ML20214R404
ML20214R404 | |
Person / Time | |
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Site: | Three Mile Island |
Issue date: | 10/27/1986 |
From: | Chaudhary S, Dyer J, Howell A, Klingler G, Mckee P, Pierson R, Sharkey J, James Smith, Trimble D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I), NRC OFFICE OF INSPECTION & ENFORCEMENT (IE) |
To: | |
Shared Package | |
ML20214R389 | List: |
References | |
50-289-86-14, NUDOCS 8612050458 | |
Download: ML20214R404 (24) | |
See also: IR 05000289/1986014
Text
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OFFICE OF INSPECTION AND ENFORCEMENT
DIVISION OF INSPECTION PROGRAMS
Report No.: 50-289/86-14
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Licensee: General Public Utilities Nuclear Corporation
P. O. Box 480
Middletown, Pennsylvania 17057
Docket No.: 50-289 License No.: DPR-50
Facility Name: Three Mile Island, Unit 1
Inspection Conducted: August 25, 1986 - September 5, 1986
Inspectors: IN #-2 3 -E
d. E. Dyer,' Inspection Specialist, IE Date
Team Leader
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J/D. Smith,InspectionSpecialist,IE
/o a/-B(,
Date
-(- \0-tab
R. C. Pierson, Inspection Specialist. IE Date
6kkav & /o-es-rc
S. K. Ehaudhary, Senior Reactor Engineer, Date
/C-4 -86
A. T. Ho ll, Inspection Specialist, IE Date
0.I alu
G.R.Kli'ngler,ReactorfperationsEngineer,IE
to -LMt.
Date
h t' h e Y $ < /O ~22.-24,
D. C. Trimble, Resident Inspector, Region I Date
/e-/6 24
. M. Sharkey, Ihstection Specialist, IE Date
Accompanying Personnel: *L. J. Callan, IE; *J. O. Thoma, NRR; *T. M. Ross, NRR;
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- A. R. Blough, RI; *R. Conte SRI, TMI-1; *D. Johnson,
RI, THI-1; *F. Young, RI, TMI-1; and *J. Rogers, RI,
. - TMI-1.
Approved by: / b
- Phillip F.fcKee, Chief
ex -
/0 -2 9 su
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Date
l Operating Keactor Programs Branch, IE
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( * Attended Exit Meeting
8612050458 861106
l PDR ADOCK 05000289
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Scope:
A special, announced inspection was performed of the licensee's management
controls over the following functional areas:
- Operations
- Design Changes and Modifications
- Maintenance
- Safety Review Activities
- Surveillance Testing
Results:
The team determined that the management controls for licensed activities in
the five functional areas inspected at TMI-1 were generally adequate. However,
six potential enforcement findings, referred to as unresolved items in the
report, will be followed up by NRC Region I.
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1 INSPECTION OBJECTIVE
The objective of this team inspection was to evaluate the effectiveness of
management controls established to conduct licensed activities. This inspection
fulfills the requirement of Comission Memorandum and Order CLI-85-09, which
lifted the 1979 Shutdown Order on TMI-1 and directed, in part, that a Performance
Appraisal Team (PAT) inspection be conducted after 12 months of operation.
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The inspection effort covered licensed activities in the following five
functional areas:
- Operations
- Design Changes and Modifications
- Maintenance
- Safety Review Activities
- Surveillance Testing
The inspectors interviewed responsible personnel, observed activities, and
reviewed selected records and documents in each functional area to detemine
whether:
(1) The licensee had written policies, procedures, or instructions to provide-
management controls in the subject area.
(2) The policies, procedures, and instructions were adequate to ensure com-
pliance with regulatory and internal requirements.
(3) The licensee personnel who had responsibilities in the subject areas
understood their responsibilities and were adequately qualified, trained,
and retrained to perform their responsibilities.
(4) The requirements of the subject area had been implemented and appropriately
documented in accordance with management policy.
The specific findings in each area are presented as observations that the j
inspectors believe to be of sufficient importance to be considered in a
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subsequent evaluation of the licensee's performance. Some observations may :
be potential enforcement findings. These observations, referred to as !
unresolved items, were presented to the NRC Region I for followup.
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! 2 SUMMARY OF SIGNIFfCANT FINDINGS
The more significant findings pertaining to the management controls of licensed
activities at TMI-1 are summarized below. Although some programatic strengths
were identified in the areas of Operations, Maintenance, and Surveillance
Testing, the following summary focuses on the significant weaknesses identified
during the inspection. Section 3 provides detailed findings, strengths and
weaknesses in each of the five functional areas reviewed during the inspection.
l The observation numbers in parenthesis after the inditidual sumary items are
l provided for reference to the corresponding discussion in Section 3.
2.1 Operator Reviews
The following deficiencies were identified through reviews conducted in the
control room:
(1) Three instances were identified where safety system valve lineups did not
have the required signatures indicating completed reviews. (3.1.4)
(2) One instance was identified where the incorrect revision of a valve
lineup procedure was used despite the fact that the supervisory reviews
were conducted. (3.1.4)
(3) Six instances were identified where errors in manual calculations of
quadrant power tilt and core power imbalance went unnoticed through
senior reactor operator and shift technical advisor reviews. These
errors were identified during operations management reviews, three days
after they were performed. (3.1.2)
(4) Three instances were identified where manual heat balance calculations
were not reviewed until 3 days after they were perfomed. There were no
errors in these calculations. (3.1.2) ,
2.2 Drawing Contro1 __
The team identified the following problems with the implementation of the
drawing control prcgram:
(1) The licensee used hard copy drawings inside the protected area to control
plant operations. All drawings reviewed were the current revision.
However, Safety-Related Drawing, 302-082, " Emergency Feedwater System "
Revision 8, did not reflect the as-built configuration of the plant.
Drawing 302-082
did not reflect that motor-operated block valves EF-V 53,
54, and 55 were electrically disconnected or that check valve EF-V3 had
its internals renoved. (3.2.4)
(2) The licensee used aperture card drawings outside the protected area and at
GPUNC.
The Computer Assisted Records and Information Retrieval System
(CARIRS) was used to verify that the aperture cards were current. Of the
12 reviewed aperture card drawings, 6 were the incorrect revision. Further,
one of the six out of-date aperture cards was identified as being the
correct revision on the CARIRS. This combination of inaccuracies presented
the potential for use of out-of-date drawings in design and maintenance
activities. The root cause for this problem appeared to be delays in
updating the drawings and the CARIRS data base. (3.2.4)
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2.3. Post-Modification Testing of Remote Shu down Panels (RSPs)
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Major modifications to the RSPs were planned for the next outage and only a
functional check of the new RSP components and circuitry was planned at the
time of the inspection. The modifications included adding a third panel
to the existing two panels and adding instrumentation for control'of the ,
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emergency feedwater system, decay heat removal system, pressurized dump
isolation to the main condenser, normal makeup water system, and pressurizer ;
power-operated relief valve'(PORV) block valve. The tean was concerned that f
the functional tests would not adequately demonstrate the operation of the '
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system and that an integrated test should be considered. (5.2.5) l
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2.4 Deficient Procedures '
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The team identified instances where procedures were improperly, classified as
not important to safety (NITS); consequently these procedJreS'did not receive
the required technical and safety reviews. Technical weaknesies also were ;
identified with procedures.
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(1) Several procedures issued by the Technical Functions Division were
improperly classified as NITS and thereby did not receiv'e required
technical or safety reviews. The following are examples of irportant- -
.to-safety (ITS) activities that were governed by these procedures:
(3.4.1)
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' minor modification development
- design verification
- field change development -
- drawing revisions
In addition to being improperly classified, the procedure controlling the
plant engineering modification process was found to be technically weak.
(3.2.3)
(2) Of 20 special temporary procedures (STPs) reviewed by the team, 3 were
improperly classified. These STPs, which controlled special evolutions
in the plant during power operations, received a technical review, but
were not evaluated to determine if they created an unreviewed safety
question. All three of the improperly chssified procedures appeared to
have technical deficiencies. Conservative action taken by the operators
< during implementation prevented potential problems. (3.4.1).
(3) Although properly classified, two temporary change notices l(TCNs) to
station procedures were technically deficient:
l (a) TCN 86-95 to Procedure 1102-4, " Power Operations " provided guidance
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. for controlling small power excursions above the steady-state licensed
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power limit that were less conservative than NRC guidance. No
! examples were found where the licensee had exceeded the NRC guidance.
(3.1.3)
(b) TCN 86-112 to Procedure M-148, " Hydrogen Recombiner Lubrication /
Inspection," directed the mixing of lubricants with different chemical
i bases in the blower motors. This was contrary to environmental
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qualification (EQ) requirements. Maintenance personnel flushed the
residual grease out of the blower motor although this was not required
by procedure. (3.3.3)
2.5 Responsible Technical Reviewer (RTR) Knowledge
The RTRs were the individuals responsible for perfoming technical and safety
reviews of proposed changes to plant procedures, tests, and systems before
implementation. RTRs were used at TMI-1 instead of the onsite review comittee.
Interviews with RTRs revealed the following knowledge deficiencies:
(1) The depth and scope of the reviews' required by the Technical Specifications
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(TS) were not clear to all RTRs. (3.4.3)
(2) Several RTRs were unable to use the CARIRS. The CARIRS was identified as
a primary means for determining which documents were considered as licensing
basis' documents during reviews. (3.4.3)
(3) Some RTRs were not knowledgeable about the equipment included in the
environmental qualification (EQ) program or the importance of maintenance
actions for this equipment. (3.3.3) .
2.6 Safety Review Process
During the inspection, the licensee implemented a revision to its safety review '
L procedure which appeared to conflict with the requirements of the TMI-1 TS. l
The TS required reviews of all proposed changes to procedures, tests, and
systems classified as ITS, including a written determination of whether the
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proposed change constituted an unreviewed safety question. The revised
procedure added a screening step to the process that eliminated the written
determination for some procedures classified ITS. The 10 CFR 50.59 safety
evaluation performed for this revised procedure did not discuss whether the
- proposed change would require a change to the TS. (3.4.2)
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3 DETAILED FINDINGS
3.I' Operations
The team reviewed the licensee's program for ensuring safe plant operation.
The review concentrated on the conduct of operations in the control room and
included a revie,t of the technical adequacy and implementation of selected
operating procedures.
3.1.1 Control Room Operations ,
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The team _-observed the control of ^various plant evolutions conducted during the
inspection,(reviewed logs and completed procedure documentation, and inter- ,
viewed shift operators. The following observations were made:
(1) Access to the control room was well regulated', particularly'near the
operating panels. Background noise was kept to a minimum and the
operators were very attentive to plant conditions. Operators who were
interviewed were knowledgeable about the overall status of systems and
the various evolutions occurring in the plant.
(2) Comunications appeared to be effective between operators and between
the operators and outside personnel. The team was particularly impressed
with the coordination and control exhibited during corrective maintenance
activities on the integrated control system (ICS). This maintenance
activity required taking manual control'of the ICS at three stations and
coordinating control of the plant until the ICS could be returned to
automatic operation. The operators performed this task in a very
controlled manner and communicated information on the various plant
parameters and coordinated power controlling actions at the stations.
(3) The licensee had achieved a relatively low number of alarmed control room
annunciators during power operation. During steady-state operating
conditions, the team observed only three alarmed annunciators.
3.1.2 Manual Calculation Review
The team reviewed the manual calculations of power distribution parameters
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required by TS and performed by the operators during the period from June 27
through July 1,1986 when the plant computer was out of service. The
following weaknesses were identified:
(1) Operators had made errors in F cf ;he 36 calculations reviewed that were
performed in accordance with ihr w al Procedure 1203-7, " Hand Calculations
for Quadrant Power Tilt ud An iwer Imbalance," Revision 18. These
errors did not result in u.y h 4.oiits being exceeded; however, they had
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gone undetected through the senior reactor operator and shift technical
advisor reviews. Operations management subsequently identified and
corrected the problems during their reviews 3 days after the calculations
were performed.
(2) Calculations performed in accordance with Procedure 1103-16. " Heat Balance
Calculations," Revision 16, were not reviewed by a reactor operator or
senior reactor operator until operations management pointed out the
deficiency during their review, 3 days after the calculation was
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performed. The team reviewed the calculation and found no errors with
the original calculation.
The team was. concerned that these deficiencies were examples of poor reviews
by the senior reactor operators and shift technical advisers. Interviews with
reviewing personnel revealed that they were knowledgeable about the manual
calculations and their responsibilities for review. The team emphasized to
licensee management that, in view of how infrequently these calculations were
performed manually, a more timely and careful review of the results would be
warranted.
3.1.3 Operating Procedures
The team reviewed selected operating procedures and found them to be technically
adequate in all but one case. The exception was Procedure 1102-4, " Power
Operations," Revision 40, which inadequately described how to maintain core
thermal power at the licensed steady-state limit. Temporary Change Notice
(TCN) 86-95 to Procedure 1102-4 revised the guidance for maintaining steady-
state power limits based on an August 22, 1980 NRC memorandum. The NRC
memorandum recognized that load fluctuations causing power oscillations
above the 100% steady-state limit were permissible up to 102% for 15 minutes,
101% for 30 minutes,100.5% for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, etc., as long as 102% power was never
exceeded and the average power level for an 8-hour shift did not exceed the
100% steady-state licensed limit. The operating guidance provided by TCN
86-95 did not require action upon reaching the stay times for power levels
between 100% and 102% of the steady-state limit and could allow power opera-
tions beyond the permissible excursions identified in the NRC memorandum. The
team reviewed the station power history and confirmed that the licensee had not
exceeded their steady-state licensed limit as defined in the NRC guidance. ,
3.1.4 Valve Lineups
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The team reviewed completed valve lineup sheets for nuclear safety-related and
important-to-safety systems and identified the following weaknesses:
(1) Independent verification of valve lineups were not documented for the -
following systen lineup procedures:
- Procedure 1104-5, " Reactor Building Spray System," performed
April 1986.
- Procedure 1104-4, " Decay Heat Removal System," perfomed on
April 16, 1986.
" Procedure 1104-11. " Nuclear Service Closed Cooling Water Systems,"
performed April 1986.
Further review revealed that, at the time these lineups were performed,
the licensee was not required to perforn independent verification of
these systems. The team detemined that the licensee had previously
committed to the NRC to expand the scope of its independent verification
program by January 1987. The details of this expanded program were still
under development at the time of the inspection and not available for the
team to review. NRC Region I was following the licensee's comitment as
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l Unresolved Item 50-289/85-27-08 and will review the expanded program at
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(2) All review signoffs were not completed for the following safety system
lineups:
- Procedure 1104-4, " Decay Heat Removal System," completed on April 16,
1986, had no review signatures. ,
' Procedure 1104-1, " Core Flooding System" (enclosure 1), completed on
April 17, 1986, did not have the second management review signature
on the valve checklist.
(3) The latest procedure revision was not used for Procedure 1104-4, " Decay
Heat Removal System," which was completed on April 20, 1986. :
The apparent failure by the licensee to follow procedures for performing the
required reviews and implementing the correct revision of valve lineup
procedures will remain unresolved pending followup by the NRC Region I :
(289/86-14-01). !
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3.2 Design Changes and Modifications *
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The team reviewed the licensee's program for the development, installation, t
and closeout of design change packages. This included a review of the program ;
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for accomplishing major plant modifications and the expedited processes for '
accomplishing modifications of lesser magnitude under the Mini-Mod and Plant
Engineering Modification Programs. Additionally, the team reviewed the i
licensee's overall program for drawing control. Unlike the Performance ,
Appraisal Team (PAT)/ Safety System Functional Inspection (SSFI) conducted
during March 3-27, 1986 (Inspection Report No. 50-289/86-03), this inspection
did not include detailed engineering analyses of selected design changes;
rather, the emphasis of this inspection was on the licensee's design change
program and . processes.
3.2.1 Plant Modifications
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Plant modifications were those design changes' engineered by the Technical
Functions Division at GPUNC. Since the PAT /SSFI inspection conducted during
March 1986, the licensee had made a considerable effort to improve its plant
modification program by revising its governing procedures and by conducting
training of responsible personnel on the new procedures and the overall
regulatory requirements for design change control. The team determined that
j the revised procedures adequately complied with the licensee's regulatory
commitments. Interviews revealed that responsible engineering personnel were
knowledgeable about the revised procedures and regulatory guidance. However,
the revised procedures had not been implemented on any plant modification
packages that were available for the team to review.
3.2.2 Plant " Mini-Mods"
Plant mini-mods were those modifications engineered by the onsite Technical
Functions Group. The Mini-Mod program expedited the design change process for
those plant modifications that did not require detailed engineering analyses
and were within the capabilities of the Technical Functions personnel on site.
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The team reviewed the selection criteria and overall control process outlined
in Procedure EMP-002, " Mini-Mods," Revision 0, and detemined that it adequately
complied with the licensee's regulatory comitments. The team reviewed the
following mini-mods:
- A25A-53150 123150, "Seis'mic Mount on Control Room Console for
Neutron Flux Recorder"
- A25A-53151 123200, "Retube of Make-up Air for RM-42 Sample Pump"
- A25A-53166 123166, " Miscellaneous Electrical Work"
The modification selection, design analyses, and safety reviews appeared
adequately implemented for these modifications.
3.2.3 Plant Engineering Modifications
Plant engineering modifications were those design changes engineered by station
plant engineers. These included minor equipment modifications and changes
classified as " replacement-in-kind." The team reviewed Procedure EMP-019,
" Plant Modifications Engineered by Plant Engineering," Revision 0, and its
implementation and identified the following weaknesses:
(1) The criteria for defining component " replacement-in-kind" appeared to
be too broad. Procedure EMP-019 allowed ". . . replacement of wornout or
failed equipment with a similar component that does not change the overall
function or performance of that equipment." This could allow substitution
of functionally equivalent components without adequate design control.
Specifically, Procedure EMP-019 did not provide a systematic process by
which nameplate data for replacement-in-kind components were evaluated
for conformance to all the required design specifications. Interviews
with plant engineering personnel revealed that this evaluation of
performance criteria was left to the discretion of the reviewing engineer
and relied significantly upon that individual's experience to perform an
adequate evaluation. The team was concerned that the cumulative effects
on a safety system by replacing functionally equivalent components with
slightly different performance characteristics could degrade the overall
ability of the system to function.
(2) The testing conducted after a plant engineering modification was not
required to be reviewed by the plant engineering personnel who developed
the modification. Station maintenance personnel accomplished the modifi-
cation and conducted the testing. The completed tests and modification
packages were not required to be reviewed by plant engineering personnel
before closecut to verify that the modified equipment was operating as
intended.
(3) A review of selected plant engineering modifications revealed that the
supporting rationale for some of the modifications appeared weak. For
example, Plant Engineering Modification 85-279-M allowed the replacement-
in-kind of the original aluminum seat with a machined brass insert in
all the Fisher Series 3500 valve positioners throughout the plant. The
engineering evaluation stated that this work did not create a seismic
concern and did not constitute an unreviewed safety question. However,
the'se assertions were not substantiated in the evaluation and the various
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locations and uses of the Fisher Series 3560 positioners were not listed
or evaluated for the modification. This appears to be a case of inadequate
design analyses and will remain unresolved pending followup by the NRC
Region I (289/86-14-02).
3.2.4 Drawing Control
The licensee controlled station drawings by two methods as described in Procedure
1001C, " Drawing
Utilization," Distribution
Revision 2. Control," Revision 5, and Procedure 1001H, " Drawing
In the first method, controlled hard copies of
selected drawings were maintained at various locations inside the protected
area.
These hard copies were maintained current by the Drawing Distribution
Control Center (DDCC) and did not require verification before use. In the
second method, drawings were maintained on aperture cards outside the protected
area and at GPUNC and did require verification before use for important-to-safety
activities. The Computer Assisted Records and Infonnation Retrieval System
(CARIRS) was used for this status verification, and outstanding drawing changes
could be obtained from DDCC on site or at GPUNC to update the aperture card
drawings.
.The team reviewed the status of 12 drawings at four locations inside the protected
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area, on the aperture cards at the onsite DDCC, and as identified on the CARIRS
data base.
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Hard copy drawings reviewed in the Control Room, Technical Support
Center Instrumentation and Control (I&C) Maintenance Shop, and Electrical
Maintenance Shop were all found to be correct. Of the 12 aperture card "
drawings reviewed at the DDCC, 6 were not the current revision and 1 of these
drawings was listed incorrectly in the CARIRS data base. Consequently, a user
of Safety-Related Drawing SS-209-655, "RC Pump Monitor Rack Outline," would
have been misled by the CARIRS into believing that Revision 2 of the aperture
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card was current, when actually Revision 3 was the current revision.
The team also identified discrepancies between the current revision of a
controllsd drawing and the'as-built configuration of the station. Safety-
~ Related Drawing 302-082, " Emergency Feedwater," Revision 8, did not reflect
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that motor-operated block valves EF-V53, 54, and 55 were electrically disconnected
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or that check valve EF-V3 had its internals removed. Interviews with station
operators revealed that they were aware of these changes; however, the drawings
l had not been updated to reflect actual plant configuration.
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As previously identified in PAT /SSFI Inspection Report No. 50-289/86-03, U
CARIRS
status. generally appeared to be an ineffective system for verifying drawing -
When a DDCC operator used CARIRS at the request of the inspection
team to verify the status of recently revised drawings, problems were encountered ;
with each of the first three drawings checked. The assistance of the Manager, j
Technical
these problems. Functions-Site, and additional DDCC operators was required to resolve
- It appeared to the team that one of the root causes for the 1
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problems identified regarding the use of CARIRS for verifying drawing status
was the significant time lag involved before CARIRS and aperture cards were {;
updated to reflect design changes. Specifically, it required approximately
2-3 months to obtain updated aperture cards an
status to be updated after a change notice was.d uj to 2 weeks for the CARIRS
issued to revise a drawing.
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During this interim period before the CARIRS was updated, station or GPUNC l
personnel, prcperly following procedures, could incorrectly determine that a
drawing was current and acceptable for use when, in fact, it was out of date.
The licensee stated that it was aware of the drawing update backlog and had '
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already initiated action to reduce the backlog by increasing its drafting
resources.
The team was concerned that inaccuracies in controlled drawings, delays in
updating aperture card drawings, and problems identified with the CARIRS could
result in incorrect drawings being used for safety-related activities in the
plant. This item will remain unresolved pending following by the NRC Region I
, (50-289/86-14-03).
3.2.5 Remote Shutdown Panel Modifications -
The team reviewed the licensees plans for modifying the remote shutdown panels
(RSPs) during the next outage. The existing configuration consisted of two
separate, independent safety-grade panels, RSP-A and RSP-B. The instrumentation
and controls on these panels were limited and required operations personnel to
be stationed at numerous plant locations for remote plant shutdown. The
planned modifications consisted of adding a third panel (designated Auxiliary
RSP-B) and additional instrumentation and controls to the existing panels
- (RSP-A&B), including controls for emergency feedwater. control to the once-
through steam generator (OTSG), decay heat removal system, pressurized dump
isolation to the main condenser, normal makeup water system, and pressurizer
power-operated relief valve (PORV) block valve. Interviews with licensee ..
management revealed that current plans were to perform only functional tests
of individual components and circuitry to demonstrate the capability of modified
remote shutdown panels. The team was concerned that these functional tests
would not provide adequate assurance of the ability of the operators to control
the plant from these panels.
At the exit meeting, licensee management representatives stated that the
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decision to conduct only functional tests of components and circuitry was based
on an engineering assessment of what would be necessary to verify proper design,
but that further testing was being considered. The licensee expressed concerns
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that conducting an integrated test would unnecessarily place the plant at risk.
However, the licensee acknowledged that a suitable integrated test could be
performed before criticality after the outage, thereby minimizing the perceived
risk to the plant. This item will remain unresolved pending followup by the
NRC Region I (289/86-14-04).
3.3 Maintenance
The team reviewed the licensee's programs for corrective maintenance, preventive
maintenance, and control of vendor manuals. Additionally, tours of the station
were made by the team to assess plant cleanliness and material condition.
3.3.1 Corrective Maintenance
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-Station corrective maintenance was accomplished using a job ticket program
that provided input to a machinery history program as described in Procedure
1407-1, " General Corrective Maintenance Procedure," Revision 27. The team
found this procedure to be adequate and the maintenance department personnel
who were interviewed were knowledgeable in all aspects of the program. The
corrective maintenance program generally appeared to be well managed as evidenced :
by the following observations:
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~, .(1) Seven corrective maintenance procedures were reviewed for technical
adequacy.- All procedures appeared sound and, where appropriate, vendor
technical manual maintenance recommendations were incorporated into the
procedures.-
(2) Twenty-six ITS corrective maintenance job tickets were reviewed to
! determine if work had been perfonned in accordance with the administrative .
guidance in Procedure 1407-1. The team noted that repair procedures were '
used when appropriate, resolution descriptions were sufficiently documented,
drawings and manuels were updated when necessary,~and post-maintenance
testing was adequately conducted.
m (3) Corrective maintenance job tickets were prioritized and appeared to be
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aggressively managed to reduce the backlog of outstanding work requests.
Since plant startup (approximately 1 year ago), the number of outstanding
corrective maintenance work requests has been reduced from 600 to 300.
3.3.2 Preventive Maintenance
The preventive maintenance program used a computerized schedule to accomplish
periodic maintenance requirements as described in Procedure 1027, " Preventive
Maintenance," Revision 16. Additionally, the licensee quarterly reviewed the .
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. output from the machinery history trending program to determine improvements
for the program as described in Procedure 1407-3, " Assessment of the Adequacy
of the Preventive Maintenance Program," Revision 2. The team considered this
overall program a strength and found the maintenance department personnel
- responsible for the preventive maintenance program to be very knowledgeable in
>
all aspects of the program. The implementation of the preventive maintenance
program appeared adequate as evidenced by the following observations:
!
,
(1) The backlog of outstanding preventive maintenance items was small and
required outage conditions to be performed. Those items that were
.
overdue had been identified by the licensee, evaluated as acceptable,
i
and scheduled for accomplishment at the next outage.
,
(2) Recently completed preventive maintenance actions on the decay heat
removal and instrument air systems were reviewed. The team noted that
correct procedures were used and work was properly documented for the
l pumps, compressors, air dryers, and electrical breakers being maintained.
(3) The team verified that the preventive maintenance requirements were
properly updated to reflect new equipment installed as the result of
plant modifications. No deficiencies were identified with the changes
required for the three modifications reviewed.
3.3.3 Control of Environmentally Qualified (EQ) Equipment
4 The team developed a concern about the licensee's program for maintenance of EQ
l equipment. This concern was based on the maintenance activities reviewed for
! the hydrogen recombiner blower motors. On July 17, 1986, Temporary Change
1 Notice (TCN)86-112 was issued to authorize the use of UNIREX 2 grease
instead of the AND0K B grease specified by Procedure M-148, " Hydrogen Recombiner
'
Lubrication / Inspection," Revision 3. This TCH was approved and the UNIREX 2
grease was added to the blower motors for both hydrogen recombiners. Investi-
I
gation into this issue by the team revealed the following:
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(1) The licensee did not have the vendor manual for the hydrogen recombiner i
blower motor and consequently could not detemine whether the vendor
manual prohibited the use of UNIREX 2 grease. A subsequent engineering
'
evaluation perfomed by the licensee revealed that UNIREX 2 was a suitable
substitu~te.
(2) Although AND0K B and UNIREX 2 are environmentally qualified greases, each
- has a different chemical base. Before the inspection the licensee
contacted the grease manufacturer regarding the generic acceptability
~
i of substituting UNIREX 2 for AND0K B and was told that the mixture could
not be approved. Although the maintenance documentation for this activity
indicated that the greases were mixed, interviews with maintenance
department personnel responsible for the lubrication of the blower motor
revealed that the motors were flushed of the old AND0K B grease when the
'
UNIREX 2 grease was added. This appeared contrary to Procedure M-148 and
TCN 86-112, which only specified adding two ounces of grease to the blower
motors.
(3) Interviews with maintenance department personnel and responsible technical
'
reviewers (RTRs) who were responsible for the review and approval of
lubrication procedures revealed a lack of knowledge about the EQ program.
- Some maintenance personnel stated that they did not know that changing -
grease could affect the EQ status of the equipment. The RTR who perfomed
the TCN review did not realize the hydrogen recombiner was EQ equipment.
In general, both groups demonstrated poor knowledge of EQ maintenance
requirements and admitted that they had received very little training on
the subject.
Based on the above evidence, it appears that the environmental qualification
of the hydrogen recombiners was maintained; however, the team was concerned
that the deficiencies with technical documentation, adequacy of reviews, and
overall knowledge of the EQ program identified in this one instance could
cause problems with other EQ equipment during maintenance activities.
3.3.4 Vendor Manual Control
i
The licensee's program for control of vendor manuals was scheduled for com-
pletion in 1988. In the interim those uncontrolled vendor manuals used for
- maintenance of ITS equipment were required to be evaluated by engineering to
determine their adequacy as described in Procedure 1065, " Vendor Document
Control," Revision 1. The team found this program generally to be adequate;
[ however, the following weaknesses were identified with the implementation of
,
the vendor manual control program:
(1) Controlled and uncontrolled copies of the same vendor manual were kept '
I together by the maintenance department. The potential for an uncontrolled
and incomplete vendor manual to be issued was increased by this practice.
I however, the team did not find any instances where this problem had
>
occurred.
(2) Two examples were noted where safety-related equipment was calibrated
using uncontrolled vendor manuals without prior engineering evaluations.
Two Bailey Meter multiplier modules were calibrated using an uncontrolled
manual " Bailey Meter (Multiplier)," E92-12, under Surveillance Procedure
1302-5.26 "0TSG Level Channel Calibration," Revision 4, accomplished
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. in June 1985. Additionally, on April 8,1986 a Bailey signal monitor
4 was adjusted using an uncontrolled manual " Bailey Signal Monitor," E92-4,
1 under Surveillance Procedure 1302-5.18 "Hi and Low Pressure Injection
Flow Channel," Revision 10. In both cases the uncontrolled vendor manuals
were later evaluated as the correct guidance so the instruments were
properly calibrated.
1
Although the vendor manuals were subsequently determined to have provided the
,
correct guidance, these examples represent an apparent failure to follow
i
Procedure 1065. This item will remain unresolved pending followup by the NRC
'
RegionI(289/86-14-01).
,
3.3.5 Plant Material Condition and Cleanliness
The team assessed the plant's raterial condition and cleanliness by reviewing
the adequacy of the dispositioning of "use-as-is" material nonconformance
'
reports (MNCR), conducting plant tours, and reviewing the licensee's house-
keeping inspection program. The team found the plant material condition and
cleanliness generally were satisfactory as evidenced by the following observations:
(1) Administrative Procedure 1000-ADM-7215.01, "GPUN Material Nonconformance
r Reports and Receipt Deficiency Notices," Revision 1, defines in part -
"use-as-is" as a material disposition that means the material, part, or
component that is the subject of the MNCR is acceptable for unrestricted
use in its present condition. For 1986, six maintenance department
MNCRs fell into the "use-as-is" category. Four of the six had not yet
been dispositioned, but had been forwarded to Technical Functions for
engineering evaluations in accordance with the procedure. The remaining
i two MNCRs had been closed out. The engineering reviews that were
documented in Section 4 of the MNCRs appeared adequate and were well
documented.
'
(2) Plant tours by the team revealed no plant cleanliness problems. Addi-
tionally, the licensee has a program described in Procedure 1008, " Good
"
Housekeeping," Revision 14, where inspections are conducted and their
deficiencies dispositioned monthly. This program appears to have been
aggressively implemented.
! 3.4 Safety Review Activities
The team revibwed the safety review process as applied to proposed plant
modifications, tests and procedure changes in accordance with the requirements
.
of TS 6.5 and 10 CFR 50.59. As described in TS 6.5, the licensee's review
I process is different from that described in the Standard Technical Specifica-
l tions in that one person reviews are pemitted instead of the comittee reviews.
l The responsible technical reviewer (RTR) performs the reviews normally assigned
, to the onsite review comittee while the Independent Safety Reviewer (ISR)
. performs the offsite committee review functions. The licensee's program also
'
is unusual in that TS 6.5 expands the scope for required reviews to include
i all activities and modifications that are classified as ITS.
l
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During the inspection, the licensee revised its procedure for conducting safety
reviews. The team reviewed the implementation of the old process described in
,
Corporate Procedure 1000-ADM-1291.01, " Nuclear Safety Reviews and Approvals at
- TMI-1 and Oyster Creek," Revision 0-01, and the adequacy of the new process
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as described in Corporate Procedure 1000-ADM-1291.01, Revision 2. Additionally,
the QA oversight of the program and the qualifications, knowledge level, and
training of RTRs were reviewed. ,
3.4.1' Safety Review Process Implementation
The team reviewed the implementation of the safety review process for tests
and procedures as described in Corporate Procedure 1000-ADM-1291.01, " Nuclear
Safety Reviews and Approvals at TMI-1 and Oyster Creek," Revision 0-01. This
procedure described a process where written safety evaluations were conducted
for all proposed changes classified as ITS. These evaluations were then
reviewed by the RTR and the ISR before the procedure was issued. TS 6.5.2.5
only required ISR review of written safety evaluations for changes to procedures
as described in the FSAR. ISR reviews were not required by TS to be performed
before a change was implemented. The licensee's procedural requirement for a
second ISR review before issuance of all ITS procedures was beyond the TS
requirements and imposed by licensee initiative. During this inspection, the
following problems were identified with the classification and technical
adequacy of the procedures:
(1) The following station special temporary procedures (STPs) provided
guidance for ITS activities and were apparently incorrectly classified
as not important to safety (NITS):
- STP 1-86-001, " Flush of MU-V-140" - This procedure flushed a check '
valve in the makeup and purification system and admitted demineralized
water to the reactor coolant system during power operations.
steam driven emergency feedwater pump during power operations.
partial draining of the intermediate cooling (IC) system during
power operations. The IC system supplied cooling to important
loads required for plant operations such as reactor coolant pumps,
j letdown heat exchangers, and control rod drive motors.
The 3 improperly classified STPs were identified from a sample of 20 STPs
reviewed by the team. STPs were essentially new procedures issued for a
temporary time period. Those STPs, classified as NITS, still received an
RTR technical adequacy review in accordance with Procedure 1001A,
" Procedure Review and Approval," Revision 11, but were not evaluated for
constituting an unreviewed safety question. The team was concerned that
by improperly classifying STPs as NITS the licensee was not performing
adequate safety reviews of its procedures.
! (2) The following technical functions procedures described _ ITS activities and
were apparently incorrectly classified as NITS:
l * Procedure EMP-2, " Mini-Mods," Revision 0-00, which described the
design chan
mini mods (ge see control
section process
3.2.2) for plant modifications classified as
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' * Procedure EMP-19, " Plant Modifications Engineered by the Plant," !
Revision 0-00, which described the design change control process I
forplantengineeringmodifications(seesection3.2.3)
- Procedure EP-9, " Design Verification," Revision 2, which described
the requirements for checking modification package analyses
- Procedure EP-25 "As Built Drawings," Revision 2, which described
how station drawings were controlled and updated after system
modification
- Procedure EMP-15. " Field Questionnaires, Change Notices, and Change
Requests," Revision 2, which described how to change a design
modification package during the construction phase of accomplishment
The above examples are only representative of several improperly classified
technical functions procedures for the control of the design change and
drawing control processes. This appears contrary to the definition of
ITS in the licensee's Quality Assurance Plan which includes activities
described in 10 CFR 50, Appendix B. Unlike the STPs, technical function
procedures were not required to receive RTR reviews. Interviews with
licensee management revealed that QA reviewed these procedures, but this
QA review did not necessarily satisfy the TS 6.5 review requirements.
(3) The following procedures had technical inadequacies: ..
- STP 1-86-001, " Flush of MUV-140," did not remove the flushing rig
from the system or restore the makeup and purification system
demineralizers to their normal lineup. Licensee personnel performing
the flush removed the flushing rig and restored the system to its
normal operating lineup.
- STP 1-86-014 " PAT Team Data EFP-1," required that a check valve
(MS-V-69) be verified open and mislabled a steam trap. These
errors did not impact the conduct of the test.
. tank level to be reduced to the engineered safeguards actuation *
!
system (ESAS) low-level set point. Low expansion tank level coincident
I
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with a high-pressure injection signal would cause partial IC system
isolation and potential loss of cooling to the reactor coolant
i
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pumps. This could compound a plant casualty. However, operators
performing the flush acted conservatively and stopped draining the
expansion tank before reaching the low-level ESAS set point.
- TCN 86-95 to Procedure 1102-4 for power operations incorrectly
translated NRC guidance into operating guidance (see Section 3.1.3).
The guidance of this TCN was less conservative than that provided
by the NRC regarding actions required for small power excursions
j above the licensed power limit.
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- TCN 86-112 to Procedure M-148 improperly pennitted the mixing of .
greases with different chemical bases in environmentally qualified
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equipment (seeSection3.3.3). Maintenance personnel acted con-
servatively and flushed the residual grease from the motor although
it was not required by procedure.
- Procedure EMP-019 did not provide adequate guidance for the evaluation
of replacement-in-kind modifications. The procedure did not require
a systematic review of component performance characteristics to ensure
that ertinent design criteria were being maintained (see Section
3.2.3 .
In the cases cited above, conservative actions on the part of the main- ;
i
tenance and operations personnel performing the activities prevented !
possible plant problems. The team is concerned that relying on personnel I
to identify and correct procedural deficiencies is not a sound practice
and could lead to procedural compliance problems.
The team was concerned that the safety review process for procedures as described
in Corporate Procedure 1000-ADM-1291.01, Revision 0-01, and implemented by the
plant and technical functions organizations was not consistently ensuring
that adequate procedures were being issued. This concern was previously raised
by NRC Region I during the most recent Systematic Assessment of Licensee -
'
Performance (SALO) Report (50-289/85-97). It appeared that the licensee's
requirement for RTR and ISR reviews before implementation of ITS procedures
,
created delays in the process that were unacceptable to the plant and technical
functions orga~izations. n Consequently, short cuts were taken by improperly
classifying procedures or providing cursory reviews that did not identify
, potential problems with individual procedural steps or restoration activities.
'
'
The' apparent failure by the licensee to properly classify procedures and conduct
adequate reviews will remain unresolved pending followup by the NRC Region I
(289/86-14-05).
3.4.2 Revised Safety Review Process
4
The new process for safety reviews implemented by Revision 2 of Corporate
Procedure 1000-ADM-1291.01 on September 1, 1986 added a screening step to the
process. The screening step had the effect of eliminating written safety
determinations for some changes to ITS procedures. Instead, a simple yes/no
check mark on a form was substituted for the written determination. Conse-
i quently, the questions in 10 CFR 50.59 comprising the definition of an
l unreviewed safety question were not directly answered in the new screening
step and there was no bases documented for the detennination. It appears
that this change to the safety review process conflicts with the intent of
TS 6.5.1.12, which required that reviewers render determinations in writing
whether proposed procedures, and changes thereto, classified as ITS constituted
an unreviewed safety question. The licensee was not required to conduct
. committee reviews of proposed changes. Instead, safety evaluations were one-
! person reviews, making it very important that the reviews be exceptionally
'
thorough. Interviews with licensee management revealed that this screening
step would reduce the number of written safety evaluations and result in a
more efficient process and allow procedure changes to be implemented more
, expeditiously.
!
The safety evaluation for Corporate Procedure 1000-ADM-1291.01, Revision 2,
t
failed to address the potential for the change to conflict with TS 6.5.1.12
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and appeared to be an inadequate 10 CFR 50.59 evaluation. This issue will
remain unresolved pending followup by the NRC Region I (289/86-14-06).
3.4.3 Responsible Technical Reviewer (RTR)
The RTR was responsible for the in line review of procedures, tests, and plant
modifications for safety and technical adequacy before implementation as
described in TS 6.5 and Corporate Procedure 1000-ADM-1291.01. The RTRs who
,
' were interviewed were generally knowledgeable and had received training in
August 1986 to prepare them for implementation of the new review process.
However, the interviews revealed the following weaknesses with the training.
>
and knowledge of the RTRs:
(1) The depth of the required reviews were not clear to all RTRs. Although
the August 1986 training program and Revision 2 to Corporate Procedure
1000-ADM-1291.01 described the technical review as a " verification of
the technical and safety adequacy of a document" and a " thorough review
!
from a technical standpoint . . .", one RTR indicated that the training
,
program was not clear regarding the extent of technical review required.
A manager-level RTR stated that depth of review varied with procedures
based upon his judgment of the significance of the change.
.
(2) The scope of the required reviews were not clear to all RTRs. RTRs were
expected to be sufficiently knowledgeable of licensing basis documents
so that they could detennine if procedure changes " require revision of
,
any procedural or operating description in the FSAR or otherwise require
revision of the TS or any other licensing basis document." Even the
senior RTRs were unable to identify all doct'nents forming this licensing
'
basis. One RTR considered the basis to be oaly the FSAR and TS.
!
(3) Some RTRs as well as other onsite personnel did not have a working
knowledge of the CARIRS. CARIRS was described by licensee management
as the principal data base for identifying licensing basis documents.
(4) One RTR failed to recognize EQ requirements associated with a TCN that
changed the type lubricant used for hydrogen recombiner blower motors
4
(see Section 3.3.3). No checklist existed to remind RTRs of items to
} look for, such as EQ requirements.
(5) One RTR had received very little training in reactor theory.
Because the TMI-I TS only require one-person reviews, it is imperative that
.
the RTRs be sufficiently knowledgeable to recognize potential problems and to
know when to seek additional reviews for areas outside their field of expertise.
The RTRs also should have a clear understanding of the depth and scope of the
.!
required reviews. The above examples indicate that several qualified RTRs may
-
not have this knowledge and understanding. -
3.4.4 Management Oversight of the Review Process
The licensee had several mechanisms for reviewing and enhancing the adequacy
of its review process. These included a QA monitoring program, the Procedure
4
,
Review Group (PRG), and the Procedure Compliance Task Group (PCTG). Specific
'
improvements initiated by these oversight activities included:
1
- 17 -
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-
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(1) The QA monitoring program had challenged the technical adequacy and
the NITS classifications of procedures on numerous occasions. The
apparent misclassification of STP 1-86-001 was challenged in report
SCD-0124A-85 as well as the technical adequacy of the procedure.
However,' these issues had not been resolved by the licensee.
(2) The PRG was a multidisciplined comittee of the senior RTRs that met
approximately twice weekly to review the more complex procedural issues.
This group provided a collegial review missing from the program outlined
by the TS.
i (3) The PCTG was made up of senior management personnel who were to review
the root causes of procedure-compliance problems, including the adequacy
of procedures within all of GPUNC. During the inspection, the PCTG
report was being finalized and reviewed by senior GPUNC managers for the
appropriateness of recommended corrective actions. The report appeared
to be a thorough review of the problems within GPUNC.
3.5 Surveillance Testing
The team reviewed the licensee's TS surveillance programs. This review included
the processes for scheduling, accomplishing, and recording individual surveil -
lances; implementing changes to the technical procedures; and the overall
management of the programs. The team did not review TS surveillance testing
for radiological environmental monitoring equipment that was covered by a
separate program.
The TS surveillance program included testing of all systems and equipment
specifically identified in the TS (except radiological monitoring surveillances)
and the calibration of those instruments required to adequately perfom the
TS surveillance tests. The program was adequately described in Procedure 1001J,
" Technical Specification Surveillance Program," Revision 6. This procedure
established a process which used a matrix to cross reference procedures and TS
requirements, computer assisted scheduling, weekly status reviews of activities
by management, and line management review of completed tests. This process
generally was considered to be a strength.
The team reviewed 30 completed surveillance tests and found no discrepancies
with the technical adequacy of the procedures, data obtained from the tests
or the timeliness of reviews of completed tests. However, two minor weaknesses
were identified:
(1) Surveillance Procedure 1303-11.45, "PORY Setpoint Check " was performed
on June 25, 1986 using Revision 6 of the procedure instead of Revision 7
which became effective June 21, 1986. The cause for this apparent
discrepancy was that the procedure became " effective" imediately upon
approval without allowing time for the procedure to be printed and
distributed. This process took approximately 1 week; during the
interim, the list of effective procedures would not reflect the issued
procedures. The team reviewed the differences between Revisions 6 and 7
of Procedure 1303-11.45 and detemined that there were no changes that
affected the test results. Additionally, the licensee had previously
identified this problem and was in the process of changing its procedures
for issuance so that both the approval date and effective date of a
procedure would be indi:ated.
- 18 -
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(2) Surveillance Procedure 1302-6, " Calibration of Non-Tech Spec Instruments
used for Tech Spec Compliance," Revision 21, was not updated to reflect
the transfer of instrument calibration responsibilities of three instruments
to the Measuring and Test Equipment (M&TE) Calibration Program. Table I
of Procedure 1302-6 listed all instruments to be calibrated; according
to the procedure, this table was used to prepare a computerized matrix for
scheduling calibrations. The team found that three instruments listed
on Table I were not on the computerized schedule. Further review revealed
that calibration responsibilities for these instruments were recently
transferred to the M&TE program and.the computer schedule was updated to
reflect the change but not the governing procedure. The team reviewed
the M&TE calibration schedule and found that the affected instruments
were calibrated on schedule.
These two examples of weak procedures did not result in any implementation
problems affecting the conduct of plant operation; however, the team was
concerned that these examples indicated a lack of attention to detail with
respect to procedure adherence.
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4 MANAGEMENT EXIT MEETING
4
An exit meeting was conducted on September 5, 1986 at the Three Mile Island,
Unit 1 Nuclear Station. The licensee's representatives at this meeting are
identified in the attached appendix. The following NRC management representa-
tives also were in attendance: P. F. McKee, Chief, Operating Reactor Programs
Branch, Office of Inspection and Enforcement (IE); L. J. Callan, Chief,
Performance Appraisal Section IE; and A. R. Blough, Chief, Reactor Projects
Section IA, Region I. The scope of the inspection was discussed and the
licensee was informed that the inspection would continue with further
'
in-office data review and analysis by team members. The licensee also was
informed that some observations could become potential enforcement findings.
, The observations were presented for each of the five functional areas
inspected and the team members responded to questions from licensee
representatives.
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APPENDIX
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PERSONS CONTACTED
The following is a list of persons contacted during this inspection. There i
were other technical and administrative personnel who also were contacted.
All personnel listed are GPUNC employees unless otherwise noted.
- H. Hukil1 - Director. TMI-1
R. Long - Vice President, Nuclear Assurance Division
- R. Toole - Director, Operations and Maintenance, TMI-1
- N. Kazanas - Director, Engineering Projects
- R. Keaton - Director, Quality Assurance
J. Thorpe - Director, Licensing and Regulatory Affairs GPUNC
D. Slear - Director, Engineering Services
- M. Ross - Director, Plant Operations
- C. Smyth - Manager, Licensing
(M. Nelson - Manager, Nuclear Safety
B. Ballard - Manager TMI QA Modifications / Operations .
D. Shovlin - Manager, Plant Maintenance
R. Markowski - Manager, QA Programs / Audits
R. Gemann - Manager, Nuclear Safety GPUNC
- C. Hartman -Manager,PlantEngineering,TMI-1(E&IC)
.. ,
R. Barley - Manager, Plant Engineering, TMI-1 (MECH) !
M. Snyder - Manager, Preventive Maintenance
L. Wickas - Manager, Operations QA
R. Harbin - Manager, Vender Document Control
R. Wulf - Manager, TMI Projects
D. Fultenberg - Manager, THI-1 Long Range Planning I
P. Moor - Manager, TMI-1 Projects
F. Barbieri - Manager, Secondary Plant
R. Harding - Manager, Quality Classification / Engineering Configuration
J. Flynn - Manager, Engineering Procedures and Standards
D. Shivas - Manager, Engineering Data and Configuration Control
T. Hawk' ins - Manager, Startup and Test, THI-1
R. Neveling - Manager, Document Distribution Control Center TMI
- C. Shorts - Manager, Technical Functions - Site
l *R. McGoey - Manager, PWR Licensing GPUNC
l R. Boyer - Shift Supervisor, Operations
! D. A. Smith - Shift Supervisor, Operations
D. E. Smith - Shift Supervisor, Operations
S. Sanfor - Supervisor, Configuration Control
- H. Wilson - Supervisor, Preventive Maintenance
- C. Incorvati - Supervisor, THI-1 QA Audits
R. Troutman - Maintenance Planning and Scheduling
G. West - Computer Supervisor
W. Frasier - Shift Foreman, Operations
D. Hoss - Shift Foreman, Operations
M. Bezille - Shift Foreman, Operations
A-1
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_. . - - _ _ _ _ _ _ , . . _ _ , - _ _ - - _ _ _ . _ _ _ _ . - . , _ _ _ _ _ _ _ _ . . . _ , . _ _ _ _ . . . , _ - , . . _ . - - _ _ _ , . . . -
- .
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, G. Davis - Shift Foreman, Operations
D. Neland- - Control Room Operator
'
J. Auger - Licensing Engineer
B. Gan - Project Engineer. TMI-1
D. Distel - Licensing Engineer
S. Ku - Secondary Plant Engineer
C. Brumbach - Maintenance, Construction and Facility -
L. Lanese - Safety Analysis and Plant Control
R. Summers - Lead Mechanical Engineer
, *D. Hassler - Licensing Engineer
- P. Sinegar - Administrator Plant Maintenance, TMI-1
T. Sinunons - Corrective Maintenance Assistant
D. Pilsatz - Document Distribution Control Center, TMI
D. Carl - Senior Technical Analyst
S. Wilkerson - Lead Nuclear Engineer
D. Atherholt - Engineer, Plant Operations
R. Eich - Technical Analyst, GMS Coordinator
T. Dunn - Operations QA
P. Wells - Safety Review Engineer
H. Shipman - Senior Engineer, Operations
C. Sertz - Senior Engineer -
G. Hoek - Control Room Operator
,
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J. Gallagher - Control Room Operator ,
J. Moore - Control Room Operator
R. Lane - Control Room Operator
R. Heilman - Control Room Operator
J. Fishell - Auxiliary Operator
R. Stotz - Auxiliary Operator
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- Personnel attending exit meeting.
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