ML20197F393
| ML20197F393 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 12/15/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20197F340 | List: |
| References | |
| 50-321-97-10, 50-366-97-10, NUDOCS 9712300208 | |
| Download: ML20197F393 (62) | |
See also: IR 05000321/1997010
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U.S. NUCLEAR REGULATORY COMMISSION
REGION 11
Docket Nos: 50 321, 50-366
Report No: 50-321/97-10. 50-366/97-10
Licensee: Southern Nuclear Operating Company. Inc. (SNC)
Facility: E. 1. Hatch Units 1 & 2
Location: P. O. Box 2010
Baxley. Georgia 31515
Dates: Cctober 5 - November 15. 1997
Inspectors: B. Holbrook, Senior Resident Inspector
J. Canady, i<esident Inspector
G. Kuzo. Senior Radiation S)ecialist. (Sections
RI.2. R1.3. R3.1. R7.1. 18.1, and R8.2)
W. Kleinsorge. Reactor Inspector. (Section M1.3)
R. Carrion. Project Engineer (Sections 08.1,
M8.1, M8.2 E8.1. E8.2. F8.1. and F8,2)
Accompanying inspector: T. Fredette -
Apprcsed by: P. Skinner Chief. Projects Branch 2
Division of Reactor Projects
Enclosure 3
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EXECUTIVE SUMMARY
Plant Hatch. Units 1 and 2
NRC Inspection Report 50-321/97 10. 50 366/97-10
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.
Doerations
e Excellent operator response on Unit 1 prevented a potential unit
scram due to a loss of condenser vacuum on October 6 '
(Section 01.1).
e Operator performance during the shutdown of Unit 1 for the
scheduled refueling outage was excellent. Supervisory and
management Jersonnel provided oversight and direction when
required. >rocedures were used appropriately and communications
were clear and concise (Section 01.2).
e Operations personnel com)leted all fuel movements and in-vessel
work activities during t1e Unit I refueling outage with no fuel
movement errors (Section 01.3).
- A selection of Technical Specification-required surveillances for
fuel movement was verified to be satisfactorily completed and at
the required frequency (Section 01.3),
o Heavy load movements observed by the inspectors were in the
designated heavy load pathways and were performed as required by
the procedure-(Section 01.3).
- Health Physics supervision was routinely observed on the refueling
floor and provided assistar.ce and directions. The radiological
controlled areas (RCAs) were clearly identified and marked with
rope and tape. The inspectors did not identify any radiological
control deficiencies on the refueling floor (Section 01.3).
- Vendor personnel inspected two fuel bundles, and other than one
piece of non-metallic debris that was removed from one bundle, no
deficiencies were identified (Section 01.3).
e Procedural. Technical Specification, and regulatory requirements
reviewed in preparation for the Unit 1 startup, were being met.
Senior site management, department management, and responsible
supervisors provided oversight and direction for the startup
activities. With noted exceptions, communications were generally
clear (Section 01.4).
e Operations personnel took the appropriate actions when the reactor
core isolation cooling system failed an operability test from the
Enclosure 3
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remote shutdcwn panel. Engineering and maintenance provided good
troubleshooting support (Section 02.1).
e Unit 1 systems used for reactor vessel decay heat removal were in
good operating condition and properly controlled decay heat. The
Final Safety Analysis Report. Technical Specifications. Unit 1
Outage Safety Assessment, and system procedural requirements for
decay heat removal system availability were met (Section 02.2).
e Operations management, supervision, and control room operators
demonstrated a safety conscious awareness for Unit 1 operation
during times of high decay heat loads (Section 02.2).
e Material conditions and general housekeeping in the Unit I drywell
just prior to the filal drywell closeout were good. The new
mirror-backed insulation installed on the reactor, as part of the
drywell insulation upgrade initiative, was in excellent condition.
No indications of system or component leakage were ooserved
(Section 02.3).
e Poor operator performance with es)ect to procedure usage, as well
as othcr administrative controls t1at were not completed, led to
the failure tt meet Technical Specification recuirements prior to
withdrawing a control rod. This was identifiec as Violation (VIO)
50-321/97 02. Failure to Meet Technical Specification Surveillance
Requirements to Withdrawal of a Control Rod While in Cold Shut bwn
(Section 04.2).
e The Significant Occurrence Reports (SOR) reviewed by the
inspectors were correctly classified and were being correctly
tracked by the commitment tracking system and plant procedures
(Section 07.1).
e The recommended schedule for determining root cause and corrective
action recommendation was appropriate for the deficiencies
reviewed. SORS were receiving senior level management as well as
department level management attention (Section 07.1).
thlintenance
e Maintenance activities reviewed or observed were completeJ in a
thorough and professional manner. Supervisory oversight was
evident (Section M1.1).
e Work activities to move new Emergency Core Cooling System suction
strainers from the warehouse to the torus were well-controlled.
Health physics and engineering personnel provided good oversight
and direction. Foreign material exclusion controls were excellent.
Onsite engineering issues were resolved in an appropriate and
timely manner (Section M1.2).
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e Unit 1 inservice inspection activities observed or reviewed were
conducted in accordance with procedures, licensee commitments, and
regulatory requirements (Section M1 3).
e Maintenance and operaticns personnel interfaced effectively during
the Unit 1 main transformer backfeed activities. The licensee
exhibited good overali planning and oversight throughout the
evolution. Operations provided good oversight on establishing the
necessary equipment clearances to remove the 10 Start Up
Transformer from service (Section M1.0 .
e The licensee had taken initial ste)s to address problems with
Westinohouse Type DHP circuit brea ers in July 1997, based on
problems and events at other utilities. The actions and
recommendations of the Event Review Team in response to the recent
circuit breaker failures were sound and appropriate
(Section M1.5).
- Additional examination by the inspectors of the licensee's
preventive maintenance (PM) program for 4160-volt breakers is
warranted based on the recent failures and the fact that two of
the breakers had undergone PMs within the past nine months
(Section M1.5).
e for the surveillances observed, the 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. Some
exceptions were noted during this inspection period (Section
M3.1).
e The lack of attention to detail was a contributing factor for an
incorrect )lacement of a Jumper during a testing activity on
Unit 1. Tae error was identified as NCV 50-321/97-10-03. Jumper
Placement Error During Unit 1 Testing Activities (Section M4.1).
e The Unit 1 Periodic Type B and C Leakage test and required
corrective maintenance were performed per applicable procedures.
The final test results met plant procedure and regulatory
requirements. Supervisory oversight was evident (Section M4.2).
Enqineerina
e The licensee's corrective actions for both units in res)onse to
Generic Letter (GL) 96-06. Assurance of Equipment Operaaility and
Containment Integrity During Design Basis Accident Conditions,
! were completed within the committed time (Section E2.1).
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e The alternative tests of the Unit 1 Safety / Relief Valves were
c mpleted in accordance with plant procedures and as specified in
b lief Request RR-V 11. Inservice Testing of Safety / Relief
Valves - Edwin 1. Hatch Nuclear Plant. Units 1 and 2. All test
data met the acceptance criteria (Section E2.2).
e The actions taken to inspect and clean the Unit 1 torus were good.
Foreign Material Exclusion controls were properly implemented.
Management was actively involved. The small amount of debris
found in the torus did not present a risk for emergency core
cooling system suction strainer blockage (Section E2.3).
e The licensee actions taken to implement Technical Specification
Amendments 204 and 145 for the Standby Liquid Control System were
timely and correct. The completed Standby Liquid Control System
surveillances verified that pum) flow and discharge pressure
requirements were met (Section E2.4).
e The 10 CFR 50.59 evaluation for the GL 89-10 modifications
implemented by Design Change Request 96 005. was appropriate.
Foreign material exclusion control for the High Pressure Coolant
injection (HPCI) 1E41 F001 valve work activity was excellent.
Operations 31acement of clearance tags was correct. The American
Society of iechanical Engineers (ASME)-required VT-3 code
inspection for HPCI valve 1-E41-F006 was satisfactorily completed
(Section E2.5).
e The initial Unit 1 Condensate Storage Tank entry to perform
desludging activities was not well-planned. Foreign material
exclusion controls were in place and were properly implemented.
The presence of health physics personnel was observed and securit)-
personnel were present to provide emergency personnel recovery
actions (Section E2.6).
- Engineering personnel provided good oversight and coordination in
respcase to the GL 96-01. " Testing of Safety-Related Logic
Circuits." for Unit 1 Emergency Diesel Generators and emergency
switchgear. Test results met the appropriate acceptance criteria
(Section E2.7).
- Licensee actions taken to correct a missed commitment for Unit 2
Technical Specification Amendment 132 were appropriate. The ASME
code-required testing completed in October 1997 was satisfactory.
This problem was identified as Deviation 50-366/9/-10-04. Missed
Commitment for Unit 2 Technical Specification Amendment 132
(Section E3.1).
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e Design Change Request work packages reviewed by the inspectors
were generally thorough and detailed. The 10 CFR 50.59
evaluations reviewed were detailed, thorough, and appropriate.
Changes to procedures, drawings, and TSs were identified when
required. Work observed was yerformed in accordance with
applicable procedures and wort packages (Section E3.2).
e NCV 50-321/97-10-09. Personnel Error During 10 CFR 50.59
Evaluation Review and Procedure Revision Process For Residual Heat
Removal On-line Testing, was identified. The licensee's completed
and planned corrective actions to revise the Updated Final Safety
Analysis Report (UFSAR), assess corporate's UFSAR review process,
enhance future 10 CFR 50.59 training and evaluation procedures,
and the issuance of a department directive to explain the
procedure review requirements, were appropriate (Section E3.3).
e The reactor pressure vessel leakage and reactor recirculation pump
runback tests were performed in accordance with approved
procedures, technical specifications, and conditions specified in
the UFSAR. The activities were performed with good coordination
between engineering, operations, and maintenance. The performance
of the pressure tests and the leak repairs was excellent
(Section E4.1).
Plant Suongrt
e in general, radiological controls, area postings and container
labels were maintained in accordance wit 1 Technical Specificctions
and 10 CFR 20. Appendix J requirements (Section R1.2).
e The failure to label eight vacuum filters stored within Bay 13 of
the Unit 1 torus was identified as VIO 50-321/97-10-05. Failure to
Label Containers of Radioactive Material in Accordance with
10 CFR 20.1904 Requirements (Section R1.2).
e External exposure controls for Unit 1 outage tasks were effective
in maintaining personnel doses significantly less than 10 CFR
Part 20 limits (Section R1.2).
e Radiation exposure and contamination controls were effective with
isolated examples of poor radiation practices identified
(Section Rl.2).
e The detailed survey maps developed by health physics to identify
the hazards present in the Unit 1 torus were not always effective
(Section R1.2).
e Licensee controls for minimizing internal exposure were effective,
with potential uptakes of radianuclides evaluated appropriately
(Section R1.3).
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e Records for determining workers' prior yearly occupational
exposures and granting administrative exposure extensions were
established in accordance with 10 CFR Part 20. Subpart L
requirements and administrative procedures (Section R3.1).
- Licensee quality control checks identified that several pieces of
slightly contaminated concrete were released to the onsite
landfill (Section R7.1).
o initiatives to address and reduce worker personnel contaminations
were effectively implemented (Section R8.1).
o NCV 50 321. 366/97-10-07. Failure to Have Adequate Surveillance
Procedures to meet the Containment High Range Radiation Monitors
Electronic Signal Substitution Calibrations Specified in
NUREG 0737. Table ll.F.1-3. was identified (Section R8.2).
e The areas of security inspected met the applicable requirements
(Section S2).
e The portion of the monthly fire protection inspection observed by
the inspectors was well performed. The fire protection engineer
was knowledgeable of the job responsibilities and fire protection
equipment. The on-the-spot correction of some minor deficiencies
was appropriate. The deficiency cards initiated to identify and
track other problems were timely (Section F3.1).
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Reoort Details .
Summary of Plant Status ,
Unit 1 began the report period at about 96% Rated Thermal Power (RTP).
Power was reduced to approximately 66% RTP on October 6 when the main
condenser vacuum began decreasing while >erforming a clearance to isolate
the "B" Steam Jet Air Ejector (SJAE). T1e valves changed by the
clearance were returned to their original position and reactor power was '
restored to the maximum achievable the next day. Operations began
reducing unit power on October 10 for the scheduled seventeenth refueling
outage. The unit was manually scrammed on October 11 to begin the
refueling outage. The unit remained in the refueling outage for the
remainder of the report period.
Unit 2 began the report period at 100% rated thermal power (RTP). The
unit operated at this power level for the remainder of the report period,
except during routine testing activities.
L Operations
01 Conduct of Operations .
01.1 General Comments (71707)
The inspectors conducted frequent reviews of ongoing plant
operations. Unit 1 power was reduced to approximately 66% RTP on
October 6 when the main condenser vacuum began decreasing while
performing a clearance to isolate the "B" Steam Jet Air Ejector
(SJAE). The valves were returned to their original position and
power was restored to 100% RTP the next day. Trouble shooting
revealed that a closed valve was leaking by and caused the
decrease in vacuum. Operator response to decreasing condenser
vacuum was excellent. In general, the conduct of operations was
professional and safety-censcious. Specific events and
observation are detailed in the section below.
01.2 Observations of Unit 1 Shutdown for Refuelina
a. Insnection Scoce (71707) (60705)
The inspectors reviewed procedures 34G0-0PS-065-OS. " Control Rod
Movement." Revision (Rev. ) 2. and 34GO-0PS-005-15. " Power
Changes," Rev. 20. Edition (Ed) 1, and observed operator
performance during Unit 1 shutdown to begin the scheduled
refueling outage,
b. Observations and Findinos
During the power reduction and manual scram of Unit 1, the
inspectors observed that appropriate procedures were used and
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communications between operators and supervisors were clear and
concise. Command and control by the Shift Supervisor (SS) was
l excellent. The SS conducted pre evolution briefings prior to
I major activities, made specific assignments for critical
l- functions, and conducted peer checks for ongoing activities. The
- inspectors observed that the operations manager was present in the ;
! control room to observe activities and provided oversight-and '
l direction when required.
The inspectors observed procedure 341T-N30-004 15. " Turbine
Overspeed Tri) Test." Rev. 1. being implemented by operations
personnel. T1e inspectors also observed that a vendor
representative was in the main control room to provide assistance
during the test. The inspectors observed that procedures were
used, communications were clear and concise, and operators used
all available control board indications to verify that the test
was satisfactorily performed.
The SS-conducted a crew briefing just prior to the manual scram of
the unit. The briefing was thorough and specific. Specific
assignments were made, past personnel and unit performance was i
reviewed, and contingency plans were discussed. The inspectors
observed that the operators' performance during and following the >
manual scram was excellent. All ecuipment operated as expected
and no deficiencies were identifiec.
c. Conclusions
Operator performance during the power reduction and manual scram
of Unit 1 for the scheduled refueling outage was excellent.
-Supervisory and management personnel provided oversight and
direction when required. Procedures were used and communications
were clear and concise.
01.3 General Refuel Floor Observations for Unit 1
a. Insnection Scone (71707) (60710)
The inspectors reviewed procedures 51GM-MLH-004-05, " Heavy Loads
Movement Procedure." Rev. 11. 52-GM-MME-004-15. " Reactor vessel .
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Reassembly." Rev. 9. 52GM MME-005 lS. " Installation and Removal of
Drywell Equipment Hatches." Rev. 2. Ed 1. and 52GM-MME-015-1S,
" Reactor Vessel Disassembly." Rev. 6. 51GM-MNT-002-0S.
" Maintenance Housekeeping." Rev.12. Ed 2. and observed work
activities in 3rogress to verify that activities were completed in
accordance wit 1 applicable procedures.
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b. Observations and Findinos
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The inspectors observed that the refueling floor coordinator
monitored ongoing work activities and was cognizant of refuel !
floor equipment status and scheduled evolutions. Overhead crane
activities were monitored and directed by an individual designated
to direct crane movements. To be readily identified by the crane i
operator, the designated person wore an orange vest, rs required i
by procedure. The heavy load moves observed by the inspectors
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were in the designated heavy load pathways required by the
procedure. The inspectors did not observe any housekeeping
deficiencies on the refueling floor. t
Health Physics (HP) personnel were observed monitoring work ,
activities that required HP assistance. HP supervision was ;
routinely observed on the refueling floor providing assistance and
direction. The radiological controlled areas (RCAs) were clearly '
identified and marked with rope and tape. The inspectors did not
observe any deficiencies with respect to the RCA boundaries.
The inspectors reviewed ]rocedures 34FH-0PS-00105. " Fuel Movement
Operation," Rev. 16. 42F1-ERP-014-0S " Fuel Movement." Rev. 12.
and routinely observed fuel movement activities from the refuel
floo, and control room. The inspectors did not observe any
deficiencies with respect to refueling activities. A selection of
fuel movement Technical Specification (TS) required surveillances
was verifled to be completed at the required frequency. No
deficiencies were observed. Operations personnel on the refuel
floor responsible for all fuel movements and some in-vessel work ,
activities completed the work task with no fuel movement errors.
Vendor personnel conducted an inspection of two fuel bundles: one
GE13LUA bundle and one GE12LUA bundle. The inspectors observed
part of the fuel inspection activities and reviewed the vendor's
report of the inspection. The report indicated that both bundles
were in excellent condition and acceptable for continued
irradiation. A piece of debris was found and successfully removed
from bundle YJE950 (GE12LUA). The debris was white in color:
appeared to be non metallic; and was located below spacer 7 on ,
side 4 and wedged between rod C1 and spacer 7. No other i
deficienries were reported. ,
c. Conclusions
Operations personnel completed all fuel movements and invessel
work activities with no fuel movement-errors. A selection of fuel
movement TS mquired surveillances was verified to be completed at
the required frequency. The heavy load moves observed by the
inspectors on the refueling floor were in the desigriated heavy ,
load pathways-required by the procedure. HP supervision was ,
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routinely observed on the refueling floor providing assistance and ,
directions. The RCAs were clearly identified and marked with rope ;
and ta,s. Vendor personnel inspected two fuel bun'iles and other !
than one piece of non metallic debris that was removed from one I
bundle, no deficiencies were reportea. i
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01.4 Prenarations for Startuo Followina Refuelina Outaae Unit 1
a. Insoection ScoDe (71707)
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Theinspectorsreviewedgrocedures34G00PS003-15."Startup l
System Status Checklist. Rev. 9. and 34GO 0PS-001 15. " Plant !
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Startup." Rev. 26. Unit 1 TSs. and reviewed licensee preparations I
to startup Unit 1 following the seventeenth refueling outage. !
Inspector activities included documentation review and- S
observaticns in the Unit 1 main control room and at selected local e
control panels.
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b. Observations and Findinas !
On November 14 and 15. the inspectors conducted reviews for i
preparation of the Unit 1 startup. Startup activities _were still i
ongoing at the end of this inspection report period. The
inspectors observed that the sections of the completed procedure 't
checklist matched unit conditions. Emergency Core Cooling Systems
(ECCS)-checklist completed was consistent with actual system ;
lineups in the control room. The inspectors reviewed selected ;
local valve positions and verified that the valves were positioned !
as specified in the procedure checklist. Selected local.ECCS !'
instrument indications were verified to be consistent with control
room indications. Selected normal and alternate ECCS breakers
were verified to be closed or in standby for emergency start
conditions.
The inspectors verified that the TS requirements for reactor
feedpump trip on high reactor water level, main steam line i
radiation monitor setpoints, cold shutdown valve operability, and
Local Power Range Monitor 1/V test were satisfactorily completed.
The inspectors observed that site senior management, as well as
department managers and supervisors, provided.oversite and
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direction of startup and control room activities as required.
Operations personnel maintained a professional demeanor in the
control. room. Control room supervision ensured that all
unnecessary personnel and discussions were outside the-control -i
room area. Communications with and between operations personnel
and other departments were generally three-part communications
which were clear and concise. Some exceptions to clear three part ;
communications were noted and discussed with operations
management. :
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c. Conclusions
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The inspectors concluded that the proceduial. TS. and regulatory
requirements reviewed for the Unit I startup were being met.
Senior site management.. department management, and responsible
supervisors provided oversight and direction for the Unit 1
startup activities. Some exceptions to clear three-part
corrinunications were noted and discussed with operations
management.
02 Operational Status of Facilities and Equipment l
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02.1 Unit 1 Reactor Core Isolation Coolina (RCIC) Failure to 00erate
from the Remote Shutdown Panel (RSP)
a. Insnection Scone (71707) (92901) (3755U
The inspectors reviewed operator performance of surveillance
procedures 345V-E51-005-lS. "0)eration of RCIC from the Remote <
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Shutdown Panel." Rev. O. 345V- 51-002 IS. 'RCIC Pump 0)erability."
Rev. 18. and Maintenance Work Order (MWO) 1-97-1228. )iscussions
were conducted with licensee personnel with respect to RCIC system '
failure to operate from the RSP.
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b. Observations and Findinos ,
On October 9. the inspectors attended the pre job briefing for the
performance of surveillance procedure 34SV E51-005-lS. Operations
personnel led the pre job briefing discussions. lhe inspectors
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observed health physics. engineering, and instrumentation and
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control personnel at the pre-job briefing. ,
The inspectors observed portions of the surveillance 3ert d ,
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from the control room. RSP, and the RCIC pump room. Juring the i
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surveillance performance from the RSP. sufficient flow and
pressure could not be obtained due to lower-than normal RCIC
turbine speed. lhe licensee decided to restore the system to its
normal control room alignment and perform an operability
surveillance from the control room in accordance with surveillance
procedure 345V E51 002-15. The performance of the surveillance
from the control room was successful. 4
The licensee entered a 30 day required action statement (RAS) in
accordance with TS 3.3.3.2 due to the inoperability of RCIC from
the RSP. The inspectors reviewed TS 3.3.3.2 and determined that
the appropriate TS actions were taken. The unit shutdown for a
refueling outage on October 11. prior to the 30-day expiration of
the RAS.
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The inspectors discussed the problems encountered in running the
RCIC system from the RSP with the system engineer on November 12.
The system engineer informed the inspectors that the data ,
acquisition system used to monitor various parameters associated '
with the system indicated that a possible problem existed with the i
governor valve (lE51-F523). The inspectors observed that an MWO i
was initiated on May 22. 1997. to replace the Unit 1 RCIC governor
valve stem with an inconel stem. The inspectors later confirmed :
that this work was completed. (The Unit 2 RCIC stem was upgraded
during the last refueling outage in 1997.)
However. with the new stem installed, the valve could not be -
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manually moved into the open position. The original valve stem
was reinstalled into the valve because the valve could be moved to -
the open position during the "as-found" inspection. Although this
action did not correct the movement problem, it did rule out the
possibility of the problem being caused by the stem. j
Further troubleshooting activities by maintenance and engineering
personnel revealed a scale deposit in the bottom portion for the
control valve body (valve bonnet bore). The scale was not readily
visible and was identified with the use of a magnifying glass, i
The scale caused the first steel washer and subsequent carbon '
washers (spacers) to become positioned at an angle to the valve.
rausing friction on the valve stem. The washers realigned
properly during valve movement in the closed direction but ;
presented friction to the valve stem for the open direction. This
scale material was machined out. The new stem was placed into the
valve, as aart of a pre planned outage activity. This activity
resolved tie movement problem. The system engineer indicate) that
the scale buildup was probably due to impurities in the steam and t
years of operation.
The inspectors reviewed the root cause analysis and noted that the
system engineer concluded that the restriction to the governor
valve movement was not due to the governor valve stem corrosion.
The restricted movement was due to mis-aligned carbon spacers
binding on the governor valve stem in the open direction. The
inspectors observed that the engineer determined that the cause of i
the spacer misalignment was due to a scale buildup in the valve.
The inspectors reviewed Information Notice (IN) 94 66, dated
September 19, 1994. "Overspeed of Turbine Oriven Pumps Caused by
Governor Valve Stem Binding." and Supplement 1 to the IN. dated >
June 16. 1995. The IN identified several sites where corrosion :
between the valve stem and spacers in the Jacking assembly caused '
RCIC failures. The inspectors reviewed t1e licensee's assessment
of the problem described in the IN. Following the IN review. .
dated January 5. 1995, licensee personnel concluded that the
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3roblems described in the IN were not a problem at Hatch. They !
Jased the conclusion on the fact that 3rocedures were in place to
perform the RCIC functional test and t1at calibrations were f
performed once per operating cycle, not to exceed 18 months and i
the procedure for major inspection and overhauls was performed
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every 6 years. Additionally, the RCIC performance monitoring .
system would detect malfunctions similar to those described in the e
IN. They also based their conclusion on the fact that the RCIC !
system had a barometric condenser which pulls a vacuum and removes :
the steam from the valve stem gland seals, and trip throttle j
valve area. The assessment of the supplement to the original IN *
stated that no additional events were cited which required further
response to that already stated in IN 94 66, and no further i
licensee action was required. Licensee personnel stated that for 1
the RCIC inspection completed during the 1994 Unit I refueling ,
outage, no corrosion or buildup of mineral de)osits were observed. :
Licensee personnel summarized the assessment )y stating. " Plant .
Hatch surveillances inspections, and calibrations, along with i
installed monitoring equipment for the RCIC system. provide the
necessary detection to prevent the described event from occurring ,
at Plant Hatch." ,
The inspectors observed that the licensee had identified a problem fi
with the Unit 1 RCIC governor valve on April 29, 1996, during
startup following the refueling outage. In this instance. the +
governor valve stuck nearly closed for about 92 seconds then ;
released and the system then operated properly. This problem was L
being monitored by operations and the system engineer. No
additional problems were identified until October 9. 1997. The
'
inspectors observed that for the two recent Unit 1 RCl,: 3roblems.
the RCIC monitoring detection system identified both pro)lems. !
The inspectors conducted a review of the performance history for
the governor valve for both units and did not find evidence of ;
other RCIC valve sticking problems. The inspectors noted that the
Unit 2 RCIC stem was upgraded during the last refueling outage in
1997. ,
The root cause determination for the most recent valve failure was l
detailed. However, no specific actions were recommended to
prevent recurrence. The inspectors discussed this problem with ,
'
management )ersonnel responsible for the root cause determination
program. T1e inspectors were informed that a review the of the IN l
and recent RCIC problems would be completed to ensure that
-
appropriate actions were taken to prevent recurrence. The .!
ins)ectors were later informed that the maintenance procedures of
bot 1 units would be revised to include monitoring for scale
buildup. ;
P
Enclosure 3
!
i
"
- , . _ _ . , - - . , _ . , , _ . , - . . . ..._-s,...
_ _ - _ _. - - ~ _ . . _ _ _ _- _ _ _ _ _ __ _ _
,
.
I ,
i
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8
! The inspectors were informed that the Unit 1 RCIC system would be _
run from the RSP during startup when reactor pressure achieved l
.
920 )sig. The inspectors verified that the testing activity was !
l on t1e startup schedule and was being actively tracked. The !
inspectors' review of this testing activity was identified as
'
Inspector Follow up Item (IFI) 50-321/97 10-01: Review of Unit 1
RCIC Testing Activities from the Remote Shutdown Panel,
c. Conclusions
i
Operations personnel took the appropriate act ...s for the RCIC
system when it failed an operability test run from the remott,
shutdown panel. Engir.eering and maintenance provided good trouble
shooting support.
!
02.2 Review of Decay Heat Removal (DHR) Systems for Unit 1 Refuelina
a. Insoection Scone (71707) (60705)
The inspectors reviewed procedures 3450 G71 001-05, " Decay Heat
Removal System." Rev. 6. and 3450-E11 010-lS. " Residual Heat i
Removal System," (RHR) Rev. 23. Ed 1: Hnit 1 Updated Final Safety
Analysis Report (UFSAR) Section 10.4: and TS Section 9.1.3: and
conducted a partial walkdown of the systems. The walkdown and
review were completed to verify that system alignment and
availability for use as the decay heat removal of the Unit I
reactor vessel and the spent fuel pool were correct,
b. Observations and Findinns
' 3 inspectors observed that the A loop of the RHR shutdown
cooling system was available and in standby for use as the initial
heat removal system. System components and instruments were
verified to be operable and in standby. The inspectors later
observed that the DHR system was in service and appropriately
controlling the decay heat load.
The inspectors walked down the DHR system and observed that system
components were in good working condition. The inspectors
observed later that the RHR system was taken out of service and
the DHR system was in service and appropriately cooling the spent
fuel pool and reactor vessel. The inspectors verified that the ;
standby diesel generator (DG) for the DHR system arrived on site
prior to the use of the DHR system, as specified in the Unit 1
Outage Safety Assessment.
The inspectors observed the electrical connections made for the l
DHR DG and part of the DG testing. The DG test was satisfactorily
completed. The inspectors verified that the local procedure for
starting the DG was conspicuously posted along with the DHR
Enclosure 3
,
i
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g- m.., , . ,- . ,
m- - , . - , , ~ . , . . - - - - - - - . - . - ,
__ . _ _ ._ . _ _ _ _ _ . . _ _ _ -__ _
.
.
..
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9
!
procedure, as required. Operations personnel routinely verified -
that the DHR system was operating properly and operators recorded
pertinent system operating parameters.
The inspectors observed that operations personnel in the main ,
control room had a heightened awareness of the high reactor vessel l
decay heat load. Administrative controls restricted work in some ;
control room panels until the reactor cavity was flooded.
Operations management. supervision, and control room operators
demonstrated a safety conscious awareness for unit operation
during times of high decay heat loads,
c. Conclusions
The inspectors concluded that Unit I systems used for reactor
vessel decay heat removal were in good operating condition and :
controlled unit decay heat. The UFSAR. TS. Unit 1 Outage Safety !
Assessment, and system procedural requirements for decay heat i
removal system availability were met. Operations management. ,
supervision, and control room operators demonstrated a safety !
conscious awareness for unit operation during times of high decay i
heat loads.
02.3 Unit 1 Drywell Inspection Follcwina Refuelino Outace
a. Inspection Stone (71707.1
The inspectors reviewed procedures 34GO 0PS 028-IS. "Drywell '
Closeout." Rev 6. and 52GM MME 007 05. " Maintenance Drywell
Closeout." Rev. 3. and-conducted a walkdown of the drywell tc
review general material conditions. housekeeping. and systems and
components for indications of leakage.
b. Observations and Findinas .
During ti e drywell walkdown prior to the final Drywell closecut
activitics following the Unit I refueling outage. the inspectors
observed that the general material conditions were good. The
f licensee had installed new mirror-backed insulation on the reactor
!
vessel as part of its drywell insulation upgrade program. The new
insulation was properly installed, securely intact, and in
excellent condition. Overall housekeeping was good. Some small
pieces of taae were observed and were collected immediately. The
inspectors o) served that some work activity was still ongoing at *
the ll4-foot elevation. There were no indications of system or
component leakage.
The inspectors later reviewed the final drywell closecut
3rocedures completed by operations and maintenance personnel,
ieither procedure identified problems or deficiencies that
Enclosure 3
- . - - . -, . - . - - . . . - - ,
__ _ _ _ _ _ _ _ _ _ _ _ _ ________ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
.,
.. ,
,
10 !
'
required attention,- The inspectors observed that the completed
procedures were reviewed by the appropriate level of supervision. '
. c. Conclusions
The inspectors concluded that material conditions and general
housekeeping in the Unit 1 drywell just prior to the final drywell >
closcout were good. The new mirror backed insulation installed on 4
the reactor as part of the drywell insulation upgrade initiative !
was in excellent condition. No indications of system or component
leakage were observed.
,
04.2 Failure to Meet TS Surveillance Reauirement Prior To Withdrawal of
a Unit 1 Control Rod - In Cold shutdown .
a. InsnectionScoDe(71701).
The inspectors reviewed
Withdrawal in Shutdown," Revprocedure
6, Significance 34G0 0PS 066 05.
Occurrence Report " Control Rod '
97-4883, and discussed the referenced problem with operations
personnel. ;
4
b. ihservationsandFindinas
The inspectors were informed by operations management that, while !
performing Attachment 5 of procedure 34G0 0PS 006-05 operations
personnel on Unit I withdrew a control rod that did not meet the
. TS requirements for withdrawal. Control rod 10 47 was withdrawn
to position 02, in order to perform Attachment 5. One Rod Out
Interlock and RPIS Functional Test, of the procedure. 1he control j
rod was then fully inserted.
1
TS 3.10.4, Single Control Rod Withdrawal - Cold Chutdown.
identifies several requirements prior to withdrawal of a control
rod. One of the requirements was that section 3.9.5. Control Rod ; '
Operability - Refueling, be met. TS surveillance requirement 3.9.5.2 requires each withdrawn control rod scram accumulator
pressure to be greater than or equal to 940 pounds per square inch ,
(psig). Prior to the withdrawal of control rod 10-47 on '
October 14. accumulator pressure was not equal to or greater than i'
940 psig, as required by the TS. ...e inspectors observed that the
accumulator had been depressurized to atmospheric pressure in
preparation for maintenance activities. t
The inspectors reviewed procedure 34G0-0PS-066 OS and observed
that step 4.3.6 clearly indicated that TS section 3.9.5 must be
. rret whenever a control rod is being withdrawn whi!c in cold
s utdown. The procedure also indicated that Attachn.ent 4.
Accumulator Pressure. RPIS Response, and Withdrawal Time, was to
-
be completed each time a control rod is withdrawn. Attachment 4 :
Enclosure 3
'
,
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-[ w w w -w .=:-t, -4 * + --- m +
---T- -1 -r'sr , - r e t- w----- r--r- u rd E er -. NW e se v 'e 'e"*~-
- _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
'
l
i
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11
lr
clearly indicated that the control rod accumulator pressure must .
be greater than 940 psig prior to withdrawing a control rod. l
The inspectors reviewed licensee performance for TS surveillances !
and observed that this was a repeat of a violation that occurred
'
on April 21. 1996. when a control rod was withdrawn on two
occasions with the scram accumulator pressure less than the ;
TS required 940 psig. The licensee identified that a !
less than-adequate procedure was the root cause of that violation. '
The corrective actions included revising the procedure, and
discussing the )roblem at Beginning Of-Shift-Training sessions. i
Additionally, tie TS issues associated with the problem were i
discussed in regularly scheduled training for licensed operators.
l
The inspectors concluded that the licensee's previous corrective 1
actions were adequate to prevent recurrence of a problem similar ;
'
to the April 1996 problem. In this case, however, an operator was
told to complete Attachment 5 of the procedure. The operator
understood that all other procedure steps and actions were
completed, when, in fact, they were not completed. The failure to l
'
review the total procedure prior to its use was not in accordance ,
with the licensee's administrative procedure for procedure usage.
, The inspectors observed that several administrative controls were ;
not implemented and contributed to the problem. Procedures i
i required a pre evolution briefing prior to any control rod 1
'
movement. A pre evolution briefing was not conducted.
Communications between operators for the % assignment were not !
, clear with respect to whethec or not all procedure steps had been
l completed. A peer checker was . d prior to the control rod '
l movement, however, both the operator and peer checker failed to
i review the procedure or to recognize light indications in the
- control room that indicated that the control rod accumulator was
depressurized and inoperable. The inspectors observed that
~
i operators were knowledgeable about the TS requirements for an
o)erable control rod. The licensee later informed the inspectors
t1at some of the control rod accumulators had been depressurized
in preparation for maintenance activities. However, the
accumulators were not tagged or otherwise identified as being
inoperable. Operations management stated that. in the future. any
'
depressurized or otherwise inoperable control rod accumulator .
would be electrically disabled to prevent movement. The licensee '
was evaluating 3rocedure revisions to clarify the disabling
requirement. T1e inspectors reviewed the licensee's immediate and :
proposed long term corrective actions to prevent this problem and
determined that the corrective actions were satisfactory. *
l
There was little safety rignificance associated with the recent !
violation with respect to an inadvertent criticality of the
,
L Enclosure 3
,
- , - , - -
- . - - - . - - . . - . - . . - - .= _ - _=
_ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
,
3
12
reactor core. The control rod was withdrawn to position 02 and ,
then reinserted within a short period of time.
The overall site surveillance program has been strengthened since
the previous similar viol 6 tion. Operator performance with respect
to conducting TS required surveillances since the previous
violation was excellent,
c. Osclusions
The inspectors conclud2d that poor operator performance with
respect to procedure usage, as well as other administrative
controls that were not completed, led to the problem. The failure
to correctly complete the TS surveillance requirement to withdraw
a control rod while in Cold Shutdown was identified as V10
50 321/97-10 02: Failure to Meet TS Surveillance Requirements
Prior to Withdrawal of a Control Rod While in Cold Shutdown.
07 Quality Assurance in Operations
07.1 Review of Sianificance Occurrence Reports (SORS) and Corrective
ofLlDai
a. Inspection Scone (71707) (405Q0).
The inspectors reviewed procedure 10AC-MGR-004-OS " Deficiency
Control System." Rev. 10. and Significance Reports generated
between October 12 - 18. 1997, to determine if the SORS were
properly classified and raised to the proper level of attention
for corrective actions.
b. Observations and Findinos
The eight SORS reviewed by the inspectors were correctly
classified in accordance with the procedure. Deficiency cards had
been generated. reviewed by appo]riate personnel, and the
deficiencies had been raised to tie prcper level of attention for
resolution. The SORS were being correctly tracked by the
commitment tracking system. The SORS indi';ted that the
responsible department were to conduct an investigation to
determine the root cause of the problem. The department's
response was to recommend actions to correct the problem and
prevent its recurrence.
On October 30. the inspectors attended a licensee corrective
action meeting, lhe meeting was held with responsible site and
department management personnel to discuss an SOR that required a
10 CFR 50.73 report. The inspectors observed that the discussion
was open and self-critical of 3rocedures and personnel performance
that caused the deficiency. T'le root causes and corrective-
Enclosure 3
-. - . - -
_ _____ __ ____ ____ _ _ _ - _- _ _--__ _ _ _ __ ___ ____ __ ___- __ _ _-_ -__ - _ - _ _ _ _ _ _ _ - _ _ _ _ .
4
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,
13
actions were discussed in detail. As a result of the meeting,
several corrective action initiatives were identified.
c. Conclusions
The eight SORS reviewed by-the inspectors were correctly
classified and w!re being correctly tracked by the connitment
tracking system and plant procedures. The recommended schedule
for determining root cause and reconmending corrective action was
appropriate for the deficiencies. SORS were receiving senior
level management as well as department level management attention.
08 Miscellaneous Operations Issues (92901)
08.1 (Closed) Violation 50 321, 366/97-01-01: Failure to follow
Procedure - Multiple Examples.
The licensee failed to establish the compensatory measures
required by procedure 31G0 0PS Oll 05. Fire Hazard Analysis (FHA)
Operating Requirements. Rev. 0, for degraded fire protection
components specifically an hourly fire watch for inoperable or
degraded fire barrier assemblies in January 1997.
The licensee's response to this violation dated April 21. 1997.
indicated that the individuals involved were disciplined in '
accordance with the company's positive discipline program and
counseled regarding the potential consequences of their actions. ,
Although there was no direct evidence of counseling. the licensee
did produce a " Site Management Review Sheet," signed by managers
of affected departments that the corrective actions described in
the response to violation had been completed.
Based upon the inspectors' review of licensee actions, this
violation example is closed. Other examples of this violation are
closed in sections M8.1. E8.1, and F8.1. One exam
violation was closed in section P8.1 of IR 50 321,ple of this
366/97-03,
08.2 (Closed) licensee Event Renort (LER) 50-321/97-05: Control Rod
Partially Withdrawn Without Pressure in Scram Accumulator.
This LER is discussed in Section 04.2 of this IR. Based upon the
inspectors review of licensee actions, this item is closed,
t
Enclosure 3
.__. -. _ - - - . .. -
_ _ _ _ _ _ _________________________ _ ______ _-
.
14
11. MaintRDanta
M1 Conduct of Maintenance
M1.1 Maintenance Observations durina the Unit 1 Refuelina Outaae
a. Inspection Scone (62707)
The inspectors observed or reviewed all or portions of the
following work activities:
- Maintenance Work Order (MWO) 1-97-1006: Remove Existing
Operator. Install larger Operator and Determine New TOL
Setting (18212 F016)
- MWO 1-97-1874: Install New Valve (IB21 F016)
- MWO 1-97-1007: Cutout Valve, Prep for installation and install
nevs valve (IB21 F019)
- MWO l-97-1008: Determine New TOL Setting (IB21 F619)
- MWO l-97-1011: Determ/ Modify Circuit F031B
- MWO l-97-1010: Determ/ Modify Circuit F031A
- MWO l-97-1091: Upgrade RR flow transmitters
- MWO 1-97-1921: Install Instrument Upgrade Kits (6) and replace
transmitters
- MWO 1-97-1088: Calibrate / Setup New APRM Recorders
- MWO 1-96-4622: Weld Instrument Tray East Cableway. Install New
Junction Box, and remove Insulation from trays
b. Observations )nd Findinas
The inspectors found that the work was performed with the work
packages 3 resent and being actively used. Procedure revisions
verified ]y the inspectors were correct. Supervisory oversight
was evident.
c. Conclusions
Maintenance activities reviewed or observed were completed in a
thorough and professional manner. Supervisory oversight was
evident. No significant deficiencies were identified by the
inspectors.
M1.2 Imnlementation of New Fmeroency Core Coolina System (FCCS) Suction
St rainers in Unit 1 (DCR 96-040)
a. Inspection Scone (62707) (37828) (37700)
The inspectors reviewed DCR 96-040, Upgrade ECCS Suction
Strainers: MWO packages 1-97-2418. Install Plate for Penetration
204A Torus, 1-97-0927. Diver Sup> ort Work To Install New ECCS
Strainers. 1-97-1038, Replace RH1 A Suction Strainer,1-97-It.42,
Enclosure 3
_.
_ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ ____ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ ___ _ ___ _ __ _ _
..
,
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Replace RHR 8 Suction Strainer, 1-97 1043. Replace RHR C Suction I
Strainer,- 1 97-1044. Replace RHR D Suction Strainer, 1-97-1045, '
Replace CS A Suction Strainer, and 1 97-1046B Replace CS B
Suction Strainer: and observed work in progress. The inspectors -
also reviewed Administrative Control Procedure 10AC MGR 021 05, '
" foreign Material Exclusion," Rev. 1.
b. Observations and Findinas
. The ins)ectors noted that the DCR and MWO work packages were
thoroug1 and detailed. Health Physics coverage for routine work ,
activities, such as contamination control (donning and removal of -
protective
in and outclothing), of the torus equipment staging, led.andHowever
was well-control movement
HP of equipment
deficiencies were identified and are discussed in Section R1.2 of i
this inspection Report. ,
.
The ins)ectors observed activities to transport some strainers to
the wort location from the warehouse str 'ng area. The inspectors
observed that the concern for personnel safety as well as
equipment integrity was continuously maintained.
The inspectors observed that two ECCS strainers were installed per
pump suction. Eight strainers were installed on the four pump
suctions associated with the RHR system and four for the two Core
Spray pump suctions for a total of 12 ECCS strainers. New elbow
piping was also custom designed for each of the installed ECCS
"
strainers. The design required the drilling of eight additional
holes in the mounting flange on the 'T' suction for attaching the ,
4
custorr. designed elbow aiping. These additional holes were drilled ,
equi-distant between tie eight existing holes.
One of the ins)ectors entered the torus and observed ongoing work
activities. T1e inspector nbserved that items taken into the
torus were logged and tracked by designated personnel in
accordance with procedure 10AC-MGR-021-05. The inspector was
informed by engineering personnel that the suctinn opening at the
flange area where the ECCS strainer would be attached was covered
4 with a foreign material exclusion (FME) barrier. This barrier
prevented metal shavings from the underwater drilling operations
, and other debris from entering the suction flowpath to the pumps.
Additionally, the inspector was informed that magnets, in
conjunction with the desludging underwater vacuum device, was used
to catch shavings generated by the drilling operations. Shavings
that fell to the underwater floor of the torus were removed during
the final desludging operations, as discussed in Section E2.3 of
this inspection report
Workers and divers were cognizant of their work responsibilities.
Attention to detail for personnel safety was ongoing. Site and
Enclosure 3
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16
corporate engineering personnel responsible for the work activity
were routinely at the work location and provided oversight and
direction, as needed.
The inspectors observed that some engineering issues presented
installation challenges. These were )rimarily due to strainer
size close tolerances, equi) ment proalems, and other
interferences associated wit 1 the installation of the new
strainers and the mounting of the custom designed elbow piping.
Due to these challenges. it was necessary to make field changes to
the original design. The field changes included the following:
- The Core Spray B left elbow flange ()enetration X2088 left) was
attached to the T suction with 14 )olts. The original
designed specified 16 bolts. Two holes could not be drilled
due to structural interferences. Five consecutive holes were
enlarged it. the elbow flange to enable alignment with existing
hoks in the 'T' flange. Similar alignment problems existed
with Core Spray A right elbow flange (penetration X208A right).
Six consecutive holes were enlarged on this elbow flange and
three holes could not be drilled. This elbow flange was
attached with 13 bolts.
was abandoned due to the inability to extract a broken drill
bit from the partially drilled nole in the T flange. This
elbow flange was attached with 15 bolts.
. The left Core Spray B stainer was installed with a rotation
angle of 67 degrees above the horizontal due to structural
interference versus the 30 degrees specified in the original
design.
The inspectors reviewed these field change requests and identified
no deficiencies. The field changes received the appropriate level
of review,
c. [onclusions
lhe inspectors concluded that the work activities to move new ECCS
suction strainers from the warehouse to the torus proper was well
controlled. Health physics and engineering personnel provided
good oversight and direction. FME control was excellent. Onsite
engineering issues were resolved in an appropriate and timely
manner.
Enclosure 3
.
$
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17
M1.3 Inservice Insnection
a. InsDection Stone (IP 73753)
To evaluate the licensee's inse.,1ce Inspection (ISI) program and
the program's implementation the inspectors reviewed selected
procedures and records and observed work in progress.
Observations were compared with ap)licable procedures, the Updated
Final Safety Analysis Resort (UFSAR). and American Society of
Mechanical Engineers (ASiE) Boiler and Pressure Vessel (B&PV) Code
Sectirns V and XI. 1989 Edition. No Addenda (89NA).
Procedur' reviewed included: MT H 500. " Magnetic Particla
ExaminatioJ Rev. 9: PT-H-600. " Solvent Removable. Color
Contrast, or Fluorescent Liquid Penetrant Examination Procedure."
Rev. 7: UT H 400. " Manual Ultrasonic Examination of full
Penetration Welds (Greater than 0.200 inch)". Rev. 16: UT-H 402.
" Ultrasonic Examination of Full Penetration Austenitic Welds."
Rev. 0: VT-V-710. " Visual Examination (VT 1)." Rev. 10: and
VT-H-730. " Visual Examination VT-3." Rev. 10.
Specific areas examir.ed included the following observations:
magneti, particle (MT) examination of weld No.1821-1FW-18B 4:
liquid p;netrant (PT) examination of weld No. 1G31-1RWCV-60-15A:
manual ultrasonic (UT) examination of weld No.1B31-lRC 28A 12:
data acquisition and analysis activities associated with automated
UT examination of piping welds using the SMART system: data
acquisition and analysis activities associated with automated UT
examinations of reactor vessel welds using the GERIS 2000 system:
data acquisition and analysis activities associated with remote
visual (VT) examination of the reactor vessel internals: and data
acquisition and analysis activities associated with automated UT
examination of the reactor core shroud using the Tecnatom. SA
TEIDE system. The inspectors also reviewed selected completed
examination reports: and reviewed the Repair and Replacement (R/R) '
Program.
The inspectors performed an independent evaluation of indications
to confirm the licensee's ISI examiners * evaluations.
The inspectors reviewed records for the nondestructive examination
(NDE) personnel and equ1pment utilized to perform ISI
examinations. The records included: NDE equipment calibration
and materials certification; and records attesting to NDE examiner
qualification, certification and visual acuity.
b. Observations and Findinos
The inspector determined that the procedures reviewed were concise
and well written. Observed and reviewed inservice examinations
Enclosure 3
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_ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
,
.
18
were conowted in accordance with approved procedures by qualified
and certified examiners usiig certified / calibrated equipment and
materials.
Indications were identified by automated UT in the V-5 and V-6
welds of the core shroud. These indications correlated well with
the indications noted by the remote visual examination of the same
welds conducted during the last Unit I refueling outage. The
inspottors determined that these indications were envelo)ed by the
analysis conducted following the visual examination of tie last
Unit I refueling outage.
A linear indication was identified by remote visual examination in
the core support plate. This indication was evaluated by the
licensee ar'd determined to be enveloped by BWRVIP-07, and
therefore was classified "Use As Is." The inspectors determined
that the licensee's evaluation was thorough,
Linear indications were also identified adjacent to the welds
joining the N2B and N2D jet pump riser elbows to their respective
thermal sleeves. During a subsequent telephone call, corporate
engineering personnel stated that they would submit a separate
report supporting the evaluation that the linear indications were
not an operability problem.
The licensee, by letters HL-5271. dated December 2. 1996, and HL-
5319. dated March 7, 1997, requested NRC relief from the repair
and replacement aspects of the Containment Rule for a period of
one year. By letter dated May 16, 1997 the NRC granted the relief
to September 9. 1997. The licensee, by letter HL-5449. dated
August 8. 1997 requested relief from compliance with the
Containment Rule relative to the use of ASME Section XI, 1992
Edition with 1992 Addenda for Class MC components for Code
activities other than examination recuirements. The NRC, by
letter dated October 16. 1997, deniec the request. The licensee
had implemented the Containment Insoection Rule R/R program by
issuance of: 42EN-ENG-014-0S. "ASME Section XI Repair /
Replacement," Rev. 10, dated September 9. 1997; 51GM-MNT-019-05.
" Painting and Coating Procedure." Rev. 8. dated October 13. 1997:
and SIGM-MNT-020-05. " Painting and Coating Procedure: Drywell and
Torus Area," Rev. R. dated October 13. 1997.
Licensee procedure 42EN-ENG-014-0S. Rev. 10. dated September 10,
1997 referenced the "lSI Program and Relief Requests" for the
applicable ASME Code Section-XI edition and addenda. The ISI
program incorrectly identified 89NA as the applicable edition and
addenda for ASME Section XI. instead of the 1992 Edition. After
some discussions, the inspectors determined that the incorrect
reference was a docum_atation problem. The licens& indicated
Enclosure 3
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I 19
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that it planned to revise procedure 42EN ENG-014 05 to include the
applicable code edition and addenda references.
c. Conclusion
Observed or reviewed inservice inspection activities were
conducted in accordance with procedures, licensee commitments, and
regulate y requirements.
M1.4 . Main Transformer Backfeed Activity (Unit 1)
a. Inspection Scooe (62707)
The inspectors observed planning and coordination activities by
the licensee for backfeeding power through the Unit 1 Main
Transformer. The backfeed was accomplished to facilitate
preventive maintenance on 10 Start-Up Transformer (SUT).
b. Observations and Findings
The ins)ectors reviewed procedure 52GM S11-001-15. "Back Feed of
Unit 1 iain Sank Transformer." Rev. 2. The procedure provided
specific instructions for personnel regarding equipment usage,
3recautions and limitations and detailed steps for isolating the
dain Transformer prior to the backfeed. The inspectors attended
two pre-enlution briefings held by operations and maintenance
personnel in preparation for backfeed activities. Coordination of
the briefings by operations, maintenance, and substation
maintenance personnel was professional and thorough. While
o)erations placed the main transformer in backfeed. the inspectors
o3 served that appropriate guidelines wre implemented by personnel
in the installation and removal of main transformer grounds and
insulation, and in checking for ground electrical currents.
Operations provided good oversight on establishing the necessary
equipment clearances to remove the ID SUT from service.
c. r;onclusions
Operations and maintenance personnel interfaced effectively to
resolve scheduling conflicts that emerged during the two
pre-evolution briefings. The inspectors concluded that the
licensee exhibited good overall planning and oversight throughout
the backfeed activity. Operations provided good oversight on
establishing the necessary equipment clearances to remove the ID
SUT from service.
Enclosure 3
-__ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _-
"
.9
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20
i JJ 1E 4160-Volt Circuit Breaker Failures
L h , action Scone (62707).
... inspectors observed the licensee's corrective maintenance
activities and actions taken in response to a serles of failures
of safety related 4160-volt circuit breakers in the Uni.1
emergency switchgear.
b. Observations and findinas
On October 31. 1997, the normal supply circuit breaker to the
IF emergency switchgear failed to close when transferring the
emergency bus from the alternate to normal supply following
testing. The inspectors reviewed the MWO initiated in response to
this failure. Maintenance personnel were unable to du)licate the
failure of this circuit breaker (Westinghouse Type 50 dip 350), and
conducted preventive mainterance in accordance with procedure
52PM-R22-001-05, "4160-Volt AC Switchgear and Electrical
Components Preventive Maintenance," Rev. 13. Ed 1. After cleanirig
and lubricating, the breaker operated smoothly. However the
licensee determined that the breaker should be replaced. The
fa d ed breaker was removed and crated for shipment to an
ir pendent laboratory for testing and root cause determination.
Maintenance personnel documented an apparent root cause as " lack
of lubrication and exercise" on MWO 19702869. The inspectors
discussed the apparent root cause with both site maintenance
personnel and corpora +e engineering. One possible root cause was
given as " hardened lubrication material," i .e. . grease, Pending
the findings of the laboratory, the licensee had been unable to
determine the root cause of this failure.
On November 5. 1997, the 1C Residual Heat Removal (RHR) pump moto-
circuit breaker (Westinghouse Type 50DHP250) failed to close when
given an auto start signal as 3 art of the RHR-Low Pressure Coolant
injection (LPCI) Logic System r unctional Test (LSFT). The
inspector observed maintenance activities initiated under MWO
19702987. The inspectors observed that maintenance personnel
performance in ide'n tifying this problem was good, and
documentation in the MWO was thorough. The ins)ectors found that
cleaning and/or lubrication of the sliding braccet assembly was
not previously conducted as part of the licensee's preventive
maintenance (PM) program for 4160-volt circuit breakers
Westinghouse had issued Technical Bulletin ESBU-TB-97-04 in May,
1997, to recommend PM activities that could be conducted or
incor) orated into existing procedures to cover the motor cut-off
switc1 assemM y. The inspectors observed that the licensee had
not yet im)lemented the technical bulletin recommendations.
However, t1e licensee was preparing to solicit vendor cupport
based on problems with Westinghouse 4160-volt circuit breakers at
Enclosure 3
. _ _ _ _ _ _ _ _ - _ _ __ _ _ _ _ _ _ _ _ - _ _ _____- _
.
21
other utilities. Full implementation was planned following the
Unit 1 Fall 1997 outage.
The licensee formed an Event Review Team (ERT) to investigate
recent failures of these Westinghouse circuit breakers and provide
recommendations to prevent recurrence. The inspectors reviewed
the ERT interim recommendations. The recommendations included
incor) oration of the Westinghouse technical bulletin actions, and
full 3M actions on a representative sample of Unit 1 safety-
related circuit breakers, including the emergency diesel generator
(EDG) output breakers, normal and alternate sup)1y breakers, and
one or two motor feeder breakers from the 1E. 17 and 1G emergency
busses. The inspectors determined that the ERT recommendations
were reasonable, based on the equipment operating service time and
failure history.
Subsecuently, on November 13, 1997, the IB RHR Service Water
(RHRSk) pump motor breaker failed to close when operators
attempted to place the pump in service. Maintenance personnel
initiated corrective actions, but were unable to find a ]roblem
with the breaker operation after repeated cycling from t1e
switchgear test sth The ERT concluded that after the breaker
had been racked out as part of a previously-conducted LSFT
activity, the breaker had not been racked in correctly and cycled
(field tested). The inspectors and a member of the ERT observed
maintenance >ersonnel racking in this breaker. The rack-in was
observed to )e smooth, and the inspectors determined that it was
improbable that incorrect racking of the breaker could have
contributed to the breaker failure. The breaker had previously
undergone preventive maintenance in March. 1997. This breaker had
not been examined as part of the initial ERT recommendations.
Additior.a1 ERT recommendations, issued November 14. 1997, called
for full cycling of each 4160-volt breaker supplying a motor / load,
and a " start-run-stop and re-start" of each motor. The inspectors
observed that no additional failures occurred.
c. Conclusions
The licensee had taken initial steps to address problems with
Westinghouse Type DHP circuit breakers in July 1997, based on
problems and events at other utilities. The actions and
recommendations of the ERT were considered appropriate. However,
the inspectors determined that additional examination by the
inspectors of the licensee's PM program for these circuit breakers
is warranted based on this series of failures and the tact that
two of the breakers had undergone PM within the past nine months.
This was identified as IFI 50-321, 366/97-10-08: Review of 4160-
Volt Breaker Failure Analysis and Preventive Maintenance Program.
Enclosure 3
l
1
-__ - - _ _
_ _ - - _ _ _ - - _ _ _ - - - - - _ _ _ _ - _ - _ _ _ _ _ _
4
4
22
M?, Maintenance Procedures and Documentation
M3.1 Surveillance Observations
a. Insoection Scope (61726)
The inspectors observed all or portions of the following Unit 1
and Unit 2 surveillance activities:
. 345V-R43-006-1S: EDG 1C Semi-Annual Test, Rev. 11
- 42SV-lET-001-15: Primary Containment Periodic Type B and C
Leakage Test, Rev. 17
- DI-0PS-57-0393N: Outage Safety Assessment, Rev. 7
. 42SV-R42-009-05: Combined Service and Modified Performance
Test, Rev. 1
. 52SV-R43-001-05: Diesel Alternator and Accessories Inspection,
Rev. 13
. 341T-N30-004-15: Turbine Overspeed Tria Test, Rev. 1
. 345V-C51-001-lS: SRM Functional Test, Rev. 7
- 341T-N21-003-IS: RFPT Weekly Test, Rev. 4
- 42IT-TET-006-1S: ISI Pressure Test of the Class 1 System and
Recirculation Pump Runback Test Rev. 9
b. Observations and Findings
The inspectors observed that, in general, personnel performing the
tests were knowledgeable of their job function, used good
communication techniques, and followed plant procedures
Supervisory and engineering oversight was good. However, some
surveillance deficiencies were noted and are discussed in sections
02.1. 04.2, and M4.1 of this report.
c. Conclusions
For the surveillances observed, 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.
Exceptions are noted above.
M4 Maintenance Staff Knowledge and Performance
M4.1 Incorrect Placement of Jumoer durina Unit 1 Local Leak Rate Test
(llRT) Activities
a. Inspection Scooe (61726) (62702)
The inspectors reviewed documentation and held discussions with
licensee personnel associated with the initiation of a Group 1
isolation signal due to the incorrect niacement of a jumper. The
Enclosure 3
l
_ - _ - - - - _ - - - _ - - _ - - - - _ _ - _ - _ _ _ _ - - - _ _ - _ _ _ _ ----_-_ _
, . - - - - .
.
,
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1
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documentation reviewed included surveillance procedure
-42SV-TET-001-15, " Primary Containment Periodic Type B and C_-
Leakage Tests." Rev. 17: administrative control procedure
00AC-REG-001-05. " Federal and State Reporting and-Federal Document
Posting Requirements." Rev. 5: dep6Ptmental instruction
DI-0PS-31-0596N. " General Guidelines for Use of Jumpers and
Links." Rev. 0: and a computer printout of the Safety Parameter
display system-(SPDS) magnetic tapes. The inspectors also
reviewed portions of the LLRT training program requirements,
b. Observations and Findinas
The inspectors observed on October 30 during a control room tour,
that a Group 1 Primary Containment Isolation Signal (PCIS) was
initiated as a result of the incorrect placement of a-jumper
during LLRT activities. Surveillance procedure 42SV-TET-001-IS
required that jumpers be placed in control room panels in order to
keep designated solenoids energized following the completion of
the LLRT. One jumper was to be placed in control-rocin panel
1H11-P602 and the other jumper was to be placed in Janel
1H11-P628. The LLRT technician erroneously placed )oth jumpers in
'
aanel 1H11-P60_. The incorrect placement of the 2nd jumper-in the
3602 panel caused : everal fuses to function which generated a
Group 1 isolation signal.
Operations personnel initially thought that all valves in the
Group 1 isolation logic were closed except for the Recirculation
Pump System Sample valve 1831 P019. Based upon that assumption,
operation's supervision made the determination that the event was
an Engineered Safety Feature (ESF) actuation and was reportable
under 10 CFR 50.72.
'
Nuclear Safety and Compliance (NSAC) personnel subsecuently
reviewed the safety parameter display system (SPDS) cata and made
the determination that the recirculation pump system sample valve
was closed before the receipt of the Group 1 isolation signal.
This made the event non-reportable and the licensee withdrew the
10 CFR 50.72 report on November 5. based upon this review.
NSAC 3ersonnel 3rovided the inspectors a copy of the printout of
the S)DS data tlat indicated which valves and relays that changed
states. The inspectors determined that NSAC personnel correctly
identified that all valves were closed prior to the generation of
the Group 1 isolation signal. Therefore, the event was not
reportable.
One LLRT technician who ) laced the' jumpers was an operations
person who had attended _LRT training. A control room operator
performed the peer check for the placement of the jumpors. As
part of the licensees corrective actions-the technicians were
>
Enclosure 3
., ..
.
,
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24
counseled and suspended from the performance of further LLRTs
until retraining was completed. Additionally, other members of
the LLRT team were provided refresher training on departmental
instruction Dl-0PS-31-0596N. The inspectnrs reviewed the
corrective actions and determined that they were appropriate.
The inspectors discussed the incorrect placement of the jumper
with the control room operator (CRO) who provided the peer check
for the LLRT technicion. The technician gave the CR0 the
im)ression that both jumpers were to be placed into the same
ca)inet (1H11-P602). During the peer checking of the second
jumper, the CR0 did not fully read the instructions in the
surveillance procedure. As a result, the CR0 did not discover
that the jumper was placed in the incorrect cabinet. This failure
to read the procedure instructions prior to performing actions was
contrary to the administrative guidance for procedure usage.
The inspectors reviewed the LLRT training program requirements and
discussed the content of the program with the licensee's
maintcnance instructor who developed the lesson plans. The
inspectors observed that jumper placement techniques were part of
the training requirements.
The inspectors reviewed the surveillance procedure and noted that
the procedure clearly indicated where the jumpers should have been
placed. In this case one operator apparently misread the
procedure and the sectnd operator failed to correctly perform a
peer check p:'ior to placing the jumpers.
c. Conclusions
The inspectors concluded that a lack of attention to detail was a
contributing factor for the incorrect placement of a jumper during
an LLRT activity. The inspectors also concluded that because all
the valves were already closed, this error had little safety
significance. The inspectors were not aware of other jumper
installation problems that occurred during the Unit 1 refueling
outage. Based upon the inspectors' review of licensee actions.
this licensee-identified violation constitutes a violation of
minor safety significance and is being identified as Non-Cited
Violation (NCV) 60-321/97-10-03: Jumper Placament Error During
Unit 1 Testing Activities. consistent with Section IV of the NRC
Enclosure 3
_ ____ ___ ________- -_ - _____________ _ _
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25
M4.2 Primary Containment Periodic Tvoe B and C Leakaae Test for Unit 1
. a. Inspection Stone (61726) (62707)
The inspectors observed selected ongoing work activities and
reviewed completed test and maintenance results to verify that
test, plant procedure, and regulatory requirements were met.
b. Observations and Findinas
During the current Unit 1 refueling outage the licensee conducted
approximately 77 type B (Seals and Penetrations) ar.J 137 type C
tests (Valves). The inspectors observed that there were seven
type B test failures and 12 type C test failures. Valve seat
leakage, worn valve seats and required adjustments of some valve
linkage contributed to the failures. The inspectors reviewed the
applicable MWO work packages observed selected work conducted to
implement repairs and retests and verified that the post
maintenance test results were satisfactory.
The inspectors observed that applicable procedures were used
during_the tests and maintenance work activities, work packages
were available at the work location, test personnel were
knowledgeable of their job function, and supervisory personnel
provided oversight when required.
c. Cnnclusions
The inspectors concluded that Unit 1 Periodic Type B and C Leakage
tests and required corrective maintenance were performed per
applicable procedures with the exception documented in
Section M4.1. The final test results met plant procedure and
regulatory requirements. Supervisory oversight was evident.
M8 Miscellaneous Maintenance Issues (92700) (92902)
M8.1 (Closed) Violation 50-321. 366/97-01-01: Failure to Follow
Procedure - Multiple Examples.
Licensee personnel failed to follow procedure 57CP-CAL-108-15.
General Electric Type IAC and Westinghouse Type C0 Relays. Rev. 9.
while performing a calibration of Type IAC and Type C0 Overcurrent
Relays in February 1997.
The licensee's response to this violation. dated April 21. 1997,
indicated that the individuals involved were disciplined in
accordance with the company's positive discipline program and
counseled regarding the potential consequences of their actions.
Also, the necessary additional changes to the settings for relays
Enclosure 3
. _
.-
.
.
26
IS32-K217-1. -2, and -3 were made. The inspectors verified that
the procedure was revised to reflect these changes.
Based upon the inspectors' review of licensee actions. this
violation example is closed. Quier exam
closed in sections 08.1. E8.1, and F8.1.ples One of this violation
example of this are
violation was previously closed in se ' ion P8.1 of IR 50-321.
366/97-03.
M8.2 (Closed) Violation 50-366/97-01-02: Inadequate Procedure for
Calibrating Unit 2 HPCI Time Delay Relay K14
This issue was documented in section M3.2 of IR 50-321, 366/97-01.
The licensee's response to this violation, dated April 21. 1997.
indicated that the event was discussed with the individuals
involved and included an explanation of its causes and
consequences. Engineering and Maintenance procedures which
involved lifting wires or opening links: involved safety-related
systems which use DC, energize to-actuate logic; and assumed that
the affected system would remain operable even with circuit
connections interrupted were reviewed. Two additional procedures
(57CP-CAL-050-1S Agastat Timing Relay Calibration, and 57CP-CAL-
050-2S. Agastat Timing Relay Calibration) were found to have the
same problem as procedure 57CP-CAL-051-2S. The inspectors
verified that the three procedures were revised on June 1. 1997,
to address their adequacy for relay calibration. Based upon the
inspectors * review cf licensee actions, this violation is closed.
III. Enaineerina
E2 Engineering Support of Facilities and Equipment
E2.1 Reviw of Licensee Actions in Resoonse to Generic Letter (GL)
96-06: Assurance of Eoujoment Ooerability and Containment
Intearity Durina Desian Basis Accident Conditions.
a. Insoection Scoce (37551) (92903)
The inspectors reviewed GL 96-06: Design Change Request (DCR)97-005 and DCR 97-006. Thermal Pressure Relief Protection: the
10 CFR 50.59 evaluation for both DCRs: and the applicable work
packages associated with maintenance and engineering act nities to
implement corrective actions on both units.
b. Observations and Findinos
Tne licensee had identified three pipe lines penetrating the
containment that were susceptible to thermally-induced
pressurization and evaluated them for operability for each unit.
Enclosure 3
__--
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.
.
.
.
27
These lines are assocu ,d with penetrations for the residual heat
removal shutdown coolirs (RHRSDC) suction line the drywell floor
drain (DWFD) sump pump discharge line, and the drywell equipment
drain (DWED) sump pump discharge line. The licensee committed to
complete the appropriate corrective actions for these pipe lines
3rior to the restart from the spring 1997 refueling outage for
Jnit 2 and the fall 1997 refuel outage for Unit 1.
The inspectors reviewed documentation used to complete the
appropriate modification on Unit 2 during the spring 1997
refueling outage. The purpose of the modification was to relieve
any thermally induced pressure buildup that may occur in the
w olated portion of the piping.
The inspectors reviewed documentation used to complete the
corrective actions on Unit 1 durinc the fall 1997 refueling ,
outage. The inspectors also discussed the work activity with
licensee personnel and entered the Unit 1 drywell to observe the
work activities and to verify that the work was completed. The
documentation reviewed by the inspectors indicated that the
corrective actions were completed, the systems were returned to
service, and the commitment to complete all corrective actions on
Unit 1 prior to the Unit 1 startup was met.
.
c. Conclusions
The licensee's corrective actions for both units in res]onse to
Generic Letter (GL) 96-06. Assurance of Equipment Opera 3ility and
Containment Integrity During Design Basis Accident Conditions.
were completed within the conmiitted time.
E2.2 Review of Alternate Testina Of Unit 1 Safety Relief Valves
a. Insnection Scone (37551) (62707)
The inspectors reviewed procedure 42SV-TET-001-1S, " Primary
Containment Periodic Type B and C Leakage Test," Rev. 17. and work
package documentation to verify that alternate tests of the Unit 1
Safety / Relief Valves were conducted in accordance with the
procedure and commitment documented in Relief Request RR-V-11.
b. Observations and Findinas
On September 5.1997, the NRC approved the licensee's Relief
Request RR-V-11, regarding Inservice Testing of Safety / Relief
Valves - Edwin I. Hatch Nuclear Plant. Units 1 and 2.
The inspectors reviewed procedure 4 G V-TET-001-15. used to conduct
the testing, and discussed the testing activity with maintenance
and engineering personnel respon;ible for the tests and reviewed
Enclosure 3
_ _ - _ _ _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ -____ ___ _ -
. . -- . - . --
.
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28
the test data. -The inspectors noted that all test data met the
established acceptance criteria.
c. Conclusions
The inspectors concluded that the proposed alternative tests of
the Unit 1 Safety Relief Valves were completed in accordance with
plant procedures and as specified in Relief Request RR-V-11.
Inservice Testing of Safety / Relief Valves - Edwin I. Hatch Nuclear
Plant. Units 1 and 2. All test data met the acceptance criteria.
E2.3 Desludaina and Cleanina of Unit 1 Torus
-a. Insoection Scoce (37551)
The inspectors reviewed licensee actions to inspect and clean the
Unit 1 torus in response to NRC Bulletin 95-02. Unexpected
Clogging of a Residual Heat Removal (RHR) Pump Strainer While
Operating in Suppression Pool Cooling. The inspectors reviewed
procedure 10AC-iGR-021-0S. " Foreign Material Exclusion." Rev. 1.
and observed related work activities,
b. Observations and Findinas
During the current refueling outage. the licensee continued its
ongoing efforts to ensure torus and ECCS suction strainer
cleanliness. The work activities included a diver swim-through
inspection. FME removal and documentation. and post work cleanup
and inspection. One of the inspectors entered the torus and
discussed the cleanup efforts and the as-found condition of the
torus.
c. Conclusions
The ins)ectors concluded that the actions taken to inspect and
clean t1e Unit 1 torus were good. FME controls were properly
implemcated. Management was actively involved. The inspectors
concluded that the small amount of debris found in the torus did
not present a risk for emergency core cooling system suction
strainer blockage.
E2.4 Review of Licensee actions with resoect to Technical Soecification
(TS) Amendment 204 and 145 for Units 1 and 2.
a. Insoection Scoce (37551)-
The inspectors reviewed TS Amendment 204 and 145, for Units 1
and 2. respectively. TS section 3.1.. for both units, and
procedures 34SV-C41-002-1S/25. " Standby Licuid Control (SBLC)-Pump
Operability Test." Rev.12. for Unit 1. anc Rev.17. for Unit 2.
Enclosure 3
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.
.
I
29
The inspectors reviewed the documentation to verify that licensee
actions for the SBLC System were completed within the time
identified in the approved TS Amendments.
b. Observations and Findinas
Technical Specification Amendments 204 and 145 were approved by
the NRC on March 21. 1997. The licensee committed to implementing
these amendments prior to startup from the Unit I refueling outage
and arior to startup from the Unit 2 refueling outage scheduled
for iarch 1997. One item identified in the TS amendments was that
each SBLC pump developed a flow rate greater than or equal to 41.2
gallons per minute (gpm) at a discharge pressure of greater than
or equal to 1232 pounds per square inch (psig). The amendments
changed the discharge pressures from 1201 psig to 1232 psig.
The inspectors verified that the a)plicable sections of the TSs
had been revised in accordance wit 1 the amendments. The
ins)ectors reviewed the a)plicable surveillance procedures for
bot 1 units and verified tlat they were revised and completed prior
to each units startup. The inspectors verified that all the SBLC
pumps met the required flow and pressure requirements.
c. Conclusions
The inspectors concluded that the lice see actions taken to
implement Technical Specification Amendments 204 and 145 for the
Standby Liquid Control System were timely and correct. The
completed :tandby Liquid Control System surveillances verified
that the flow and pump discharge pressure requirements were met.
E2.5 Generic Letter 89-10 Valve Modifications and Hiah Pressure Coolant
inlection (HPCI) lE41-F001 Work Activities
a. Inspection Scoce (37700) (71707) (62707)
The inspectors reviewed DCR 96-005 and the associated 10 CFR 50.59
evaluations. and observed work activities associated with the HPCI
steam supply isolation gate valve 1E41-F001. The placement of
clearance tags associated with the 1E41-F001 valve work activity
was a'so reviewed. Discussions were held with licensee personnel
and the completion of a committed ASME Section XI VT-3 inspection
was verified.
b. Observations and Findinas
The purpose of DCR 96-005 was to provide assurance that safety-
related motor operated valves (MOVs) would meet their safety
function when subjected to the maximum differential pressure
Enclosure 3
._. _ ___-_-__ - _ _ _-
.
.
30
across the valve during normal operation and abnormal events
within the design basis of the plant.
Valves subject to the power uprate conditions were changed to
accommodate the additional loads of the uprated conditions.
The following valves were mod'fied per the design specifications
described in the DCR:
. Main Steam line crain isolation valves 1821-F016 and 1821-F019.
. Reactor Recirculation Pump outlet isolation gate valves
1B31-F031 A and B.
. RHR heat exchanger flush to torus valves 1E11-F011 A and B.
. HPCI steam supply isolation gate valve 1E41-F001.
. HPCI steam supply isolation gate valve 1E41-F002
. HPCI pump discharge gate valve 1E41-F007
. RCIC pump discharge gate valve 1E51-F013
. RCIC trip and throttle valve 1E51-F524
. RWCU inboard isolation gate valve 1G31-F001
Modifications to the valves listed above included replacing the
existing motors aad operators with units of larger capacity,
modification of control circuits and operator gearing,
installation of larger capacity motors and operators, and
replacement of circuit breakers due to larger capacity motors.
The inspectors observed two craftsmen working on the valve seating
for the HPCI steem su) ply isolation gate valve 1E41-F001. The
inspectors observed tlat the piping system had been breached and
the work area was prominently identified as a FME area. The
inspectors also observed that the craftsmen had a FME barrier
installed to prevent dropped tools or other material from enterin,
the piping system.
The inspectors verified the placemenc of a re)resentative sampling
of clearance tags for the 1E41-F001 valve war ( activities in
accordance with clearance 1-97-445. No discrepancies were
identified.
In the licensee's reply to VIO 50-321/96-11-02, the licensee
committed to performing an ASME code required VT-3 inspection on
the HPCI 1E41-F006 valve during the Unit 1 fall 1997 refueling
Enclosure 3
._ _ _ . _ . _ - -
, _ _ _ . _ _ _. . .
.
..
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31-
outaga The inspectors reviewed MWO 1-96-2647 and verified that
the Visual Examination Record VT-3 For Pumps and Valves was
-completed and signed for the performance of a VT-3 examination.
'
,
c. Conclusions
The 10 CFR 50.59 evaluation for the Generic Letter 8910
modification in accordance with DCR 96-005 was a)propriate. *
Foreign material exclusion control for the 1E412001 valve work -
activity was excellent. The placement of clearance tags was good.
The ASME required VT-3 inspection for HPCI valve 1-E41-F006 was
completed satisfactorily.
.
E2.6 Unit 1 Condensate Storaae Tank (CST) Desludaina Operations
a; Insoection Scooe (37551)
The inspectors observed preparation for CST desludge work
-activities on Unit 1. Discussions were also held with licensee
engineering per sonel.
b. Observations and F mdinas
The licensee completed desludging activities in the CST to
possibly improve control rod movement difficulties. One possible
contributor to the problem was suspected to be sludge that had
accumulated in the CST. The CST had not been previously cleaned
The inspectors observed preparation for CST desludging work
activities on October 8 while Unit I was still operating. FME
controls were in place and were properly implemented. Tha
presence of HP was observed and security personnel were present to
provide emergency recovery actions.
A diver entered the CST the following day for a short period of
time but had to be removed due to heat stress. The CST water
temperature was too high. The work activity was curtailed
indefinitely until a different work plan was formulated.
The divers made an entry into the CST subsequent to the Unit 1
- - shutdown for the refueling outage. The divers completed
desludging activities. The following items were recovered from
the Unit 1 CST: a.one-foot long piece of 1/2-inch diameter rope,
green / white nylon rope six inches long, four welding rod stubs,
three pieces of_No. 9 wire (one 2-foot piece and two 3-foot-
pieces).' and about a handfull of miscellaneous chips of paint.
-
The inspectors were informed that very little sludge build up was
observed and may not have been-a major contributor to control rod
.
movement problems. This problem was still being evaluated by
engineering.
Enclosure 3
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_ _ - - - . .. .. .. . . .
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32
c. Conclusions
The initial Unit 1 CST entry by the divers to perform desludging
activities was not well-planned for water temperature conditions,
FME controls were in place and were properly implemented. The
presence of HP was observed and security personnel were present to
provide emergency recovery actions.
.
E2.7 Emeroency Diesel Generator (EDG) Logic System Testino in Resnong
to Generic Letter (GL) 96 01
a, Insnection Scone (37551)
As documented in IR 50-321, 366/97-03, licensee reviews of EDG
logic system testing incorporated into Unit 2 procedures in
response to GL 96-01. " Testing of Safety-Related Logic Circuits."
A licensee review of logic system tests had identified that
emergency switchgear alternate supply breaker ur.dervoltage and
degraded voltage trip logic was not being tested. The inspectors
reviewed Unit 1 procedures and licensee actions taken to
incor) orate the additional logic testing for EDGs and emergency
switc1 gear.
b. Observations and Findinas
The inspectors reviewed Unit 1 surveillance procedures
42SV-R43-021-15. " Diesel Generator 1A LOCA/LOSP LSFT," Rev. 5,
42SV-R43-024-15. " Diesel Generator 1B LOCA/LOSP LSFT." Rev. 5, and 1
42SV-R43 025-1S. " Diesel Generator 1B Logic Tests." Rev. 4. The
inspectors verified that changes made to the logic system
functional test (LSFT) procedures in August, 1997. included steps
for testing 1E and 1F emergency switchgear alternate supply
breaker relay contacts.
The inspectors observed licensee engineering activities to test #
the IF emergency switchgear alternate supply breaker trip logic
using special purpose procedure 42SP-103097-OL-1-1S, " Emergency
Bus Alternate Supply Breaker Trip Test." Rev. 1. This procedure
was implemented due to the main transformer power backfeed, which
aligned the IF supply power from the alternate sup)1y breaker, and
would have forced the 1B EDG to be inoperable if t1e alternate
supply breaker trip logic was not tested. The inspectors reviewed
the special purpose procedure and test results. No discrepancies
were identi fied.
c. Conclusions
The inspectors concluded that engineering personnel had provided
good oversight and coordination in response to the GL 96-01.
" Testing of Safety-Related Logic Circuits," for Unit 1 EDGs and
Enclosure 3
l
1
_ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ ______________ __-_-_- _ __
.
.
33
emergency switchgear. Test results met the appropriate acceptance
criteria.
E3 Engineering Procedures and Documentation
E3.1 Missed Commitment for Unit 2 Technical Soecification (TS1
Amendment 132
a. Insnectton Scone (37551)(92903)
The inspectors reviewed a licensee application for TS Amendment
132, document HL-4546, dated March 2?.1994, which documented the
requirement to add valve 2B21-F021 and downstream piping to the '
main condenser as ASME Class 11: NRC-approved TS Amendment 132.
dated March 17, 1994: and licensee documentation outlining
corrective actions for a missed TS requirement for Amendment 132.
b. Inspection Scope
The inspectors were informed by Nuclear Safety and Com)liance
(NSAC) management that a commitment with respect to a Jnit 2 TS
Amendnent had not been completed during the last Unit 2 refueling
outage. TS Amendment 132 increased the allowable Main Steam
Isolatico Valve (MSIV) leakage and deleted the MSIV leakage
control system. Credit was taken for an alternate leakage control
path from the MSIVs to the condenser through MSIV drain line valve
2B21-F021. The NRC had acce)ted a commitment made by " a licensee
to include the alternate leacage control path in the American
Society of Mechanical Eng.neers (ASME)Section XI Inservice
Inspection (ISI) Program and treat the drain line piping as
Class 2 for repairs and replacement under ASME Section XI. This
commitment was to be met prior to Unit 2 startup following the
Spring 1994 refueling outage.
During the last Unit 2 refueling outage. March 1997, the 2821-F021
valve and about 4 inches of piping were replaced under Design
Change Request (DCR) 96 006. However, two welds and a 4-inch
piece of pipe downstream of the drain valve were not treated as
Class 2 because the ISI boundary diagrams and 151 program plan had
not been changed to reflect the commitment requirements. The
licensee determined that the problem was caused by personnel
error. Initially, the ISI plan drawings were revised to capture
the requirement and Inservice Testing (IST) documents were revised
to address the testing requirements. However, during a process to
update prints (new ISI boundary drawings) the requirement for the
) articular valve and piping was not detected and the new ISI
aoundary drawing failed to reflect the code requirement.
The inspectors reviewed licensee corrective actions to correct
this problem. The inspectors reviewed procedure 421T-TET-004-05.
Enclosure 3
_ _ _ - _ _ - _ _ ___ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - __
.
.
34
" Operating Pressure Testing of Piping and Components." Rev 5.
dated October 10, 1997, that was used to complete the code-
required testing of the components. The test results were
satisfactory,
c. Conclusions
The inspectors concluded that the licensee actions taken to
correct the missed commitment for Unit 2 Technical Specification
(TS) klendment 132 were appropriate. The code-required testing
cont' 'ted in October 1997 was satisfactory. This problem was
idenu fied as Deviation 50-366/97-10-04: 1:issed Commitment for
Unit 2 Technical Specification Amendment 132.
E3.2 Review and Observations of Desian Chance Reouests (DCRs) Durina
Unit 2 Refuelina Outaae
a. Inspection Scope (37700)
The inspectors reviewed selected DCR packages and observed part of
the ongoing work activities during the Unit I refueling outage.
The review included the DCR base documents, activity summary, work
description. MW0s. plant drawings, and applicable 10 CFR 50.59
review to determine if an unreviewed safety question existed.
b. Observations and Findinas
The inspectors reviewed the following DCRs and associated
documentation and observed selected wo.-k activities.
e 86-318: Cable Re-route (Containment Penetration Work)
e 93-047: Condensate Demineralizer Backwash System
e 94-007: Power Range Neutron Monitoring
e 95-032: Breaker / Fuse Coordination
e 95-053: Upgrade Feedwater Controls
e 96-035: Install New DP Indications on EHC Filters
e 96-038: Convert 1C EDG to Series Operation
e 96-040: Upgrade ECCS Torus Suction Strainers
e 97-005: Thermal Pressure Relief Protection
e 97-016: Pull and Replace Control Cables to 23 Valves
Enclosure 3
,
e
35
4 97-044: Provide Cable Separation
-The inspectors observed that work packages were generally thorough
and complete. The 10 CFR 50.59 reviews were detailed and did not
identify any unreviewed safety questions. Procedures, drawings,
and TSs were identified when changes were required and the basis
for the 10 CFR 50.59 screening questions were thorough and
detailed. The design verification summaries reviewed by the
inspectors were detailed. The evaluation of the effects of the
design on the overall original plant design structures, systems
and components was reasonable.
During the review of DCR 97-016. the inspectors observed that some
procedures in the work package were not the current revision.
Additionally, some minor administrative errors existed on the Fire
Protection Checklist. No work had been performed using the
incorrect procedure revision or fire protection checklist. The
procedure errors were corrected prior to any work being performed
that required the procedures.
During work observations of DCR 96-035, the inspectors observed
that FME controls were good. However, minor discrepancies in
housekeeping were discussea with licensee management. The
inspectors observed later that the discrepancies had been
corrected.
c. Conclusions
The inspectors concluded from the DCR work reviewed that work
packages were generally thorough and detailed. The 10 CFR 50.59
evaluations were detailed, thorough, and appropriate. Changes to
procedures, drawings, and TSs were identified when required. The
evaluation of the effects of the design change on the overall
original plant design structures, systems and components was
reasonable. Work observed was in accordance with applicable
procedures and work packages.
E3.3 10 CFR 50.59 Evaluation Review and Procedure Chanae Process for
On-line Testina of Unit 1 Residual Heat Removal System
a, Insoection Scoce (62707)
The inspectors reviewed procedures 42SV-E11-004-1S, " Residual Heat
Removal Shutdown Cooling LSFT," Revision (Rev.) 5, and
42SV-Ell-005-1S, " Containment Spray LSFT", Rev. 5. ED 1. and the
Unit 1 Final Safety Analysis Report (FSAR), Section 4.8.11.
Residual Heat Removal (RHR) System Inspection and Testing, and
reviewed licensee personnel performance for RHR testing prior to
the Unit I refueling outage. The inspectors reviewed engineering
Enclosure 3
. __ __ _ _ _ . _ _ _ _ _ . -
.
.
36 l,
4
performance with respect to the 10 CFR 50.59 evaluations and
procedure revision process.
-
b. Observations and Findinos
The inspectors observed that engineering and operations personnel
completed procedure 42SV-E11-005-15 and portions of procedure
42SV-E11-004-15 while the unit was operating at about 98% and 92%
power respectively. Procedure 42SV-E11-005-IS was started at
2:36 p.m. on September 7 and was completed at 5:32 p.m. the same
day. Procedure 42SV-E11-004-1S was started at 9:50 a.m. on
October 8 and was partially completed at 4:55 p.m. the same day.
The inspectors observed that the tests were satisfactorily
completed and no deficiencies were observed.
The inspectors observed that section 4.8.11 of the Unit 1 UFSAR
stated, in part. " Testing of the sequencing of the LPCI mode of
operation is performed after the reactor is shut down and the RHR
system has been drained and flushed. Testing the operation of the
valves required for the remaining modes of operation of the RHR
system is performed at this time." In this case, one of the above
procedures was completed and one was partially completed with the
reactor in operation and the system not drained and flushed.
For the review of procedure 42SV-E11-004-15. Rev 5. the
inspectors obtained the official document from document control
and noted that step 6.2 of the prerequisites stated that. "The
'
unit shall be in Cold Shutdown Condition or Refuel Mode during the
performance of this 3rocedure " However, the inspectors were
later informed that Rev. 6 of the procedure for " validation use
only" was used by engineering to conduct the test. Revision 6 of
the procedure, dated October 7.1997, indicated what sections of
the procedure could be performed in different modes of Unit
operation. Some sections of the procedure were permitted to be
performed while the unit was operating.
Step 6.4 of procedure 42SV-E11-005-lS stated. in part, it is
recommended that the unit be in Cold Shutdown or Refuel Mode
during the performance of the test, although the test can be
performed in any operating condition.
The inspectors observed that, in the recent past, these LSFT
-
procedures were performed while the unit was shutdown. Als' it
was not a standard practice or requirement to have the RHR system
drained and flushed prior to conducting-the LSFTs.
The inspectors reviewed the 10 CFR 50.59 evaluations completed by
engineering for the procedure revisions that allowed on-line
performance of these procedures. The inspectors observed that the .
,
evaluation did not address section 4.8.11 of the FSAR which
Enclosure 3
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.
_ -. _ . . . . _ _
,
'
,
,
37
s)ecified applicable test conditions, The inspectors observed
-tlat- two 10 CFR 50.59 screening cuestions wer e answered "no" as to .'
whether or not a change would be' required to a licensing document
and whether or.not the change to the procedure represented-a
change to the plant condition described in the FSAR. In this ;
case. "yes" should have been the correct answer to both of these
screening questions.
The inspectors discussed this 10 CFR 50.59 review problem with
licensee management. The inspectors were informed that management
was reviewing a proposed revision to change the UFSAR wording to
match how the plant actually conducted the LSFTs. The ins]ectors
-also questioned licensee management as to whether or.not t1e
ongoing IIFSAR review program, which is conducted at the corporate
office, would have detected the UFSAR deficiency. Licensee
management later informed the inspectors that it was not likely
that the ongoing UFSAR review process would have detected the
UFSAR deficiency. The inspectors were informed that management
would assess the UFSAR review process to determine what changes
would be appropriate.
As part of the inspectors' review of the use of validation
)rocedures, procedure 10AC-MGR-003-05. " Preparation and Control of
3rocedures." Rev. 16, was reviewed. The inspectors observed that
the procedure was very subjective as to how validation of
procedure changes were to be processed. The procedure did not
provide clear guidance as to whether a procedure change would be
processed as a temporary procedure change (TPC) or a validation
comment. The inspectors discussed this and other minor
deficiencies with licensee management. The inspectors were
informed that procedure 10AC-MGR-003-0S would be reviewed for
possible improvements and to clarify some steps.
In this case, a change to procedure 42AV-E11-004-1S was not
completed in accordance with procedure 10AC-MGR-003-05.
" Preparation and Control of Procedures." Rev 16. The inspectors
.
were not aware of other 10 CFR 50.59 evaluation or procedure
~
revision problems.
c. Conclusions
The licensee's planned corrective actions to revise the FSAR,
assess corporate UFSAR review process, enhance future 10 CFR 50.59-
training and evaluation procedures, and the issuance of a-
department directive to explain the requirements, were
4
appropriate. A violation of minor safety significance is being
identified as Non-cited Violation (NCV) 50-321/97-10-09:
Personnel Error During 10 CFR 50.59 Review and Procedure Revision
Process For Residual Heat Removal On-line Testing.
Enclosure 3
_
.
.
38
E4 Engineering Staff Knowledge and Performance
E4.1 Inservice Leak Testina of ASME Class 1 System (Unit 1)
a. Inspection Scoce (37551) (6270Z1
The inspectors reviewed inspection test procedure 421T-TET-006-15.
"ISI Pressure Test of the Class 1 System and Recirculation Pump
Runback Test," Rev. 9, conducted observations, and reviewed
documentation associated with the tests performed on November 8.
b. Observations and Findinos
The inspectors observed testing and reviewed the associated test
data. The inspectors observed that engineering personnel were
responsible for the performance of the procedure, including
assisting in the pre-evolution briefing, verifying test data, and
ensuring acceptable test results. Support was provided by
o)erations and maintenance personnel. The reactor pressure vessel
(RPV) leakage testing included the following:
- the establishment of an air bubble in the top of the reactor
pressure vessel with the water level between 170 inches and
190 inches above instrument zero
e the initial pressurization of the vessel to 100 psig using
plant service air
- the heat up of the vessel, using the reactor recirculating
pumps, to the minimum temperature specified in step 7 1.5 of
procedure 411T-TET-006-1S, and
- the pressurization of the vessel, to the test pressure of 1035
psig to 1050 psig by injection from the control rod drive
system and the controlling of pressure by varying reactor water
cleanup reject flow.
The inspectors observed that the responsibilities of operations
included starting the reactor recirculating pumps, pressurizing
the vessel, monitoring and maintaining vessel temperature,
controlling the vessel pressure, and recording data. Operations
supervision responsibilities during the test included command and
control of control room activities, conducting pre-evolution and
shift briefings, coordinating engineering support activities, and
insuring that the test was performed in accordance with procedural
requirements.
Maintenance was responsible for making repairs to leakage
identified during the RPV leakage test. The following
Enclosure 3
.
.
39
deficiencies were identified and documented on deficiency cards
(DCs) during the test:
. C09705671 - Loop A RHR isolation gate valve 1E11-F060A had a
packing leak of approximately 100 drops per minute (DPM). MWO
l-97-3088 was implemented for repairs.
. C09705672 - The end cap after RWCU inlet vent globe valves
1G31-F131 and -F132 was leaking at a rate of less than one DPM.
MWO 1-97-3089 was implemented for repairs.
. C09705673 - Instrument isolation globe valve 1821-F014K (valve
was incorrectly identified as IB21-F015J Ua the DC) had a
slight packing leak. The follower and nuts had corroded. MWO
1-97-3087 was implemented for repairs.
. C09705675 - 45 north bank and 18 south bank control rod drive
hydraulic control units had valves with packing leaks or wet
packing. Maintenance work order (MWO) 1-97-3090 was
implemented for repairs.
The inspectors verified that all of the identified deficiencies
were satisfactorily repaired following the test.
The 1A reactor recirculation pump runback capability was
successfully tested following the performance of the RPV leakage
test. However, the 1B reactor recirculation pump tripped while
maintenance personnel were investigating a loss of speed
indication. The runback test for this pump was 3ost3oned until
the speed indication problem was resolved. Trou)leslooting
identified rolled wires as the cause. The wires were correctly
landed and the runback test for the IB reactor recirculation 3 1p
was later performed successfully. The inspectors discussed tit
rolled wiring with engineering personnel. The inspectors were
informed that the recirculation pump trip resulted when wiring
connections were loosened to reverse the rolled wires. The
loosened wires provided a circuit to the MG set field flashing
circuit, whicn was lost and caused the trip. The inspectors
observed that sianificant DCR work occurred with the wiring in the
control room panels. However, tne actual cause of the rolled
wires was not determined.
The inspectors reviewed the TS requirements for the leakage test
and reactor recirculation pump runback These requirements are in
TS section 3.10. "Special Operations." subsection 3.10.1.
" Inservice Leak and Hydrostatic Testing Operation." and TS section 3.4. " Reactor Coolant System (RCS)." subsection 3.4.9.
"RCS Pressure and Temperature (P/T) Limits." respectively.
Additionally, section 4.3.6 of the Unit 1 UFSAR was reviewed for
test applicability.
Enclosure 3
4
%
40
c. Conclusions
The inspectors concluded that the RPV leakage and reactor
recirculation pump runback tests were performed in accordance with
a) proved procedures. TSs. and conditions specified in the FSAR.
T1e activities were performed with good coordination between
engineering, operations, and maintenance. The performance of the
pressure tests and the leak repairs was excellent.
E8 Miscellaneous Engineering Issues (92700) (92903)
E8.1 (Closed) Violation 50-321. 366/97-01-01: Failure to Follow
Procedure - Multiple Examples.
Licensee personnel failed to follow procedure 42CC-ERP-011-0S,
Control Rod Exchange. Rev. 8, while executing a control rod
sequence exchange in January 1997.
The licensee's response to this violation, dated April 21, 1997,
indicated that the individuals involved were disciplined in
accordance with the company's positive discipline program and
counseled regarding the potential consequences of their actions.
Also, procedures 34G0 0PS-065-1S and 34G0-0PS-065-25, Control Rod
Movement, used in concert with 42CC ERP-011-05, were combined into
one procedure (34GO-0PS-065-05, effective April 16, 1997), which
requires varification that the Rod Worth Minimizer is enforcing
the proper sequence prior to using new control rod movement
sheets, she inspectors verified that procedure 34G0-0PS-065-0S
was revised.
Based upon the inspectors' review of licensee actions, this
violation example is closed. Other examples of this violation are
closed 'in sections 08.1, M8.1. and F8.1. One example of this
violation was closed in section P8.1 of IR 50-321, 366/97-03.
E8.2 (Closed) Violation 50-321/97-01-03: Failure to Translate Original
Design Specifications into Applicable Instructions.
This issue was documented in section E2.2 of IR 50-321. 366/97-01.
The licensee's response to this violation, dated April 21. 1997,
indicated that the licensee analyzed the subject vent line
configuration for vibration-induced stress and determined that it
was acceptable: issued Department Directive GM-97-06 on March 14,
1997, instructing engineering personnel how to obtain design
drawing information from available data bases: and drawing S-01286
was listed in the document retrieval system as a design drawing
reference for the vent line valves on April 14. 1997. The
inspectors were given a demonstration of how to obtain design
drawing information from available data bases, including verifying
that drawing S-01286 was listed in the document retrieval system
Enclosure 3
-_ . .
.. . .
.
.
.
.
I 41
as a design drawing' reference for the vent line valves. Based
upon the inspectors review of licensee actions, this violation is
closed.
IV Plant SuoDort
R1 Radiological Protection and Chemistry Controls
R1.1 Observation of Routine Radioloaical Controls
a. Insoection Scoce (71750)
General HP activities were observed during the report period.
This included locked high radiation area doors proper
radiological posting. and personnel frisking upon exiting the RCA.
.
The inspectors made frequent tours of the RCA and discussed
radiological controls with HP technicians and HP management. The
minor deficiencies identified were discussed with HP technicians
and HP management for corrective actions. Specific observations
are detailed in the sections below.
Rl.2 Conduct of Radioloaical Protection Controls
a. Insoection Scone (83750)
Radiological controls associated with Unit 1 (U1) refueling cycle
RF 17 outage activities and with ongoing Unit 2 (U2) operations
were reviewed and evaluated by the inspectors. Reviewed program
areas included: area postings and radioactive waste (radwaste)
and material container labels, high and locked-high radiation area
controls, and procedural and radiation work permit (PWP)
implementation. Established controls were compared against
anlicable sections of the Updated Final Safety Analysis Report
(FSAR) requirements detailed in the Technical Specifications
(TSs), and 10 CFR Part 20.
The inspectors made frequent tours of the Radiologically
Controlled Area (RCA) and observed work activities within the U1
drywell, torus. reactor building, refueling floor, and turbine
deck areas. Guidance in specific procedures and RWPs was
reviewed and discussed with responsible health physics (HP) staff.
The inspectors directly observed HP technician performance.
Results of independent radiation and contamination surveys for
selected equipment and facility locations were compared against
current survey results used to establish RWP controls. Exposure
-results provided by digital alarming dosimeters (DAD) used during
diving. Inservice Inspection (ISI). and insulation operations were
reviewed and discussed. In particular, radiological controls
Enclosure 3
_ _ _ _ . . _ _ _ _ _ - _ - _ - -
.
%
42
described in the following RWPs were directly observed and
evaluated in detail:
e 197-1041. Rev. O. Divers Desludge Coating and Upgrade ECCS
Torus Strainers for Residual Heat Removal and Core Spray inside
Torus Proper Using Procedure 62-RP-RAD-022-05 and Support Work
Including Condensate Storage Tank (CST) Diving dated
September 6, 1997.
e 197-1022. Rev. O. Inservice Inspection (ISI) and Support Work,
dated September 3, 1997,
e 197-1020. Rev. O. Repair Shield Doors, insulation / Removal /
Replacement Temporary Shielding Scaffolding. Tent
Building / Removal & Support Work Including Subpile Room, dated
September 3, 1997.
b. Observations and Findinas
High and locked-high radiation aiaa controls were implemented in
accordance with TS requirements, Postings were proper and in
accordance with TS or 10 CFR 20 Subpart J requirements. Excluding
concerns with spent vacuum filters temporarily stored in the U1
torus pool and containers holding radwaste, contaminated materials
and equipment were labeled in accordance with 10 CFR 20.1904
requirements.
During tours conducted on October 22, 1997, the inspectors
identified labeling concerns for eight spent vacuum filters which
were st, red within the U1 torus pool. At the time, diving
operations were ongoing to upgrade the U1 Emergency Core Cooling
System (ECCS) torus strainers in accordance with RWP 197-1041.
During tours and observations of operations and equiament in
general areas located away from diving operations, t1e inspectors
observed eight lanyards attached to the catwalk railing which were
used to suspend material in the torus 3001 Bay 13 area. From
subsequent discussions with the HP teclnician providing job-
coverage of dive operations, the ins)ectors determined that the
suspended materials consisted of eig1t spent vacuum filters having
maximum contact dose rates of 4.7 to 7.5 rem per hour (rem /hr).
The filters previously were used in torus desludging operations
and were moved to their present location earlier in the day.
Labels were not affixed to the lanyards, identifying that
containers of radioactive materials. i .e. , the spent filters, were
suspended from the lanyards. Lanyards suspending eight additional
spent filters stored in U1 torus 3001 Bay 4 area were labeled
properly. The inspectors noted tlat 10 CFR 20.1904(a) requires
licensees to ensure that containers of licensed material not
subject to the exemptions of 10 CFR 20.1905 bear a durable,
clearly visible label bearing the radiation symbol and the words
Enclosure 3
-, _ - --- - -.
i
,
s
43
- CAUTION, RADI0 ACTIVE MATERIAL" or " DANGER. RADIOACTIVE MATERIAL."
The label must provide sufficient information to permit
individuals handling or using the containers, or working-in the
vicinity of_ the containers, to take precautions to avoid or .
minimize exposures. During discussion of access and radiological
controls within the 01 torus area, the inspectors determined that
-
continual HP coverage was required only when U1 torus diving .
operations were in progress and that the exemptions specified in
10 CFR 20.1905(c) and (e) were not met because the spent vacuum
filters were accessible to personnel entering the area at all
times. The inspectors identified the failure to label the spent
vacuum filters temporarily stored in the U1 Bay 13 torus pool area
as violetion (VIO) 50-321/97-10-05: Failure to Label Containers
of Radioactive Material in Accordance with 10 CFR 20.1904
Requirements.
Concerns were also identified regarding the adequacy of the
radiation survey map documentation associated with the U1 torus
pool spent filter temporary storage. The inspectors noted that
the current detailed survey maps of the U1 torus did not identify
,
the specific location of the stored filter.e within Bays 4 and 13.
- From discussion with responsible HP staff and review of radiation
protection survey log sheets and control point logbooks, the
inspectors determined that radiological surveys, both contact and
general area dose rates, were taken when the filters were
uncoupled from the vacuum equipment ano placed in their temporary
storage locations. The reviewed survey documents met current
procedural guidance specified in 62RP-RAD-008-OS. Radiation and
Contamination Su veys, Rev. 9. effective March 4, 1997. The ,
inspectors questioned whether the torus spent filter storage
location changed dose rates to personnel on the catwalk above the
2001 as well as divers conducting subsurface operations,
lesponsible HP staff stated that, following movement of the
filters, radiation surveys verified that previous dose rates
affecting ongoing torus activities were not changed. The
inspectors noted that the information which the survey
documentation )rovided was marginal in identifying specific
locations of tle spent filters to all personnel who could access
the U1 torus locations. Licensee representatives stated that this
documentation concern would be evaluated and improvements in
survey documentation _would be initiated as necessary.
No concerns for external exposures were identified for persons
involved in diving activities. Accumulated dose and maximum dose
rates measured by. DADS were within expected ranges and
significantly below 10 CFR Part 20 limits. Where applicable,
extremity monitoring was used. For diving operations conducted
from October 18-20, 1997, a maximum dose rate of approximately
2.04 rem /hr and an accumulated dose of 98 millirem (mrem) were
Enclosure 3
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_ _ _ . _ _ .. . _. ~ _.
, ,
.
%i -
'44
documented. The observed high dose rates were associated with
changeout of the spent vacuum filters.
From direct comparison with the previous U2 outage, the
inspectors noted that housekeeping and radiological control
practices associated with U1 turbine deck activities were
improved. In general, radiation exposure and contamination
control practices were followed by workers. However, several
'
isolated examples of poor radiation or contamination control
practices associated with U1 outage activities within the drywell,
torus, and reactor building areas were identified. The poor
3ractices included several examples of workers and a HP technician
laving loose or unfastened protective clothes (PC), i.e., hoods.
-while conducting U1 drywell and torus area activ1 ties. In
addition, the inspectors noted a worker laying on the floor of the
drywell airlock between ISI setup activities.
c. Conclusions
,
in general, radiological controls, area )ostings, and container
labels were maintained in accordance witi TS and 10 CFR 20,
Appendix J requirements.
'
The failure to label eight vacuum filters stored within the U1
torus Bay 13 pool was identified as VIO 50-321/97-10-05: Failure
to Label Containers of Radioactive Material in Accordance with 10
CFR 20.1904 Requirements.
The effectiveness of detailed survey maps to identify the hazards
from spent vacuum filters stored in the U1 torus was marginal.
External exposure controls for U1 outage tasks were effective in
maintaining personnel doses 'significantly less than 10 CFR Part 20
-limits.
In general, radiation exposure and contamination controls were
effective, with only isolated example of poor radiation practices
identified.
R1.3 Internal Exoosure
a '. Insoection Scone (83750)
The inspectors reviewed and discussed evaluations of potential
radionuclide. uptakes and resultant internal exposure from U1 RF17
outage activities.
Enclosure 3
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.
1 ~
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45
b. Observations and Findinas
As of October 22. 1997. five instances of potential radionuclide
uptake during the Ul outage activities were identified by routine
or investigative wholebody count analyses. Evaluations for the
five potential uptakes were completed in accordance with the
approved procedures. . No concerns were identified for assumptions,
time of initial uptake, or internal exposure pathway used in
licensee evaluations. All radionuclide intakes were less than 0.2
percent of the annual limit of intake (ALI), which would require
the internal exposure to be added to an individual's official
exposure records, in accordance with approved licensee procedures.
c. Conclusions
Licensee controls for minimizing internal exposure were effective,
with potential uptakes of radionuclides evaluated appropriately.
R3 Radiological Protection and Chemistry (RP&C) Control Procedures
and Documentation
R3.1 Dase Records
a. Insoection Scone (83750)
The inspectots reviewed and evaluated licensee program guidanco ,
and results for determining current-year prior occupational s.
The inspectors reviewed and discussed NRC Form 4, or equivalent
records, for selected contractor personnel involved in U1' RF17
outage health physics, ISI. drywell insulation. or torus diving
operations.
Licensee program guidance and corresponding records were compared
against 10 CFR 20 Subpart L requirements.
b. Observations and Findinos
The inspectors verified that appropriate records of current year
prior occupational doses were available for the selected
individuals. Estimated prior year doses assigned to the skin,
extremities, and lens of the eye for each individual worker were
conservatively based on the total effective dose equivalent (TEDE)
estimate or record. During review of applicable dose records
provided by previous employers, the inspectors identified several
examples of inconsistencies between deep and shallow dose
assignment. In each case, licensee representatives assigned the
more conservative dose value for estimating the individual's
current year exposure. Licensee representatives stated that
additional guidance for handling inconsistent ex30sure data
provided in individuals' official records would ]e developed.
Enclosure 3
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The inspectors also verified that records were available for
granting administrative dose extensions. in accordance with
approved procedures.
c. Conclusions
Records for determining workers' prior yearly occupational
exposures and granting administrative exposure extensions were
established in accordance with 10 CFR Part 20 Subpart L
requirements and administrative procedures.
R7 Quality Assurarre in Radiation Protection and Chemistry Activities
R7.1 Release of Contaminated Materials
a. Irlsnection Scone iB3750) (84750)
On approximately June 9-10, 1997, licensee radiation survey
quality checks of concrete material disposed of in the onsite
landfill, identified several potentially contaminated pieces of
material having contamination levels of 1100 to 1200
disintegrations per minute (dpm) above background. The inspectors
initiated a review of licensee pre- and post release survey
results, program guidance and licensee evaluations of the event,
and subseque.1 corrective actions.
Program guidance was evaluated against 10 CFR Part 20 requirements
and guidance provided in NUREG/CR-5569. Health Physics Positions
(HOPPOS) Data Base, Rev. 1. HPPOS-072 and -073.
b. Observations and findinos
from discussions with cognizant licensee re)resenta'ives and
review of pre-release surveys and HP logboots, the inspectors
determined that the concrete material was screened directly using
E-120 friskers prior to release from the Waste Separation and
Temporary Storage facility. Log entries of general survey results
for the concrete rubble released for disposal in the onsite
landfill indicated less than 100 corrected counts per minute per
100 square centimeters. From discussions with licensee
representatives who conducted the quality checks. the inspectors
determined that subsecuent OC surveys using E-120 friskers at the
landfill indicated raci' ,on levels of 1100 to 1200 dpm per probe
area for several pieces of concrete recovered from landfill
o)erations. Subsequent gamma-spectroscopy analyses verified that
t1e concrete rubble released to the onsite landfill was
contaminated slightly with cesium-137 and cobalt-60. The
inspectors noted that all of the licensee corrective actions
associated with the identified issue were not complete and.
pending additional NRC review, this item would be considered an
Enclosure 3
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Unresolved Itcm (URl) 50 321, 366/97-10 06: Review Licensee
Final Evaluation and Corrective Actions for Contaminated Concrete
Waste Materials Released to the Onsite Landfill.
c. Conclusions
Licensee OC checks identified that several pieces of slightly
cont W.nated concrete were released to the onsite landfill.
The inspector opened URI 50-321, 366/97-10-06: Review Licensee
Final Evaluation and Corrective Actions for Contaminated Concrete
Waste Materials Released to the Onsite Landfill.
R8 Miscellaneous RP&C Issues
R8.1 Contamination Cor, trol Initi6tives
a. Inspection. Scone (83750)(84750)
Implementation of licensee ( mtamination contrcl initiatives and
personnel contaminations were reviewed and discussed.
b. Observations and findinos
The inspectors discussed and verified the im)1ementation of
licensee initiatives to identify and reduce personnel
Contamination Event (PCEs) and associated Personnel Contamination
Reports (PCRs). Initiatives included: extensive RCA
contamination level determinations: laundry vendor and facilities
audits: 1ssuance of plant stand down orders in September 1997:
documentation of man 6gement expectations for plant radiological
practices; discussions of radiological work practices during
safety meetings: establishment of alarm levels for reusable mops
and towels: and development of radiological observation
checklists. 'n addition. the inspectors reviewed initiatives '
regarding availability of PCE and PCR data on the local area
network: administrative reassignment of all HP technicians to
report directly to HP management: and radworker requirements to
check with HP prior to performing work in the RCA. The inspectors
also reviewed and discussed the previous outage PCRs.
For the first 10 days of the current U1 outage the number of
daily PCEs i.e., contamination levels greater than 1000 dpm but
less than or equal to 10000 dpm, and PCRs. contamination levels
greater than 1000 dpm. were reduced relative to the previous U2
outage. For the first 10 days of the U1 outage, the licensee
re>orted approximately 30 total contamination events. i.e. 17
PCEs and 12 PCRs. respectively, compared to more than 200 total
contamination events for the same U2 outage period. The maximum
number of contamination events, approximately seven individuals.
Enclosure 3
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was reported for the second day of the U1 outage. The inspectors l
identified the initiatives as a program strength which were ;
expected to contribute to a reduction in total contamination l
,
events through time, j
4' c. Conclusions >
Initiatives to address and reduce workar personnel contaminations !
events were effectively implemented.
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R8.2 Insoector Fo110w-un of Previous Doen items (84750) j
(Closed) Unresolved Item (URl) 50 321. 366/97-05 05: Evaluate
Adequacy of CHRMs Electronic Signal Substitution Calibrations t
following Additional Review of the Licensee Response to Generic
Letters 82 05 and 82 10 Dated March 17, 1982 and May 5. 1982.
Respectively.
This item identified that in sftu calibration of the containment i
high range monitors (CHRMs) by electronic signal substitution as i
'
specified in procedure 575V-CAL 007 2S. Drywell High Range l
Radiation Monitor Loop Calibration. Rev. 1, was conducted for four
of the six range decades above 10 Roentgens per hour (R/hr). 6s
specified in NUREG 0737. Table II.F.1-3. The licensee did not
identify any exemptions from meeting the specific requirements of.
- NUREG 0737. Table ll.F.1-3 in its response to Generic Letters 82-05 and 82-10. dated March 17. 1982 and May 5, 1982,
respectively. The inspectors noted that the surveillance
]rocedures were inadequate to meet the explicit requirements of
9UREG 0737. Table ll.F.1-3. The failure to have adequate
surveillance procedures to meet the CHRM electronic calibration
renuirements of NUREG 0737. Ta"le ll.F.1 3 was identified as a
violation of minor safety significance and, consistent with 'i
Section IV of the NRC Enforcement Policy. was being identified as
. NCV 50 321, 366/97 10-07: Failure to Have Adequate Surveillance
Procedures to meet the Containment High Range Radiation Monitors
Electronic Signal Substitution Calibrations Specified in
NUREG 0737. Table ll F.1-3.
During the onsite inspection, licensee representatives ) resented
revisions of surveillance procedures 575V-CAL-007-15. *)rywell-
High Range-Radiation Monitor Loop Calibration," Rev. 3. and
57SV CAL-007-2S. "Drywell High Range Radiation Monitor Loop
Calibration." Revs 3. From review of applicable records, the
inspectors verified that CHRH electronic calibrations for both-
units were completed by October 9. 1997. The 11spectors noted no
concerns with the procedural changes nor with the results
obtained.
Enclosure 3 l
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S2 Status of Security facilities and Equipment (71750)
!
lhe inspectors toured the protected area and observed that the
perimeter fence was intact and not compromised by crosion nor
disrepair. The fence fabric was secured and barbed wire was i
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 escorting
of visitors. Vehicles were searched. escorted, and secured as '
described in applicable procedures.
The inspectors concluded that the areas of security inspected met
the applicable requirements.
F3 Fire Protectica Procedures ard Documentation
F3.1 General Observations of Fire Protection Proaram Issues
a. Insnection Scone (71750)
The inspectors reviewed procedure 40AC-ENG-008 05 " Fire
Protection Program." Rev. 8. and made general observations during
plant walkdown tours,
b. Observations and Findinos
The inspectors observed that the )lant was generally clear of
excessive combustible material. Fire doors that were blocked open
for the Unit 1 refueling outage work were correctly documented
with tha required fire watch responsibilities identified.
Transient combustible permits (TCPs) were issued and posted
locally for material tlat required TCPs. The insoectors observed
that TCP 97-1180, issued for the temporary storas " +ransformer
oil, contained administrative errors. Th. identified
coolin!0poundsofoilwasallowedtobestoredatthatlocation.
that 3
The inspectors calculated that actual amount of oil stored was
about 2115 pounds. The inspectors contacted the engineer
responsible for the work.and noted that the TCP was immediately
corrected. The overall fire loading for the area was also changed
to reflect the correct value. The inspectors were later informed
that the TCP should have stated that 35.0 gallons of oil was
permitted to be stored, not 350 pounds. The inspectors did not
, view this error as significant. Immediate corrective actions were
appropriate.
Enclosure 3
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The ins)ectors observed that fire extinguishers were located at
hot worc locations when required by procedure. Additionally, a
constart fire watch was properly stationed at the hot work
location,
The inspectors accompanied a fire protection engineer on part cf
the routine monthly fire protection inspection on October 31,
Sections of the Unit I reactor building were walked down and
reviewed for potential deficiencies. The engineer immediately
correcteo some minor deficiencies and later initiated five
deficiency cards for more significant problems. The problems were
later corrected. immediate corrective actions were appropriate,
c. Conclusions
The inspectors concluded that the portion of the monthly fire
protection inspection observed by the inspectors was well-
performed. The fire protection engineer was knowledgeable of the
job responsibilities and fire protection equipment. The on the-
spot correction of some minor deficiencies was appropriate and the
deficiency cards initiated to identify and track other
deficiencies were timely.
F8 Hiscellaneous Fire Protection Issues (92904)
F8.1 1 Closed) Violation 50-221. 366/97-01 01: failure to Follow
Procedure - Multiple Examples.
1icensee personnel failed to follow procedure 40AC-ENG 008 05,
fire Protection Program, Rev, 8, in that they moved 55-gallon
drums of oil, oil and water, and oil sludge to the ll2-foot
elevation of the control building without first obtaining a
Transient Combustible Permit in February 1997.
The licensee's response to this violation, dated April 21. 1997,
indicated that the individuals involved were disciplined in
accordance with the company's positive discipline program and
counseled regarding the potential consequences of their actions.
Also, the 55-gallon drums were removed from the 112-foot elevation
of the control building and placed in a designated non-safety
related storage location, pending treatment and disposal of their
contents Transient Combustible Permit 97-2025 was issued for
storage of the drums in this area.
Based upon the inspectors * review of licensee actions this
violation example is closed. Other examples of this violation are
closed in sections 08.1, M8 1, and E8.1.
Enclosure 3
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F8.2 (Closed) Violatim 50 321. 366/97 01-04: Failure to Submit
Special Report on Degraded Fire Barriers.
This issue was documented in section F3 of IR 50-321, 366/97-01.
The licensee's response to this violation, dated April 21. 1997,
indicated that licensee personnel failed to realize that Fire
Hazardous Analysis (FHA) Appendix B required penetrations
separating fire areas to be operable regardless of which safe
shutdown systems and components were located in those areas. That
failure led persconel to erroneously conclude that the penetration
was not required by FHA Appendix B to be operable and. therefore,
to conclude that a special report was not required. The issue was
discussed with the individuals involved to heighten their
awareness of the consequences. The required special report was
submitted to the Safety Review Board on April 3. 1997. The
inspectors reviewed the re) ort and verified that it was submitted
as required. Based upon t1e inspectors' review of licensee
actions, this violation is closed,
y.Manaaementleetinas
X.2 Review of UFSAR Commitments
A recent discovery of a licensee operating its facility in a
manner contrary to the Updated Final Safety Analysis Report
(UFSAR) description highlighted the need for a special focused
review that compares plant practices, procedures and/or parameters
to the UFSAR description. While performing the ins)ections
discussed in this re) ort, the inspectors reviewed t1e applicable
portions of the UFSAR that related to the areas inspected. The
inspectors observed that section 4.8.11 of the Unit 1 UFSAR stated
in part that. " Testing of the sequencing of the LPCI mode of
operation is performed after the reactor is shut down and the RHR
system has been drained and flushed. Testing the operation of the
valves required for the remaining modes of operation of the RHR
system is performed at this time," This was not consistant with
the licensee's current testing methodology. This problem is
described in Section E3.3 of this inspection report.
X.3 Exit Meeting Summary
The inspectors presented the inspection results tu members of the
licensee management at the conclusion of the inspection on
November 25. 1997. The license acknowledged the findings
presented. An interim exit was conducted on October 24, 1997.
The inspectors asked the licensee whether any materials examined
during the inspection should be considered proprietary. No
proprietary information was identified.
Enclosure 3
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
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Anderson, J., Unit Superintendent
Betsill, J., Assistant General Manager - Opt. rations
Breitenbach C.. Engineering Support Manager - Acting
Curtis. S. , Unit Superintendent
Davis. D., Plant Administration Manager
fornel. P., Performance Team Manager
Fraser. 0.. Safety Audit and Engineering Review Supervisor
Hantnonds J. , Operations Support Superintendent
Kirkley W. Health Physics and Chemistry Manager
Lewis. J., Training and Emergency Preparedness Manager
Madison. D., Operations Manager
Moore. C.. Assistant General Manager - Plant Support
Reddick. R., Site Emergency Preparedness Coordinator
Roberts. P. Outages and Planning Manager
Thompson, J. . Nuclear Security Manager
Tipps. S., Nuclear Safety and Compliance Manager
Wells. P., General Manager - Nuclear Plent
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 37700: Design Changes and Modifications
IP 37828: Installation and Testing of Modifications
IP 40500: Ef fectiveness of Licensee Controls in Identifying.
Resolving, and Preventing Problems
IP 60705: Preparations for Refueling
IP 60710: Refueling Activities
IP 61726: Surveillance Observations
IP 62707: Maintenance Observations
IP 71707: Plant Operations
IP 71750: Plant Support Activities
IP 73753: Inservice Ins)ection
IP 83750: Occupational Radiation Exposure
IP 84750: Radioactive Waste Treatment, and Effluent and
Environmental Monitoring
IP 92901: Followup - Operations
IP 92902: Followup - Maintenance / Surveillance
IP 92903: Followup - followup Engineering
IP 92904: Followup - Plant Support
.
Enclosure 3
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ITEMS OPENED AND CLOSED l
Doened
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50-321/97-10 01 IFI Review of Unit 1 RCIC Testing l
Activities from the Remote Shutdown i
Panel (Section 02.1). >
t
50-321/97-10-02 VIO Failure to Meet TS Surveillance i
Requirements Prior to Withdrawal of a
Control Rod While in Cold Shutdown :
(Section 04.2).
50-321/97-10 03 NCV Jumper Placement Error During Unit 1 !
Testing Activities (Section M4.1). ]
50-366/97 10 04 DEV. Missed Connitment for Unit 2 Technical !
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Specification Amendment 132 (Section
E3.1). !
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50 321/97-10-05 VIO Failure to Label Containers of
Radioactive Material in Accordance '
with 10 CFR 20.1904 Requirements
(Section R1.2). .
50 321, 366/97-10-06 URI Review Licensee Final Evaluation and
Corrective Actions for Contaminated ;
Concrete Waste Materials Released to ,
the Onsite Landfill (Section R7.1).
50 321, 366/97-10-07 NCV Failure to Have Adequate Surveillance [
Procedures to meet the Containment ;
High Range Radiation Monitors ;
Electronic Signal Substitution ,
Calibrations Specified in NUREG 0737
Table ll.F.1-3 (Section R8.2).
50-321, 366/97-10-08 IFI Review of 4160-Volt Breaker Failure
Analysis and Preventive Maintenance ,
Program (Section M1.5)- l
50 321/97-10 09 NCV Personnel Error During 10 CFR 50.59
Evaluation Review and-Procedure
- Revision Process For Residual Heat-
Removal On-line Testing (Section E3.3)
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Enclosure 3
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Closed
50 321. 366/97-01-01 VIO Failure to follow Procedure - Multiple
Examples (Sections 08.1, M8.1. E8.1.
F8.1. of this report and P8.1 of
IR 50 321, 366/97-03).
50-321/97-05 LER Contro. Rod Partially Withdrawn
Without Pressure in Scram Accumulator
(Section 08.2).
50-366/97 01-02 VIO Inadequate Procedure for Calibrating
Unit 2 HPCI Time Delay Relay K14 c
(Section M8.2).
50-321/97-01 03 V10 Failure to Translate Original Design
Specifications into Ap>l1 cable
Instructions (Section E8.2).
50-321, 366/97-01-04 VIO Failure to Submit Special Report on
Degraded Fire Barriers (Section F8.2).
50-321, 366/97-05 05 URI Evaluate Adequacy of CHRMs Electronic
signal Substitution Calibrations
Following Additional Review of the
Licensee Response to Generic Letters 82-05 and 82-10 Dated March 17. 1982
and May 5. 1982. Respectively
(Section R8.2).
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50-321/97-10-03 NCV Jumper Placement Error During Unit 1
Testing Activities (Section M4.1).
50-321, 366/97 10-07 NCV Failure to Have Adequate Surveillance
Procedures to meet the Containment
High Range Radiation Monitors
Electronic Signal Substitution
Calibrations specified in NUREG 0737.
Table ll.F.1 3 (Section R8.2).
50-321/97-10-09 NCV Personnel Error During 10 CFR 50.59
Evaluation Review and Procedure
Revision Process For Residual Heat
Removal On-line Testing (Section E3.3)
Enclosure 3
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