IR 05000282/1990014
| ML20058F506 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 11/01/1990 |
| From: | Burgess B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20058F502 | List: |
| References | |
| 50-282-90-14, 50-306-90-14, NUDOCS 9011080319 | |
| Download: ML20058F506 (23) | |
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION III
Reports No. 50-282/90-14(DRP); 50-306/90-14(DRP)
Docket Nos. 50-282; 50-306 License Nos. DPR-42; DPR-60 Licensee:
Northern States Power Company 414 Nicollet Mall Minneapolis, MN 55401 Facility Name: Prairie Island Nuclear Generating Plant Ine;,ection At: Prairie Island Site, Red Wing, MN Inspection Conducted:
August 14 through September 24, 1990 Inspectors:
P. L. Hartmann D. C. Kosloff (4
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Approved By:
B. L. Burges Chief A/id /, 8/d Reactor Projects Section 2A Date Inspection Summary Inspection on August 14 through September 24, 1990 (Reports No. 50-282/90-14(6kP); 50-306/90-14(ORP))
Areas Inspected:
Routine unannounced inspection by resident inspectors of Licensee Action on Previous Items, Plant Operational Safety, Maintenance, Surveillance, Inspector Followup, Temporary Instruction TI 103 (Loss of Decay-Heat Removal), Refueling Activities, Engineering Safeguard Features, and Licensee Event Reports.
Results: Unit 1 operated at full power during the report period. Unit 2 operated in coastdown until shutdown for refueling on September 10, 1990.
Of the nine areas inspected, three licensee identified violations of NRC requirements were identified. One involved a personnel error which resulted in auxiliary feedwater pump autostart during plant shutdown for the refueling outage (paragraph 3.a).
The second involved a procedural error which resulted in an autostart of the auxiliary feedwater pumps during installation of the ATWS mitigation system (paragraph 3.b.(3)). The third involved an electrical maintenance procedure which did not adequately address de-energitation of chlorine monitors and resulted in an autostart 'f the Control Room Special Ventilation System (paragraph 3.b.(4)).
Howe r, in accordance with 10 CFR 2 Appendix C.Section V.G., a Notice of Violativa was not issued fer these violations.
9011000319 901101 DR ADDCK 050
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Two unresolved items were identified. One involved the lack of procedures for Residual Heat Removal train and component cooling pump interface requirements (paragraph 3.b.(6)). The second involved operability of the 11 Turbine Driven Auxiliary Feedwater Pump shaf t-driven lube oil pump (paragraph 11.a).
The following additional summary information is provided by SALP functional area:
Plant Operations Unit 1 operated the entire report period without major incident. A Reactor Protection System (RPS) BF0 relay failed and required replacement. The licensee's interpretation of Technical Specification requirements places the unit in a four hour Limiting Condition for Operation (LCO) whenever a reactor trip bypass breaker is utilized to power control rods. Thus, when an RPS relay is discovered failed, the licensee must repair and complete testing within a four hour period. The licensee is pursuing a license amendment request to clarify operational time restraints during use of reactor trip bypass breakers.
A similar LC0 time constraint was experienced when a rod control power cabinet component card failed, causing an urgent failure alarm. The licensee's interpretation of Technical Specifications placed the unit in an eight hour LCO.
This conservative interpretation of Technical Specifications is being reconsidered by the licensee and resolution is being pursued in the form of a license amendment request to clarify rod inoperability as caused by a irss of electrical control rod movement only.
A non-cited violation was idenuified by the licensee when an autostart of the 22 Turbine Driven Auxiliar; Feed Pump occurred. The cause was failure to follow a step of tho shutdown procedure prior to stopping the main feedwater pump. An unreselved item was identified for circumstances surrounding an autostart of a :omponent cooling water pump during changeover of operating Residual Heat Removal pumps. A component cooling system piping difference exists between the units and procedures to address component cooling pump selection have not addressed this situation.
The Unit 2 outage progressed in a controlled and well planned manner.
The refueling activities conducted by operations were conducted without incident. The technical support supplied by nuclear engineering was valuable and consistent for all shifts. This support contributed to the successful and timely completion of refueling activities.
Maintenance / Surveillance
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The large number of activities involving this area were well planned, controlled and executed. Many major work activities were on or ahead of schedule. The licensee's conservative operation was illustrated by a
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decision to shut down Unit 2 one day ahead of schedule in response to high gassing detected in the main transformer.
The transformer was in
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the process of being replaced at the end of the report period.
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A non-cited violation was identified during the report period which involved preventive maintenance of an electrical breaker. Although a
procedure was written to address the isolation for maintenance, a
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precaution to prevent an autostart of the Control Room Special Ventilation System was not adequate. The autostart occurred when one train of
chlorine detectors was de energized by isolation of the breaker for maintenance.
The licensee performed 100 percent eddy current testing of steam generator tubes. A regional specialist inspected this area.
Additionally, the licensee performed eddy current testing of feedwater heater and condenser tubing as part of a predictive measurement program.
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Engineering and Technical Support An unresolved item was identified involving the operation of the turbine-driven auxiliary feedwater pump shaf t-driven lube oil pump. This pump is required for operability since it does not require AC power. The engineering group is responding to inspector questions regarding operability of the pump.
The operational problem with the shaft-driven lube oil pump was identified during a surveillance by the licensee and t
was similar to problems which occurred in 1986 and 1987.
A non-cited violation was identified by the licensee involving an
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installation procedure written by technical engineering to install new microprocessor hardware for the ATWS mitigrtion system. The technical engineering group did not fully review a vendor procedure which went beyond the scope of work that was intended to be performed. However, this group also acted conservatively in not relanding leads for the turbine trip signal from this system due to concern for that undesired result.
This conservative action prevented a reactor trip from 77 percent power.
A diesel cooling water pump was rendered inoperable by a fuse losing continuity within its fuse clip.
This was due to fuse clip aging, apparently induced by repeated fuse removal for electrical isolation.. The licensee is planning to submit a letter documenting plans to systematically
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remedy this situation in response to NRC concerns.
A diesel cooling water pump tripped on overspeed.
System engineers determined that the cause of the trip had not affected the operability of the_ pump.
Engineering and technical support for identified problems was i
generally prompt and technically adequate.
Radiation Control Radiological Protection appeared to be well controlled during the outage.
Frequent plant inspection including containment tours indicated strong health physics technician involvement and control.
This is a licensee strength and performance continues to indicate this, i
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Emergency Pretaredness
A Notification of Unusual Event (NUE) was declared due to loss of a
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Control Room Annunciator. System.
The plant resMnsa rss prompt and
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appropriate.
Required repairs were identified t i
and repairs and I
testing were completed in a timely manner. A ref. c,ial specialist
reviewed event classification and concluded that licensee actions were
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appropriate.
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DETAILS 1.
Persons Contacted
- E. Watzl, General Manager, Prairie Island Nuclear Site t
- M. Se11 man, Plant Manager i
- D. Mendele, General Superintendent, Engineering and Radiation Protection
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- G. Lenertz, General Superintendent, Maintenance
- A. Smith, General Superintendent, Planning and Services
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R. Lindsey, Assistant to the Plant Manager D. Schuelke, Superintendent, Radiation Protection
- G. Miller, Superintendent, Operations Engineering
- K. Beadell, Superintendent, Technical Engineering T. Breene, Superintendent, Technical Engineering
- M. Klee, Superintendent Quality Engineering R. Conklin, Supervisor, Security and Services
- M. Wadley, General Superintendent, Operations G. Eckholt, Nuclear Support Services
- J. Leveille, Nuclear Support Services
- A. Hunstad, Staff Engineer
- Denotes.those present at the exit interview of October 2, 1990.
2.
Licensee Action on Previous Inspection Findings (92701)
{ Closed)OpenItem 50-282/88-01-01:50-306/88-01-01: Accuracy of Electrical Drawings.
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The licensee developed a plan to address electrical drawing accuracy and reference concerns.
Phase 1 required an electrical engineering consultant to investigate the condition of and problems with the electrical drawing
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. system at Prairie Island.
In response to the-investigation report, the licensee developed Phase 2 which was intended to apply recommendations l
from Phase 1 to the safety injection system during design basis i
documentation development. This effort provided lessons learned and the
licensee concluded that the drawing improvement effort must be separate I
from systems design basis development, due to inefficiencies experienced.
L The licensee now plans a' third phase-to separately pursue long~ term L
corrective actions to address. drawing accuracy. The inspectors will continue to follow the licensee's efforts in this area as routine followup.
No violations or deviations were identified.
3.
Operational Safety Verification (71707. 93702)
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Routine Inspection Unit 1 operated at full power through the entire report period.
Unit 2 operated in a coastdown mode until September 10, 1990, when a shutdown was commenced at.1635 hours0.0189 days <br />0.454 hours <br />0.0027 weeks <br />6.221175e-4 months <br /> with the unit offline at 1800 hour0.0208 days <br />0.5 hours <br />0.00298 weeks <br />6.849e-4 months <br />s-Unit 2 remained in the refueling outage at the end of the
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report period,
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k A reportable event occurred at 2020 during the Unit 2 shutdown when the 22 Turbine Driven Auxiliary Feedwater (TDAN) Pump autostarted
at the same time botn main feedwater pumps were secured.
The 21 Main Feedwater Pump maintained steam generator levels adequately.
The Unit 2 shutdown procedure 201.3 (Rev. 26) requires a non operating A N pump controller to be placed in the auto-shutdown position prior to securing both main feedwater pumps in order to preclude the autostart signal.
The operator was attempting to stabilize the cooldown rate and jumped ahead in the procedure to remedy the undesired cooldown rate.
By doing so, the operator unintentionally did not perform step 5.17.6 which requires placing the AFW pump mode selector
switches in the auto-shutdown position, prior to securing the 22 Main i
Feedwater Pump.
r Short term corrective action was to identify the source of the
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autostart signal, and secure the pump.
The operator was counseled by manageinent on the requirement of procedures compi.tance.
The event was. discussed at operations shift meetings for all shifts.
Long term corrective actions include discussion of the event during i
routine training, emphasizing procedure compliance. Also, the licensee has initiated a procedure change moving the time of placing the unstarted AFW pump in auto shutdown sooner within the procedure, proving a more systematic progression of events during the shutdown. Operations personnel will review the event during routine training.
The sailure to follow written procedures is a violation of Technical
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Speufications.
Technical Specification 6.5, Plant Operating Procedures, requires:
Detailed written procedures shall be written and followed for areas including (A.) plant operations.
However, the operator did not-perform step 5.17.6 of the Unit 2 shutdown
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procedure, which resulted in an autostart of the 22 TDAFW pump.
This event is a licensee-identified (self disclosing) violation (306/90-14-01) of Technical Specifications.
This licensee-identified violation is not being cited because,the criteria specified in 10 CFR 2. Appendix C Section V.G. of the NRC Enforcement Policy were
satisfied. This exercise of discretion is being given because the
NRC wants to encourage and support 1tcensee initiative for
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self-identification and correction of problems.- A violation must meet a_11 of the following criteria:
(a) It was identified by the licensee; (b) It is normally classified at a Severity Level IV or V; (c) It was reported, if required; (d) It was or will be corrected, including measures to prevent recurrence, within a reasonable time;:
and (e) It was not.a willful violation or a violation that could-reasonably be expected to have been prevented by the licensee's
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corrective action for a previous violation.
j The inspector observed control room operations, reviewed applicable
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logs, conducted discussions with control room operators and observed shift turnovers.- The inspector verified operability of selected emergency systems, reviewed equipment control records, and verified
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the proper return to service of affected components, conducted tours i
of the auxiliary building, turbine butiding and external areas of the plant to observe plant equipment conditions, including potential
fire hazards, and to verify that maintenance work requests had been
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initiated for the equipment in need of maintenance, b.
Control Room Activities i
(1) Loss of NS$5 Annunciator Power
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On August 23, 1990, while operating at 100 percent power, Unit 1 lost power to the Nuclear Steam Supply System (NSSS)
annunciator system.
This system provides power to the annunciator logic for the NSSS systems, and acknowledge power for the Balance of Plant (BOP) annunciator system. The loss of i
NSSS annunciator power occurred at 1443 hours0.0167 days <br />0.401 hours <br />0.00239 weeks <br />5.490615e-4 months <br /> and was immediately observed by the control room operators since the normally lit overhead annunciators had extinguished.
The shif t supervisor directed the 80P annunciators to be tested since no B0P annunciators were previously lit.
All BOP annunciators tested satisfactorily. However, since the NSSS annunciator system was de-energized, the BOP annunciators could
not be acknowledged and thus continued to flash and sound.
-The control room immediately requested the computer staff I
verify that the plant computer was available, and directed
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technical engineering and electricians to investigate the loss of the annunciator system. At 1456 the plant computer was
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verified as operable. At 1457 annunciator power was restored as indicated by the illumination of the normally lit NSSS annunciators. The BOP audio alarm and test mode was then reset.
Testing of the NSSS and BOP annunciators was complete at 1507.
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r At 1500 hours0.0174 days <br />0.417 hours <br />0.00248 weeks <br />5.7075e-4 months <br /> a notice of unusual event (NVE) was declared.
The investigation within the NSSS system cabinet initially
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showed the K-1 relay was chattering, and damage to the relay
was visually apparent.
The technical staff concluded the event had been caused by the intermittent operation of K-1 and replacement was necessary.
At 1655, following a shift meeting and pre-briefing, the NSSS annunciator system was de-energized for K-1.and K-2 i
replacement.
K-2 is a relay that senses _ power available from the primary source and was replaced as a precaution due to
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aging concerns. At 1714 power was restored to the NSSS annunciator system.
At 1738 post maintenance testing was completed and the system was declared operable. At 1745 the NUE was terminated.
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The licensee initially has classified the component failure as age related.
The intermittent operation of K-1 in the form of chattering plausibly explains the loss of power since the relay
changes state in order to select either a primary or secondary power supply.
During the chattering a system engineer observed the relay armature vibrating between the primary and secondary contacts until K-1 selected the primary set of contacts and re-energized the annunciator system.
The unaffected Unit 2 K-1 relay was visually inspected and no damage was identified.
The licensee plans to replace the K-1 and K-2 relays on Unit 2 when replacement parts are available.
The licensee discussed the event classification of the event with a regional emergency preparedness inspector.
In accordance with Emergency Plan Implementing Procedure F3-2, Rev. 11, loss of the NSSS and BOP annunciator systems would not be escalated to an Alert classification unless the plant computer was unavailable. The inspector concluded this guidance was appropriate.
(2) Loss of Control power for No. 12 Diesel Cooling Water Pumg
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On September 5, 1990, at 1404 hours0.0163 days <br />0.39 hours <br />0.00232 weeks <br />5.34222e-4 months <br /> operators observed a control room annunciator that indicated a loss of control power to the No.'12 Diesel Cooling Water Pump.
The operators declared the pump inoperable and investigated the cause of the alarm.
The licensee's findings are described in Paragraph 11.
The pump was declared operable at 2045 hours0.0237 days <br />0.568 hours <br />0.00338 weeks <br />7.781225e-4 months <br />.
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(3) Start _of Auxiliary Feedwater Pumps
On September 5, 1990, at 1523 hours0.0176 days <br />0.423 hours <br />0.00252 weeks <br />5.795015e-4 months <br />, while operating at 77 percent power, the 21 and 22 Auxiliary Feedwater (AFW) pumps
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received an autostart signal. _The pumps started without-incident and were shut down upon source confirmation of the start signal. The unintended autostart signal was generated f rom the ATWS Mitigation System Actuation Circuit ( AMSAC)
. system'during post hardware installation testing.
Unit 2 was in a coastdown mode to the September 12, 1990, refueling outage. - The licensee installed new hardware into the AMSAC system which was in a new location.
The work request approved to install the new AMSAC hardware utilized a vendor (Westinghouse) installation procedure attached to the work request. A separate work request had been written to perform pre-operational' testing.
The vendor installation procedure went beyond installation and included diagnostic testing which would.
provide AFW pump autostart signals.
L Precautions to defeat the AFW pump autostart and turbine trip l
signals'were not implemented within the installation work
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request. The cause was inadequate staff review of the Westinghouse installation proceoure. A more thorough review by the technical engineering staff would have identified that additional precautions were necessary for use of the i
entire Westinghouse installation procedure.
A turbine trip was fortuiteetly avoided by conservative treatment of this logic function during cabinet movement.
The turbine trip logic wiring was lif ted, and due to concern for any unintended turbine trip signals, the leads for this function were not to be relanded until the unit was off line. Thus, when the AMSAC operability test was unintentionally run a turbine trip was generated, but not fully transmitted. The AFW pump start relay logic is different (normally de-energized) and the concern for inadvertent activation by lead mishandling was not as great.
This event will be reported to the NRC by LER 306/90-04-LL.
Short term corrective action included an immediate stoppage of all AMSAC installation work.
Management held a review of work
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conducted which included verification of the autostart signal source. A briefing was then held with all involved personnel to discuss the cause and implications of the event.
Following the briefing, all work invo ving AMSAC was secured until the refueling outage.
Long tc.m corrective action involved a review of the administrative work controls, which were considered adequate with proper usage.
The engineering work group reviewed
the event and was instructed regarding review requirements for procedures added to a work request.
Responsible personnel were individually counseled by management.
The event has been added to engineering and technical support routine training. All groups will review the event report.
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10 CFR 50 Appendix B, Criterion V., " Instructions, Procedures, and Drawings," requires that activities affecting quality shall be prescribed by documented instructions, procedures or
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drawings of a type appropriate to the circumstances.
The work request established to install the new AMSAC hardware wcs inadequately prepared to prevent the AFW pump autostart Juring this work activity, and is a violation (306/90-14-02). A turbine trip and reactor trip from 77 percent power was avoided
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by conservative treatment of the turbine trip AMSAC function by
.the technical staff. The licensee-identified violation is not being cited because the criteria specified in 10 CFR 2, Appendix C, Section V.G. of the NRC Enforcement Policy were
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satisfied.
(4) Autostart of Control Room Ventilation Systems On September 19,1990, at 0350 hours0.00405 days <br />0.0972 hours <br />5.787037e-4 weeks <br />1.33175e-4 months <br />, the Unit I control room
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operator noticed the 122 Control Room Cleanup Fan running.. The
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licensee could not initially determine the cause of the start l
of the cleanup fan. At 0829 the licensee concluded the cause
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was due to inadvertently removing power to the B train of 122 Control Room Special Ventilation System Chlorine Monitors when a 480 VAC Breaker (226) was oe-energized for niaintenance. The de-energization of the B train of chlorine monitors caused an
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autostart of the system.
The breaker was rolled out at approximately 1500 hours0.0174 days <br />0.417 hours <br />0.00248 weeks <br />5.7075e-4 months <br /> on September 18, 1990, which caused tne autostart of the 122 control room special vent system.
This autostart is annunciated on a common control room ventilation alarm section. The licensee believes the autcstart was alarmed, acknowledged, but not recognized as an unintended
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autostart of the system until the later discovery by the oncoming control room operator.
The inspector reviewed the work request procedure for the 226
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breaker maintenance.
The procedure included a precaution to ensure that the train A chlorine monitors were operable or verification that the 122 Control Room Special Ventilation System was running. The shift supervisor signed this step with the understanding that the train A chlorine monitor was operable.
Apparently terknical support and operations did not, via the work ret.est, communicate the fact that de-energizing both B +:ain chlorine monitors would autostart the 122 Control Room Special Ventilation System. The operations shift supervisor did not recognize this potential because the work package provided listed only one of the two B train chlorine monitors as an affected load.
Short term corrective action consisted of verifying the source of the autostart signal and restoring the system to standby status.
Since the chlorine detectors were de-energized, the operability surveillance was conducted to establish proper operation. Operations management has counseled involved
personnel regarding the need for thorough board walkdowns upon shift turnover. The involved engineering staff were counseled regarding the need for more thorough review of procedures involving modified systems.
Long term corrective action
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includes an ongoing effort to update load listings more promptly
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by "on line" updating rather than hard copy listing updates.
This would improve the timeliness of updates to load listings.
The licensee is also making efforts to improve the timeliness of load listings endating.in the modification process, by requiring load listing update prior to modification-closeout. This event will be added to.the engineering and technical staff routine
training and all groups will review the event report.
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Technical-Specification 6.5 Plant Operating Procedures requires:
Detailed written procedures, including the applicable checkoff lists and instructions shall be prepared for activities including (C.) Maintenance and Test. Maintenance and Test procedures will be developed-for preventive maintenance of plant equipment that could have an effect on nuclear safety.
The maintenance procedure developed for. work on breaker 226 did not meet the above requirement to satisfy the routine preventative maintenance
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activity.
This is a violation (282/90-14-03). The licensee-identified violation is not being cited because the criteria specified in 10 CFR 2, Appendix C, Section V.G. of the NRC Enforcement Policy were satisfied.
The licensee will report
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this event as LER 282/90-14-LL.
(5) On September 16, 1990, at 0744 hours0.00861 days <br />0.207 hours <br />0.00123 weeks <br />2.83092e-4 months <br />, the Unit I rod control system experienced an urgent failure on Power Cabinet 2 AC.
The licensee declared the control rods for banks A and C
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inoperable, although the rods were onty electrically unmovable.
This places the plant in an eight hour Limiting Condition for
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Operation (LCO). The safety function of insertion into the core upon a reactor trip signal was available.
At 1244,
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following rod control power cabinet card replacement and i
testing, the rods were declared operable.
The licensee has recognized the need to address, within Technical Specifications, rod control inoperability by loss of electrical movement (versus mechanical binding).
The licensee plans to submit a license
amendment request to clarify this issue.
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(6) Autostart of Component Cooling Pump On September 23, 1990, while Unit 2 was in cold shutdown, an autostart occurred on the 22 Component Cooling (CC) Pump. A
control room operator had started the 22 Residual Heat Removal'
(RHR) pump and secured the 21 RHR pump.
To facilitate RHR heat exchanger (Hx) CC flow to both Hxs during this transient, the second (22) CC pump was started. Once 22 RHR pump operation
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stabilized,lthe unit operator secured 22 CC pump.
In accordance with recent experience gained on CC pump shutdown (ref. LER 282/90-09-LL), to prevent an autostart, the operator held the pump controller in the off position until system pressure stabilized.
However, in this instance, when the.
I controller was released to neutral the 22 CC Pump autostarted..
on low pressure. The root cause of'the autostart is under investigation by the licensee. A CC system piping difference exists between Unit 1 and Unit 2 that requires the same train of.RHR (pump and Hx) and CC pump on Unit 2, while Unit I does not. The licensee has not procedurally addressed CC pump operation with respect to RHR train operation..The inspector will review this event for root cause analysis and system piping differences during the next inspection period.
Unresolved Item 306/90-14-04.
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No other Molations or deviations were identified.
4.
Maintenance Observation (71707, 37700, 62703)
Routine, preventive, and corrective maintenance activities were observed to ascertain that'they were conducted in accordance with approved procedures, regulatory guides, industry codes or standards, and in conformance with Technical Specifications.
The following items.were t
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P considered during this review:
adherence to Limiting Condition for i
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
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components or systems to service, quality control records were maintained, activities were accomplished by qualified personnel, radiological controls were implemented, and fire prevention controls were implemented.
Portions of the following maintenance activities were observed or e
reviewed during the inspection period:
a.
Investigation of No.11 Auxiliary Feedwater Pump Auxiliary Lube Oil Pump Failure to Shut Off b.
Replacement of ISVI-SB-Turbine Stop Valve Relay Train B.
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performance of SP 1035A Reactor Protection Logic Test at Power, a
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BFD relay failed to operate in a timely manner. The cause was a lack of smooth movement of the relay plunger.
The relay was replaced with an onsite spare BF0 relay and the surveillance was completed.
During the process of replacing the relay, a functional test was performed. More involved response time testing was not required since the affected circuit was the turbine stop valve closure turbine trip and not a reactor protection reactor trip (less time dependent).
i The inspector discussed with the licensee application of Technical Specification requirements during the time one channel of the Reactor Protection System (RPS) is in a test mode and a reactor trip bypass breaker is installed.
The licensee currently lacks formal guidance regarding necessary actions upon exceeding the four hour LCO for reactor trip bypass breaker operation.
The licensee
. intends to develop appropriate guidance and plans to submit a license amendment request for a more specific LCO regarding reactor trip bypass breaker operation. A nonconforming item report (NIR
- 0275) was written to investigate and resolve this BFD relay failure, c.
Repair of Emergency Diesel Generator (EDG) 1 Constant Lube Oil Pump.
On August 22, 1990, the EDG 1 constant lube oil pump was discovered nonfunctional by the turbine building operator.
This pump circulates lube oil from the crankcase to a heat exchanger to maintain a warm i
lube oil temperature.
The operation of this pump is important since the licensee considers the EDG inoperable if lube oil temperature falls'below 100 degrees F.
The auxiliary building operator discovered the lube oil pump was not running following a routine operability test of EDG 1.
Following the operability test an operator had questioned the status of the lobe oil pump, since it was not running.
Due to a logic drawing error, the operations-shift concluded the constant lube oil pump not running was the normal / proper status.
Following a shift
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change during log taking, the oncoming auxiliary building operator questioned the status of the constant lube oil pump in response to relatively lo.y (106 degrees F) lube oil temperature.
The operations shift management promptly recognized the situation and started the EDG to raise temperatures.
The pump was repaired by an emergency work request without incident.
d.
Replacement of EDG 2 cylinder liners.
During preventive maintenance of EDG 2 the cy M nder liner threads for a fuel line-to-cylinder liner adapter were found to be damaged.
This required replacement of the cylinder liner.
Following replacement of the cylinder liner a hydrotest of the EDG water jacket was required; during the hydrotest a water leak was found on another cylinder liner.
This cylinder liner was also replaced.
Replacement of cylinder liners requires the disassembly and removal of the upper crankline. During reassembly of the upper crankline a bolt was dropped into another cylinder, scratching and denting the chrome surface of the inner surface of the cylinder itner. The 'icensee stoned the scratch smooth and discussed continued use of the cylinder liner with the manufacturer. After this discussion the licensee performed a formal evaluation of the cylinder liner condition and decided to operate the.EDG without replacing the dented cylinder.
The licensee will continue to monitor the condition of the dented cylinder liner and the inspectors will review the results of this monitoring during future inspections.
The licensee's preventive maintenance was conducted during a seven-day LCO.
The work was initially planned to be completed in four days; however, due to the problems identified during the work, operability testing was completed during the seventh day.of the LCO.
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Troubleshooting of 12 Diesel Cooling Water Pump overspeed trip.
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No violations or deviations were identified.
3, Surveillance (61726, 92701)
The Inspector witnessed portions of surveillance testing of safety-related systems and components.- The inspection included verifying that the tests were scheduled and performed within Technical Specification requirements, observing that procedures were being followed by qualified operators, that Limiting Condition for Operation (LCO)
appeared not to be violated, that system and equipment restoration was completed, and that test results were acceptable to test and Technical Specification requirements.
SP1106A Diesel Cooling Water Pump Test-(12). When this test was
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performed the diesel tripped on overspeed..The operators declared the pump inoperable.
The licensee response to this event is discussed in paragraph 11.
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SP1106B Diesel Cooling Water Pump Test (22).
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SP1047 Control Rod Exercise.
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SP1102 Steam Turbine-Driven Auxiliary Feedwater Pump Test.
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During this test the electric-driven lube oil pump did not stop af ter the turbine started.
The operators noted this condition and declared the auxiliary feedwater pump inoperable. The licensee response to this event is
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discussed in paragraph 11.
No violations or deviations were identified.
6.
Inspector Followup on Information Notice (Closed) Information Notice 88-46, Supplement 1:
Licensee Report of Defective Refurbished Circuit breakers This information notice and its supplement I were reviewed during a Vendor Inspection Branch team inspection of procurement at Prairie Island (reference NRC Inspe: tion Report 282/88-201; 306/88-201).
The inspection found the licensee evaluation and actions in response to the information notice inadequate. The licensee stated a reassessment would be performed in response to this conclusion.
In the licensee response to findings from the procurement inspection dated November 20, 1989, the licensee stated the information notice was superseded by NRC Bulletin 88-10, which required a timely response.
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NRC Bulletin 88-10. Nonconforming Molded-Case Circuit Breakers, was issued August 3, 1989.
NRR reviewed licensee responses for both Bulletin
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88-10 and Supplement 1, and, by letter dated March 7, 1990, informed the licensee the responses were considered completed, although subject to later inspection.
Remaining issues in this area will be followed by procurement inspection followLp and/or inspection of Bulletin 88-10, No violations or deviations were identified.
7.
Temporary Instructions (SIMS S8-17, 2515/103)
[ Closed)TI2515-103:
Loss of Decay Heat Removal (Generic Letter No.
88-17),10 CFR 50.54(f) Programmed Enhancements
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Loss of decay heat removal (DHR)' capability during nonpower operation and the consequences of such a loss have been of increasing concern throughout the nuclear industry.
Operating a plant with a reduced reactor coolant o
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system (RCS) inventory was determined to be a particularly sensitive condition. Generic Letter (GL) 88-17 required licensees to respond to NRC recommendations for " expeditious actions" and " programmed enhancements."
TI 2515/101 was used to review the licensee's response to the recommended expeditious actions. This review was described in Inspection Report No.
50-282/89-08(DRP); 50-306/89-08(DRP)..The purpose of TI 2515/103 is to
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review the licensee's response to the recommended programmed enhancements.
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05.01 General:
The inspectors reviewed the licensee's response to GL 88-17 submitted January 6,1989.
The submittal provided responses to the NRC recommendations for expeditious actions and programmed enhancements.
Comments on the response to specific recommendations follow.
The licensee does not plan to use all of the programmed enhancements until the next scheduled Unit I refueling outage.
However sufficient work has been accomplished to allow evaluation.- Several items were identified that do not comply with the guidance provided to the inspectors. These items have been discussed with the Licensing Project Manager and R:gion III management and the inspectors are awaiting further guidance.
05.02 Instrumentation a.
RCS level:
Four indications of RCS water level will be available in the control room for each unit during mid-loop operations, Two of these indicators were installed in Unit I during its January 1990 refueling outage and two are being installed in Unit 2 during its current refueling outage. The newly installed indicators are intended to meet the requirements of GL 83-17.
Each unit will alsc, retain a plastic tubing level indicator and a wide range refueling canal level indicator, In each unit one new level transmitter senses pressure between the 5+eam generator and the reactor coolant pump in each RCS loop.
Eact '=1nsmitter provides an output signal to a common "D2-REDUCED INVENioRY," CRT display.
The transmitters have independent non-safety related power supplies.
The control room operator may select from a variety of CRT locations for display of the REDUCED INVENTORY screen.
The output of each transmitter is individually displayed on the CRT as a wide range (0-100")
indication and a narrow range (0-28") indication. With RCS pressure at containment pressure an indication of 0" is.75" above the bottom of the RCS hot leg. An indication of 100" is about one foot above the reactor vessel flange. The level is displayed graphically and numerically.
The level indication is not compensated for
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differences between RCS pressure'and containment pressure. The level indicators provide a high level alarm and a low level alarm.
The alarm is annunciated as a DHR trouble alarm. The source of the alarm is indicated on an alarm display.on the REDUCED INVENTORY CRT display. The licensea has not yet established specific alarm setpoints for the alarms.
The licensee plans to make-the setpoint for the low level alarm slightly below the normal mid-loop operation level. The licensee does not plan to provide alarms for inadvertent entry into a reduced inventory or mid-loop operation, or upon loss of= sufficient level for reliable RHR pump operation.
b.
R'S temperature: The licensee will provide three incore
- H ermocouple inputs for the common CRT REDUCED INVENTORY display.
These will be.available whenever the head is on the reactor vessel.
High temperature as indicated by the incore thermocouples will be annunciated as a DHR trouble alarm.
There will be no reactor vessel RCS temperature indication available with the head removed.
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DHR System Monitoring: The licensee will monitor DHR system
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MrformancewiththeREDUCEDINVENTORYCRTdisplay.
DHR pump motor current and pump suction pressure will be displayed graphically and numerically along with other DHR parameters and an active mimic of the system. A 30-minute historical trace of seven indicators including motor current and suction pressure will be included on the CRT display.
Low motor current or low suction pressure will be annunciated as a DHR trouble alarm and each has a visual alarm block on the CRT display.
5.03 Procedures: The licensee has not yet issued procedure revisions or new procedures that address all programmed enhancements. The licensee plans to have all required procedures in effect prior to the next entry into reduced inventory conditions.
The inspectors used a checklist provided by Region III to ve ify that the current procedures were adequate. This verification was completed before the licensee reduced RCS inventory during the current Unit 2 refueling outage. The inspectors will review the licensee's new or revised procedures before the next plant entry into reduced inventory.
5.04 Equipment: The inspectors reviewed the equipment requirements based on current procedures. New or revised procedures incorporating the programmed enhancements will also be reviewed before the next reduction of RCS inventory.
a.
Adequate reliable equipment was provided for normal core cooling, including support equipment. The licensee has not removed the autoclosure interlock (ACI) for the DHR suction valves.
Westinghouse analysis WCAP-12197, " Residual Heat Removal System Autoclosure Interlock Removal Report for the Prairie Island Nuclear Plant Units 1 and 2," was completed in July 1989. Although the licensee plans to remove the ACI, based on WCAP-12197, it has not yet resolved all related technical issues, b.
The licensee provides two reliable means of cooling the core.
(i) One high head safety injection pump is provided.
(2) Two charging pumps are provided as another method of core cooling. A steam generator (SG) is also provided until one primary manway is removed.
(3)
It was not necessary to evaluate or test the injection flow paths.
(4) Long term heat removel was considered in the event the alternate-methods of cooling are required.
If a SG is operable, a 6G power operated relief valve and an auxiliary feedwater pump are also required to be operable. The licensee requires two containment cooling fan coil units to be operable during RCS reduced inventory operation.
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(5) Licensee procedures require sufficient support equipment to be available during RCS reduced inventory operation, c.
Licensee procedures require that reliable communications be established between the control room and appropriate personnel outside the control room.
5.05 Analyses:
The analyses that the licensee uses to prepare the programmed enhancement procedures will be reviewed in conjuction with the future review of the programmed enhancement procedures.
5.06 Technical Specifications:
No technical specification changes have been identified.
5.07 RCS Perturbations:
The licensee's current procedure controlling RCS reduced inventory operations forbids operations that would perturb the RCS or supporting systems during a reduced inventory condition. When the programmed enhancement procedure development is complete, the inspectors will review them for centrols of RCS perturbations.
No violations or deviations were identified.
8.
, Refueling Activities (60710)
The inspectors. observed three shifts of refueling activities.
The inspectors confirmed that:
core monitoring was in accordance with Technical Specification (TS) requirements; fuel accountability methods
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were in accordance with the fuel shuffle procedure; vessel and spent fuel pool water levels were maintained as required; and boron concentration and boron flow path availability were checked on a per shift basis.
The inspectors also confirmed that the TS required staffing was maintained, i
and that 1/m plots were updated with each fuel assembly insertion.
Adequate radiation protection controls were observed in the refueling and-spent fuel pool areas.. Provisions to protect.against foreign objects falling into the open reactor vessel were observed to be adequate.
No violations or deviations were identified.
9.
Engineering Safeguard Features (ESF) System Walkdown and System Focus (71710, 61626)
The inspector performed a walkdewn of the Emergency Diesel Generator (EDG) No. 2 and observations included confirmation of selected portions of the licensee's procedures, checklists, verification of correct valve and power supply breaker positions to insure.that plant equipment and instrumentation were properly aligned, and local system indication to insure proper operation within prescribed limits.
Several minor discrepancies were noted between the procedure and equipment status.
Additionally equipment in need of minor repairs was discovered. These matters were discussed with the licensee.
The constant lube oil pump required repair during this walkdown.
The EDG-1 constant lube oil pump
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also required repair during the report period (reference paragraph 4.c).
The inspectors will follow this repair during the next report period.
Portions of the following checklists were utilized to conduct the walkdown:
01.1.20.7-7, Diesel Generator D2 MCR Electrical Console G-1 Switch and Indicating Light Status, Rev. 4 C1.1.20.7-6, 02 Diesel Generator Auxiliaries and Room Cooling Local Panels, Rev. 3 C1.1.20.7-5, 02 Diesel Generator Valve Status, Rev. 7 C1.1.20.7-8, 02 Diesel Generator Circuit Breakers and Panel Switches, Rev. 8 No violations or deviations were identified.
10.
Licensee Event Report (LER) Followup (92701 & 92700)
a.
(Closed) LER 306/88-02-LL: Diesel Generator Outpit Breaker Did Not Close During Surveillance.
On December 8, 1988, both units were at 100% power.
U1 Emergency
> Diesel Generator (EDG) was inoperable for scheduled maintenance.
The daily operability test of D2 Emergency Diesel Generator was being performed in accordance with Technical Specification requirements. At 0927, the control room operator attempted to close the D2 Emergency Diesel Generator Output Breaker 25-6 using the control board control switch and the breaker did not close.
Breaker 25-6 was declared operable at 1025 following inspection and repeated satisfactory testing of the control room control switch and the breaker.
A licensee conducted review of the maintenance records of the breaker did not identify any problems which could have resulted in breaker 25-6 failing to close. The breaker underwent routine preventative maintenance in January 1988.
Investigative reports for events involving 4.16 KV breakers were reviewed and operations personnel were interviewed.
No similar occurrences were found.
All control room diesel generator panel switches associated with D2 Emergency Diesel Generator were removed, inspected, and cleaned during the January 1989 maintenance outage for D2 Emergency Diesel Generator.
The training on circuit breaker operations was reviewed to assure there were no deficiencies identified.
Since this event there has been no repeat occurrence.
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b.
(Closed) LER 282/88-07-LL: Automatic Initiation of Train A of Auxiliary Building Special Ventilation System as a Result of Radiation Monitor Spike.
On October 29, 1988, both units were operating at full power. At 0330 hours0.00382 days <br />0.0917 hours <br />5.456349e-4 weeks <br />1.25565e-4 months <br />, a spike on radiation monitor IR-37 caused an automatic start of the 121 Auxiliary Building Special Ventilation System (ABSVS).
Investigation showed the radiation monitor to be in alarm with a normal response indicated by its meter.
Since there was in fact no high radiation condition, the ABSVS was returned to its normal standby condition.
A spike on IR-37 radiation monitor caused the high radiation alarm which triggered the event.
The spiking on radiation monitor IR-37 was determined to be the result of a failure of the radiation monitor detector.
The most probable cause of the failure was the-absorption of halogen quench gas.
Some evidence of sporadic response was indicated in the-trending of this detector; however, no conclusive evaluation was determined from the data.
The most probable cause of the detector failure was concluded to be the age of the GM tube, which was at the end of its normal life.
The event was not reported within the time requirements of 10CFR50.72; This concern was addressed within inspection report 50-282/88-19; 50-306/88-19, paragraph 3, and determined to be a non-cited violation.
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There have been multiple reportable events involving spiking 'of radiation monitors (reference LERs 282/88-11-LL; 89-08-LL; 89-16-LL; 89-18-LL). The licensee has an upgrade plan to filter the electronic output signal-from radiation monitors. The licensee has also replaced detectors and cabling for radiation monitors since the event as a partial solution system upgrade.
The licensee is utilizing LER-282/89-18-LL to track corrective actions.
Two revisions to the LER have been submitted regarding the long term-corrective action of electronics upgrading. The inspectors will follow licensee corrective actions by LER 282/89-18-LL.
c.
(Closed) LER 282/88-08-LL: Gaseous Effluent Analysis Not Complete When Effluent Samples Were Lost Enroute to Contractor's Laboratory.
Technical Specification 4.17.B.I.c requires that each gaseous effluent release path be analyzed for Sr-89 and Sr-90 on a quarterly composite particulate sample.
Plant personnel collect the particulate filter samples; the Sr-89 and-Sr-90 analyses are conducted by Teledyne Isotopes Midwest Laboratory. At the completion of each quarter, the particulate filters are packaged i
with other liquid composite samples and shipped to Teledyne for analysis.
On November 2, 1988, Teledyne informed the plant by telephone that the third quarter 1988 particulate samples listed on the shipping
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documents could not be located. A search of the Count Room and Warehouse were made and interviews with warehouse and radiation protection personnel were conducted. All radioactive composite samples are shipped by the same individual each quarter. Other warehouse and radiation protection personnel witnessed that the particulate filters were packaged and shipped.
The licensee notified Teledyne that NSP was confident the samples had been shipped.
The contractor had discarded the shipping material so it couldn't be searched further.
Teledyne QA personnel initially did
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not report any damage to the shipping container; they later reported there may have been a small tear but they did not feel it was large enough for the filter package to escape.
United Parcel Service was also notified with negative location results.
In response to the event, the licensee implemented several actions.
A value of S 1.0 E-14 for Sr-89 and Sr-90 was assigned to each airborne release path for third quarter 1988 based on an analysis detailed within the LER.
Regional Specialists reviewed this compensating measure and found the action appropriate.
The' licensee also discontinued use of Teledyne Laboratory in favor of another contract laboratory.
This labo atory had been previously used by the licensee and the licensee had previously performed a quality assurance audit on the laboratory.
The lic.ensee also performs beta counts of the particulate filters by procedure (Radiation Protection Implementation Procedure 4512, Rev. 1)
since the event as a backup radiation release indicator. The licensee also has improved shipping container labeling and coloring.
There have been no repeat occurrences since the event.
d.
(Closed) LER 282/88-11-LL: Auto-Start of Train A of Auxiliary Building Special Ventilation System as a Result of Radiation Monitor Spike.
In December 29, 1988, both units were operating at 100% power. At 0809 a spike on radiation monitor IR-37 caused an automatic start of the 121' Auxiliary Building Special Ventilation System (ABSVS).
Investigation showed the radiation monitor to be in alarm with a normal response indicated by its meter.
Since there was in fact no high radiation-condition, the ABSVS was returned to its normal standby condition.
Further investigation included electronic troubleshooting.and
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inspection of cable and circuit board connections; no cause for the
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spiking could be found. The monitor appeared to function properly before and after the event.
As discussed above, the licensee has implemented several corrective actions for auxiliary building radiation monitor spiking problems.
Corrective action is-being followed by: LER 282/89-18-LL.
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e.
(Closed) LER 282/89-08-LL: Auto-Start of Train A of Auxiliary Building Special Ventilation System as a Result of Radiation Monitor Spike.
On,1une 18, 1989, both units were operating at 100% power. At 0025 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br />, the control room received a Train A High Radiation alarm, which initiated an automatic start of the 121 Auxiiiary Building Special Ventilation System (ABSVS).
Radiation monitor IR-37, which actuates the ABSVS, was found to be in alarm with a normal response indicated by the meter located on the monitor.
Since there was in fact no high radiation condition in the Auxiliary Building, the ABSVS was returned to the normal standby condition.
Further investigation including electronic troubleshooting and inspection of cable and circuit board connections found no cause for the spiking, The monitor appeared to function properly before and after the event.
As discussed above, the licensee has implemented several corrective actions for auxiliary building radiation monitor spiking problems.
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Corrective action is being followed by LER 282/89-18-LL.
f.
(Closed) LER 282/89-16-LL: Auto-Start of Train B of Auxiliary Building Special Ventilation System as a Result of Radiation Monitor Spike.
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On September 8, 1989, both units were operating at 100% power. At 1555 hours0.018 days <br />0.432 hours <br />0.00257 weeks <br />5.916775e-4 months <br />, the control room received a Train B High Radiation alarm, which initiated an automatic start of the-Auxiliary Building Special Ventilation System (ABSVS).
This was a non-Engineered Safeguards Feature actuation of an.ESF system.
Radiation monitor 2R-30, which actuates the ABSVS, was found to be in alarm.
Since
.there was in fact no high radiation condition in the Auxiliary Building, the control room operator reset the alarm on the radiation monitor and returned the ABSVS to the normal standby condition and returned the Auxiliary Building Normal Ventilation System to r
service.
The radiation monitor detector tube and one electronic card were replaced and the monitor tested satisfactorily.
In the corrective action section of the_LER the licensee described a planned radiation monitor upgrade.
This long term corrective action i
was scheduled to be completed by December 31, 1990.
In LER
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282/89-16-LL, the licensee revised the schedule date to February 1990. This date was revised to September 1990 within Revision 2 l
dated March-30, 1990. The corrective actions for radiation monitors will be followed by LER 282/89-18-LL and its revisions.
No violations or deviations were identified.
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11.
Engineering and Technical Support (92701)
The inspectors reviewed the following events which required investigation by licensee engineers:
a.
On August 29, 1990, during surveillance testing, the main (shaf t-driven) lube oil pump for the 11 Auxiliary Feedwater
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(AFW) Pump did not develop a high enough discharge pressure to activate the pressure switch that stops the electric (alternating current) auxiliary lube oil pump. The licensee declared the AFW pump inoperable and added oil to the AFW pump sump in an unsuccessful attempt to remedy the problem.
Later the pump was taken out of service to further investigate the problem. The licensee found that the installed oil check valves were not as described in the pump vendor's documentation and that the oil piping configuration allowed air to be forced into the main lube oil pump. The licendee determined that increasing the oil level in the sump would prevent air from degrading the performance of the main lube oil pump.
The inspectors reviewed an October 19, 1979, letter from the NRC to the licensee,
"NRC Requirements for Auxiliary Feedwater Systems at Prairie Island Nuclear Generating Plant, Units 1 and 2".
fhe letter required the licensee to ensure that one AFW pump would be capable of operating for two hours without alternating current (AC) electric power. The inspectors discussed this issue with the NRC Licensing Project Manager who confirmed that a turbine-driven AFW pump must be capable of operating for two hours without AC a
'r to be considered operable. At the end of the. inspection period the,icensee had not completed its evaluation of whether or not the 11 AFW pump was operable before the sump level was increased. This item is unresolved (50/282-90-14-05) pending the inspectors' review of the licensee's operalility determination and the adequecy of the licensee's control and testing of the AFW lube oil check valves.
b.
On_ September 5, 1990, control power was lost for the 12 Diesel Cooling Water Pump. The licensee' declared the pump inoperable and investigated the problem. A OC control power fuse was-found to be loose in its fuse clips. The licensee placed clamps on the fuse clips for both control power fuses and the punip was restored to-service. Discussion with licensee personnel revealed that a similar problem had occurred with this circuit in September 1988 and fuse clip clamps were installed at that time. This was considered to be a plant equipment aging issue and was included in a proposed program for resolution-of several electrical equipment aging issues.
It appears that repeated removal and reinsertion of the fuses for electrical isolation for maintenance cause the fuse clips to lose strength.
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The licensee is preparing a letter to the 14RC which will describe its corrective actions for this event and other electrical equipment-aging issues.
The NRC will review the licensee's corrective actions and follow aging issues at Prairie Island.
c.
On September 20, 1990, during surveillance testing of the 12 Diesel Cooling Water Pump, the diesel tripped on overspeed. The system:
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engineer reviewed the event and determined that the governor response allowed the diesel to reach the overspeed trip setpoint of 1350 RPM.
However, after review of the manufacturer's literature and the pump
performance during a recent integrated Safety Injection test, the i
licensee concluded that the pump was operable.
This conclusion was based on the fact that the overspeed trip is bypassed during an i
emergency (safety injection) start of the diesel and vendor guidance which indicates a momentary overspeed of the diesel does not affect its performance. The licensee concluded that the overspeed was caused-by a combination of system flow conditions and slow governor response.
- The governor response was adjusted and the pump was successfully tested.
No violations or deviations were identified, i
12.
Unresolved Items Unresolved items are matters about which more information is required in i
order to ascertain whether they are acceptable items, violations, or
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deviations. ' Unresolved items identified during the inspection are discussed in Paragraphs 3.b.6 and 11.a.
13.
v solations for Which a " Notice of Violation" Will Not be Issued i
The NRC uses the Notice of Violation (NOV) as a standard method for
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formalizing'the existence of a violation of a legally binding l-requirement, However, 10 CFR 2, Appendix C, Section V.G. has been
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changed to provide the staff with the flexibility not to issue a Notice l
of Violation for NRC or licensee identified inspection findings.
Such
' violations are by definition of minor safety concern.
- Three violations of regulatory requirements identified during the
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inspection for which a Notice of Violation will not be issued are discussed in Paragraph 3.a., 3.b.(3), and 3.b.(4).
14.
Exit (30703)
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'he inspectors met with the licensee representatives denoted in' par? graph i
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I at the conclusion of the report period on October 2, 1990.
The
~ inspectors discussed the purpose and scope of the inspection and the fin lings.
This discussion included the three non-cited violations and-two inresolved items contained within the report.
The inspectors also i
l discussed the likely information content of the inspection. report with regard to documents or processes reviewed by the inspectors during the
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inspection.
The licensee did not identify any. documents or processes as
proprietary.
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