ML20216E798
| ML20216E798 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 03/10/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20216E778 | List: |
| References | |
| 50-321-97-12, 50-366-97-12, NUDOCS 9803180165 | |
| Download: ML20216E798 (55) | |
See also: IR 05000321/1997012
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U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos: 50-321. 50-366
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Report No: 50-321/97-12. 50-366/97-12
Licensee: Southern Nuclear Operating Company. Inc. (SNC)
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Facility: E. I. Hatch Units 1 & 2 i
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Location: P. O. Box 2010
Baxley. Georgia 31515
Dates: December 28, 1997 - February 7. 1998
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Inspectors: B. Holbrook. Senior Resident Inspector !
J. Canady. Resident Inspector
C. Rapp. Team Leader (Sections E3.1 thru E3.12)
G. Kuzo. Senior Radiation Specialist (Sections
R1.1. R1.2. R5.1 and R7.1)
Accompanying Inspectors: T. Fredette. Resident Inspector
approved by: P. Skinner. Chief. Projects Branch 2
Division of Reactor Projects
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Enclosure 2
9803180165 980310
G ADOCK 05000321
EXECUTIVE SUMMARY
Plant Hatch. Units 1 and 2
NRC Inspection Report 50-321/97-12, 50-366/97-12
This integrated inspection included aspects of licensee operations.
engineering, maintenance, and plant support. The report covers a 6-week
period of resident inspection and region-based specialist inspection. In
addition, the results of an engineering inspection conducted at your corporate
headquarters in December 1997 are included.
Ooerations
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- e Operator response to the 2A Emergency Diesel Generator (EDG) fire was
good. Maintenance evaluation of the cause of the fire and subsequent
recommendations for surveillance testing were also good (Section 02.1).
e The EDG procedural precautions contained ambiguity related to running the
EDGs unloaded, or at low load (Section 02.1).
e The inspectors concluded that the Nitrogen Supply System for the
Containment Atmospheric Dilution System (CAD) was operable. However, the
. system was not well-maintained. Violation (VIO) 50-366/97-12-02. Failure
to Implement Changes to Vendor Manual, was identified (Section 02.2).
l e The inspectors observed during a walkdown of the CAD system that the
Technical S)ecification (TS) surveillance requirements (SR) for both
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units were )eing met. All valve positions checked in the main control
l room and locally were in their required position (Section 02.2).
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l e An example of VIO 50-366/97-12-09. Failure to Follow Procedure - Multiple
Examples, was identified. Operations failed _to submit a timely
deficiency card for a frozen safety-related nitrogen pressure control
l valve (Section 02.2).
l e The Plant Review Board (PRB) organization and function met Updated Final
l Safety Analysis Report (UFSAR) requirements. The 10 CFR 50.59
l evaluations reviewed were thorough and detailed. Equipment reliability
and corrective action meetings were effectively focused. Equipment
problems were being corrected and management and PRB members demonstrated
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a strong safety focus for equipment availability and reliability
(Section 07.1).
Maintenance
e Maintenance personnel _and Plant Equipment-Operators exhibited excellent
procedural familiarity for the isolation of the instrument air supply
l outside the power block. Appropriate compensatory measures were taken
for the partially opened fire door to the Emergency Diesel Generator day
tank room (Section M1.2).
Enclosure 2
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e Instrumentation and Control personnel adherence to procedural
i instructions during reactor vessel water level reference leg backfilling
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activities was good and work activities were performed in a 3rofessional <
manner. Appropriate Technical Specification actions were tacen during l
these activities (Section M2.1). '
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e Maintenance and engineering personnel 3rovided excellent support for the
trouble shooting and repair of the 2C Emergency Diesel Generator
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following a failure to start. Procedures were used, supervisory
oversight was evident and all Technical Specification requirements were
met (Section M2.2).
e The inspectors concluded that the pre-test briefing for a High Pressure
Coolant Injection Test was satisfactory. An improvement was observed in
operato r.hree-part communications during the test. Supervisory
oversig:4 during the test was evident (Section M3.2).
e The 10 CFR 50.72 notification for the inoperable Unit 2 High Pressure
Coolant Injection System was appropriate. All the surveillance test
acceptance requirements were met (Section M3.2).
- Due to a lack of attention to detail, a surveillance procedure frequency
change form was not submitted. This resulted in a failure to perform
weekly RPS channel test switch functional tests as committed to in a
General Electric (GE) Licensing Topical Report. This was identified as
NCV 50-321/97-12-03, Failure to Follow Procedure for Scheduling Weekly
Testing of RPS Scram Test Switches (Section M3.3).
Enaineerina
e The inspectors concluded that the licensee had taken the appropriate
action in addressing the 10 CFR 21 issue related to GE Type CR120 AD
relays (Section E2.1). I
e The inspectors concluded that engineering personnel demonstrated
excellent observations for problem identification on the Standby Liquid
Control and Standby Plant Service Water systems. Corrective actions were
timely; site maintenance and engineering and corporate engineering
support was excellent (Section E2.3).
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e The Significant Occurrence Report associated with the review of the
Traversing Incore Probe nitrogen purge valve issue was good. The
determination that the valve could be removed from the lis'/,9 of drywell
isolation valves was appropriate (Section E2.4).
e VIO 50-321, 366/97-12-05. Failure to Include Nitrogen Valves in a Test l
Program In Accordance with 10 CFR 50.Section XI of Appendix B. Test
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Cantrol, was identified (Section E2.5).
l e VIO 50-321, 366/97-12-06. Insulation on Nitrogen Supply Piping Not
l Installed in Accordance with Drawings, was identified (Section E2.5). I
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e The licensee's followup of the cycle-dependent SLMCPR issue was adequate.
The licensee was knowledgeable about the subject and took conservative
actions to correct possible safety deficiencies (Section 3.8).
e Although the RBM channels were operable during this period, and
administratively required after the licensee became aware of the problem._
the TS requirement was not implemented until after the licensee TS
-amendment request of May 9, 1997 (Section E3.12).
Plant Suncort
e Radiological controls for normal opnam e J for routine radioactive
waste (radwaste) processing, storage ar.c trannortation activities met-
procedur01. Technical Specification and 10 CFR Part 20 requirements
(Section R1.1).
e Current radiological environmental monitoring program (REMP) equipment.
instrumentation, and operations met Offsite D>se Calculation Manual
(ODCM) requirements (Section R1.1),
e The Radiation Protection Chemistry technician observed taking a drywell
grab sample was professional and knowledgeable of procedural
requirements. Procedural weaknesses were identified for guidance
associated with actions to take when noble gas readings exceed the
acceptance criteria (Section R1.3).
e A violation was identified for failure to dispose of licensed material in
accordance with 10 CFR 20.2001(a) requirements (Section R1.2).
e The limited use of automated gc.ma-sensitive equipment to conduct surveys I
of aggregate U1 Radwaste Building concrete debris released to the onsite !
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landfill was identified as a program weakness (Section R1.2). ;
e Technician'and management interpretations of radiation control procedural
requirements were inconsistent (Section R1.2).
- Prior to June 1997, management oversight of the release of U1 Radwaste
building debris from the Waste Separation and Temporary Storage facility
was limited (Section r;.2). .
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o An example of VIO 50-321. 366/97-12-09. Failure to Follow Procedures -
Multiple Examples, was identified for a failure to follow procedures for
documenting release surveys (Section R1.2).
e No exposure rates above background were identified during confirmatory i
surveys of the two landfill trenches where the U1 Radwaste Building l
concrete debris was buried (Section R12).
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e The fission product monitoring (FPM) system trouble shocting activities
led by chemistry with maintenance. and operations support was not well-
planned or coordinated. The problem solving team convened by Nuclear
Safety and Compliance conducted an excellent investigation for the root
causes of the FPM and commercial grade oxygen analyzer problems. NCV 50-
321/97-12-08. Personnel Error Results in a Breach of Drywell Integrity,
was identified (Section R2.1).
e The investigations for personnel contamination reports were generally
adequate. The recommended corrective actions were not always thorough i
and comprehensive and some were narrow in focus. Some reports did not
have any recommended corrective actions (Section R3).
e Training provided to contract Health Physics technicians involved in
surveying. releasing, and disposing of U1 Radwaste Building concrete in
the onsite landfill was current and met procedural and 10 CFR Part 19 l
requirements (Section R5.1). I
o Licensee health physics technicians appropriately identified the disposal
of licensed material in the onsite landfill as a deficient radiological
condition (Section R7.1).
- An example of a VIO 50-321. 366/97-12-09. Failure to Follow Procedures -
Multiple Examples, was identified for failure to follow administrative
control procedures for deficiency c;- d initiation (Section R7.1).
e Violation 50-321, 366/97-12-10 was identified for failure to maintain
decommissioning records in accordance with 10 CFR 50.75(g) requirements
(Section R7.1).
- The inspectors concluded that the Self Contained Breathing Apparatuses
were being properly maintained. The emergency facilities were maintained
in a state of readiness and the telephone communications checks were
satisfactory (Section P2.1).
e The ins)ectors concluded that the areas of security inspected met the
applica]le requirements (Section S2).
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Reoort Details
Summary of Plant Statul
Unit 1 operated at 100% rated thermal power (RTP) for the report period.
except during routine testing activities.
Unit 2 began the report period at 100% rated thermal power (RTP). Power was
reduced to approximately 95% on January 6 for removal of the 2B 4th Stage-
Feedwater Heater from service to effect re
Separator Reheater (MSR) drain tank valve.Power pairs of
wasthe 2nd Stage
restored Moisture
to PJP on
January 7. The unit remained at 100% RTP for the remainder of the reporting j
period, except during routine testing activities.
I. Operations i
01. Conduct of Operations
01.1 General Comments (71707)
The inspectors conducted frequent reviews of ongoing plant operations.
In general, the conduct of operations was professional and safety-
conscious: specific events and observation are detailed below.
02 Operational Status of Facilities and Equipment
02.12A Emeraency Diesel Generator (EDG) Exhaust Manifold Fire
a. Insoection Scooe (71707)(92901)(37551)
The inspectors assessed licensee actions following an engine exhaust
manifold fire that occurred during a surveillance test of 2A EDG. A
review was conducted of maintenance and operations recommendations. fire i
incident reporting, and root cause determinations for this fire. I
b. Observations and Findinos
A fire occurred in the 2A EDG exhaust during a semi-annual test conducted
November 22, 1997. The EDG was run unloaded while maintenance personnel j
attempted to adjust and set the " Governor Not at Synchronous Speed" ~
annunciator switch. The EDG is designed to run for extended periods of I
time at no load: however. lube oil accumulates in the exhaust manifold if
the engine is run too'long with no load. During the annunciator switch
adjustment. the engine was run for more than 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> at no load. Lube I
oil collected in the exhaust manifold and subsequently leaked through a
manifold flange, soaking the insulation. and eventually ignited.
Operators reported the fire, secured the EDG. and took appropriate steps
to extinguisi the fire with hand held extinguishers. A fire incic'ent '
report was generated in accordance with DI-FPX-04-0694N. " Fire Incident
Reports." Revision (Rev.) 0. The inspectors reviewed the report and ,
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found that there was confusion.in documenting the actual source of the
fire. The report spec.fied fuel oil as the cause. However, discussions
with maintenance personnel stated that the cause was accumulated lube
oil. Operability of the EDG was not compromised. The fire caused slight
damage to the insulation.
The inspectors reviewed the licensee's procedures for running the EDGs.
All procedures include precautions for the operators to closely observe
engine operation, and to minimize running the engine for " extended
periods of time" at low loads. The EDG procedure precautions contained
ambiguity related to running the EDGs unloaded, or at low load. No clear
definition existed for " extended period of time." The inspectors
discussed this ambiguity with operations personnel. Maintenance
personnel had made informal recommendations to operations regarding
running the EDGs for surveillance purposes including surveillance testing
with maintenance 3ersonnel present to aid in observing and
troubleshooting a] normal EDG behavior. The licensee contacted the vendor
to determine an appropriate "exterded period of time" at low loada.
This issue is identified as Inspector Follow-up Item (IFI) 50-321,
366/97-12-01. Review of Operations. Maintenance and Engineering Actions
for Long-Term Resolution of Running the EDGs Unloaded or at Low Loads,
c. Conclusions
The inspectors determined that the response to the 2A EDG fire by i
operators was good. Maintenance evaluation of the cause of the fire, and !
subsecuent recommendations for operations were also good. The EDG '
procecural precautions contained ambiguity related to running the EDGs
unloaded, or at low load.
02.2 Enaineered Safety Feature Walkdown
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a. Insoection Scooe (71707)
The inspectors reviewed selected parts of the nitrogen inerting system
for Unit 1 and Unit 2. The activity included a review of plant drawings
H-16000 for Unit 1 and H-26083 for Unit 2: procedures 34SV-SUV-011-IS.
" Primary Containment Integrity Demonstration." Rev. 1: 34SV-SUV-011-2S. i
" Primary Containment Integrity Demonstration." Rev. 8. ED 1: 34S0-T48- i'
002-2S, " Containment Atmospheric Control and Dilution." Rev 16:
34S0-T48-002-IS. " Containment Atmos)heric Control and Dilution." Rev.17. )
ED -1, and 52IT-MME-006-0S. " Safety Relief Valve 8ench Test Rev.14. The
ins)ectors conducted a system and component performance history review:
wal ced down parts of the. system to verify that valves were in the
recuired position: and verified that the Technical Specification (TS) and
Upcated Final Safety Analysis Report (UFSAR) requirements were met. 1
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b. Observations and Findinas
The Containment Atmosphere Dilution (CAD) system functions to maintain
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combustible gas concentrations within the primary containment at or below
the flammabi.ity limits following a postulated Loss of Coolant Accident
-(LOCA). Unit I has a safety-related CAD system and Unit 2 uses safety -
l- related hydrogen recombiners. A Unit 2 nitrogen supply. system supplies
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one of the two r@ uired Unit 1 CAD systems. The Unit 2 nitrogen system
is also safety-related.
The inspectors reviewed procedure 521T-MME-006-0S and observed that the
Applica3ility section of the procedure indicated that the procedure was
applicable, but not limited, to Units 1 and 2 safety relief valves. (SRV)
listed in Attachment 1. Eleven Unit 1 SRVs for the CAD system were
listed and one SRV (1T48-F072) was not listed. For Un;t 2. there were
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three SRVs listed and at least five SRVs indicated on plant drawing H-
26083 that were not listed. The inspectors did not find any plant
3rocedure that contained the required set point for any of the SRVs.
10 wever, the procedure required that valve name plate data be recorded
and used as a set point reference. The inspectors concluded that the
procedure was not specific but was adequate to perform the required
tests.
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The ins)ectors "eviewed Unit 1 TS 3.6.1.2 which required verification of
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each CA) subsystem manual power-operated, and automatic valve in the
flow path that is not locked, sealed or otherwise secured, to be in (or
can be aligned to) the correct position. The inspectors reviewed
procedures 345V-SUV-011-1S and -2S for Units 1 and 2. respectively, which
implemented the TS requirement. The inspectors observed that the
procedures did not contain the pressure control valves (PCVs) for the
flow path indicated on the drawings for both units. The inspectors
discussed this with licensee management and engineering person.nel. The
inspectors were informed that the procedure would be reviewed to
determine its adequacy. The inspectors concluded that the PCVs had the
potential to be inadvertently mispositioned but could be returned to the
correct position if required.
On January 20. operators placed the Unit 2 nitrogen storage tank on
manual pressure control because PCV F466 was frozen and would not control
tank pressure. The tank pressure is normally controlled by PCV F466 in
automatic. The inspectors were informed that on or about January 15.
operations personnel filled the nitrogen storage tank from a vendor tank
truck. The licensee believed that the tank may have been overfilled,
which caused the safety relief valve to open on January 20. Flow through
the relief valve caused excessive flow through the PCV. causing it to
freeze. Operations personnel opened the PCV bypass valve and controlled
tank' pressure in manual. The PCV was isolated, safety-tagged, and
removed from service so that it could thaw. The PCV was placed back in
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service on January 21. On February 1. the PCV would not control tank
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pressure and a relief valve lifted. The PCV valve was removed. repaired
and placed back in service on February 3.
The inspectors observed that when PCV F466 froze on January 20. no
deficiency card was initiated-to document the problem. The inspectors
,. reviewed procedure 10AC-MGR-004-05. " Deficiency Control System." Rev.10.
l and observed that step 8.3.1.1 requires, in ) art, that the person who
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identifies a deficiency is to report it to tie Plant Dispatcher within
! one hour. The inspectors observed that a deficiency was reported on
l about January 21 after the inspectors discussed the problem with
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operations supervision. This failure to identify a deficiency was
identified as an exam)1e of VIO 50-321, 366/97-12-09. Failure to Follow
Procedure - Multiple Examples. The failure to document deficiencies for
the nitrogen system was a previously identified 3roblem. A failure to
submit deficiency cards was also identified by tie NRC and is discussed
in Section R7.1 of this Inspection Report.
On February 1. operations personnel again observed that PCV F466 was not
properly controlling the Unit 2 nitrogen tank aressure. A deficiency
card was initiated for maintenance to disassemale, repair and reassemble
the PCV. The inspectors reviewed Maintenance Work Order (MWO) 2-98-356
and procedure 52PM-MME-012-05. " Fisher Pressure Regulator Valve
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Maintenance." Rev. 1. which was used to repair the PCV. The inspectors
observed that step 7.3.26 required the procedure user to contact the
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responsible engineering personnel to determine the operating pressure for
the applicable valve. Step 7.3.27 stated, in part, to adjust the
operating pressure of the valve in accordance with the operating pressure
determined in the previous step. In this case, maintenance personnel
failed to contact engineering to determine the operating pressure of the i
valve. Instead, they used information stated in procedure 34S0-T48-002- )
'2S, which indicated that the normal tank pressure was between 125 and 140
psig, to set the PCV pressure. The inspectors discussed this observation
with maintenance and operations personnel. The inspectors were informed
that the two steps ir the maintenance procedure would be marked not
applicable (N/A) due to the fact that the procedure user could determine
a pressure range (125 to 140) identified in system operating procedure
3450-T48-002-2S. Maintenance management informed the inspectors that the i
practice of marking procedure steps N/A would be reviewed for l
improvement. The inspectors concluded that marking the procedure steps l
N/A was allowed by procedure. However, using alternate means of '
determining system component setpoints was not a good practice.
The inspectors reviewed table 1-1 of the system vendor manual and
ob e yed that the pressure set point for PCV-1 (PCV F466) was listed as
145 psig. Maintenance personnel informed the inspectors that they had ,
l set the pressure for PCV F466 at about 132 asig. The system engineer
I informed the inspectors that the pressure s1ould be set at about 138 psig :
I and that a higher pressure caused the relief valves to open on '
overpressure. However, in this case, the current set point would be i
satisfactory. Maintenance and engineering persorinel informed the i
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. inspectors that a desired pressure set point below the vendor manual
recommended value was recognized over a year ago. The vendor manual was
never revised to reflect the lower set point requirement based upon
system performance history. The inspectors reviewed 3rocedure
20AC-ADM-003-05 ' Vendor Manual Review and Control." lev. 4. and observed ]'
that step 8.7.1 states in part, that-individuals who identify a need for
a vendor manual change may submit the information as a proposed As-Built
Notice (ABN). per applicable procedure. This action was never completed.
and the requirement of 10 CFR 50.. Appendix B. Criterion VI,.to ensure
changes to the vendor document was not met. This. problem was identified
as VIO 50-366/97-12-02. Failure to Implement Changes to Vendor Manual.
The inspect ' review of procedures 34S0-T48-002-15 and -2S identified
that the i s page numbering for.some sections of the Unit 1 procedure
was not co- act. Operations supervision was informed of this
administrauve error.
The inspectors' review of procedure 30AC-0PS-001-0S. ' Control of
Equipment Clearances and Tags." Rev. 17. used to isolate PCV F466 for
repair, verified that the tags were properly placed. One minor
administrative error was observed in that the plant drawing referenced on
the clearance sheet was H20093 and the correct drawing was H26083.
Operations supervision was informed of this error.
Other problems associated with the Nitrogen Inerting System are discussed
in Section E2.5 of this report.
c. Conclusions
The inspectors observed that the TS surveillance requirements (SR) for
both units were being met. All valve positions checked in the main j
control room and locally were in their required position.
The inspectors concluded that the Nitrogen Supply System for the
Containment Atmospheric Dilution System was operable. However, the
system was not well maintained. VIO 50-366/97-12-02. Failure to i
Implement Changes to Vendor Manual, was identified.
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Also, a failure to identify a deficiency was identified as an example of i
VIO 50-321, 366/97-12-09. Failure to Follow Procedure - Multiple 1
Examples.
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07. Quality Assurance In Operations
07.1 Plant Review Board (PRB). Eauipment Reliability. Corrective Actions. and
Information Meetinos
a..Insoection Scooe (71707)(40500)
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Tlie inspectors reviewed Hatch Updated Final Safety Analysis Report
(UFSAR) section 13.4. Review and Audit, that describes the organization
and function'of.the PRB and section 13.4A. Edwin I Hatch-Units 1 and 2
Plant Review Board Charter, and verified that the specified actions and
requirements were being met. The inspectors verified that the equipment i
reliability. meeting addressed equipment with demonstrated deficiencies,
goals and standards for inclusion and exclusion into the program were
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being met, and management was informed of the identified deficiencies.
b. Observations and Findinas
The inspectors attended three PRB meetings. The inspectors observed that
appropriate members were in attendance with the required departments
represented. The inspectors observed that the meetings were held more ,
frequently than required by the UFSAR. Safety issues were discussed and I
procedure changes were reviewed. The 10 CFR 50 59 evaluations reviewed
by the inspectors were thorough and detailed.
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The inspectors attended one equipment reliability meeting (Reg-00401297),-
which focused on significant occurrence reports (SOR) initiated due to
equipment reliability problems. Three SORS were reviewed by Janel i
members for consideration for addition to the equipment relia]ility list.
Engineering support Jersonnel. presented an overview of their
investigation into tie equipment problems.
The inspectors also attended an information meeting which was part of
plant management's effort to meet with all site employees early in 1998.
The inspectors observed that among the topics discussed were:
organizational goals, management's expectations, regulatory compliance,
-industrial safety, im) roving appearance and housekeeplng, and improved
performance for healti physics and radiological controls. Plant
management clearly expressed expectations-for improved performance in all
areas of plant operations.
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c, Conclusions
The inspectors concluded that the Plant Review Board (PRB) organization
and function met UFSAR requirements. The 10 CFR 50.59 evaluations were
thorough and detailed. Equipment reliability and corrective action
meetings were effectively focused. Equipment problems were being
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. corrected, management and PRB members demonstrated a strong safety focus
i for equipment availability and reliability. Plant management clearly
l' expressed expectations for improved performance in all areas of plant
- operations.
l' II. Maintenance
M1 Conduct of Maintenance
! M1.1 General Comments i
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a. jnsDeCtion SCQDe (62707)
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! The inspectors observed or reviewed all or portions of the following work
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activities: i
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- MWO 1-98-0205: Investigate Unit I high drywell oxygen
. MWO 1-97-2416: Clean and eddy current' test 1T41-8004B cooler.
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- MWO 1-98-0088: Investigate EHC puna 18 failure to start
l- * MWO 1-98-0011: . Fire Pump 1B will not develop rated flow
l * MWO 1-98-0012:' Fire Pump 1B tripped on overspeed
l- * MWO 1-97-1737: Replace degrading relays
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b. Observations'and Findinas
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The inspectors found that the work was performed with the work packages
( present and being actively used.
c. Conclusions on Conduct of Maintenance
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Maintenance activities were generally completed thoroughly and
- professionally. No deficiencies 'were identified by the inspectors.
M1.2 Reoair/Reolacemant of Instrument Air Line in Vicinity of Emeraency Diesel
Generator (EDG) Buildina
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a. Insoection Scope (62707)
.. The' inspectors reviewed validation procedure 51CM-MNT-001-05. " Isolation i
of Instrument Air Supply Outside the Power Block." and Maintenance Work j
L Order (MWO) 1-98-0058. These documents were associated with the repairs !
to a. leaking instrument air line outside the power block. The inspectors !
also observed portions of.the work activity and discussed the work ;
activity with maintenance supervision, j
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p b. Observations and Findinas
On January 26. the inspectors observed work activities associated with
the repair / replacement of a section of underground instrument air piping.
The section of piping was replaced due to an air leak caused by
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corrosion. Components of Technical Specification (TS) systems that had
the potential of being affected by the work activities were the level
indication for the EDG storage tanks and the minimum flow valves for the
Plant Service Water and the Residual Heat Removal (RHR) Service Water
minimum flow valves.
The inspectors observed that Plant Equipment Oprators (PEO) supported '
maintenance personnel in the isolation of instrue, ant air headers and the
placement of clearance tags. The inspectors also observed the presence
of maintenance engineering support during the procedural isolation of
the instrument air headers and the connection of temporary tubing with
filters and pressure gauges by maintenance craft persons. The temporary
tubing was used to cross connect service air to instrument air.
The inspectors observed that procedure 51CM-MNT-001-0S provided guidance
for placing a temporary air hose from service air to an instrument air
connection in + e 2C EDG day tank room. This work activity resulted in
the inability to fully close the fire door associated with the room. The (
inspectors observed that the appropriate compensatory measures s)ecified j
in the Fire Hazard Analysis were taken for the partially opened EDG day -
tank room door.
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The inspectors observed from the review of MWO 1-98-0058, discussions
with maintenance supervision. and observance of the work activity that
approximately 25 feet of instrument air piping was replaced. The piping )
connection was fabricated outside of the excavated trench. The
inspectors were informed that the section of piping was re31 aced in order
to minimize the number of weld joints to be performed in t1e excavated
trench.
c. G.ggplusions
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Maintenance personnel and PEOs exhibited excellent procedural famillarity
for the isolation of the instrument air supply outside the power block. i
Appropriate compensatory measures were taken for the partially opened
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fire door to the EOG day tank room.
M2 Maintenance and Material Condition of Facilities and Equipment
M2.1 Backfillf;? of Reactor Vessel Water Level Reference lag
a. Insoection Scoce (62707)(92902)
The inspectors reviewed procedure 57CM-MIC-002-15. "Backfilling of Water
Level Instruments." and Technical Specification 3.3.3.1. " Post Accident
Monitoring (PAM) Instrumentation." This review was associated with the
inoperability and backfill of a PAM reactor vessel water level channel.
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~ b. Ob'servations and Findinas ,
l On December 30. the inspectors observed the backfilling of the reactor
- pressure vessel (RPV) reference leg associated with water level
i
condensing chamber 1821-D002. This reference leg was backfilled due to -
abnormally high. level readings in the control room for indications from i
!
level transmitters (LT) 1C82-N110 and 1B21-N027.
L The inspectors observed that the Instrumentation and Control (I&C)
. technicians performed the backfill activity in accordance with procedure
l 57CM-MIC-002-1S. Subsequently. operations personnel performed a channel
- check and confirmed. proper indication.
I
c. Conclusions
l
'
The I&C personnel adherence to procedural instructions was good and work '
activities were performed.in a professional manner. The appropriate TS
actions were:taken during this evolution.
M2.2 Emeraency Diesel Generator 2C Failure to Start
L
a, Insoection Scone (62707)
The inspectors observed part of the maintenance activities )ost
maintenance testing and operability surveillance on the 2C E E following q
l- , a failure to start during a surveillance conducted on January 20. The:
inspectors reviewed procedures 52SV-R43-001-05. " Diesel. Alternator and
Accessories Inspection." Rev.13; 34SV-R43-006-25. " Diesel Generator 2C
Semi-Annual Test." Rev. 14. ED 1: and 34SV-R43-002-25. " Diesel Generator
-
1B Monthly Test." Rev. 17. The inspectors reviewed the Unit 2 TS section
~ 3.8.1. AC Sources - Dperating, and verified that required actions were .
'
completed.
b. Ob_servations and Findinas
l
During a monthly operability surveillance on January 20. tha 2C EDG
L failed to start. This was the third EDG start failure since September
1997 and the second start failure for the 2C EDG. Previous EDG start
failures are discussed in Section E2.2 of Inspection Report 50-321.
366/97-11.
During trouble shooting and a subsequent EDG run maintenance personnel
observed that the fuel racks opened and then immediately closed. Further
trouble shooting led maintenance to suspect the governor to be the
problem. Some logic circuit wiring connectors were observed to be
cracked however a megger did nnt indicate that the wiring contributed to
'the problem. The wiring was repaired. the governor was re) laced. and
post-maintenance runs were com)leted to setup and adjust t1e governor.
The inspectors were informed tlat the governor will be sent to a vendor
for failure analysis. Nuclear Safety and Compliance (NSAC) personnel
Enclosure 2
l
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f
10
completed the recuired TS common cause failure determination and
- initially concluced that the other EDGs were not affected by the failure
and issued documentation for the conclusion. However, following further
,
trouble shooting. NSAC rescinded the initial common cause failure letter
'
and informed operations personnel that the other EDGs may be affected by
the failure. Operations personnel then performed the TS-required
operability surveillances for the remaining EDGs. No problems were
identi fied. l
The inspectors observed part of the maintenance trouble shooting and l
repair activities. Procedures were used and supervisory oversight and
-engineering support were observed. The inspectors observed part of the
TS-required operability test of the remaining EDGs. The test acceptance
l criteria were met. The licensee increased the monitoring frequency by
running the EDG weekly as part of the corrective actions taken.
c. Conclusions
The inspectors concluded that maintenance and engineering 3rovided
excellent support for the trouble shooting and repair of t1e 2C EDG
following a failure to start. Procedures were used, supervisory
oversight was evident and all TS requirements were met. l
M3 Maintenance Procedures and Documentation
M3.1 Surveillance Observations (61726)
Insoection Scooe and Conclusions
The inspectors observed all or portions of six Unit ? and Unit 2
surveillance activities which included the following:
57SV-L51-003-05: Seismic Instrumentation FT & C. Rev. 4. Ed 1
+ 34SV-E41-002-2S: HPCI Pump Operability. Rev. 26
34SV-C71-002-IS: RPS Channel Test Switch Functional Test Rev. 5
For the surveillances observed, with noted exceptions, all data met the
required acceptance criteria and the equipment performed satisfactorily.
The performance of the operators and crews conducting the surveillances
was generally professional and competent.
M3.2 Unit 2 Hiah Pressure Coolant In.iection (HPCI) TemuorarilY Inocerable
Followina Surveillance
l a. Insoection Scooe (62707)(71707)
The ins ectors reviewed procedure 34SV-E41-002-2S. "HPCI Pump
Operabi ity". Rev. 26. and observed operators perform sections of the
surveillance procedure. The inspectors attended the pre-test briefing
and discussed observations with operatius management.
Enclosure 2
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b. Observations and Findinos
- On January 27, the inspectors attended the pre-test briefing conducted
prior to the HPCI surveillance. The briefing was conducted by operations
personnel with maintenance engineering, health physics, and a member of
operations management in attendance. A Unit 1 supervisor was present and
conducted an " Observation For Excellence" checklist, routinely completed
to provide feedback to personnel for areas of improvement to ensure that
management's expectations are met. The inspectors observed some aspects
of the briefing that did not meet management's ex)ectations which were
not identified by the Unit 1 supervisor. These oaservations were
discussed with operations' supervision and management personnel.
About 20 minutes into the HPCI surveillance, the inspectors observed that
the " Torus Level High" alarm actuated several times. The alarm did not
seal in but flashed as if it had initiated then immediately reset.
Operators responded to the alarm used the alarm procedures, and
monitored the torus level indication in the control room. The indicated
torus level was below the level required to actuate the alarm. Shortly
thereafter, the "HPCI Pum) Discharge Flow Low" alarm actuated and the
operators observed that t1e HPCI suction swapped from the condensate
storage tank to the torus. This action is normal for a high torus level l
or low condensate storage tank level, The operators secured the HPCI 1
system and contacted maintenance to initiate trouble shooting activities
to determine why the suction swap occurred. The HPCI system ccntroller
was left in manual while the cperator described the issue to shift
supervision and maintenance perscnnel. Later, at the direction of the
superintendent of Shift (S05), the centroller was placed back in l
automatic. The licensee issued a 10 CFR 50.72 notification for the HPCI
being inoperable for the time the controller was left in manual.
Maintenance personnel calibrated the level instruments and found that one
channel had drifted slightly. However, the instrument was not i
sufficiently out of tolerance to have caused the suction valve to swap. '
0)erations, maintenance, and engineering did not specifically determine
t1e reason for the swap, but suspected contributing factors to be the
turbulence caused by exhausting steam and operating in the torus cooling
mode, differential pressure changes on the level transmitters caused by
the turbulence and, the sensitivity of the level transmitters.
1
On January 29 the inspectors observed operators complete the HPCI
surveillance test. All TS surveillance requirements were met and no
deficiencies were observed.
4
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c. Conclusions
.
The inspectors concluded that some aspects of the pre-test briefing did
not meet management's expectations. An improvement was observed in
f operator three-part communications. Supervisory oversight was evident.
J Enclosure 2
I
[ 12
The 10 CFR 50.72 notification for the inoperable HPCI system was
appropriate. Surveillance test requirements were met.
M3.3 Review of Reactor Protection System (RPS) Channel Test Switch Weekly
l Testina Reauirements
a. Insoection Scooe (61726) (71707)
l The licensee determined on December 30 that procedure 34SV-C71-002-1S had l
not been performed since the Unit 1 startup from the 1997 fall refueling
'
l
outage (November 21, 1997). The procedure is required to be performed '
weekly.
As a result, the inspectors reviewed Administrative Control Procedure
90AC-0AP-001-OS. " Test and Surveillance Control," Rev. 2: Surveillance
Procedure 34SV-C71-002-15, "RPS Channel Test Switch Functional Test "
Rev. 5: Technical Requirement Manual (TRM) Loss of Function Diagrams !
(LFDs) 1-RPS-17 and 2-RPS-17. RPS Instrumentation Manual Scram for Unit I
and 2 respectively; and Technical Specification (TS) 3.3.1.1 RPS
Instrumentation for Units 1 ano 2. In addition, the 10 CFR 50.59
evaluation for a requested change of procedure 34SV-C71-002-1S was
reviewed and discussions were held with Operations and Engineering
personnel. <
b. Observations and Findinos
The LFD for Unit 1 indicates that the Manual Scram RPS logic is actuated
by the K15 relays and associated contactors. The automatic scram relays '
(K14) and associated contactors are not actuated during an actuation of
the manual scram pushbuttons on Unit 1. The LFD for Unit 2 indicates
that both the manual and automatic relays and associated contactors are
actuated during an actuation of the manual scram pushbuttons.
Surveillance Requirement 3.3.1.1.5 for both Units 1 and 2 requires that
the manual scram logic be tested weekly. The inspectors verified that
the TS-required manual scram surveillance arocedure (34SV-C71-004-1S/2S)
..fr each respective unit was performed weedy. Performance of the
procedure for Unit 2 tests both the K14 and K15 relays and associated
contactors. However, performance of the Unit 1 procedure only tests the
K15 relays and associated contactors.
The licensee had committed to testing of the K14 relays on a weekly basis i
as one of the requirements of Topical Report NEDC-30851P-A, " Technical
Specification Improvement Analysis for BWR Reactor Protection System," as
part of the new improved TS submittal. For compliance with the
requirement of this commitment. Rev. 5 of procedure 34SV-C71-002-15 was
implemented on November 17. 1997.
l Prior to implementation of the Power Range Neutron Monitoring (PRNM)
'
System on Unit I during the 1997 Fall Refueling Outage, the licensee took
l Enclosure 2
l
13
credit for t ! sting of the K14 relays and contactors during the weekly
I APRM down scale surveillance. This surveillance was eliminated after
l implementation of the new PRNM system.
l
Licensee personnel responsible for the change of procedure 34SV-C71-002- i
1S did not submit the appropriate forms for updating the procedural
testing / surveillance' data base as required by procedure 90AC-0AP-001-05,
section 8.1. Test Control. There was no surveillance task sheet 2
f available to prompt performance of the test procedure. This failure to !
, update the Surveillance Program Data Base for the performance of
l procedure 34SV-C71-002-15 constitutes a violation of minor safety
! significance and is identified as Non-Cited Violation (NCV)
- 50-321/97-12-03. Failure to Follow Procedure for Scheduling Weekly ;
Testing of.RPS Scram Test Switches, in accordance with NUREG 1600.
The data base was subsequently updated with the first scheduled RPS Scram
Test Switch testing frequency beginning on January 16.
- c. Conclusions
,
Due to a lack of attention to detail, a procedural change form was not
'
submitted for a procedural frequency change. This resulted in a failure
l to perform weekly twS channel test switch functional tests. A Non-Cited
Violation was identified for this problem.
l III. Enaineerina
l
El Conduct of Engineering
l On-site engineering activities were reviewed to determine their
l effectiveness in preventing, identifying. and resolving safety issues,
i events, and problems. In general, engineering support to operations,
maintenance, and plant support was excellent.
E2 Engineering Support of Facilities and Equipment
E2.1 Review of ootential 10 CFR 21. ReDortina of Defects and Noncomoliance.
l a. Insoection Scooe (37551)(92903.).
!
l The inspectors reviewed a 30-day report for a potential 10 CFR 21 defect
L identified at another facility. The potential defect was associated with
a potential failure of General Electric Type CR120 AD relays. The
inspectors reviewed and assessed the licensee's evaluation for
applicability at the Hatch facility in accordance with Regulatory
l
Compliance procedure 03RC-CPL-002-0S " Defects and Noncompliance."
Rev. 1.
Enclosure 2
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b. Observations and findinos
A potential 10 CFR 21 report identified at another facility indicated
that the potential failure of certain CR120 AD relays with specified date
codes was due to a manufacturing defect. Engineering personnel evaluated
this problem for applicability at Hatch in accordance with procedure
03RC-CPL-002-0S and found two safety-related replacement relays in the
warehouse that had not been installed. These relays have been placed on
hold pending replacement or testing instructions from General Electric.
None of the affected relays were identified as having been installed in
the piant.
c. Conclusions
The inspectors concluded that the licensee had taken the appropriate
action in addressing the potential 10 CFR 21 issue.
E2.2 Bgview of Unit 1 and Unit 2 Valves Not Included In The Inservice Testina
iTST) Procram
a. Insoection Scooe (37551)
On January 30, the inspectors were informed that corporate engineering
had identified twelve valves associated with the Plant Service Water
.
'
(PSW) makeup tn the Unit 1 and Unit 2 Spent Fuel Pools (SFP) which had .
not been incitmed in the IST program.
The inspectors reviewed Unit 1 and Unit 2 TS section 5.5 and deficiency
card (DC)98-382, and discussed the proposed corrective actions for the ,
valves that were not included in the IST 3rogram. The inspectors !
reviewed Unit 1 UFSAR section 10.4. Fuel 2001 Cooling and Cleanup, and
Unit 2 UFSAR section 9.1. Fuel Stora r? and Handling.
b. Observations and Findinas
The inspectors reviewed DC 98-382 which documented the problem and
observed that the following valves were listed on the DC:
Manual valves that should be in the IST program for quarterly exercising:
l
) Enclosure 2
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Power Operatad Valves that should be in the IST program for remote
indication verification every two years:
L 2G41-F054.
l ' Check valves that should be in the IST program for quarterly exercising
i
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to the open position required to fulfill their design function:
IG41-F055
Unit 1 and Unit 2 TS 5.5, Programs and Manuals, section 5.5.6, require an
,
~
. Inservice Testing Program. Implicit in this requirement is that all
valves and components that are required to be tested under the program be
L
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included. American Society of Mechanical Engineers (ASME) Operations and
Maintenanca (C&M) code requires that active and passive valves which
_ mitigate the consequences of an accident be included in the IST 3rogram.
Plant Service Water is a safety-related seismic Class I system w1ich
provides makeup water to-the SFP.
,
i Nuclear Safety and Compliance (NSAC) personnel made an initial
j determination to prepare a 10 CFR 73 license event report (LER) based
l upon information in the DC. The determination to prepare the LER was
l based upon operations or conditions prohibited by plant TS. Operations
personnel also entered the appropriate required actions of the TSs.
l NSAC personnel informed the inspectors that additional reviews in
conjunction with the LER preparation will be performed to determine-
'
. whether the valves of concern should be placed in the IST program. The.
j results of this review will be documented in a Significant Occurrence
' Report. This issue was identified as inspector followup item (IFI)
50-321. 366/97-12-04, Review of IST Basis for PSW Makeup Valves to Spent
l Fuel Pool .
c. Conclusions
l Corporate engineering did a good job in identifying that various valves
were not included in the inservice test (IST) program. The licensee is
continuing the review of this informdtion to determine if these valves
should have been in the IST program. An IFI was opened to review this
issue upon completion of the licensee's action.
E2.3 Enaineerina Walkdown of Systems and Comoonents
,
! ' a. Insoection Scooe (37551)
The inspectors reviewed deficiencies. MW0s, and engineering evaluations
associated with deficiencies identified during a licensee walkdown of the
Standby Liquid Control (SBLC) and Plant Service Vater Systems. The
inspectors discussed the problems with engineering and management
j
Enclosure 2
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personnel, verified that corrective actions were completed, and assessed
system operability.
l
b. Qb.servations fpd Findinas
On December 29 the inspectors were informed by licensee management that !
some bolts on the mounting flanges of the SBLC system test tanks (legs I
from the tank to the floor) were missing. The test tanks are for testing '
l. )urposes and are not' required for the system design function. Each tank
'
las three legs and each leg was designed to have four a m hor bolts
i embedded into the concrete as shown on plant drawing S1'352. For Unit 1.
l two legs had the required bolts and the third leg contened no bolts.
l For Unit 2. each leg had only two bolts. The licensee believed that this
i condition existed since initial construction. Corporate engineering was
not able to locate any engineering evaluation or assessment for the
existirig condition and performed the required seismic analysis. Site
!- personnel replaced all of the missing bolts. except for one bolt on each
l- unit, due to a physical ,bstruction which prevented their installation.
! .The inspectors reviewed the work Jackage, observed part of the ongoing
!
work activity and verified that t1e corrective actions were completed in
l a timely manner. The inspectors reviewed the preliminary safety
evaluation (the final evaluation was still being developed) which stated
l
that the currently installed anchor bolts and bolt configuration was not
a seismic concern and would not compromise the ability of the SBLC system j
to perform its safety function.
_
On February 5. during a walkdown of the standoy plant service water
l (SPSW) system engineering personnel identified that a small section
'
(about 18-20 inches) of plant service water piping on the supply to
Emergency Diesel-Generator (EDG) 1B had no missile protection. The
licensee believed that this condition had existed since initial
l construction. Operations declared the EDG inoperable and entered the !
l required TS action statement. A temporary concrete barrier was
! . positioned to provide the required protection. Engineering was to !
l develop a work plan to construct a permanent missile barrier. l
l
l The inspectors reviewed the reported deficiency. discussed the problem l
L with management personnel and observed that the temporary barrier would
l provide protection from a horizontal missile. ;
i
c. Conclusions j
,
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The inspectors concluded that engineering personnel demonstrated ;
excellent observations for problem identification on the Standby Liquid !
Control and Standby Plant Service Water systems. Corrective actions were
timely: site maintenance and engineering and corporate engineering
support was~ excellent.
Enclosure 2
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E2.4 Removal of Traversina Incore Probe (TIP) Nitrogen Purae Valve from
_1stina of Primary Containment Isolation Valves
a. Jnsoection Scoce (37551) (92903)
' The inspectors reviewed surveillance procedure. 34SV-C51-005-05. " Stroke
Time Testing of NUMAC TIP Ball Valves Rev. 4. Significant Occurrence
Report (SOR) C0 97-3808 and held discussions with licensee personnel.
Additional documentation reviewed by the inspectors included. TSs
applicable to primary containment isolation valves (PCIVs), applicable
l sections of the Technical Requirement Manual (TRM), the UFSAR. Licensing
i
Document Change Request (LDCR) 98-02 and Southern Company Drawing H-
28993. Neutron Monitoring System, sheet 2 of 2. The documentation review
and discussions were associated with the listing of the TIP Nitrogen (N2) l
Purge Solenoid Valve (2C51-F3012) as a PCIV in the UFSAR and the TRM.
f
b. Observations and Findinas
- The inspectors reviewed data packages associated with the performance of
l procedure 34SV-C51-005-0S and noted that the TIP Purge Solenoid valve
l 2C51.F3012 failed to remain closed following the perforriance of the
procedure on August 11, 1997. A deficiency card was written and the j
appropriate required action statement (RAS) of TS 3.6.1.3 Primary /
Containment Isolation Valves, was entered.
The licensee initiated a root cause review of the valve )roblem that was
l documented in SOR C0 97-3808. The inspectors reviewed t1e SOR and s
! Drawing H-28993 and noted that the TIP N 2 Purge Solenoid Valve is located
in the N 2S.upply line to the TIP indexing mechanism. The TIP indexing
mechanism 1s located inside the drywell. A N2 purge blanket is used to
minimize corrosion of the indexing mechanism. The valve is normally
I opened tc provide the N 2purge and closes on a Group 11 containment
,
isolation signal.
i
The inspectors were informed by licensee personnel that the force l
'
associated with the N 2 pressure in the line to the drywell is greater i
than the spring tension for the closing of the valve. The flow of the N 2 i
,
is o)posite to that of accident flow from the drywell. The pressure in i
l the 12 header to the valve is greater than the analyzed drywell pressure ;
'
following a Loss of Coolant Accident (LOCA). Check valve 2C51-T3017 l
located in the TIP room. is also in the penetration flow path downstream l
of the TIP Purge Valve in the direction of N2 flow. The check valve i
prevents flow in the accident direction from the drywell. The licensee
concluded that the pressure of the 2N in the line provided an isolation l
boundary to the drywell in the event that the valve failed to remain
closed due to the N 2pressure following a LOCA. Unit I does not have ,
this problem because a pressure regulator is installed in the flowpath of '
the N2 line prior to the N Purge
2
Valve (1C51-3012).
Enclosure 2
.
!
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The inspectors reviewed an approved LCDR which removed the TIP Purge
Solenoid Valve from the TRM and UFSAR listing for PCIVs for Units 1 and
Unit 2. including a Request for Engineering Assistance (REA HT-97615) and
the 10 CFR 50.59 evaluation. This information supported the removal of
the TIP Purge Solenoid Valves from the TRM and UFSAR listing of PCIVs for
Units 1 and 2.
!
'
c. Conclusions
I
The SOR associated with the review of the TIP nitrogen purge valve issue
l
was good. The determination that the valve could be removed from the
PCIV list in the FSAR and the TRM was appropriate.
E2.5 Valve Testina and Drawina Review of Containment Atmosobere Dilution (Ghp_1
System
,
]
a. Insoection Scooe (37551)
,
The inspectors reviewed selected components of the Nitrogen Inerting
System for Units 1 and 2. The activity included a review of plant
,
drawings H-16000 for Unit 1 and H-26083 for Unit 2. The inspectors
conducted a system and component performance history review and walked
down parts of the system,
b. Observations and Findinas ,
I
l The inspectors selected a sampling of Relief Valves (RVs) and Pressure
Control Valves (PCVs) and reviewed documentation associated with the CAD
system. This valve sampling and document review was done to determine
the testing frequency and the results of the testing. The inspectors
observed that of 16 valves selected on Unit 1. five valves were
identified as being on a 60-month testing frequency. There was no
history of testing for the remaining 11 valves and there was no task
l identified to perform testing. The testing of the five referenced valves
was required due to valve failure or replacement. None of the valves was i
tested as part of a routine testing or preventive maintenance effort. j
For Unit 2.12 valves were selected for review. Two valves were tested l
l due to repair or replacement following valve failure. One valve was I
identified as being on a 54-month test frequency. However, testing
records were not located for the remaining nine. Also, there was no task
identified to perform testing or preventive maintenance of the valves.
The inspectors discussed these observations with maintenance and 1
engineering aersonnel. The inspectors were informed that the RVs and '
PCVs for bot 1 units were not ) art of the routine testing program. There ;
were no records to indicate tlat some of the v61ves were ever tested and
others were only tested following repair or replacement. 10 CFR 50.
Appendix B. Criterion XI. Test Control, requires, in part, that all 1
testing required to demonstrate that components will perform ;
satisfactorily in service is identified and performed in accordance with i
written test procedures which incorporate the requirements and acceptance
Enclosure 2
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i limits contained in applicable design documents. The failure to
incorporate these com
50-321. '366/97-12-05.ponents
Failure tointo a testNitrogen
Include programValves
is identified as VIO
in a Test.
,
Program.
l
The ins)ectors walked down parts of the system on both units using
!
applica)le unit drawings. During the walkdown on Unit 1 and Unit 2 the
inspectors observed that a significant amount of ice had accumulated on
piping and some valves located at the nitrogen storage tanks. The manual
isolation valve for the Unit 1 tank was iced over. The inspectors
informed management. personnel of this observation and questioned if the
ice problem may be a seismic concern. The inspectors were later informed
that a deficiency card had been initiated and corporate engineering was
reviewing the problem for seismic concerns. The inspectors later
observed that the licensee had placed light- heaters in the tank
enclosures to thaw the valve.
l The inspectors' observed that all four of the safety relief valves on-
!
piping associated with the Unit 1 nitrogen storage tank were leaking
slightly. This observation was discussed with licensee management and
engineering personnel. Some engineers associated with the nitrogen
L system were aware of the leaking valves'. The inspectors'were informed
!
that the valves had been leaking for some time. The ins
- view this as an immediate operability concern. However,pectors did not
it demonstrated
'
- a lack of attention to material conditions of the system. The inspectors
did not identify that any deficiency cards had been initiated for the-
leaking safety relief valves. The inspectors observed that PC F469 on
]
- _
Unit 2 had a small leak near the bottom of the valve. This leak had not
[ been identified previously by the licensee.
l Note 11 on plant drawing H-16000 for Unit 1 indicated that some piping )
from the nitrogen storage tank toward the steam vaporizer should have
been insulated. The inspectors observed that much of the piping was not
, insulated. Note 10 on plant drawing H-26083 for Unit 2 indicated that 1
l the piping from the nitrogen storage to the steam vapon zer should be !
L insulated. The inspectors observed about 4 feet of insulation on )iping
i and one PCV was insulated at the front of the nitrogen storage tant.
Other piping at The storage tank area was not insulated as indicated on
plant drawings. The inspectors observed that the vendor manuals also
recommended that the piping be insulated.
l
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,
This failure to insulate piping as required by the design drawings was
identified as VIO 50-321, 366/97-12-06. Insulation on Nitrogen Supply
Piping Not Installed in Accordance with Drawings.
Following the inspectors' identification of the above problems, the
inspectors were informed that licensee management had initiated an Event
Review Team to review the system and previously identified problems.
Other problems identified with this system are also discussed in Section !
02.2 of this report.
Enclosure 2
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L c. Conclusion
.The licensee.has exhibited a lack of attention to the material condition
! of these systems. DCs have not been generated to identify and correct
L w problems and routine maintenance and testing has not been performed. Two
l violations were identified.during this review: one for a failure to
l include nitrogen valves in a test program and one for a failure to meet
h
s
design drawing requirements.
.
E3 Etx.jineering Procedures and Documentation
Paragraphs E3.1 through E3.12 provide the results of a team inspection of
L various. fuel performance and managemerit issues. This inspection was
!
conducted at the Southern Nuclear Operating Company (SNC) corporate
offices the week of December 15, 1997.
,
E3.1 Core Thermdl Heat Balance
p a. Insoection Scoog (37550)
Due to recent fuel vendor notifications of discrepancies in the core
thermal heat balance calculation, the inspectors reviewed bounding
i calculations for discrepancies, root cause analysis, and corrective
, actions.
'
b. Findinas and Observations
i
In December,1995. General Electric (GE) notified the licensee that
! " unconsidered control. rod drive (CRD) bypass flow may result in
- nonconservative heat balance calculations. In response,'the licensee
L opened SOR C09505439 to evaluate the CRD: bypass flow issue and other
L potential discrepancies in the heat balance calculation. The analysis
i showed that, while Plant Hatch was not susceptible to the CRD bypass-
l issue. ~other potential sources of error existed in the heat balance
l calculation. A root cause analysis showed that the impact of parameters
l not previously considered in the heat balance calculation was about.
l' O.6025 MW thermal. The licensee has added this value to the value for
- - radiative heat losses in the heat balance calculation methodology.
M c. Conclusions
The inspectors concluded that the licensee *s re-evaluation of heat i
l
bal$nce calculation inputs contained in SOR C09505439 was a proactive
- measure to minimize future discrepancies.
!
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Enclosure 2
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l
L E3.2 BWR Peak Clad Temoerature
i
a. Insoection Scoce'(37550)
The inspectors reviewed the licensee's peak clad temperature (PCT)
reporting due_to recent discrepancies in the fuel vendor's PCT analysis-
methodology. ,
.
b. Findinas and Observations
l-
l , As reguired by 10 CFR 50.46(a)(3)(I), by letter dated January 13, 1997
the licensee informed the NRC that the sum of the changes and errors was
-
l
- -approximately 215 F. The licensee also stated that the 1986 SAFER /GESTR
'
ECCS evaluation resulted in approximately 675 F of margin to the 2200*F
limit. The inspectors observed that the SNC Nuclear-Fuels Department
maintained a proceduralized process for complying with 10 CFR 50.46
reporting requirements for PWR nuclear units. However, no similar
2roceduralized process existed for BWR nuclear units. Because individual
3WR licensees were submitting the yearly report, the lack of procedures-
l for . tracking PCT changes at BWRs was an area for improvement.
k c. Conclusion
i i '+
n Although the licensee had not been susceptible to recent reports of
!
inaccuracies in PCT. the inspectors noted that PCT changes for BWPs were
not proceduralized and tracked in a manner similar to PWRs.
I
E3.3 Review of Nuclear Fuel Performance
!
a. Jnsoection Scooe (37550)
! The inspectors reviewed fuel performance over the last four to six cycles
! of operation for both Units 1 and 2 and evaluated licensee efforts to 1)
l~ identify the root cause of fuel failures, 2) prevent future failures, and
l 3) mitigate effects when failures occur during operation.
b. Observai..ons and Findinas
Since fuel assembly failures occurred in both units in early cycles of
I operation due to crud-induced-localized corrosion (CILC), the licensee
l' became very aggressive in analyzing and preventing fuel assembly
l failures At the time of the inspection. Unit 1 was in Cycle 18 and
Unit 2 was in Cycle 14. The most recent fuel failures in Unit 1 occurred
'
i'
i- during Cycle 12, one fuel assembly failure due to debris, and two fuel
I assembly failures during Cycle 16 for unknown causes. Unit 2 had two
fuel assembly failures during Cycle 10 and three fuel assembly failures
f during Cycle 11. all due to debris. Following the Unit 2 fuel assembly
failures, the licensee shut down Unit 2 during Cycle 11 to remove one !
failed fuel assembly and perform an examination of all fuel assemblies to
look for and remove debris. The debris found during the examination
Enclosure 2
22
consisted of small steel turnings. All failed fuel assemblies were
removed from the core as were other fuel assemblies with evidence of
debris fretting. The licensee had inspected the failed fuel assemblies
from both units to determine the root cause of each failure and to
propose corrective actions.
The licensee had proactive fuel assembly failure prevention programs to
exclude debris and evaluate effectiveness of GE debris filter design in
lead use assemblies. The licensee also had a program to mitigate fuel
assembly failure degradation. Typical strategies used to mitigate
degradation were:
e shorten length of time for partial control rod insertion during
startup
e improveSfuelleakerdetectionfailedfueloperatingguidelines.
' e degradation resistant fuel design frequent interface with
industry, and
e vendors to learn new techniques.
c. Conclusions
The licensee maintains aggressive programs to eliminate and mitigate
effects of failures. The licensee also actively participated in industry
programs to prevent and mitigate failures.
E3.4 Lead Use Assemblies and Introduction of GE-13 Desian Fuel Assemblies
a. Insoection Scooe (37550)
The inspectors reviewed the licensee use of Lead Use Assemblies-(LUAs) to
evaluate new fuel designs. The inspectors also evaluated licensee
interface and interaction with the fuel vendor prior to introduction of
GE-13 design fuel assemblies into Unit 1 Cycle 18 and Unit 2 Cycle 14.
g b. Observations and Findinas
l
The licensee does not introduce fuel design changes into its cores
without the following information and testing results.
LUAs testea in their own core, with data from at least two cycles of
operation vendor requirement to inform them of all design changes
(including minor ones) between the LUAs and the actual design to be used
for reloads demonstrated satisfactory performance of full reloads of new
design at other licensee plants.
>
The licensee monitored three cycles of operation of GE-13 LUAs in Unit 1
before loading a full reload. SNC performed several audits of the vendor
during design fabrication and reload licensing analyses prior to -
introducing the GE-13 design. The vendor audits by SNC were of
sufficient depth and breadth with good findings and followu SNC also
used check lists for design changes in areas of 1) nuclear.p.2)
Enclosure 2
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23
mechanical 3) core compatibility (mixed core issues), 4) core design,
5) o)erating strategy 6) analysis methods and analyses performance,
7) tiermal limits 8) technical specification changes, and 9) fuel
r
'
reliability. They also conducted formal reviews.of reload design and
licensing from the preliminary to the final design phase and prior to
submittal of Reload Safety Evaluation and Core Operating Limit reports. i
and reload licensing calculations and documentation.
,
l
c. Conclusions
l .,
r
l The licensee had a very conservative philosophy toward introducing new
fuel designs into their cores. It waited until another. utility has i
already proven the design with a full reload, with satisfactory
performance, plus LUA use in its own cores with sufficient data to i
. substantiate performance. )
l
The licensee performed a thorough review of vendor design and analyses
information prior to the change to the GE-13 fuei design.
L
l E3.5 Review of Asymmetric Ooeration j
i
f a. Insoection Scoce (37550)
The inspectors reviewed the licensees evaluation of asymmetric power
operation during Unit 2 Cycle 11.
b. Observations and Findinas
During Unit 2 Cycle ll, a failed fuel assembly required the insertion of
l adjacent control rods to prevent further deterioration of the failed fuel
l assembly. The insertion of these control rods resulted in asymmetric
L
power operation for the remainder of Cycle 11. The inspectors reviewed
the licensee's technical evaluation dated April 28, 1993, that confirmed
the acceptability of continued operation with the adjacent control rods
inserted. In addition, the licensee provided copies of Section 3.4.2.8.
Symmetry, of GESTAR II [NEDE-24011-P-A-13), and NED0-20340-1. which
justified asymmetric power operation. A review of GESTAR II indicated
that the safety limit MCPR calculated by GE procedures was applicable for
both symmetric and asymmetric power operation. The inspectors reviewed
3D MONICORE P1 outputs for Unit 2 Cycle 11, before and after asymmetry
power operation was established. The location of the ten most limiting
fuel bundles did not change following the insertion of the adjacent
control rods and the MCPR values did not change significantly for the
asymmetric power condition.
A primary concern stated in the technical evaluation wat increased flow
through the failed fuel assembly due to depressing power around the
failed fuel assembly. Calculations indicated that the flow increase
would exceed the flow range of applicability for the GEXc correlation.
The licensee also evaluated this condition and concluded that the
Enclosure 2
l
>
24
increased flow was acceptable and that the high-flow warnings generated )
by either'3D MONICORE or PANACEA simulations could be ignored. )
'
The inspectors also reviewed cycle-specific calculations for Cycle 11. 1
The inspectors identified that the only analysis affected by the !
asymmetric power operation was the Rod Withdrawal Error (RWE)
calculation. The licensee.had reanalyzed the RWE calculation using the )
asymmetric power operation conditions and demonstrated that the new RWE
analysis was bounded by existing limits. The licensee also evaluated the
effect on Cycle 12 core design due to asymmetric operation during
Cycle 11. The licensee concluded that Cycle 12 could be designed without i
adverse consequences. I
c. Conclusions
The evaluation of the asymmetric operation caused by a leaking fuel pin
during Cycle 11 was thorough and complete. The licensee properly
identified and resolved all major technical issues, including the impact
of increased bundle flow and the effect of asymmetric power operation on
Cycle 12 core design.
E3.6 3D MONICORE Ouality Assurance Procedures
a. Insoection Scooe (37550)
l
'
.The inspectors reviewed the licensee's procedures used to' verify the
integrity of the Beginning of Cycle (BOC) data for 3D MONICORE.
b. Observations and Findinas
The inspectors reviewed the licensee's BWR Core Analysis Procedure.
BCA 50-100. 3D MONICORE BOC Wrapup Checkout, which documents the steps
taken by SNC to verify proper implementation of the BOC data for 3D
MONICORE. The procedure states that the responsibility for the integrity
of the BOC data belongs to the preparing organization (typically the fuel
vendor) and that the steps in procedure BCA-50-100 provided only
incremental quality assurance. The ins)ectors reviewed the design record
file for Unit 1 Cycle 18 and verified tlat the procedure was followed.
An interview with the licensee indicated that the licensee performed )
procedure BCA-50-100 for all cycles since the procedure was issued. The
licensee stated that normally the SNC BWR Core Analysis Group receives an
advanced copy of the final 3D MONICORE data which provided additional
time for the checkout process. However, in case of a delay in receiving
the final 3D MONICORE data from the vendor, the unit can proceed with an
initial approach to critical. SNC engineering would still have
sufficient time to verify the data because 3D MONICORE was not placed in
operation until about 25% rated thermal power.
Enclosure 2
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i 1
25
The licensee stated that it routinely finds problems with the 30 MONICORE
data provided by the vendor. Most of these )roblems were related to
limit settings..where different options may )e selected by the user.
-
When errors were found, the differences were resolved with the vendor. '
l The licensee was interviewed regarding the applicability of 3D MONICORE
l methods to model 3 art-length rods and other features of advanced fuels
l such as GE-13. T1e licensee provided a copy of a GE letter MFN 059-89.
L JSC-8985. Application of Approved Methods to a New GE Fuel Design, dated
August 7. 1989. This letter discussed the application of NRC-approved
metnods to the GE-13 fuel design,
c. Conclusions
The inspectors found that the procedure for quality assurance of 3D
MONICORE data were technically adequate. A review of the documentation
for Unit 1 Cycle 18 indicated that the procedure had been followed.
E3.7 Doeratino Limit Uncertainty
]
a. .Igspection Scone (37550)
The inspectors reviewed the cycle-dependent Safety Limit Minimum Critical- 1
Power Ratio (SLMCPR) evaluations for both Unit 1 and Unit 2. I
b. Observations and Findinas
The cycle-dependent SLMCPR evaluations resulted in different limiting
values for both units even though the operating strategy and fuel loading
patterns were similar. Unit 2 Cycle 13 had a SLMCPR value of 1.08 )
whereas Unit 1 Cycle 17 had a SLMCPR value of 1.06. The licensee stated
that they were aware of these differences and had questioned the vendor -
about them. The differences were finally attributed to a flatter power
distribution in Unit 2. The 0.02 safety limit difference between the two i
units remained for Cycles 14 and 18 even though the SLMCPR values
increased to 1.12 and 1.10, respectively, because of the fresh GE-13
design fuel loaded in those cycles.
)
l
To investigate the above SLMCPR differences, the licensee used the TRACG l
code to determine if more-advanced best-estimate methods could be used to
determine the Operating Limit Minimum Critical Power Ratio (OLMCPR) more
accurately. Following established licensing procedures, the OLMCPR was
calculated by the addition of two components; the SLMCPR and the ACPR
which was estimated from the limiting transient calculation. The
licensee evaluated whether the OLMCPR could be calculated directly from a
statistical evaluation of a number of TRACG results. The inspectors
reviewed the results of this study which indicated that establishing a
OLMCPR directly from a number of statistical TRACG calculations was
feasible. Following this procedure the OLMCPR for Unit 2 could be
reduced by as much as 0.03 for Cycle 14. The licensed ODYN/TASC
Enclosure 2
26
methodology yields an OLMCPR value of 1.35 whereas this valu can be
reduced to 1.32 if the TRACG statistical analysis were usec'
,
During review of the licensee's results, the inspectors noted that the I
uncertainty in the calculated ACPR ranged from 0.04 to 0.07. Thu
licensed ODYN/TASC methodology applies a fixed uncertainty of 0.01 to the ) ,
calculated ACPR which is significantly lower. Tne inspectors informed-
the licensee that this large discrepancy in uncertainties could
potentially result in a 0.06 penalty in OLMCPR. The inspectors were also
concerned with the lack of licensee or vendor follow up on this issue.
c. Conclusions
The inspectors considered the licensee *s actions to identify the observed i
differences in safety limit between essentially identical plant designs i
to be proactive. However, the inspectors were cor.cerned with the large
non-conservative difference between the OLMCPR uncertainty used in the
licensed ODYN/TASC methodology.and the uncertainty using the TRACG ,
methodology. Also, the inspectors considered the lack of licensee
followup with the vendor and/or NRC on this potential safety issue as an
area that could be improved.
E3.8 SNC Resoonse to Cycle-Decendent Safety limit MCPR Issue
a. Insoection Sroce (92903)
The inspectors reviewed the licensee's response to 10 CFR 21 nottfication
to potentially non-conservative SLMCPR calculations
b Observations and Findinos
By letter dated April 3, 1995. GE informed the NRC that GE intended to
replace the current SLMCPR generic analysis with a cycle-specific
analysis. As a result GE determined that the St.MCPR calculated using
the generic analysis could be non-conservative when applied to certain
actual core and fuel designs. As a result of this potential
non-conservative condition, the licensee imposed a temporary penalty of
0.03 in the SLMCPR for both Units 1 and 2. This penalty was reduced to
0.02 for Unit 2 and no penalty for Unit 1 once the cycle-dependent safety
limit calculation was . verified.
The inspectors reviewed several licensee documents related to the cycle-
dependent SLMCPR evaluation by the licensee. These documents contained
all correspondence between the licensee and GE. as well as internal
documents and communications, and topical reports. The inspectors
concluded that this issue was thoroughly documented by SNC and that the
licensee was knowledgeable of the subject and took conservative
, corrective actions. However, the inspectors were unable to determine if
the licensee could or should have anticipated these errors before the
vendor discovery. The ist.ue is identified as URI 50-321, 366/97-12-11.
Enclosure 2
27
Timeliness of Identi'fication of SLMCPR Errors, pending additional review
by the NRC staff,
c. Conclusions
Based on discussions with licensee personnel and review of the
documentation the inspectors found that the licensee's followup of the
cycle-dependent SLMCPR issue was adequate. The licensee was
knowledgeable about the subject and took conservative actions to correct
possible safety deficiencies.
E3.9 Imolementation of Lona Term Stability Solution 00 tion III
a. Inspection Scooe (37550)
The inspectors discussed with licensee personnel the status of the
implementation of Long Term Stability Solution Option III. As part of
this discussion, the licensee provided a number of documents related to
the Option III implenentation.
b. Observations and Findinas
As a result of Generic Letter 94-02, the licensee committed to implement
BWROG Option III as a long-term solution to detect and su) press potential
reactor instabilities. By letter dated March 21, 1997, t1e NRC issued TS
Amendment Nos. 205 and 146 for Units 1 and 2. respectively. These TS
amendments allowed the licensee to install a new digital Power Range
Neutron Monitoring system which included Option III implementation.
By SNC letter dated June 20. 1997, the licensee requested an axtension of
the testing period for the Optb 'II hardware due to an unusually high
number of confirmation counts s false positives) from the 3eriod-
based detection system (PBDS). Ik 'icensee personnel stated tlat they
required additional time to "cune" the PBDS using less sensitive
settings. By letter dated September 12. 1997, the NRC approved the
licensee's request: however, the letter stated that the less sensitive
settings proposed by SNC would have to be reviewed separately.
During the Unit 2 Cycle 14 " tuning" tests, the licensee used less
sensitive settings and the longest confirmation observed was 4 counts.
Based on these results. the licensee proposed to use the less sensitive
settings. Because these settings are outside the previously approved
ranges, further NRC review was required. In response to a recuest for
additional information the licensee provided test data that cemonstrated
that the proposed settings were covered by the initial evaluation, but
that the sensitivity of these proposed settings is very low. The
inspectors reviewed the data and were concerned that the )roposed
settings would not provide a warning alarm before the hig1-amplitude
Option III scram would occur. Further discussions with licensee
personnel indicated that the problems observed during testing did not
Enclosure 2 j
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1
28
appear to have been communicated properly throughout the industry. 1
Specifically, the licensee appeared-to have solved the 3roblem "on their
own" without consulting other 0) tion III plants or the lardware vendor.
This was a concern because the )BDS sensitivity problems appear to be a j
generic issue and has been experienced independently by the Option I-A 4
plants.
c. Conclusions
The inspectors concluded that the licensee has 3 roper documentation of )
the Option III implementation d6ta. However, tie inspectors were '
concerned that the licensee does not a) pear to have communicated what
ap3 ears to be a generic problem with tie PBDS algorithm sensitivity to
otler Option III vendors and utilities.
E3.10 Review of Stability-Pelated Procedures
a. Insoection Scoce (37550)
The inspectors reviewed the licensee's BWR Core Analysis Procedure number
BCA-10-270. Stability Considerations, which documents the stability-
related considerations taken during reactor core management and reload
licensing activities. This procedure applied to both Unit 1 and Unit 2. ,
i
b. Observations and Findinas
Prior to Option III im)lementation. Procedure BCA-10-270 specified that
both units follow the 3WROG Interim Corrective Actions dated June 6
1994. The )rimary recommendation of Procedure BCA-10-270 was to remain
within the )ounds of established operating experience. Specifically, the
procedure recommended that axial and radial )ower peakings be minimized,
that feedwater temperature be maintained wit 11n normal range, that
unusual xenon conditions (e.g., startup following a short shutdown) be
evaluated for their effect on reactor power distribution, and that
additional analyses be performed when a new fuel design was loaded into
the reactor core.
Following implementation of Option III. Procedure BCA-10-270 saecified
the actions taken during the reactor core anal.ysis to verify tlat the
o)erating margin due to instability events, detected and su) pressed by
tie OPRM scram system. were not limiting. The results of t ais
confirmatory analysis were reported in the Su)plemental Reload Licensing
Report and the OPRM values were supplied in tle COLR.
A review of Unit 2 Cycle 11 startup stability calculations indicated the
potential for out-of-phase instability. Even though the calculated
channel decay ratios were within the " core-channel ~ stability acceptance
region, the channel decay ratios were high. indicating that an out-of-
phase instability may occur.
Enclosure 2
1
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29
Procedure BCA-10-270 specifies that the form provided with Attachment 1
i.
'
may be used to help evaluate the new cycle for stability. However, an
interview with licensee personriel found that this form was not used.
L Licensee personnel stated that they planed to modify the procedure to
i require that the form be used to document their evaluation. Licensee
! personnel indicated that the customary procedure was to include the
stability evaluation as 3 art of the Cycle Management Report (CMR). The
inspectors reviewed the Jnit 2 Cycle 14 CMR (Rev.1). Section 4.2.
Reactor Thermal-Hydraulic Stability. The Unit 2 Cycle 14 CMR contained-
the results of three stability calculations which showed a core-wide
decay ratio of less than 0.29 and a channel decay ratio of less than
0.12. The analyzed condition was 35.8% rated power and 34% rated core
flow, which lies just outside the Unit 2 stability interim corrective 1
action exclusion region. l
The inspectors also reviewed CMR Section 4.2. Reactor Thermal-Hydraulic
Stability. Rev. O. for Unit 1 Cycle 18. This section did not contain any
documentation specific to the stability of the Cycle 18 reactor core,
which was the first cycle where GE-13 design fuel was used. The form
provided with Attachment 1 was not completed for this cycle. When
interviewed, licensee personnel stated that they had not performed a
cycle-specific stability evaluation because the results of Unit 2 Cycle
14 had shown a large margin (decay ratio less than 0.29) and that the
Unit I reactor core design was essentially identical to that of Unit 2
Cycle 14. However, no formal evaluation was conducted to demonstrate
that the Unit 2 Cycle 14 stability calculation applied to Unit 1 Cycle
18. The inspectors compared the Unit 1 Cycle 18 and the Unit 2 Cycle 14
reactor core designs and concluded that the stability evaluation was
technically adequate. However, the lack of a formal evaluation was
considered to be an area that could be improved.
The use of ODYSY for stability calculations was discussed with the
licensee. The licensee was aware that ODYSY is not approved for
licensing stability calculations and that these stability calculations l
were performed for operational purposes only. '
c. Conclusions
The Stability Considerations procedure BCA-10-270 adequately addressed
stability-related issues for new reactor cores. However the form :
provided with Attachment 1 was not being used to evaluate the new cycle l
for stability. All relevant documentation relative to the stability for i
Unit 2 Cycle 14 was adequately covered by the CMR. The inspectors also :
found that the stability evaluation for Cycle 18 of Unit 1 was i
technically adequate. However, there was no formal documertation of this
evaluation.
i
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l
L Enclosure 2 j
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E3.11 Licensee Oversiaht of Vendor Performance
a'. Insoection Scooe
At a' follow-up to concerns found during recent fuel vendor inspections,
the inspectors evaluated licensee programs to adequately oversee their
nuclear fuel vendor. General Electric. '
>
! .
L : b. Observations and Findinas
The inspectors found that SNC has a comprehensive Quality Assurance (0A)
3rogram, from the Corporate 0A Policy and Guidelines to specific Nuclear
r uel (NF) Department
arocedures. The inspectors reviewed two detailed NF
0A audit reports for latch Unit 2. Cycles 13 and 14. In addition.: the
BWR audit logs from 1995 through 1997 were reviewed. The inspectors
found that 4 to 5 separate audits were oerformed for each reload core 6
design campaign. It was noted that a S4C Corporate Quality Services
audits of Nuclear Fuel in 1994 and 1996 also evaluated the BWR vendor
audit program, with no adverse findings.
c.. Conclusions
The ins >ectors found the Hatch licensee vendor oversight program to be a
strengt1 both in the formal 0A audits and follow-up activities with the
vendor.
E3.12 Rod WithdCpwal Error / Rod Block Monitor Ooerability Technical
Specifications
]
a. Insoection Scooe (92903)
The inspectors reviewed the licensee *s res)onse and assessment of recent
vendor reported problems with the Rod Bloc ( Monitor (RBM) operability
requirement of TS'for the rod withdrawal error (RWE) event. j
b. Observations and Findinas
The inspectors evaluated the licensee's response to a GE letter dated
October 31, 1994, informing the licensee that the 1% plastic cladding i
strain limits should be considered for ARTS plants and that the strain ;
limit would be met if one channel of the RBM remains operable. The '
inspectors noted that the GE Safety Reload Licensing Reports (SRLRs) for
Unit 1. Cycles 16 and 17. and Unit 2. Cycles 13 and 14, indicated the
necessary protective measures, but failed to clearly address the !
conditions under which the RBM should be operable. During an inspection i
of the vendor. GE informed the NRC that its analyses showed that the
licensee's M0P screening limits had been exceeded, but the that the 1%
strain limits were not exceeded. Following this' inspection. GE issued a ;
formal notification to all ARTS plants that at least one channel of RBM i
must remain operable to meet the 1% plastic cladding strain limits. In l
l- Enclosure 2 l
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31
April. 1997, the licensee submitted Licensee Event Report (LER)'
50-321/97-03. describing the discrepancy between GE RWE analyses-
procedures and the TS requirements and the corrective actions that were
taken.
In March 1995. GE began cycle-specific RWE. analyses for all plants and
fuel types. During the period when the potential existed for the MOP
, screening criteris to be exceeded, and before the detailed 1% cladding
strain analyses was completed, the TS.for Hatch Unit 1. Cycles 16 and 17
and Hatch Unit 2 Cycle 13 did not require the RBM operability. However,
the inspectors were not able to determine if the licensee could or should.
have been aware of this aroblem before formal notification by GE. This-
issue is identified as URI 50-321. 366/97-12-12, Timeliness of Amendment
of Technical Specifications, pending additional review by the NRC staff.
c. Conclusions
Although the RBM channels were operable during this period, and
administratively required after the licensee became aware of the problem,
the TS requirement was not implemented until after the licensee TS
amendment request of May 9. 1997.
E8 Miscellaneous Engineering Issues (92700) (92903)
E8.1 (Closed) Unresolved Item (URI) 50-321. 366/97-05-04: Determine the
Reoortability of Licensee-Identified Deficiencies With Resoect to IN 92-
18. " Potential for Loss of Remote Shutdown Caoability Durina a Control
Room Fire."
This URI was opened as a result of questions concerning the
reportability, under 10 CFR 50.72 and 50.73. of design and " hot short"
issues that were raised as a result of the licensee's review of IN 92-18.
The inspectors reviewed.the reportability requirements and the licensee's
rationale for not reporting-this issue. The inspectors reviewed NUREG-
1022. " Event Reporting Guidelines." and concluded that the licensee's
justification was sound. The " hot'short" scenario, as it relates to the
Hatch Units 1 and 2 design, was regarded as extremely remote. The
corrective action implemented through Design Change Recuests (DCRs) 97-
016 and 97-017 was reviewed. Updated lists of affectec motor-operated
valves were included in the DCR packages. The inspectors verified that
the complete list of valves was modified per DCR 97-016 during the Unit 1
Fall 1997 refueling outage. The updated list for DCR 97-017 (Unit 2), to
be accomplished in the Fall of 1998 was also verified. i
Based upon the inspectors review of the licensee's actions in response to
IN 92-18, and an assessment of the licensee's reportability
justification, this URI is closed
Enclosure 2
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32
E8.2 (Closed) URI 50-366/97-11-08: Unit 2 Failure to Meet General Desian
Criteria 56 for Procer Automatic Containment Isolation Valve Outside '
Containment.
This item is documented in Section E2.1 of IR 50-321. 366/97-11 and was
pending further NRC' review. The NRC conducted additional reviews of this
problem and acknowledged that both units have identical designs and that
3 resents little safety significance. The licensee's exemption request is
3eing reviewed by the NRC. Based upon the inspectors review of
licensee's actions and the minor safety significance of the problem, this
item is closed.
E8.3 (Closed) Licensee Event Reoort (LER) 50-321/97-04: Sinole Failure Renders
inocerable the RHRSW Lona-term Containment Heat Removal Mode.
This event is documented in section El.1 of IR 50-321, 366/97-07.
relating to licensee-identified inadequate cable separation issues. The
inspectors reviewed the licensee's corrective actions, which included
detailed walkdowns of the emergency 4160-volt switchgear and selected
control room panel circuits. Circuits that did not meet electrical
separation criteria were evaluated by the Architect-Engineer and found to
be acceptable. The inspectors reviewed the safety assessments, which
were thorough and detailed. Additional cable separation deficiencies
were corrected by Maintenance Work Orders (MW0s) to wrap cables with
S11 temp which is a qualified barrier and secured with tie-wrap.
Based on the inspectors review of licensee actions, this LER is closed.
IV Plant Support
R1 Radiological Protection and Chemistry (RP&C) Controls
R1.1 Conduct of Radiological Protection Controls (71750)(83750)(84750)
a. Insoection Scooe
Radiological controls associated with on-going routine Unit 1 (U1) and l
'
Unit 2 (U2) operations were reviewed and evaluated by the inspectors.
Reviewed program areas included area postings and radioactive waste 4
(radwaste) and material container labels, high and locked-high radiation i
area controls, and procedural and radiation work permit (RWP)
implementation. In addition, operational status of offsite environmental
monitoring station equipment was verified.
The inspectors made frequent tours of Radiological Control Areas (RCAs)
and observed work activities in progress. In particular, radiation l
control practices and Health Physics (HP) staff activities were observed.
i
Results of ongoing radiation and contamination survey results wes ;
- veri fied. Tours of selected offsite environmental monitoring stations i
j and direct observations of equipment operability were conducted. !
,
l Enclosure 2 l
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33
Established radiological controls were compared against ap)licable
sections of the Updated Final Safety Analysis Report (UFSAR) and the
applicable requirements specified in licensec procedures. Technical
Specifications (TSs). Offsite Dose Calculation Manual (ODCM), arid
b. Observations and Findinas
Area postings and container labels were determined to be adequate for the
associated radiological conditions. Controls for high and locked high-
radiation areas were implemented appropriately. Dose rate and
contamination survey results were conducted with calibrated
instrumentation. Radiation and contamination surveys were conducted in 3
'
accordance with approved procedures and results met regulatory
requirements.
No operational concerns were identified for the offsite Radiological
Environmental Monitoring Program (REMP) equipment. For the environmental
monitoring stations visited, thermoluminescent dosimeters (TLDs), and the i
surface water and air sampling equipment were verified to be in place.
calibrated properly and operational in accordance with procedural or ODCM
specifications.
c. Conclusions
Radiological controls for normal operations and for routine radwaste
processing, storage and transportation activities were maintained in
accordance with procedural. TS. and 10 CFR Part 20 requirements.
Current offsite radiological environmental monitoring program equipment,
instrumentation, and operations met procedural and ODCM requirements.
R1.2 Release of Material to the Onsite Landfill (83750. 84750)
a. Insoection Scooe
Radiation Protection program activities associated with the unconditional I'
release of materials from RCAs were reviewed and discussed. In
particular, the inspectors reviewed and discussed licensee actions
associated with review of NRC unresolved item (URI) 50-321, 366/97-10-06.
This item documented the release of potentially contaminated materials
from the Waste Separation and Temporary Storage (WSTS) facility area RCA !
whicn subsequently were buried in the onsite landfill. The inspection l
included extensive interviews with licensee and contractor health physics
technician (HPT) staff. su)ervisors, and managers. Detailed reviews and ;
discussions of the applica)le entries in the WSTS facility logbook were l
conducted. 1
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The HPT staff's understanding and implementation of applicable procedures
were reviewed. The following Administrative Control (AC), Radiation
Protection (RP) and Health Physics Instrumentation (HI) procedures and
Health Physics Information Letter (HPLI) guidance regarding completion
and documentation of radiological surveys of materials released from
established RCAs for disposal. in the onsite landfill were reviewed and
discussed with responsible staff. ,
e Procedure, 60AC-HPX-007-0S, Control of Radioactive Materials,
Revision (Rev.) 4.
. Procedure, 60AC-HPX-004-05, Radiation and Contamination Control,
.Rev. 14.
. Radiation Protection (RP) Procedure 62RP-RAD-017-05, Release
Surveys, Rev. 6.
- Procedure 62RP-RAD-008-OS, Radiation Contamination Surveys,
Rev. 9.
. -Procedure 62HI-0CB-056-OS, Waste Separation and Temporary Storage
Facility, Rev. 6.
.- Health Physics Information Letter Number (No.) 96-13. Rev. 1.
- Procedure 62HI-0CB-016-OS, Radiation Monitor RM-14 Operation and
Calibration, Rev. 8. l
e Procedure 62HI-0CB-019-05, Geiger Counter Model E0120 Operation
and Calibration. Rev. 4.
- Procedure 62HI-0CB-040-05, Ludlum Micro R Meter /Model 12-S. ?
Rev. 3.
The inspectors reviewed and discussed opplicable radiation and
contamination data, including. survey records of the pre-demolition U1
Radwaste facility floors and walls, drums containing radwaste building i
concrete debris released from the main power block RCA, concrete debris
released from the WSTS facility RCA, and qualitative gamma-spectroscopy
analyses of concrete rubble retrieved.from the onsite landfill during the
week of June 8, 1997. On January 14, 1998, the inspectors directly
observed and verified supplemental gamma surveys using a Ludlum Micro R
meter conducted at the two onsite landfill trenches where the U1 Radwaste
Building concrete deoris was deposited prior to June 10, 1997.
Inspection of staff training and licensee actions subsequent to
identification of the issue are documented in Sections ('SS) R5.1 and R7.1
of this report.
The established radiological controls and actions were compared against
applicable procedural guidance, and requirements of 10 CFR Parts 20 and
50, as applicable. ;
.
Enclosure 2
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i^ .
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b. Observations and Findinos
'
l . Based'on discussions with licensee and contractor HPTs and from review of
associated WSTS facility logbooks, the inspectors noted that the buried
material. concrete debris, was generated during construction of a
contaminated tool room in the Unit 1 Radioactive Waste (Radwaste)
- building. Only concrete debris from the U1 Radwaste Building
132 foot (') elevation was transferred to Sealand trailers located
adjacent to.the WSTS building entry and within the facility's established
RCA. The concrete was processed for unconditional release within the
WSTS facility RCA and buried .in the onsite landfill between December 1.
1996, through June 10, 1997.
Pre-demolition radiological surveys of the U1 Radwaste Building '132'
elevation conducted between October through December, 1996, documented
that significant fixed surface contamination was present in the area.
Initial decontamination'of the concrete included removing and disposing
of the outer painted surfaces of the concrete walls and floor as
, radioactive waste. Survey records of drums of concrete rubble originally
designated for processing at the WSTS facility documented maximum dose-
rates of 20 millirad (mrad) contact and 0.7 mrad at one meter. No core
samples from the U1 Radwaste Building floors or walls were taken and
submitted for gamma spectroscopy analysis to evaluate potential internal
contamination on the internal surfaces of the walls or floors. Excluding
a single use of a sorting table gamma-sensitive monitor on June 6. 1997,
the concrete debris was hand-frisked using a Geiger-Mueller (GM) E-120
detector at the WSTS facility work area and segregated into clean and
contaminated material based on established guidelines. Subsequently, the
clean concrete material was placed into drums or boxes. Periodically
each drum or box of clean concrete was re-surveyed using a Ludlum Micro-R i
meter prior to release from the WSTS. facility RCA and transferred to the !
onsite landfill. The concrete debris was placed into the open burial l
trenches: and re-surveyed prior to its being covered in the landfill j
trench.
In response to employee concerns regarding the adequacy of surveys of the {
concrete materials conducted at the WSTS facility RCA. a quality control '
check of the landfill trenches was conducted by the licensee on June 8, l
1997. Although the majority of concrete taken to the landfill was
buried licensee representatives identified several pieces of U1 Radwaste
building concrete either in, or adjacent to the landfill trench in use.
Approximately seven pieces of concrete were identified where traces of 3
surface paint had not been removed. Surveys of these concrete pieces ;
resulted in count rates slightly above the licensee procedural release i
limits of 1000 disintegrations per minute (dpm) per probe area. !
'Oualitative gamma-spectroscopy analyses conducted between June 9 through
- . June 11, 1997. verified that Cobalt-60 and Cesium-137 radionuclides were
L associated with the concrete material. The inspectors noted that l
L 10 CFR 20.2001(a) requires, in part. disposal of licensed material only l
l :
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by. transfer to an authorized-recipient as provided in section (5)
20.2006. The inspectors identified the disposal of. contaminated material
in the onsite landfill as Violation (VIO) 50-321.366.97-12-07. Failure
.
to Dispose of Licensed Material in Accordance with 10 CFR 20.2001(a)
Requirements. Individual surveys of the remaining pieces of unburied
concrete. approximately one-third of a drum, recovered from the landfill
, did not indicate any of the items exceeded the established release
limits. As of June 10. 1997, the licensee stopped disposal of U1
-
Radwaste Building concrete debris into the onsite landfill.
The identification of licensed material in the onsite landfill indicated
potential weaknesses in the use of the GM E-120 and Ludlum Micro R survey
instruments to unconditionally release the concrete from the WSTS
facility area. For example, core samples of the radwaste building
concrete floors and walls followed by gamma spectroscopy analyses were
not conducted to verify that the surveys of accessible surfaces were
representative of inaccessible areas. In addition to the pieces of
concrete having flat planar surfaces, the debris included irregularly
shaped pieces, small particles and dust, all of which were more
appropriately analyzed using supplemental gamma-sensitive automated
surveys of the aggregate materials to identify the low level radioactive
contamination. A gamma-sensitive automated Sorting Table was used on
June 6. 1997 for only one batch of material.
Inconsistencies and confusion regarding HPT and management understanding
of procedural methods and equipment availability for WSTS facility
operations were noted. For example. contract and licensee HPTs and
seva al first-line su3ervisors understood Section 7.1.2 of 62RP-RAD-017
Section 7.1.2 and HPI_ No. 96-13 to require the use of an automated
monitoring system, i.e., the SAM 9. for releasing the concrete materials
from the RCA. However. licensee management interprettt the procedure and
documented guidance to imply use of the equi) ment only if the SAM 9
detectors were established and assigned to t ie specific task. Also, the
inspectors noted-inconsistent responses among staff and management
regarding the specific procedures used for releasing m6terials. survey
instrument response times, and the need to take core samples for j
unconditionally releasing the concrete debris from the WSTS facility
area <
Prior to June 1997, licensee oversight of the release of concrete Gebris
from WSTS facility RCA was limited. Several licensee and contractor HPTs
stated that as a result of concerns regarding frisking of the material, a
request to use SAM 9 detectors to conduct surveys of the aggregate
concrete materials was discussed with direct supervisors but no actions
were taken. Review of Instrument and Calibr 'on Department records
indicated that SAM 9 detectors were calibrat and could have been made
available for use. Huwever, licensee manage wnt representatives stated
that they were unaware of the requests to use the SAM 9 equipment.
Enclosure 2
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Concernt, were also identified to licensee management regarding the
documentation and maintenance of applicable radiological surveys
conducted. Records of surveys conducted for release of concrete from the
WSTS facility RCA and at the landfill only documented results of direct
and smearable contamination levels of the concrete debris released to the
landfill . Based on discussions with several contractor technicians and
supervisors, gamma scintillation surveys of each drum or box of aggregate
concrete material were made as required by Section 7.5.1 of
62RP-RAD-017-0S prior to release from the WSTS facility area and also
after placement of the material in the landfill using a Ludlum Micro R
meter. Although procedure 62RP-RAD-008-0S recuired accurate and legibly
documented surveys to evaluate the present anc potential radiological
hazards and to comaly with the regulations of 10 CFR 20. results of the
final surveys of t1e aggregate materials released from the RCA and
subsequent to alacement in the landfill were not documented or
maintained. T1e inspectors identified this failure to follow
radioactivity control procedures in accordance with TS 5.4.1.a as another
example of VIO 50-321, 366/97-12-09. Failure to Follow Procedures -
Multiple Examples.
Licensee representatives statec that all unburied concrete had been
retrieved and the transfer of material to the landfill terminated. No
concrete rubble was observed during tours of the onsite landfill trenches
during the week of January 12, 1998. Measured exposure rates directly
above the two filled trenches where the concrete debris was buried were
similar to background values, approximately 10 micro-Roentgens per hour.
c. Conclusions
A violation regarding disposal of licensed material in the onsite
landfill was identified: Failure to Dispose of Licensed Material in
Accordance with 10 CFR 20.2001(a) Requirements.
The lack of automated gamma-sensitive ecuipment to conduct survey
aggregate concrete debris was identifiec as a significant program
weakness.
Technician and management interpretations of procedural requirements were
inconsistent.
Prior to June 1997. licensee management of the release of U1 Radwaste
Building debris from the WSTS facility was limited.
A violation of TS 5.4.1.a for failure to follow procedures for
documenting release surveys was identified as another example of VIO
50-321, 366/97-12-09. Failure to Follow Procedures - Multiple Examples.
No ex)osure rates above background were identified for the two landfill
trencies where the U1 Radwaste Building concrete debris was buried.
Enclosure 2
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L
RI.3 Fission Product Monitor Grab Samolina
a. Insoection Scooe (71750)
l
L The inspectors reviewed procedure 64CI-0CB-005-0S, " Fission Product
L Monitors," Rev. 2. Ed 1, and observed a chemistry technician perform a
grab sample of the drywell atmosphere. The inspectors also reviewed TS 3.4.5, RCS Leakage Detection Instrumentation. The drywell grab samples
were required per the TS due to the Fission Product Monitor (FPM) System
being inoperable.
b. Observations and Findinas
,
On January 15. the inspectors observed a radiological protection (RP)
chemistry technician take grab samples of the drywell atmosphere. This
activity was performed in accordance with Chemistry Instrumentation
Procedure 64CI-0CB-005-0S.
The inspectors observed that the noble gas activity for the grab sample l
obtained by RP chemistry at 9:00 p.m. on January 11 had an asterisked
notation, indicating that the acceptance criteria specified on the data
sheet had been exceeded. The statement "will monitor" was entered on the
data sheet as an explanation of the asterisk. The subsequent 12-hour
reading for the noble gas activity was within the acceptance criteria.
The asterisked notation on the data sheet indicated that the readings
would be monitored but that no compensatory measures beyond that required
for a normal reading were taken. The ins)ectors discussed this with RP
Chemistry supervision and were infornied tlat no compensatory actions were
taken for this reading because the subsequent 12-hour reading was within
the acceptance criteria and the total activities involved were relatively
-small
The inspectors observed from a representative sampling of control room
log entries that the RP chemistry department had notified control room
personnel of the drywell oxygen concentration. The inspectors noted that
the results of the noble gas sampling was not documented. The shift
supervisor informed the inspectors that the isotopic noble gas results
reported by RP chemistry personnel typically are not logged if they are
acceptable. Operations personnel were not aware of the noble gas reading
of January 11 which exceeded the acceptance criteria.
The inspectors were informed by chemistry supervision that the procedure
would be enhanced to provide clearer guidance for noble gas readings that
exceed the acceptance criteria.
l Enclosure 2
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c.. Conclusions
' The RP Chemistry technician observed taking a drywell grab sample was
professional and knowledgeable of procedural requirements. Procedural
weaknesses were identified for guidance associated with actions to be
taken when noble gas readings exceed the acceptance criteria.
R2 Status'of RP&C Facilities and Equipment
R2.1 Fission Product Monitorina (FPM) System Problems on Unit 1-
l
a.-Insoection Scooe (71/50)(37551)(92904J -
The inspectors reviewed system operating procedure 3450-D11-001-15.
" Fission Product Monitoring System.~ Rev.1. Ed 1: and chemistry
instrumentation ]rocedure 64CI-0CB-005-0S, " Fission Product Monitors."
Rev. 2. Ed 1. T1e inspectors also reviewed MWO 1-98-0057 and held
discussions with licensee personnel. The documentation review and
discussion were associated with the Fission Product Monitor System and
Commercial Grade Oxygen Analyzer (CGOA) problems.
b. Observations and Findings 1
The' inspectors observed that the licensee began trouble shooting .
activities associated with the Unit 1 FPM on January 8 as a result of i
'
abnormally The. licensee determined
frc"! troublehigh drywell
shooting Oxygen.hat
activities (0[)the
content.
control room reading for the
CGOA was affected when the FPM particulate pump 1011-C026 was operating.
This pump was replaced and the same effects were observed when the pump
was run. Continued troubleshooting activities icd the licensee to.
believe that an obstruction existed in the FPM drywell return line. It
was believed that the restriction caused a back pressure on the CGOA.
thus causing _it to read incorrectly high.
The' diagnostic activity for determining the location of the restriction l
to flow, invalved the monitoring of flows and pressures at the CGOA with '
all pumps running while individually opening serious valves to create a
vent )ath from the FPM drywell return line. The trouble shooting results ;
led tie team to believe that the suspected obstruction was caused by !
either the FPM outboard isolation valve 1D11-F052. or the inboard ;
isolation valve 1D11 F050. 1
During this trouble shooting activity, the 1Dll-F131 containment manual l
test valve was opened as part of the diagnostic testing for venting the ;
FPM drywell return line. Chemistry. maintenance. and operations i
personnel were performing the troubleshooting activity when the valve was ;
opened. Chemistry personnel had the lead responsibility for the
'
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troubleshooting activity. The inspectors observed. from a review of
procedures 3450-D11-001-15. Attachment 2, FPM System Valve Lineup, and
I
,
!
Enclosure 2
40
64CI-0CB-005-0S, Attachment 4. FPM Sam)le Panel Schematic, that the
normal position of manual test valve 1)11-F131 is closed.
Normally-closed valve 1011-F131 is on a 3/4-inch diameter capped pipe
that is connected to the main FPH return line to the drywell. The 3/4-
inch piping connects to the FPM return line between the drywell and the
inboard FPM isolation valve 1D11-F050. The cap on the end of the piping
that contained the ID11-F131 manual valve was removed by the
troubleshooting team prior to opening the valve. The valve was opened
for approximately.five minutes during the trouble shooting activity.
Drywell integrity was lost during the time that the valve was open. The
activities of removing the piping end cap and opening valve 1011-F131 was
not discussed with or approved by the Shift Su)ervisor (SS). The
ins)ectors were informed that overall troubleslooting methods and
tec1niques did not meet management's expectations. The opening of manual
valve 1011-F131 by the trouble shooting team that resulted in a breach of
drywell integrity was of minor safety significance and is identified as
NCV 50-321/97-12-08. Personnel Error.Results in a Breach of Drywell
Integrity, in accordance with NUREG 1600.Section VII.
Trouble shooting personnel concluded after opening valve.1D11-F131 and
removal of the end cap that an obstruction existed in or near the 1011-
F050 FPM Drywell isolation valve. The SS conservatively declared the
1011-F050 valve inoperable when Chemistry reported that an obstruction
ap) eared to be in or near the valve. The appropriate TS actions were
ta(en for the inoperable primary containment 1 solation valve. Chemistry
also began taking grab samples for 02 concentration and noble gas
activity in the drywell for the inoperable FPM system, as required by the
TSs. The inspectors observed the performance of a grab sampling activity
as discussed in Section R1.3 of this report.
Testing similar to a local leak rate test was performed by engineering
subsequent to the SS declaring the 1011-F050 valve inoperable. This
testing demonstrated the operability of the 1D11-F050 valve. The
ii.spectors observed portions of this testing activity. j
i
A problem solving team was convened by Nuclear Safety and Compliance to i
continue the investigation into the behavior of the FPM system and the '
high 0, readings on the CGOA. Early in the investigation, an engineer 1
suggested that the apparent obstruction may be the symptoms of the ,
normal, expected pressure drop in the return line. The engineer !
demonstrated through calculations that the pressure drops observed in the !
line during the previous troubleshooting activities could be accounted
for by the flow through drywell isolation valves 1D11-F050 and 1D11-F052.
Hence, the FPM return line obstruction theory was discontinued.
The problem solving team concluded that the FPM and CG0A systems are more
sensitive to pressure flow interactions than had been previously !
understood. Small adjustments in pressures and flows on the FPM system
produced immediate. visible effects on the flows and pressures of the
Enclosure 2 .
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41
'
CGOA system. The teamed believed that the behavior of the FPM system and
the high 02 was due to a confluence of factors including incorrect
operation of the CGOA system, vacuum leaks. and degraded components.
As corrective actions for system operation, the following were undertaken
by the licensee:
Filters 1D11-D044 and 1D11-0045 were changed. New filter paper was
installed in the FPM system. New flow control valves were installed in )
the FPM system on both the particulate monitoring panel and the
iodine / noble gas panel. The FPM particulate monitor was checked and
found to be free of obstruction. The flows and pressures were set up on
the FPM and CGOA system in accordance with their operating procedures.
The FPM and CGOA systems were placed back in service on January 23 and
have operated with no problems since.
c. Conclusions
Trouble shooting activities by chemistry with maintenance and operations
support were not well-planned or coordinated. The problem solving team
convened by NSAC conducted an excellent investigation for the root causes
of the FPM and CG0A problems. A Non-Cited Violation for a personnel
error which resulted in a breach of drywell integrity was identified.
R3 RPC Procedures and Documentation
i
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a. Insoection Scooe (717501
The inspectors reviewed procedure 62RP-RAD-004-05. " Personnel
Decontamination." Rev. 8. five Personnel Contamination Reports (PCRs),
and discussed the licensee's assessment of the contamination problems and
recommended corrective actions with health physics (HP) supervisors. '
b. Observations and'Findinas
The inspectors observed that the procedure provided guidance as to when )
PCRs were required. One requirement was that for a personnel
contamination level greater than or equal to 10.000 dpm, a PCR would be
completed. - The inspectors observed that all five PCRs reviewed were for
contamination levels greater than 10.000 dpm. Personnel involved
included two from maintenance, two from health physics, and one from
chemistry. Two contaminations occurred in a designated clean area. For
these problems. one area was decontaminated and one area was roped off ,
and identified as a contaminated area. The inspectors observed that. 1
although the licensee has recently placed more emphasis on housekeeping
and decontamination activities, contaminations in a clean area is a
recurring problem. Two PCRs indicated that an improper work practice
was the root cause. The inspectors concluded that a third contamination ;
j problem was also due to an improper work practice. In this case. '
I Enclosure 2 !
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maintenance activities included dry surface grinding which resulted in
contamination on the individual's face and mouth area. The PCR indicated
that the root cause was due to changing conditions that exceeded the-
capacity of protective clothing (PCs). The inspectors observed that the
grinding was discussed with HP supervision.
The inspectors observed that one section of the PCR was used to document
the investigation and corrective actions. Although the inspectors
observed that generally the investigation was adequate..they concluded
that the recommended corrective actions were narrow. For example, while
calibrating a conductivity cell in the lab without wearing gloves, one
individual become contaminated. There was no corrective action
documented. However. the PCR indicated the individual was asked what he
would do differently next time. For the maintenance person who become
contaminated during dry grinding. the corrective action was to add a
s)ecial instruction on the radiological work permit to require that all
a)rasive operations be performed wet and for workers to wear grinding
shields and facial protection. There were no recommendations for general
work practice improvement-(grinding work is generally skill-of-craft),
training, or discussion for shift briefings similar to recommendations
observed in other departments. !
The inspectors observed that step 7.1.3.4 of procedure 62RP-RAD-004-0S 4
required, for certain conditions, that a more detailed investigation be l
completed. One of these conditions was that "three or more l
contaminations have occurred on a shift from the same location." The !
inspectors discussed this observation with HP personnel to gain a better
understanding of management's expectations to reduce contamination i
events. HP personnel stated that the procedure would be reviewed. i
c. Conclusions
The inspectors concluded that the investigations for personnel I
contamination reports were generally adequate. The recommended ;
corrective actions were not 6 ways thorough and comprehensive. Others l
were narrow.in focus and in some reports recommended corrective actions j
were not submitted. ,
R5 RP&C Training and Qualification (83750. 84750)
R5.1 Contractor Health Physics Technician Trainina
a. Inspection Scooe
Training provided to six contract HPTs involved with surveying.
unconditionally releasing, and subsequently transporting and disposing of
the U1 Radwaste Building concrete at the onsite landfill was reviewed.
The review included evaluation of applicable radiation protection program
'HPT study guides, verification of completion of training and an i
Enclosure 2
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assessment of contractor and licensee staff understanding of procedural
requirements.
l- The 3rovided training was reviewed against requirements specified in
L 10 C R Part 19 and Departmental Instruction (DI) DI-HPX-02-0286N. HP/ CHEM
l
New Employee Check-In Rev. 6.
b. Observations and Findinas
The training reviewed and tested technicians on ap)licable surveys. and
the control and release of materials from establisled RCAs. For the
contract HPTs involved in the WSTS facility RCA release activities,
training was determined to be current. Both contract and licensee HPTs
displayed appropriate knowledge of procedural guidance and details,
c. Conclusions
Training provided to contract HP technicians involved in surveying,
releasing. and disposing of U1 Radwaste Building concrete in the onsite
landfill was current and met procedural and 10 CFR Part 19 requirements.
R7 Quality Assurance in RP&C (83750, 84750) i
1
R7,1 Identification and Corrective Actions for Contaminated Material Released I
to the Onsite Landfill !
i
a. Inspection Scooe
Licensee actions subsequent to verification that concrete rubble I
containing low levels of radio nuclides was released to the onsite i
landfill were reviewed and discussed. The review included interviews of ,
contractor and licensee HPTs. supervisors and managers, and a review of :
the WSTS facility logbooks and deficiency control documents. !
Program implementation and licensee actions were evaluated against .
3rocedural requirements specified in procedure 10AC-MGR-004-05. !
Jeficiency Control System. Rev. 10.
b. Observations and Findinas
From discussions with cognizant licensee and contractor personnel, the
inspectors determined that initial concerns regarding the adequacy of :
radiological surveys and the potential for release of licensed material
to the onsite landfill were identified during the week of June 2.1997.
On June 9.1997 licensee HPT staff identified approximately seven small
pieces of concrete rubble at the landfill. The rubble should have had
l
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the green paint removed during decontamination activities. Surveys of
the subject pieces of rubble using a GM E-120 detector indicated count
,. - rates slightly exceeding 1000 disintegrations per minute (dpm) per probe '
area. Qualitative gama-scan analyses of the free-released pieces of
Enclosure 2
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concrete rubble conducted between June 9-11, 1997. verified low-level l
radioactive contamination from Cobalt-60 and Cesiumd37 radio nuclides.
From review of licensee commitment tracking data base, the inspec-t6rs
noted that although both HPTs. supervisors, and managers were aware of
the identified concerns during the initial weeks of June 1997 the issue
was not entered into the licensee's tracking system until August 9, 1997.
The inspectors determined that licensee HPT staff initially identified
their concerns to immediate supervisicn and subsecuently to upper
management. Licensee resolution documentation incicated that the
identified concern was treated as an expected statistical anomaly rather
than a deficient radiological concern because the contamination values
were near the release criteria, i.e., the survey instrumentation lower
limit of detection. The inspectors noted that the initial concern
included the adequacy of surveys for unconditionally releasing
potentially radioactive concrete debris from the U1 Radwaste Building and
that the positive gamma-scan analyses verified that at a minimum,
approximately seven ]ieces of the low-level contaminated concrete rubble
was transferred to t1e onsite landfill contrary to 10 CFR 20.2001(a).
The inspectors noted that Administrative Control (AC) procedure 10AC-MGR-
004-05 Deficiency Control System. Rev.10, required, in part, that an
identified deficiency be entered into the NUCLEIS computer system.
reported to the Plant Dispatcher or documented on a written deficiency
card within one hour. Conditions requiring completion of a deficiency
card included not meeting 10 CFR Part 20 regulations. The inspectors
noted that the disposal of licensed material in the onsite landfill met
the criteria for initi6 ting the deficiency card in a timely manner and
that the health physics section was responsible for initiating DCs
identifying low level waste mishap events. This issue was identified as
another example of a violation for failure to follow procedures. VIO 50-
321, 366/97-12-09. Failure to Follow Procedures - Multiple Examples.
Licensee actions taken in response to the identified concerns were
reviewed and discussed with responsible 1scensee representatives.
Although a statistical conclusion regarding the identification of a
" false negative" response was provided to both the NRC Resident
Inspectors and representatives of the State of Georgia. Environmental
Protection Division no estimation of the notential maximum quantities
and types of radionuclides which could have been placed into the onsite
landfill was presented. Based on this statistical interpretation,
licensee documents indicated that no additional actions were necessary.
The inspectors noted that 10 CFR 50.75(g) requires records of unusual
occurrences such as the spread of contamination in and around the site
which are important to the decommissioning of the facility to be
maintained. As of January 12, 1998. the licensee had not included the
information regarding the potential burial of radionuclide contaminants
in the onsite landfill in the site's decommissioning records. This issue
was identified as V10 50-321, 366/97-12-10. Failure to Maintain
Decommissioning Records in Accordance with 10 CFR 50.75(g) Requirements.
Enclosure 2
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c. Conclusions
Licensee HPTs appropriately identified the disposal of licensed material
- in the onsite landfill as a deficient radiological condition.
An additional example of VIO 50-321. 366/97-12-09. Failure to Follow I
Procedure.s - Multiple Examples, was identified.
A violation. 50-321, 366/97-12-10, was identified for failure to maintain
decommissioning records in accordance with 10 CFR 50.75(g) requirements.
R8 Miscellaneous RP&C Issues (83750, 84750)
R8.1 .(Closed) Unresolved Item (URT) 50-321. 366/97-10-06: Review Licensee
Final Evaluation and Correctlye Actinns for Contam_inated Concrete Waste ;
iaterials Released to the Onsite Landfill ,
Inspector review of this issue is documented in Sections R1.2. RS.I. and
R7.1 of this report. Based on these reviews, this item is closed.
P2 Status of EP Facilities, Equipment, and Resources
P2.1 Self-Contained Breathina Aooaratus (SCBA) Insoection
a. Insoection Scooe (71750)
The inspectors reviewed procedure 62RP-RAD-003-09. ~Use and Care of
Respirators." Rev. 7. ED 1. and observed a portion of the monthly
inspection of SCBAs designated for emergency use. The inspectors toured
emergency facilities to verify that they were in standby readiness and
conducted telephone communication checks.
b. Qbjervations and Findinas
The inspectors observed that personnel conducted inspections of SCBAs
stored in the 0)erations Su) port Center (OSC) without the use of a
procedure, checclist or otler guidance. The inspectors discussed this
observation with management personnel and were informed that procedure
62RP-RAD-003-0S was not a procedure that required continuous use. The j
SCBA inspections were generally performed as skill of the craft. The i
inspectors did not observe any deficiencies in the inspection process,
c. Conclusions
The inspectors concluded that the SCBAs were being properly maintained.
The emergency facilities were maintained in a sate of readiness and the ,
, telephone communications checks were satisfactory. l
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S2 Status of Security Facilities and Equipment (71750) ;
The
fenceinspectors
was intact toured
and notthe protected area
compromised and observed
by erosion that the
or disrepair. kerimeter
he fence
fabric was secured and barbed wire was angled as required by the
licensee's Plant Security Program (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 patdown for firearms. explosives and ,
contraband. Badge issuance was observed, as was the processing and l
escorting of visitors. The licensee searched. escorted, and secured
vehicles as described in applicable procedures.
The ins)ectors concluded that the areas of security inspected met the
applica)le requirements.
V. Manacement Meet _if.gs
X.1 Hanagement Changes !
On January 10. 1998, the licensee announced the following management
changes that were effective immediately:
i
. P. E. Fornel, from Performance Team Manager to Plant Modification
and Maintenance Support Manager
- M. H. Googe, from Operations Shift Supervisor to Performance Team
Manager
X.2 Review of UFSAR Commitments
A recent di.scovery 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 re] ort, the inspectors
reviewed the applicable portions of the UFSAR t1at related to the areas
inspected. The inspectors observed that the licensee have initiated a
UFSAR update change to remove the TIP Purge Solenoid Valve 1C51-F3012 and
2C51-F3012 for Units 1 and 2. res)ectively. from the UFSAR listing of
PCIVs. The inspectors verified tlat the UFSAR wording was consistent
with the observed plant practices, procedures, and/or parameters.
X.3 Exit Meeting Summary
The inspectors presented the inspection results to members of the
licensee management at the conclusion of the inspection on February 20.
- 1998. The licensee stated that the three violations proposed in the RP &
l C section would be denied. An interim exit was conducted on January 16,
1998. On. March 2 and March 3. 1998, teleconferences between NRC Region
! Enclosure 2
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II management and Mr. S. Tipps. Manager, NSAC Hatch Nuclear Plant, were
conducted to address issues raised during a February 23, 1998. NRC/ Hatch
Nucleer Plant Management Meeting. The discussed issues involved.
. violations specifically associated with improper disposal. of licensed
material into the onsite landfill.
l. .
The inspectors asked the licensee whether any materials examined during
the inspection should be considered proprietary. 'No proprietary
!
information was identified.
X.4 Other NRC Personnel On Site
i On January 12. Mr. H. N. Berkow. Director Project Directorate 11-2.
Division of Reactor Projects (DRP)-I/II. Office of Nuclear Reactor
Regulation (NRR): Mr. L. N. Olshan. Senior Project Manager Hatch. Project
Directorate II-2. DRP-I/II. Office of NRR; Mr. L. L. Wheeler. Senior
Project Manager, Non-Power Reactors and Decommissioning. Project
Directorate, Division of Reactor Program Management. Office of NRR: and
Mr. D. H. Jaffee. Senior Project Manager Vogtle. Project Directorate II-
2. DRP-I/II. Office of NRR. visited the site. They met with the resident
inspector staff to discuss licensee performance and regulatory issues.
They toured the facilities to observe equipment in operation and general
plant conditicns. They attended the morning management meeting and met i
licensee managemerit personnel. l
PARTIAL LIST OF PERSONS CONTACTED
Licensee
Anderson. J., Unit Superintendent .
Bets 111. J., Assistant General Manager - Operations
Bennett. D., Health Physics Superintendent .
Breitenbach, C.. Engineering Support Manager - Acting l
Carr, W., Environmental Services Manager. Corporate
Coleman..V.. Chemistry Supervisor
Curtis. S., Unit Superintendent
Davis. D., Plant Administration Manager
fornel. P., Plant Modification and Maintenance Support Manager
Fraser. 0.. Safety Audit and Engineering Review Supervisor
Googe. M. Performance Team Manager
Hammonds. J., Operations Support Superintendent
Kirkley. W.. Health Physics and Chemistry Manager
E Lewis, J.. Training and Emergency Preparedness Manager
Madison, D., Operations Manager
McCracken. D., Manager of Regulatory Engineering and Environmental l
Services. Corporate
Metzler. T., Nuclear Safety and Compliance Manager. Acting
Moore. C.. Assistant General Manager - Plant Support
Reddick. J., HP Su3ervisor Support
Reddick. R. , Site Emergency Preparedness Coordinator
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Riner. G., Plant Health Physicist
Roberts. P., Outages and Planning Manager
Smit'.1. D. , Chemistry Superintendent
Thonpson. J. , Nuclear Security Manager
finps. S., Nuclear Safety and Compliance Manager
Wells. P. , General Manager - Nuclear Plant
IMSPECTION PROCEDURES USED
IP 37550: Engineering
IP 37551: Onsite Engineering
IP 40500: Effectiveness of Licensee Controls in Identifying. Resolving.
and Preventing Problems
IP 61726: Surveillance Observations
IP 62707: Maintenance Observations '
IP 71707: Plant Operations
IP 71750: Plant Support Activities
IP 83750: Occupational Radiation Exposure
IP 84750: Radioactive Waste Treatment, and Effluent and Environmental
Monitoring l
IP 92700: Onsite Follow-up of Written Reports of Nonroutine Events at !
Power Reactor Facilities l
IP 92901: Followup - Operations l
IP 92902: Followup - Maintenance / Surveillance ;
IP 92903: Followup - Followup Engineering i
IP 92904: Followup - Plant Support i
ITEMS OPENED AND CLOSED :
Ooened
50-321, 366/97-12-01 IFI Review of Operations. Mairtenance and I
Engineering Actions for Long-Term
Resolution of Running the EDGs !
Unloaded or at low Loads
(Section 02.1).
50-366/97-12-02 VIO Failure to Implement Changes to Vendor
Manual (Section 02.2).
50-321/97-12-03 NCV Failure to Follow Procedure for
Scheduling Weekly Testing of RPS Scram
Test Switches (Section M3.3).
50-321. 366/97-12-04 IFI Review of IST Basis for PSW Makeup I
Valves to Spent Fuel Pool
(Section E2.2). j
50-321, 366/97-12-05 VIO Failure to Include Nitrogen Valves in
a Test Program In Accordance with 10
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CFR 50.Section XI of Appendix B. Test
Control (Section E2.5).
50-321, 366/97-12-06 VIO Insulation on Nitrogen Supply Piping
Not Installed in Accordance with
Drawings (Section E2.5)
50-321, 366/97-12-07 VIO Failure to Dispose of Licensed
Material in Accordance with
10 CFR 20.2001(a) Requirements
(Section RI.2).
50-321/97-12-08 NCV Personnel Error Results in a Breach of
Drywell Integrity (Section R2.1).
50-321, 366/97-12-09 VIO Failure to Follow Procedure - Multiple
Examples (Sections 02.2. R1.2, and
R7.1).
50-321, 366/97-12-10 VIO Failure to Maintain Decommissioning
Records in Accordance with
10 CFR 50.75(g) Requirements
(Section R7.1).
50-321, 366/97-12-11 URI Timeliness of Identification of SLMCPR
Errors (Section E3.8).
50-321, 366/97-12-12 URI Timeliness of Amendment of Technical
Specifications (Section E3.12).
Closed
50-321, 366/97-05-04 URI Determine the Reportability of
Licensee-Identified Deficiencies With
Respect to IN 92-18. ' Potential for
loss of Remote Shutdown Capability
During a Control Room Fire"
(Section E8.1).
50-366/97-11-08 URI Unit 2 Failure to Meet General Design
Criteria 56 for Proper Automatic
Containment Isolation Valve Outside
Containment (Section E8.2).
50-321/97-04 LER Single Failure Renders Inoperable the
RHRSW Long-term Containment Heat
Removal Mode (Section E8.3).
50-321, 366/97-10-06 URI Review Licensee Final Evaluation and
, Corrective Actions for Contaminated
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Concrete Waste Materials Released to
the Onsite Landfill (Section R8.1)
50-321/97-12-03 NCV Failure to Follow Procedure for
Scheduling Weekly Testing of RPS Scram
Test Switches (Section M3.3).
50-321/97-12-08 NCV Personnel' Error Results in a Breach of
Drywell Integrity (Section R2,1).
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