IR 05000255/1985034
| ML18052A338 | |
| Person / Time | |
|---|---|
| Site: | Palisades  |
| Issue date: | 03/12/1986 |
| From: | Anderson C, Hehl C, Swanson E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML18052A339 | List: |
| References | |
| 50-255-85-34, NUDOCS 8603180197 | |
| Download: ML18052A338 (11) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No. 50-255/85034(DRP)
Docket No. 50-255 Licensee:
Consumers Power Company 212 West Michigan Avenue Jackson, MI 49201 Facility Name:
Palisades Nuclear Generating Plant Inspection At:
Palisades Site, Covert, MI License No. DPR-20 Inspection Conducted:
December 24, 1985 through February 3, 1986
~JI~ t-r Inspectors:
E. R. Swanson eJvJ /H.v._ /;r C. D. Anderson
/J_,,.J /~
Approved By:
C. W. Hehl, Chief Reactor Projects Section 2A Inspection Summary Inspection on December 24, 1985 through February 3, 1986, (Report No. 50-255/85034(DRP))
Date Date
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3 /12-/!t Date Areas Inspected:
Routine, unannounced inspection by resident inspectors of management meeting, operational safety; maintenance; surveillance; procedures; reportable events; limitorque valve operators; refueling, leak rate testing and auxiliary feedwate The inspection involved a total of 202 inspector-hours onsite by two NRC inspectors including 26 inspector-hours onsite during off-shift Results:
Of the areas inspected two violations were identifie The first was a result of several ineffective attempts to ensure that biennial reviews of procedures were completed on tim The second was a procedural violation for not resetting a Safety Injection Signal actuation for four days while shutdow Several open items were issued to track completion of various issue An unresolved item was issued related to the local leak rate test failure.
- Persons Contacted Consumers Power Company (CPCo)
- W. T. McCormick, Chairman DETAILS
- F. W. Buckman, Vice President, Nuclear Operations
- R. B. DeWitt, Vice President, Energy Supply
- K. W. Berry, Director, Nuclear Licensing
- J. F. Firlit, General Manager
- J. G. Lewis, Plant Technical Director
- R. D. Orosz, Engineering and Maintenance Manager
- W. L. Beckman, Radiological Services Manager C. E. Axtell, Health Physics Superintendent R. M. Rice, Plant Operations Manager C. S. Kozup, Plant Operations Superintendent H. M. Esch, Plant Administrative Manager
- D. W. Joos, Plant Planning Director R. A. Fenech, Technical Engineer
- D. L. Fitzgibbon, Licensing Engineer
- R. A. Vincent, Plant Safety Engineering Administrator
- R. E. McCaleb, Quality Assurance Director U. S. Nuclear Regulatory Commission
- J. G. Keppler, Regional Administrator
- C. W. Hehl, Chief, Projects Section 2A
- E. R. Swanson, Senior Re~ident Inspector, Palisades
- C. D. Anderson, Resident Inspector, Palisades
- Denotes those present at the Management Intervie #Denotes those present at the Management Meeting on January 31, 198 Numerous other members of the plant Operations/Maintenance, Technical, and Chemistry Health Physics staffs, and several members of the contract Security forces, were also contacted briefl.
Management Meeting On January 31, the personnel denoted above met to discuss the progress and adequacy of the licensee's maintenance activities during the current outag The NRC concluded that the licensee had met their commitments under the Confirmatory Action Letter of October 30, 1985, with respect to the expected status of the maintenance order backlog and control room deficiencies prior to start u Other related topics were also discussed.
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Operational Safety The inspectors observed control room activities, discussed these activities with plant operators, and reviewed various logs and other operations records throughout the inspectio Control room indicators and alarms, log sheets, turnover sheets, and equipment status boards were routinely checked against operating requirement Pump and valve control positions were verified proper for applicable plant condition On several occasions, the inspectors observed shift turnover activities and shift briefing meeting Tours were conducted in the containment, turbine and auxiliary buildings, and the central alarm station to observe work activities and testing in progress and to observe plant equipment condition, cleanliness, fire safety, health physics and security measures, and adherence to procedural and regulatory requirement The inspectors made observations concerning radiological safety practices in the radiation controlled areas including: verification of proper posting; accuracy and currentness of area status sheets; verification of selected Radiation Work Permit (RWP) compliance; and implementation of proper personnel survey (frisking) and contamina-tion control (step-off-pad) practices. Health Physics logs and dose records were routinely reviewe The inspectors observed physical security activities at various access control points, including proper personnel identification and search, and toured security barriers to verify maintenance of integrit Access control activities for vehicles and packages were occasionally observe Activities in the Central Alarm Station were observe An ongoing review of all licensee corrective action program items at the Event Report level was performe At 1441 hours0.0167 days <br />0.4 hours <br />0.00238 weeks <br />5.483005e-4 months <br /> on January 9, 1986, while the unit was in cold shutdown for a refueling outage, the 11A 11 bus (4160V) was de-energized when reports -0f smoke (steam) coming from it were receive Fire and explosion potential existed requiring de-energization of the 11 R11 bus which is the 345 KV tie-in to the main gri Prior to stripping the 11 R 11 bus the licensee started and loaded the 1-2 diesel generator (DIG)
onto the vital 2400V 11D 11 bu This occurred at 145 At 1508 the vital 11C 11 and nonvital 11 E 11 2400V buses were de-energized along with the 11A 11 4160V bu The 11A 11 and 118 11 buses feed the primary coo 1 ant and condensate pumps which were not being used. The 11C11 bus was not energized because its emergency feed is the 1-1 DIG which was out of service for maintenanc An Unusual Event was declared at 1500 and the NRC was notified at 152 The resident inspectors followed the Unusual Event until it was terminate The problem was due to a cable shorting to its grounded jacket which boiled off water in the conduits between the 1-1 startup transformer and the 11A11 bu At 1650 the
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licensee restored power to the 11c 11,
11 D 11 and 11 E 11 buses from the 1-2 station power transformer by backfeeding through the main transforme The 1-2 DIG was then unloaded, stopped and returned to standby. The Unusual Event was terminated at 170 The licensee replaced the cables and restored the electrical alignment on January 10, 198 No unresolved concerns exist related to this even While shutdown on December 28, 1985, energizing new relays on the 11 C
2400V vital bus resulted in an undervoltage condition being sensed which started the 1-2 Emergency Diesel Generator and tripped the startup power breake The 1-1 Diesel Generator was out of service and did not start, so the 11 C 11 bus remained de-energize Load shedding did not occu The relays were isolated and the 11C 11 bus was re-energized through the startup transformer breake Evaluation by the licensee determined that the relays were wired to the wrong contacts (normally closed instead of normally open) and the subsequent checkout of the relays did not detect the error due to misinterpreta-tion of readings on a digital volt meter (zero and infinity indicated by 0 and 000000 respectively).
With respect to the failure to load shed, the licensee has determined that an auxiliary contact on the breaker malfunctioned, but it is not precisely known wh The contact was cleaned, realigned and tested satisfactoril It is suspected that the auxiliary contact problem is related to previous events where the startup power breaker failed to clos The licensee performed similar preventive maintenance on the other five similar breaker Preventive maintenance has been performed on these breakers but did not include these auxiliary contacts which remained in the cubicle when the breaker was remove Evaluation of this problem will be tracked under the Licensee Event Report No. 255/85-031 closeou This event was properly reported under 10 CFR 50.7 While in cold shutdown at 1900 on January 25, 1986, the licensee was preparing to conduct a fast transfer test of the power supplies to the lC vital bus (Safeguards) by manually transferring between power supplies to the bu When attempting to transfer, power was lost to the bus which caused automatic starting of the emergency diesel generators, load sequencing and restoration of power to the bus by one diesel generato It was subsequently found that the startup power breaker was in the test position which caused a trip of the other power supply while it was not connecte This condition was known by the operator, but apparently forgotten during the evolutio The power was restored and the test re-performed satisfactorily at 0659 on January 27, 198 This event was properly reported under 10 CFR 50.7 While in cold shutdown at 1017 hours0.0118 days <br />0.283 hours <br />0.00168 weeks <br />3.869685e-4 months <br /> on January 26, 1986, an electrician working on an inverter inadvertently de-energized its output, thus causing a loss of the second instrument bus (one was already out for other reasons).
This caused an actuation of the Reactor Protection System, a reactor trip, turbine trip, containment isolation, safety injection and diesel generator starts. All systems operated as expected and were reset and restore Approximately 1000 gallons of water were injected and relieved through the blocked open Power Operated Relief Valve This event was properly reported under 10 CFR 50.7 * While in cold shutdown at 2252 hours0.0261 days <br />0.626 hours <br />0.00372 weeks <br />8.56886e-4 months <br /> on January 25, 1986, and again at 0050 hours5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br /> on January 26, 1986, Safety Injection System (SIS)
actuations occurred due to personnel errors by I & C technicians performing calibrations on an indicato Removing the wrong instrument from service caused the SIS block to de-energize, allowing the standing low pressure SIS signals to actuate. The event was repeated because the technician did not recognize that his error had caused the first SIS and restored the instrument to servic Then when he came back to complete his work, he caused another by repeating the erro In both cases, the SIS actuated as expected for plant conditions, again injected about 1,000 gallons each tim Both of these events were properly reported under 10 CFR 50.7 No violations or deviations were identifie.
Maintenance The inspector reviewed and/or observed the following selected work activities and verified appropriate procedures were in effect controlling removal from and return to service, hold points, verification testing, fire prevention/protection, and cleanliness: The inspector reviewed the continuing work on replacement of the General Electric HFA relay spools and observed the rebuilding of these re 1 ay Preventive maintenance on 2400V breaker 152-311 (support building and new warehouse feeder breaker), Work Order No. 24504384, was observe The inspector noted that the electrician was using a procedure with a past due expiration dat When this was pointed out, the electrician proceeded to resolve the issue by obtaining the same procedure (which was the correct one) with an updated expiration date on i Preventive maintenance on several 480V breakers was observe Replacement of the P-8A auxiliary feedwater pump rotating element was observe The outboard thrust bearing had seized fro~ lack of lubrication when seal water had displaced the oil and was not detecte A spare rotating element was sent to the manufacturer for additional machinery and installe The turbine driver for P-88 auxiliary feedwater,pump was rebuilt when inspection disclosed blading damag The damage was apparently caused by a loose bolt several years ag The turbine driver was overhauled and a new governor was installe The inspector verified that appropriate testing was scheduled prior to startu Inspectors met with the licensee on January 7, 8, and 29, 1986, to discuss progress and status of the October 30, 1985 Confirmatory Action Lette The licensee has made a significant reduction in outstanding Work Orders (WOs) (1333 on the 29th).
They plan to have only six 11Shall 11 WOs and six control room deficiencies when plant startup is commence The inspectors reviewed the work not able to be completed and agreed that they are not likely to have any significant impact on plant operation or operator performanc *
No violations or deviations were identifie.
Surveillance The inspectors reviewed surveillance activities to ascertain compliance with scheduling requirements and to verify compliance with requirements relating to procedures, removal from and return to service, personnel qualifications, and documentatio The following test activities were inspected: Daily.Control Room Surveillance - Test D/W0-1 Containment Local Leak Rate Testing (LLRT) - Test R0-32 on penetrations:
40 (primary coolant sample line)
44 (primary coolant pump controlled bleed off)
52 (containment sump level instrument)
65 (reactor cavity fill and recycle) Control Rod Drive Mechanism Calibration - Test R0-19 Safety Channel Linear Power Drawer Alignment - RI-6 Only a portion of RI-62 was observed prior to the activity being suspended during resolution of a rod withdrawal prohibit alarm that would not clea Until that time no abnormalities were note No violations or deviations were identifie.
Procedures On December 23, 1985, an unexpected containment isolation (CI) occurred due to a HFA relay modification procedure inadequac The procedure should have stated that CI would occur, instead it implied that one would not occu This is an example of inadequate procedure revie The Integrated Leakrate Test (ILRT) procedure, RT-36, contained numerous inaccuracies revealing inadequate technical review by knowledgeable individual Approximately 15 temporary change notices (TCNs) were written between January 17 and 22, 1986, to correct the problems so the valve lineups could be completed properl The licensee stopped part way through the valve lineups, after realizing the numerous errors in the procedure, and did a further technical revie This procedure was the result of a major rev1s1on to the previous ILRT including the addition of new steps and information.
- These two examples stress the necessity of a good review proces The first example resulted in a 10 CFR 50.72 notification and a LE The second example resulted in delays in the ILRT performanc This concern was discussed at the exit *meeting on January 31, 198 Section 5.2.15 of ANSI NI8.7-1976 as implemented by Administrative Procedure 10.41, Paragraph 4.9.1 requires that procedures be reviewed no less frequently than every two year On January 23, 1986 the inspector tried to obtain a listing from the Periodic Activity Control (PAC) system of all procedures that were overdue for their biennial revie Not all procedures had been entered onto the PAC system at that time including the Emergency Operating Procedures (EOPs) and Off Normal Procedures (ONPs).
The information that was on the PAC printout was not in all cases meaningful as to what the biennial due date wa Some procedures had entries for when the PAC group wanted information back on what the biennial review date should b In response to the violation 255/85003-0l(DRP) the licensee committed to using the PAC system to provide early notification of impending biennial reviews with the capability for readily identifying overdue procedure Full compliance was to have been achieved by July 15, 198 As of January 24, 1986, the inspector noted seven Emergency Operating Procedures (EOPs) and eleven Off Normal Procedures (ONPs) as being overdue for biennial revie This is considered a violation for failure to take corrective action in a timely manner (255/85034-0l(DRP).
One violation and no deviations were identifie.
Licensee Event Reports Through direct observations, discussions with licensee personnel, and review of records, the following reportable events were examined to determine that reportability requirements were met, immediate corrective action was accomplished as appropriate, and corrective action to prevent recurrence has been accomplished per Technical Specificatio (Closed) LER 255/85020:
On November 26, 1985, NRR approved the extension of the required ASME Section XI hydrostatic test of the main steam and feedwater lines until the next outag Although a violation of the code requirements, a Notice of Violation will not be issued due to the licensee 1 s self identification, reporting and corrective actio This item is close (Closed) LER 255/85025:
On November 30, 1985, the licensee declared certain components inoperable because they were not environmentally qualified prior to the 10 CFR 50.49 deadlin This required a plant shutdown; thus, the licensee began the refueling outag All required equipment will be environmentally qualified prior to startu This event is close *
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(Closed) LER 255/85026:
Two Safety Injection Tanks (SITS) were inoperable simultaneousl This event is described in Inspection Report No. 255/85030, Paragraph The leaking valves are to be repaired during the current refueling outag This event is considered close (Closed) LER 255/85027:
On December 5, 1985, with the plant in cold shutdown the results of an engineering analysis showed that a terminal block associated with one of four pressurizer pressure instrument channels and located inside containment was not environmentally qualified (EQ) as previously analyze Preliminary contact with Sandia Laboratory indicated that the blocks were acceptabl NUREG/CR-3691 provided additional data which indicated that the blocks were not fully acceptable from an EQ standpoin The block in the pressurizer pressure circuit was replace Had the block failed in service with another channel in test it could have resulted in a 2 of 2 logic required for the protection system actuatio This LER is close (Closed) LER 255/85-028:
An inadvertent left channel safety injection (SI)
actuation occurred during replacement of the channels 11 C 11 and 11 D 11 steam generator pressure indicator The investigation discovered that the cause was not due to an electrician causing a short, as was previously believed (Inspection Report No. 255/85030(DRP)), but was due to the lack of detailed steps in the construction work packag The AC power to the indicators on both channels was removed causing the SI block to be remove Once the block was removed, the actual low pressure condition caused the S Only one channel should have been worked on at a time to avoid removing the block signa Although both the right and left SI channels should have been actuated during this event, only the left channel actuate The licensee has committed to issuing a supplement to this LER describing the cause for the right channel not activatin This will be tracked by Open Item No. 255/85034-02(DRP).
Action is planned by the licensee to determine a better method for controlling construction activities on plant installed engineered safeguards circuitry to prevent recurrence of this type of even This will be tracked by Open Item No. 255/85034-03(DRP).
Following this event the operator was to reset the SIS and restore the actuated equipment to normal as required by Alarm and Response Procedure (ARP) 8 for an invalid signa On December 14, 1985, the licensee discovered that the SIS had not been properly reset on December 10, 198 It had only been reblocked and not rese This is considered a failure to follow the procedure and as such is a violation as noted in the Appendix (255/85034-04(DRP)).
It is expected that the licensee will include in the supplemental LER a description of the circumstances which led to the SIS not being reset for four day The failure to reset was discovered during troubleshooting of the containment sump drain valve, CV 1103, which failed to ope It was being held closed by the SI Two other valves were found to be held in position by the SIS als The boric acid recirculation valve, CV 2130, was being held closed and the service water outlet from one of the containment air coolers, CV 0867, was being held ope Each of these valves were known to 8 *
be discrepant but the common cause of the SIS was not identified until December 14, 198 The annunciator labelled 11Safety Injection Initiation Signal A 11 was evidently lit for this entire four day perio On each shift, the Control Operator 1, Control Operator 2, Shift Engineer and Shift Supervisor are required to walkdown the control boards. Apparently no one noticed it or identified its significanc Currently there is no procedure that tells an operator how to reset a SI In addition there is no checklist or guidance for determining the validity of an SIS and under what conditions it can be reset from a plant status such as cold shutdow In the Reactor Trip Procedure, EDP 1, there is guidance on when the SIS can be reset following a reactor tri The licensee plans to revise Administrative Procedure 4.08, Post Trip Review Requirements, to expand its applicability to include other events such as safety injection This will be tracked as an Open Item No. 255/85034-05(DRP).
(Closed) LER 255/85029:
The licensee reported that the testing on one containment penetration violated the limit for local leak rate testin This issue is receiving additional review by the NRC because the penetration was known to be leaking significantly as early as May 198 (Unresolved Item No. 255/85034-06).
This LER is close (Closed) LER 255/85030:
An inadvertent containment isolation (CI) occurred during the refueling outage when a HFA relay modification procedure was being performe The procedure should have stated that a CI would occur (See Paragraph 5).
Discussions were held with the Electrical Systems Engineers emphasizing the need for identifying all resultant ESF system actuations that are part of the preplanned sequenc (Open) LER 255/85031:
This event describes an inadvertent automatic start of the 1-2 Diesel Generator due to improper maintenance activities and the subsequent failure of the load shed featur As discussed at the exit meeting on January 31, 1986, the report requires updating to include additional details as to why the relay maintenance and verification of this activity was ineffective and why the breaker contacts were not included in the preventive maintenace progra An evaluation of the personnel errors was also missin This LER remains ope One violation and no deviations were identifie Limitorgue Operators With Environmentally Nongualified Wires The licensee was verbally informed by the Senior Resident Inspector of the environmentally nonqualified wires found at the Zion Station in October 198 The licensee was supplied with copies of the Zion 10 CFR 21 Report and Supplement on December 20 and 30, 1985, respectivel During the refueling outage which began on November 30, 1985, the licensee inspected 25 valve operators inside containment which were potentially affecte Thirteen were found to need re-wiring due to not having environmentally qualified wire All thirteen were re-wired prior to startu *
No violations or deviations were identifie.
Refueling Activities During movement of the Upper Guide Structure (UGS) on December 31, 1985, the resident inspector noted that the two radiation monitors RIA 2316 and 2317 were in the 11 cut out 11 position when they should have been in service and capable of initiating a containment isolation on high radiatio When pointed out to the Shift Engineer, the monitors were promptly placed back in servic As discussed in Inspection Report No. 255/85030(DRP)
Paragraph 2.i., the UGS was considered a core component, thus its movement necessitated all the requirements in Technical Specifications (TS)
Paragraph 3.8.1 for refueling operations to be met, including the radiation monitor The licensee made a four hour non-emergency 10 CFR 50.72 report at 1:01 p.m. for having containment isolation inoperabl Subsequent to this event, a discussion was held between the licensee and NRR to resolve whether or not the UGS should be considered a core component for TS 3. At that time, NRR deemed that the UGS was not a core component due to the unlikely possibility of causing fuel damage or a reactivity change by mishandling and TS 3.8.1 did not apply for movement of the UG Similarly the incores are not considered core components, therefore, TS 3.8.1 does not apply to their movement eithe No violations or deviations were identifie.
Auxiliary Feedwater 1 At 1345 hours0.0156 days <br />0.374 hours <br />0.00222 weeks <br />5.117725e-4 months <br /> on January 9, 1986, the licensee identified that P-8A, the motor driven auxiliary feedwater pump, did not possess the performance characteristics listed in their updated FSA Table 9-14 indicated that the pump is required to produce 417 gpm at 885 psig while previous testing showed that it was capable of only 325 gpm at 790 psi The licensee re-analyzed the steam generator tube rupture event (which requires the highest cooldown rate) and determined that 375 gpm at 885 psig is required for the cooldow This flow rate can only be achieved by closing the mini-flow valve, which is a local manual valv The operating procedure contains this provision and the licensee is planning to revise the Emergency Procedure to include it as wel Additional review of this issue will be conducted in a future amendment to the Technical Specification NRR has provisionally accepted the licensee's resolutio Containment Local Leak Rate Testing (LLRT)
The inspector witnessed a number of LLRT tests noted in Paragraph 5 and reviewed procedure R0-32 and verified that applicable containment penetra-tions and isolation valves are subject to LLR LLRT 1s are performed at containment design pressure except where NRR has approved reduced pressure testin The licensee utilizes the pressure drop method of leak rate determinatio The licensee exceeded 0.6 La, the Technical Specification limit, on December 4, 1985 when penetration #40 leakage was found in excess of the total allowabl This was reported, although late, as discussed in
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Report No. 255/8503 As discussed in Paragraph 7 of this report, the leakage of this penetration will be tracked as an unresolved item pending further review by the NRC and 1 i cense The 11 as found 11 1 eakage exceeded the limit and is considered a failur The sum of all penetrations and valves leakage 11 as left 11 was 42,398.4 standard cubic centimeters (seem)
which compares to the limit (0.6 La) of 65,200 see Repetitive failures of the LLRT will be addressed further in another repor.
Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations or deviation An unresolved item disclosed during the inspection is discussed in Paragraph.
Open Items Open Items are matters which have been discussed with the licensee, which will be reviewed further by the inspector, and which involve some action on the part of the NRC or licensee or bot Open items disclosed during the inspection are discussed in Paragraph.
Management Interview A management interview (attended as indicated in Paragraph 1) was conducted on January 31, 198 The scope and findings of the inspection were discussed. The inspector also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspector during the inspectio The licensee did not identify any such documents/processes as proprietar