ML20203D759
| ML20203D759 | |
| Person / Time | |
|---|---|
| Site: | Three Mile Island  |
| Issue date: | 12/02/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20203D733 | List: |
| References | |
| 50-289-97-09, 50-289-97-9, NUDOCS 9712160282 | |
| Download: ML20203D759 (50) | |
See also: IR 05000289/1997009
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U. S. NUCLEAR P.EGULATORY COMMISSION
REGION l !
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Dodet Not 50189
License No OPR 50
Report No. 97 09 !
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Licensee: GPU Nuclear Corporation
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. Facility:- ~ Three Mile Island Station, Unit 1 l
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location: P.O. Box 480
Middletown, PA i%?
., Dates: September 7 November 1,1997 ,
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Inspectors: Wayne L. Schmidt, Senior Resident inspector
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Samuel L.- Hansell, Res dent inspector
John R McFadden, Radiation Specialist
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Harold E. Gray, Reactor Engineer
Tom F. Burns, Reactor Engineer
Thomas J. Kenny, Senior Operations Engineer
Lois M. James, DRS, Engineer
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Keith A. Young, DRS, Engineer
Approved by: Peter W. Eseigroth, Chief
Reactor Projects Branch No. 7 (
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EXECUTIVE SUMMARY
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Three Mile Island Nuclear Power Station i
Report No. 50-289/97-09 l
September 7,1997 November 1,1997
This integrated inspection included routine resident inspector activities and announced
inspections in the areas of licensee operations, engineering, maintenance, and plant
support over an eight week period. 4
GPU Nuclear (GPUN) conducted outage activities, including reactor refueling, maintenance,
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and unit restart safely over the period
Plant Operationg
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e Generally, GPUN conducted the 12R refueling outage well. Operators, despite
severallapses, displayed excellent control of plant and equipment conditions,
including draining to mid loop and in refilling the reactor coolant system (RCS) and
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in unit restart activities (Sections 01.1 and 01.2.1) <
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e The inspectors questioned the safety significance of GPUN management's decision
to drain the RCS to mid loop with only one decay heat removal (DH) system
available. While apparently allowed by the Technical Specifications (TS), the
wording of the TS bases would lead to a reasonable safety interpretation that this
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condition should not occur. The inspectors considered this an Inspection Followup
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ltem, pending further NRC review of the safety significance of this issue. (Section
01.2.2) (Inspection Followup Item (IFil 50 289/97 08 01)
e During the RCS filling operations a shift supervisor (SS) displayed a poor procedure
compliance standard. The SS directed the plant operators to increase the fill rate,
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from a flow path not included in the applicable operating procedure. This resulted in
1 an excessive flowrate and led to the overflow of approximately 50 gallons of RCS
water out of the control rod drive mechanism (CRDM) vent openings. This
appeared to be a violation, based on failure to follow approved station operating
procedures. (Section 01.2.3) (Escalated Enforcement issue (EEI) 50 289/97 02)
e- Operations department and training management continue to coordinate licensed
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operator requalification classroom, simulator, and on the-job training well, providing
intensive preoutage training, in addition, all operators involved with the core offload
and reload completed on the job training and a qualification card that contained
. refueling operation tasks from the job task analysis. (Section 05.1)
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Executive Summary
Mahtenanne
- Routine outage meetings provided good insight into upcoming work activities and
equipment problems. For the Job Order activities observed, the work packages
contained the needed planning information and the workers properly documented
the completed work. GPUN used lessons learned from the prior refuel outages and
other plants to prevent recurring problems. (Section M1.1)
- Maintenance rework was required for the pressuriter power operated relief valve
(PORV), following identification of a miswired operating solenoid valve (Section
M2.1) and repeatedly on the 'A' DH pump following seal replacurnent. The rework
on the 'A' DH pump resulted in an extended time with only the 'B' DH pump
operable for core heat removal. (Section M1.1)
- Plant management's decision to replace the remaining 31 old design thermal barriers
during the 12R refuel outage with the new design displayed a clear commitrnent to
resolve the slow CRDM drop time issue. All control rod drop times were less that 1
the TS limit when tested before the plant startup. (Section M1.1)
- GPUN responded proactively to the generic makeup (MU) system high pressure
injection (HPI) thermal sleeve cracking issue at Babcock and Wilcox (B&W) plants. l
Af ter finding two cracks in the 'B' thermal sleeve, plant management decided to
complete a visualinternal inspection of the remaining three sleeves, detecting no l
additional flaws. Replacement of the 'B' thermal sleeve was well conducted and
supervised. (Section M1.1.1)
- The pressurizer PORV was inoperable for the two year operating cycle from October
1995 to September 1997 due to a wiring error and the failure to do a post-
maintenance test (PMT) after the valve replacement in the September 1995 refuel
outage. This issue involved the unavailability of the PORV during plant
depres=urization situations as directed by the emergency operating procedures and
on the uniculated increase in core damage frequency (4.10E-5/ year to 4.85E-
5/ year). This appeared to be a violation of TS IST requirements. (Section M2.1)
(eel 50 289/97-09 03)
on safety related equipment, on a sampling basis, because of the PORV root cause
analysis. This assessment was very comprehensive and appropriately expanded
after a few minor documentation problems were found. Plant management's
decision to evaluate and resolve the minor PMT issues before plant restart was
prudent. (Section M2.1)
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Executive Summary
- - The inspector identified a question concerning the appropriateness of testing an I
emergency diesel generator (EDG), following simulated loss of offsite power (LOOP)
and loss of coolant accident !LOCA) conditions, with the output breaker in the pull-
to lock position. This issue was considered an Unresolved item pending further ,
NRC staff review. (Section M2.2) (URI 50 289/97 09 04)
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- The licensee's corrective actions were appropriate and timely to prevent recurrence
of violations regarding scaffold construction in safety related areas of the plant.
(Closed Violation (VIO) 50 289/96 07 01)
Society of Mechanical Engineers (ASME)Section XI,1986 Edition and 10 CFR
50.55alg). The inspectors found the f!ow accelerated corrosion (FAC) program -i
thorough, effective, and capable of predicting the depletion of piping wall thickness.
(Section M8.2) 3
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- The eddy current inspection program was well planned and organized, and could
determine the integrity of the once through steam generator (OTSG) tubes,
according to the ASME Code,Section XI and TS. (Section M8.3)
lionineerJnn
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- The PORV problems were recognized due to the diligent review and questioning
attitude of an electrical engineer. The engineer recognized and pursued the
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connection between the PORV problem found in the current refuel outage and the
possibility of the same problem existing with the previously installed PORV.
(Section M2.1)
- Based on a detailed system review, GPUN has maintained the core flood (CF)
system in good material condition. Engineering maintained the design basis
following 10 CFR 50.46. The inspector also concluded the design basis document
(DBD) was " easy to use" and thorough in describing the design basis Documents
were found consistent with the applicable sections of the DBD, updated final safety
analysis report (UFSAR), TS, IEEE standards, procedures, system drawings and
system layout. Adequate procedures were in place to operate the CF within its
design basis. (Section E.1)
- GPUN took adequate actions to improve the content by resubmitting LER 97-003.
This LER now correctly recounts the events in a more clear and concise manner.
(Section E8.1) (Closed - VIO 50 289/97 07 01)
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Executive Summary
- Engineering developed and maintenance installed a modification to improve the
closing capabilities of MU V 3 the RCS letdown outboard isolation valve. The
modification installed an air to cluso function on this air operated valve, increasing
the ability of the valve to close under system flow and differential pressure. The
modification package was detailed and well developed and the PMT appeared
complete. (Section E8.1.2)
Plant SuDR9tl
General:
- Material conditions continued to be good. Equipment needed to meet TS
requirements for shutdown conditions was maintained and operated well. (Section
R1.1)
- Generally the inspectors found that housekeeping degraded over the outage. This
degradation was particularly evident in the reactor building (RB), where outage
related activities resulted in large amounts of debris to be lef t on floors and surfaces
The debris observed included nails and pieces of wood and sawdust from
scaffolding activities, plc tic tie wraps from the installation of temporary hoses and
cables, a large roll of sheet plastic, pop rivet stems from sheet metalinstallations,
and tape materials left following work. (Section R1.1)
Radiation Protection:
- Adequate contamination controls and radiation survey and monitoring programs
were being carried out. However, weak attributes were noted in the establishment
and maintenance of contaminated areas and in the survey program. The inspectors
noted instances where local postings did not agree with the area conditions and
where material was allowed to cross contaminated area boundaries, in these cases
the rad:ation protection staff corrected the conditions. (Sections R1.1 and R1.3.1)
- GPUN failed to survey adequately during the removal of the reactor vessel seal
plates. As such, adequate hot particle controls were not in place and did not
prevent a personnel skin contamination. This appears to be a failure to follow TS 6.11 and is a violation. (Section R1.3.2) (EEI 50-289/97 09-05)
- Activities to maintain personnel exposures as low as reasonably achievable (ALARA)
were generally considered strong, especially the prejob reviews. (Section R.1,4)
- A contract worker failed to follow the high radiation control procedure; the action
led to an unlocked high radiation area, the 'B' OTSG shiold door, with the potential
for an inadvertent radiation exposure greater than personnel limits. This failure was
similar to a prior problem that occurred in the 1993 and 1995 refuel outages. This
issue appeared to be a violation of TS 6.8.1, in that procedures for locking high
radiation areas were not followed. (Section R4.1) (eel 50 289/97 09 06)
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Executive Summary
- The selection, training, and qualification of contracted radiological control
techr'icians for the outage were in accordance with requirements. The new
radiation worker coaching process set up by radiological controls (RC) Field
Operations was a good in:tiative. (Section RS)
- NSA conducted a good quality audit of the RC area with proper scope and depth.
The surveillances by RC personnel resulted in the correction of numerous minor
deficiencies. (Section R7) ,
Security:
- The inspector noted no deficiencies during a night tour of the protected area.
(Section R1.1)
- All openings in the protected area boundary were controlled properly by the security
department for the entire 12R refueling outage. Based on this improved
performance, the inspectors concluded that GNN had taken effective corrective
actions for prior problems. (Section S1)
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TABLE OF CONTENTS
PAGE NO.
EX EC UTIVE SU M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . il
R e p o r t D e t a il s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Summary of Plant Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1. Operations .................................................... 1
01 Conduct of Operations (71707, 92901) . . . . . . . . . . . . . . . . . . . . . . . . 1
01.1 General Comments ................................. 1
01.2 Re f uel Outage Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01.2.1 Draindown to the Reactor Coolant System Mid loop
O p e r a tio n . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
01.2.2 Review of Draindown Following Refueling - Open - URI
50 289/97-09-01: Decay Hcat Removal Requirements
During Reactor Vessel Draining . . . . . . . . . . . . . . . . . . . . 2
Reactor Coolant System Fill and Vent Open eel 50-
289/ 97-09-02; Failure to Follow Reactor Coolant
System Filling procedure ........................ 4
05 Operator Training and Qualification . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
05.1 Licensed Operator Refuel Outage Training . . . . . . . . . . . . . . . . . 6
ll. Maintenance .................... ............................. 7
M1 Conduct of Maintenance (62707,61726,92902) ................ 7
M 1.1 General Comments ........................ ........ 7
M1.1.1 High Pressure injection Thermal Sleevo Replacement . . . . 8
M2 Maintenance and Material Condition of Facilities and Equipment ...... 9
Open - eel 50-289/97-09 03 Power Operated Relief Valve
Inoperable for an Operation Cycle ...................... 9
Review of Loss of Power and Loss of Coolant Accident Outage
Electrical Testing. - Open URI 50 289/97 09-04 Emergency
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Diesel Generator Testing During Simulated Accidents . . . . . . . . 12
M8 Miscellaneous Maintenance issues .......................... 13
M8.1 Closed VIO 50-289/96-07-01: Safety Related Scaffolding . . . . 13
M8.2 Inservice Inspection (73753,73755) .................. 13
M8.3 Once Through Steam Generator Tube Eddy Current Testing
and Related Work (73753, 73755) . . . . . . . . . . . . . . . . . . . . . 15
lli. Engineering . . . . . . . . . . . ...................................... 18
El Conduct of Engineering (37550,37551,92903,93809) .......... 18
E1,1 Core Fiood System Review Introduction and Purpose . . . . . . . . 18
E1.2 Evaluation of the Design Basis . . . . . . . . . . . . . . . . . . . , . . . . 18
E1.2.1 Licensing and Regulatory Requirements ............ 18
E1.2.2 Interface With Chemistry and Sampling . . . . . . . . . . . . . 19
E1.2.3 Mechanical Maintenance . . . . . . . . . . . . . . . . . . . . . . . 19
E1.2.4 Electrical Distribution System . . . . . . . . . . . . . . . . . . . 19
E1.2.5 Instrumentation and Control ................ 20
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TABLE OF CONTENTS
PAGE NO.
EX ECUTIVE SU M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . - . . . . . . . . . . . . . . . . . . . . 11
R e por t De t ails . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 ;
Summary of Plant Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1. Operations ...................................'................. 1 i
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01 Conduct of Operations (71707, 92901) . . . . . . . . . . . . . . . . . . . . . . . . 1
01.1 General Comments ................................. 1
01.2 Ref uel Outage Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , 1 i
01.2.1 Draindown to the Reactor Coolant System Mid Loop ;
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O pe r a ti on . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
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01.2.2 Review of Draindown Following Refueling Open - URI
50 289/97-09-01: Decay Heat Removal Requirements _$
During Reactor Vessel Draining . . . . . . . . . . . . . . . . . . . . 2 t
Reactor Coolant System Fill and Vent - Open - eel 50-
289/97-09 02: Failure to Follow Reactor Coolant
System Filling Procedure ........................ 4
05 Or~'ar Training and Qualification . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
05.1 Licensed Operator Refuel Outage Tralning . . . . . . . . . . . . . . . . . 3
II. Maintenance ....................... 4 ....... .......... ...... 7
M1 Conduct of Maintenance (62707,61726,92902) ................ 7
M1.1 General Comments ................................. 7
M1.1.1 High Fressure injection Thermal Sleeve Replacement . . . . 8
M2 Maint; nance and Material Condition of Facilities and Equipment ...... 9
Open - eel 50 289/97 09 03 Power Operated Relief Valve
Inoperable for an Operation Cycle ...................... 9
Review of Loss of Power and Loss of Coolant Accident Outage
Electrical Testing, - Open - URI 50-289/97 09 04 Emergency
Elesel Generator Testing During Simulated Accidents . . . . . . . . 12
M8 Miscellaneous Maintenance issues .......................... 13 t
M8.1 Closed - VIO 50 289/96 07 01: Safety Related Scaffolding . . . . 13
M8.2 Inservice Inspection (73753,73755) .................. 13
M8.3 Once Through Steam Generator Tube Eddy Current Testing *
and Related Work (73753, 73755) . . . . . . . . . . . . . . . . . . . . . 15
lli . E ng i n e e ri ng . . . . . . . . . ._ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
E1 Conduct of Engineering (37550,37551,92903,93809) .......... 18
E1.1 Core Flood System Review Introduction and Purpose ........ 18
E1.2 Evaluation of the Design Basis . . . . . . . . . . . . . . . . . . . . . . . . 18
E1.2.1 Licensing and Regulatory Requirements ............ 18
E1.2.2 Interface With Chemistry and Sampling . . . . . . . . . . . . . 19
E1.2.3 Mechanical Maintenance . . . . . . . . . . . . . . . . . . . . . . . 19
E1.2.4 Electrical Distribution System . . . . . . . . . . . . . . . . . . . . 19
- E1.2.5 Instrumentation and Control ................ 20
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E1.2.6 Environmental Qualification . . . . . . . . . . . . . . . . . . . . . 20
E1.2.7 Core Flood Tank Heaters . . . . . . . . . . . . . . . . . . . . . . . 21
Ins ervic e Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
E1.2.9 Testing ................................... 22
E1.3 System Walkdown . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
E1.4 Related Design Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
E1.4.1 Replacement of the Valves Motors . . . . . . . . . . . . . . . . 24
E1.4.2 Volume Requirement Change . . . . . . . . . . . . . . . . . . . . 24
E1.4.3 Relief Valve Addition to the Sample System ......... 25
E1.4.4 Transmitter Replacement . . . . . . . . . . . . . . . . . . . . . . . 26
E1.5 Review of NRC Bulletins, information Notices, Generic Letters . . 27
E8 Miscellaneous Engineering Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
E8.1 (Closed) Violation 97 07 01: Failure to Write a Clear Licensee
Event Report Narrative . . . . . . . . . . 28
E8.2 Modification Review - Letdown Valve Closing Capability
Upgrade........................................ 28
IV. Plant Support ................................................ 29
R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . 29
R1.1 General Plant Tours . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
R1.2 Radiological Controls-External and Internal Exposure . . . . . . . . . 29
R1.3 Radiological Controls Radioactive Materials, Contamination,
Surveys, and Monitoring ............................ 30
R1.31 General Outace Controls , 30
R1.3.2 Review of Hot Particle Contamination - Open - eel 50-
289/97-09 05; Personnel Hot Particle Contamination
Due to inadequate Surveys . . . . . . . . . . . . . . . . . . . . . . 31
R1.4 Radiological Controls As Low As Reasonably Achievable ..... 33
R1.5 Other Changes to the RP Program . . . . . . . . . . . . . . . . . . . . . . 34
R4 Staf f Knowledge and Performance in RP&C . . . . . . . . . . . . . . . . . . . . 35
R4.1 Open eel 50 289/97-09 08; Inadequate Control Over Once
Through Steam Generator Locked High Radiation Area . . . . . . . 35
R5 Staff Training and Qualification in RP&C . . . . . . . . . . . . . . . . . . . . . 36
R7 Quality Assurance in RP&C Activities ........................ 37
R8 Miscellaneous RP&C lssues ............................... 37
SI Cond' Jct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 37
V. M anag em e nt Me e ting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
X1 Exit M e e ting Su m m ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
INSPECTION PROCEDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...... 39
ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
LIST O F AC R O N YM S U S E D . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
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Report Delallt
SMmmary of Plant Statug
Unit 1 was shutdown at the beginning of @e report period for the scheduled 12R refuel
and maintenance outage. GPUN completed the outage work in 44 days. Operators took
the unit critical on October 18 and synchronized the generator to the grid on October 19.
The plant reached 100% reactor power on October 22 and remained there over the rest of
the inspection period.
l. Operations
01 i;onduct of Operations (71707,92901)'
01.1 Hung.tpl Comments
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Using Inspection Procedure 71707, " Plant Operations," the inspectors conducted
frequent reviews of ongoing plant operations. Usually, the conduct of operations
was professional and safety conscious; specific events and noteworthy
observations are detailed in the sections below. In particular, the inspectors noted
that the decision to drain the fuel transfer canal and install the reactor vessel head
with the 'A' DH system pump out of service placed the plant in a more vulnerable
condition to ensure sufficient decay heat removal capabilities.
Plant management's decision to replace the remaining 31 old design thermal barriers
during the 12R refuel outage with the now design displayed a clear commitment to
resolve the sMw CRDM drop time issue. All control rod drop times were less that
the TS limit when tested before the plant startup.
01.2 Refuel Outaae Contrpj
a. S.qgp.g
The inspectors routinely monitored control room activities and the establishment of
specific plant conditions necessary for outage work, including review of: log books,
plant status paperwork, safety systems in operation or required for standby service,
and reactor vessel water level requiremente,
b. Observations /Findinas
Overall control of plant conditions was excellent, except for severalissuas
discussed below. Operators conducted reactor coolant systern (RCS) draining and
establishment of mid loop operations very well. Reactor vessel water level
instruments were properly installed and operable. The operation department's
control and oversight of the core offload and reload were done without error.
Topical headings such as 01, M8, etc., are used in accordance with the NRC standardized
reactor inspection report outline Inunndual repons are not expected to address all outline
topics.
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During the first day on shutdown cooling the inspectors found that GPUN was
recording the outlet temperature of the reactor coolant leaving the DH system heat
exchanger as the RCS temperature. This did not appear correct since this did not
represent the bulk coolant temperature. GPUN agreed and changed the monitored
temperature to be the reactor coolant temperature at the inlet to the DH heat
exchanger,
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The operators retained proper control over the MU system pumps and valves to
reduce the possibility of RCS overpressurization whi!e in cold shutdown. Operators
performed well during restoration of the MU system, including the racking in of
circuit broniers and initial starting of the pumps, following establishment of proper
RCS condinons.
Operator training handouts on specific changes / modifications completed during the
outage were well prepared and provided the operators with needed information on
the effects of t%se changes on the operation of systems and components.
The operations department conducted the plant pressurization, heatup, and startup
very well. Control room command and control were very good.
01.2.1 Draindown to the ReAptor Coolant System Mid Looo Operation
The operating crews performed the two RCS mid loop draindown evolutions during
the 12R refuel outage, without incident, in a controlled manner. In both evolutions
the control roorn staff had two independent reactor vessellevelindications available
to ensure a level above the DH pump vortex limit. Prior changes to Operating
Procedure 110311 " Draining and Nitrogen Blanketing of the Reactor Coolant
System," have improved the operators' ability to control reactor vessel water level
and decay heat removal pump suction during RCS draindown.
On October 5,1997, with RCS level steady in mid loop operation, the inspectors
questioned the reason for the energized RCS "Draindown Level Hl/LO Alarm." At
the time of the alarm the RCS level was at approximately 14.2 inches and the low
level alarm was in solid. The low level alarm provides a warning to plant operators
that a leak or inadvertent water removal is in progress from the RCS The shift
supervisor contacted instrurnentation and control (l&C) technicians to adjust the low
level setpoint to the correct value. The l&C technicians adjusted the low level alarm
to the proper band based on the plant conditions.
01.? 2 Beview of Draindown Followina Refuelina Onen URI 50-289/97-09-01: Decav
'h" Removal Recuirements Durina Reactor Vessel Drainina
The inspectors reviewed the sequence of events fe'iowing the completion of reactor
refueling on September 29. During this review ine inspectors determined that
GPUN took actions that placed the unit in d degraded decay heat removal condition
before and during mid loop conditions U.e., only one DH pump operating and
operable) although apparently allowed by TS. A sequence of events with a
discussion of the applicable TS follows:
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Rx vessel flange 321 feet
Bottom of cold leg 314', the centerline of cold leg, or 0 inches mid-loop i
instruntents. [
!
TIME LINE
- l'
9/24 initial Conditions: Fuel transfer canal (FTC) flooded above 344 feet (> 23
feet above the RX Vessel flange), defueled. No DH system in operation. 'A'
- DH operable, but not in operation. 'B' DH out of service due to pump g
replacement and decay heat removal closed cooling (DC)/ decay heat removal
,
river water (DR) heat exchanger work.
With no fuelin the reactor vessel TS allow no DH systems to be in service.
9/26 1:30 a.m. 'B' DH operable, followir g maintenance and testing I
7:50 a.m. 'A' DH removed from service for maintenance, cannot be
restored within 24 houra.
12:00 p.m.- Fuel reload begins
TS require two operable DH systems, with one in operation, when there is ,
fuelin the reactor vessel. TS allow a reduction to only one DH system with !
FTC level maintained above 344 feet, there is no LCO for this condition.
.
9/29 06:30 p.m. Fuel transfer completed and core verified
10:00 p.m. Began draining FTC to < 344
10:50 p.m. Entered 7 day LCO on 'A' DH since level was now < 344
TS require two operable DH systems, with one in operation, when there is
fuelin the reactor vessel. TS allow a reduction to only one DH system, if
the other system is out of service for less than seven days.
9/30 3:15 a.m. Secured draining FTC, level at 341 feet
Afternoon CF system testing, 'B' DH pump secured for a short period
when injecting the 'B' CF tank.
4:55 p.m. Recommenced draining >
10/1 12:55 a.m. RCS level 323 feet 5 inches
1:55 a.m. Secured pump down. RCS level 320 :eet 8 inches
2:15 a.m. Started pumping from 'B' DH to continue lowering vessellevel
2:30 a.m. - RCS level 318 feet 10 inches (approx. 58 inches above <
centerline of cold leg)
12:30 p.m. 'A' DH pump ready for fun, sealleaks
6:50 p.m. RCS level 57 inches (hvove the centerline of cold leg) on mid-
loop instrument (MLI)
10/2 3:00 a.m. Lowered RCS level to 50 inches MLl
- 5:10 a.m. Plenum installed in reactor vessel
6:00 a.m. RCS levellowered to 18 inches MLI
--wu ~ ary-r*q5- y-97 J's -p vyv s e+ 7- y9 ge qq 3- p- sy,ww7.my--- yp ry og gy e e a+-u- qe ,pmaeg ar w: y
y--9 %,wy-+u p3,-i-aw,my p+,.-Sv-1--9g e.- -- *-
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4
1:30 p.m. Reactor vessel head installed
10/3 5:50 a.m. Filling 'A' DH
6:50 a.m. Lowered level to 12 inches MLI for HPl nozzle inspections
!
8:00 a.m. Open drains for 'A' DH sealleaked
10/4 12:50 a.m. Opened MU V94 for first nozzle inspection
1:00 a.m. RX vessel head tensioned
6:50 p.m. DH V 22A opened for inspection
10/5 8:30 a.m. Filling 'A' DH
10/6 5:20 a.m. 'A' DH declared operable following testing
'
TS required that the 'A' DH system be returned to service in less than seven days,
In review of the TS and the associated bases the inspectors questioned if GPUN
took a conservative path during this period. Specifically, the TS Bases stated that
either 23 feet above the flange would be maintained or another flow path from the
> borated water storage tank (BWST) established to maintain subcooled conditions for
seven days, before the redundant train could be taken out of-service. This seems
consistent with the improved TS that would not have allowed the draining with only
one train of DH operable.
The inspectors found that the plant review group (PRG) became involved af ter the
'A' DH pump seal f alied following initial replacement. The PRG reviewed the TS
requirement and possible ways to establish an alternate cooling path from the
BWST, if the DH pump maintenance took longer than seven days, but determined.
, that such a path had not previously been established and that developing the path
would not be a worthwhile initiative at the time. The inspector did note that the
BWST could have been used as a makeup source to the reactor vessel through the
operating DH system using the pump or just head of the tank, but that this oath
would not have provided any cooling.
Overall, the inspectors believe that lowering reactor vessel water level to a mid-loop
condition with only one means of decay heat removal was not the safety
conservative decision. Further, the inspectors questioned if the TS wording was
correct based on the wording of the bases.
01.2.3 Reactor Coolant System Fill and Vent - Open - eel 50 289/97 09-02: Failure to
Follow Reactor Coolant System Fillina Procedure
The inspectors observed portions of the two day RCS fill and vent evolution at the
end of the outage. OP 1103 2, " Fill and Vent of the Reactor Coolant System"
provided excellent precautions, limitations, and prerequisites to ensure proper RCS
'
and support system alignment for the important evolution. The prerequisites listed
_
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,
4
5
the reactor coolant bloed tank (RCBT) as the preferred water source. The procedure
contained hold points and actions at specific water level heights to ensure the fill
progressed without an inadvertent loss of water or over fill.
On October 15, the day shift supervisor (SS) displayed poor command and control
by directing the control room operator (CRO) to increase the fill flowrate, using a
flow path not allowed by the procedure. Specifically, the SS directed the opening
of the manual 'B' DH pump suction throttle valve from the BWST. The auxiliary
building (AB) auxiliary operator (AO) opened DH V 58 approximately eight turns
after hearing flow through the valve. Almost immediately the pressurizer level
recorder, in the control room, changed from a gradual increase to a prompt rise.
The CROs observed the rapid increase in pressurizer level and secured the RCS fill
from the RCBT. The CROs attempted to direct the AO to close the DH V 5B
isolation valve. However, radio communication difficulties resi ' tea in a delay before
the AO received the message und closed the DH V-58. Before a valve was
closed, approximately 50 gallons of RCS water spilled out of the CRDM sent
openings onto the reactor vessel head area.
The inspector found that the procedure only allowed the flow path from the RCBT.
The procedural guidance for the BWST make up directly to the RCS is contained in
OP 1104 4, " Decay Heat Removal System," but was only specified for crsntrolling
RCS level and specifically warns against using this path for the filling operation. OP
1104 4, Enclosure 2, step 11.1. states that "The Plant Operations Director shall
e.stablish tne level to be maintained in the RCS. Controlling the level using this
method is NOT considered to be nor should it be used as a major RCS fill and vent
method."
Further OP1103 2, Section 3.1.2,17.c provided good guidance on controlling the
filling operation as water level neared the top of the CRDMs. In part the procedure
'
stated, "when the level at the CRDM vent is observed at one to two feet below the
top, TERMINATE THE RCS FILL and hold level."
A corrective action process (CAP) form, CAP 1997 800, was initiated to evaluate
the information and determine the root cause and associated corrective actions.
Based on the mancgement review of the CAP data, a quality deficiency report
(ODR) was initiated to track the root cause evaluation and completion of the
corrective actions,
c. Conclusions
Overall, GPUN conducted the 12R refueling outage very well. Operators, despite
severallapses, displayed excellent control of plant and equipment conditions,
including draining to mid-loop and 5 refilling the RCS and in unit restart activities.
The inspectors questioned the safety significance of GPUN management's decision
to drain the RCS to mid-loop with only one DH system available. While this
appeared to be allowed by the wording of TS, the wording of the TS bases would
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.
!
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6
lead to a reasonable safety interpretation that this condition should not occur. The
inspectors considered this an inspection Followup item, pending further NRC review
of the safety significance of this issue. (IFl 50 289/97 09 01)
An SS showed a poor procedure compliance standard for the RCS fill and vent
evolution, by directing plant operators to increcse the RCS fill rate from a flow path
not included in the applicable operating procedure. The excessive flowrato led to
the overflow of approximately 50 gallons of RCS water out of the CRDM vent
openings. The lack of ::ontrols and failure to follow procedures by the SS during
the filling process appeared to be a violation. (eel 50-289/97 09-02)
05 Operator Training and Qualification
05.1 1,1 censed Ooerator Refuel Outaae Trainina
,
a. Scope
The inspectors reviewed the licensed operator requalification (LOR) training before
the 12R refuel outage. Also reviewed were the operator on the job training tasks
conducted before the refueling activities.
b. Qtuiervations/Findinns
The topics selected for the LOR continuing training were focused on details of the
12R outage, lessons learned from the last refuel outage, and industry information
related to outage problems and events.
The classroom training included lectures on the fuel handling equipment, DH system
operation, outage fuel reload topics, reactor coolant system mid loop operation, and
other refuel outage related topics. The lectures included normal operating
procedures, administrative requirements, and refuel outage problems that occurred
at TMI and similar plants. ,
In addition, all operators involved with the core offload and reload completed on-
the job training and a qualification card that contained refueling operation tasks from
the job task analysis. The training included the movement of dummy fuel bundles
and f amiliarization with the refueling equipment,
c. Conclusions
Operations and training management continue to coordinate licensed operator
requalification classroom, sirnulator, and on the job training to provide intensive
training to plant operators prior to the refuel outage, in addition, all operators
involved with the core offload and reload completed on the job training and a
qualification card that contained refueling operation tasks from the job task enalysis,
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7
ll. Maintenance
.
M1 Conduct of Maintenance (62707,61726,92902) -
t
M 1.1 General Comments ,
a, Scope
The inspectors routinely attended plant morning and afternoon outage meetings and
the morning maintenance meeting to assess the control of work and planning for
upcoming activities.
The inspectors observed all or portions of the following rnalntenance and
surveillance work activities:
I'
o Job Order Nos. 112731 and 109174, "'A' and 'B' Circulating Water Pump
Replacement."
e Job Order No. 132154, "'A' Decay Heat Removal Heat Exchanger Clean and i
Inspect."
e Job Order No. 132592, " Main Steam Safety Relief Valve MS V 218
inspection and Clearance Checks."
e Job Order No. 143061, "'B' High Pressure injection Thermal Sleeve
Replacement."
e Job Order Nos. 112731 and 112732, "'A' and 'B' Circulating Water Pump
Replacements."
e Surveillance Procedure 130311.54, "'A' Low Pressure injection Teat."
'
e Surveillance Procedure 1300 38, *lST of 'A' Decay Heat Removal Pump and
Valves." ,
e Surveillance Procedure 1300 3T, " Pressure isolation Test of FAC Valves CF-
V4A/B, CF VSA/B and DH-V22A/B."
e Refueling Procedure 1505-1, " Fuel and Control Component Shuffle." >
'
b. Observations /Findinas
Work activities associated with the circulating water pumps and other potential
protected area boundary openings were coordinated with security and operation
departments to ensure that all openings received the proper security response, ,
Additional details of the work controls are discussed in Section S1 of the report. '
l
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J
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.
8
Main steam (MS) safety relief valve work on MS-V 20B and MS V 218 was
completed with the assistance of the valve vendor. Experienced mechanical
maintenance personnel conducted the work activities and coordinated with
radiological controls when opening the valve internals for inspection.
The pressure isolati>n test of the CF valves CF-V4A/B and CF VSA/B were
coordinated effect'vely between multiple departments. Lessons learned frorn other
B&W plants such as lowering the fuel transfer canallevel before the test prevented
repeat problems that occurred at other sites. The test was done satisf actorily with
no adverse imract on the plant.
To resolvo a generic B&W problem with control rods with slow drop times following
a reactor trip, GPUN replaced the remaining 31 old design CRDM thermal barriers
with a now design during the 12R refuel outage. This demonstrated a clear
commitment to resolve the slow CRDM drop timo issue. During pre startup testing
all control rods inserted within the times allowed by TS.
Except for the work on the PORV, discussed in Section M2.1 and the 'A' DH pump
seal replacement, the maintenance work activities wero very well controlled and
dono correctly the first time. The leaking seal on the 'A' DH pump was replaced 3
times prior to stopping the leak; it ultimately was necessary to get the vendor
representative in for installation expertise. The rework on the 'A' DH pump resulted
in en extended period with only the 'B' DH pump operable for core heat removal.
M1.1.1 Hiah Pressure inioction Tilermal Sleevo Rentacement
GPUN performed wellin conducting the internal visual inspection of the four MU
system on HPl nonles. ISI engineers performed radiography and visualinspection of
the four thermal sleevo pipe sections at the RCS cold log. The inspectors observed
the internalinspection of two of the four MU injection line thermal sleeves. The ISI
engineer coordinated the inspection with operations and radiological controls
departments. The internal visualinspection was done with a camera and was
videotaped for additional review and verification of the thermal sleeve condition.
Initially, two of the four HPIlines were scheduled for inspection. After finding the
cracks in the 'B' thermal sleeve, plant management decided to perform a internal
inspection of the remaining two MU line thermal sleeves. GPUN verified that the
three other thermal sleeves were free of any cracks or flaws.
The visual inspection of the 'B' thermal sleeve revealed two 2 to 3 inch surface
cracks. The faulty thermal sleeve was replaced and tested before the RCS heatup.
The inspectors monitored the work for Job Order No. 143061, '"B' High Prese.are
Injection Thermal Sleevo Replacement." The work was done by Framatoihi
personnel who were involved with a similar repair at Oconoe Nuclear Power .utatiol
,
The site quality verificat;on (QV) personnel provided excellent oversight of the repa,
l work including the use of non destructive testing to verify the weld was performed
'
satisfactorily.
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9
c. Cnngjueions
Routino outage meetings provided good insight into upcoming work activities and
equipment problems.
For the Job Order activities observed, the work packages contained the needed
planning information and the workers properly documented the completed work.
Lessons learned from the pdor refuel outages and other plants were used during the
12R outage to prevent recurring problems. Maintenance rework was required for
the pressurizer power operated relief valve and the 'A' DH pump seal replacement.
The rework on the 'A' DH pump resulted in an extended time with only the 'B' DH
pump operable for core heat removal.
The GPUN responded proactively to the generic MU high pressure injection thermal
sleeve cracking. Af ter finding two cracks in the 'B' MU high pressure injection
thermal sleeve, plant management decided to complete a visualinternal inspection
of the remaining three MU line thermal sleeves, detecting no additional flaws.
Replacement of the 'B' thermal sleeve was well conductec' and supervised.
Plant management's decision to replace the remaining 31 old design thermal barriers
during the 12R refuel outage with the new design displayed a clear commitment tn
resolve the slow CRDM drop tirne issue. All control rod drop times were less that
the TS limit when tested before the plant startup.
M2 Maintenance and Material Condition of Facilities and Equipment
M 2.1 Open eel 50 289/97-Q903 Power Operated Relief Valve 'looerab!e for an >
Oneration Cvele
a. flagj; ground / Scone
On October 13,1997, GPUN determined that the pressurizer PORV, installed
September 23,19^5, could not be opened during the operating cycle before the
12R refueling outage, either automatically or manually from the control room. An
electrical engineer detected a wiring error after the PORV failed to operate following
the valve replacement in September 1997. The engineer reached this conclusion
based on the failure of the PORV to operate after the valve was replaced during the
12R outage and from the observation that the removed valve had also been wired
incorrectly.
The inspectors reviewed the documentation associated with the replacement of the
pressurizer PORV. The PORV was inoperable for the two-year operating cycle from
October 1995 to Septernber 1997 due to a wiring error and the failure to conduct a
PMT after the valve replacement in the September 1995 refuel outage. In response
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10 '
to the PORV PMT issue, the inspectors independently reviewed a select number of l
refuel outage work packages to evaluate the extent of the missed PMT problem, in ;
addition, the inspectors monitored the NSA PMT evaluation ec,nducted because of
this issue.
b. Observations /Findinas
4
The root cause of the event was identified as personnel error. An electrician failed
to connect the PORV wires corrsatly during the valve installation in 11R refueling.
outage. Besides the wiring crror, the required PMT on the valve following the }
installatit n was not performed and the independent verification of the wiring was
inadequate. ,
The pressurizer pressure relief function is provided by two ASME Code safety
valves, that are nuclear safety grade components and one PORV that is not a safety :
'
grade pressure relief device. The PORV was not considered to perform a safety
related function because *he valve was not required for safe shutdown of the t
reactor, maintaining it in a safe shutdown condition, nor to prevent or mitigate the
consequences of an accident as described in the UFSAR. j
'
The PRG evaluated the safety consequences of the inoperable PORV, TS
compliance, and the ASME Section XI PMT requirements. PRG determined that the
safety consequences were minimal because the accident analysis did not take credit
for the PORV to open to accomplish an RCS pressure reduction. The wiring error
resulted in the f ailure of the PORV, normally closed, to open in the automatic or
manual mode. A review of the PORV refueling interval surveillance test for the
199b refuel outage determined that the test was performed before replacement of .
the PORV during the 1995 refuel outage. Because the surveillance test was donet
before the valve replacement, it did not fulfill the ASME Code requrements for an
inservice post maintenance test.
)
The TMl 1 probability risk assessment (PRA) personnel analyzed the impact of the
PORV failure and the associated change in the Core Damage Frequency (CDF). The
PRA calculations determined that a CDF increase of 16% would occur, from 4.18E-
5/ year to 4.85E 5/ year.
The PORV does function as an approved redundant and diverse means of providing
low temperature overpressure protection (LTOP) during plant heat-up and cooldown.
TS 3.1.12 addresses the TMI LTOP mitigation system function. The T.S. 3.1.12
action statement and bases allow for other means of low temperature
overpressurization protection. Written procedure controls in the TMI Cooldown,
Heatup, and Makeup system operating procedures require that the MU pump
discharge valves MU V 16A/B/C/D and MU V 217 are danger tagged closed when
the RCS temperature is less than 332*F. The inspectors verified that the MU
isolation valves were tagged closed as required by procedure to ensure compliance
with the TS action statement during the period when the PORV was inoperable.
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TS 4.2.2 requires that ASME Code Class 1, Class 2, and Class 3 valves be inservice
tested (IST) according to Section Xl of the ASME Code and Oma 1988, Part 10,
paragraph 3.4, before returning a valve to service. Administrative Procedure AP
1041, "lST Program Requirements," Section 4.2, requires, in part, "Af ter an IST ,
valve has been replaced and before the time it is returned to service, an IST valve
test shall be performed." ,
Before the plant restart, the NSA independently reviewed the outage PMT activities
to find out if the PORV issue represented an isolated or a programmstic problem. ,
The review was focused on safety related equipment work packages that included -
multi disciplinary coordination. The focus was on electrical maintenance and safety i
related motor operated valve (MOV) work. The initial review conducted by the NSA
and OV organizations included 44 work packages. The evaluators found three work
packages that were missing tho IST documentation needed to verify proper valve
stroke times in each case the valves were stroked and the times were documented i
- using c! ectr.bal maintenance data sheets. Operations stroked all of the valves in !
question using the required IST procedure. All valve times were within the required
IST band for satisfactory stroke times. Based on this information the NSA
,
'
assessment group looked at the remaining MOV work packages (five total) and did
not find any additional problems. Because of the initial paper work discrepancies, .
NSA expanded their review to include all other plant work disciplines. No additional
'
problems were noted for the work packages reviewed (approximately 30 additional
packages were reviewed). Based on the NSA findings, plant management-
authorized proceeding with the plant startup.
The inspectors independently reviewed 10 work control packages and found one
case of a missing MOV IST data sheet, similar to that found by NSA. The problem
-was corrected satisfactorily. Four of the packages the inspectors randomly selected
were also reviewed by the NSA group including two MOV work packages that
lacked the proper IST documentation for the MOVs. I
c. Conclusions
The pressurizer PORV was inoperable for the two year operating cycle from October
1995 to September 1997 due to a wiring error and the failure to do PMT after the
valve replacement in the September 1995 refuel outage. This issue involved the
4
unavailability of the PORV during plant depressurization situations as directed by the
emergency operating procedures and on the calculated increase in core damage
-
frequency (4.18E 5/ year to 4.85E 5/ year). Failure to conduct the PMT appeared to
be a violation of TS IST requirements. (eel 50 289/97-09 03)
.
-
The PORV problems were recognized due to the diligent review and questioning
attitude _of an electrical engineer. The engineer recognized and pursued the
connection between the PORV problem found in the current refuel outage and the
possibility of the same problem existing with the previously installed PORV.
!
t
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12
The NSA Review of PMTs related to the PORV root cause analysis was
comprehensive and appropriately expanded af ter a few minor documentation
problems were found. Plant management's decision to evaluate and resolve the
minor PMT issues before plant restart was prudent.
M2.2 Review of loss of Power and Loss of Coolant Accident Outaae Eleculcal Testina. -
Open - URI 50-289/97 09-04 Emeraency Diesel Generator Testina Durino Simulated
Accidents
a. Scope
The inspector reviewed Surveillance Test 130311.10 Emergency Safeguards (ES)
System Emergency Sequence and Power Transfer Test, to verify that it met current
TS requirements for the testing of offsite power system loading and sequencing and
for the operation of the EDGs in a post LOOP and post LOCA condition.
b. Observations /Findinas
The inspector found that GPUN conducted the testing such that the EDG would
start on an ES signal, with its output breaker in a pull to lock position. There might
not be a need to have the breaker in this position since the EDG shodr' not close
onto the bus follov'ing an ES signal, since offsite power was not lost.
The next part of the test caused the simulation of an undervoltage condition,
simulating a LOOP; here too the EDG breaker was lef t in a pull-to-lock position.
Once the ernergency bus deenergized following the LOOP signal the procedure
instructed the operator to wait five seconds and then take the EDG breaker out of
pull to-lock. Once out of pull to lock the EDG breaker would close to repcwer the
bus and then the loads would sequence on.
The inspector questioned if conducting this testing with the EDG breaker in pull to-
lock met the TS surveillance requirement of " automatically start and loading the
EDG." The inspector was concerned since the test might not be conducted in a
mode where the EDG would respond automatically, and as realistically as possible,
to the simulated ES and LOOP signals. However, based on the June 1997 LOOP it
would appear that the EDGs performed their safety function and started properly.
The inspector further noted that improved TS would have allowed GPUN to take
credit for the LOOP portion of the testing, based on tt.e satisfactory performance in
June 1997. The inspector considered this issue Unresolved pending further review
by the NRC staff concerning suitability o" this testing to meet TS requirements.
(URl 50-289/97 09-05)
c. Conclution
The inspector identified a question concerning the appropriateness of testing an
EDG in simulated LOOP and LOC A conditions with the output breaker in the pull-to-
lock position. This issue was considered an Unresolved item pending further NRC
staff review.
, _ _
d
.
13
M8 Miscelleneous Melntenance issues
M8.1 fdosed - VIO 50 289/96-07 01: Safety Related Scaffoldina
a. Scope (92902)
,
The inspectors reviewed the corrective actions carried cut because of the previoust,-
identified scaffold violation,
b. Observations /Findinas
GPUN responded to the Notice of Violation (NOV), 50 289/96-07 01, in a letter
dated December 24,1996, which provided background information regarding the
scaffold construction problems and failure to follow procedure 1440 Y 3, " Scaffold
Construction / Inspection and Use of Extension Ladders." The root causes, as
determined by the licensee, included the failure to use standards policies, and
administrative controls; fack of attention to detail by the maintenence; and in one
case the operations personnel inspecting and using the scaffolds. Short term
corrective actions had been previously rs,iewed by the inspectors and were
adequate to correct and prevent recurrence of similar problems. The long term
corrective actions and quality of scaffold construction in safety telated areas were
reviewed during the 12R refueling outage.
The inspectors observed the installation, inspeedon, and approval of scaffold
constructed in the safety related areas of the plant including the RB. The scaffold
construction and use was controlled by 9,e procedure with no problems noted. The
long term corrective actions included incorporating the lessons learned from the
event in the operators' training classes, scheduling personnel for self-checking,
effective observation and coaching techniques training, and management support
and leadership to foster an environment that encourajes attention to detailin this
area. The inspectors reviewed the application of the longer term corrective actions
and found that they were adequate to prevent similar events. This item is closed,
c. Conclusions
The licensee's corrective actions were appropriate and timely to prevent recurrence
of violations regarding scaffold construction in safety related areas of the plant.
M8.2 laservice insogglion (73753,73755)
a. hann
The inspector reviewed portions of the ISI p*ogram and related nondestructive
examination (NDE) activities that were according to the ASME Code Section XI
1986 Edition and required by 10 CFR 50.55 a(g). Specific areas inspected included:
qualification and certifications of the NDE contractors
observation of NDE activities
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
.
.
14
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effectiveness of GPUN's controls over ISI NDE contractors
review of approved ISI NDE procedures and examination data
review of FAC monitoring program
b. Dhiqtyyliqns/Findinas
s
GPUN utilizes NDE contractors to do ISI NDE examinations. The contr::ctors must
successfully complete a proficiency examination in the specific NDE method, before
that NDE method can be applied to examination of plant components. Proficiency
examinations are administered by a TMI NDE Levelill. The proficiency extimination
includes demonstration of understanding the TMl NDE procedures and performance
of practical examinations. The inspector verified NDE ISI contractor qualification
and certifications were following the ASME Code and the TMI procedures.
The inspector observed NDE contractors performing ultrasonic testing (UT) of
reactor coolant pump main flange bolts and emergency feedwater header to flange
welds, using TMl procedures NDE UT 09 and NDE-UT 02 respectively. These
activities were well planned and performed according to procedure. The inspector
also observed TMI's NDE Level lliinvolvement in the examination being parfurmed
on the reactor coolant pump main flange bolts. TMI's NDE Level til audits the NDE
contractors during examination of plant components to assure procedures are being
followed.
The inspector reviewed the approved ultrasonic testing (UT) procedures and the
completed examination data packages. These examinations were performed
according to procedures, and the data packages were complete and properly
documented.
The inspector reviewed the TMI technical document ieport (TDR) No.1065
Revision 2, which provides details and component evaluation results of the FAC
program inspections completed at TMl since 1983. This TDR also presents FAC
theory, component summaries, and program development. GPUN is currently using
CHECWORKS, the latest released computer program from Electric Power Research
Institute (EPRI), as a functional database for FAC information and to aid in
component wear rate estimations. Data from CHECWORKS can be directly
transferred to Microsoft Excel. This reduces the risk of human error in data
transfer, TMI was scheduled to examine 110 components during the 12R outage.
Of the 110 components, 40% are being reinspected from previous outages. Thirty-
two foodwater risers were inspected with Icas of pipewall thickness found on one.
TMI's evaluation criteria for scheduling reinspection was based on the estimated
safe operating life and the disposition of degraded components.
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..
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15 ,
c. .Qonclusion
The ISI NDE program at TMI is well planned and organized. Observed ISI
examinations were performed according to procedure. The random audits by the
NDE Level 111 provide assurance that the NDE examinations are being done
rocording to procedure. The examination data sheets were complete and properly
.'
amumented. The FAC program was found thorough, effective, and capable of
predicting the depletion of piping wall thickness. ,
M8.3 Om Throuah Steam Generator Tube Eddy Current Testino and Related Work
'(73753,73755)
a. Scope
The purpose of this inspection was to review and observe the implementation of the .j
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licensee's eddy current testing (ECT) program during Outage 12R for the TMI 1-
OTSG tubes, plugs and sleeves. The inspection covered the program
implementation to verify the outage testing met TS requirements and ASMF Section
XI Division 1, Rules for ISI of Nuclear Power Psant Components.
During this inspection period (12R Outage) the tube indication acceptance criteria
has been revised to provide further definition oetween tube " imperfections" and a
" degraded tube". This new acceptance criteria has been added to the TS to enable
the classification of tube indications which are outside the current criteria for-
" degraded". Those indications which do not meet the " degraded" criteria
(indications are smaller then the minimum threshoid) will be further evaluated to a
new criteria defined as " imperfection." These additional criteria will enable the
'
classification of tubes with inside diameter intergranular attack (IGA) that cannot be
through wali depth sized. This new criterion provides a category for patch-like IGA
indications and not those which may be indicative of a crack.
Discussions regarding the work were hold with supervisory individuals responsible
for these activities and with the individuals'doing the inspection. Observations of
work in progress were made Dy the inspector.
b. Observations /Findinos
The TMI-1 RCS includes two OTOGs identified as 'A' and 'B' Each OTSG contains.
15,531 Inconel 600 tubes, fifty-six feet long with an outside diameter of 0.625"
and a nominal wall thickness of 0.037".
The licensee planned to inspect 100% of the tubes in both OTSG 'A' and 'B' during
this outa0e (12R). This level of inspection for this period, exceeds the requirements
of TS 4.13, OTGG Tube ISI. The TS provides the requirements for tube inspection
frequency at TMI-1. The licensee also planned to remove and replace existing tube
plugs made from inconel 600 with pMgs made from inconel 690.
. . .. . - ..-.- - . - - . . . . . - .
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16
The licensee had conttructed on site, a full scale " mock-up" of the OTSG for
training of personnel in the installation of the actual ECT test equipment. The
placement of this equipment is a crucial element in enabling the installation and
operating personnel to conclusively assure tube identification during the
examination process. The inspector observed the completed positioning of this test )
equipment in both the lower and upper heads of the OTSG " mock-up."
The inspector observed that initial examination of the tubes was being poh med
from the inside diameter of the tube using the bobbin coil probe. No exd 'ons
were being performed from or on the outside surfaces of the tubes. Tubh
identified with indications that cannot be characterized using the bobbin co;l probe,
those with cracklike indications below 40% throughwall, and indications 40% (or
greater) of through wall thickness are then examined in the area of interest using a
motorized rotating pancake probe (MRPC).
The inspector noted that the licensee had contracted with an outside vendor
(Framatome Technologies incorporated, FTI) to do this e,xamiraation. The
examination was performed using FTl Procedure 54-ISI 400-05, Revision
July 7,1997. Multi-Frequency Eddy Current Examination of Tubing. Data
collection and Analysis was conducted following GPUN Procedure NDE ECF03,
Revision 1, Change Number 2, Analysis of OTSG Eddy Current Data. The data
acquisition, data management and resolution analysis were conducted on site at the
data acquisition center (DAC). At this location, operators verified tube identification
and, using the remotely operated manipulator, inserted the probe and monitored the
probe position and function for each individual tube. The data was evaluated by the
technicians as it was accumulated with attention to any indications of poor probe
performance, signs of deterioration or axcessive probe wear. When indications of
such malfunctions were noted by the ;echnician, he probe was replaced and
previous affected tube examinations were repeated
The data acquired is transmitted off site for analysis at two separate ana$is
" stations" by a primary and a secondary analyst. Resolution of allinterpretation
discrepancies from the primary and secondary analysts is performed on site in the
DAC by the Resolution Analyst. Provision is made for feedback to these analysts of
all changes to their " calls." The original examination results are retained at the DAC
to assure these data can be retrieved as recorded.
The inspector observed the data acquisition, data management and analysis
restdution activities and found them to be following the above procedures, ASME
Seeraon XI and the TS. The inspector performec a verification that personnel doing
the inspections and the resolution analyst had been qualified for these activities
and, their qualifications had been reviewed and approved by the licensee's NDE
Specialist.
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4
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17
At the time of this inspection during the week of September 22 through 26,1997,
the inspection of the tubes in both OTSGs was in progress. The inspection using -
the bobbin coil probe was essentially complete and the examination of "special
interest" tubes had begun. The "specisiinterest" tubes are those where indications
have been identified which require further examination for accurate characterization.
Also, extraction of the previously installed Inconel 600 tube plugs was underway.
This replacement activity with inconel 690 material, intended to prevent tube
-leakage, had not commenced during the inspection.
INSPECTION STATUS AT INSPECTION CONCLUSION
INSPECTIONS OTSG "A" OTSG "B" OTSG "B"
Scheduled Completed Scheduled Completed
,
a Complete Tube 14028 14028 15114 15114
(0.510 dia, probe)
'
(0.540 dia, probe) 235 235 39 39
(0.540 HF-Expanded 74 74 51 51
Scope)
17 inch Kinetic Exp 3483 3483 3470 3470
22 inch Kinetic Exp 238 238 232 23
Final Resolution of 1?O28 14022 15114 15107
Indications (1 and 2
above)
Sleeve, Sleeve Plus Point, Lane and Wedge, l- 690 Plugs, Westinghouse Plugs and
Rerolls were 100% complete at the conclusion of the inspection. Plug extraction,
retests and analysis resolution were still underway at the conclusion of the
inspection.
4
,
c. Conclusion
The eddy current inspection program for the OTSG tubes at TMI 1 was found to be
'
well planned and organized, and capable of determining the integrity of the steam
generator tubes. The inspection met ASME Code,Section XI and TS requirements.
,
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111. Enoineerina
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'E1 Conduct of Engineering (37550,37551,92903,93809)
-E1.1 Core Flood Svstem Review Introduction and Puroose
a. Scope
The CF system is part of the emergency core cooling system (ECCS) and provides a
rapid injection of borated water into the reactor vessel, for core cooling and
reactivity contrci during a large break LOCA. The inspection evaluated the CF
design basis and how it complies with 10 CFR 50.46, " Acceptance Criteria for
Emergency Core Cooling System for Light Water Nuclear Power Reactors."
'E1.2' Evaluation of the Desian Basis
a. Scope
,
The inspectors evaluated aspects of the CF DBD to verify compliance with 10 CFR
E0.46. The inspectors reviewed applicable sections of TS, sections of the UFSAR,
operating procedures, emergency operating procedures, test procedures, and codes
ar'd standards. In addition the inspectors evaluated if changes made to the system
were appropriately reflected in the DBD. The current DBD TI 213-0, was dated
June 3,1996; 10 CFR 50.46 " Acceptance Criteria for Emergency Core Cooling
System for Light Water Nuclear Power Reactors;" The Safety Evaluation Report
'
(SER) by the Atomic Energy Commission (AEC), dated July 11,1973; and the
b. Observations /Findinos
E1.2.1 Li.censino and Reaulatorv Reauirements
The inspectors verified that the above CF documents agreed, and that the UFSAR
and the DBD have been correctly maintained to reflect the design criteria listed in
i- 10 CFR 50.46. The DBD was maintained in a computer based system and updated
, continuously as changes were made to the CF,
The DBD was in hard copy form and contained references collected, copied and.
included within the document. The inspectors verified the validity of the references
of the subject matter to confirm compliance with the_ design bases for the area of
interest. For example, the inspector reviewed fourteen references, including
calculations, publications, bulletins, generic letters, codes and standards, licensing
documents, etc. to assess core flood tank (CFT) liquid volume (discussed in Section
E1.4.2 of this report). Other similar reviews, by the inspectors, showed the DBD to
be " easy to use" and thorough in describing the design basis.
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The inspectors reviewed sections 3.1.6.1, 3.1.6.10, 3.3.1 and 3.3.2 of the TS and
compared them with the DBD. The ir.spectors verified that the TS bases for the
sections reviewed were discussed and repres9nted in the DBD, showing how the
design satisfies the TS basis. Both TS and the DBD related the information
necessary for the inspectors to confirm that they satisfy the five design criteria set
forth in 10 CFR 5046. The five criteria stated that (1) the peak cladding
temperature of 2200*F, (2) the maximum cladding oxidation vf 0.17 times the
cladding thickness, (3) the maximum generation of hydrogen of 0.01 times the
hypothetical amount that is possible, (4) the coolable geometry, and (5) the long-
term cooling will not be exceeded.
E1.2.2 Interface With Chemistry and Samolina
TS 3.3.1.2 requires that the boron concentration for the CFTs shall not be less than
2270 ppm boron. This chemistry requirement would maintain the boron
concentration higher than that of the RCS. The higher concentration ensures that
the injected water, in the event it is needed for a large break loss of coolant
accident (LBLOCA), will not dilute the borated water present in the RCS. The
inspector reviewed the chemistry sample results for the past two years and
determined that the results exceeded the TS minimum requirement.
The DBD discussed the interfaces with the sarapling system. The inspector noted
that a design change for the sample system was recently completed to add relief
valves to the sampling system to satisfy the requirements of Generic Letter 96-06.
Refer to Section E1.4.3 of this report for details.
E1.2.3 Mechanical Maintgange
The inspector reviewed the corrective maintenance performed on the CF for the
past five years to determine if any patterns of problems were present and to
determine if longstanding problems existed. The record showed that the corrective
maintenance on the system was not extensive, there was no backlog, and repetitive
problems did not exist.
E1.2.4 Electrical Distribution Svstem
The inspectors reviewed applicable portions of IEEE Standard 279-1971, " Criteria
for Protection Systems for Nuclear Power Generating Stations," and compared
those requirements to the design basis requirements in the DBD. No discrepancies
were found.
The inspectors verified that operating procedure 1104-1 has appropriate procedural
steps in place to energize and open valves CF-V-1 A&B when reactor coolant
pressure is > 650 psig but less than 700 psig. The inspectors also verified that the
l procedure has appropriate steps to ensure that, when reactor coolant pressure
reaches 2155 psig, but prior to ci.icality, the breakers are opened and tagged to
!
prevent inadvertent closure of ths Notation valves. Circuit breakers "1 A Rad Waste
j Control Center (RWCC) Unit 6C" (CF-V-3A) and "1B RWCC Unit 6B" (CF-V-38)
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20
were verified to be open and tagged by the inspector to preclude inadvertent valve
movement. The inspectors noted that these actions are consistent with the DBD.
The inspectors verified that during plant heatup, appiopriate steps were in place to
operate the breakers when necessary. The inspectors also ver;fied that during plant
cooldown appropriate steps were in place to close the circuit breakers and close CF-
V-1 A&B prior to depressurizing below 700 psig in the primary coolant system. The
'
inspector noted that these actions are also consistent with the DBD.
E1.2.5 Instrumentation and Control-
TS Table 4.1.1, item 25, requires that a calibration of the CF pressure and level
instrumentation be performed during each refueling outage to show proper operation
of the system. The licensee extended the operation cycle from 18 months to 24
months. The inspectors reviewed calculation number C1101-2 i3 5350-011,
Revision 0, "CF Tank Pressure and level Channels 24 Month Drift Calculation." The
inspectors verified that the calculational assumptions were technically reasonable,
and that the calculation provided adequate justification to extend the calibration
cycle to 30 months.
The inspectors verified that procedure number 1302 5.15, revision 21, "CFT
Pressure and Level Chann.41," was properly upgraded.
The inspector also verified that the design changt was accurately described in the
E1.2.6 Environmental Qualification
The inspector reviewed the following documents:
- GPUN Technical Data Report, TDR 598, " Methodology and List of Equipment
Components Requiring Radiation Qualification for Small Break Loss of
Coolant Accident Mitigation," revision 1
- GFUN Technical Data Report, TDR 648, " Methodology and List of Electrical
Components Requiring Environmental Qualification for Large Break LOCA and
High Energy t.ine Break (HELB) Mitigation," revision O
e TMI Document Number 9901429, revision 14, "TMI-1 Environmental
Qualification (EO) Master List"
- GMS-2 Environmental Qualification, System Component Evaluation
Worksheets (SCEW) sheets T1-213-001 thru 012
The inspectors noted that the above documents provided adequate justification
about why specific CF components are qualified or exempt from radiation and high
energy line break (HELB) environments. The inspectors verified the containment
isolation valves located in the RB and the AB require radiation qualification because
of the harsh environment during a small break or large break LOCA. Valves CF-V-
- _ _ - - - _ _ - _ _ _ _ _ _ _ _
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.
21
2A&B also require HELB classification because of their location in the RB The
remaining isolation valves (CF-V 19A&B, CF V 20A&B) do not require HELB
classification because of their location outside the RB.
The inspector verified that the CFT isolation and vent valves (CF-V 1 A&B, CF V-
3A&B) do not require radiation or HELB qualification. The inspectors noted that
these valves would be in a harsh environment after they complete their accident
function. The inspectors verified that EQ valves motor control center (MCC) breaker
cabinets for valves CF V-1&2 do not require radiation or HELB qualification. These
cabinets are located in areas which have a mild radiological environment during
normal operating conditions and/or postulated small break LOCAs. The inspectors
found that there was appropriate classification between the DBD and reviewed EO
documentation.
E1.2.7 Core Flood Tank Heaters
The CFT heating system was originally installed to maintain the tanks above the nil
ductility transition temperature (NDTT) (85 F plus a safety factor) to reduce the
potential for brittle fraction of the tank walls. B&W, however, recommended the use
of a lower hydro test temperature (70'F). In 1995, GPUN reevaluated their
selection of the NDTT + 30 F CFT temperature and reduced the CFT temperature
limit to the hydro test temperature.
The inspectors reviewed the "CFT Temperature Limitations" Safety Evaluation, SE-
00023 005. The inspectors located original correspondence regarding the selection
of the CFT temp;jture limit. The inspectors also reviewed an independent
assessment of SE-UOO23-005 performa.' Sy B&W, which concurred with the
technical basis of the reduced CFT temperature limit.
Through the review of the above, the inspectors determined that containment
temperature does not go below 75 80 F. The inspectors determined that the
heaters have not been used to maintain the CFT temperature greater than 70*F.
The operators provided records documenting the monitoring of the CFT tank
temperature and the systt.m engineer provided the calibration and verification
schedule for the CFT temperature instrumentation. Even though the heaters are not
used on a regular basis, the inspectors determined that operating procedures require
the CFT heating systems to be available in standby.
E1.2.8 Inservice Testina
information Notice 09-67, " Loss of Residual Heat Removal Caused by Accumulator
Nitrogen injection," alerted licensees to potential problems resulting associated with
the injection of nitrogen from the accumulator into the RCS during shutdown
conditions, in their 1989 response to this Information Notice, GPUN provided a
rationale for determining that Information Notice 89-67 was not applicable, based
on performing Surveillance Procedure 13003-11.21.
.
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22
Calculation C1101213-E270-014, Revision 0, " Core Flood Check Valve Test
Analysis," determined a maximum final CFT pressure to avoid leakage into the RCS,
based on the water height in the fuel transfer canal and the height of the CFT
connection. The premise of this determination was that if the water levelin the
CFT remained above the height of the CFT connection, the nitrogen gas would not
be able to expand to the CFT connection and be injected into the RCS,
Surveillance Procedure 1303-11.58, " Core Flood System Test for IST," was
completed on September 30,1997, and observed by the resident inspectors.
Nitroqen from the CFT was not injected inte the RCS.
E1.2.9 Testina
The inspectors verified that the CFT valves listed below were in the Inservice
Testing Program. TMI-1 Administrative Procedure 1041 "lST Program
Requirements" specified the valves that are within the scope of the IST program:
, * CF-V1 A/B - CFT isolation valves
- CF-V 2A/B - CF containment isolation valves
- CF-V-4A/B - Check valves outside secondary shield
- CF-V-5A/B - Check valves inside secondary shield
- CF V-12A/B - Check valves downstream of CF-V-19A/B
- CF-V-19A/B - Makeup and nitrogen supply valves
- CF-V 20A/B - Sample and drain valves
The CFT relief valves were recently added to the IST program. The inspectors,
reviewed IST results from Outage 12R and verified that testing has been performed
for the above valves. The inspector verified that the recently added relief valves
were also tested,
c. Conclusion
The inspectors concluded that the documents, listed above, were correctly
maintained and display the means to maintain the design basis of CF according to
the five design criteria in 10 CFR 50.46. The inspector also concluded the DBD, for
the CF, was " easy to use" and thorough in describing the design basic.
The boron cencentration of the CFTs was being maintained and sampled following
TS requirements.
The relatively low amount of maintenance history for the system, plus the results of
the physical walkdown (see Sectinn E1.3 of this report) led the inspector to
conclude that the CF was well maintained.
Do,:uments were consistent with the applicable sections cf the DBD, UFSAR, TS,
IEEE standards, procedures, system drawings and system layout. Adequate
procedures were in place to operate the CF within its design basis.
- _ _ - _ _ _ . - - _ _ _ _ _
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23-
The design change and calculation reviewed were adequate to support system
operability extension to 30 months.
EQ documentation was consistent with the DBD, and that justification for CF
component evaluation were adequate.
The CFT heaters have not been used since implementing a 1995 Safety Evaluation
which decreased a CFT temperature limitation. The use of the decreased
temperature limitation was consistent with industry practices and the
recommendation of the Nuclear Steam System Supplier, B&W. The inspectors
verified that document and procedural changes accurately reflect the new CFT
temperature limitation.
GPUN adequately considered nitrogen injection in planning and performance of
Surveillance Procedure 1303 11.58. ,
The inspectors concluded that the CF system valves that require testing by the
ASME code were in the IST program and that testing was performed as scheduled.
E1.3 System Wt,lkdown
a. Scope
The inspectors performed a walkdown of the CF to evaluate the material condition
of the system and its consistency with the P&lD and electrical system drawings.
b. Observations /Findinas
The material condition of the CF was good. The inspectors paid particular attention
to CFTs, isolation valves, vent vet tes, various interface piping, valve flanges and
caps, level and pressure transmitters, instrumentation and electrical system wiring
interfaces, and piping insulation. Th3 inspectors found no discrepancies between
the P&lD (drawing number 302-711, revision 25, " Core Flooding Flow Diagram,"
the actual system layout, and the DBD.
c. Conclusions
The material condition of the CF was good, and consistent with the P&lD, the
actual 3ystem layout and the DBD.
E1.4 Related Desion Chanaes
The inspectors reviewed design changes: (1) " Replacement of the CF Valves 1 A
and 1B Motors," (2) "CFT Water Volume Change," (3) " Relief Valve Addition to the
Sampling System," and (4) "CF transmitter Replacement" to determine if the system
design control and licensing input information met the design basis.
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E1.4.1 Replacement of the Valves Motors
a. Scope
Isolation valves CF V-1 A&B were intended to isolate the CF from the reactor vessel
during shutdown conditions when the RCS is below 600 psig. The original motors
were two pole high speed motors with a Dings break. The motors caused damage
_
to the valves and were replaced with four pole motors without a break. The closing
of the valves time increased from 10 to 20 seconds. The inspector evaluated the
design change to determine compliance with changes to the facility and to review
,
compliance with the design basis,
b. Observations /Findinos
The inspectors reviewed design change T1-MM-418668-OO3 developed to change
the motors on CF-V-1 A&B. The safety evaluation and 10 CFR 50.59 assessed the
motor's increased time and the lack of a break. The increased time was not a
factor for the intended operation of the system, because the valves are opened and
locked prior to the need for the system. The slower movement of the valve in
closing was more controlled and no break was required. The safety evaluation
properly concluded that the change to the CF did not affect the response time of
the CF to carry out the safety function as designed. ~ ne breakers for the motors
were also changed to satisfy the new motors. The inspectors reviewed the
materials list and the purchase order and verified that the breakers and the motors
installed were as ordered and received by the quality assurance inspection. The
inspector verified that the valves were in the valve testing program and received
testing following the ASME code. The inspector also verified that the UFSAR was
. changed to reflect the new motor's speed.
c. Conclusions
The inspectors concluded that since the CF is a self-contained, self actuated and
passive system, the changing of the valves and breakers would not affect the
operation of the system during a LBLOCA.
E1.4.2 Volume Reauirement Chanae
a. S.cgst
The CFT volume of borated water has changed since the original design. The
inspectors evaluated the reasons for the volume change, and a newly proposed
change implemented during 12R. The inspectors evaluated applicable calculations to
determine if the design bases were satisfied. The design is intended to provide
enough borated water to imep the core covered and provide core cooling.
4
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b. Observations /Findinas
The liquid inventory of the combined CFTs is based on the approximate volume of
the reactor vessel downcomer and lower plenum. The original calculation showed
the minimum level of each CFT (two installed) as 897 ft'. The plant operated with
CFT liquid volume of 940145 f t' until 1971, when ECCS rules were changed
prompting new studios that resulted in increasing the volume of each CFT by 100
ft'. The new volume was to compensate for water loss during blowdown, and to
reduce nitrogen entering the RCS after the CFT pressure equalizes with RCS
-
,
pressure,- by reducing the nitrogen pressure when the tanks are emptied, in new
studies performed by B&W, and in particular, engineering analysis 51 1244420-00
pe formed to power upgrade the reactor from 2568 MWt to 2772 MWt show a
volume change was required.
~!
These studies were performed using B&W's REFLOD3B code that simulates
hydraulic behavior of the primary system during refill and reflood phases of a
3
LBLOCA. The studies showed that the most conservative approach to the tank
volume-versus pressure ratio was to reduce the volume to 940 30 ft', and increase
the nitrogen pressure to 600125 psig. This change will enable the water to be
injected quicker. The volume was actually in the same range as the original
calculation for water volume for the CFT.
- Tha above was submitted, by the licensee, to the NRC for a TS Change. The
inspectors reviewed the NRC's safety evaluation and approval to operate with the
volume discussed above. The inspector evaluated the calculation for setting the
level to correspond with the proper volume. The inspector verified tank volumes
and alarm setpoints were changed according to the calculation, and that the
appropriate changes were made to the TS.
c. Conclusions
The original CFT volume design basis was not compromised, and currently meets
the latest studies conducted by B&W and accepted by the NRC. The inspector also
concluded that the latest volume to pressure ratio'of the CFT supports the licensees
proposed power upgrade.
,
E1.4.3 Relief Valve Addition to the Samole System
a. Scope
GL-96-06 requested the evaluation of fluid piping systems that penetrate
containment for susceptibility to thermal expansion which could cause pipes to
rupture. GPUN determined that the piping between the containment isolation valves
CF-V-2A&B and CF V 20A&B on the sample and drain line was susceptible to
overpressurization during abnormal conditions and thermal relief valves should be
.
4
e % -e c w =- -%- - --a,r -r--, g.-vi -, - e-= +-- g--a.- - -
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26
added to the s/ stem. The inspectors reviewed this design change to determine if
the added relief valves could relieve the overpressurization concerns expressed in
GL 96-06. The inspector also reviewed the containment leak tightness of CF-V-46
A&G ss required by 10 CFR, Appendix J.
b. Observations / Finding
Relief valves, CF-V-46A&B, were installed to the piping between CF V-2A&B and
CF-V 20A&B to relieve excess pressure during abnormal conditions. The inspectors
reviewed the results of the pressure integrity, lif ting pressure, and re-seal pressure
tests. The tests indicated that the valves lifted at the design pressure (~ 1500 psi)
and re-sealed at the appropriate pressure (approximately 84% of the lift pressure),
and that the joints maintained the pressure boundary (no visible signs of !eakage).
The inspectors also reviewed the results of TMI 1 Surveillance Procedure 1303-
11.18, "RB Local Leak Rate Testing." The purpose of the RB local leak rate tests
was to determine the leak tightness of several valves, including CF-V-46A&B. The
results showed that the tested localleak rates for CF-V-46A&B was below the
calculated target leak rate criteria as defined and calculated in TMI-1 SP 1303-
11.18.
c. Conclusions
Based upon the review performed, the inspectors concluded the testing performed
on CF-V-46A&B provided confidence that the design modification could relieve
excess pressure during abnormal conditions and maintain the RB pressure boundary.
E1.4.4 Transmitter Replacement
a. Scope
GPUN replaced the CFT level transmitters with Rosemount transmitters because of
the reliability and maintainability of the originally installed Bailey transmitters. The
inspectors evaluated the design change for compliance with GPUN's procedures.
The inspectors also reviewed licensee documentation to insure that the new
transmitters met NRC Bulletin 80-16, " Potential Misapplication of Rosemount
Transmitters."
b. Observations /Findinas
The inspectors reviewed design change package (DCP) 1165, 9/6/78, " Replacement
of Bailey "BY" Transmitters on the CFTs." This DCP installed Rosemount
transmitters in place of Bailey transmitters to monitor CFT level. The inspectors
verified that the DCP contained sufficient documentation to permit evaluation of the
effect of this change on the design and licensing basis. The package documented
the necessary procedure and drawing changes, adequate installation instructions,
and appropriate retest instructions. The inspectors verified, during the walkdown of
the CF, that the Rosemount transmitters CF2-LT1\2\3\4 (Part Number
. . .
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27
1151DP5E22PS) were installed as required by the DCP. The inspectors also ,
'
- reviewed maintenance records for the CF (see Section E1.2.3 of this report) and
determine that no maintenance was required for the transmitters since their
installation.
The inspectors reviewed Bulletin 8016, " Potential Misapplication of Rosemount
Transmitters," and the licensee's response, to verify that the Rosemount
. transmitters with either 'A' or 'D' output codes were not used in the CF. The
Rosemount transmitters with either 'A' or 'D' output codes would provide
ambiguous signals when exposed to excessive over or reverse pressure conditions.
The inspectors verified that the Rosemount transmitters installed and those in the
warehouse use 'E' codes and are not effected by the over or reverse pressure
conditions.
4
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c. Conclusions .
Based on the systern waikdown and the review of calibrations and maintenance
records, the inspectors concluded that the replacement of the transmitters on the ,
CFTs increased the reliability and maintainability of the levelinstrumentation. The
+
inspectors also ccncluded that the new transmitters were not in conflict with
E1.5 Review of NRC Bulletins. Information Notices. Generic Letters
a. Scope
The inspectors conducted a search of NRC Bulletins, Information Noticos, Generic
Letters from 1979 to present. The search found that several were applicable to the
CF. The inspectors reviewed the licensee's actions regarding the information
. presented.
'
b. Observations /Findinos
The following NRC documents were applicable to the CF:
,
- Bulletin 80-16 contained concerns regarding rosemount transmitters. See
'
Section E1.4.4 for inspector findings.
- 1rfrmation Notice 89-67, " Loss of RHR Caused by Accumulator N'
1r.ection" see Section E1.2.8 for inspector findings.
- = Information Notice 91-05, "Innergranular Stress Corrosion Cracking in the
PWR Safety injection Accumulator Nozzles." The inspector reviewed GPUN
.
memo " Review of Information Notice 91-05..." that disclosed the problem
was found at a Westinghouse Plant in a 304 stainless steel nozzle. The TMl
design was carbon steel clad with stainless with a different weld
1
- , , ,, - - - _
, --
- - _ _ ._ . . ___ ___ _ . . - _ . . _ _ _ _ _._
,
.
28
configuration. The document also showed that there was machining of the
internal diameter weld surface which removed the stresses prior to cladding.
The inspector concluded that the TMl design was different than the nozzle
referenced in the Information Notice.
e Generic Letter (GL) 96-06. GL 96-06 requested the evaluation of fluid piping
systems that penetrate containment for susceptibility to thermal expansion
that could cause pipes to rupture. See Section E1.4.3 of the report for
, inspector findings.
c. Conclusions
The inspectors concludtd that the licensee was properly acting upon information
from the NRC to enhance the operation of the CF, or to assess problems applicable
to the CF.
During the inspection no UFSAR concerns were identified.
E8 Miscellaneous Engineering issues
E8.1 _( Closed) Violation 97-07-01: Failure to Write a Clear Licensee Event Reoort
Narrative:
GPUN failed to provide an adequate description of multiple over pressurizations of
4 the make up system suction piping in LER 97-003. The inspectors verified that the
licensee has taken corrective actions by issuing new guidance for the formulation of
LERs. GPUN also hired a root cause analysis trained person to fill the position of
" Organizational Effectiveness Coordinator." The position will oversee root cause
analysis and the CAP. These two functions will be key to the development of the
LERs. In addition the licensee resubmitted the LER that now correctly recounts the
events in a more clear and concise manner.
E8.2 Modification Review - Letdown Valve Closina Caoability Uoorade
B. SCDPft
The inspector reviewed the modification installed on the MU outboard letdown
isolation valve (MU-V-3), to improve the isolation capability.
.
b. Conclusion
The modification installed an air to close function on this air operated valve; this
increased the ability of the valve to close under system flow and differential
pressure.
The modification package was detailed and well developed and post-modification
testing appeared complete,
i
, -
- . . - . - -- - _ . _ _ _ _ - _ _ _ _ _ _ _ - _ - _
-
0
0
29
IV. Plant SuDDort
R1 Radiological Protection and Chemistry (RP&C) Oontrols
R1.1 General Plant Tours (71750)
a. SS&pg
The inspector made routine tours of the RB, AB, and the intermediate building (IB)
during the outage looking at material and radiological conditions, and plant
housekeeping. The inspectors also toured the site at night to determine that ability
to monitor the protected area boundary,
b. Conclusions
Material conditions continued to ba good. Equipment needed to meet TS
requirements for chutdown conr'itions was maintained and operated well.
The inspectors found radiolor, cal conditions adequate; however, there were
instances noted where local postings did not agree with the area conditions and
where material was allowed to cross contaminated area boundaries. In these cases
the radiation protection staff corrected the conditions. The controls in place for
highly contaminated and high radiation areas, such as the OSTGs appeared proper.
Generally the inspectors found that housekeeping degraded over the outage. This
degradation was particularly evident in the RB, where outage related activities cause
the large amounts of debris to be left on floors and surfaces The debris observed
included nails and pieces of wood and sawdust from scaffolding activities, plastic
tie-wraps from the installation of temporary hoses and cables, a large roll of sheet
plastic, pop-rivet stems from sheet metalinstallations, and tape materials left
following work.
The inspector noted no deficiencies during a n.sht tour of the protected area.
R 1.2 Radiolooical Controls-External and Internal Exoosure
a. Scoce (837501
The inspector reviewed the licensee's control of external and internal exposure.
Information was gathered through observation of activities, tours of the
radiologically controlled area (RCA), discussions with cognizant personnel, and
review and evaluation of procedures and documents.
b. Observatic is/Findinos
Radiation work permits (RWPs) and controls in place in the field for various work
evolutions were reviewed, observed, and discussed with the licensee staff. The
activities involving incore instrumentation replacement, CRDM work, and OTSG
. _ . _
. _ ______ . _ _ _ _ _ _ - . - _ _.__.______ . . _ . _ _ _ .
.
i.
...
30
.. tube eddy current testing were especially inspected. Appropriate proper personnel
protective clothing and equipment, precautions and instructions were being
prescribed for the work descriptions and radiological conditions at the work sites. A
pre-job briefing for stuck incore cuttings work was detailed, thorough, and
emphasized an understanding of the work sequence and individual responsibilities.
The pre job ALARA review and RWP for recent diving operations in the spent fuel
'
pool were reviewed, and these documents plus the personnel doses received during
these diving operations were discussed with cognizant licensee personnel. Diving
operations had been well centrolled, and lessons learned from recent operational
experience at another site had been incorporated. Individual and cumulative dose ,
'
,
'
were examined and showed that personnel external and intemal dose controls were
being effectively implemented. .
c. Conclusions ;
.
Personnel external and internal dose controls were being effectively implemented.
.
- R1.3 Radioloaical Controis-Radiosctive Materials, Contamination Survevs and Monitorino
R1.3.1 General Outaoe Controls
a. Scone (83750)
The inspector reviewed the I:censee's control of radioactive materials,
i contamination, surveys, and mondoring. Information was gathered through
observation of activities, tours of the RCA, discussions with cognizant personnel,
and review and evaluation of procedures and documents,
b. Observations /Findinas
l Water and gatora'Je were placed in the uncontaminated area outside the access
point of the RB and were made available to workers exiting the RB to replace lost
fluids, especially for workers who were experiencing heat stress symptoms. _
Adequate contamination controls were in place so that the workers could bs.
provided the liquids without leaving the contaminated area and could return to the
RB without doffing and donning protective clothing. High radiation boundaries,
gates, and postings were properly established and maintained. The establishment
and maintenance of contaminated areas exhibited some weak attributes. In some
,
- cases, the barricade rope / tape was not continuous around the contaminated area,
- leaving small openings, and in other cases, structures or permanent carts were
incorporated as part of the boundary. These conditions made the e.,act perimeter of-
the contaminated areas unclear for the radiation workers. There were also several
examples of equipment and hardware lying on the floor across the vertical plane of.
the contaminated area boundary whicn made it unclear wnether the
equipment / hardware was contaminated'or not. Routine and job specific radiological
"
survey records were reviewed and, in general, were found e contain appropriate
information and to be accessible to the radiation workers. However, several weak
-
-
attributes were noted in the survey program which detracted from the availability of
s-
- -
rm+ r m, -
v - , e
_ .
l >
i
l.
I
31
accurate and current radiological condition information to the radiation workers. ,
Severalindividual surveys posted in the AB were incomplete in that they did not.-
accurately identify all radiologically posted areas and bouadaries in the areas
covered by the survey maps. Deficiencies with the surveys posted at the two main
RCA access points were also noted. ' At the main HP access control point, several
location labels on the board were incorrect, and a dated survey, superseded by a
more recent one, had not been removed. At the Outage Equipment Storage Building
control point, two dated surveys, superseded by a more_recent one, had not been
removed. Also, the survey boards at both control points were subject to foot traffic
congestion.
c. Conclusions
- Adequate contamination controls and an adequate radiation survey and monitoring
program were being implemented. However, weak attributes wore noted in the ~
establishment and maintenance of contaminated areas and in the survey program.
R1.3.2 Review of Hot Particle Contamination - Ooen eel 50-289/97-09-05: Personnel Hot
Particle Contamination Due to inadeouate Survevs
a. Scope
The inspector reviewed the licensee's control r.f work which resulted in a hot
particle exposure to a worker and the licenser /s dose assessment. Information was
' gathered through discussions with cognizar.c personnel and through review and
evaluation of procedures and documents.
,
b. Observations /Findinas
.
On October 4,1997, the task of raising (parking) the seal plate (a reactor vessel
head activity) and removing gasket material was performed under RWP No.
141032. Based on prior surveys after decontamination, the work area was not
posted or controlied as a hot particle a.aa. On the initial entry into the work area,
the workers wore a single set of coveralls, double rubber gloves, double rubber
boots, wet suit bottoms, hood, hard hat, and safety glasses. After the seal plate
was parked, the radiation control technician reportedly halted work to perform a
survey of the newly exposed surfaces. The survey results and visual examination
of smears and sticky wipes indicated that the newly exposed work area was a hot
particle area. meeting the criteria for Level 11 controls (presence of discrete particles
with an activity of 50,000 net counts per minute or greater). However, the
licensee's procedures stated that the preferential method for dealing with emergent
^
.
- hot particle areas was to eliminate hot particles and sources of hot particles from
the area so that work could resume without the need for hot particle controls.
in this instance, since decontamination tools were available in the immediate area
and since gasket removal was estimated to last less than one hour, the radiation
control technician decided to proceed without implementing any additional
. protective clothing requirements or other hot particle controls and without notifying
_ _.
. . _ -
.
.
32
his supervision. The radiation contrcl technician and the supervisor of the work
crew, under the technician's direction, decontaminated the newly exposed work
area to eliminate hot particles and to allow gasket removal work to commence in
the decontaminated areas. The radiation workers in the work crew stayed back
from the seal plate area during this hot particle decontamination effort and were not
involved. After completion of the hot particle decontamination effort, the radiation
workers in the work crew proceeded to perform the gasket removal task. At the
end of this work evolution, the radiation workers were required by the technician to
frisk at the exit of the RB. At the frisking location, one of the radiation workers was
discovered to have two separate hot particles (16.1 and 1.2 microcuries) (each
particle wr.s approximately equal parts Zirconium-95 and Niobium 95) on the skin of
his lower face. The licensee's final dose assessment for the 16.1 microcurie
particle was 13.978 rem, total dose to the skin (12.825 rem, beta dose and 1.153
rem, gamma dose) and 50 millirem, total dose to the whole body. Upon discovery
of the hot particle contaminations, the seal plate area was posted as a hot particle
area.
A review of the licensee's hot particle control procedure on pages E81 through
E8-3 of Procedure 6610 ADM-4110.04 indicated severalinconsistencies with
10 CFR 20.1501. First, specific controls were not required during the elimination of
hot particles and sources of hot particles from the area in an emergent situation so
that work could resume. Second, it was not clear if Level 11 controls included Level
I controls (Level l area: presence of discrete particles with an activity of 5,000 net
counte per minute or greater; Level ll area: presence of discrete particles with an
activity of 50,000 net counts per minute or greater) or if Level ll controls stood
alone; for example, the requirement that allitems removed from the area were to be
labeled or marked as originating from a hot particle area appeared in both the Level I
and il controls, but consideration of face shields and a requirement that all
personnel were to utilize a whole body frisker after exiting the hot particle area only
appeared in the Level I controls. Third, most of the listed controls were only
recommendations, not requirements. For example, of the seven controls identified
for LevelI areas, five were required only to be considered while two were required
to be implemented (i.e., frisking as soon as possible after exiting and labeling all
items removed from the area as originating from a hot particle area); of the seven
controls identified for Level 11 areas, only two were required to be implemented
(i.e., a cognizant on-shif t GRCS needed to be aware of all work in progress and
labeling allitems removed from the area as originating from a hot particle area).
Fourth, there was little guidance on varying hot particle radioactivity (and, thus,
potential magnitude of skin dose) versus required frisking intervals. The licensee's
root cause analysis stated that the hot particle control procedure would be
evaluated for lack of specificity and revised accordingly.
TS 6.11, Radiation Protection Program, requires that procedures for personnel
radiation protection shall be prepared consistent with the requirements of 10 CFR
20 and shall be approved, maintained, and adhered to for all operations involving
personnel radiation exposure. 10 CFR 20.1501 requires that each licensee shall
make or cause to be made, surveys that may be necessary for the licensee to
comply with the regulations in 10 CFR 20 and are reasonable under the
. - - . _ _ - ..- - - . -_ . - - . . . .
. .
.
33
circumstances to evaluate the extent of radiation levels, and concentrations or
quantities of radioactive material, and the potential radiological hazards that could
i
be present. The licensee's hot particle control procedure on pages E8-1 through
E8 3 of Procedure 6610 ADM-4110.04 was inconsistent with 10 CFR 20.1501 in
that it did not cause surveys to be made reasonable under the circumstances to
evaluate the extent of quantities of radioactive material and the potential ;
radiological hazards that could be present and resulted in a radiatior worker
receiving a skin exposure of 13.978 rem.
c. Conclusion
GPUN failed to perform adequate surveys during the removal of the reactor vessel
seal plates, as such adequate hot particle controls were not in place and did not
prevent a personnel skin contamination. This appears to be a violation of TS 6.11.
(eel 50 289/97 09-06)
R1.4 Radioloalcal Controls As low As Reasonabiv Achievable
a. Ecoce (83750)
The inspector reviewed the licensee's pre-job ALARA reviews, use of temporary
shiciding, and radiological goals, projections, and results,
b. Observations Findinas
Numerous pre job ALARA review packages had been generated, and the ones for
incore instrumentation replacement, CRDM thermal barrier replacement, OTSG
activities (tube plugging / repairs, tube eddy current testing, cold leg dams, and
Roger robot work), replacement of the 'B' DH pump, and spent fuel pool diving
operations for cable modification and maintenance of fuel transfer carriages were
evaluated and found to be detailed and thorough. The current outage cumulative
total effective dose equivalent was tracking close to the goal projection.
Cumulative committed effective dose equivalent for the outage was low (less than
50 mrem). Personnel contamination goals were established, and personnel
contaminations were being trached and evaluated for cause. The amount of
temporary shielding used as compared to last outage had been increased by almost
a f actor of two.
c. Conclusions
ALARA activities, especially the pre-job reviews, were generally considered a strong
point of the radiological control program,
a
s - w .
- .
.
.
34
R1.3 Other Chanaes to the RP Proaram
a. Scoce (83750)
The inspector reviewed the effect of the elimination of the Corporate Radiological
Health / Safety Director position on the overall performance of both (Oyster Creek
and Three Mile Island-1) radiation protection programs. Information was gathered
through discussions with cognizant personnel and document review.
b. Observations /Findinag
During the radiological control portion of NRC Inspection No. 50-289/97-06, it was
noted that the TMI Radiological Controls / Occupational Safety (RC/OS) Director had
reported to the Corporate Radiological Health / Safety Director up to approximately
June 1997. This had changed because the Corporate Radiological Health / Safety
Director position had been eliminated. The TMl RC/OS Director now reported to the
Oyster Creek RC/OS Director. The effect of this change on the overall performance
of both (Oyster Creek and TMI 1) radiation protection programs was uncertain and
required further NRC review; of particular concern was the disposition of
responsibilities and authorities previously maintained by the corporate director
relative to review and maintenance of the GPUN Radiation Protection Plan and to
the required annual review of Radiation Protection Program content and
implementation for each site; during a telephone discussion after that inspection,
the Oyster Creek RC/OS Director informed the inspector that those responsibilities
and authorities previously maintained by the corporate director would be performed
by the Oyster Creek RC/OS Director; this issue was documented as an item to be
reviewed during a subsequent inspection (IFl 50-289/97-06-02). During the current
inspection, the TMI RC/OS Director stated that a Safety Determination and 50.59
Review was in progress to address this issue. A review of the in progress Safety
Determination and 50.59 Review indicated that needed changes to the Oyster Creek
and TMI 1 UFSAR had been identified.
c. Conclusions
The change in the corporate organization, involving the climination of the Corporate
Radiological Health / Safety Director position, vesting the responsibilities and
authorities previously maintained by the corporato director in the Oyster Creek
RCIOS Director,2nd having the TMl RC/OS Director reporting to the Oyster Creek
RC/OS Director was being evaluated by the licensee. The effect on the
performance of the site radiation protection programs is still uncertain and will
require further NRC review.
._ _ _. . _ . _ _ _ _ _ _ _ _ _ . . _ . _
A
.
35
R4 Staff Knowledge and Performance in RP&C
R4.1 Ooen eel 60-289/97-09-06: Inadeouate Control Over Once Throuoh Steam
Generator Locked Hioh Radiation Area
a. Backoround/Scqpa
The inspectors reviewed the licensee identified failure to maintain positive control of
the 'B' OTSG locked high radiation area. The review included the radiological
controls procedum 6610-ADM-4110.06, " Control of Locked High Radiation Areas,"
plant TS, CAP form T1997-0738, and PRG meeting minutes for prior high radiation
control issues.
'
b. Observations /Findinos
On September 30,1997, a radiation control technician, at a remote video monitor,
noticed that the 'B' OTSG upper manway shield door was unlocked and unattended.
A contract worker f ailed to maintain positive control for the 'B' OTSG upper
manway shield door. With the high radiation door unlocked, the contractor left the
area unattended and exited the RB in violation of the administrative procedure for
the control of locked high radiation areas. The opening was monitored continuously
from a remote video monitor display. Upon recognition of the missing worker a
radiological technician was sent to the 'B' OTSG to lock the manway shield door.
The high radiation barrier was left unattended for approximately 60 to 90 minutes.
The radiation levels in the 'B' OTSG were approximately 3 to 4 Rem / hour. This is a
repetitive issue of a similar problem that occurred in the 1993 and 1995 refuel
i
outages,
'
TS 6.B.1 states, in part, that written procedures shall be established, implemented,
and maintained covering certain activities, including the applicable procedures
recommended in Appendix 'A' of Regulatory Guide 1.33, Revision 2, February
1978, which includes radiation protection procedures for the control of access to
radiation areas. The licensee's Radiation Protection Procedure Number 6610-ADM-
4110.06, " Control of Locked High Radiation Areas," states in part that, " prior to a
OTSG platform worker leaving the area, they must turn over the locked high
radiation controls to an on-coming platform worker or have the OTSG shield door
verified locked by a radiological control technician." The contract worker failed to
follow the high radiation control procedure; the action led to an unlocked and
unattended high radiation area, the 'B' OTSG shield door, with the potential for an
inadvertent radiation exposure in excess of personnel limits. This is an apparent
vio!ation.
.
- - - - _ - - - . - - ,
_ _ _ _ - _ _ _ _ _ _ _ _ _ - _ -
_ .. .. .
.
.
.
36
c. C_onclusions
A contract worker f ailed to follow the high radiation control procedure, the action
led to an unlocked high radiation area, the 'B' OTSG shield door, with the potential
for an inadvertent radiation exposure in excess of personnel limits. This failure was
similar to a prior problem that occurred in the 1993 and 1995 refuel outages. This
issue appeared to be a violation of TS 6.8.1, in that procedures for locking high
radiation areas were not followed. (eel 50 289/97-09-06)
R5 Staff Training and Qualification in RP&C
a. Scope (83750)
The inspector reviewed the licensee's selection, training, and qualification program
for the contracted radiological control technicians hired for the current outage. The
radiological controls (RC) Field Operations guidance for coaching radiation workers
was also reviewed. Information was gathered through discussions with cognizant
personnel and review and evaluation of procedures and documents.
b. Observations /Findinas
Licensee's procedures and documentation for the training and qualification of
contracted radiological controls technicians hired for the current outage were
reviewed and discussed with training personnel. The review of training procedures
and records showed that the procedures were being properly implemented. The
training and qualification process was on-going at the time of this inspection, and
the status of each contracted technician's progress in this process was being
tracked by the licensee. Based on a review of the documented experience of
selected contracted radiological control technicians and on discussions with the
supervisor of RC Field Operations, selections were in accordance with the TS
experience requirement. RC Field Operations had initiated additional radiation
worker coaching at the start of this outage. This coaching was for radiation
workers who were new to nuclear power sites or to TMI-1. The coaching was
performed in accordance with written guidance, conducted in the RCA, and lasted
for approximately 1.5 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The coaching addressed practical factors
involved with RCA access and egress and involved radiological control requirements
applicable to radiation workers while in the RCA.
c. .Conclusiong
The selection, training, and qualification of contracted radiological control
technicians for the outage were in accordance with requirements. The new
radiation worker coaching process implemented by RC Field Operations was a good
initiative.
_ . . _ _ . . . . . .
.
.. _ .. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ __ _
. - - _ _. -. -. . - -
.
.
37
R7 Quality Assurance in RP&C Activities
a. Scoce (83750)
The inspector reviewed the licensee's independent and self assessing processes.
Information was gathered through discussions with cognizant personnel and review
and evaluation of procedures and documents,
b.- Observations /Findinos
GPUN'S NSA group performed independent reviews of the radiation protection
program. NSA audits the entire program every two years in two parts. The
inspector reviewed the completed, but not yet approved audit designated S TMl 97-
06 which covered organization, training and qualifications, dosimetry, TS
surveillances, source accountability, use, maintenance, and calibration of radiation
instrumentation, procedures, document control, and records. This audit had a broad
scope and was also highly detailed and in depth, it resulted in the identification of
several minor deficiencies, but no quality deficiency reports.
Self assessment efforts by the radiation protection organization since the last
inspection were examined by the inspector. Approximately thirty surveillance
inspection reports for various plant locations had been performed and documented.
The inspector's review indicated that thes* aurveillances by radiological control
supervision and radiological engineering staff resulted in the identification of
numerous minor deficiencies. Most of these resulted in corrective action being
implemented on the spot.
c. Conclusions
The scope and depth of the NSA audit of the radiological controls group was of
good quality. The surveillances by the radiological control personnel resulted in the
correction of numerous minor deficiencies.
R8 Miscellaneous RP&C issues
While performing the inspections discusced in this report, the inspector reviewed
the applicable portions of the UFSAR that related to the areas inspected. The
inspector verified that the UFSAR wording was consistent with observed plant
practices, procedures, and/or parameters.
S1 Conduct of Security and Safeguards Activities
The inspectors monitored the security department's control of protected area
openings throughout the 12R refueling outage. The ;ontrol of protected area
boundary openings and worker sensitivity toward security requirements was a
weakness during the 11R refuel outage.
, - - ,
. . - - . .- - . . -_ _- - _ . _ _._ - _ -. . - . _ . - -
.
. :
38
All openings in the protected area boundary were controlled properly by the security
department for the entire 12R refueling outage. An example of improved boundary
controls was noted throughout the replacement of the 'A' and 'B' circulating water
pump impellers Security locks were placed on the purnp discharge valves and
associated electrical breakers to prevent an inadvertent breech in the protected area
boundary. The increased involvement of security personnel at the daily work
planning process, increased wurker sensitivity to security requirements, and ,
improved security references in the work packages resulted in the improved
performance in the security area. Based on the improved security performance for
the refuel outage, the inspectors concluded that the plant corrective actions for prior
-problems were offective.
.
V. Manaaement Meetinas
X1 Exit Meeting Summary l
At the conclusion of the reporting period, the resident inspector staff conducted an exit
meeting with GPUN management on November 10.1997, summarizing Unit 1 inspection
activities and findings for this report period. The licensee acknowledged the findings
presented. No proprietary information was identified as being included in the report.
.
l
. . - .
. _. .- - ._ . -
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .
. . .. .
O
.
I
39
INSPECTION PROCEDURES USED
lP 37550: Engineering
Ir 37551: Onsite Engineering
IP 40500: Eff( viveness of Licensee Controls in Identifying, Resolving, and Pre,enting
Problems
IP 61726: Surveillance Observations
IP 62707: Maintenance Observation
IP 71707: Plant Operations
IP 71750: Plant Support Activities
IP 73753 Inservice Inspection
IP 73755 Inservice Inspection; Data Review and Evaluation
IP 83750 Occupational Radiation Exposure
IP 92901: Followup Plant Operations
IP 92902: Followup - Maintenance
IP 92903: Followup - Engineering
IP 92904: Followup Plant Support
IP 93809 Safety System Engineering Inspection
ITEMS OPENED, CLOSED, AND DISCUSSED
_Qpened
50-289/97-09-01, Decay Heat Removal Requirements During Reactor Vessel Draining
(IFI)
50-289/97 09-02, Failure to Follow Reactor Coolant System Filling Procedure (EEI)
50-289/97-09-03, Power Operated Relief Valve Inoperable for an Operation Cycle (EEI)
50-289/97-09-04, Emergency Diesel Generator Testing During Simulated Accidents (URl)
50-289/97-09-05, Personnel Hot Particle Contamination Due to inadequate Surveys (EEI)
50-289/97-09-06, Inadequate Control Over Once Through Steam Generator Locked High
Radiation Area (EEI)
Closed
50-289/96-07-01, Safety Related Scaffolding (VIO)
50-289/97-07-01, Failure to Write a Clear Specific Narrative Description in LER 97-003
(VIO)
Uodated
NONE
I
-- . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
1
o. -
! .
-o
40
LIST OF ACRONYMS USED
AB Auxiliary Building
AEC Atomic Energy Commission
ALARA Ac low As Reasonably Achievable
ASME American Society of Mechanical Engineers
B&W Babcock and Wilcox
BWST Borated Water Storage Tank
CAP Corrective Action Process
CDF Core Damage Frequency
CF Corc Flood System
CFR Code of Federal Regulations
CFT' Core Flood Tank
CR Control Room
CRDM Control Rod Drive Mechanism
CRO Control Room Operator
leBD Design Basis Documents
DCP Design Change Package
DH Decay Heat Removal System
ECCS Emergency Core Cooling System
EDG Emergency Diesel Geneiator
eel Escalated Enforcement issue
EPIP Emergency Plan and Implementing Procedure
ESF Engineered Safety Feature
FAC Flow Accelerated Corrosion
FTC Fuel-Transfer Canal
GPUN GPU Nuclear (Licensee)
IB Intermediate Building
IFl Inspection Followup Item
IPE Individual Plant Evaluation
IR . inspection Report
ISI inservice Inspection
IST Inservice Testing Program
HELB- High Energy Line Break
HPl High Pressure injection (MU)
JO Job Order
LCO Limiting Condition of Operr. son
LER Licensee Event Report
LOCA Loss of Coolant Accident
LOOP Loss of Offsite Power
-LOR Licensed Operator Requalification
s LPI Low Pressure injection (DH)
LTOP Low Temperature Overpressure Protection
MCC Motor Control Center
MNCR - Material Nonconformance Report
MOV Motor Operated Valve
MU Makeup System
_
.
_- ___ - _-________a
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
_-
.
.
o
41
NCV Non-Cited Violation
NDE Non Destructive Examination
NDTT Nil Ductility Transition Temperature
NOV Notice of Violation
NRC Nuclear Regulatory Commission
NSA Nuclear Safety Assessment
OTSG Once Through Steam Generator
PCR Procedure Change Request
PMT Post Maintenance /ModificationTest
PPB Part per Billion
PPM Part per Million
PRA Probabilistic Risk Assessment
PORV Po wer Operated Relief Valve (Pressurizer)
PRG Plant Review Group
ODR Ouality Deficiency Report
QV Quality Verification
RB Reactor Building (Primary Containment)
RC Radiological Controls
RCA Radiolog' cal Control Ama
RCBT Reactor Coolant 3160 Tri n.
RP Radiation Protection
RWP Radiation Work Permits
SALP Systematic Assessment of Licsansee Performance
'e R Safety Evaluation Report (NRC)
SF Shif t Foreman
SRO Senior Reactor Operator
SS Shift Supervisor
Tl Temporary instruction
TS Technical Specification
UFSAR Updated Final Safety Analysis Report
URI Unresolved item
VIO Violation
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