IR 05000331/1999001

Insp Rept 50-331/99-01 on 990113-0302.No Violations Noted. Major Areas Inspected:Operations,Maint,Engineering & Plant Support

ML20204J757
Person / Time
Site:	Duane Arnold
Issue date:	03/24/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20204J738	List: IR 05000331/1999001 ML20204J734
References
50-331-99-01, 50-331-99-1, NUDOCS 9903300157
Download: ML20204J757 (21)

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U. S. NUCLEAR REGULATORY COMMISSION _ j

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Docket No: 50-331

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License No: DPR-49

. Report No: 50-331/99001(DRP)

Licensee: Alliant, IES Utilities In First Street P. O. Box 351 Cedar Rapids, IA 52406-0351 Facility: Duane Arnold Energy Center Location: Palo, Iowa

. Dates: January 13 through March 2,1999 Inspectors: P. Prescott, Senior Resident inspector M. Kurth, Resident inspector Approved by: M. N. Leach, Chief Reactor Projects Branch 2 j Division of Reactor Projects 9903300'15'l 990324

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EXECUTIVE SUMMARY I

Duane Arnold Energy Center NPC Inspection Report 50-331/99001(DRP) ,

This inspection report included the resident inspectors' evaluations of aspects of licensee operations, engineering, maintenance, and plant suppor Operations

. Overall, the conduct of operations was appropriately focused on safety. Onshift ope rations crews performed the downpower evolutions for the main turbine surveillance testing without errors. Also, management impressed on operators, prior to commencing a plant shutdown for both diesel generators being inoperable, that regardless of any' ;

progress made on the Notice of Enforcement Discretion (NOED) request, a controlled shutdown should continue. Additionally, operators responded conservatively to a main steam tunnel high temperature alarm by maintaining reactor power at reduced levels until the problem was resolved (Section 01.1).

- The inspectors identified that the licensee failed to complete corrective actions specified ' ]

in an Action Request after a highly radioactive item was discovered in the cask pool without the required documentation. The licensee administratively closed the Action Request using the corrective action process; however, the corrective actions were not completed due to a lack of supervisory oversight. The licensee's failure to complete these corrective actions was a Non-Cited Violation (Section O2.2).

. The inspectors noted the onshift operations crew responded appropriately to the l potentialinoperability of both control room standby filter unit trains. Also, onshift 1 operations management conservatively viewed the momentary inoperability of both j standby gas treatment system trains as being reportable (Section 02.3).

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. The inspectors viewed the licensee's response to the inoperability of both standby diesel !

generators for not meeting Technical Specifications as conservative and appropriat The surveil lance test procedure requirements failed to adequately test the standby diesel generators based on overly restrictive requirements in the licensee's improved Technical Specifications. The licensee did proceed with an orderly shutdown, as required by Technical Specifications. The shutdown was subsequently stopped when the NRC approved the licensee's NOED request. However, the licensee failed to note during an earlier surveillance test that the procedure was inadequate. The inadequacy ;

of the surveillance test was a Non-Cited Violation (Section O3.1).

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The inspectors identified multiple discrepancies regarding the storage of non-fuel materials in the spent fuel pool and cask pool in accordance with procedures, due to an inattention to detail and a lack of managerial oversight. This was a non-cited violation (Section O3.3).

Maintenance

.. The inspectors identified that the onshift operations crew were not made aware of the difference between the revised emergency action level primary containment radiation monitoring action setpoints and the unchanged associated control room annunciator

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alarm setpoiDts, due to e delayin maintenance activities. The licensee took appropriate corrective oClions after the identification of the discrepancy (Section M1.2).

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Observant inttr urnentstion and control technicians noted that the air flow indicating controller wsg pot reading accurately on the "A" standby gas treatment system while calibrating thg O' trair1. However, instrumentation and control technicians were mistakenin thgirinitialu derstanding n of the operating principle of the differential i

pressure svl tep for the control room standby filter units, initial response from the various maintenance depa rtrnent personnel was viewed as timely and appropriate for repairs to tra jgiled resisto rin the logic circuitry for the main steam tunnel high temperature %1grn). However, maintenance personnel lacked a definitive plan to address the Ibn9 standing problern of the resistor failures (Section M2.1).

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The inspect0ts identified several ambiguous Technical Specification required steps prior to standby gastreatrnent systern efficiency testing. The licensee failed to recognize the subtle differshces in testing requirements from the previous and current Technical Specificatio0. re quiren,ents. The licensee corrected the steps prior to conducting the testing (Sectign N3.1),

Enaineerina

. Although the Iggues forloss of condenser vacuum and the main generator ground have not been resOlve d,licens ee action to date was thorough and methodical. The system engineer perfDr61ed an inadequate initial operability evaluation on the "B" standby filter unit differentl41 pressure switch function, which resulted in operators initiating an unnecessarf blgnt shutdown. Also, the failure of the Group one logic circuitry has been

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a longstanding problen1%ith no specific corrective action proposed. Finally, the system engineerrniss ed an arlier e opportunity to identify a surveillance procedure deficiency for the standby diggel generators (Section E1.1).

Plant Support

. Overall, licenseg perform ance in the emergency preparedness training drills was goo No significant weaknesSes were noted. The licensee identified a discrepancy between the primary co ntainroent radiation rnonitoring alarm setpoints in the simulator control room from tre larma setpoints in the actual control room (Section P1.1).

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Report Details Summary of Plant Status At the beginning of the inspection period, the licensee operated the plant at 100 percent powe On January 16,1999, at 11 > p.m., the licensee initiated a power reduction to approximately 70 percent for control rod segaence exchange and turbine valve tosting. Full power operatons resumed January 17,1999, at 3:36 On January 19,1999, the licensee determined that both standby diesel generators did not meet a Technical Specification (TS) surveillance requirement. Both diesel generators were declared inoperable and a TS required plant shutdown was initiated on January 20, at 4:50 a.m. The licensee requested a NOED, which NRC granted. On January 20, at 10:30 a.m., the diesel generators were declared operable and the shutdown stopped at 41 percent powe On February 9,1999, while planned maintenance was being performed on the control room "A" standby filter unit (SFU), instrumentation and control (l&C) technicians identified that the "B" SFU was also inoperable due to a heater controller problem. With both trains of the SFUs inoperable, TS 3.0.3 was entered and a plant shutdown was begun at 4:59 p.m. The power '

reduction continued until the switch for the "B" SFU unit was repaired and tested satisfactorily at 7:58 p.m. Plant power had been reduced to 80 percent. At 8:15 p.m. a power increase was l begun, with the plant returning to 100 percent power at 10:00 On February 20,1999, at 11:01 p.m., the licensee initiated a power reduction to approximately 80 percent power for main turbine logic and bypass valves testing. Testing was completed satisfactorily. However, on February 21, at 3:01 a.m., a main steam tunnel high temperature j annunciator in the control room due to a failed resistor in the logic circuitry. Onshif t operations management conservatively decided to hold reactor power at 80 percent until the resistor was replaced. At 3:06 p.m. the logic circuitry was tested and declared operable and a reactor power increase began at 3:24 p.m. Full power operation was reached at 6:21 l. Operations 01 Conduct of Operations 01.1 Observations of Routine Activities and Planned Plant Power Reductions Inspection Scope (71707)

The inspectors conducted frequent reviews of ongoing plant operations. These reviews included observation of control room shift turnovers and operator performance during plant evolutions. Also, the inspectors reviewed daily logs and intewiewed operations personnel regarding plant status and events. The inspectors observed discussions regarding the status of plant eqtipment, planned testing, and maintenanc The inspectors observed licensee activities during two power reductions for control rod sequencing and main turbine valve testing. A power reduction was also observed for a TS issue related to the diesel generators. This included observation of portions of each operations shifts' activities, management and reactor engineering briefings, operator use of procedures, and coordination between control room and in-plant operator .

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• On January 16 through 17,1999, operators initiated a reduction in power to i 70 percent for control rod sequence exchange and main turbine valve testin * On January 19,1999, a plant shutdown was comme ~ed due to the diesel generators being declared inoperable for failure to meet TS requirements (see Section O3.1 for details)

• On February 9,1999, a plant shutdown was commenced for both trains of SFUs being declared inoperable. The control room "A" SFU was unavailable due to a planned maintenance outage and the "B" SFU was declared inoperable due to the failure of a differential pressure switch which was initially believed would prevent the electric heater from coming on (see Section O2.3 for details) l l

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• On February 20 through 21,1999, operators initiated a reduction in power to )

80 percent for main turbine valve logic and bypass valve testin b. Observations and Findinas The inspectors observed that operations personnel were knowledgeable of plant and equipment status, maintained accurate records, effectively communicated operational information, and operated equipment in accordance with approved procedures. The inspectors observed strict use of procedures and thorough shift turnovers. Overall, the licensee promptly addressed emergent equipment issues and conduct of operations was appropriately focused on safet !

Operations personnel performed an error-free power reduction on January 16 through 17,1999. The inspectors noted good communication between control room operators and reactor engineering personnel during the evolutio l The onshift operations crew commenced a plant shutdown whe . both diesel generators were declared inoperable. Management discussed the resoon for the shutdown with the l onshift crew. In the discussion, it was impressed on the operators to perform a controlled shutdown and not consider whether or not the NOED request would be approved. The shutdown was stopped at approximately 40 percent power. The inspectors observed that the onshif t operators performed the shutdown in a controlled manner and no problems were note The inspectors noted safety-conscious operator performance for the February 20 through 21,1999, power reduction for main turbine valve logic and bypass valve testin Just prior to operators beginning the reactor power ascension, a main steam tunnel high temperature alarm was received in the control room. The onshift crew conservatively decided to hold reactor power at the current level until a failed resistor in the scram logic was replaced and declared operabl c. Conclusions Overall, the conduct-of operations was appropriately focused on safety. Onshift operations crews performed the downpower evolutions for the main turbine surveillance testing without errors. Also, management impressed on operators prior to commencing a plant shutdown for both diesel generators being inoperable, that regardless of any

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progress made on the NOED request, a controlled shutdown should continu Additionally, operators responded conservatively to a main steam tunnel high l temperature alarm by maintaining reactor power at reduced levels until the problem was resolve Operational Status of Facilities and Equipment  :

' O2.1 General Plant Tours and System Walkdowns (71707)

i The inspectors followed the guidance of Inspection Procedure 71707 to evaluate the following systems. The systems chosen. based on maintenance work activities and risk significance, were:

. standby gas treatment

. standby filter units

. reactor core isolation cooling

. spent fuel pool The inspectors determined that equipment operability, material condition, and housekeeping were acceptable in all cases. The inspectors identified problems with l storage of non-fuel items that the licensee temporarily stored in the spent fuel pool l

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(see Section 03.3 for details). Also, the inspectors noted an increase in equipment problems that challenged operators (see Section O2.3 for debils).

O2.2 Failure to Comolete Corrective Actions for Refuel Floor Concern Inspection Scope (40500)

As detailed in Section O3.3 of this report, the inspectors assessed the material control of non-fuel items in the spent fuel pool and the cask pool. The assessment included a review of the licensee's corrective actions for concerns that were previously identified regarding non-fuel material controlin the spent fuel pool and cask pool. Also, the inspectors used Administrative Control Procedure (ACP) 1407.2, " Material Control in the g

Spent Fuel Pool and Cask Pool," Revision 4 to assess licensee compliance to proper storage of items in the epent fuel pool and cask poo Observations and Findinas On September 3,1998, a radiation protection technician i ~.tiated Action Request (AR) 982343 to address a highly radioactive item that was in the cask pool, but was not logged. Subsequently, the refuel floor supervisor documented in the AR that the item was contained and was logged per ACP 1407.2. The AR was administratively closed on November 30,199 During the inspectors' audit of items in the spent fuel pool and cask pool on January 25,1999, the inspectors identified that the same item in the cask pool still did not have a storage permit or associated storage permit tag. Discussions with the refuel floor supervisor revealed that he failed to initiate a storage permit and storage permit tag when he administratively closed AR 982343. The licensee has since properly tracked the item by using a storage permit and storage permit tag in accordance with ACP 1407.2. The outage manager, who has oversight responsibilities of the refuel floor,

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explained th'11it was his expectation that corrective actions are completed prior to administrative!y closing AR CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality shall be prescribed by documented procedures and shall be accomplished in accordance with these procedures. Administrative Control Procedure 114.5, " Action ]

Request System," Revision 16, Step 3.2.1(2), requires, in part, that the process outlined in the flow chart of Section 3.3 shall be used to control the processing of AR Flowchart D of Section 3.3 requires the licensee, in part, to complete corrective actions ,

and obtain the required concurrence for AR closure. Contrary to the above, from November 30,1998, until January 29,1999, the licensee failed to complete corrective actions after obtaining the required concurrence for AR closure. This Severity Level IV Vio!ation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy (50-331/99001-01(DRP)). The violation was in the licensee's corrective action program as AR 991465 c. Conclusions The inspectors identified that the licensee failed to complete corrective actions specified in an AR after a highly radioactive item was discevered in the casi pool without the required documentation. The licensee administra:ively closed tha AR using the corrective action process; however, the correctiv<s actions wer's not completed due to a ,

lack of supervisory oversight. The licensee's fai ure to comNete these corrective actions '

was a non-citec violatio d O2.3 Eauipment Problema that Reauired Entry into TS 3. a. Inspection Scope (71707)

i The incpectors evaluated licensee response to equipment problems associated with the i standby gas treatment (SBGT) system and control room SFU trains, which required ]

operators to met the requirements of TS action statement 3.0.3. The inspectors reviewed ope.ator logs, action requests, vendor manuals, and design basis documents associated with the SBGT system and SFU train b. Qbservations and Findinas On February 9,1999, while performing planned maintenance on the control room "A" SFU, l&C technicians discovered that a light bulb for the photocell in a photoelectric differential pressure switch that provided part of the logic parmissive to start the electric l heater on the "B" SFU was not lit. At the time, the I&C technicians and the system ;

engineer believed the heaters would not have initiated on a start signal to the SF Subsequently, the operations shift declared L.s "B" SFU inoperable. Because the

"A" SFU was also inoperable for maintenance, operators entered TS LCO 3.0.3. The  !

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operators commenced a plant shuMown, while maintenance personnel replaced the differential pressure switch. The auferential pressure switch was replaced and successfully tested. During this period, the operak 3 had decreased plant power to approximately 80 percent. The operations onshift management made the necessary 10 CFR 50.72 notification to the NRC and the licensee was preparing a 10 CFR 50.73 written notification.

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On February 22,1999, operators were performing a monthly surveillance test on the

"B" SBGT system when the "A" SBGT system flow indicated higher tFan expected flo The two trains share a common flow transmitter. Operators declared the "A" SBGT syatem inoperable. The l&C technicians repaired the "A" train flow indicating controller before the ongoing "B" SBGT system surveillance test was completed. While shutting down the "B" SBGT system from the surveillance test, operators briefly disabled the

"B" SBGT system from automatically starting. For that brief period of time (15 seconds),

both SBGT system trains were considered inoperable. Operators temporarily entered TS LCO 3.0.3, but no operator action was taken to shutdown the plant as this was a momentary entr The "A" SBGT system was successfully post-maintenance tested to demonstrate operability for the repairs to the flow indicating controller. Operations shif t management made the required 10 CFR 50.72 notification to the NRC for a TS required shutdow c. Conclusions The inspectors noted the onshift operations crew responded appropriately to the potentialinoperability of both control room SFU trains. Also, onshift operations management conservatively viewed the momentary inoperability of both SBGT system trains as being reportabl Operations Procedures and Documentation O NOED Reauest For Standbv Diesel Generators inspection Scope (71707_)

The inspectors observed the performance of surveillance test procedure (STP) 3.8.1-06,

" Standby Diesel Generators Operability Test," for both diesel generators. The STP and test data were reviewed for conformance with TS requirements. Also, the inspectors reviewed previous correspondence between the NRC and the licensee and the Updated Finai Safety Analysis Report (UFSAR), pertaining to the diesel generator b. Observations and Findinas On January 19,1999, the licensee determined that the existing STP 3.8.1-06, " Standby l Diesel Generators Operability Test," Revision 3, used to demonstrate compliance with j TS surveillance requirement (SR) 3.8.1.7, did not fully meet the TS requirement Specifically, TS SR 3.8.1.7 required the licensee to verify every 184 days that each diesel generators would start from standby condition and achieve within 10 seconds, voltage between 3744 and 4576 volts, and frequency between 59.5 and 60.5 hertz. The STP did not account for potential" overshoot" in voltage or frequency outside the stated allowable limits due to the diesel generators being tested in an unloaded condition. The test only confirmed that the diesel generator initially reached the required minimum voltage and frequency value within 10 seconds and did not confirm that the voltage and frequency remained within the required band within the 10 second limit. The licensee revised and re-performed the surveillance test. The diesel generators exceeded the specified frequency requirements. Operators declared both diese! generators ir.verable. The TS LCO 3.8.1 was entered on January 20, which required the plant to

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be in hot shutdown (mode 3) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and cold shutdown (mode 4) within 36 hour4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> The licensee missed an earlier opportunity to identify tne deficient surveillance procedure. The last surveillance test using STP 3.8.1-06 occurred on October 29,199 Improved Technical Specifications (ITS) were implemented on August 1,1998. The diesel generators met the procedure requirements, which were based on the licensee's previous TS requirements. The previous TS required the diesel generators start within 10 seconds and meet minimum voltage and frequency requirements. The licensee did not update the procedure when ITS was implemented. Technical Specification 5.4. requires, in part, that procedures shall be implemented covering activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2,1978," Typical Procedures for Pressurized Water Reactors and Boiling Water." Section 8.b. states, in part, that written procedures are required for surveillance tests listed in TS. Surveillance Test Procedure 3.G.1-06, Revision 1, did not meet all the requirements of TS SR 3.8. Specifically, that within 10 seconds, voltage and frequency would not exceed 4576 volts or 60.5 hertz, respectively. The failure to establish adequate procedures is a violation of TS 5.4.1. This Severity Level IV Violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy (50-331/99001-02 (DRP)).

This violation was in the licensee's corrective action program as ARs 9914167 and 9914280. Corrective actions were completed when the procedure was revised and the TS SR amende This surveillance requirement underwent significant changes near the end of the NRC review of the licensee's conversion to the ITS. Previous correspondence indicated that the licensee did not inte nd for the basic requirements for this testing to be different from that contained in the old TS, when in fact, significant change was introduced due to the adoption of the wording of the Standard Technical Specifications (STS). Because this was not recognized, the previous STP was not correctly revised as part of the ITS implementation process. Industry and NRC had recognized this issue subsequent to the licensee's ITS conversion, and a generic change to the STS was approved by the NRC to correct this SR. Therefore, the licensee concluded it was in the interest of safety not to initiate a plant shutdown due to a recognized deficiency in the licensee's TS. The licensee requested the NRC consider an NOE The diesel generators did meet the requirements of the UFSAR in Sections 1.8.9 and 8.3.1.4. The diesel generators started and accelerated to the minimum required voltage and frequency within the required time of 10 seconds in the accident analysis, accepted !

the supported loads in the proper sequence, recovered the bus voltage and frequency ,

within their design limits between loads, and achieved and maintained the required j steady-state voltage and frequency conditios. In addition, a review of the most recent data (January 20,1999) showed that the diesel generators reached the required  !

steady-state performance on voltage and frequency. Based upon this performance, the j licensee concluded that the diesel generators were capable of performing their intended i safety function, as assumed in the accident analysis; therefore, the diesel generators l

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should be considered operable and meeting their LCO requirement The NRC evaluated the licensee's safety rationale for the requested NOED and approved the request not to enforce c7mpliance with the SR 3.8.1.7 until the reviCon to SR 3.8.1.7 was processed, which involved minimal increase in risk to the safe operation of the plant. The diesel generators were demonstrated to pass SR 3.8.1.7 per the

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licensea's exigent amendment request. The proposed revision adopted the NRC approved change to the STS. Based on these considerations, NRC staff concluded that Criterion 1 of Section B, and the applicable criteria in Section C.4 to Manual Chapter 9900," Technical Guidance, Operations - Notice of Enforcement Discretion,"

were met. Criterion 1 of Section B stated that for an operating plant, the NOED was intended to avoid an undesirable transient (plant shutdown) as a result of forcing compliance with the license condition, and thus minimize the potential safety consequences and operational risks. The licensee submitted an exigent TS amendment to revise SR 3.8.1.7 on January 22,1999, and NRC approval was granted on February 17,199 l Conclusions The inspectors viewed the licensee's response to the inoperability of both diesel generators for not meeting TS as conservative and appropriate. The surveillance test procedure requirements failed to adequately test the diesel generators based on overly l restrictive requirements in the licensee's ITS. The licensee did proceed with an orderly shutdown, as required by TS. The shutdown was subsequently stopped when the NRC approved the licensee's NOED request. However, the licensee failed to note during an ;

earlier surveillance test that the procedure was inadequate. The inadequacy of the surveillance test was a Non-Cited Violatio O3.2 Licensee Failed to incoroorate Procedural Chance to Annunciator Response Procedure 1 insoection Scope (71707)

The inspectors assessed operators' conduct in the performance of the SBGT system efficiency surveillance test. The assessment included the review of procedures used to perform the surveillance test. The inspectors reviewed the following procedures:

STP 3.6.4.3-03, " Standby Gas Treatment System HEPA [High Efficiency Particulate Air) and Charcoal Efficiency Tests," Revision 1

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1C23, C-3, " Main Plant [ Heating, Ventilation, and Air Conditioning] HVAC,"

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• Administrative Control Procedure (ACP) 1410.1, " Conduct of Operations,"

Revision 19 Observations and Findinas During the week of February 8,1999, the licensee performed STP 3.6.4.3-0 Operators were assigned to complete the testing with assistance from chemistry department, radiation protection, and system engineering personnel. During the testing, a non-licensed operator secured both steam jet air ejector room exhaust fans to maintain the proper SBGT system flow parameters for testing. The non-licensed operator failed to acknowledge a warning placard next to the fan controls to open the turbine building sump room door after securing both fans. When the exhaust fans were secured, a licensed operator acknowledged the associated low flow alarm, as expected, in the control room back panel (1C23,C-3). The inspectors noted that the operator did not read the annunciator response procedure. Procedure, ACP 1410.1 allowed operators to acknowledge expected alarms without reviewing the annunciator response procedure, provided he/she was aware of actions that needed to be taken and

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completed those actions. The steam Jet air ejector room exhaust fans were secured for greater than one hour when the inspectors identified that the annunciator response procedure stated that operators must open the turbine building sump room door (Door 108) if both steam jet air ejector room exhaust fans were secured for greater than one hour for SBGT system testing. The inspectors questioned the operator and he indicated that he did not dispatch anyone to open Door 108. A non-licensed operator was subsequently dispatched Wpen Door 108. The licensee initiated AR 9914463 for failing to open Door 108 during the SBGT system test when both steam jet air ejector room exhaust fans were secure The licensee conducted a review and identified that AR 950388.00 and AR 950388.02 addressed the issue of opening Door 108 while the SBGT system was operating. Prior to 1995, the licensee received elevated hydrogen alarms in the turbine building sump room whenever the SBGT system was running. The elevated hydrogen levels were due, in part, to steam leaks that included hydrogen gas from the condenser bay and heater bay drains to the turbine building sump room. The turbine building sump room and the steam jet air ejector room shared a common ventilation, which flowed to the offgas stack ventilation. The SBGT system also flowed to the offgas stack ventilation and when started, would tend to decrease the exhaust flow from the steam jet air ejector room and turbine building sump room. The decrease in ventilation flow allowed the buildup of hydrogen gas in the turbine building sump room and triggered a high hydrogen concentration alarm in the control room. The system engineer corrected this by revising procedures that instructed operators to open Door 108 whenever the SBGT system was running. Long term corrective actions were to repair the steam leak When the steam leaks were repaired and there was no longer a hydrogen gas buildup concern in the turbine building sump room, the system engineer revised the procedures to remove operator actions to open Door 108 whenever the SBGT system was runnin Action Request 950388.02 initiated actions to remove this operator action from SBGT system surveillance tests; however, the AR did not address the need to remove the operator action from ARP 1C23, C-3. Administrative Control Procedure 106.1,

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requires, in part, that procedure owners shall coordinate any process-related changes to procedures with other users of the procedure and with owners of interfacing procedure Contrary to the above, since January 28,1996, the system engineer failed to coordinate process-related changes to procedures with other users of the procedure and with owners of interfacing procedures by not revising ARP 1C23, C-3, to reflect the change to allow Door 108 to remain closed during operation of the SBGT system. This minor program deficiency constituted a violation of minor safety significance and was not subject to formal enforcement action. This deficiency was in the licensee's corrective action program as AR 991446 c. Conclusions The inspectors identified that the system engineer failed to coordinate process-related changes to procedures with other users of the procedure and with other owners of interfacing procedures by not revising ARP 1C23, C-3, to reflect the change to the turbine building sump door to remain closed durig eperation of the SBGT system. This minor program deficiency constituted a violation of minor safety significance and was not subject to formal enforcement actio .

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O3.3 Inadeauate Procedural Adherence for Storaae of Non-Fuel Materials in the Soent Fuel Pool and Cask Pool  ; Inspection Scope (71707 and 40500)

On January 25,1999, the inspectors assessed the material control of non-fuel items in the spent fuel pool and cask pool by conducting an independent audit. The inspection included a review of the requirements and methods of storing and documenting non-fuel materialin accordance with ACP 1407.2," Material Controlin the Spent Fuel Pool and Cask Pool," Revision 4.- Observations and Findinas The inspectors identified the following:

• Three examples of multiple items stored in the spent fuel pool using one storage permit rather than only one storage permit per item as required by ACP 1407.2, !

Step 3.2.4;

• Examples in the past several years when the quarterly audit of the spent fuel pool and cask pool were not performed as required by ACP 1407.2, Step 3.2.7.;

= Examples of items (three tri-nuke fili 6rs) stored in the spent fuel pool not having contact dose rates and dose rates at a certain distance recorded as required by ACP 1407.2, Step 3.6.(1); and

. Two examples of items stored in the spent fuel pool not having a storage permit as required by ACP 1407.2, Step 3.4 and the associated storage permit tag as required by ACP 1407.2, Step 3. On January 28,1999, after the inspectors' findings were communicated to plant management, the refuel floor supervisor initiated AR 9914383 to document the above discrepancies. The licensee took prompt actions to correct the deficiencies and revised ACP 1407.2 to ensure non fuel items in the spent fuel pool and cask pool were adequately identified and logged. To prevent future recurrence of failing to conduct quarterly audits, the licensee entered an action item in the computerized maintenance activities program which will track and alert the responsible person to conduct the audit

- on a quarterly basis. The discrepancies noted were due to an inattention to detail and a lack of managerial oversigh CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality j shall be prescribed by documented procedures and shall be accomplished in l accordance with these procedures. As described above, numerous examples were identified for failing to adhere to the procedural requirements of ACP 1407.2 and, therefore, is a violation of NRC requirements. This Severity Level IV Violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy (50-331/99001-03(DRP)). The violation was in the licensee's corrective action program as AR 991438 The inspectors identified the tri-nuke filters stored in the spent fuel pool not having contact dose rates and dose rates at a certain distance recorded as required by ACP 1407.2, Step 3.6.(1). The refuel floor supervisor had conducted several audits; however, he failed to identify and correct the deficiency. Additionally, the inspectors were concerned that two cloth filters were stored in the cask pool and were not

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contained in any way to prevent the filter from possible disintegration; thus, causing the generation of tiny highly radioactive particles in the cask pool. The licensee has since stored the cloth filters in a stainless steel storage container. Also, as detailed in Section R1.1, a radiation protecF?a technician initiated AR 981872 in June 1998, when he recognized the need for a p'.Nedural enhancement to ACP1407.2 to document and track dose rate information fr :tems stored in the spent fuel pool and cask pool. He identified that dose rates were being recorded for items in the spent fuel pool and cask pool using radiation survey forms (HP-41); however, in some instances, the dose rate information was not being recorded on the storage permits or storage permit tags. The refuel floor supervisor administratively .osed the AR by initiating process changes to be made to ACP1407.2 to reference a co.apleted HP-41 form to obtain dose rate .

information for items stored in the spent fuel pool and cask pool. The process changes j were considered routine with no completion date assigned. Also, as detailed in l Section O2.2 of the report, the inspectors identified that corrective actions were not taken to address a previous concern identified by a radiation protection technician when {

a highly radioactive item was identified in the cask pool. Although the concern was closed using the corrective action process (AR 982343), the licensee did not follow J through on completing its prescribed corrective actions of tracking the item as required I by ACP 1407.2. This was a Non-Cited Violatio I c. Conclusions i

The inspectors identified multiple discrepancies regarding the storage of non-fuel materials in the spent fuel pool and cask poolin accordance with procedurer., due to an inattention to detail and a lack of managerial oversight. This was a Non-Cited Violatio . Maintenance M1 Conduct of Maintenance M1.1 General Comments Inspection Scope (62707 and 6172_6_)

The inspectors observed all or portions of the surveillance test activities and work i request activities listed below. The applicable surveillance test or work package documentation was reviewed. The inspectors focused on risk-significant work and surveillance test activitie ,

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Maintenance Activities

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. Corrective Maintenance Action Request A43031: "A" SBGT system variable heaters controller TT5805A; install seismic screws and brackets

. Preventive Maintenance Action Request 1107445: "B" SBGT system demister roughing filters; remove and replace

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Surveillance of Activities

. STP 3.3.1.1-13, " Turbine Control Valve EOC RPT Logic and RPS Instrument Functional Test" 13 i

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. STP 3.3.1.1-19, " Functional Test Of TSV [ Turbine Stop Valve) Closure input To RPS And RPT"

- STP 3.6.4.3-01, " Standby Gas Treatment and Standby Filter Unit Operation with Heaters On"

- STP 3.6.4.3-03, " Standby Gas Treatment System HEPA and Charcoal filter Efficiency Tests"

- STP 3.7.7-01, " Bypass Valves Test"

. STP 3.8.1-06," Standby Diesel Generators Operability Test (Fast Start)"

- STP NS930001," Main Turbine Operational Tests" Observations and Findinas The inspectors noted that, generally, licensee personnel conducted the work associated with these activities in a professional and thorough manner. Technicians were knowledgeable of their assigned tasks and work document requirements. Surveillance tests and work requests observed are listed. The inspectors' comments on specific items are detailed in the proceeding section M1.2 Primary Containment Radiation Monitoring Alarm Setooints Differ From Simulator and Actual Control Room  ;

, Inspection Scope (61726)

i The inspectors observed portions of the January 27,1999, emergency preparedness I training drill. During the conduct of the drill the licensee identified that the primary I containment radiation alarm setpoints in the simulator differed from the actual control room. The inspectors reviewed the circumstances involving the setpoint differences and what aulons were taken in the control room concerning the alarm setpoint change Observations and Findinas Effective September 1998, the licensee conservatively revised the emergency action level primary containment radiation monitoring action setpoints. Revisions were made to the simulator control room annunciator alarm setpoints; however, the maintenance work to change the associated control room annunciator setpoints was delayed due to problems with equipment needed to revise the setpoints. The maintenance work was l rescheduled to be performed five months after the issuance of the revised emergency action level setpoints. The difference in annunciator alarm setpoints could have caused

, confusion during a response to an even After discovery, the licensee committed to revising the control room annunciator alarming setpoints. The day after the discovery, the inspectors questioned the onshif t operations shift manager regarding the setpoint differences. He was not fully aware of the differences between the emergency action level setpoints and the control room annun'ciator alarm setpoints. Therefore, operation's management provided operators

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int,a r . ,egarding the difference in the annunciator alarm setpoints and the emergency action level setpoints and the need to use the more conservative emergency action level setpoints. Currently, the licensee is revising the annunciator alarm setpoints with the vendor's assistanc c. Conclusions The inspectors identified that the onshif t operations crew were not made aware of the difference between the revised emergency action level primary containment radiation monitoring action setpoints and the unchanged associated control room annunciator alarm setpoints, due to a delay in maintenance activities. The licensee took appropriate corrective actions after the identification of the discrepanc M2 Maintenance and Material Condition of Facilities and Equipment M Plant Material Condition Inspection Scoce (62707 and 61726)

The inspectors reviewed several emergent work items to ensure appropriate operability evaluations were performed, TS were met, repairs were made, and root causes were determined where appropriat Observations and Findinas The inspectors noted that there were several emergent equipment issues during the inspection period. The oxamples are listed b;iow:

. On January 7 ar. ~o bruary 5,1999, the operators responded to an upward

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trend in pressure u the high pressure condenser. Reactor power was reduced slightly to 98 percent. Vacuum was restored by realigning the steam jet air ejectors. There have been problems related to condenser vacuum since the plant was placed online on December 21,199 . On February 9,1999, while planned maintenance was performed on the "A" SFU train, l&C technicians discovered that the "B" SFU differential pressure switch photocell light was not lit. However, l&C technicians wev .acorrect in their assumption of how the SFU differential pressure switch 1metioned. Based on this information from the l&C technicians, the system engineer recommended to the onshift operators that the "B" SFU train be declared inoperable. No review of the vendor manual or other information sources on the switch were checke . During a post-maintenance review of the function of the light bulb for the ,

photocell in the differential pressure switch, the licensee discovered the heater '

would still have been operable. The photocelllight beam is blocked when the ;

flow indicating needle reaches the flow set point, which allows the heater to I energize. The licensee was ordering a new style switch with a light emitting diode, which the vendor considered more reliable. Operators began a power reduction due to both trains considered inoperable, which was that was later terminated at 80 percent reactor power after the "B" SFU differential pressure switch was replaced and tested satisfactoril .

. On February 21,1999, with the plant at 80 percent power after the completion of I main turbine testing activities, a steam tunnel high temperature alarm annunciated in the control room. A resistor was found to have burnt up and was replaced. This was the third relay for main steam tunnel high temperature logic to have failed in the last three months. The maintenance manager initiated AR 9914486 to identify this problem. However, the inspectors identified by a review of past ARs, that this was a longstanding problem. In discussions with maintenance personnel, the inspectors found there was no finalized plan to address the problem. The inspectors noted that maintenance personnel repaired the main steam tunnel high temperature Group one (MSIVs) resistor in a timely manne )

. On February 22,1999, during a surveillance test on the "B" SBGT system, observant I&C technicians identified that the "A" SBGT system flow indicating controller was reading higher than expected flow. Operators had to momentarily f

l enter LCO 3.0.3 when the "B" train of SBGT system control switch went from auto to manual position when the train was secured from the surveillance tes Conclusions Observant I&C technicians noted that the air flow indicating controller was not reading accurately on the "A" SBGT system while calibrating the "B" train. Howevor, the l&C technicians were mistaken in their initial understanding of the operating principle of the differential pressure switch for the control room SFUs, which required operators to enter TS 3.0.3 because the other train was also inoperable for maintenance. Initial response from the various maintenance department personnel was viewed as timely and appropriate for repairs to the failed resistor in the logic circuitry for the main steam tunnel high temperature alarm. However, maintenance personnel lacked a definitive plan to address the longstanding problem of the resistor failure M3 Maintenance Procedures and Documentation M3.1 Standbv Gas Treatment System Efficiency Test Inspection Scope f 61726)

The inspectors observed portions of STP 3.6.4.3-03, " Standby Gas Treatment (SBGT)

System HEPA and Charcoal Efficiency Tests," Revision Observations and Findinas Prior to performing STP 3.6.4.3-03 on the week of February 8,1999, the inspectors identified several ambiguous TS required steps. Technical Specification 5.5.7 required that SBGT system efficiency tests (Dioctyl phthalate (DOP] and halocarbon efficiency testing) demonstrate for each system that the penetration and system bypass be less than 0.1 percent. Surveillance Test Procedure 3.6.4.3-03 stated that the efficiency for both SBGT system trains be greater than or eaual_tg 99.9 percent efficient or less than 0.1 percent penetration This testing requirement was ambiguous by allowing an acceptable test result to equal 99.9 percent efficient or to be less than 0.1 percent penetration. The inspectors reviewed the TS that were in effect prior to August 1,1998, and noted that the SBGT system efficiency testing required that results be squal to or

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less than 99.9 percent efficient. Therefore, the licensee combined old and current TS l requirements without identifying the subtle difference between the two requirement J The licensee initiated AR 9914464 and revised STP h 6.4.3-03 prior to performing the sunleillance tes Also, as detailed in Section O3.2, an ACP was not updated to reflect current plant conditions. In addition, as detailed in Section 01.1, a non-licensed operator did not complete the actions of a warning placard by opening a door when securing the steam jet air ejectors room exhaust fans during the testing. Although the non-licensed operator did not complete tha warning placard actions, the testing was completed satisfactoril c. Conclusions The inspectors identified several ambiguous TS required steps prior to SBGT system ,

efficiency testing. The licensee failed to recognize the subtle differences in testing j requirements from old and current TS requirements. The licensee corrected the steps J prior to conducting the testin . Enaineerina E1 Conduct of Engineering E Enaineerina Support on Emeraent issues Comments (37551.)

a. Inspection Scope (37551)

The inspectors observed engineering involvement with the several equipment problems that occurred during this inspection period. The inspectors evaluated engineering involvement in the resolution of the emergent equipment problems. The inspectors reviewed areas such as operability evaluations and root cause analyses. The effectiveness of the licensee's controls for the identification, resolution, and prevention of problems was also examine b. Observations and Findinas l

When the control room "B" train of SFU was declared inoperable, the system engineer's initial operability evaluation was incorrect in assuming that the differential pressure switch was inoperable. The system engineer did not refer to the vendor manual, which was available onsite. The system engineer relied solely on the incorrect information provided by the l&C technicians. Bench testing the following day indicated that with the light for the photocell not lit, the flow switch provided the heater permissive logic signal as if adequate flow existed. Therefore, if an initiation signal had been received, the

"B" SFU system would have started, the heater would have energized, and the safety function of pre-heating the air would have been fulfilled. The operators would not have had to enter TS 3.0.3 and initiated a shutdown of the plan As was noted earlier with the failure of the main steam tunnel high temperature resistor in the logic circuitry, there have been three similar failures in the last three month These appeared to be age-related problems with the plant equipment. No specific

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action as yet has been proposed. This resulted in operators holding power at a reduced level with a % scram condition until the relay was replace The system engineer for the SBGT system failed to initiate a procedure change to ARP 1C23, C3, to reflect the change to allow Door 108 to remain closed during operation of the SBGT system. This resulted in a Non-Cited Violation for failure to process a procedure change affecting related procedure On January 17 and February 21,1999, during the planne-d downpowers, engineering personnel, with the assistance of a vendor, performed testing to determine the source of elevated steam jet air ejector and offgas flow. The problem was believed to be condenser inleakage. The testing proved inconclusive. There have been minor operational problems related to condenser vacuum since the plant was placed online following a forced maintenance outage on December 21,1998. The inspectors noted the condenser inleakage problem was not yet resolved. However, a review of actions taken to date indicated a methodical and deliberate approach to identifying the inleakage source. The lead engineer had contacted several other utilities for ideas to f

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resolve the proble f The system engineer is responsible for ensuring the system is capable of meeting its design furiction through surveillance test procedures. An earlier opportunity to identify that the diesel generators met their design function by starting and coming to a specified voltage and frequency was missed. This resulted in a Non-Cited Violation for an inadequate procedur Since January 1,1999, there have been almost daily main generator field ground annunciators received in the control room. Although the problem has not yet been resolved, engineering and maintenance personnel actions have been deliberate and thorough. The licensee has contacted the generator vendor on several occasions and kept them up to date on troubleshooting progress. Several other utilities were contacted for the troubleshooting methods they employed. The ARP was revised to reflect the problem, instrumentation to record the grounds when received was thoroughly reviewed

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and walkdowns of accessible equipment were also don <

C. Conclusions Although the issues for loss of condenser vacuum and the main generator ground have not been resolved, licensee action to date was thorough and methodical. The system engineer performed an inadequate initial operability evaluation on the "B" SFU differential pressure switch function, which resulted in operators initiating an unnecessary plant shutdown. Also, the failure of the Group one logic circuitry has been a longstanding problem with no specific corrective action proposed. Finally, the system engineer missed an earlier opportunity to identify a surveillance procedure deficiency for the standby diesel generator v ,

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P1 . Conduct of Emergency Preparedness Activities

' P Emeraency Preparedness Trainina Drills Inspection Scope (71750j The inspectors observed.the emergency preparedness training drills on January 27 and February 17,1999. The inspectors observed portions of both drills and the pre-drill brief. Operations personnel were observed in the simulator, Observations and Findinas The inspectors observed good command and control by the operations shift superviso Licensed operators use of three-way communications was adequate. Through the course of the simulator drill on January 27,1999, the licensee identified that the primary containment radiation monitor control panel alarm setpoints were more conservative than the actual control room alarm setpoints. As detailed in Section M1.2, the simulator control room primary containment radiation monitor alarm setpoints were revised to match the updated conservative emergency action level radiation set points; however, the revision to the actual control room panel afarming setpoints was delayed for approximately five month Conclusions Overall, licensee performance in the emergency preparedness training drills was goo No significant weaknesses were noted. The licensee identified a discrepancy between the primary containment radiation monitoring alarm setpoints in the simulator control room from the alarm setpoints in the actual control roo V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on March 2,1999. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie ,

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PARTIAL LIST OF PERSONS CONTACTED

- Licensee R. Anderson, Manager, Outage and Support J. Bjorseth, Maintenance Superintendent D. Curtland, Operations Manager J. Franz, Vice President Nuclear R. Hite, Manager, Radiation Protection )

M. McDermott, Manager, Engineering K. Peveler, Manager, Regulatory Performance 1 G. Van Middlesworth, Plant Manager

INSPECTION PROCEDURES USED IP 37551: Onsite Engineering

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IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing .

Problems

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- IP 61726: Surveillance Observation IP 62707: Maintenance Observation 1-IP 71707: Plant Operations J IP 71750: Plant Support 1 ITEMS OPENED, CLOSED, AND DISCUSSED-Opened 50-331/99001-01 NCV Failure to take corrective actions after AR closure on spent fuel pool issue 50-331/99001-02 NCV TS SR for standby diesel generators not met by surveillance procedure 50-331/99001-03 -NCV Procedural adherence deficiencies regarding storage of non-fuel items in spent fuel pool and cask pool Closed 50-331/99001-01 NCV Failure to take corrective actions after AR closure on spent fuel

. pool issue 50-331/99001-02 NOV TS SR for standby diesel generators not met by surveillance procedure 50-331/99001-03 NCV Procedural adherence deficiencies regarding storage of non-fuel items in spent fuel pool and cask pool

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i Discussed None

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LIST OF ACRONYMS USED ACP Administrative Control Procedure AR Action Request ARP Annunciator Response Procedure CFR Code of Federal Regulations DAEC Duane Arnold Energy Center DRP Division of Reactor Projects l&C Instrument and control IP Inspection procedure ,

ITS Improved Technical Specifications l

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LCO Limiting condition for operation MSIV Main steam isolation valve NCV Non-cited violation NOED Notice of Enforcement Discretion NRC Nuclear Regulatory Commission SBGT Standby gas treatment SFU Standby filter unit i

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SR Surveillance requirement STP Surveillance Test Procedure STS Standard Technical Specifications TS Technical Specification UFSAR Updated Final Safety Analysis Report

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