IR 05000409/1981021
| ML20040H000 | |
| Person / Time | |
|---|---|
| Site: | La Crosse File:Dairyland Power Cooperative icon.png |
| Issue date: | 01/29/1982 |
| From: | Branch M, Farney W, Hunter D, Streeter J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20040G993 | List: |
| References | |
| TASK-2.B.4, TASK-2.E.4.2, TASK-2.K.3.19, TASK-2.K.3.27, TASK-TM 50-409-81-21, IEB-81-02, IEB-81-2, IEC-81-04, IEC-81-09, IEC-81-13, IEC-81-4, IEC-81-9, NUDOCS 8202160716 | |
| Download: ML20040H000 (14) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No. 50-409/81-21 Docket No. 50-409 License No. DPR-45 Licensee: Dairyland Power Cooperative 2615 East Avenue - South La Crosse, WI 54601 Facility Name: La Crosse Boiling Water Reactor Inspection At: La Crosse Site, Genoa, WI Inspection Conducted: September 1 through December 21, 1981 Inspectors P
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W9/8z Mb I/2M82.
(December 81 only)
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0" s/69 A67 Approved By:
D. R. Hunter, Chief
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Projects Section 2B Inspection Summary Inspection on September 1 through December 21, 1981 (Report No. 50-409/81-21)
Areas Inspected: Routine resident inspection of licensee's 9perational Safety, Maintenance Activities, Surveillance Testing, Preparation for Refueling, Onsite and Offsite Review Committee Activities, Semi-Annual Review of Plant Operation, Inspection and Enforcement Bulletin Followup, Inspection and Enforcement Circular Followup, TMI Task Action Plan Item Followup, Followup on Plant Scrams, Followup on Open Inspection Items and Attending of Public Meetings. The inspection involved a total of 340 inspector-hours onsite by two NRC inspectors including 51 inspector-i hours onsite during offshifts.
Results: No items of noncompliance or deviations were identified.
8202160716 820129 PDR ADOCK 05000409 O
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DETAILS 1.
Persons Contacted
- R. Shimshak, Plant Superintendent
- J. Parkyn, Assistant Plant Superintendent
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- G. Boyd, Operations Engineer
- L. Goodman, Operatices Engineer H. Towsley, Quality Assurance Supervisor
- S.
Rafferty, Reactor Engineer M. Polsean, Shift Supervisor W. Nowicki, Supervisor, Instrument and Electric R. Wery, QA Specialist
- G. Joseph, Security & Fire Protection Supervisor
- L. Kelley, Assistant Operations Supervisor
- P.
Shafer, Radiation Protection Engineer
- B. Zibung, Health & Safety Supervisor
- R.
Brimer, Electrical Engineer D. Rybarik, Mechanical Engineer
- Denotes those present at exit interview.
2.
Operational Safety Verification The inspectors observed control room operations, reviewed applicable logs and conducted discussions with control room operators during the period from September 1 through December 21, 1981. The inspectors verified the operability of selected emergency systems, reviewed tagout records and verified proper return to service of affected components.
Tours of the reactor building and turbine building were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations and to verify that maintenance requests had been initiated for equipment in need of maintenance. The inspector by observation and direct interview verified that the physical security plan was being implemented in accordance with the station security plan.
The inspectors observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls. During the period from September 1 through December 21, 1981, the inspectors walked down the accessible portions of the No. IA and IB Emergency Diesel Generator systems, the Shutdown Condenser system and the Boron Injection system to verify operability.
These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under technical specifications, 10 CFR, and administrative procedures.
No items of noncompliance or deviations were identified.
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3.
Monthly Maintenance Observation Station maintenance activities of safety related systems and components listed below were observed / reviewed to ascertain that they were conducted j
in accordance with approved procedures, regulatory guides and industry
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codes or standards and in conformance with technical specifications.
The following items were considered during this review:
the limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were 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
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control records were maintained; activities were accomplished by quali-
-l fied personnel; parts and materials used were properly certified; radiological controls were implemented; and, fire prevention controls were implemented.
Work requests were reviewed to determine status of outstanding jobs and to assure that priority is assigned to safety related equipment maintenance which may affect system performance.
The following maintenance activities were observed / reviewed:
a.
Replacement of Nuclear Instrument Channel No. 8 detector and cable connectors, b.
Repairs to Control Rod Drive (CRD) Hydraulic Pump discharge valve.
c.
Repairs to Forced Circulating Pump Coupling Oil System (Main-tenance Request MR-0947).
d.
Inspection and Trouble Shooting of No. IB Reserve Feed Breaker (252-RIB).
Repairs to Control Drive (CRD) Hydraulic Pumps No. IA and IB.
e.
Following completion of maintenance on the Nuclear Instrumentation Channel No. 8 equipment, the inspectors verified that this system had been returned to service properly.
The problem with the (CRD) Hydraulic Pump discharge valve appears to be a recurring problem and the plant engineering staff is considering a facility modification as a 1cng-term correction of the problem.
Following completion of maintenance on the No. IB Reserve Feed Breaker (252-RIB), the inspectors verified that this system had been returned
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to service properly.
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No items of noncompliance or deviations were identified.
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4.
Monthly Surveillance Observation The inspector observed technical specifications required surveillance testing on the Reactor Safety Channel No. 1, the bi-weekly test of Radiation Monitoring equipment, the weekly Station Battery checks, and the Emergency Service Water Supply System (ESWSS) pump fuel check and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that limiting conditions for operation were met, that removal and restoration of the affected components were accomplished, that test results conformed with technical specifications and procedure requirements and were reviewed by personnel other than the individual directing the test, and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
The inspectors also witnessed and reviewed portions of the following test activities:
No. lA and IB Emergency Diesel Generator Monthly Test; No. IA and IB High Pressure Service Water Diesel Monthly Test; Monthly-Test of Nuclear Instrument Scram Contacts; and the Fire Suppression System Valve Line-up. The inspectors noted that the valve line up check sheet for the fire suppression system required the manual valves necessary for automatic actuation of the Main Power Transformer Spray to be closed. This item was oiscussed with the Fire Protection Supervisor who stated that the valves were correctly in the closed position since the automatic mode of opera-tion for this system is not required until November 1, 1981. This item is considered unresolved (409/81-21-01).
The monthly surveillance verification of the supply for the four (ESWSS)
pumps revealed that all four pumps contained less than the required 5.0 US gallons of gasoline. The li'ensee investigated this event and determined that one possible cause w, air being trapped in the tank during the filling process. The filling procedure is being modified to eliminate the entrapment of air during the filling process.
This item is the subject of licensee Reportable Occurrence No. 81-12.
No items of noncompliance or deviations were identified.
5.
Preparations for Refueling The inspectors reviewed the New Fuel Receipt Inspection Procedure (OP-30-03) to ensure that a technically adequate and properly approved procedure was available for the receipt, inspection and storage of new fuel. The inspectors also observed receipt, inspection and storage of new fuel elements designated as 4-1, 4-4, 4-5 and 4-7 to ensure performance in accordance with procedure OP-30-03.
It was noted during a review of documentation for the receipt inspection of fuel elements 4-17 thru 4-24 that the licensee discovered that the chamfer on the upper tie plates for these elements was not in accordance-4-
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with the design requirements. The licensee issued a material deficency report and the discrepancy was corrected by an Exxon field representative.
The discrepancy was related to a plant imposed design modification to insure freedom of installation and res> val and was not of safety concern.
The inspectors' expressed concern that the discrepancy was not detected j
during the normal receipt inspection process by the supplier or receiver.
No items of noncompliance or deviations were identified.
6.
Onsite and Offsite Review Committee Activity a.
Onsite Review Committee (ORC)
(1) The inspectors attended the onsite Operations Review Com-mittee (ORC) meeting of November 12, 1981, a nonparticiprnts and observed the following:
The meeting was conducted in accordance with the provisions of the Plant's Technical Specifications and the members in attendance provided expertise in the areas that were dis-cussed and constituted a quorum.
There was an air of informality at this meeting with the members including the minute taker, entering and exiting at will. This informal manner could lead to important matters being improperly assessed and also a loss of con-tinuity from meeting to meeting.
These observations were discussed with plant management for correction and will be reviewed on a subsequent inspection.
This item is an outrtanding inspection item (409/81-21-02).
(2) The inspectors reviewed the minutes from th.e following ORC meetings and noted that none of the minutes contained a minority report and there appeared t.o be an absence of an effective tracking method to ensure followop of unresolsed items from meeting to meeting:
The meeting reviewed were ORC-80-1, ORC-80-2, ORC-80-3, ORC-80-4, ORC-80-5, ORC-80-6, ORC-80-97, ORC-80-98, ORC-80-100, ORC-80-101, ORC-80-102, ORC-81-17, ORC-81-18 and ORC-81-19.
l (3) The inspectors have expressed a concern with the effective-ness of the (ORC) and this concern was a topic of discussion I
at the Enforcement Conference of July 28, 1981, and again at the Management Meeting of September 25, 1981. The plant management has committed to conducting a self-analysis of the committee's effectiveness and to initiate positive and effective corrective action. This item is an outstanding inspection item (409/81-21-03).
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b.
Safety Review Committee (SRC)
(1) The inspectors reviewed the August 26, 1980, revision of the Safety Review Committee Charter (Revisior No. 12) and verified that the-revised charter is consistent with the Technical Specifications.
The inspectors also verified that the review group member-ship and qualifications were as required by Technical Specifications and that the meetings conducted during the years 1980 and 1981 were held more frequent than that re-quired by Technical Specifications.
(2) The inspectors have expressed a concern with the effective-ness of the (SRC) and this concern was a topic of discussion at the Enforcement Conference of July 28, 1981, and again at the Management Meeting of September 25, 1981. Corporate Management has committed to analyzing the committee's activi-ties and to initiate positive, effective corrective actions.
This item is an outstanding inspection item (409/81-21-04).
No items of noncompliance or deviations were identified.
7.
Semi-annual Review of Plant Operations a.
Security The inspectors observed security guard weapon training and verified that proper training and instructions were provided.
b.
Emergency Preparedness The inspectors visited the Emergency Operations Center for the Vernon County Emergency Government and witnessed a practice exercise to assure their familiarity with their role in the overall emergency plan.
c.
Training The inspectors attended several of the licensee's operator re-qualification lectures and verified that lesson plan objectives were met and that training was in accordance with the approved operator requalification program. The inspectors also attended fire brigade training and equipment usage demonstration to verify compliance with fire protection Technical Specifications.
No items of noncompliance or deviations were identified.
8.
IE Bulletin Followup For the IE Bulletin listed below, the inspectors verified that the written response included the information required to be reported,
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that the written response included adequate corrective action commit-ments based on information presented in the Bulletin and the licensee's response, that.the licensee management' forwarded copies of the written
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response to the appropriate onsite management ~ representatives, that
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information discussed :bi the licensee's written response was accurate,
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and that corrective action taken by the licensee was as _ described :b2 the written response.
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(Closed) I/E Bulletin 81-02-Supplement #1 (Failure of Gate Type Valves to Close Against Differential Pressure). -The licensee's response,
7 letter LAC-7907 dated November 12, 1981, was not issued within the time period stated in the bulletin and no request for extention was requested nor granted. The response was submitted following inquiry by the resident inspector..The untimeliness of the response was dis-cussed with the licensee management and will'be considered during
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reviews of future responses to the NRC. The licensee committed to ensuring future responses are issued in a more timely manner.
Licensee response indicated that no valves of the type in question are in use at LACBWR.
e No items of noncompliance or deviations were identified.
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9.
IE Circular Followup
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For the IE Circulars listed below, the inspector verified that the Circular was received by the licensee management, that a review for
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i applicability was performed, and that if the circular were applicable to the facility,. appropriate corrective actions were taken or were
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scheduled to be taken.
a.
(Closed) 81-04 (The Role of Shift Technical Advisor and Importance I
of Reporting Operational Events). The inspectors reviewed Plant Memo to file dated June 30, 1981, and verified the response was
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appropriate.
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b.
(Closed) 81-09 (Containment Effluent Water ttat Bypasses Radio-activity Monitor).
The inspectors reviewed Plant Memo to file l
dated August 4, 1981, and verified the response was appropriate.
The inspectors questioned the accessibility of the manual isola-
tion valve'for the component cooling water surge tank overflow line during the Design Basis Accident (DBA). Based on the results
of the most recent shielding survey, this area would be accessible
during the (DBA).
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c.
(0 pen) 81-13 (Torque Switch Electrical Bypass Circuit for Safe-
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j-guard Service Valve Motors). The inspectors reviewed the f
October 13, 1981, Memo from W. Nowicki to R. Shimshak and the l.
position the plant took is' contrary to Reg. Gaide 1.106 and 1'
SEP III.10.a SER dated September 22, 1981. This position was i
discussed with NRR and will be considered unresolved until after l
the Integrated Assessment of SEP topics at LACBWR (409/81-21-05).
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No items of noncompliance or deviations were identified.
10.
TMI Task Action Plan Item Followup The inspectors reviewed the licensee's response and action to the
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following Task Items and verified that action taken by the licensee
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was in accordance with written committments.
(Closed) II-B.4 (Training for Mitigating Core Damage). The a.
inspectors conducted a review of the licensee course outline and attendance records and verified that the training was presented to all required plant personnel.
b.
(Closed) II.E.4.2.5 (Containment Pressure Setpoint). The present containment pressure setpoint of 5 psig was accepted by NRR as documented in July 28, 1981, letter from Crutchfield to Linder.
c.
(Closed) II.E.4.2.7 (Radiation Signal on Purge Valves). The inspectors reviewed the licensee's response and verified that the ventilation dampers close on Radiation Signal and that Facility Change 55-81-5 was completed to include this signal for the closure of the 4 offgas vent header valve.
d.
(Closed) II.E.4.2.6 (Containment Purge Valves). This item is closed bases on the completion of Facility Change 73-80-2 which installed environmental qualified solenoid valves on the opera-tors of the containment purge valves. This action was reported in I/R 81-16 and completed the modifications necessary to satisfy the requirements of this task item.
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(0 pen) II.K.3.19 (Interlock on Recirculation Pump Loops). The e.
licensee's response contained in letter LAC 7112, dated September 3, 1981, stated that the licensee did not agree with the requirement to install interlocks on recirculation loops and they also indicated that the present license justified this position. The inspectors have been in conference with NRR on this subject and this item will remain open until NRR concurs with the licensee's position. This is open inspection item (81-21-06) and will be reviewed during a subsequent inspection.
f.
(0 pen) II.K.3.27 (Common Reference Level for Vessel Level Instrumentation). The licensee's response contained in letter LAC 7112 indicated that all water level transmitters have a common reference elevation for vessel taps. This response does not meet the intent of item II.K.3.27 in that the common reference elevation is of very little significance when the electronics of the detectors are adjusted to make indicated
"0" different. On the three normal operating level safety channels instrument "0" is at the 668'-0" level, on the wide range instrument "0" is at the 657'-0" level, and on the High Range instrument "0" is at the 675'6" level. This item has been discussed with NRR and will remain unresolved until the licensee position is accepted by NRR (409/81-21-07).
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No items of noncompliance or deviations were identified.
11.
Plant Trips a.
Beginning on September 10, 1981, and continuing through September 13, 1981, there were a series of five reactor scrams caused by spurious spikes on Nuclear Instrument (NI) Channel No. 8.
The inspectors ascertained the cause of the scrams as being a coaxial connector at the containment penetration which may have been disturbed during the installation of the TMI Post-Accident Sampling equipment. The spikes were intermittent and several unsuccessful repairs were attempted with associated testing. Following the final successful repair on September 13, 1981, another reactor scram occurred when the operator improperly upscaled NI Channel No. 6.
The inspectors verified the establish-ment of proper communications, and reviewed the corrective actions taken by the licensee following these reactor scrams.
All systems responded as expected and the plant was returned to operation on September 14, 1981.
b.
Following the plant scram on October 18, 1981, caused by low loop flow the inspectors ascertained the status of the reactor and safety systems by observation of control room indicators and discussions with licensee personnel concerning plant parameters, emergency system status and reactor coolant chemistry. The inspector verified the establishment of proper communications and reviewed the corrective actions taken by the licensee.
All systems responded as expected, and the plant was returned to operation on October 19, 1981.
c.
Following the plant scram on November 12, 1981, caused by a spike on Nuclear Instrument (NI) Channel No. 7 while NI Channel No. 5 was being tested the inspectors ascertained the status of the reactor and safety systems by observation of control room indi-cators and discussions with licensee personnel concerning plant parameters, emergency system status and reactor coolant chemistry.
The inspector verified the establishment of proper communications and reviewed the corrective actions taken by the licensee.
All systems did not respond as txpected. The No. IB Reserve
Breaker (252-RIB) did not transfer automatically upon the opening l
of Normal Main Breaker (252-MIB). There was also a total loss of l
recirculation flow when the discharge valve for the No. IA Forced Circulation Pump (FCP) closed on a high delta between loops and t
the discharge valve for the No. 1B FCP was shut when power was l
lost to the No. IB FCP due to the failure of the IB Reserve Breaker l
to close. The closure of the FCP discharge valves were in accord-ance with system design. This information was submitted to NRR for evaluation due to the resemblance of this event to the Oyster Creek event that generated Task II.K.3.19 in NUREG 0737. This item is considered unresolved (409/81-21-08).
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No items of noncompliance or deviations were identified.
12.
Followup on Open Inspection Items (0II)
(0 pen) Unresolved Item (409/81-07-02):
Loss of feedwater heating transient of March 16, 1981.
While operating at 85% power on March 16, 1981, a problem was expe-rienced with sticking of the turbine generator governor valve linkage (secondary relay valve). The sticking resulted in fluctuations of reactor coolant system pressure which in turn caused the main steam bypass valve to open to 34% to maintain reactor pressure.
The licensee attempted several times to free the linkage by using the instructions contained in Operating Memorandum DPC-86, Revision 0, to move the load limiter up and down and thereby exercise the governor valves and their linkage. When this failed, the turbine generator was taken off the line (governor and stop valves closed) and the 85%
steam flow was automatically diverted to the main condenser via the main steam bypass valve. The plant remained in that condition for approximately 30 minutes until the linkage problem was corrected and the turbine generator placed back on the line with no steam flowing through the main steam bypass valve.
The inspectors reviewed this event and identified the following significant matters:
a.
Safety Analysis The action of taking the turbine off the line and bypassing the 85% steam flow to the main condenser effectively resulted in loss of all three feedwater heaters. The heaters use turbine extraction steam as the principal source of heat for the feed-water and with the turbine governor and stop valves closed there is no extraction steam. The result is a decrease in feedwater temperature, and supplying of relatively cooler water into the reactor vessel which constitutes a positive reactivity insertion.
The total bypass mode of operation at significant power levels during normal plant operation was not analyzed during the licensing of the plant or in subsequent safety analyses. All procedures and systems descriptions in the FSAR indicate the main steam bypass valve will normally be closed during power operation but will be used during a normal startup and shutdown, following a scram, or during times when the reactor coolant
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system pressure is increasing above an establishci normal opera-ting value. An analysis had been performed for t'e loss of a single feedwater heater and the analysis is descr2 ied in Section 14.3.2.3 of the FSAR. The ' analysis indicated that the loss of a single feedwater heater at 100% power would result in a 70' F drop in feedwater temperature and a power increase to 116%
(assuming no scram) but there would be no core damage. The
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operation on March 16, 1981, at 85% power resulted in a 150' F decrease in feedwater temperature and a power increase to about 102% for approximately 30 minutes with no apparent core damage.
Since the initial reactor power level was less than 100%, the decrease in feedwater temperature by 150' F resulted in actual consequences which were less severe than the transient analyzed in the FSAR.
A later transient analysis that addressed the loss of a single feedwater heater was performed and documented in NES 81A0025,
" Response to Question 4, Transient Analysis for LACBWR Reload Fuel", dated February 18, 1977. That review did not analyze in detail the loss of the heater because it was concluded that the event was bounded by the Increase in Feedwater Flow event which was analyzed in detail. On June 10, 1981, another analysis was performed to determine if the total bypass mode of operation impacted the conclusions of previous transient analyses. The conclusions of that analysis indicated that "...for all antici-pated transients previously evaluated, except the increase in feedwater flow transient, a scram on high power is not required to safely shutdown the plant. This conclusion assumes that the reactor scrams on the first scram signal. The feedwater flow increase transient does not pose a safety problem if the flow increase is limited to that available from one pump. Two feed-water pumps are available only when a transfer is being made between pumps".
As a result of this latest analysis, the plant incorporated an administrative prohibition against a transfer between feedwater pumps during the total bypass mode of operation.
The operation on March 16 was conducted without verifying that the operation was inside the envelope of the safety analyses for the plant and not an unreviewed safety question. The operation on March 16 did constitute a change to the procedures for opera-tion of the main steam bypass system as described in FSAR Sections 13.4.1, 13.4.2, 13.4.3, 13.4.4, 8.2, 8.2.2, and 8.2.3.
Therefore, this operation was required by 10 CFR 50.59 to have been preceded by a written safety evaluation providing the bases for the deter-mination that the operation did not involve an unreviewed safety question.
b.
Instrumentation During the bypass operation, the actual reactor power increased from 85% to approximately 102% as subsequently determined from heat balance data. However, at the time of the operation the
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power range nuclear instruments continued to indicate approximately 85% power. The automatic high power scram setpoints during this event were nonconservative because the instruments were not indi-cating true power. The instruments were indicating approximate 17% below actual core power. The inability of the instruments to accurately reflect true power while operating at power on the main steam bypass valve results in the inability to satisfy the
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requirements of Technical Specification 2.10.2.2 during such operation. Technical Specification 2.10.3.3 requires that the nuclear instrumentation be capable of detecting and indicating power levels and of initiating scram actions at power levels specified TS Table 4.0.2.2.1-1.
The licensee has prohibited operation in the steam bypass mode during power operation, c.
Operating Memoranda On March 17, 1981, the licensee issued Revision 1 of Operating Memorandum DPC-86 to allow plant operation on the main steam bypass valve as necessary to correct governor valve linkage problems. Following discussions with the inspectors, the li-censee subsequently recognized that the information contained in Revision 1 should have been issued in the form of a procedure.
Therefore, Revision 2 was issued on April 22, 1981, to rescind the provisions of Revision 1.
The rescinded information was then incorporated into a change to annunciator response procedure B14-3, Main Steam Bypass Valve Not Closed, contained in Section 3.2 of Volume 1 of the Operating Manual.
Additionally, the inspectors reviewed the licensee's Operating Memoranda system and noted that there are about 15 effective memoranda. The inspectors determined that some of the memoranda address matters which would normally be addressed in procedures.
In addition to DPC-86, Revision 1, other examples of memoranda which appear to require procedures are DPC-78, 80, 81, 83, 84, and 91.
The inspectors' concern is that the memoranda approval chain is not as stringent as the approval chain for procedures in that approval by the Operations Review Committee (ORC) is not required. Thus, for those cases where Operating Memoranda are issued in lieu of procedures, the Technical Specification 6.8.2 requirement to have procedures reviewed by the ORC is circumvented.
d.
Preplanning and Operator Awareness The apparent reason for the March 16, 1981, operation was to avoid a possible scram due to reactor pressure fluctuations and to avoid shutdown to correct the linkage problem.
Both the scram and orderly shutdown would have entailed a loss of electrical generation during plant recovery and the performance of radio-activity analyses required by the Technical Specifications.
Therefore, for operational convenience, the temporary total bypass steam flow operation at 85% power was conducted.
Information reviewed by the inspector indicated a lack of pre-planning for this significant plant evolution. The most obvious evidence of this is the failure of supervisory operating per-sonnel to recognize the need for and to obtain a properly ap-proved procedure.
In the absence of such a procedure, the proper course of action should have been to conduct an orderly plant shutdown.
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Even without adequate preplanning, the inspection revealed that the operators should have been aware that the evolution would result in a positive reactivity insertion which would cause the power to increase. Familiarity with the transient analyses of the FSAR and other documents discussed in Paragraph 8.a. above would have enabled the operators to anticipate the sizable power increase. However, the operators believed the erroneous nuclear instrument indication and were not aware of the sizable power increase until data war evaluated following the evolution. The main steam bypass operation was stopped following correction of the governor valve linkage problem, not because of awareness of the power level.
The above matters related to the March 16 event are still under review by the NRC and will continue to be unresolved pending completion of that review.
13.
Public Meeting The inspectors attended a public meeting on October 22, 1981, at 7:30 p.m. in Caledonia, Minnesota. The purpose of this meeting was to acquaint members of the public, within the affected area of the Emergency Planning Zone, with the content of the Radiological Emergency Response Plan for the State of Minnesota and the County of Houston. Approximately five people attended from the general public.
The inspectors also attended a public meeting on November 10, 1981, at 7:30 p.m. in Viroqua, Wisconsin. The purpose of this meeting was also to acquaint members of the public, within the affected area of the Emergency Planning Zone, with the content of the Radiological Emergency Response Plan for the State of Wisconsin and the County of Vernon. Only one person attended from the general public.
14.
Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, items of noncompliance, or deviations. Unresolved items disclosed during the inspection are discussed in Paragraphs 4, 6, 9, 10, 11 and 12.
15.
Exit Interview The inspector met with licensee representatives (denoted in Paragraph 1) throughout the inspection period, and at the conclusion of the inspection summarized the scope and findings of the inspection activi-(
ties.
In addition, the inspector and a Region III supervisor aet with the licensee on December 4, 1981, to discuss in detail the items dis-cussed in Paragraph 12 of this report. The licensee committed to the following:
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The procedure that allowed intentional operation in the main a.
steam bypass mode during power operations for the purpose of correcting turbine generator control problems was withdrawn and will not be reissued without prior NRC approval.
b.
Operator knowledge of plant transients will be reviewed and the operator training and retraining program will be augmented as necessary to ensure a higher degree of operator awareness of plant transients.
The administrative policy governr g the issuance of Operations c.
Memoranda will be reviewed to ensure that any policy existing is consistent with Technical Specifications 6.8.1 requirements for plant procedures.
In addition, by January 31, 1982, any Operation Memoranda that are not in accordance with the adminis-trative policy will be canceled.
d.
Operating personnel will be reinstructed on the administrative policy concerning the requirements for recording in the log books a complete and descriptive account of operational events occurr-ing on shift.
The setpoints utili2ed for high power and power-to-flow protective e.
equipment will be reviewed to ensure that instrument inaccuracies are utilized in determining these setpoints or reset the setpoints to account for these inaccuracies. The licensee determined from this review that the high power trip should be set at <115% to account for the 15% nuclear instrument error. The power-to-flow setpoints of <48.3% was previously evaluated using the above error.
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