IR 05000282/1993019
| ML20058F253 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 11/29/1993 |
| From: | Kobetz T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20058F240 | List: |
| References | |
| 50-282-93-19, 50-306-93-19, NUDOCS 9312080047 | |
| Download: ML20058F253 (33) | |
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION 111
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Reports No. 50-282/93019(DRP); 50-306/93019(DRP)
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Docket Nos. 50-282; 50-306 License Nos. DPR-42; DDR-60 l
Licensee: Northern States Power Company
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414 Nicollet Mall Minneapolis. MN 55401
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Facility Name:
Prairie Island Nuclear Generating Plant t
Inspection At:
Prairie Island Site, Red Wing, MN Inspection Conducted: September 14 through November 8, 1993 i
Inspectors:
M. L. Dapas R. L. Bywater W. D. Stearr.s C. N. Orsini
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Approved
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i so Acting Chief
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Re tor Projects Section 2A Dat'e
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Inspection Summarv
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Inspection on September 14 through November 8, 1993
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(Reports No. 50-282/93019(DRP); 50-306/93019(DRP))
Areas Inspected: Routine unannounced inspection by resident and regional inspectors of plant operational safety including onsite followup of events,
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maintenance, surveillance, engineering and technical support, security,
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licensee followup on previously identified items, licensee event report i
followup, and Quality Assurance program implementation.
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93120B0047 931129 FDH ADOCK 05000282 O
PDR l
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i Executive Summarv
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Enforcement l
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Three non-cited violations of NRC requirements, one unresolved item, and three j
inspection followup items were -identified in the areas inspected.
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Operations-l
One non-cited violation was identified involving the inadvertent entry into a l
condition of minimum defense-in-depth with respect to the critical safety-
function of containment closure associated with the licensee's shutdown safety
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assessment program (paragraph 1.c).
j Maintenance and Surveillance
. One non-cited violation was identified involving an inoperable safety-related
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snubber (paragraph 6.c), and one inspection followup item was identified regarding the quality classification of charging pumps and associated motors (paragraph 2.a).
One new strength was identified regarding emergency diesel
generator and integrated safety injection system testing (paragraph 3.d).
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l Enaineerina and Technical Support
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t One non-cited violation was identified involving inadequate design control of
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steam exclusion area boundaries (paragraph 5.c).
However, a strength was
identified regarding licensee efforts to reconstruct design basis information and evaluate the impact of current modifications on steam exclusion area
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boundaries.
One inspection followup item was identified involving reactor
protection system NBFD relay failures (paragraph 5.a).
One weakness was
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identified regarding the licensee's failure to perform an adequate review to
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determine if test acceptance criteria remained valid for a different' set of
turbine-driven auxiliary feedwater pump (TDAFW) surveillance test initial conditions.
This resulted in the use of over one-half of the allowed cutage
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time for the TDAFW pump to verify that the pump had performed per design (paragraph 3.e).
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Plant Support
One inspection followup item was identified in the area of Security involving i
the licensee's investigation into a building window damaged by a bullet
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(paragraph 7).
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I DETAILS
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1.
Operational Safety Verification '(71707. 93702)
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The inspectors observed control room operations, reviewed applicable i
logs, conducted discussions with control-room operators, and observed
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shift turnovers.
The inspectors verified operability of selected j
emergency systems, reviewed equipment control records, verified the l
proper return to service of affected components, conducted tours of the auxiliary building, turbine building and external areas of the plant to l
observe plant equipment conditions, including potential fire hazards,
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and to verify that maintenance work requests had been initiated for.
j equipment in need of repairs.
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General l
Unit 1 operated at full power throughout the inspection period.
i Unit 2 operated at full power until October 9, 1993, when l
coastdown for the. refueling outage was initiated.
Unit 2 was j
taken off line on October 28 for a refueling and maintenance
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outage scheduled to last approximately 44 days. The inspectors observed activities in the control room on October 28-29 as the licensee shut down Unit 2 from approximately 15 percent power to
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hot shutdown (subtritical) conditions and conducted turbine i
overspeed surveillance testing. The inspectors noted good
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communications and self-checking practices among the control room i
operators and outplant personnel.
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b.
Bus 16 Load Seouencer Failure.
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At 12:31 a.m. on October 5,1993, the licensee identified that the-l programmable logic controller (PLC). indicator light on.the load
sequencer for Unit 1 4160 Volt safeguards bus No. 16 was a
continuously off. The licensee exchanged light bulbs, however the I
light remained out. This event' was similar to the load sequencer i
failure for safeguards bus No. 15 that occurred on September 5, 1993, (refer to NRC Inspection Report 50-282/93014; i
50-306/93014(DRP)), except that in the bus No. 15 case, the PLC
status light failed to a condition of continuously on.
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discovery of the load sequencer problem, the licensee entered an
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abnormal operating procedure, placed the selector switch for
.i emergency diesel generator (EDG) D2 in pullout, and entered a
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7-day limiting condition for operation action statement for having D2 EDG inoperable. The bus No. 16 load sequencer was repaired and
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returned to service at 5:02 a.m. on October 5, and D2 EDG was
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subsequently declared operable. The inspectors will follow-up on
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this load sequencer failure in conjunction with their review of l
the previously identified inspection followup item-l 50-282/93014-01; 50-306/93014-01(DRP).
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c.
Inadvertent Entry into a Shutdown Safety Assessment Orance Condition
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I The licensee implemented a shutdown safety assessment (SSA)
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methodology to minimize shutdown risk during its current Unit 2
refueling outage.
The SSA process is implemented by the j
licensee's procedure SAWI 3.15.4, " Planned Outage Management," and
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has been discussed in NRC Inspection Report No. 50-282/92201; 50
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l 306/92201. The inspectors have observed that, in general, the SSA i
and the outage management processes have been used effectively by l
the licensee in its scheduling and performance of work to minimize
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shutdown risk.
In one instance during this inspection period, however, the licensee identified that it had inadvertently entered an " orange" condition in the SSA key safety function of.
containment closure.
By definition, an orange condition indicates
that the minimum redundant equipment is available to support the l
key safety function.
Activities during an outage are scheduled to j
avoid any entry into an orange condition unless it is approved by the operations committee (OC) and approved contingency plan
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procedures are in place.
If an unplanned orange condition'in a
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key safety function is identified, the licensee is required per
its procedures to restore equipment availability to obtain a green
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or yellow condition, or institt" an OC-approved contingency plan.
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On November 3, 1993, the licensee initiated actions per Work
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Request No. U4912-SG-Q to remove flanges per procedure 2D61.1,
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" Unit 2 Installation of Steam Generator Services Cables at
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Containment Penetrations," from two, 2-inch pipes within I
containment penetration 42E. Approval was granted by-the shift supervisor to start work; however, the procedure for removal of the flanges was written such that a direct path from containment to the Auxiliary Building would be created before accessory, j
compressed air pipes (with valves) were installed for steam j
generator sludge lancing. The procedure contained prerequisites j
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that Unit 2 be in cold shutdown and that refueling integrity wasL
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not required.
These conditions were satisfied; however, per the SSA checklist for containment integrity, the SSA condition is i
orange when penetration 42E is open if the reactor coolant system
(RCS) is not intact or the' refueling. cavity is not flooded greater j
than 20 feet. On November 3, when penetration 42E was opened, the t
RCS was not intact and the refueling cavity was not flooded.
l Therefore, an orange condition was inadvertently entered.
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A member of the licensee's staff observed the open penetration while on a tour of the Auxiliary Building on November 3, and
immediately initiated actions to have the penetration closed.
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This restored the containment closure condition to yellow. On l
November 4, the licensee revised procedure 2D61.1 to explicitly i
specify that as each flange was removed, it be replaced with the j
accessory compressed air pipe, and the. associated valve closed.
This process ensured'that integrity of the penetration was
'j maintained. The safety significance of the event was low because j
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L of the small size of the penetration and the short amount of time
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that it was open. However, the. inspectors discussed the event
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with the licensee and expressed a concern that the work planning,
scheduling, and approval process should have been able to prevent-l this containment penetration from being opened at an inappropriate
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time. Additionally, the inspectors expressed a concern that the responsible individual for a particular work request should also -
be cognizant of the timing of the work as it may affect the SSA.
i The licensee initiated a number of corrective actions' for this
event.
These included performing a review of all catage work l
requests to identify those that affected containment boundaries,
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ensuring that these work requests all had schedule " activity
numbers" associated with them so they would appear on the four day l
~i outage schedule, and reviewing the identified work requests to ensure that procedural instructions with respect to containment j
boundary control were correct.
The licensee also informed the
inspectors that it would initiate an Error Reduction Task Force l
review of this event. The inspectors concluded that the l
licensee's corrective actions were sufficient to prevent i
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recurrence.
Part 50 of Title 10 of the Cods
.f Federal Regulations (10 CFR 50), Appendix B, Criterion V, as implemented _by Section 7.0 of the j
Northern States Power Company Operational Quality Assurance Plan,
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requires that activities affecting quality shall be prescribed by
.l documented instructions, procedures, or drawings,-of a type
appropriate to the circumstances and shall be accomplished in
.l accordance with those instructions, procedures, or drawings.
Administrative Work Instruction 5AWI 3.15.4' specifies that the
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duty shift supervisor shall ensure work request packages will not j
result in an unplanned entry into an orange condition in any of.
the key safety functions, prior to approving them for work.
Contrary to the above, on November 3, 1993, Work Request l
No. U4912-SG-Q was approved by the shift supervisor for the start I
of work, and activities conducted per this work procedure resulted in entry into an unplanned orange condition for containment
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integrity. As described above, the. licensee's actions appeared to be in violation of NRC requirements.
However, the violation is not being cited because the criteria specified in Section VII.B.2
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of the " General Statement of Policy and Procedure for NRC i
Enforcement Actions," (Enforcement Policy, 10 CFR Part 2,-Appendix C), were satisfied.
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d.
Identification of Leakina Pressurizer Power Operated Relief Valve (PORV)
The inspectors reviewed the events surrounding the licensee's identification of seat leakage in a Unit 1 PORV.
At 2:41 p.m. on September 17, 1993, control room operators received a pressurizer PORY high temperature alarm on the emergency response computer system (ERCS) and initiated actions to quantify the leak rate and
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1; continuously monitor relevant parameters. Within an' hour, a
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control board annunciator high temperature alarm was received as
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well.
Indications were that there was a small amount of seat l
leakage from one of the two PORVs. A historical plot of PORV outlet temperature from ERCS indicated that temperature had been
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slowly increasing over the previous 10 days. Technical l
Specification (TS) 3.1.A.2 c.l.b.1 requires that with one or both
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PORV(s) inoperable due to excessive seat leakage, within _one hour either restore the PORV(s) to operable status or close the associated block valve (s) with power. maintained to the block l
l valve (s).
This TS was recently added by a license amendment dat.ed
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June 21, 1993, and is identical to the Westinghouse Standardized
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Technical Specifications.
The identity of the PORV experiencing seat leakage was confirmed as CV-31232 and its associated block.
valve, MV-32196, was closed at 10:09 p.m. on September 18, 1993.
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The inspectors discussed with the licensee the methodology
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employed by the control room operators in determining which PORV
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had seat leakage, the quality of the control room log entries, and
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the licensee's interpretation of when PORV seat leakage is
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considered excessive.
Standardized Technical Specifications
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contain a valve size-dependent definition of what constitutes
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excessive seat leakage. The Prairie Island Technical
.j Specifications do not contain a similar. definition, and this
resulted in some confusion as to whether the PORV was inoperable i
because the amount of seat leakage was very low (less than 0.1
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gpm). Although the PORV was isolated by closing its associated block valve (power to the block valve was maintained)' because it had been experiencing seat leakage, the licensee concluded that
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The inspectors concluded that the -
l licensee's actio.ns in identifying and isolating the PORV were
appropriate and conservative.
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Unit 2 Control Room A-Panel Modification i
The inspectors reviewed portions of the licensee's modification of the Unit 2, main control board A panel which is part of the i
licensee's NRC commitments for control room design review and
improvement for human factors considerations. The inspectors observed portions of work involving the set up of temporary
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l control panels and the transfer of equipment controls from the
"old" A panel to the temporary panels.
The inspectors observed
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good communications between work groups and concern for potential,
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i operational impact that performance of the modification might have l
on each unit.
l One non-cited violation was identified. No deviations, unresolved
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items, or inspection followup items were identified.
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2.
Maintenance Observation (71707. 37700. 627031-l i'
Routine preventive and corrective maintenance activities were observed to ascertain that they were conducted in accordance with approved
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procedures, regulatory guides, industry _ codes or standards, and in
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conformance with Technical Specifications.
The following items were i
considered during this review:. adherence to Limiting Conditions for
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Operation while components or systems were removed from service, approvals were obtained prior to initiating the work, activities were
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accomplished using approved procedures and were inspected as applicable, functional testing and/or calibrations were performed prior to. returning components or systems to service, quality control records were j
maintained, activities were accomplished by qualified personnel,
radiological controls were implemented, and fire prevention controls
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weie implemented.
Portions of the following maintenance activities were observed or l
reviewed during the inspection period:
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a.
Quality classification of charging pumps and associated motors
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The inspectors reviewed a surveillance report (SR-PI-93-40).
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conducted by the licensee's onsite quality assurance (QA)
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organization which was issued on September 22, 1993. The-l surveillance report discusses the quality classification of the-
charging pumps and associated motors. The inspectors also
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reviewed Corporate Nuclear Administrative Control Directive
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NIACD 1.3, Revision 6, which defines those structures, systems,
and components (SSCs) controlled-by the Operational-_ Quality
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Assurance Plan (0QAP).
NIACD 1.3 specifies that the 0QAP shall be
used to identify safety-related SSCs subject to Appendix B of
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This list is. referred to as the Q-List.
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NIACD 1.3 further states that sub-structures, subsystems, and.
component parts of Q-Listed items shall be safety related unless
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reviewed by knowledgeable personnel and determined to be non
safety-related, and that these reviews shall be documented.
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l accordance with NIACD 1.3, the plant manager may further identify i
safety-related versus non safety-related substructures, subsystems
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and component parts of Q-Listed items by means of Q-List
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Extensions. The inspectors reviewed the Q-List in the 0QAP.
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list is categorized by major system headings.
Under the Chemical i
and Volume Control System (CVCS) heading, the subcategory
" Positive displacement charging pump and motor" is listed.
On December 5,1988, the Q-List Committee approved j
reclassification of the CVCS charging pumps from QA-1 functional
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to QA-1 pressure retaining based on a supporting safety. evaluation
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(SE 251).
The Q-List Committee meeting minutes for December 5, l
1988, state, "PSQA and Licensing will submit a change to the Operational QA Plan to remove the' Charging Pump Motor from the Q-List." These~ minutes also contain'a note which states,
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" Charging Pump Motor and Drive spare parts will be ordered
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QA-Related, but not Safety Related, until the NRC approves QA Plan t
Revision. At that point, all non-pressure retaining spare parts
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may be ordered QA-Ill Non-Safety Related."
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Based on the December 5, Q-List Committee meeting, the charging pump motors, drive systems, and non-pressure retaining components
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were downgraded from safety-related to non' safety-related status
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on the Q-List Extension. No change to the.00AP was submitted to j
the NRC to have the charging pump and motor removed from the i
Q-List.
Surveillance report SR-PI-93-40 states that Nuclear-Support Services did not consider the justification in SE 251 for.
downgrading the quality classification of the charging pumps,
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sufficient to submit a corresponding 0QAP change request to the
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NRC. The subject surveillance report also stated-that an
investigation of past work orders from 1985 to 1992 for charging j
pump repair work indicated that non-safety related parts had been used in the variable-drive system for the charging pump motors.
The licensee initiated a nonconforming activity report (NAR)_to l
address the surveillance finding that the existing Q-List and
Q-List Extension are not in agreement regarding the safety l
classification of the CVCS charging pumps and related motors.
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i inspectors reviewed the response to the NAR and discussed the charging pump issue with the licensee.
The NAR response states
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that the design basis safety function of the charging pumps and motors is to maintain the reactor coolant system pressure boundary, which is a passive safety function.
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safety classification of the charging pumps as pressure retaining l
is appropriate. The NAR response further states that the l
classification of the positive displacement charging pump and
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motor as safety related functional based on reactivity control was
overly conservative.
In addition, since the charging pump motor-
breaker must be capable of isolating the motor from its electrical i
source (480 Volt bus) during a fault, the classification of the j
motor breaker as QA-1, safety-related on the Q-List Extension is
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appropriate.
The licensee discussed the quality classification nonconformance
issue at a meeting on October 20, 1993.
At this meeting, the
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licensee concluded that from a technical engineering perspective, i
the CVCS charging pump and motor should be classified as " pressure
retaining" because the charging pumps are not required for mitigating any accidents.
In addition, the nonconformance is due to a discrepancy in the 00AP Q-List versus design basis l
functionality.~ The licensee concluded that the quality of the charging pumps and associated motors had not been compromised because of work performed.
The licensee stated that No.13 J
charging pump motor had been replaced in July 1993 with a QA-1
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spare motor (refer to NRC Inspection Report 50-282/93014; j
50-306/93014(DRP)).
The licensee stated that a safety evaluation is being written, using SE 251 as input, to document the design basis for the charging pumps and related motors, and to provide the justification for an 00AP revision. This is considered an inspection followup item (50-282/93019-01; 50-306/93019-01(DRP))
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pending a review of the subject safety evaluation and pending a
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review of.the work history for. No. 11, 12, 21, 22, and 23 charging r, umps to determine if, and to what extent, non-safety related parts were used for these pumps.
The inspectors 'will also -
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determine the safety significance of using non-safety related
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NRC L
Inspection Report 50-282/93002; 50-306/93002(DRP) discusses i
related quality classification issues involving the Q-List-Extension.
b.
Preventive Maintenance of D2 Emergency Diesel Generator
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Disassembly and Reassembly of No. 22 Turbine-Driven Auxiliary
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Feedwater Pump Steam Supply Valves
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One inspection followup item was identified.
No violations, deviations, or unresolved items were identified.
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Surveillance (37700. 61726. 71707)
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The inspectors reviewed Technical Specification required surveillance testing as described below, and verified that testing was ~ performed in accordance with adequate procedures, test instrumentation was i
calibrated, and Limiting Conditions for Operation were met. The
inspectors further verified that the removal and restoration of-affected
I components were properly accomplished, test results conformed with
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Technical Specifications and procedure requirements,. test results were-l reviewed by personnel other than the individual directing the test, and
.i deficiencies identified during the testing were properly reviewed.and i
resolved by appropriate management personnel, Portions of the following test activities were observed or reviewed:
a.
SP 1028, " Radiation Monitoring Monthly Source Test" j
On October 28, 1993, the licensee informed the. inspectors that l
during performance of SP 1028, an unintended automatic start of the 121 spent fuel special ventilation system (SFSVS) was-initiated during the source test for 122 special ventilation system.
The inspectors discussed with the. licensee the potential
_i for reportability of this event as an actuation of an engineered safety feature (ESF). The event occurred when a radiation protection specialist depressed an instrument rack pushbutton with 1;
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the intent to disable the radiation monitor associated with 121 j
SFSVS.
However, the pushbutton did not remain in its engaged l
position to disable the radiation monitor from initiating a -start
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signal. When 122 SFSVS'was tested by placing a radiation. source
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in the vicinity of its associated radiation monitor, the monitor for 1213FSVS also sensed the presence of the source and both trains of.SFSVS started. Upon review, the licensee noted that the
radiation monitor disable pushbutton did not remain' fully depressed.
Therefore, both trains of SFSVS automatically started
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when the source was in the vicinity of the radiation monitors.
The licensee reperformed the test satisfactorily, self-checking the status of the pushbuttons before bringing the source near the monitor.
The licensee stated it would revise the procedure to verify the status of radiation monitors associated with safeguards ventilation systems before the monitors are source-tested.
The licensee concluded that this was an invalid actuation of an exempted ESF per 10 CFR 50.72 and therefore was not reportable.
The inspectors concluded that the licensee's determination was correct and that the procedural change and improved self-checking would help prevent another unintentional autostart of an ESF.
b.
SP 1544, " Containment At Power Inspection Unit 1" SP 2035A, " Reactor Protection Logic Test At Power" c.
On October 14, 1993, the inspectors observed the licensee perform an inspection and conduct thermography of Unit 2 reactor protection system (RPS) relays.
On October 21, 1993, the inspectors observed the licensee perform a pre-surveillance test inspection of the Unit 2 RPS relay racks (refer to paragraph 5.a for a detailed discussion of NBFD relay problems).
d.
D5/D6 Qualification Testing and SP 2083, " Unit 2 Response to the Safeguards Signal Test (Integrated Si Test)"
A previous NRC Inspection Report (50-282/92024; 50-306/92024(DRP)), discussed preoperational testing and qualification issues associated with the DS and D6 emergency diesel generators (EDGs).
The licensee's preoperational testing and qualification program resulted in the D5 and D6 EDGs being qualified to a load equivalent to 75 percent of rated load.
In order to qualify the D5 and D6 EDGs for full load, the licensee committed to the NRC to perform the 24-hour full-load-carrying capability (endurance and margin) tests during the next 18 month l
Technical Specification-required surveillance tests.
The licensee
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planned on conducting these tests during the fall 1993, Unit 2 refueling outage.
The inspectors discussed with the licensee its preparations for these tests and reviewed the test procedure to ensure it adequately implemented the licensee's qualification plan commitments.
The licensee discussed with the inspectors and staff of the HRC Office of Nuclear Reactor Regulation the acceptability of operating within bandwidths for power factor and load specified in NRC Rcgulatory Guide (RG) 1.9, Revision 3.
The NRC concluded that this was an acceptable method of meeting the licensee's previous commitment to RG 1.108, Revision 1.
The tests for the D5 and D6 EDGs included a demonstration of full-load carrying capability, of which 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> were at a load equal to 105 to 110 percent of the continuous rating of the EDG, and 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> were at a load equal to 90 to 100 percent of its continuous rating.
The inspectors observed portions of the D5
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test on October 29-30 and portions of.the D6 test on ' October j
30-31. Test results were satisfactory and the inspectors
concluded that the licensee's test commitment to achieve full-load j
EDG qualification had been completed.
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Prior to the performance of the D5 24-hour load test, the licensee.
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identified an anomaly in the DS engine room safeguards ventilation
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damper configuration.
The recirrulation damper, which normally
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response to temperature controller demand signals, was found in-l the closed position. The expected position of.this damper during
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cold weather 'is open with the fresh air damper closed. ' The
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licensee initiated action to fail the fresh air damper in the open
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position, which would ensure that adequate engine room ventilation
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would be provided during engine operation.
The inspectors
discussed the impact of the as-found condition with respect to_the minimum room temperature required for_EDG operability.
The EDGs
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are qualified to be capable of starting at a minimum room-l temperature of 50 degrees Fahrenheit with the lube. oil and jacket i
water keep-warm heaters inoperable.
The licensee initiated a work l
request'to repair the recirculation damper.
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The inspectors also observed the full-load rejection and hot
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restart te.C s for D5 and D6.
These tests were performed immediately prior to the performance of the integrated 51 tests
and their results were satisfactory. A discussion of the j
performance of the integrated Si tests with respect to testing the
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r capability of the undervoltage (UV) logic circuitry to
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automatically de-energize a safeguards bus in response to a UV
condition is included in NRC Inspection Reports 50-282/92015; 50-
306/92015(DRP), and 50-282/92029; 50-306/92029(DRP). The
_
i inspectors observed the performance of this test on October 30,
!
which tested the UV logic circuitry for 4160 V safeguards bus No.
l 25, and observed the performance of this test on October 31, which
tested the UV logic circuitry for 4160 V safeguards bus No. 26 l
tested.
The results of both tests were satisfactory. The j
inspectors considered the performance of the licensee's staff in
!
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the planning and execution of these tests to be excellent.
'
e.
SP 2103, "22 Turbine-Driven Auxiliary Feedwater (TDAFW) Pump Once l
,
Every Refueling Shutdown"
.i i
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j This surveillance procedure (SP) includes a Technical-
_
l Specification-required, full flow capacity test and an inservice testing program-required performance test of the No. 22 TDAFW j
pump. The licensee performed this SP and entered a 72-hour
.
Technical Specification limiting condition for operatinn' action I
statement on October 25, 1993.
Test results were unacceptable for l
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pump discharge p.ressure and flow per acceptance criteria specified.
I in the SP. As. pump discharge flow was increased above 200 gpm,-
-j pump speed decreased below the range specified in the SP. When
the test was performed again and similar results were obtained,
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the licensee initiated a priority work request to diagnose and repair a suspected problem with the steam admission governor valve
!
for the pump turbine.
The licensee disassembled the governor
!
valve but did not observe any anomalies in valve stroke length,
'
plug condition, or seat condition. The licensee then considered that a strainer in the steam supply trip / throttle valve might have I
been fouled, thereby reducing steam supply pressure at the turbine
,
inlet.
The trip / throttle valve was disassembled and the strainer
was found to be clean of debris. The licensee then initiated a
,
review of design basis information for TDAFW pump performance as'a
function of steam turbine inlet pressure.
The licensee has
historically performed SP 2103 at lower power levels during the
- l unit shutdown when steam supply pressure to the. pump turbine is at its highest values (greater than 900 psig).
The_ licensee now schedules this SP to be performed before power reduction begins.
.
for a refueling outage. This would result in the subject SP being j
performed when steam pressure to the TDAFW pump is approximately i
700 psig.
j In reviewing pump and turbine design basis data, the licensee
!
determined the expected values for the pump performance parameters
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of discharge pressure and flow and pump speed for a lower steam-j inlet pressure to the turbine, which is the condition present when
the SP is performed with the unit at higher power levels.
The SP j
requires that steam pressure be greater than 695 psig as a j
prerequisite to performing the surveillance. Steam pressure was
greater than this when the surveillance was performed on October j
25.
However, the licensee's design basis review indicated that at.
i higher pump flow rates, given the initial condition of lower steam l
inlet pressure than the pressure at which the test has
.
historically been conducted, pump speed is expected to'be lower.
!
The licensee completed restoration of No. 22 TDAFW pump and
'i performed SP 2103 again on October 27, 1993. Results of the test i
were consistent with the results obtained before the steam supply
'
valves were disassembled, and the results were consistent with the predicted results for initial conditions of lower steam inlet pressure.
Based upon these results, the licensee declared the
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i pump operable.
The pump had been declared inoperable.for approximately 48% hours. The licensee's onsite' safety review j
committee reviewed the result.s' of the SP-ard concluded that the
,
pump performed as designed, given the lower steam inlet pressure j
to the turbine.
The licensee initiated a nonconforming activity report (NAR) for.
.I this event, indicating that design basis information addressing the effects that lower steam inlet pressure would have on test
results, was inadequately incorporated into the SP, and recommending that procedures, technical manuals, and design basis documentation be updated to address the observed results. The inspectors concluded that it was appropriate for the licensee to
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i initiate an NAR for this event.
The inspectors also noted that
the licensee did not perform an adequate review to determine if
test acceptance criteria remained valid for a different set of
surveillance test initial conditions.
This resulted in the use of j
over one-half of the allowed outage time for the TDAfW pump to
identify that the pump had. performed per design.
j
f.
SP 2544, " Containment At Power Inspection Unit 2"
.
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No violations, deviations, unresolved items, or inspection followup
[
items were identified.
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4.
Duality Assurance Proaram Review and Evalua_ti_on of Licenseg
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Self-Assessment Capability (35701. 40702. 40704. 40500)
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The inspectors observed in-process activities, conducted interviews with selected personnel and reviewed program documentation to determine
!
whether the licensee has develuped and implemented a quality assurance
!
(QA) program relating -to audits of activities that is in conformance-with Technical Specifications, regulatory requirements, commitments in
..'
the Final Safety Analysis Report, and industry guides and standards.
'
The inspectors also evaluated the effectiveness of both the corporate i
based QA audit organization and the onsite QA organization relative to-
' i the licensee's self-assessment function.
Specifically, the inspectors evaluated whether the QA organization contributes to the prevention of j
problems by monitoring and evaluating plant performance, providing assessments and findings, and communicating and following up on
,
'
corrective action recommendations.
The Nuclear Quality Department (NQD), formerly called Power Supply Quality Assurance, is the licensee's QA organization and is responsible for implementing the operational QA program as described in the
)
Operational Quality Assurance Plan (00AP) contained in Appendix C to the
!
Updated Safety Analysis Report (USAR)'.
This program governs plant
-
operational and support activities at both Monticello and Prairie
Island.
The Director Quality Assurance'is the program director and
)
reports to the Vice President Nuclear Generation. The Manager Nuclear Operations Quality Assurance (N0QA) is responsible for the QA audit function and reports to the Director Quality Assurance at the corporate
j office.
The corporate QA audit group contains eight full time auditors i
(currently onc vacancy) reporting to one supervisor, who in turn reports i
to the Manager N0QA.
l Responsibility for the administration of operational QA program-requirements at the site is assigned to the Superintendent. Site. Quality.
This includes implementation of both the site quality control inspection program and the performance based, QA surveillance program.
Until very recently, the Superintendent Site Quality-at Prairie Island reported
.
directly to the Director Quality Assurance.
This individual now reports directly to the site ~ general manager.
The NRC is reviewing this
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apparent reduction in commitment to the 0QAP described in Appendix C to the USAR. This is considered an unresolved item (50-282/93019-02, 50-306/93019-02(DRS)).
I Several months ago the inspectors raised a concern with the
!
effectiveness of the corporate QA audit program.
The inspectors-
!
questioned the Director Quality Assurance and the Manager N0QA as to
!
whether the licensee's resources were being used to effectively identify i
problems needing management attention.
The inspectors also questioned
.
the technical adequacy and scope of selected audits and provided the QA
!
program managers with some specific examples to illustrate their t
concerns. During the next several months, the inspectors conducted a-
more comprehensive review of both the QA audit program and the onsite QA surveillance program to determine if these programs were making a positive contribution to the licensee's self-assessment effort and. if
,
so, to what extent.
The inspectors discussed the scope of individual audits with the lead auditors, observed selected in-process audit and
-!
surveillance activities, reviewed all audit and surveillance reports,
observed audit exit meetings with licensee management, visited the t
corporate office to evaluate the audit preparation process, and
_
,
routinely met with the audit group supervisor, Manager N0QA, and the
Superintendent Site Quality to discuss program status and significant l
audit and surveillance findings. The inspectors also met with the j
Director Quality Assurance to discuss QA program effectiveness.
During i
their review of the QA program, the inspectors promptly discussed each
identified issue with the individual auditors, surveillants, and/or j
.
program managers as appropriate.
The inspectors also reviewed and
discussed with program managers the results of a Joint Utility j
Management Assessment (JUMA) of the QA audit program conducted from
August 30 to September 3, 1993.
The JUMA team was comprised of five i
representatives from five different utilities.. The team assessed the -
l overall effectiveness of the audit program relative to industry
_
expectations.
l Based on the results of their comprehensive review of the QA program,
'!
the inspectors concluded that both the onsite surveillance program and
the corporate based audit program were effective in identifying problems j
to licensee management.
The corporate QA audit program consists of'
l standardized audits and discretionary audits.
Standardized audits are
!
periodic, have defined objectives, and satisfy 10 CFR 50 Appendix B
audit requirements. These audits are performed every two years unless
!
c identified as annual or triennial. Discretionary audits are_ performed-l as directed by management and as necessary to evaluate the Corporate Nuclear Administrative Control program.' The inspectors concluded that
!
auditors are sufficiently qualified to perform the required audits.
,
Seven of the eight auditors have twelve or more years of technical j
-
related experience and six of the auditors have a bachelor's degree.
!
The ' audit group is currently staffed with seven auditors, one of the
!
more experienced audi' tors having recently left the company.- In the
{
past, auditors were typically involved with eight to ten audits per year
!
with only one auditor a'ssigned responsibility for a particular audit.
j More recently, the audit group has adopted the team approach with at
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.least two auditors assigned to a particular audit.. In 1992 and 1993, 44 and 38 audits were performed, respectively. On average, auditors are.
working on seven to eight audits per year.
'
The inspectors also identified some areas in the corporate QA audit l
program that required improvement. The majority of audit reports j
reviewed contained sufficient detail to support conclusions on licensee
performance in each of the functional areas evaltated.
However, some l
'
audit reports contained performance conclusions-that were based
- primarily on procedure review with very' limited or no performance' based
observations.
In addition, the inspectors considered the threshld for initiating corrective action doctments in response to identified deficiencies to be too high. Deficiencies identified during the audit
>
process are recorded as " findings" Open findings are tracked by NQD l.
and require a written response from the line manager for the respo_nsible l
'
organization. To close the finding, NQD must review and accept the
'
corrective action identified in the written finding response Audit-reports may also contain " recommendations" to address areas of concern.
However, recommendations are not tracked by NQD and no response by line i
management is required.
Using the finding process to Mentify
deficiencies to line management promotes root cause analysis of the
deficient condition and ensures corrective action followup.
The inspectors observed that the quality of the audit reports has improved
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over the last several months.
The results of the audit activities for l
specific areas identified in the audit scope are more fully discussed in
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the body of the audit reports.
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The inspectors concluded that the onsite QA surveillance pronram'is strongly oriented toward performance-based observations.
Several
substantive issues have been identified by the~onsite QA group.
Deficiencies. identified through the surveillance process are reported as
,
nonconformances, either as a nonconforming item report (NIR) or as a i
nonconforming activity report (NAR).
The inspectors concluded that the threshold for initiating an NIR or an NAR in response to an identified
,
deficiency was appropriate.
One unresolved item was identified.
No violations, deviations, 'or inspection followup items were identified.
l S.
Licensee Followup on Previously Identified Items (92701)
a.
Reactor Protection System Relav Failures i
'
L On July 19, 1993, during performance of monthly surveillance
. ;
'
testing of the Train A reactor protection. system (RPS) for Unit 2,
. ;
two NBFD relays failed. The failure mode was such that the coil l
opened electrically, resulting in an actuation of the relay to its
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de-energized state.
Initial licensee and resident. inspector followup on these relay failures is discussed in detail in NRC Inspection Report 50-282/93014; 50-306/93014(DRP).
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The failed relays-were returned to the vendor (Westinghouse) for failure analysis. Westinghouse concluded that the observed coil
!
case bulges and coil conductor openings were most likely caused by overheating resulting in expansion of non-homogeneous--potting i
compound. Westinghouse suggested that the overheating was l
probably caused by one or more of the following:
a) extended
overvoltages, b) lack of cooling or air circulation, c) breakdown
-
.
of the winding conductor varnish insulation, or d) poor winding or j
manufacturing practices.
The licensee concluded that the i
overheating was caused by either insulation breakdown or a
'
manufarturing error of some nature since the relays had been
. !
subjected to 132 VDC several days prior to the observed failures i
during a battery charge (the relays are qualified to 140 VDC), and the relays are housed in cabinets with adequate ventilation in.an
. t air conditioned room.
In addition, as part of its effort to
identify the root cause for the relay failures, the licensee l
performed voltage monitoring during Unit'2 Train A and B testing.
!
Nominal voltage was 130 VDC and 128 VDC, respectively, with only a
!
minor variation (1/4 VDC) observed during testing.
.
The non-homogeneous potting compound issue had previously been reported to the NRC in Westinghouse letters NS-NRC-91-3600 and
.
ET-NRC-91-3627 dated June 24, 1991 and December 13, 1991,
!
respectively.
In these letters, Westinghouse identified a concern j
with relays in a normally energized application in that the heat I
from energization could cause softening of epoxy (potting
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compound) that encapsulates the relay coil and resultant flow of j
this epoxy into the area of the armature causing sticking of the
plunger assembly. This could result in a delay of the relay to reset upon de-energization.
The NRC issued Information Notice'
j 91-45, "Possible Malfunction of Westinghouse ARD, BFD, and NBFD
!
relays, and A200 DC and DPC 250 Magnetic. Contactors," on July 5,
1991, to address this issue.
l In their original 10 CFR Part 21 notification (Westinghouse letter NS-NRC-91-3600), Westinghouse stated that verifying the performance of normally energized applications through at-least two surveillance periods reduces the. concern over common mode failures in redundant-systems to the extent that subsequent
,
failures could be considered random.
Through a series of sample
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tests, Westinghouse determined that if individual' coil assemblies
-
were subjected to 250 degrees Fahrenheit for 2.5. hours in a-
'
preheated oven and then checked for epoxy softening (referred to as the heat-and-probe test), a high percentage of those assemblies that might fail in service due to poor epoxy.would be detected.
Westinghouse recommended that normally energized devices that had
not been through at least two surveillance cycles, normally -
de-energized devices with machine mixed epoxy, and all spare
devices, be heat-and-probe tested. Westinghouse concluded that if a device did not exhibit epoxy softening.as a result of this test, then it was suitable for continued in-service application.
Westinghouse requested that the results of the testing for all
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spare devices be forwarded to Westinghouse so that the Westinghouse Owners Group (WOG) could evaluate the data.
In a
letter from the WOC to the NRC dated September 9, 1992 (0G-92-49),
the WOG in referencing the results of the spare DC coil assembly
~
testing program, stated that the observed low failure rate during i
the~ spares testing program coupled with the historically low i
number of reported in-service failures provides sufficient
,
confidence in the performance of the DC coil assemblies, and it is
therefore not necessary to test existing installations to verify
'
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the adequacy of the relay coil epoxy compound.
,
The licensee installed new relays in the Unit 2 RPS on L
September 20, 1990. All of the Unit 2 relays satisfied the
-!
Westinghouse recommended in-service test criteria of no performance problems for two surveillance cycles.
Following the
Part 21 notification, the licensee heat-and-probe tested all of
,
its existing spare relays..
Eleven of these relays were
,
subsequently installed in the Unit 1 RPS.
Remaining Unit I relays
!
were purchased after Westinghouse had identified and corrected the l
deficient manufacturing process that had resulted in specific lots of non-homogeneous potting compound.
On September 24, 1993, during RPS testing of Train A, a third NBFD
.
relay failed (open coil)..
During an inspection of the Train A l
relay racks prior to testing, the licensee identified that three
relays contained longitudinal cracks along their respective coil
]
cases with indications of epoxy extrusion. The licensee exercised the plunger for each of the cracked relays and verified that the j
plunger moved freely. Additionally, all three relays passed the j
surveillance test.
The licensee sent-the failed relay and one of
!
the three cracked relays to Westinghouse for analysis. On
,
September 27, 1993, during a pre-surveillance test inspection of
!
Unit 2, Train B relays, one cracked relay was discovered.
i in discussion between Westinghouse and the licensee on_0ctober 8,
!
1993, Westinghouse stated that the conclusions of their
December 13, 1991 letter to the NRC were still valid regarding i
epoxy related problems; specifically, that based on epoxy related i
failures reported in-service to date, it is apparent that they are j
random in nature, and.that verifying the performance of normally energized applications through at least two surveillance periods i
reduces the concern over common mode failures to the extent that
subsequent, failures could be considered random. Westinghouse also referred to the September 9, 1992 WOG letter (0G-92-49), which stated that the data from the spares testing program showed such a i
t low failure rate, i.e., incidence of e'poxy softening, that-any
failure of'an in-service relay could be considered random,
'
l regardless of whether or not it had past d the two surveillance i
~
cycle in-service testing or heat-and-probe testing criteria.
<
1he licensee performed an inspection of Unit 2 relays on October 14, 1993,'to determine whether there was any change in the
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i condition of the previously identified cracked relays.to identify l
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the existence of any new cracks or coil case bulges, and to l
conduct thermography to assist in root cause analysis. During
this inspection the licensee discovered three more crhMd relays, j
two in Train A and one in Train B.
One of these relays was a l
j normally de-energized relay, which energizes to start the l
turbine-driven auxiliary feedwater pump.
This relay'is energized
!
during monthly surveillance testing, but only for several minutes which is not enough time for substantial heating to occur.
No
cracked relays were identified during an inspection of the Unit 1 l
l RPS on October 13, 1993.
On October 21, 1993, the licensee identified seven additional i
,
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cracked relays in Train A and ten additional cracked relays in Train B during pre-and post-surveillance test inspections of the
Unit 2 RPS relay racks.
The licensee believed that the cracks in
!
these relays did not necessarily result from the October 21 i
surveillance test, as the cracks were identified in relays that l
were very difficult to inspect due to their close proximity to
!
adjacent relays and these cracks were most likely missed during
!
previous inspections.
In addition to the three failed relays.
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(open coil), as of October 21, the licensee had identified a total
-
of 24 cracked relays in the RPS for Unit 2,12 in Train A d 12 a
in Train B.
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On October 28, 1993, Unit 2 was shut down for a refueling outage.
The licensee subsequently removed all Unit 2 NBFD relays and.sent them to Westinghouse-for inspection and analysis.
The licensee identified 39 additional cracked relays during inspection of the relays upon removal. Of the 43 relays normally installed in each train, the licensee has identified 30 relays with cracks of-varying degree in Train A and 33 in Train B.
In addition, the licensee has observed slight epoxy extrusion'from some of the relay cracks.
On October 26, the licensee issued an' informational note for the INPO Nuclear Network describing its recent experience with cracked and failed NBFD relays.
Westinghouse.also issued an INF0 GRAM on the same subject shortly thereafter.
In this INF0 GRAM, Westinghouse stated that the failure of the three NBFD relays sent to Westinghouse for analysis had originally been attributed-to the deficient potting compound issue.
The coil openings were attributed to the inductive voltage spike (about 2000 Volts DC),_
generated by the de-energization of the relay coils, breaking through coil conductor insulating materials which had been degraded by deficient-potting compound and heat. -However, further testing and sectioning of the' returned relay coils, along with additional analysis, indicated that' NBFD relay coils may also fail due to improper or inconsistent Mylar insulation placement during their manufacture.
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T On November 8, 1993, Westinghouse issued its failure analysis f
report for the two relays sent to Westinghouse following the.
failure of the third NBFD relay on September 24, 1993.
The report i
reaffirmed the conclusions stated in the previously issued
!
INF0 GRAM, and further stated that the coil case cracking j
phenomenon was observed in earlier vintage NBFD relay coils -
According to Westinghouse, the NBFD65NR dual' coil case design, j
with Mylar insulating material wrapped around the wound coil, was j
intended to preclude coil case cracking. Westinghouse s+.ated that i
of 1059 coils oven tested for potting integrity, only four have exhibited cracked coil cases, and Westinghouse has seen few coils l
with the cracking phenomenon in the failed relays which have.been
returned to Westinghouse.
l l
The inspectors had some concerns with the statements made by~
,
Westinghouse in their failure analysis report and discussed these concerns with the licensee. The licensee has identified cracked coil cases in 63 of 86 installed relays, whereas Westinghouse has
seen only four cracked coil cases in 1059 which were oven tested.
l I
In addition, the statement that Westinghouse has seen few coils with the cracking phenomenon in the failed relays which have been returned to Westinghouse, implies that some cracked relays also
failed. Also, no characterization of the failures, i.e. coil open
'
or epoxy flow, was provided. The inspectors'were most concerned with the statement that NBFD relay coils may also fail due to i
l improper or inconsistent Mylar insulation placement during their-l manufacture. The inspectors discussed potential Part 21-l reportability for this issue.
The licensee stated that it had i
discussed the insulation issue with Westinghouse on November 10,
1993. During this discussion, Westinghouse stated that they had
performed destructive testing on eight of the 86 relays designated ~
for shipment to the licensee for replacement in the Unit 2 RPS, Westinghouse claimed that these eight relays were representative-of all relays manufactured subsequent to resolution of the original 10 CFR Part 21 deficient potting compound issue, and that this testing indicated that the Mylar insulation had been properly applied.
The licensee informed the inspectors that Westinghouse had committed to provide the licensee with some documentation to support their conclusions regarding the acceptability of NBFD relays with Mylar insulation.
While there have been no instances reported to-Westinghouse since
)
the original Part 21 was issued, where deficient potting compound flow has resulted in the improper operation of an NBFD relay, i.e.
a-delay or failure of a relay to actuate or reset, the three. relay
,
l failures and numerous cracked relays identified by the licensee,
..l which may be attributed to epoxy flow, are cause for concern.
It
'
appears that the instances of epoxy softening and resultant flow are not random.
In addition, the fact that NBFD relay coils may also-fail due.to improper or inconsistent Mylar insulation i
placement alone or in conjunction with potting compound flow is j
cause for additional concern.
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This issue is considered an inspection followup item
'
(50-282/93019-03; 50-306/93019-03(DRP)), pending the inspectors'
evaluation of documentation from Westinghouse regarding.the acceptability of NBFD relays with Mylar insulation.
The NRC is also considering a supplement to NRC Information Notice 91-45 to j
address the generic aspects of the NBFD relay. issues.
i
I b.
Empowerment i
Approximately six months ago, the inspectors identified a concern l
with the licensee's implementation of its empowerment philosophy l
relative to ensuring that an appropriate level of management is
l I
involved in the decision making process, and that those-f individuals entrusted with making decisions keep their respective l
l.
supervisors informed (refer to NRC Inspection Report 50-282/93008; q
l, 50-306/93008(DRP)).
In response to this concern, the plant.
f manager issued a memorandum to his staff discussing management's i
expectations for the implementation of the empowerment philosophy.
l In addition, the plant manager made a presentation on empowerment L
to the various departments and work groups that directly report to
!
him, e.g. Operations, Maintenance, Engineering, etc.
The j
_
inspectors observed the plant manager's presentation to'the
maintenance department.
The presentation was informative, l
discussed the inspectors concerns in this area, and appeared to be
!
well received by those in attendance.
The inspectors will i
continue to evaluate the effectiveness of the licensee's actions
-:
to address previously identified concerns with.the licensee's j
implementation of its empowerment philosophy during future j
inspections, j
i c.
(Closed) Unresolved item 50-282/93014-02: 50-306/93014-02(DRP)
l The inspectors continued their ieview of high energy line. break j
(HELB) and steam exclusion issues as previously discussed in NRC l
Inspection Report 50-282/93014; 50-306/93014(DRP). On
.l l
September 13, 1993, the licensee requested and was granted a
'
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notice of enforcement discretion (NOED) to extend the limiting l
condition for operation action statement time for_4 kV safeguards bus No. 16.
This request was initiated when a concern was.
identified regarding the location of a temporarily sealed wall i
penetration into the bus 16 room relative to the location of a j
main steam line design basis break point.
Locations of design basis break points are specified in Appendix 1.of the Updated l
Safety Analysis Report (USAR). The USAR also specifies locations
'
of impingement barriers and encapsulation sleeves which serve to mitigate the effects of a design basis break. The subject break point is identified in-the USAR as not having an encapsulation sleeve or an impingement barrier. However,-the actual piping configuration does contain an encapsulation sleeve at the subject break point location. This information was not immediately l
recognized by the licensee when it requested the NOED.
Upon L
identification of the presence of the encapsulation sleeve, the
1
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t licensee evaluated the steam jet impingement effects of a design
!
basis crack (the worst case credible event at this location) on the temporary penetration seal and determined that the seal would-l remain intact. Therefcre, the steam exclusion boundary into the i
bus 16 room would not have been breached. The inspectors
!
considered the licensee's performance in using the NOED process a i
strength and considered.the licensee's request for an N0ED to be.
j appropriate and conservative given information available at the
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time of the request. However, the inspectors considered the-
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l misidentification of the encapsulation sleeve to be an example of_
i a weakness that existed in the licensee's HELB and steam exclusion
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boundary design control.
l The inspectors also reviewed the licensee's evaluations of steam f
exclusion boundary breaches in the Auxiliary Building (as y
discussed in NRC Inspection Report 50-282/93014;
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50-306/93014(DRP)) in order to assess the safety significance of-
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the as-found conditions.
The 695' elevation of the Auxiliary
Building is defined to be a mild, post-HELB environment area, it contains equipment that is not qualified to operato in a harsh l
environment, and it contains equipment necessarv itigate the consequences of a HELB.
On August 6, 1993, ation i
approximately 0.25 ft' in area was drilled through the floor of
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the Auxiliary Building 715' elevation per Work Request No.
U3312-CS-Q, implementing a portion of Modification No. 90L188 to install new containment spray recirculation piping.
The subject penetration resulted in a breach in a steam exclusion boundary.
The worst-case credible HELB that could have impact on the environment of the 695' elevation " compartment" was determined to -
be a design basis crack in the main steam line in the 715'
elevation compartment. An analysis was-performed for this event, given a 0.25 ft' openirg from the 715' elevation to the 695'
elevation.
The results indicated that changes in environmental conditions on the 695' elevation were insignificant (peak temperature rise was less than 1 degree Fahrenheit). Therefore, the 695' elevation would remain mild and equipment operability would not be affected.
As part of its immediate corrective actions following the identification of the steam exclusion boundary issue, the licensee completed a thorough walkdown of the steam exclusion boundary and sealed all openings that could provide a possible steam path to the 695' elevation compartment.
None of the openings found were j
egregious; several were very small or provided a subtle, tortuous i
path to the 695' compartment.
Those identified openings (including the 0.25 ft" penetration) which provided a credible t
i steam transmission path to the 695' compartment, when summed together, produced a total opening of approximately 2 ft'.
The-licensee analyzed the environmental impact of a HELB, given a 2 ft' opening to the 695' compartment. The maximum temperature:in the 695' compartment during the accident was computed to be i
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119 degrees Fahrenheit, and therefore the environment would remain t
mild for' temperature. The relative humidity would reach
100 percent in the compartment, but the safety injection (SI) pump
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motors and motor operated valve (MOV) actuators and motors are qualified to operate in a 100 percent relative humidity
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environment.
The limiting components necessary to function in the
post-HELB environment are the 480 V motor control centers (MCCs),
which are not moisture tight.
The licensee performed an
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evaluation illustrating that with a conservative amount of. air j
displacement inside the MCCs, condensation within'the MCC cubicles-l would not occur. Additionally, the time at which room ambient
temperature would exceed MCC cubicle internal temperature (allowing internal condensation to begin) would not occur until af ter all MCC MOV loads had completed their accident function.
>
Based upon their review of the licensee's analyses, the inspectors
concluded that the as-found conditions were of minor safety
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significance.
However, openings have existed historically in the steam exclusion boundary that were greater than 2 ft" in area (equipment hatches, stairwell doors, etc.).
These would have
resulted in harsh, post-HELB conditions in the 695' compartment j
that would have adversely impacted the operability of equipment needed to mitigate the consequences of a HELB.
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The licensee's corrective actions in response to the steam exclusion boundary issue have been excellent. A Steam Exclusion Advisory Committee was established to develop and. implement a -
project plan for resolving steam exclusion issues. Among the action items completed or in process are completing the evaluation of the as-found conditions as discussed above, reconstitution of steam exclusion design bases (including validation of USAR HELB analyses and analyses performed following the NRC's issuance of Information Notice 84-90, " Main Steam Line Break Effect on Environmental Qualification'of Equipment"), improvement in computer modeling capability of post-accident conditions in the plant, development of an interim. review process for allowing planned work, and incorporation of lessons learned into an improved modification process.
The licensee is using its Design Basis Documentation Follow-on' Item (f01) Process to resolve open items as they are identified.
The inspectors reviewed the licensee's interim methodology for controlling and evaluating the opening of penetrations for. planned modification work. The licensee issued a Special Order enumerating controls to be followed_to ensure that any planned-opening'in a steam exclusion boundary is evaluated as acceptable, and that this acceptance is documented by a Steam Exclusion Boundary Opening Permit. Work Requests that require an opening to be made arc evaluated on a case-by-case basis by licensee engineers.
The licensee's ongoing station blackout / electrical
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systems upgrade project is the principal customer for permits at i
this time due to the number of new penetrations being created for
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cable pulling. The inspectors reviewed the log of permitted i
openings and discussed the bases for approval of particular j
openings with the responsible engineers.
The inspectors concluded
that the licensee's process for controlling the location, size,
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and number of penetrations was adequate in the interim,.to ensure t
equipment operability until a more' formal method is' implemented into the modification preparation process.
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The licensee has improved the sophistication of its modeling.of the Auxiliary Building. An F01 was identified regarding the control room chiller rooms No. 121 and No. 122, located on the i
755' elevation of the Auxiliary Building..Each chiller room is i
designated as a mild environment and contains equipment (not.
j environmentally qualified) which provides cooling for safeguards
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equipment rooms.
Concerns were identified that a HELB could
result in a breach in the boundary between the harsh environment
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area on the 755' elevation and the mild chiller room environment.
i The licensee's new Auxiliary Building models provided temperature
and pressure profiles for a previously unanalyzed area of the
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j building.
With these results, the licensee performed analyses of.
i the structural integrity of the chiller room walls and doors, and concluded, with a justification for continued operation and safety
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evaluation, that the chiller room environment would remain mild.
The inspectors reviewed the licensee's assessment, discussed it-l with the responsible engineers, and concluded that this issue was
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adequately addressed.
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The licensee is completing a thorough corrective action program to
correct its self-identified weaknesses in the control of steam l
exclusion boundar;es.
However, the inspectors considered that the
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programmatic weakness-that. existed regarding cognizance of the
steam exclusion boundary design basis prior to September 1993, to be significant.
Part 50 of Title 10 to the Code of Federal Regulations (10 CFR 50) Appendix B, Criterion III, as implemented
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by Section 5.0 of the Northern States Power Company Operational-
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Quality Assurance Plan, requires that design changes shall be
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subject to design control measures commensurate with those applied to the original design.
Contrary to the above, steam exclusion boundary control was not considered as a' design input in the i
development and authorization of Work Request No. U3312-CS-Q,
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implementing modification No. 90L188, resulting in an unanalyzed
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breach in a steam exclusion boundary on August 6, 1993.
As described above, the licensee's actions appeared to be in l
violation of NRC requirements.
However, the violation is not being cited because the criteria specified in Section-VII.B.2 of the " General Statement of Policy and Procedure for NRC Enforcement Actions," (Enforcement Policy,10 CFR Part 2, Appendix C), were
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satisfied..The inspectors will review the licensee's progress in-
implementing its corrective actions as specified in the licensee
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event report that was submitted for'this issue and additional F01 items in a future inspection.
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i One non-cited violation and one inspection followup item were identified.
No deviations or unresolved items were identified.
6.
Licensee Event Report (LER) Followun (92700. 9071?m92701)
I a.
(Closed) LER 50-282/90002. Rev, 1:
Excessive pressurizer cooldown j
rate.
On January 19, 1990, review of the cooldown data indicated that l
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the-cooldown rate of the pressurizer had exceeded the Technical-
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Specification limit of 200 degrees Fahrenheit per hour, and the
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l temperature difference between the pressurizer auxiliary spray and
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the pressurizer had exceeded the Technical Specifications limit of
.j 320 degrees Fahrenheit. This event is discussed in NRC Inspection
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Report 50-282/90002; 50-306/90002(DRP).
The inspectors reviewed
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the licensee's corrective actions to prevent recurrence as
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l described in the original LER, concluded that they were adequate, i
and closed the original LER in NRC Inspection Report 50-282/90019;
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50-306/90019(DRP).
Since that time, however,-the licensee has adopted a more conservative approach to plant cooldown which
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virtually eliminates the possibility of having an excessive pressurizer cooldown rate.
In cooling down the plant, the
l licensee maintains a narrow band of differential temperature
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between the pressurizer and the reactor coolant system, in contrast to the large temperature differences maintained in the
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past.
This method of cooldown reflects a more conservative l
operating philosophy.
This LER is closed, b.
(Closed) LER 50-282/91007:
Automatic start of Auxiliary Building Special Ventilation System caused by testing the wrong radiation, monitor.
As discussed in Inspection Report 50-282/91011; 50-306/910ll(DRP),.
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a radiation protection technician exposed radiation monitor IR-37-
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to a source instead of lR-30, resulting in an ESF actuation of the Auxiliary Building special ventilation system. The licensee's corrective action for this event consisted of counseling the radiation protection specialist who made the error.. The inspectors noted that this event is exempt from existing 10 CFR 50.73 reporting requirements.
This LER is-closed.
c.
(Closed) LER 50-282/91008: One Unit I safety-related. snubber-failed its functional test.
j On June 19, 1991, with Unit 1 shut down for refueling, the safety-related, hydraulic snubber at location 1-SIRH-23B was being functionally tested in accordance with Technical Specification (TS) 4.13.C.
The subject snubber had been in. service for five.
years on a safety injection system accumulator discharge line.
The snubber failed its functional test when it could not be i
operated through its full stroke of five inches in either tension
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or compression (only 3% inches of movement was observed).
In
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l addition, the internal snubber fluid which is usually translucent
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t with a blue or pink tint, had evidently deteriorated such that it was dark and opaque. The snubber was declared inoperable and was -
subsequently disassembled and. inspected.
l The licensee concluded that the deteriorated fluid condition was
caused by small amplitude, constant vibration which results in
' i constant movement of the snubber piston. This constant piston
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movement caused localized heating of the snubber fluid which in i
turn caused the fluid to deteriorate. - The fluid degradation allowed heating and abnormal wear of the metal piston rings and
cylinder walls to occur.
In addition, the degraded fluid
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partially plugged internal control valves, preventing proper
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piston movement.
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i The licens9e implemented several corrective actions in response _ to
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the failed snubber functional test. A thermal growth analysis of j
the piping associated with the failed snubber was performed by the i
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architect-engineer.
Based on the results of this analysis, the licensee concluded that 3% _ inches of movement was sufficient to -
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allow the snubber to accommodate thermal expansion of the associated piping. The licensee also performed the required TS,
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engineering evaluation of the components supported by the
- i inoperable snubber to determine if these components were_ adversely I
affected such that they could no longer perform their design
function.
Results from this evaluation indicated that no.
components were adversely affected by the inoperable snubber.
The
snubber fluid was analyzed and found to contain metal wear i
products.
To satisfy TS 4.13.C, the licensee removed, i
functionally tested, disassembled, and inspected an adjacent i
snubber which had been in service for four years and had been
subject to the same operating conditions as the failed snubber.
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No abnormalities were noted. However,'this particular snubber had
elastomer piston rings installed. The licensee visually inspected
all safety-related snubbers for fluid quality and did not identify any other snubbers with deteriorated fluid.
The licensee replaced
the failed snubber with one that-contained elastomer piston rings.
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The licensee modified its visual inspection frequency. for snubbers
in accordance with TS 4.13.A and added procedural steps to snubber-
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surveillance procedures requiring specific inspection of the j
snubber fluid quality. The licensee _has also invoked the practice
of using elastomer piston rings instead of metal rings -in rebuilt snubbers.
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The licensee considered the condition of the inoperable snubber to be a violation of TS 3.12.A, and therefore reportable as a
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condition prohibited by the plant's Technical Specifications per
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10 CFR Part 50.73 (a)(2)(i)(B).
The inspectors concluded that the j
condition of the inoperabie snubber was a violation of TS 3.12.A which requires all safety-related snubbers to be operable when the j
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Unit is operating in a condition other than cold shutdown or refuel ing. However, this violation of NRC requirements is not.
j being citod because the criteria specified in Section Vll.B.2 of i
the "Ge ieral Statement of Policy and Procedure for NRC-Enforcement-l Actior.s," (Enforcement Policy,10 CFR Part 2, Appendix C), were satisfied.
This LER is closed.
d.
(Closed) LER 50-306/93003:
Both trains of ventilation for safeguards electrical equipment secured for several hours due to
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inadequate administrative control.
The D5/D6 building is a seismic category I building which houses j
the emergency diesel generators (EDGs) and associated _ Class IE
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electrical distribution equipment for Unit 2 engineered safety features loads.
Safeguards electrical equipment areas of the building, including the 4160 Volt bus rooms, 480 Volt bus rooms, and EDG control rooms, are provided with a " safety-related emergency equipment switchgear areas ventilation system", referred to as the D5/06 building heating, ventilation, and air conditioning (HVAC) system.
Each train of D5/06 building HVAC provides ventilation for one train of safeguards equipment.
On July 19, 1993, the licensee secured both trains of the 05/06 building HVAC system for approximately 15% hours. The NRC'
performed a special safety inspection to review this event.
The results of that inspection are documented in NRC Inspection Report 50-306/93015(DRP)'which discusses the details of the event and addresses relevant' regulatory compliance issues.
The licensee performed preliminary calculations to demonstrate that the equilibrium temperature in the Unit 2 safeguards bus rooms and the D5/D6 EDC control rooms, with the HVAC system.
secured for approximately 15% hours, would not exceed operating temperature limits for the electrica1' equipment in these rooms.
These calculations assumed that a loss of offsite power occurs and that safeguards buses are carrying electrical loads to mitigate a design basis accident. Based on those calculations, the licensee concluded that operating temperature limits would not be exceeded for the set of conditions that existed on. July 19, 1993.
Subsequently, a more rigorous analysis of the heatup characteristics of.the 05/D6 building with no forced ventilation, was performed by a licensee contractor. This analysis assumed that a steam line break occurs in the Auxiliary _ Building adjacent ~
to the 05/D6 building resulting in the transfer of heat to the.
05/D6 building, that a loss of offsite power occurs, and that the safeguards buses are carrying design basis electrical loads in response-to a safety injection signal.
Results from this analysis indicate that for the. worst case scenario (ambient temperature of 96 degrees and room temperature of 90 degrees Fahrenheit),
qualification temperature limits for the electrical equipment in
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the 4160 Volt and 480 Volt safeguards bus rooms and in the EDG
control rooms would be exceeded.
For the set of conditions that.
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existed on July 19, 1993 (ambient temperature and room temperature
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of 75 degrees Fahrenheit), the analysis results' indicate that l
qualification temperature limits for electrical' equipment in the
y 480 Volt safeguards bus room would be exceeded in 15%. hours.
l The corrective action described in this LER is the same as that
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described in the licensee's response to NRC violation J
50-306/93015-01(DRP).
The inspectors will evaluate the adequacy i
of the licensee's corrective actions during a future inspection.
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This LER is closed.
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i e
(0 pen) LER 50-282/93011: Opening found in steam exclusion i
boundary.
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The events associated with this LER are discussed in paragraph
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5.c.
In the LER, the licensee committed to complete a
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comprehensive review of the design bases related to outside'of containment high energy line break effects, including the steam exclusion boundary and the environmental qualification program.
Also, the licensee committed to develop an enhanced steam exclusion boundary control program.
The inspectors reviewed the licensee's efforts in these areas and observed that significant progress has been made. The licensee informed the inspectors that-its goal for completion of these commitments was February 1994.
The inspectors will further evaluate the adequacy of the licensee's actions during a future inspection.
f.
(0 pen) LER 50-282/93012:
Failure to perform offsite dose and l
effluent monitor setpoint calculations due to personnel inadequacy and personnel error.
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On September 8,1993, during a review of dose calculations for-liquid and noble gas-releases' for the month of August 1993, the Radiochemistry Supervisor noted that dose calculations had not been completed for the month of July 1993.
The Radiochemistry Supervisor also identified'that monthly alarm setpoint calculations for liquid and airborne effluent monitors,- which are-l normally performed at the same time as the dose cal.culations, had not been completed for the month of July 1993, as well..The dose and-setpoint calculations are required by Technical Specifications in accordance with methods specified in the Offsite Dose a
Calculation Manual.
This event is further discussed in NRC
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Inspection Report 50-282/93014; 50-306/93014(DRP)..
The licensee's corrective action to prevent recurrence for this event, as described in'the LER, was to incorporate the monthly dose and effluent monitor setpoint calculations into both the Chemistry Group's work scheduling and surveillance programs.
The licensee has also revised its Radiation Protection-Implementing
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i Procedures to reflect this new scheduling process. -The licensee plans on conducting a review of other areas assigned.to the l
Radiation Protection and Chemistry Group, to determine if various
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requirements are dependent on the-completion of non-scheduled
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activities.
If any non-scheduled activities are identified, the
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licensee intends on adding them to the existing work scheduling l
programs.
A regional radiation protection specialist.will a
evaluate the adequacy of the licensee's corrective actions during
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a future inspection.
{
g.
L0 pen) LER 50-282/93013:
Gaseous effluent sampling requirements
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not met for a two-day period due to personnel error and inadequate
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procedures.
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Gaseous effluents exiting the Unit 1 Auxiliary Building normal l
ventilation stack are monitored by redundant radiation monitors
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1R-30 and IR-37. These monitors each sample for noble gases,
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iodine, and particulates.
In addition, a portable silica gel sampler is valved into one of the operating monitors to provide a i
monthly composite sample for tritium.
If the sample pump for that monitor is removed from service, the silica gel sampler must be valved in to the other monitor's sample system to insure that a j
representative sample of effluent flow is obtained.
The Shield
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Building stack, which is monitored by radiation monitor 1R-22,
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serves as the exhaust for-the Auxiliary Building special-ventilation system.
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On September 7, 1993, a work request was initiated to modify radiation monitor 1R-30.
The licensee verified that redundant i
moniter IR-37 was operable. Auxiliary Building ventilation was
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then shifted from the normal ventilation system to the special l
ventilation system. The duty chemist valved in the silica gel
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sampler for monitor 1R-22, since effluent flow would be exiting through the Shield Building stack. The portable silica gel sampler was not valved into the sample system for monitor 1R-37 since the Auxiliary Building normal ventilation system was not in service.
Radiation monitor 1R-30 was then isolated and its sample pump and associated motor were removed from the monitor.
On September 8,1993, power was restor-ed to 1R-30 and Auxiliary Building ventilation was shifted from the special ventilation to
the normal ventilation system. At this point, 1R-30 was still.
inoperable since its sample pump was still removed. On September 10, the licensee identified that a representative sample had not been collected on the silica gel sampler for two days.
The silica gel sampler was then valved into operating monitor 1R-37.
The licensee considered the failure to obtain a representative sample.of effluent flow for a two-day period to be a violation of TS 4.17.B.l.c, and therefore reportable as a' condition prohibited
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by the plant's Technical Specifications per 10 CFR Part 50.73 (a)(2)(i)(B). The licensee's corrective action to prevent
....
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b I
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. recurrence for this event, as described in the LER, was to revise existing procedures to ensure that the portable silica gel sampler'
l will always be valved into an operating radiation monitor,-and to
more clearly define when the duty chemist must be notified in i
response to ventilation system changes. The licensee intends to-i
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conduct training addressing required operator notifications to the i
duty chemist as part of the 1994 licensed operator requalification l
program. The licensee also. intends to-conduct training for the r
engineering staff on requirements for writing work requests that i
affect effluent release paths.
A regional radiatior, protection
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specialist will evaluate the adequacy of the licensee's. corrective j
actions during a future inspection.
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One non-cited violation was identified. No deviations, unresolved
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items, or inspection followup items were identified.
j 7.
Security (71707)
l At approximately 9:45 a.m. (CST) on October 25, 1993, the central alarm
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station (CAS) operator received a telephone call from an unidentified l
individual informing him that an office window on the second floor and i
south side of the New Administration building was broken. :The
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unidentified individual stated that the damaged window appeared to have j
been caused by a bullet, but noted that nothing had penetrated the
window. Two members of the licensee's security organization inspected -
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i the window and concluded that some type of projectile had impacted the-
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window. The subject window is constructed of double pane glass and it i
appeared that the projectile had not penetrated either pane.
The l
licensee did not identify any other building damage.
During a
subsequent inspection of the parking lot outside of the protected area i
in the vicinity of the damaged window, security personnel found a
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9 millimeter (mm), copper jacketed bullet.
During the investigation of-
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this incident, a security guard was approached by.a member of the-
licensee's staff who stated that he may have been onsite when the window-i was broken.
This individual stated that he was working in his office on the second floor of the New Administration building between 12:00 and 1:00 p.m. on Saturday, October 23 during which time he heard a loud
noise. The individual stated that he noticed the broken window at about
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3:30.p.m. when he walked outside by the window on his way to leaving the
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site.
Based on the deformation of the bullet and the damage to the window,. the
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licensee concluded that the bullet was fired from a considerable
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distance from the building. The licensee also located 'several spent
9 mm cartridges and empty ammunition boxes in an area near the~ training center approximately 700 yards from the damaged window. The-licensee a
learned that this area had been used for target practice and weapons i
firing in the past, apparently by local residents.
These spent cartridges and empty ammunition boxes had nothing to do with the onsite guard force or their training.
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The inspectors discussed the incident with security personnel and
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reviewed the results of the licensee's investigation. The inspectors
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also informed Region 111 security specialists of the incident.
The
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licensee's response'to this incident will be reviewed by Region III
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security specialists during a future inspection. This is considered an t
inspection follow up ' item (50-282/93019-04; 50-306/93019-04(DRSS)).
One inspection followup item was identified.
No viclations, deviations,=
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or unresolved items were identified.
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Ir d3 pendent Spent FueLStorace Installation (37700)
8.
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On October 19, 1993, the NRC issued a 10 CFR Part 72 license to Northern
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States Power Company authorizing the licensee to store spent nuclear j
fuel from its Prairie Island Nuclear Generating Plant in an independent
spent fuel storage installation (ISFSI) located onsite. The subject-i license authorizes the. licensee to move fuel that has been stored in the l
spent fuel pool for at least ten years to the ISFSI and to place the
fuel in dry storage casks manufactured by Transnuclear incorporated.
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These TN-40 dry storage casks were specifically approved by the NRC for i
use at the Prairie Island facility.
The NRC reviewed all relevant health and safety aspects of the ISFSI i
design, including criticality, structural, thermal, and shielding i
considerations, under both normal and accident conditions.
The NRC l
concluded that there was reasonable assurance that the ISFSI would be i
constructed and operated without endangering the health and safety of
the public, without significant environmental impact, and in compliance -
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with the conditions of the license and NRC regulations. While the NRC i
has issued a license authorizing the use of the ISFSI, approval must
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also come from the state of Minnesota legislature. The next session of
the legislature convenes in February 1994. The licensee has issued a i
stop work order for any further cask fabrication pending a decision by the state legislature.
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The spent fuel pool contains 1386 storage locations.- Before the start
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of the Unit 2 refueling outage on October 28, 1993,-there were 1233
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spent fuel assemblies and 48 fresh fuel assemblies in the spent fuel l
pool.
Currently,. 30 storage locations contain non-fuel material or are j
inaccessible for fuel storage. Of these, it is po.ssible to reclaim 19
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storage locations' by moving or consolidating' non-fuel material.
A full.
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core offload for each unit consists of 121-fuel assemblies.
During a
'l refueling outage, 48 assemblies are discharged.
Four, 7x7 temporary
_i fuel storage racks are available which can be installed in the cask
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laydown area of the spent fuel pool, providing an additional 196 storage
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locations.
However,. a storage cask cannot be placed in the cask laydown j
area of the spent fuel. pool if a temporary storage rack is present.
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To accommodate the Unit 2, full core offload for the 10-year inservice
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inspection (ISI)'of the reactor vessel, the licensee'had to install a i
temporary storage rack in the cask laydown area. After the Unit 2
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refueling outage, there will be 75 permanent storage locations available
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in the spent fuel pool (94 if the non-fuel material is consolidated).
Therefore, af ter the Unit 2 refueling outage, the licensee does not have.
j full core offload capability without the use of temporary storage racks.
i in order to perform the ISI of the Unit I reactor vessel during the Spring 1994 refueling outage, the licensee will have to install l
temporary storage racks. After that refueling outage, there will be 27 permanent storage locations remaining in the spent fuel pool (46 with-non-fuel consolidation). After the Spring 1994 outage, the licensee will not be able to conduct refueling without the use of temporary storage racks.
l No violations, deviations, unresolved. items, or inspection followup items were identified.
9.
f_naineered Safetv Feature System Walkdown (71710)
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The inspectors pe~ formed a detailed walkdown of the accessible portions of the Unit I residual heat removal (RHR) system to verify system
operability.
This included verification that the system lineup procedure is consistent with plant system drawings and the as-built configuration, valve and power supply breaker positions are correct to
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ensure that plant equipment and instrumentation were properly aligned, j
major system components are properly labeled, lubricated, cooled, and no
leakage exists, local and remote indication of significant process
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parameters are consistent with normal expected values, and support
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systems essential to system actuation performance are operational.
Some i
l minor discrepancies were noted in the component alignment checklist with I
respect to the specified location of component cooling water supply and return valves versus their actual location.
In addition, some
discrepancies were noted with the use of safeguards hold tags and i
blocking devices on valves for component cooling water supply and return j
to RHR pump seal-water heat exchangers. Safeguards hold tags and j
l blocking devices were attached to the subject valves but were not
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l-indicated as having a tag or blocking device on the checklist.
Each of l
the subject valve's position status agreed with the checklist.
The i
inspectors discussed each of these discrepancies with the licensee. The j
licensee stated that appropriate corrective action would be initiated i
after the current Unit 2 refueling outage.
No violations, deviations, unresolved items, or inspection followup
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items were identified, j
i 10.
Miscellaneous Items a.
Contact with members of the public (94703).
I
'l During the week of October 4, 1993, the licensee conducted a i
series.of community education / awareness classes on the fundamentals of nuclear power for interested residents of u
Hastings, Minnesota. The licensee had conducted similar classes I
for interested residents of Red Wing, Minnesota in April 1993.
The senior resident inspector gave a presentation for both i
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l community groups on the role of the NRC and the inspection program responsibilities of the resident inspector staff.
During a
question and answer period following the presentation, the senior i
resident inspector addressed several questions on dry cask storage and NRC involvement in the associated licensing process.
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b.
Notification to Another Government Aaency On November 2, 1993, the licensee made a 4-hour, non-emergency-l notification to the NRC, per 10 CFR 50.72, that.it had contacted
the Minnesota Pollution Control Agency (MPCA) regarding a j
situation involving protection of the environment.
The situation
was identified during an audit by the licensee's nuclear-. ;ality
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department and environmental and regulatory aff airs department,
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The audit group identified that the licensee had been disposing.of-
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microfilm photoprocessing chemicals in the onsite septic system l
and that the MPCA should be informed of this practice. This i
activity is outside the scope of NRC regulations; however, the
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licensee appropriately made the required NRC notification, No violations, deviations, unresolved items, or inspection followup
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items were identified.
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i 11.
Unresolved Items
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Unresolved items are matters about which more information is required in
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order to ascertain whether they are acceptable items, violations, or deviations. An unresolved item is discussed in paragraph 4.
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12.
Inspection Followup Items
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Inspection followup items involve activities which were not ' completed I
within the inspection period, where additional inspection is necessary
and planned.
Inspection followup items are discussed in paragraphs 2.a.
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5.a, and 7.
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13.
Manaaement Interview (71707)
J The inspectors met _with the licensee representatives denoted in
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paragraph 14 after the conclusion of the report period on i
n November 12, 1993. The inspectors discussed the purpose and scope of
the inspection and the findings. The inspectors -also discussed th'e.
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likely information content of the inspection report with regard to documents or processes reviewed by the inspectors during the inspection.
The licensee did not identify _any documents or processes as proprietary.
i 14.
Persons Contacted
- E. Watzl, General Manager, Prairie Island
- M. Wadley, Plant Manager K. Albrecht, General Superintendent, Engineering G. Lenertz, General Superintendent, Maintenance
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- D. Schuelke, General Superintendent, Radiation Protection
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and Chemistry
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- J. Sorensen, General Superintendent, Plant Operations i
- M. Reddemann, General Superintendent, Electrical and i
instrumentation Systems
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- G. Rolfson, General Superintendent, Engineering-Nuclear Generation
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Services i
R. Fraser, Superintendent, Mechanical / Civil Engineering-Nuclear l
Generation Services
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i G. Miller, Superintendent, Technical Support l
- J. Mcdonald, Superintendent, Site Quality Assurance
- A. Hunstad, Staff Engineer j
J. Hill, Superintendent, Instrumentation and Controls
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Systems
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- P. Kamman, Manager, Nuclear Operations QA
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- 0. Krech, Quality Supervisor, Nuclear Quality Dept.
- C. Hoglin, Nuclear Quality Department
- R. Lindsey. General Superintendent Safety Assessment
- 0. Mendele, Director, Power Supply QA
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- F. Evitch, Superintendent, Security l
J. Maki, Superintendent, Electrical Systems
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P. Ryan, Shift Manager M. Schmidt, Outage Manager W. Eppen, Nuclear Lead Plant Equipment and Reactor Operator J. Hoffman, Senior Consultant Engineer i
R. Mella, Production Engineer
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G. Thoraldson, Production Engineer E. Ballou, Production Engineer
- E. Eckholt, Nuclear Support Services J. Leveille, Nuclear Support Services G. Aandahl, Superintendent Design Standards
- M. Dapas, NRC' Senior Resident inspector
- R. Bywater, HRC Resident Inspector C. Or-ini, NRC Reactor Engineer l
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- Denotes those present at the management interview of November 12, 1993, i
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