ML20149D323
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| ML20149D323 | |
| Person / Time | |
|---|---|
| Site: | Three Mile Island  |
| Issue date: | 12/22/1987 |
| From: | Cowgill C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20149D302 | List: |
| References | |
| 50-289-87-19, NUDOCS 8801120274 | |
| Download: ML20149D323 (35) | |
See also: IR 05000289/1987019
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket / Report No. 50-289/87-19 Licensee: DRP-50
Licensee: GPU Nuclear Corporation
P. O. Box 480
Middletown, Pennsylvania 17057
Facility: Three Mile Island Nuclear Station, Unit 1
Location: Middletown, Pennsylvania
Dates: October 2 - 31, 1987
Inspectors: R. Conte, Senior Resident Inspector (TMI-1)
D. Johnson, Resident Inspector (TMI-1)
S, Peleschak, Reactor Engineer, Region I
Reporting
Inspector: R. Conte, Senior Resident Inspector
Approved by: d ' an. __
/ M!/'7
C. Co 91 1 C ief, Reactor Section No. lA, DRP Date
Inspection Summary:
The NRC resident staff conducted safety inspections (160 hours) of the plant
operations, maintenance, and surveillance areas which specifically included:
simultaneous inoperability of both energency diesel generators; the reactor
protection system (RPS) trip breaker replacement; and, pressure switch
calibration for the nuclear service river water system. Other areas reviewed
were: independent verification program (IVP); control room environment; storage
of transient equipment in safety-related areas; Licensee Ever.t Reports; and,
licensee followup / response to previous inspection findings.
The inspectors also performed an inspection at the corporate office of the
following: allegation review and followup; Nuclear Safety and Compliance
Committee activities; outage /long-range planning for Cycle 7R; technical
support reassessment; and, safety evaluations.
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Inspection Results:
Licensee management attention and involvement, especially in daily
activities, continued to be noted. As evidence of this, the licensee
instituted a six-month preventive maintenance replacement of reactor
protection system breaker. In general, procedures were properly imple-
mented.
However, certain personnel performance problems were noted; one of these
resulted in a violation on failure to properly follow lifted lead admin-
istrative controls (see paragr ph 3.2.2). Other underlying causes appear
to be a combination of the following: poor attention to detail; poor
technical and safety review and/or poor training in system classifi-
cation, along with the scope of applicability for independent verifica-
tion.
The verification of correct operating activity procedures met revised
licensee commitments in this area. Weaknesses were noted in the
applicability of the program to certain areas. Problems were noted with
the licensee's response on the independent verification program.
The corporate staff was adequately supporting TMI-1 safe operations.
Three unresolved items were identified during this review (paragraphs 5.2 -
and 5.5).
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DETAILS
1.0 Introduction and Overview
1.1 NRC Staff Activities
The purpose of this inspection was to assess licensee activities during
the power operations mode as they related to reactor safety and radiation
protection. Within each area, the inspectors dorumented the specific
purpose of the area under review, acceptance criteria and scope of inspec-
tions, along with appropriate findings / conclusions. The inspector made
this assessment by reviewing information on a sampling basis through
actual observation of licensee activities, interviews with licensee
personnel, measurement of radiation levels, or independent calculation
and selective review of listed applicable documents.
The resident inspectors also assisted in the monitoring of the annual
emergency preparedness exercise of October 22, 1987, as documented in NRC
Inspection Report No. 50-289/87-16.
1.2 Licensee Activities
During this period, the licensee operated the. plant at essentially full
power.
2.0 Plant Operations
2.1 Criteria / Scope of Review
The resident inspectors periodically inspected the facility to determine
the licensee's compliance with the general operating requirements of
Section 6 of the Technical Specifications (TS) in the following areas:
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review of selected plant parameters for abnormal trends;
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plant status from a maintenance / modification viewpoint, includ-
ing plant housekeeping and fire protection measures; i
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control of ongoing and special evolutions, including control room
personnel awareness of these evolutions;
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control of documents, including logkeeping practices;
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implementation of radiological controls; and,
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implementation of the security plan including access control, i
boundary integrity, and badging practices. i
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The inspectors focused on the areas listed in Attachment 1.
2.2 Findings / Conclusions
2.2.1 General
The inspection focus by the NRC resident office during this inspection
period was the followup on a nunber of outstanding items, some of which
involved major plant operational programs. The results of these reviews
are documented elsewhere in this report, such as for the independent
verification program (Section 4) and control room environment (Section 6).
In general, procedures were properly implemented, except as noted below
and in Section 3. Personnel errors occurred, although they did not result
in any reportable events. Housekeeping ano fire protection measures
continued to be properly implemented.
Overall, licensee management continued their detailed attention and
involvement in daily activities.
2.2.2 Emergency Diesel Generators not in Engineered Safeguards (ES)
Standby
During preparations for Engineered Safeguards. and Actuation System
(ESAS) testing per Surveillance Procedure (SP) 1303-5.2, the licensee
inadvertently removed both emergency diesel generators (EDG's) from the
ES standby condition for about two minutes. The situation was immediately
recogni:ed by operations personnel and the condition corrected.
The problem occurred when an auxiliary operator (AO) manually tripped the
fuel racks for the "A" EDG when the "B" EDG was already blocked f rom an
ESAS auto start capability. The operator who mispositioned the "A" fuel
rack lever was not fully aware that tripping the "A" EDG would place both
EDG's in an ESAS inoperable status.
A communication problem between operations personnel in the control room
and the A0 was the primary cause of the problem. The "B" EDG had correctly
been placed in the "ES" standby condition, an initial condition for manual
start. The AD had incorrectly noted on his copy of the procedure that
the "A" EDG was to be run. The AD also failed to communicate to the CR0
in the control room which EDG he was tripping. Both personnel assumed
that the correct actions were to be taken.
The "A" EDG fuel racks were reset in approximately two minutes ano
immediately after the control room annunciators indicated the problem.
With the EDG's blocked, the CR0 repositioned the "B" EDG start and
exciter switches to "auto" to place the "B" EDG in ES standby.
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The inspector reviewed the event and discussed the probitm with the
operations staff. An internal Plant Incident Report (Plit) completely and
correctly documented the problem. The PIR concluded that, although the
safety significance was minor, proper communications neec to be observed
when complicated, multi-station tests are being performec. The licensee
noted that more aggressive use of proper formal communications needs to
be implemented to prevent future reoccurrences of this type of problem.
The licensee also evaluated the problem as non-reportable since the
Limiting Condition for Operation (LCO) time clock for the condition was
not exceeded. The LCO for this condition allows both EDG's to be
inoperable for up to eight hours before plant shutdown actions are needed.
The inspectors also concluded that this item was of minor safety signific-
ance as operators were quickly aware of the condition and corrected it
immediately. Off-site power was available. The inspectors were notified
of the event shortly after occurrence at 5:30 a.m. on October 8,1987.
The licensee review of the circumstances concerning this problem was
complete and adequate. The inspectors had no other safety concerns on
this event.
2.3 Plant Operations Summary
Housekeeping continued to be quite good. Procedures, in general, were
properly implemented.
For the above-noted wrong train / component event, the inspector noted a
lack of attention to detail on the part of personnel performing the test. [
Also, the inspector noted that the time of day the surveillance test was
performed may have contributed to the problem. ,
Licensee management continued their detailed attention and involvement in
daily activities.
3. Maintenance / Surveillance - Operability Review
3.1 General Criteria / Scope of Review i
The inspector reviewed activities to verify proper implementation of the
applicable portions of the maintenance and surveillance programs. The
inspector used the general criteria listed under the plant operations
section of this report. Specific areas of review are listed in Attachment
1. A more detailed review of equipment operability was also addressed
below,
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3.2 Findings / Conclusions
3.2.1 Reactor Trip Breaker Replacement
The licentee completed the changeout of all six reactor trip breakers
(RTB) during this inspection period. The two a.c. and four d.c. breakers
(GE-AK-II-25) were changed out, one for one, with breakers that had
recently had preventive maintenance accomplished. This replacemerit was
accomplished during weekly reactor protection system (RPS) surveillance
testing, such that all six breakers were changed out in a four-week period.
This complete changeout is accomplished on a six-month basis.
The inspector reviewed documentation associated with the preventive
maintenance for the RTB's and witnessed portions of the breaker
changeout and surveillance test activities. The following documents
were reviewed:
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SP 1303-4.1, Revision 53, dated May 22, 1987, "Reactor Protection
System;" and,
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Preventive Maintenance Procedure E-36, Revision 15, dated October 8,
1987, "CR0 Trip Breaker Check."
The inspector also discussed the preventive maintenance activities with
licensee personnel.
A review of the "as found" data for the RTB's that had been in service,
revealed no major breaker degradation. Time response and major breaker
operating parameters, were all found to be within specifications such as,
spring pressures, trip bar lift pressures, and shunt and undervoltage
(UV) coil voltages.
The inspector observed that personnel who were installing the breakers
appeared knowledgeable of their task and changeout of two d.c. breakers
was accomplished without problems. He also observed portions of SP
1303-4.1 for RPS Channel "C," which verified breaker operability (shunt ,
trip and UV trip) after breaker replacement. No problems were noted. '
The inspector concluded that the changeout of the RTB's had been l
accomplished in a safe and orderly manner. The inspector had no safety I
concerns on this evolution.
3.2.2 Differential Pressure Switch Calibration j
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During a review of maintenance activities associated with the "1B" l
nuclear river water pump (NR-P-18), the inspector observed an Instrument ;
and Control (I&C) technician performing a calibration check of the instru- l
mentation associated with NR-P-18. While reviewing the applicable preven- l
tive maintenance (PM) procedure IC-15, the inspector noted that the '
technician had marked "N/A" for the step requiring verification of the
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use of the "lifted lead" log per Administrative Procedure 1013, Enclosure
5. This step would have required the technician to fill out a lifted
lead log entry for some pressure switch connections for NR-DPS-138, the
NR-P-1B strainer differential pressure (D/P) switch. The leads were to
, be lifted to prevent operation of the backwash valve when simulated
pressure was increased above the setpoint. The technician had msrked the
step "N/A" as he believed that the system being worked was not important
to safety (ITS). This was an incorrect assumption. The procedure was
unclear in defining exactly which systems were ITS.
The inspector notified licensee management of the problem. The licensee
immediately reviewed the problem and concluded that the technician had
misunderstood IC-15 and the NR systems status as an ITS system. At the
same time efforts were initiated to ensure NR-DPS-138 was wired correctly.
The technicians from the I&C shop were instructed in the proper use of AP
1013.
Followup licensee long-term corrective action included accomplishing
the following.
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A review of other corrective and preventive maintenance procedures
to eliminate any confusion that may exist; i.e., clarification of
the decisions on steps that will not be performed in procedures
which are to be marked as N/A. The licensee representative agreed
that the identification of procedures that need to be changed is to
be completed by February 2,1988.
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Those systems that are classified as ITS will be reviewed with all
I&C technicians to ensure their awareness of where independent
verification of AP 1013, Enclosure 5, is required.
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A Procedure Change Request (PCR) will be initiated to clarify the
wording in procedure 1C-15, which caused confusion for the technician.
As defined above, the licensee's actions will be completed by February 2,
1983.
The inspector concluded the immediate and long-term corrective actions
for this problem were adequate to resolve the inspector's concerns. ,
The licensee concluded that this problem was an isolated occurrence and
that, generally, I&C technicians were aware of which systems were ITS.
Additionally, it was noted that Enclosure 5 of AP 1013 must be used for
all systems -- both ITS and NITS (not important to safety). The "ITS"
classification triggers an additional independent verification of lifted
lead status on Enclosure 5,'if the system being worked is ITS. From a
training viewpoint, the inspectors concluded that this was not an isolated
case.
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The failure of the technician to properly implement the provisions of
AP 1013 during the conduct of calibration of NR-DPS-138 in accordance
with IC-15 is a violation of TS 6.8.1(289/87-19-01).
3.3 Operability Summary
From the inspector's review of the reactor trip breaker preventive
maintenance procedures, it is noteworthy that the licensee has adopted
a preventive maintenance practice to changeout reactor protection system
(RPS) breakers at six-month intervals, lest procedures were properly ,
implemented and test results were in accordance with the licensee's
acceptance criteria.
The performance problem associated with the pressure switch calibration
was due to failure to follow administrative control procedures and it was
not indicative of a flaw in the independent verification (IVP) program
(see Section 4). However, there were signs of other underlying causes
for this event. They are: poor technical and safety review that did not
identify the need for updating of sub-tier implementing procedures with '
respect to IVP and, perhaps, poor training in system classification along
with the scope of applicability of the IVP.
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The inspector was satisfied with licensee's corrective actions taken or
planned for the above-noted violation.
4. Independent Verification Program (IVP)
4.1 Introdu: tion and Background ,
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The NRC staff opened a previously unresolved item (289/85-27-08 - see
also paragraph 9.2) because the licensee's program to verify correct
operating activities was: (1) not clearly defined in that various ,
sections of TMI-1 hearing records addressed multiple and conflicting '
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attributes of this type of program; and, (2) various administrative
control procedures applied this program to a different set of equipment
which was not clearly correlatable to the hearing commitments. In '
addition, the program was not consolidated in addressing TMI Task Action '
Plan (TAP) I.C.6 key elements (see paragraph 9.2).
The purpose of this review was to assure sufficient licensee resolution
of the above items and to assess the technical adequacy of the program.
Overall, favorable results are addressed below, but there is a weakness ;
on the scope of equipment within the IVP.
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4.2 Scope of Review
In addition to discussions with cognizant licensee personnel, selected l
sections of the following documents relating to the independent
verification program (IVP) were reviewed.
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Administrative Procedure (AP) 1001A, Revision 13, effective
June 26, 1987, "Procedure Review and Approval"
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AP 10010, Revision 11, effective December 10, 1986, "Procedure
Preparation"
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AP 1001K, Revision 9, effective December 10, 1986, "Biennial
Procedure Review"
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AP 1001J, Revision 6, effective July 22, 1986, "Technical
Specification Surveillance Testing Program"
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Ap 1002, Revision 49, effective July 17, 1987, "Rules for the
Protection of Employees Working on Electrical and Mechanical
Apparatus"
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AP 1013, Revision 23, effective August 5, 1987, "Bypass of
Safety Functions and Jumper Control"
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AP 1029, Revision 25, effective May 20, 1987, "Conduct of
Operations"
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AP 1067, Revision 1, effective March 19, 1987, "Independent
Verification Program"
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Operations Procedure (0P) 1101-3, Revisior 45, ef fective
September 25, 1987, "Containment Integrity and Access Limiti"
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OP 1104-28 (Series) "Solid Radwaste Handling"
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SP 1302-5.7, Revision 10, effective March 31, 1987, High Reactor
Building Pressure Channel"
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SP 1302-5.10, Revision 16, effective June 2, 1987, "Reactor Building
4 psig Channel"
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SP 1302-5.11, Revision 10, effective May 5, 1987, "Reactor Building
30 psig Channel"
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SP 1302-18, Revision 4, effective June 16, 1986, "Calibration of
Reactor Building Post-LOCA/ Hydrogen Monitor"
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SP 1302-19, Revision 4, effective May 19, 1987, "Hydrogen Recombiner
Instrument Channel Calibration"
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SP 1302-20, Revision 2, effective September 25, 1986, "Containment
Pressure Instrument Calibration" l
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4.3 Findings / Conclusions
4.3.1 IVP Essential Elements
Operationally important and critical components within safety- related
systems are included in the licensee's IVP (AP 1067) using the criteria
specified in the licensee's letter, dated April 29, 1986. Essentially
all Engineered Safeguards and Actuation System (ESAS), containment,
emergency feedwater (EFW) systems are listed, including major flow path
valves; key breakers; and, other key components, such as manual flow path
valves that, if mispositioned, could disable the train. Manual valves in
high radiation areas are generally on the locked valve list. The AP 1067
list does not include drain / vent valves or other components where status
would be monitored or verified by other means. These other means would
be ESAS checklist (once/shif t) or the shif t and daily surveillance
procedures. Also, there would be an obvious system depressurization if a
drain / vent were inadvertently left open. The AP 1067 list also includes
control and power supply breakers and control switches for each system
1 within the scope of the program.
The program, as embodied in AP's 10010, 1001K, 1002, 1013, 1029, and
1067, has administrative controls that are now, in general, consis-
tent with one another. A minor exception was noted (see paragraph 9.2).
Instrumentation is handled separately. The reactor protection system
(RPS) is not specifically listed in AP 1067; but, by virtue of the shift
and daily check surveillances done on the system, the RPS is routinely
verified to be operational. This is also true for the actuation logic of
ESAS, but certain components were also listed in AP 1067. Other safety-
related instruments (such as wide-range / narrow-range (WR/NR) reactor
building (RB) pressure, hydrogen recombiner instruments, and containment
hydrogen monitor) are not necessarily independently verified to be
correctly lined up.
Support or attendant ecuipment is designated with referral to other
sections in this AP 1067. The AP 1067 valve listing was developed by
review of applicable system drawings.
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The AP 1067 states that surveillance procedures (SP's) stand alone on IVP
on restoration to normal, and in general, that is true except for safety-
related instrumentation as noted above. The biennial review procedure
(AP 1001K) verifies that SP's are consistent with AP 1067 guidance.
Further, AP 1001D requires that, as a minimum, critical components have
independent verification applied when SP's are generated.
The same is true for restoration to normal with respect to switching
and tagging related to maintenance work. If no tags are used in minor
maintenance effort, a procedural-required form is used which invokes the
IVP requirements for critical components.
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For plant startup from outages, the AP 1067 critical valve listing is
implemented at the discretion of the Plant Operations Director. In
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general, systems affected by the outage would have the AP 1067 listing
verified. Containment integrity is independently verified whenever it is
set. The locked valve list is also checked.
4.3.2 I)!P Strengths
A number of strengths were noted as a result of the licensee's actions on
the IVP in response to NRC concerns..
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The graded approach highlights safety significant equipment
r.1ong those components listed as safety related.
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AP 1013 on temporary moaifications (TM's) (bypasses) still applies
to "important-to-safety" equipment which includes safety-related
equipment.
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The program was updated to reflect the latest modification work
(e.g., Heat Sink Protectior. System (HSPS)).
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Specific guidance on how to do IVP is specified in AP 1067 - the
doer and verifier must be different.
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For minor maintenance or maintenance with no tags applied , the
control room operator (CRO) must document the independent verific-
ation of restoration to normal from maintenance in the CR0 log
Analysis is provided below (paragraph 4.3.5).
4.3.3 IVP Weaknesses
The following shortcomings were noted with respect to the currently
defined IVP:
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Some safety-related equipment will be manipulated during operation,
maintenance or surveillance and not be independently verified to be
restored to normal.
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The IVP for radwaste and fire protection (FP) essentially does not
exist for routine processing / transfers. These system valves are
included if they are containment isolation valves. (It should be
noted that in the FP area TS requires a monthly alignment check (SP ;
3301-M1), but this would not necessarily assure correct alignment
for times in between the check when equipment is removed from
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service.)
Analysis is provided below (paragraph 4.3.5).
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4.3.4 IVP Implementation
During this inspection period, the inspector independently verified
the correct lineup of selected safety-related equipment. This was
accomplished using the following methods:
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routine control room and safety-related areas review and walkdown
of selected safety-related equipment;
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check of the positions for valves and breakers listed in AP 1067 for
EFW and its interface systems -- condensate and main steam;
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selective verification of lineups as listed in the licensee's ESAS
checklist and secondary auxiliary operator shift logs focusing on
reactor building spray system pressure instruments and EFW and its -
interface systems - condensate and main steam; and,
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the calibration activity described in paragraph 3.2.2 of this report.
Within the scope of this review, safety-related equipment was properly
aligned to perform its intended function. As described below, minor
l implementation problems were identified, but none included nan-adherences
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to AP 1067.
Paragraph 2.2.2 describes a wrong train / component situation which
resulted in both emergency diesel generators becoming inoperable with
respect to ESAS signal for a short period of time. The root cause was a
communications problem, but the inspector also reviewed the event with
respect to IVP. For the situation described, IVP was not applicable
since the licensee was in the middle of a surveillance test. The IVP's
3 purpose, in part, is to verify equipment to be restored to normal. This .
does not reflect a weakness in the IVP, although an incorrect activity
was performed. Closer attention to detail could have prevented it.
Control room operators were attentive to quickly correct the problem.
Paragraph 3.2.2 of this report describes a licensee individual's
- failure to follow the applicable administrative controls for lifting
leads in safety-related equipment. Contributing to this event was a
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procedure adequacy problem in that it still used the pre-AP 1067
terminology of selective applicability of IVP to certain safety-related
equipment, However, another section of the procedure properly invoked AP
1013 requirements, but the individual apparently did not fully understand
the system's classification that he was working on. In any case, these
problems do not reflect adversely on the adequacy of the IVP per AP 1067
l and AP 1013. It is clear that the clarification in scope of equipment to i be independently verified per AP 1067 was not adequately reflected in
sub-tier implementing procedures and this reflects a weakness in the
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licansee's technical and safety review process.
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Section 8 of this report describes Licensee Event Report (LER) No. 87-009
(see also NRC Inspection Report No. 50-289/87-17, paragraph 2.2.1) on an
effluent radiation monitor interlock (with discharge valve) being inopera-
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ble during a release. The LER describes several personnel errors on the
part of mainte,1ance and operations staffs. However, procedure enhancements
were also planned to verify and control the proper positioning of the
interlock defeat / enable switches in the release sequence. The inspector
reviewed this event for any adverse implications to the IVP. Tne particular
enable / defeat switches were included in AP 1013, which provides control
measures for the bypass of safety functions. These measures were not
properly iinplemented by the personnel and/or by the sub-tier calibration /
operational procedures. The inspector concluded that this was not a
weakness in the IVP, but it does reflect a weakness in the licensee's
technical and safety review process.
The events described above do indicate a need for closer attention to
detail, better technical and s&fety reviews, and additional training
in the area of safety classification and scope of IVP applicability.
The inspector concluded that the IVP is being properly implemen+ed.
4.3.5 Evaluation of the IVP
Evidence indicates that the past and current IVP programs, in
general, have been effective at least since 1933. In September 1983,
there were a number of containment integrity violations when the plant
was in hot functional testing, The IVP was then enhanced on a limited
basis. The inspector has reviewed LER's since then and he concluded that
none of the LER's were due to flaws in the IVP. There also have not been
significant safety events as a result of IVP weaknesses in the past two
years of power operations. (Paragraph 4.3.4 alludes to weaknesses in
other areas.) Further, the implementation review noted above confirmed
the proper alignment of the EFW and reactor building spray systems, as
examples.
The IVP (per AP 1067) does not stand alone, however. A number of other
controls constitute a verification of correct operating activities in
addition to AP 1067 measures.
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ESAS checklist done on a shift basis supplemented by various checks
done by the primary, secondary, and outbuilding auxiliary operators.
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Locked valve list as required by AP 1011, "Controlled Key Locker
Control."
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Shift and daily checks (SP 1301-1) and weekly checks (SP 1302-4.X
seriesofprocedures).
Proper implementation of these measures were also independently verified
by 'he inspector, based on this review.
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Licensee management has agreed that there has been an enhancement to
safety as a result of their efforts to respond to NRC staff concerns in
this area. The AP 1067 now clearly defines what components are important
and, accordingly, what components deserve the special attention of the
IVP. Licensee management indicated their receptiveness to resolve any
future NRC staff concerns if incorrect activities should cccur. They
emphasized that future (independent verification) corrective actions
would probably be procedure spec!fic to the component (s) involved so as
not to dilute the importance of critical valves listed in AP 1067 with a
program expansion.
The licensee should strongly consider incorporating independent verifica-
tion measures into facility procedures dealing with the below-listed
systems before any major events occur as a result of a lack of
independent verification.
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Fire protection
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Solid, liquid, and gaseous radwaste
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Safety-related instruments not within the scope of RPS/ESAS
periodic tests
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In conclusion, the licensee's programs for verifying correct operating
activities meet revised commitments in this area. A number of strenghts
with the programs were noted. The weakness is centered around the scope
of applicability of IVP. To date, this weakness has not adversely
affected safe plant operations. Accordingly the backfit process is ,
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inappropriate at this time (see paragraph 9.2). l
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4.3.6 Procedure Clarifications [
During the review of AP 1067, the inspector noted some minor discrepancies [
for which the licensee is agreeable to resolve by the
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next revision to AP 1067.
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Paragraph 4.3.b.1 of AP 1067 on the use of remote indication by two !
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different people does not have a "caution" or "note" to assure that
direct indication be available in distinction to power demand signal
lights. The licensae agreed to provide such a highlight. ;
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Paragraph 6.0 of AP 1067, on References, lists the first licensee
response lettar of April 29, 1986. The other licensee response letter
of June 3,1987, was not included and it provides additional program
description. The licensee agreed to incorporate the latest licensee
letter by reference into AP 1067.
4.4 IVP Prcgram Summary
The licensee's procedures for verifying correct operating activities
meets revised commitments in this area. A weakness was identified in that
IVP applies to a subset of safety-related equipment. However, program
implementation has, in general, been quite good without events involving
rnajor safety significance. Performance problems with respect to verifying ,
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correct activities are not correlatable to IVP weaknesses. They point
out a need for closer attention to detail, better technical and safety
reviews, and additional training in the area of safety classification
and IVP scope applicability.
5. Corporate Inspection
5.1 Introduction
) The Senior Resident Inspector (SRI) (TMI-1) conducted an inspection at i the licensee's corporate headquarters in Parsippany, New Jersey, on >
October 13-15, 1987. The main focus of the inspection was to follow up
i
on various previously identified open issues (as described below) to
assess licensee sctions toward resolution of these items or to assess
proper implementation of selected corporate-level programs in support of <
TMI-1 safe operations. Many of these issues are either identified in '
past inspection reports or in the latest SALP (Systematic Assessment of
Licensee Performance) process.
i
5.2 Allegation on Polar Crane Operation - Procedural Controls
.'
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,
On September 3, 1987, the SRI (TMI-1) received an allegation on procedural
controls for the operation of the reactor building (RB) polar crane (No. .
,
RI-87-A-0108). The polar crane is used to lift heavy loads within the RB
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to support refueling outage-type work. The licensee employee's concern
apparently developed during the last refueling outage (November 1986 to
Mai,o 1987) and they centered on the following:
--
the director or sivalman for RB polar crane operator was not equally
qualified (medically and/or trained) as the operator of the crane;
and,
--
licensee management arbitrarily deleted these apparent procedural
requirements.
The individual came to NRC apparently because he felt he had a safety ,
concern and because he felt that licensee management was not effectively
resolving the issue. The inspector encouraged the individual to use the
licensee's internal systems, such as the "Ombudsman Program," to resolve
his issue; but the inspector acknowledged that NRC staff would review the
matter.
Af ter his conversation viith the inspector, the individual apparently
informed the licensee's ombudsman of the issue on the same day. As a
part of Region I's review of the matter, it was decided to let the
licensee's ombudsman review the matter and then the NRC staff would
re. aw the licensee's results. While at the corporate office, the
inspector discussed the concerns with the licensea's ombudsman and
the engineer assigned to resolve the problem.
In addition to the above-noted conversation, the inspector reviewed the #
following licensee documents / records:
--
Maintenance Procedure (MP) 1406, Revision 9, dated December 8, 1986,
"Crane Operator Qualifications;"
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Refueling Procedure (RP) 1507-1, Revision 6, dated December 8, 1986,
"Polar Crane Operation;"
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ANSI B30.2.0 - 1976, "Overhead and Gantry Cranes;"
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Temporary Change Notice (TCN) No. 1-86-087, dated November 21, 1986,
to RP 1507-1, Revision 5; and,
--
Licensee Internal Memorandum, dated Septembe- 13, 1987, from 1.
Mengel to R. German on "Review of Change to .I-1 Polar Crane
Operating Procedure."
The inspector had the below-listed findings on the licensee's review of
the matter.
Prior to the last refueling outage, MP 1406 implied that the director (or
signalman) be qualified to the same standards as the operator. The TCN
1-86 187 was initiated, reviewed, approved, and issued to more clearly *
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state requirements. The requirements for qualification apply only to the
operator, not-the signalman. It is the operator's responsibility that
the signalman, if Jsed, can adequately communicate. signals to assure : safe
crane operation. This is consistent with ANSI B30.2.0 - 1976, which is
referenced by-NUREG 0612, "Control of Heavy Loads," to which the licensee
is committed.
During the licensee's review of this matter, it was identified that
RP 1507-1 and 1507-2 (for Fuel Handling Building Crane) had hand signals
that were inconsistent with the 1976 version of the ANSI. Standard. The
licensee planned to revise RP 1507-1 and 1507-2 'to make the designated ,
signals consistent with that committed to in the standards. _ . _ . , _ j
The inspector independently confirmed the licensee's findings. The
ombudsman also reported that licensee Quality Control (QC), .and Safety
and Health personnel agree with the ombudsman's findings.
The ombudsman reported that he discussed his findings with the concerned
employee on September 25, 1987, but the employee did'not appear-to be j
satisfied. The employee raised another specific allegation-(discussed
later) and he indicated that this issue (additional allegation) and the
one on the polar crane were indicative of a broader issue -- the nuclear
safety implications of working people out of a job classification by
,
,
procedural word changes. The licensee representative reported that the
employee indicated that a labor relations grievance would be. filed; but, ,
as of the end of this inspection period, the employee had not filed such '
a grievance.
!
The gist of the other allegatio1 was the potential nuclear safety
implications of operations personnel doing a job that is also done by
maintenance technicians. The ombudsmen indicated that they would review !
this additional allegation with respect to nuclear safety. j
This is unresolved pending completion of the licensee's review of this-
matter and subsequent NRC Region I review (289/87-19-02).
Based on this review, the original allegation (No. RI-87-A-0108) is
considered closed.
5.3 Nuclear Safety and Compliance Committee Activities
At the corporate and site, the insnector reviewed Nuclear Safety and
Compliance (NSCC) activities to assure that the applicable-restart
condition (No. 1.t) was continued to be met. The inspector conducted a
more detailed review in NRC Inspection Report No. 50-289/86-19. In
,
addition to discussions with the NSCC staff members, the following
records or documents were reviewed:
--
GPUN Board of Director Meeting Minutes on the NSCC report of
activities for the period November 1986 to August 1987; and,
.
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.
--
NSCC Semi-Annual Report (No. 6), dated-April 8, 1987, for the period
October 1, 1986, to March 31, 1987.
The inspector continued to note that events or NSCC staff findings unique '
to the sites (which are not necessarily receiving much publicity) are
~
being followed by the NSCC staff and reported to the GPUN_ Board of
~
Directors. This continues to be advantageous in that it enhances.the
board's knowledge of a number of issues at 'both Oyster Creek and TMI-1.
The inspector also noted substantial attention by the NSCC and its staff
to past significant events at Oyster Creek. There also appears to be an
appropriate level of attention to TMI-1 activities. _The inspector also __
noted the identification and tracking of issues raised by NSCC.
The NLCC staff leader reported on a number of licensee actions that could
be considered measures of the effectiveness of the NSCC and its staff.
Except in one area, details will not be given since the inspector he; not
made any recent observations in the areas. Accordingly, the inspector
would not be able to judge whether licensee performance improvemen.s have
really occurred, nor would the inspector be able to judge if they were as
a direct result of NSCC activities or other groups, outside company
activities. What was important was that the NSCC staff was evidently
reviewing its own activities and attempting to assess its impact on
enhancing licensee performance.
The above-noted exception was in the area of logkeeping. Like the NSCC
staff, the inspectors have noted improvement in the d. tails given in l
control room narrative logs on off-normal events at the plant, which are
not reportable to the NRC. However, as noted in NRC Inspection Report.
No. 50-289/87-17, it does appear that the threshold is still high for
formal review of such events using such mechanisms as the plant incident
reporting system. ;
The inspector had no additional comments on the NSCC and its staff's
activities.
,
5.4 Outage /Long Range planning
At the corporate office, the inspector reviewed outage /long range
planning with the cognizant manager and selectively reviewed Topical
j
,
Report 042, Revision 1, dated October 8, 1987, "TMI-1 Nuclear
Generating Station Long Range Plan, Cycle 6 through 9R." The
purpose of tnis review was:
--
familiarization and assessment of long range plan; in particular,
the Cycle 7 refueling outage;, and,
--
assure ' regulatory issues or required modifications were incorporated
into the plan.
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.
The inspector determined that the licensee has adopted the integrated
living schedule (ILS) plan proposed by NRC Generic Letter No. 85-07.
They have submitted a Technical Specification Change Request (TSCR) No.
170, dated July 13, 1987, requesting adoption of the ILS into the TMI-1
operating license. The proposed ILS is consistent with Topical 042.
During the last year, the licensee revised its corporate structure ~to
provide a vice president dedicated to Planning and Safety Review.
Incorporated into this organization is the Licensing Department and Long
Range Planning for TMI-1 and Oyster Creek, each having dedicated staffs.
It appears that the licensee has effectively. unified planning and
prioritization of regulatory and safety issues under the direction of
a single vice president who is corporate based.
The inspector &lso noted that this Topical Report was complete in that it. ,
has all the issues for which there were inspector-known licensee commitments
for Cycle 7R. This included such things as certain modifications in
conjunction with Regulatory Guide (RG) 1.97 and Inservice Testing commit-
ments dealing with the need for additional pump / valve instrumentation.
The 7R outage is scheduled to start July 1, 1987, for nine weeks, but
this is subject to change depending on plant performance-during 1986/1987
and the need for power in the summer months. The length of the outage
may be shortened depending on progrest already started for RG 1.97
modifications not needing a plant shutdown. The planning also includes
contingencies for unforeseen work, such as-in response to adverse inservice-
inspection results. Contingencies for person-rem exposure and radwaste
generation were also noted.
Also, the inspector noted licensee initiative to schedule modification
work for 7R that would enhance the reliability of the integrated control
system (ICS). -This was in response to the Babcock & Wilcox (B&W) Owners
Group's System Performance Improvement Program, which is a part of the
NRC staff B&W Reassessment. The NRC staff is still reviewing the owners'
group effort.
5.5 Technical Support Assessment
In response to the latest SALP, the licensee agreed with a SALP board
recommendation to reassess the technical support functional area. In
July 1987, the inspector received a briefing on how the licensee was to
proceed with the reassessment. While at the corporate offico, the
inspector obtained a status on the effort with the task group leader.
In accordance with the Institute of Nuclear Power Operations (INP0) ,
guidelines the technical support area includes a number of major '
sub-areas in addition to engineering support (provided by the Technical
Functions Division and the Plant Engineeri.3 Depart 2nt). These additional
areas include: inservice inspection and testing, surveillance, maintenance,
and plant analysis. The initial phase of the reassessment was to survey
.
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selected site and corporate personnel by both a questionnaire and, in
some cases, by actual interview. These responses were completed, being
tabulated, and preliminary analysis is just starting. Issues for follow-up
need to be identified and presented to licensee management for review.
Root cause analysis is expected to follow this review with a definitive
action plan for corrective action to be formulated along with monitoring
to assure effective results.
The inspector noted that an uncertainty existed on when the above-noted
process would be completed, including the initiation of corrective action
and morJ toring for results. It appeared to the inspector that reaconable
progress was made by the licensee on this effort, but the inspector also
noted that the licensee would be working on this reassessment well into
the next SALP period. Accordingly, since this reassessment is a lef t-over
issue from the last SALP to enhance performance, this area is unresolved
pending licensee identification of corrective actions and the initiation
of monitoring for effective results and pending subsequent Region I review
(289/87-19-03).
Also, the licensee's response, dated April 1, 1987, to the last SALP
indicated that Technical Functions (TF) will initiate a program of
sampling reviews to assure that "replacement-in-kind" parts were being
handled properly. As of the end of this inspection period, no real
progress occurred on this item. The licensing department initiated
Licensing Action Item (LAI) No. 87-9122 early this year at the time of
the SALP response (April 1987).
Related to this area and based on discussions with the QA Audits Supervisor,
a QA audit (No. 87-015) is in progress in the plant engineering area; and,
in particular, focus is to occur in the "replacement-in-kind" area.
Accordingly, this area is unresolved pending completion of the TF review
and subsequent NRC Region I review (289/87-19-04).
5.6 Safety Evaluations
The inspector reviewed selected licensee safety evaluations (SE's) for
facility modifications and corporate procedure changes to assess compliance
with 10 CFR 50.59 and related licensee procedure controls to implement
these requirements.
The inspector reviewed selected sections of the following SE's.
Modifications
--
SE No. 115302-022, Revision 0, March 4, 1987, and Revision 1, May 15,
1987, "River Water Pumps Lubrication System, Reclassification from
ITS to NITS"
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ISE No. 0005'33-001, Revision 0, December 29, 1986,. and Revision 1,
i January 30, 1987, "The Addition of Unions to Pressure Instrumentation
Piping on Decay Heat Service Cooler DC-C-2A"
--
SE No. 419628-001, Revision 0, April 10,11987, and Revision 1,
April .13,1987, "Fire Service Water Connection' for the-Instrument
Calibration Facility"
--
~SE No. 418051-001,' Revision 0, October.4, 1986, and Revision 1
April 16, 1987, "Extension of TMI-1 Microwave Perimeter Intrusion
Detection System"
~ ~' ~
--
SE No. 413916-001, Revision 0, July 6,1987 "WDL-V535 Low LTv^el
Interlock"
--
SE No. 412484-001, Revision 0, August 19, 1987, "Installation of
Local Flow Measurement Instrumentation (for Screen House / Control
Building Heating and Ventilation (H&V) System)
--
SE No. 412458-003, Revision 0, August 17,1987,"CIV(Containment
Isolation Valve) Replacement"
--
SE No. 115302-024, Revision 0, March 11, 1987, "TMI-1 250/125 V
d.c. Fuse Changes"
--
SE No. 000231-003, Revision 0, January 23, 1987, "Installation
of Isolation Valve for WDL-7A/8"
--
SE No. 000852-001, Revision 2, July 10,1987, "Isolation of Back-Up
Instrument Air to MS [ Main Steam] and EFW [ Emergency Feedwater]
System Components"
!
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SE No. 412384-013, Revision 0, September 14, 1987,L"Reactor Coolant
Pump Trip Modification"
--
SE No. TI-412525-001, Revision 0, "Two Hour Back-Up Instrument
Air Charging Compressor"
Corporate Procedure Changes
--
SE No. 945100-008, Revision 0, December 24, 1986, and Revision
2-00 to 5000-ADM-7312.01, GPUN Drawings (EP-002)
--
SE No. 084001-S004, Revision 0, June 5, 1987, and Revision 2-00
to (SP-004) 5000-ADM-7335.04, "Test Closecut," and' Revision 2-00 to
(SP-001) 5000-ADM-7335.01, "Startup and Test Program and Test
Requirements"
--
SE No. 945100-001, Revision 2, March 27, 1987, to (EP-027)
1000-ADM-1218.03, "Plant Procedure Review"
. .. . . . --. . . . .. .
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SE No. 945100-002, Revision 2, March 27, 1987, Land Revision 3,
June 16,~1987, "Safety Review Process" (EP-016)
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SE for Revision 3 to11000-ADM-1291.01, September.20, 1987,,"Procedure
for Nuclear Safety and Environmental Impact Review and Approval '
Documents"
Other Documents
--
Computer.Index of SE's Search issued for'1987 (12711tems listed)-for'
modification, procedure changes, and TSCR's
~ ~~
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Technical Data Report'(TOR), ' Revision 0, February 21, 1986, i~nb~ '~~~
Revision 1, December 12, 1986, "Safety-Related Pump Operation
Without Clean Water Bearing Lubrication"
For modifications, the SE's were reasonably thorou'gh and, in some. instances,
quite extensive and detailed. Invariably, the licensee's two-step process
(Form 1 and 2) was fully ~ invoked in that the second form with the -traditional
10 CFR 50.59 unreviewed safety questions were addressed. In accordance
with the licensee's procedural controls for SE's (Technical Functions
Procedure EP-016), the SE narratives were quite detailed in addressing ,
applicable safety grade criteria. The. inspector noted that, in certain
instances, the independent safety reviewers challenged the.SE's and that
resulted in subsequent revisions.
For corporate procedure changes, the inspector noted no significant
discrepancies.
No violations were identified.
5.7 Corporate Inspection Summary
,.
In general, the licensee corporate personnel were adequately working on
or addressing the open issues discussed above. For the areas reviewed,
the licensee programs were. supporting safe operation at TMI-1. A target
-
completion date needs to be identified by the licensee for the. technical
support reassessment. Within the scope of this review, no conditions
adverse to safety or regulatory requirements were identified.
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6. Control Room Environment
6.1 Background / Scope of Review
The-inspector reviewed the conditions that exist in the control room which
affect the conduct of the licensed operators. This review was accomplished
under the guidance given in Region I Temporary Instruction No. RI-87-01,
issued January 16, 1987. The purpose of this review was to assure that
no conditions exist in the control room that would prevent safe operation
of the plant or could allow distractions that would_ prevent full attention
of licensed operators in performing their duties.
~ ~
The inspector reviewed the following documents in accomplishing tiis ,
, review:
--
10 CFR-50.54, Conditions of License;
,
--
Regulatory Guide (RG) 1.114, "Guidance on Being an Operator at
the Controls of a Nuclear Power Plant;"
--
IE Circular 81-02, "Performance of NRC-Licensed Individuals While ,
on Duty;" and,
--
Director, Division of Reactor Projects, NRC internal memorandum
dated January 4, 1985, to resident inspectors.
6.2 Findings / Conclusions ,
The inspector reviewed the following areas related to the control room
environment during this review with the results discussed below. These
, areas are normally reviewed on a daily basis through frequent' routine
tours of the control room and discassions with operators.
6.2.1 Licensed Operator Professionalism
Licensed operators generally conduct their duties with a good. sense of '
pride and discipline at TMI-1. There are no major distractions that
exist in the control room; no radios or televisions are present, nor are
they permitted. The operators have never been observed reading extraneous
material or engaging in activities that were not conducive to safe plant
operations. When questioned by NRC inspectors, the operators gene ally
provide complete and accurate responses. Plant status is aisplayed on a
status board and current plant abnormal conditions are displayed on a
monitor (or CRT) in full and easy view of plant operators. Operators are
responsive to plant annunciators and respond appropriately.
6.2.2 Noise Control
The conduct of shift business that must be accomplished in the control
room; e.g., discussions with the shift foreman for the conduct of
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surveillances and maintenance, is carried out in an area of the control
room that does not affect the operators performance of routine duties.
The noise level in the control room is generally kept to an acceptable
level.
6.2.3 Control Room Access
Access to the control room is controlled by the shift supervisor
(SS) or shift foreman (SF). A physical barrier exists to separate
the "control room proper" (CRP) from the routine conduct of business
area. Operations personnel who normally tour the control room and
} shift personnel usually enter the CRP without permission. Other } personnel; e.g., maintenance, surveillance, quality assurance /
quality control (QA/QC) monitors, are required to request permission
from the SS/SF as noted by a prominently posted sign. This practice
is routinely noted by the inspectors to be observed. The number of
people actually working in the CRP sr conducting official business
is generally kept to minimum levels. During certain major evolutions;
i.e., planned startups and shutdowns, larger numbers of operations and
management personne!, along with oversight personnel such as QA/QC, are
routinely present. These situations are necessary and the inspectors
note that they have not detracted from plant operations control.
6.2.4 Control Room Appearance
The ccntrol room is generally kept clean and orderly. Adequate
space is provided for operators to use procedures / manuals for
routine evolutions. Eating activities are permitted, but the
inspector has not observed that this activity was detrimental to
plant operations. Eating and drinking are not permitted directly
over control room panels. Equipment normally used in the control
room is stored adequately. Overall, there usually is an appearance
of order in the control room.
Also, the licensee continues to make progress in achieving a "black-
board" main annunciator panel (that is, no annunciator normally lighted).
The licensee processed certain design changes to eliminate normally
lighted annunciators. The only one on the main board remaining are two
annunciators indicating a battery ground. The "black-board" concept
enhances operator attention to truly off-normal occurrences.
6.3 Summary
In general, the overall control room environment is quiet, profes-
sional, and businesslike. There are few distractions for the
operators, access is properly controlled, and noise levels are
acceptable. Overall management actions are conducive to the
__ _ . . .. _ . - . -. ~ . . -_ _
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current state of.this environment. Temporary Instruction RI-87-01 is
closed.
7. ' Storage of Transient Equipment in Safety-Related Areas
7.1 Background / Scope of Review
The inspector reviewed the storage of transient equipment in safety-
related areas to assure no adverse impact on safety-related equipment
in case of an industrial accident and/or seismic event. -This-review was-
accomplished under the guidance of Region I Temporary Instruction (TI) '
No. RI-87-03, dated March 5, 1987,.to resident inspectors. Transient
equipment includes: dollies; blocks and tackles; fille'd or unfilled gas
bottles; heavy equipment- (stationary or on rollers); and temporary'of fice ,
spaces; along with housed furniture, cabinets, etc.
The purpose of this review was to:
--
ascertain the status of licensee administrative controls (or other
type of tacility procedures) in the subject area;
--
determine the proper implementation of administrative controls
(or other type of facility procedures) for the subject area;
identify if deficiencies exist independent of whether or not
'
--
facility procedures cover the subject area; and, l
--
where deficiencies exist, assess the licensee corrective action
process with respect to the applicable NRC Information Notice.
The inspector reviewed the following documents:
--
10 CFR 50, Appendix A, Criteria 2 and 4; i
--
NRC IN 80-21, dated May 16, 1981;
--
Maintenance Procedure (MP) 1401-18,'"Equipment Storage Inside
-
Class 1 Buildings;" and,
-
MP 1440-Y-3, "Scaffold Inspection."
Selected areas of the following safety-related buildings were inspected:
reactor building (on previous inspections); auxiliary building; fuel
handling building, intermediate building; diesel generator building; and,
control building.
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_.4,.. ._ _ - , . , . . -,.s.., ,, m _. __% , -.m ,, - . - - -
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7.2 Findings / Conclusions
The resident inspectors have reviewed this area routinely since TMI-1
restart on October 3, 1985. Also, they have more extensively reviewed
the established procedurai controls for adequacy and for proper procedural
adherence during the following inspections: Nos. 50-289/85-19, 85-21, .
_
85-22, and 87-09. -The raore focused reviews have occurred primarily during
the licensee's transition from cold shutdown (outages) to power operations.
These inspections have found the program to be generally adequate with '
only minor implementation discrepancies.
During this inspection, the inspectors noted no conditions adverse to i
safety or regulatory requirements during the routine inspection of
safety-related building spaces. This indicated continued adherence to
established controls. Unrestrained equipment without rollers was located-
and positioned on the floor.at a safe distance so as not to adversely
affect safety-related equipment if it fell over. Equipment on rollers
was restrained with~ wire rope. Scaffolding was rigid and restrained to
the building walls, using wire rope and cement anchors. Loose equipment
on top of platforms or brackets was minimized and was assumed to fall
and, therefore, kept at a safe distance from the safety-related equipment.
Based on a limited review of licensing records, the inspector concluded
that procedural controls in this area were upgraded in response to the
subject NRC Information Notice.
7.3 Transient Equipment Storage Summary
The licensee's procedural controls for the storage of transient equipment
(as defined above) is adequate and these controls are, in general, properly
imp'emented.
8.0 .l censee Event Reports (LER's)
The inspector reviewed the LER's listed below, which were submitted to the
NRC Region I office pursuant to 10 CFR 50.73. Based on a review of these
LER's, the inspector determined that corrective actions discussed in the ;
report were appropriate and that there were no generic issues.
--
LER 87-008, dated October 16, 1987, for an event on September 16,
1987, "Reactor Trip From Turbine Trip Due to High Moisture Separator
Level." The high moisture separator level was found to be caused by
a defective moisture separator drain tank level control valve, which
allowed the moisture separator level to increase to the turbine trip
level. A high level alarm in the drain tank failed to function.
The root cause of this event was equipment malfunction-(level
control valve). Licensee corrective action included improving the
preventive maintenance on the level switches and level control
valves for the moisture separator drain system. Immediate and j
,
long-term planned corrective action for this event appear adequate. ;
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- ,, ,,,mo - - - - - - - -y 6- er - -.- y i,, - - ,.-y-- w m-, ,& s - ,,-~v- e
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The inspector had no other concerns on this~ event, which was
reviewed in NRC Inspection Report No. 50-289/87-17.
--
LER 87-009, dated October 26, 1987, for an event on September 27,
. 1987, "Release with . Liquid Release Monitor (RM-L6) in Defeat' Due to
Personnel Error." An effluent radiation monitor. (RM-L6) . interlock
to assure closure of the tank release discharge valve was inoperable
during a release. The LER describes several personnel errors on the
part of maintenance and operations staffs in assuring the interlock
was enabled. However, procedure enhancements were also planned to
verify and control the proper positioning of the interlock defeat / .
enable switches'in the release sequence. This is a. licensee-identi- ~~ ~ '
fied violation; and, in accordance with the NRC's Enforcemeni ~
Policy, no citation will be issued.
This event was reviewed in NRC Inspection Report No. 50-289/87-17
(Unresolved Item No. 289/87-17-01). By issuance of this LER, the ,
licensee resolved the outstanding issues listed for this. item. By
paragraph 4.3.4, Region I reviewed this item for implications to the
IVP. However, the LER listed procedure enhancements are not specific.
Accordingly, this item (289/87-17-01) remains open pending completion-
of licensee action as stated in LER 87-009 and pending subsequent !
NRC: Region I review.
* ;
9. - Licensee Action on Previous Findings !
9.1 Closed) Unresolved Item 289/84-16-01: Ventilation Balance
Problems in the Auxiliary and Fueling Handling Buildings.
This item was opered due to problems. experienced when airborne radio-
activity releases were made in the auxiliary / fuel handling buildings
(A/FHB) during routine operations. The licensee contracted an outside
engineering firm to test and properly balance the ventilation flows from
the different areas of the A/FHB. With.this balanced condition, any ;
airborne releases would be properly channelled through normal filtered i
and monitored ventilation paths. l
The licensee completed this test and balancing in July of 1987. Several
components in the system, mainly dampers and flow control devices were
found out of adjustment or incapable of functioning properly. These items
,
<
have been repaired. l
The inspectors have routinely toured areas of the A/FHB in recent months l
since completion of the balancing. The inspectors observed negative
pressures existing in areas / cubicles of the auxiliary building where
-
airborne releases have occurred in the past. The inspector reviewed the
"as-found" and final flow data from the contractor's report.
areas were initially significantly out-of-design flow rates. . Several The flows,
in most of the areas, have been adjusted to gene' rally be much closer to
design values.
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The licensee is in the process of formally issuing an internal report on
the problem and may make additional modifications to the ventilation
systems based on their final review.
The inspector concluded that ventilation in the auxiliary and fuel handling
building has been significantly improved over previous conditions. The
inspector had no other safety concerns and this item is closed.
9.2 (Closed) Unresolved Item (289/85-27-08): Verification of
Correct Operating Activities
Previous NRC Inspection Report (IR) Nos. 50-289/82-16 and 83-02 previously
closed TMI Task Action Plan (TAP) Item No. I.C.6, "Verification of Current
Operating Activities," and related open issues. NRC Inspection Report
No. 50-289/85-27 reopened the issue associated with Item No. I.C.6
because of questions on the scope of program application and a somewhat
confusing record on what were licensee commitments in this area.
The licensee's letter of April 29, 1987, in response to IR No. 85-27 was
reviewed in IR No. 86-17 and the letter was found to be unacceptable in
addressing the elements of TAP Item No. I.C.6. The licensee's letter of
June 3, 1987, was in response to NRC concerns addressed in IR No. 86-17.
This latest letter is considered an acceptable response. The licensee's
independent verification program (IVP), as embodied in these two licensee
letters, was reviewed in Section 4 of this report.
The licensee's letter of June 3, 1987, made it clear that any additional
commitments or scope expansion would have to be justified by substantial
safety reasons using the backfit process (10 CFR 50.109).
Also, this letter made two statements with which the inspector did not
agree. First, the licensee stated that: "We feel that our commitments
as well as the scope of the independent verification program are clear,
especially now that the procedures specify verification at the component
level. We are not aware of any inconsistencies." The follow lng is an
example on where commitments are not clear and a minor inconsistency still
existed.
In response to NRC staff questions (Nos. 21 and 22) as documented in
TMI-1 Restart Report, Supplement 1, Part 2, the licensee states:
"Post-maintenance valve lineup of safety-related systems will be compared
to system flow diagrams by two independent operator reviews of the
switching orders prior to removal of safety tags to ensure proper
restoration of the system to operability;" and "Following surveillance
tests or special operations on ESAS and EPd systems, two independent
valve and breaker lineups will be conducted within the boundary of the
system affected by the tests or special operations to provide assurance
that the system is returned to full operational status." Reviewing these
later two licensee statements, the inspector finds for the activities of
making something inoperable and then the restoration to normal by a
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surveillance or a maintenance activity: (1) there are two different
scopes; one statement says safety related and the other statement says
ESAS and EFW; (2) one method is comparison of a lineup by two operators
to flow diagrams; the other method is two independent valve and breaker
lineups within the boundary of the system affected; and, (3) critical
valves (currently defined) were not apparently defined in relation to 10
CFR 100 release criteria in the hearing record.
These confusing items, although minor, remain in AP 1001A, Revision 13,
effective June 26, 1987, "Procedure Review and Approval," Enclosure 4.
"Special Temporary Procedure (STP) Instructions," Line 3, which states:
"The STP must contain a step which requires an independent valve _and/or
switch position verification check be performed within the boundary of
[ESAS and EFW) system (s), component (s), channel (s), etc. affected by the
STP prior to returning [the same] to service." This statement is not
clear and apparently is inconsistent with the critical valve philosophy
of AP 1067. It should also be noted that AP 1001A is not referenced in
the AP 1067 as being embodied in the IVP program. Accordingly, it is not
clear what requirements for IVP the licensee intended to be incorporated
into an STP. A licensee representative agreed to change AP 1001A to make
it consistent with AP 1067.
Secondly, the same licensee letter stated that: "The TMI-1 Independent
Verification Program was intentionally limited to those systems / components
for which the risk and consequences of their misposition could result in
a significant potential for off-site dose. This is consistent with NRC
Information Notice (IN) 84-51, concerning independent verification." The
inspector disagrees on the consistency of NRC IN 84-51 being limited to
significant potential of off-site dose. The critical valve concept in
relation to 10 CFR 100 release is not mentioned in IN 84-52. Further,
the IN implies or recommends that complete safety-related system valve
lineups be independently verified when coming out of a major outage. The
licensee's program falls short of this recommendation. However, no
adverse safety impact is noted as a result.
None of these disagreements affect the resolution of this unresolved
item.
Accordingly, the unresolved item is closed since the licensee provided
the required responses as noted above.
9.3 (Closed) Unresolved Item (289/85-28-01}: Independent Verifica-
tion of Containment Penetration Test-Tee Caps
The licensee's independent verification program (IVP) overall was reviewed
in Section 4. Specific procedure deficiencies identified as a part of
the items were verified to be corrected by this review. Essentially, the
test-tee caps are independently verified to be properly installed in
accordance with the IVP (AP 1067) and as required by applicable operation
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and surveillance procedures, especially those involving containment
integrity. Applicable surveillance records and inspector independent
verification confirmed proper implementation of the IVP.
This item is considered closed.
9.4 (Closed) Unresolved Item (289/86-06-05): Station Vital Battery
Testing.
The adequacy of the licensee's vital battery test program was questioned
during review of the test results after replacement of the "A" vital battery
bank in March 1986. The issue concerned the adequacy of the licensee's
capacity test performed on a refueling outage basis (per Technical
Specification (TS) 4.6.2.d) in lieu of a duty-cycle load test specified
in Institute of Electrical and Electronic Engineers (IEEE) Standard 450 -
1980 (not a licensee commitment). A duty-cycle load test had been
performed by the manufacturer on selected individual battery cells prior
to installation. A periodic duty-cycle load test that attempts to simulate
the actual demand on the battery during worst case loading is not performed
by the licensee once the battery is installed. However, in accordance
with TS 4.6.2.d, a capacity test (two hour constant current discharge per
SP 1303-11.11) is performed during each refueling outage.
The licensee subsequently re-evaluated the acceptability of their battery
test method as satisfactory based on the following considerations.
--
The presently performed two hour constant rate discharge test is
similar to the design basis duty-cycle load profile. The design
basis load profile (amperes versus time) has some higher short
duration loads than the constant rate test / load. The cell sizing is
determined by the amount of energy (ampere- hours) needed to be
expended or discharged.
--
Duty-cycle loads, which exceed the battery's two-hour rating, occur
early in the duty-cycle when the battery is essentially still fully
charged and these loads do not result in battery voltages approaching l
minimum design voltage. Since the duty-cycle load profile is similar '
to a constant current-load profile, the voltage profile recorded for
either type of discharge will also be similar.
--
The above statements are shown to be true by actual test results
from the manufacturer on a worst-case individual cell basis.
--
Cell-to-cell inter-connection resistance could adversely affect the
above-noted test results. The inter-cell and inter-tier connections
on each station battery cell are measured. Inter-cell and inter-tier .
connections are checked at each plant refueling period. Connection l
resistance measurements must be with in 20 percent of baseline data,
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- The above evaluation was considered adequate to resolve the. inspector's
concerns about the adequacy of the licensee's battery test program.and
this item.is considered closed.
9.5 (0 pen) Unresolved Item (289/86-19-01: Review Procedures
Compliance Task Group Corrective Actions..
.The. inspector reviewed the status of the long-term corrective actions
which were recommended by the Procedures Compliance Task Group (PCTG).
- The PCTG had formulated seven short-term and seven long-term corrective
actions.to resolve past procedure compliance problems. -Short-term
corrective actions have been completed as previously discussed in NRC
Inspection Report No. 50-289/86-19. -These short-term actions were .
generally the issuance of internal memoranda and reminding individuals of
their. responsibility to adhere to procedures. Most long-term corrective
actions are still pending licensee evaluation and implementation. .,
Formal procedure guidelines to implement a consistent policy on procedure I
adherence has been formulated and is awaiting final approval. The ;
"procedure owner" program is a part of this-administrative procedure
change (1000-ADM-1218.01).
Another initiative,' development of procedure writing guidelines and an
associated training program is awaiting funding. Other initiatives such- '
as the procedure improvement "team" concept, developing faster change
mechanisms and developing "target" levels for QA deficiencies are still
in the evaluation process.
The inspector concluded that reasonable progress has been made in this
area. The inspectors will review these initiatives as they are completed ,
or resolved and become a part of the licensee procedure control program.
9.6 (0 pen) Unresolved (289/87-17-01): Inoperable Radiation i
Effluent Monitor Interlock (LER 87-009) !
, See section 8 for details.
9.7 (Closed) Region I Temporary Instruction (No. 289/87-TI-01): 1
Control Room Environment. !
&
See section 6 for details.
;
9.8 (Closed) Region I Temporary Instruction (No. 289/87-TI-03): l
Storage of Transient Equipment in Safety-Related Areas, j
. See section 7 for details. !
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10. Exit Interview
The inspectors discussed the inspection scope and findings with
licensee management at interim interviews on October 16, 1987
(corporate inspection), and on October 20,1987 (Independent Verifi-
cation Program), and a final exit interview conducted November 2,
1987. Senior Itcensee personnel attending the final exit meeting
included the following:
G. Broughton, Operations and Maintenance Director, TMI-1 ,
J. Colitz, Plant Engineering Director, TMI-1
K. Harkless, Safety Review Engineer, TMI-1 ___
H. Hukill, Director, TMI-1
C. Incorvati, TM1-1 Audit Manager
M. Nelson, Manager, Nuclear Safety, TMI-1
H. Shipman, Operations Engineer, TMI-1
D. Shovlin, Plant Material Director
C. Smyth, TMI-1 Licensing Manager ,
M. Snyder, Preventive Maintenance Director
The inspection results as discussed at the meeting are summarized in
the cover page of the inspection report. Licensee representatives
did not indicate that any of the subjects discussed contained
proprietary or safeguards information,
t
Unresolved Items are matters about which more information is re-
quired in order to ascertain whether they are acceptable,
violations, or deviations. Unresolved items discussed during the
exit meeting are addressed in Sections 5 and 9.
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ATTACHMENT 1
NRC INSPECTION REPORT
NO. 50-289/87-19
ACTIVITIES REVIEWED
Plant Operations
Control room operations during regular and back shift hours, including
frequent observation of activities in progress and periodic reviews of
selected sections of the shift foreman's log and control room operator's
log and selected sections of other control room daily logs
Areas outside the control room
Selected licensee planning meetings
Shift Turnover on October 28, 1987
Emergency Feedwater Standby Status as of October 29, 1987
Emergency Diesel Generator Standby Status as of October 7, 1987
Control Room Environment
During this inspection period, the inspectors conducted direct inspec-
tions during the following back shif t hours.
Date Time
10/4-5/87 11:30 p.m. - 1:00 a.m.
10/10/87 8:30 a.m. - 10:30 a.m.
10/11/87 10:00 a.m. - 12:00 Noon
10/28/87 6:00 a.m. -
7:00 a.m.
10/30/87 5:30 a.m. - 6:30 a.m.
10/31/87 8:00 a.m. - 9:30 a.m.
Maintenance
Reactor Protection System Breaker Replacement (PM E-36) on various dates
throughout the inspection period
Storage of Transient Equipment in Safety-Related Areas
Surveillance
Reactor Projection System Surveillance (SP 1303-4.1) at various dates
throughout the inspection period
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Attachment 1 -2-
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Differential Pressure Switch Calibration, NR-DPS-138 (per IC-15) on
October 15, 1987
Reactor Coolant System Leak Rate (SP 1301-1) on November 1,1987
Reactor Coolant System (RCS) Leak Rate
The inspector selectively reviewed RCS leak rate data for the past
inspection period. The inspector independently calculated certain RCS
leak rate data reviewed using licensee input data and a generic NRC
"BASIC" computer program "RCSLK9" as specified in NUREG 1107. Licensee
(L) and NRC (N) data are 'abulated below. ____
TABLE
RCS LEAK RATE DATA
All Values GPM
DATE/ TIME (NUREG 1107) CORRECTED
DURATION L
g Ng Ng N
U 'U
10/5/87 0.6416 0.64 -0.25 -0.15 -0.1440
08:27:13
2 Hours
10/8/87 1.3396 1.34 -0.13 -0.03 -0.0217
00:30:13
2 Hours
10/8/87 1.2622 1.26 -0.01 0.09 0.0933
07:42:26
2 Hours
10/8/87 1.6475 1.64 -0.10 0.00 0.0077
16:33:37
2 Hours
10/14/87 0.5019 0.50 -0.13 -0.03 -0.0210
00:37:21
2 Hours
10/22/87 0.0679 0.07 -0.42 -0.32 -0.0326
15:49:47
2 Hours
10/26/87 0.7946 0.79 -0.01 U.us 0.0934
16:34:13
2 Hours
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Attachment 1 -3-
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DATE/ TIME (NUREG 1107) CORRECTED
OURATION L N N N
G G U U 'U
10/28/87 0.8532 0 85 -0.09 0.01 0.0159
16:54:01
2 Hours
10/31/87 0.3960 0.40 -0.02 0.00 0.0031
07:08:30
2 Hours
.
11/1/87 1.1851 1.18 -0.09 0.01 0.209
16:13:41
2 Hours
_ _ _ _
)
G = Identified gross leakage U = Unidentified leakage
L = Licensee calculated N - NRC calculated
Columns 2 and 3, 5 and 6 correlate 1 0.2 gpm in accordance with NUREG
, 1107. (N is corrected by adding 0.1044 gpm to the NUREG 1107 N due to i
u u
, total purge flow through the No. 3 seal from RCP's.
}}