
07.1 Licensee Self-Assessment Activities (40500)
On September 12, the Hatch SRB convened meeting H96-03 at
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Plant Hatch.
The meeting was conducted in accordance with
the requirements of the Hatch Final Safety Analysis Report
The board discussed the status of
previously-opened items and determined which items should be
closed.
Much of the discussion centered on the past
problems experienced by the Operations and Engineering
Departments and their solutions.
New issues were identified
and assigned to the copropriate manager for resolution.
There was some discussion involving the quality of
contractor work, particrictly that of the plant's Nuclear
Steam Supply System (NSSS) vendor.
Various problems were
discussed, along with solutions and ways of avoiding future
problems.
The inspectors concluded that licensee efforts in
this area for self-assessment were effective.
08
Miscellaneous Operations Issues (92901)
08.1
(Closed) Unresolved Item (URI) 50-321.366/96-07-01:
Determine Safety Significance and Testing Requirements for
Unit 1 and Unit 2 Containment Isolation Status Panel.
The inspector reviewed Abnormal Operating Procedure,
34AB-C71-001-1S and 2S, Scram Procedure, Revision 6,
for
Enclosure 2
_ - .
_
.
_
.
_ . _ _
_ __
- _~__ _ _. _ _ .
- _ _ . _ _ _ _ _ _ . _ . .
1
a
-
'
GPC
13
i
both units.
The procedures made a general reference that
isolation status could be found on Panel 1/2-H11-P601
i
vertical display.
The procedures also listed other
+
locations, such as the Safety Parameter Display System
(SPDS) where system isolation indications could be located.
.
.
The inspectors reviewed both the Unit 1 and 2 UFSARs to
i
determine the isolation panels description and use.
Unit 1
i
FSAR Section 5.2.3.5.2 states in part,
"A mimic display
J
board for only isolation valves provides indication of
l
isolation valve position.
When isolation has occurred, all
energized lights of the display are green".
,
i
I
]
The UFSAR for Unit 2,
Section 7.3.2.2,
System Description -
1
i
Primary Containment and Reactor Pressure Vessel Isolation
}
Control System;
Subsection 7.3.2.2.7,
Testability, states,
in part, " Isolation valves can be tested to ensure that they
'
l
are capable of closing by operating manual switches in the
j
Main Control Room (MCR) and observing the position lights
i-
and any associated process effects".
The subsection directs
'
the reader to "See also figure 7.3-2 (Nuclear Boiler System
- Functional Control Diagrams)."
The inspector reviewed the
figure and observed that it contained 12 sheets of logic
diagrams with control switch and indicating light MCR panel
locations.
The diagrams for the isolation valves clearly
showed indication lights for both the opened and closed
positions on the graphic display located on MCR panel
i
From reviews, observations, and discussions with licensee
personnel, the inspectors found that the isolation status
panels were used by the operators to verify isolation
status; are being maintained current with plant design
changes; and are referenced in plant procedures and the
UFSARs for both units.
The inspectors did not locate any procedure that required
testing or verification that the isolation panel indications
correctly reflected system status or isolation condition.
The inspectors frequently observed operators monitoring the
isolation panel during normal panel observations.
The
inspectors also observed that Design Changes (DCs) were
initiated when required to properly maintain the panels.
,
'
The inspectors were not aware of any discrepancy between the
isolation panel indications and plant systems.
The inspectors observed that Operations management issued an
operating order instructing control room operators to
observe and record light indications that could be monitored
from the isolation status panel for all valves that were
cycled.
Also, plant procedures were to be revised to
include verification of indication response for valves
Enclosure 2
-
.
-
.
.
.
-- -
_
- . _ .. _ _ _ _ _.- _.__ _ - _ _ _ . _ . _ _ _ _ . _
. _ . . _ . _ _ _
. -
.__..
_ _ -
1
-
' GPC
14
located on the isolation status panel.
Most of the checks
,
will be conducted during unit cold shutdown conditions.
<
The inspectors determined that although the failure to test
or verify the isolation valve indications on the isolation
status panels was an oversight, no regulatory violation had
occurred.
Based upon this review URI 50-321, 366/96-07-01
is closed.
b.
Conclusions
Systems that are used by the operators to verify the status
of safety-related systems and are discussed in the UFSAR
should be tested or verified periodically.
'
08.2
(Closed) Licensee Event ReDort (LER) 50-321/96-011:
Inadequate Procedure Results in Missed Technical
Specifications Surveillances.
This problem was discussed in
,
j
Inspection Report (IR) 50-321, 366/96-10.
No new issues
were revealed by the LER.
i
08.3
(Closed) Violation (VIO) 50-321/95-23-01:
Operators'
Failure to Follow Procedure While Transferring Diesel Fuel
011.
This violation was identified when operators were
receiving new fuel oil from a tanker truck.
Due to a valve
lineup, not in accordance with procedure, 300 gallons of
fuel overflowed a day tank.
The inspector reviewed the
>
)
licensee's response, dated January 2,
1996.
The response
indicated that administrative personnel action was taken and
that procedure changes were being considered.
The
- inspectors reviewed the EDG procedure 34SO-R43-001-1S,
Revision 18, and observed procedure changes.
These changes
included a simplified drawing of the fuel oil system piping
and valves.
This drawing was to aid personnel in
determining the correct valve line up for the activity to be
performed.
08.4
(Closed) VIO 50-366/95-26-01:
Inability to Safely Shutdown
,
Unit 2 from the Remote Shutdown' Panel in the Event of a Fire
'
in the Main Control Room.
This violation was identified
when operators attempced to perform a surveillance on the
Unit 2 Remote Shutdcwn Panel (RSDP).
The surveillance was
being performed for the first time because of the TSIP.
'.
Prior to the implementation of the TSIP, testing of the RSDP
was not required.
The inspectors reviewed the licensee's
response, dated February 12, 1996.
The response indicated
that failure to perform periodic testing, as well as
inadequate design and design change functional testing,
contributed to the violation.
This item was initially
documented in IR 321,366/95-23.
Subsequent licensee and
inspector activities were documented in irs 321,366/95-26
and 95-27.
These activities included observed licensee
corrective actions involving system testing, maintenance and
Enclosure 2
,
R
-
- - , -
,
n
,
- - - . ,
--,--e
. , - -
-,e-.
.+-
..,-.4
- - -
1
.
.
GPC
15
modification work.
The inspectors concluded that the
licensee's corrective actions had been appropriate.
08.5 (Closed) VIO 50-321.366/95-18-02:
Failure to Follow
Procedure, Second Example.
This example was identified when
1
operators failed to follow a procedure while performing.
hydrogen water chemistry flow changes.
This resulted in
'
unnecessary exposure to personnel performing maintenance in
the condenser bay.
The inspectors reviewed the licensee's
response dated October 26, 1995.
The response indicated
that a less-than-adequate operating procedure and less-than-
adequate training contributed'to the violation.
The
response stated that personnel were counseled regarding
their actions, training material would be revised, and
procedure changes would be made.
The inspectors reviewed
the revised material and procedure changes and concluded
that the licensee's corrective actions had been appropriate.
II. Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a.
Inspection Scoce (62703) (62707)
The inspectors observed all or portions of the following
work activities:
-
MWO 2-96-2492: . Replace seal on 2B Plant Service Water
(PSW) Pump
-
MWO 2-96-2586:
Insulation inspection of Reactor
Protection System (RPS) MG Set 2A
-
MWO 2-96-2131:
RPS MG Set Minor Design Change (MDC)
95-5037 Implementation
b.
Observations and Findinas
The inspectors found that the work was performed with the
work packages present and being actively used.
The
inspectors observed that during the implementation of the
MDC the system engineer was present at the job site.
Appropriate post-modification and maintenance tests were
performed.
These tests consisted of operating the equipment
following the completion of work activities.
c.
Conclusions on Conduct of Maintenance
Maintenance activities were generally completed in a
thorough and professional manner.
No deficiencies were
identified.
Enclosure 2
, . -
- - . - - ~ - - .
_.
- - . -..- - .
.
. . ~ -
- . . -
--.
,--
l
!
!
l
GPC
16
l
l
M3
Maintenance Procedures and Documentation
l
l
M3.1 Surveillance Observations
l
l
a.
Inspection Scoce (61726)
The inspectors observed all or portions of the following
Unit 1 and Unit 2 surveillance activities:
- 34SV-R43-004-1S:
Diesel Generator 1A semi-annual test
- 34SV-E41-002-2S:
HPCI Pump operability
b.
Observations and Findings
The HPCI surveillance observed was the three-month
operability test to meet TS and AMSE Code In-Service Testing
requirements.
Data was collected on system valve stroke
i
times and pump operating characteristics.
A pre-evolution
briefing was conducted by the licensed operator performing
!
,
l
the surveillance.
All personnel involved were in
attendance.
The diesel surveillance was performed without problem and
all parameters were within specification.
c.
Conclusions
l
For both surveillances, all data was within the required
,
!
range and the equipment was determined to pass the
surveillance.
The performance of the operators and crews
conducting the surveillances was generally professional and
competent.
No deficiencies were identified.
M8
Miscellaneous Maintenance Issues (92700) (92902)
M8.1 (Closed) LER 50-366/96-03:
High Pressure Coolant Injection
i
System Temporarily Inoperable Following Engineering Safety
I
Feature Actuation.
The cause of this problem was a physical
" slip" that occurred when a technician was manipulating a
piece of test equipment during surveillance testing
activities.
The system responded as expected.
As part of
l
'
the corrective actions, management discussed the problem
with the technician and suressed the importance of caution
when performing test act.vities.
The system was realigned
to the operable (standby' condition.
M8.2 (Closed) VIO 50-321,366/95-18-02:
Failure to Follow
Procedure, First Example.
This example was identified when
divers entered the intake structure pump pit area to perform
inspection activities without the use of a procedure.
A
service water pump was declared inoperable when a section of
the diver's life, air and communication line entered the
suction of the pump. The inspector reviewed the licensee's
response dated October 26, 1995.
The response indicated
l
Enclosure 2
l
..
._
__ _.
_ _ _ _ . . ._.
_ __
.
_ _ . _ _ _ _ _
.
.
'
.
4
GPC
17
that miscommunications among personnel regarding the use and
i
applicability of a procedure contributed to the violation.
The response stated that administrative personnel action was
taken, procedure changes would be made and signs would be
posted.
The inspectors reviewed the procedure changes and
observed the posted signs.
The inspectors concluded that
the licensee's corrective actions had been appropriate.
III. Encineerina
E2
Engineering Support of Facilities and Equipment
E2.1 Harmonics on Safety Related EDG 4160 V Switchaear
,
a.
Insoection Scope (92903)
,
i
The inspectors performed followup activities involved with
,
electrical harmonics discussed in IR 50-321, 366/96-06.
4
i
b.
Observations and Findinas
}
The inspectors observed electrical data supplied by licensee
personnel.
The data clearly indicated the presence of
]
harmonics on both Unit 1 and Unit 2 EDG 4160V switchgear.
The harmonics appeared to be identical on all safety-related
,
j
4160V switchgear on both units.
The inspectors discussed the harmonics with licensee
personnel.
The inspectors were informed that the harmonics
could possibly cause reverse power trips of the EDGs when
=
they were in parallel with the grid and operating at low
power.
The inspectors were also informed that the manner in
which the switchgear was instrumented, on what phases the
e
i
voltage and current were sensed, could be changed to help
prevent unnecessary reverse power trips.
Under current
j
conditions the CR operators could possibly have erroneous
indication on an EDG and due to the harmonics get a reverse
,
j
power trip.
i
c.
Conclusions
'
The engineering group was actively pursuing a solution to
,
j
the effects of the harmonics on EDG operation and testing.
~
At the end of this report period, the inspectors concluded
i
that the information about the effects of the harmonics had
not been forwarded to the Operations Department.
Recommendations to assist the operators in mitigating the
harmonic effects on EDG operation had also not been
i
forwarded.
EDG reverse power trips during surveillance
1
testing has been a problem at the site.
Some of the reverse
power trips were due to personnel error and inattention to
,
detail while the root cause of others was inconclusive.
The
inspectors were informed that the potential harmonic effects
on EDG operations was being reviewed by the Engineering
.
Enclosure 2
.
.
GPC
18
Department.
The results of the review will be forwarded to
the Operations Department.
This is identified as Inspector
Followup Item (IFI) 321, 366/96-11-01:
Review of
-
Engineering Report on the Effects of Harmonics on EDG
Operation.
E2.2 ASME Code Insoection Not Performed
a.
Inspection Scope (92903)
The inspectors followed up the licensee activities involving
a missed ASME code-required inspection of Unit 1 HPCI
injection valve, 1E41-F006.
b.
Observations and Findinas
The inspectors identified a violation in IR 50-321,
,
366/96-06 involving activities associated with missed VT-3
inspections for three valves.
The VT-3 inspections were
required by procedure but only the HPCI valve required a
VT-3 inspection in accordance with the ASME code.
During the inspectors' initial review of the problem, the
inspectors were informed that a VT-3 inspection was
performed on HPCI valve 1E41-F006, in conjunction with a
cleanliness inspection conducted by contract personnel.
The
inspectors reviewed licensee-supplied documents and agreed
with the licensee's assessment that an adequate VT-3
inspection had been performed.
On August 12, the licensee informed the inspectors that new
information had been received from the contract personnel
who performed the cleanliness inspection.
This led site
personnel to conclude that an adequate VT-3 inspection had
not been completed.
As a result, an ASME code-required post
maintenance VT-3 inspection was not performed.
The inspectors reviewed the licensee's testing of the valve
and the valve's performance since the completion of the
maintenance activities and the missed VT-3 inspection.
No
deficiencies were identified.
Cognizant licensee personnel
stated that they planned to disassemble and complete a VT-3
inspection of the valve during the next scheduled refueling
outage.
The licensee provided the inspectors with information which
indicated that the root cause of the missed VT-3 inspection
was an inadequate resolution to the Quality Control
Inspection Report (QCIR) that identified the original
problem.
The QCIR did not specify that a VT-3 inspection
should be performed after completion of maintenance.
As a result of this problem, the inspectors conducted i
review of maintenance and engineering activities that
Enclosure 2
_ . _ . _ -
_
_ _ . . _ .
.
. . _ _ _ _ .
_ _ . . _ . _ . _ _ _ . _ _ _ . _ _ _ _ _
.
.
GPC
19
occurred during the last two refueling outages to determine
l
if other code-required VT-3 inspections were missed.
The
inspectors review included Safety Audit and Engineering
!
l
Review (SAER) audits, Design Change Requests (DCRs), DCs,
,
i
Maintenance Work Orders (MWOs), SORc, work records, Quality
l
Control (QC) documents, and discussions with licensee
'
,
management personnel.
The inspectors did not identify other
j
examples of missed code-required VT-3 inspections.
The
inspectors also reviewed the licensee evaluation, dated
August 12, 1996, which concluded that there was no valve
operability concern.
The failure to perform an ASME code-required VT-3 inspection
on a safety related component was considered significant.
Lack of thoroughness in determining post-maintenance testing
,
'
requirements centributed to this problem.
The failure to
complete a code-required VT-3 inspection was identified as
VIO 50-321/96-11-02,
Failure to Perform an ASME Code-
Required VT-3 Inspection on HPCI Valve 1E41-F006.
c.
Conclusions
j
The inspectors concluded that an operability concern did not
i
exist for the HPCI injection valve.
The inspectors did not
i
identify other examples of missed code-required VT-3
inspections and concluded this was not a recurring problem.
E7
Quality Assurance in Engineering Activities
E7.1 Unit 2 Station Service Batteries
a.
Insoection ScoDe (92903)
The inspectors continued to monitor the licensee activities
involved with the sediment in the Unit 2 Station Service
(SS) Battery cells. Previous inspector observations are
documented in IR 50-321,366/96-07.
The inspectors were
informed that 52 of 120 cells had sediment in the bottom of
their jars.
-
b.
Observations and Findinos
The inspectors observed the preparation of a new battery
receiving and storage area in an onsite warehouse.
This
area was constructed so that replacement batteries received
on site could be stored in an area that has battery charging
capability as well as temperature and cleanliness controls.
The new cells can be maintained fully charged for
replacement when required.
l
c.
Conclusions
At the end of this report period, the inservice SS battery
capacity exceeded TS requirements.
Increased battery
,
Enclosure 2
__
i
l
e
1
'
l
GPC
20
monitoring and testing continued and no immediate
operability concerns were identified.
Onsite engineering
was taking appropriate pre-installation measures to ensure
adequate replacement battery cell condition.
E8
Miscellaneous Engineering Issues (92700) (92903)
E8.1 (Closed) VIO 50-321/95-16-01:
Contract Personnel Failure to
Follow Procedure While Performing Maintenance on Valve
This violation was identified after contract
'
personnel performed GL 89-10 activities on valve 1E41-F003,
,
HPCI Steam Isolation Valve.
The contractors were under the
control of site engineering personnel.
The inspector
,
reviewed the response from the licensee dated September 28,
"
1995.
The valve was repaired.
The licensee counseled site
'
contractor representatives on the importance of following
procedures.
The inspectors reviewed records which indicated
'
that all contractor valve technicians received procedure
training.
The inspectors concluded that the licensee's
corrective actions were appropriate.
JV. Plant Suonort
R1
Radiological Protection and Chemistry Controls
R1.1 Observation of Routine Radiolocical Controls
a.
Insoection Scoce (71750)
j
General Health Physics (HP) activities were observed during
the report period.
This included locked high radiation area
i
doors, proper radiological postings, and personnel frisking
upon exiting the Radiologically-Controlled Area (RCA).
The
inspectors made frequent tours of the RCA and discussed
radiological controls with HP technicians and HP management.
No deficiencies were identified.
R1.2 Misalioned Sucoression Pool Sample Valve
a.
Insoection Scoce (71750)
The inspectors discovered Suppression Pool Sample Valve
2P33-F364 to be open on August 14.
The valve is located on
Sample Panel 2P33-P101 in the Reactor Building.
b.
Observations and Findinas
During a routine tour of the Reactor Building, the
'
inspectors observed a steady stream of water flowing from
the Suppression Pool Sample Valve, 2P33-F364.
The inspectors reviewed the applicable plant procedure,
64CH-SAM-004-OS, " General Chemistry Sampling," Rev.5, Ed.
1,
'
dated November 7,
1995, and Piping and Instrumentation
}
Enclosure 2
4
.
GPC
21
Diagram (P&ID) which indicated that the normal position of
the valve was closed.
FSAR section 9.3.2,
Process Sampling
System, did not specifically indicate the normal position of
,
'
the valve but stated that the sampling valve is for drawing
process fluid into a closed sample container.
l
l
The inspectors discussed the problem with chemistry
g
personnel.
The inspectors were informed that sampling flow
J
through this sample valve and the corresponding valve on
Unit 1 was, as a matter of routine, left running because of
problems encountered with sample line blockage due to
i
sediment buildup.
The inspectors were not able to find any
I
procedural guidance that allowed the continuous flow of
I
sampling streams to prevent line blockage for these valves.
l
1
The licensee took immediate corrective action by returning
j
the valve to its normal position as specified by procedure.
1
The licensee stated they would monitor the buildup of
j
sediment in the sample lines.
In the future, if conditions
warrant, a procedural change will be initiated prior to
leaving any sample valves open to prevent line. blockage.
The inspectors verified that the corresponding suppression
pool sample valve on Unit 1 was in the closed position,
c.
Conclusions
This NRC-identified failure to follow procedure is being
treated as an NCV consistent with Section IV of the NRC
NCV 50-366/96-11-03, Failure to Follow
Procedure for Sample Valve Lineup, was identified.
R4
Staff Knowledge and Performance
j
1
R4.1 Samolino Analysis Collection Technicues (71750)
1
On August 8,
Chemistry Department personnel informed the
d
operations Department that fuel oil samples collected on EDG
1A and 1B fuel oil tanks and the diesel-driven fire pump
fuel oil tank were not within specifications.
Analysis
indicated particulate at 16 milligrams per liter (mg/1) and
11 mg/l for the 1A and 1B EDG, respectfully.
The fire pump
fuel oil analysis indicated particulate at 55 mg/1.
TS 3.8.3.D for stored fuel oil requires total particulate to be
less that or equal to 10 mg/1.
The Operations Department
immediately entered the appropriate TS LCO for the systems.
The out-of-specification tanks were immediately re-sampled
and the samples sent offsite for analysis.
On August 9,
the
re-analysis indicated satisfactory results.
Chemistry
personnel investigated the problem to determine the root
cause for the discrepancy and identified areas for
improvement in the collection techniques.
Licensee
l
i
Enclosure 2
l
l
!
!
_ . _ _ .
_
_ _ _ .
. _ . _ _ _ _
_ _ _
. _
_
_
__ _
,
.
o
22
l
representatives stated that they believed personnel
collecting the samples stirred up the bottom of the tanks
resulting in non- representative samples.
Poor collection
-
techniques were also suspected as a problem during
,
subsequent backup sample collections.
Personnel who collected the samples were qualified in
collection techniques but had not recently performed the
task.
As part of the corrective actions, management
cautioned personnel of the importance of obtaining
representative samples and the impact and consequences of
poor sampling techniques.
.
The inspectors reviewed and discussed the problem with
licensee management, reviewed applicable sampling procedures
l
4
.
and the licensees corrective actions.
The inspectors
'
concluded that poor sampling techniques were probably the
root cause of the problem.
More attention to detail during
the sample collection process may prevent similar problems.
This was identified as an area for improvement in the
chemistry sampling process.
P2
Status of EP Facilities, Equipment, and Resources
'
P2.1 Facility Insoection
a.
Inspection Scoce (82701)
'
The inspectors toured the facilities to determine whether
!
key facilities and equipment were adequately maintained in
accordance with the site Emergency Plan.
i
b.
Observations and Findinas
The inspectors toured the Technical Support Center (TSC)
Emergency Operations Facility (EOF) , and Operational Support
Center (OSC).
The inspectors witnessed the testing of
selected telephones, fax machines, Safety Parameter Display
System (SPDS), Non-Regulated Emergency Response Data System
(ERDS), Dose Assessment Computer, and the Emergency
Notification Network (ENN) phone.
The equipment operated
properly.
No significant changes had been made to the
facilities.
.
i
The inspectors reviewed documentation that indicated
surveillance of emergency equipment and verification of
'
communications capability were performed at the frequencies
specified in 73EP-TET-001-OS, Control And Testing Of
Emergency Communication Equipment, Revision 4 Ed.
1,
Effective Date June 9,
1994.
The inspectors noted that
deficiencies were resolved in a timely manner.
The inspectors reviewed documentation that indicated
]
facility supplies were being inventoried and maintained in
4
i
Enclosure 2
i
-
.
. . .
.
- - . -
. - -
-
-
..
- . _ - . . - - -
,
..
l
l
l
-
.
GPC
23
accordance with the requirement in 73EP-INS-001-OS,
Emergency Equipment Inventory, Revision 1,
Effective Date
April 27, 1996.
The inspectors randomly selected facility
cabinets and audited emergency supplies and tested
equipment.
No discrepancies were identified by the
inspectors.
c.
Conclusion
The inspectors concluded that the licensee maintained the
facilities and equipment at a satisfactory level of
I
operational readiness.
P2.2 Emercency Response Dose Assessment Cacabilities
a.
Inspection Scoce (82701)
Dose assessment capabilities were inspected to verify that
the licensee maintained continuous dose assessment
capabilities which used real time meteorological and
radiological data.
Also, the inspectors reviewed the
licensee's computerized dose assessment system to evaluate
the training required to operate the system, the capability
of the system, and verify that the licensee's system had
been compared to Radiological Assessment System for
Consequence Analysis (RASCAL).
b.
Observations and Findinos
l
The licensee's Meteorological Information and Dose
'
Assessment System (MIDAS) program was installed on
designated personal computers in the TSC and EOF and if
needed, the program could be loaded on other personal
computers.
Real time radiological and meteorological data
was input to the computer.
The program used default values
from WASH 1400 for the source terms and did not have the
,
'
capability of using actual isotopic analysis data from a
Post Accident Sampling System (PASS) sample.
MIDAS had the
capability to use field team radiological data to back
l
calculate a source term.
The inspectors observed the licensee perform several dose
assessment calculations using MIDAS.
The inspectors
observed that the computer dose assessment system was user
friendly and did not require extensive training to obtain a
dose assessment.
The Senior Reactor Operators (SROs) and Reactor Operators
(ROs) were trained to do on-shift dose assessment using the
" Prompt offsite dose assessment" version of MIDAS.
This was
a simplified version of MIDAS which used some default
i
l
values.
The operators received MIDAS training as part of
l
licensed operator training.
Enclosure 2
- _ .
- - . - . - . -
. .
- - .
- . -
_ - - ~ . ~ - - - . -
. . .-..-_
.- .
.
A
GPC
24
The inspectors verified that the licensee had compared dose
j
assessment calculations from MIDAS to calculations from
NRC's RASCAL and that the results were comparable,
i
c.
Conclusion
l
The inspectors concluded that licensee personnel were
capable of performing on-shift dose assessments using real
l
time meteorology.
The licensee's MIDAS dose assessment
l
calculation program was user friendly and results were
l
comparable to those from RASCAL.
,
P2.3 Emeroency Operations Facility - Emeroency Ventilation System
I
a.
Insoection Scoce (82701)
The inspectors reviewed the EOF Emergency Ventilation System
L
and its testing to determine if the licensee was maintair.ing
the system in accordance with Emergency Plan requirenents.
b.
Observations and Findinas
'
The EOF was not designed as a hardened facility and the
l
licensee maintained a fully equipped backup EOF.
The EOF's
l
Emergency Ventilation System was a zero pressure system with
j
High-Efficiency Particulate Air (HEPA) Filters and no carbon
.
filter.
In the emergency mode of operation, the Emergency
ventilation System isolated outside air and recirculated air
in the EOF through HEPA filters.
The inspectors interviewed
the system engineer responsible for the system, performed a
walkdown of the system, and observed an operational
demonstration of the system.
All components (dampers) and
instrumentation worked properly.
!
c.
Conclusion
l
The inspectors concluded that the licensee was testing and
maintaining the EOF Emergency Ventilation System adequately.
!
P2.4 Tone Alert Radios. Public Alert And Notification
Caoabilities
a.
Insoection Scone (82701)
This area was inspected to determine if the licensee's
method of notifying the public in the event of an emergency
was in accordance with the site Emergency Plan.
In
addition, the inspectors reviewed the system's procedures,
l
configuration, and reliability.
j
l
\\
!
!
l
Enclosure 2
l
l
l
i
-
_
_
.
.
- - - - .
.
.
. . .
. __
_
. . .
.-
_ _ .
. _ . _
_
_ .__ _ _ __
-
_
_ _ _ . . . _ .
_
!
.
!
.
]
]
GPC
25
!
b.
Observations and Findinos
!
The inspectors reviewed licensee's documentation and
discussed with the licensee, their public alert and
<
notification process.
The licensee's system for alerting
and notifying the public used approximately 2900 Tone Alert
Radios located within about a ten mile radius of the plant.
i
The licensee maintained accountability of local business and
4
residence within the ten-mile Emergency Preparedness Zone
i
(EPZ) that needed Tone Alert Radios with the aid of the
i
local electrical power companies.
When a local business or
resident changed their electrical power services, the
utility notified the licensee.
i
i
In September 1995, Plant Hatch's National Oceanographic &
Atmospheric Administration (NOAA) service was discontinued
from the Savannah, Georgia weather station and service was
updated and switched to the National Weather Service (NWS)
.
in Jacksonville, Florida.
The primary communication was
'
from Jacksonville and utilized a leased line from
Jacksonville to the Brunswick micro-wave tower, then the
Georgia Power Company (GPC) micro-wave system to the site.
A secondary line was a leased land line from Jacksonville to
'
1
Plant Hatch.
The radios were operationally tested each
Wednesday when the NWS station generated a tone which was
'
transmitted from the Plant Hatch NWS transmitter to activate
the tone alert radios.
In addition to the testing, there
-
were numerous instances in 1995 and 1996 in which the system
was activated for severe weather conditions.
The inspectors
reviewed the 1995 annual report for the Tone Alert Radios.
The report and supporting data indicated a 99 percent
i
ava: lability factor for 1995.
There were two instances of
minor losses of services during the year, one for 50 minutes
!
and another for 22 minutes.
c.
Conclusion
The inspectors concluded that the Tone Alert Radio system
had been demonstrated to be reliable through testing and
actual actuation, and the system was being adequately
maintained.
P3
EP Procedures and Documentation
P3.1 Maintenance of th3 Emeroency Plan and Procedures
a.
Insoection Scone (8?701)
The inspectors reviewed the licensee's process for making
changes to the Emergency Plan and Emergency Implementing
Procedures (EIPs).
The inspectors reviewed changes to the
EIPs and verified that changes to the EIPs were in agreement
with and implemented the Emergency Plan.
Enclosure 2
i
j
.
J
j
_ .
.
.
__
_
e
.
-
.
GPC
26
'
b.
Observations and Findinos
1
Procedures were revised in accordance with administrative
.
procedure 10AC-MGR-003-OS, Preparation and Control of
,
4
'
Procedures.
Proposed changes to the Emergency Plan and EIPs
received a 50.59 evaluation and a review by the Plant Review
Board. The inspector reviewed the licensee's documentation
t
for four EIP changes.
The inspectors reviewed the changes
4
to evaluate the licensee's evaluation of the changes, and to
i
independently evaluate the changes for the intent of the
.
change and to verify that the change continued to
I
implemented the plan.
A review of licensee records
indicated that the revisions to the EIPs were satisfactory
and were submitted to the NRC within 30 days of the
implementation date, as required.
l
Controlled copies of the EIPs in the EOF and TSC were
l
reviewed and determined to be maintained up to date.
1
c.
Conclusion
i
The inspectors concluded that the licensee's review process
was satisfactory and met the requirements of
j
P3.2 Use Of The Emeroency Implementino Procedures
a.
Insoection Scoce (82701)
The inspectors reviewed the licensee's event declaration to
verify that the event was properly classified and the
Emergency Implementing Procedures were properly implemented.
b.
Observations and Findinos
!
The inspectors reviewed the licensee's one event declaration
since the last inspection conducted in April 1995.
On March 20, 1996, a NOUE was declared due to a
contaminated, injured individual being transferred off-site
to a local hospital.
,
I
c.
Conclusion
,
The inspectors concluded that the event was properly
classified, the notification was made in a timely manner,
!
and the applicable EIP was implemented.
i
a
I
1
i
l
Enclosure 2
J
!
l
. .
- _
.
GPC
27
P5
Staff Training and Qualification in EP
PS.1 Trainino of Emercency Response Personnel
a.
Inspection Scoce (82701)
The inspectors reviewed the Emergency Response Training
Program and verified that emergency response personnel were
initially trained and retrained annually to maintain their
training current.
b.
Observations and Findinos
The inspectors reviewed Plant E.I.
Hatch System Master Plan
for Emergency Preparedness Training. The Master Plan
described the program, position, qualification requirements,
required job performance task, and initial and continuing
training requirements.
Emergency Response Organization
(ERO) training consisted of completing job task, classroom
training, and self study.
The inspectors selected two
lesson plans and their associated exams from the Master Plan
for review.
The inspectors concluded from the review that
the lesson plans satisfactorily covered the information
necessary for the position; the lesson plans were organized
and contained the appropriate depth of material; and the
exams were challenging.
The inspector selected six individuals within the ERO from
the current revision of the Emergency Response Position
Matrix and reviewed their training records against their
required training.
All of the individual qualifications
reviewed by the inspectors were up-to-date,
c.
Conclusion
The inspectors concluded that the licensee maintained a
satisfactory Emergency Preparedness training program.
P5.2 Emeroency Plannino Drills
a.
Insoection Scope (82701)
The inspectors compared the licensee drill commitments to
the actual drills performed, and evaluated the quality of
those drills.
b.
Observations and Findinos
The inspectors reviewed and compared the licensee's drill
documentation to Section N,
Exercises and Drills of their
Emergency Plan, and the requirement in 73EP-ADM-001-OS,
Maintaining Emergency Preparedness, Revision 3, Effective
Date April 9,
1996.
The inspectors found the licensee's
documentation to be well-organized.
The licensee's drill
Enclosure 2
.
--
.
- .-
- . - _ - _ - _ _ _ - - . .
.~ -
.
.
.
'
i-
GPC
28
scenarios were satisfactory, the critiques were objective,
and the drill comments or action items were well-documentad
and tracked.
I
c.
Conclusion
l
l
The licensee satisfactorily met their its drill commitments.
P6
EP Organization and Administration
a.
Insoection Scoce (82701)
The inspectors reviewed this area to determine if any
changes in management or personnel had occurred which would
affect the efficiency or performance of the ERO.
b.
Observations and Findinos
The inspectors reviewed the licensee ERO structure and
discussed the current ERO with the Emergency Preparedness
Coordinator.
c.
Conclusion
The inspectors concluded that since the last inspection in
April 1995, no onsite management or significant personnel
changes had occurred which would affect the performance or
maintenance of the Emergency Preparedness Program.
P7
Quality Assurance in EP Activities
P7.1 Recuired 10 CFR 50. 54 (t) Audit Of Emeroency Preparedness
Procram
a.
Inspection Scoce (82701)
The inspectors reviewed this area to assess the quality of
the required audit, the qualifications of the auditors, and
verify that the audit met the requirements of
b.
Observations and Findinos
The inspector reviewed SAER-07, " Hatch Project Safety Audit
And Engineering Review Procedure For SAER Audits", Revision
8,
dated December 12, 1995.
The procedure required an
" Audit Planning Matrix" to be prepared once per year for the
upcoming year and the final revision to be distributed to
the SRB.
The Audit Planning Matrix was to list the Audit
Area Titles and a breakdown of the Audit Elements.
Auditors were to use the Audit Planning Matrix to prepare an
audit plan and checklist.
Enclosure 2
__.
_
_
_ _ .
_ __ _ _. __
. . . . _ . -
__ _ _ _ _ . _
.
.
1
'
GPC
29
'
The inspectors reviewed the Audit Planning Matrix for the
The matrix listed fifteen areas which
'
corresponded to the titles of each chapter in the Emergency
)
I
Plan.
l
The inspector reviewed Audit 95-EP-2, which was a three-
person audit conducted between November 13, and December 13,
,
1595.
The audit was considered by the licensee to be the
-
annual Emergency Preparedness. Audit required by
l
The cover letter stated that the audit was
based upon completing the fifteen elements specified in the
Audit Planning Matrix.
The inspectors reviewed each
auditor's checklists and noted that the audit was not based
upon or conducted in accordance with the Planning Matrix or
as specified in the report cover letter.
The actual audit
was performed using the guidance in an Institute of Nuclear
Power Operations (INPO) document,85-014, " Generic Guidanco
For Emergency Preparedness Review."
The auditors' checklist
and notes mirrored the elements, A through G,
and the
elements breakdown in the INPO document.
The audit
contained 118 element breakdowns.
In reviewing the
auditors' notes, the inspectors noted that, for some issues,
the auditors relied on discussions with EP staff but did not
independently verify their results.
One element breakdown questioned whether the EIPs provided a
space for a check mark or initial to indicate that the step
had been complete.
The audit result indicated that the
procedures did provide a space. The inspectors independently
reviewed approximately five different EIP's and did not
observe any such provision in the EIPs.
There were no issues identified by the licensee in the Audit
report.
The inspector reviewed the audit to verify that the elements
identified in 10 CFR 50.54(t) were addressed.
The
inspectors noted that Audit 95-EP-2 did not address the
requirement in 10 CFR 50.54 (t) for " Adequacy of interface
with State and local governments."
After discussions with
the licensee, it was determined that the element was covered
in an independent Corporate audit, Audit Report No. 96-3.
The inspectors reviewed the qualification requirements for
an auditor and lead auditor and concluded that the program
qualification requirements were in accordance with American
National Standards Institute, Inc. (ANSI)-N45.2.23.
The
inspectors reviewed each auditor's qualification card and
noted that their qualifications were satisfactorily
completed and up-to-date.
Enclosure 2
.
~ . . .
.
--.
- - . . ~
. . -
. ~
. - -
.- -.
-.- -
.
-
.
.
GPC
30
c.
Conclusion
The inspectors concluded that the audit performed did not
independently verify some conclusions and at least one audit
finding was incorrect.
Although the audit was not conducted
in accordance with the Audit Planning Matrix, the aggregate
,
j
of the audit elements satisfied the 10 CFR 50.54 (t)
requirement for an annual independent. audit of the~EP
program.
The inspectors concluded that the auditors
,
qualification program was satisfactory and the auditors were
qualified.
'
I
P7.2 Licensee's Corrective Action Procram For Drill Comments and
Issues
a.
Insoection Scoce (82701)
The area was inspected to evaluate the licensee's corrective
.
actions to comments and issues identified in their drills.
J
b.
Observations and Findinas
The inspectors reviewed the licensee's drill documentation
and verified that significant critique comments were being
tracked and resolved.
Emergency Preparedness issues were
tracked on-the licensee's Action Item Tracking (AIT) system.
.
For each issue, the AIT gave a description of the issue,
J.
identified the responsible group and person, and indicated
its status and estimated completion date.
Individuals
maintained a file on the issues assigned to them, and when
,
{
the AIT was updated, the individual was responsible to
review the status of their issues.
The inspectors noted
from the review of the AIT that there were few issues older
-
than one year old,
c.
Conclusion
The inspectors' review concluded that the emergency
preparedness issues were satisfactorily tracked and resolved
in a timely manner.
The licensee's resolution of items
tracked was adequate.
P8
Miscellaneous EP Issues
,
P8.1 (Closed) Follow-uo Item 50-321.366/95-09-01:
Correction of
discrepancies between the Plan and EIPs regarding follow-up
i
notifications to the State and counties at the Alert level
and above.
The inspector reviewed and verified that
procedures 73EP-EIP-004-OS, Duties Of Emergency Director,
Revision 5,
Effective Date July 26, 1995 and
73EP-EIP-073-OS, Offsite Emergency Notifications,
^
Revision 11, Effective Date July 19, 1995, had been revised
+
i
to correct discrepancies regarding follow-up notifications
to State and local officials during declared emergencies.
i
!
Enclosure 2
a
f
.
--
.
i
GPC
31
The applicable emergency preparedness training material was
revised to reflect the changes to the procedures.
Both
'
procedures had been changed to require follow-up
notifications to be performed " periodically."
P8.2 Conclusion / Assessment
i
The licensee Emergency Preparedness Program plan and
procedures, training equipment, and response facilities were
being satisfactorily maintained.
The licensee properly
classified an event and made the necessary notifications in
a timely manner.
Licensee personnel were capable of
performing on-shift dose assessments.
The tone alert radio
system was reliable and adequately maintained.
Licensee
drill comments were satisfactorily resolved in a timely
manner.
S2
Status of Security Facilities and Equipment
The inspectors toured the protected area and coserved that
the perimeter fence was intact and not compromised by
erosion nor disrepair.
The fence fabric was secured and
barbed wire was angled as required by the licensee's Plant
Security Plan (PSP).
Isolation zones were maintained on
both sides of the barrier and were free of objects which
could shield or conceal an individual.
The inspectors
observed that personnel and packages entering the protected
area were searched either by special purpose detectors or by
a physical search for firearms, explosives and contraband.
Badge issuance was observed, as was the processing and
escorting of visitors.
Vehicles were searched, escorted,
and secured as described in the PSP.
The inspectors
verified that the security procedures addressed suspension
of safeguards during emergencies in accordance with 10 CFR 50. 54 (x) and 50. 54 (y) .
The inspectors concluded that the areas of the PSP inspected
met the PSP requirements.
V.
Manacement Meetinas
X.
Review of UFSAR Commitments
A recent discovery of a licensee operating its facility in a
manner contrary to the Updated Final Safety Analysis Report
(UFSAR) description highlighted the need for a special
focused review that compares plant practices, procedures
and/or parameters to the UFSAR description.
While
performing the inspections discussed in this report, the
inspectors reviewed the applicable portions of the UFSAR
l
that related to the areas inspected.
The inspectors
verified that the UFSAR wording was consistent with the
l
observed plant practices, procedures, and/or parameters.
!
i
Enclosure 2
.
.
- GPC
32
X.1
Exit Meeting Summary
The inspectors presented the inspection results to members
of licensee management at the conclusion of the inspection
on September 20, 1996.
The license acknowledged the
findings presented.
An interim exit was conducted on
August 30, 1996.
The inspectors asked the licensee whether any materials
examined during the inspection should be considered
proprietary.
No proprietary information was identified.
X.2
Other NRC Personnel On Site
On August 19-20, 1996, Mr.
P.H. Skinner, Chief Reactor
i
Projects Branch 2, visited the site.
He met with the
l
resident inspector staff and discussed plant issues,
licensee performance, and generic issues.
He also attended
licensee management meetings and met with licensee
management to discuss licensee performance and regulatory
issues.
l
PARTIAL LIST OF PERSONS CONTACTED
Licensee
Anderson,
J.,
Unit Superintendent
Betsill,
J.,
Operations Manager
Coggin,
C.,
Engineering Support Manager
Curtis,
S.,
Operations Support Superintendent
Davis,
D.,
Plant Administration Manager
Fornel,
P., Performance Team Manager
Fraser,
O.,
Safety Audit and Engineering Review Supervisor
Hammonds,
J.,
Regulatory Compliance Supervisor
Kirkley,
W.,
Health Physics and Chemistry Manager
Lewis,
J., Training and Emergency Preparedness Manager
Moore,
C.,
Assistant General Manager - Plant Support
Reddick,
R.,
Site Emergency Preparedness Coordinator
Roberts,
P.,
Outages and Planning Manager
Sumner,
H.,
General Manager - Nuclear Plant
Thompson,
J.,
Nuclear Security Manager
Tipps,
S.,
Nuclear Safety and Compliance Manager
Wells,
P.,
Assistant General Manager - Operations
INSPECTION PROCEDURES USED
IP 37551:
Onsite Engineering
IP 40500:
Effectiveness of Licensee Controls in
Identifying, Resolving, and Preventing Problems
IP 61726:
Surveillance Observations
IP 62703:
Maintenance Observation
IP 62707:
Maintenance Observation
IP 71707:
Plant Operations
IP 71750:
Plant Support Activities
Enclosure 2
.-.-.-.-. _ -. . - - _ ..-.- .-_ - -. - . .- _ ..- .-.- _ .-....~. _ ._ .. - . - ._. .
-
'
i
GPC
33
IP 82701:
Operational Status Of The Emergency Preparedness
Program
IP 92700:
Onsite Follow-up of Written Reports of Nonroutine
Events at Power Reactor Facilities
r
'
IP 92901:
Followup - Operations
p IP 92902:
Followup - Maintenance / Surveillance
NIP 92903:
Followup - Followup Engineering
ITEMS OPENED, CLOSED, AND DISCUSSED
!
!
Opened
I
!
50-321,366/96-11-01
IFI
Review of Engineering Report
l
on the Effects of Harmonics on
EDG Operation (Section E2.1).
50-321/96-11-02
Failure to Perform an ASME
Code Required VT-3 Inspection
identified (Section E2.2).
$
Closed
l
50-321,366/95-09-01
IFI
Correction of discrepancies
l
between the Plan and EIPs
regarding follow-up
notifications to the State and
counties at the Alert level
and above (Section P8.1).
50-321/95-16-01
Contract personnel failure to
]
follow procedure while
performing maintenance on
valve 1E41-F003
i
!
(Section E8.1).
50-321,366/95-18-02
Failure to follow Procedure.
First example (Section M8.2).
Second example (Section 08.5).
50-366/95-26-01
Inability to safely shutdown
Unit 2 from Remote Shutdown
Panel in the event of a fire
in the Main Control Room
(Section 08.4).
50-321/95-23-01
Operators' failure to follow
procedure while transferring
diesel fuel oil
(Section 08.3).
.
!
i
Enclosure 2
l
l
.
wwa -
r-
,
,w
4
e-
+
-
-r
iw--
ni
e-wi
,-
>w-w,
e-
-
-g,+y9
.
_ .. ~ .
- - - - - - - - . _ _ _ - - -
..- - . - .- ._ - . .. -.. _ ..- -.
..-. - .
.
j
-
-
GPC
34
50-366/96-03
LER
High Pressure Coolant
Injection System Temporarily
Inoperable Following
Engineering Safety Feature
l
Actuation (Section M8.1) .
50-321,366/96-07-01
Determine Safety Significance
and Testing Requirements for
Unit 1 and Unit 2 Containment
Isolation Status Panel
(Section
08.1).
50-321/96-11
LER
. Inadequate Procedure Results
in Missed Technical
!
Specifications Surveillances
(Section 08.2).
50-321,366/96-11-01
Failure to Test or Verify the
Function as Described in USFAR
of the Isolation valve
Indication on the Containment
Isolation Status Panels
,
'
(Section 08.1).
50-366/96-11-03
Failure to Follow Procedure
for Sample Valve Lineup
(Section R1.2).
LIST OF ACRONYMS USED
-
Action Item Tracking
ASME -
American Society of Mechanical Engineers
I
cfm
-
cubic feet per minute
CFR
-
Code of Federal Regulations
CR
-
Control Room
l
-
Control Rod Drive
!
-
Design Change
-
Design Change Request
ECCS -
Emergency Core Cooling Systems
-
-
Electro Hydraulic Control
l
EIP
-
Emergency Implementing Procedures
-
Emergency Notification Network
-
Emergency Operating Facility
-
-
ERDS -
Emergency Response Data System
l
-
Emergency Response Organization
i
FSAR -
Final Safety Analysis Report
(
GPC
-
Georgia Power Company
HEPA -
High-Efficiency Particulate Air Filters
'
-
Health Physics
,
HPCI -
High Pressure Coolant Injection
I
j
Enclosure 2
-
. . . .
-
.
.
--
_ _ _ . _ . _ . _ - - _ _ - . - _ . _ _ . _ _ . _ . _ _ _ _ _ _ . . . . _ - . - . . . _ _ . _ _ . _ . _
-
=
,\\<:
.
i j Ii
J
1 illl
GPC
35
ig;
1 5 It'
f ('
Hz
-
hertz
i
,
l
IFI
-
Inspector Followup Item
INPO -
Institute of Nuclear Power Operations
Inspection Report
IR
-
kw
-
kilowatt
1
-
liter
LCO
-
Limiting Condition of Operation
Licensee Event Report
LER
-
LPCI -
Low Pressure Coolant Injection
Main Control Room
-
-
Minor Design Change
mg
-
milligram
-
Motor-Generator
l
MIDAS-
Meteorological Information and Dose Assessment
j
l
System
MWO
-
Maintenance Work Order
-
Non-Cited Violation
NOAA -
National Oceanographic & Atmospheric Administration
NOUE -
Notice of Unusual Event
l
NRC
-
Nuclear Regulatory Commission
-
Nuclear Reactor Regulation
'
I
NSSS -
Nuclear Steam Supply System
-
National Weather Service
-
Operations Support Center
P&ID -
Piping and Instrumentation Diagram
PASS -
Post Accident Sample System
-
Public Document Room
-
Plant Security Plan
PSW
-
Plant Service Water System
-
Quality Assurance
-
Quality control
QCIR -
Quality Control Inspection Report
-
Required Action Statement
RASCAL- Radiological Assessment System for Consequence
Analysis
-
Risk Achievement Worth
-
Radiological Controlled Area
-
Reactor Feedwater Pump
RFPT -
Reactor Feedwater Pump Turbine
-
-
-
Reactor Recirculation
-
Rated Thermal Power
-
Site Area Emergency
SAER -
Safety Audit and Engineering Review
Standby Gas Treatment
-
SOS
-
Superintendent On Shift
SPDS -
Safety Parameter Display System
Surveillance Requirement
SR
-
-
Senior Reactor Operator
-
Station Service
7
TS
-
Technical Specifications
-
Enclosure 2
. -
. -
.
, _ . _
.
. _ _ _
._.
f
i
.
.
1
.
GPC
36
TSIP -
Technical Specification Improvement Program
UFSAR-
Updated Fina) Safety Analysis Report
-
Unresolved item
-
Violation
1
l
I
1
l
Enclosure 2
'