IR 05000010/1997004

Insp Repts 50-010/97-04,50-237/97-04 & 50-249/97-04 on 970125-0307.No Violations Noted.Major Areas Inspected: Operations,Maintenance,Engineering & Plant Support

ML20138K114
Person / Time
Site:	Dresden
Issue date:	05/01/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20138K102	List: IR 05000010/1997004 ML20138K098
References
50-010-97-04, 50-10-97-4, 50-237-97-04, 50-237-97-4, 50-249-97-04, 50-249-97-4, NUDOCS 9705120159
Download: ML20138K114 (20)

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U.S. NUCLEAR REGULATORY COMMISSION REGION lll Docket Nos: 50-10; 50-237; 50-249 ,

License Nos: DPR-2; DPR-19; DPR 25

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l Report No: 50-010/97004; 50-237/97004; 50-249/97004 i

Licensee: Comed i l

Facility: Dresden Nuclear Station Units 1,2, and 3 l

l Location: 6500 N. Dresden Road Morris, IL 60450 Dates: January 25 - March 7,199 !

Inspectors: J. Hopkins, Acting Senior Resident inspector, Dresden K. Riemer, Senior Resident inspector, Duane Arnold l L. Collins, Resident inspector, Quad Cities j J. Hansen, Resident inspector, Dresden j E. Plettner, Operator Licensing Examiner D. Roth, Resident inspector, Dresden )

C. Settles, inspector, Illinois Department of Nuclear j Safety, Dresden C. Brown, Resident inspector, Big c xk Point Approved by: Wayne J. Kropp, Chief Reactor Projects Branch 1 i

I 9705120159 970501 PDR ADOCK 05000010 0 PDR

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i EXECUTIVE SUMMARY

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Dresden Nuclear Station Units 1,2, and 3 '

NRC Inspection Report 50-10/97004; 50-237/97004; 50-249/97004 Areas inspected this period included aspects of licensee operations, maintenance,  !

engineering, and plant support. The report covers a 6-week period of resident inspectio l Operations Overall, the licensee completed the startup of Unit 3 safely. Good communications, and command and control were observed by the inspector. The inspectors observed that the  ;

operators were attentive to the panels, knowledgeable of the reasons for lit annunciators, and aware of activities in the plant. The procedures reviewed by the inspectors were noted as adequat !

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During routine control room and field observations, the inspectors noted some examples of '

good performance. However, during this inspection period your staff, concurrent with the NRC, identified several performance issues in operations. There were examples of issues and events that involved poor communications and failing to follow through on question l Your staff's recognition of these issues and the steps taken to reinforce operational standards were indicative of a sound self-assessment process. The effectiveness of your *

staff's corrective actions will be assessed by the NRC in future inspection ;

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Maintenance l

The work witnessed or reviewed by the inspectors was performed correctly. Some minor )

inattention-to-detail and lack-of-a-questioning-attitude were noted concerning wrong valve numbers in a work package and an emergency light being lit due to a tripped breake Good radiological practices were note The inspectors' review indicated that the licensee's initial response, immediate corrective actions, and prompt investigation for a licensee identified error involving data transpositioning during a high pressure coolant injection surveillance were goo Engineerina Errors in the core flow calibration during the Unit 3 startup revealed additional examples of known design control deficiencies. The licenseo took appropriate corrective actions to address the design data problems, and to improve procedures, decision . making, and i communicatio ,

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Plant Suncort

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l Workers were following good radiological practices. The use of a " greater" to challenge workers reinforced station standards. The inspectors considered the radworker and radiation protection performance to be goo I I Site Quality Verification

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Part of the input to management's assessment of performance in operations was the site

! quality verification (SOV) department conclusion that a decrease in overall station performance had occurred during this inspection period. The SOV management indicated that the decline was being discussed with each department and the licensee planned to bring in a root-cause assessment contractor. The inspectors considered the SOV identification to be timel i e

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REPORT DETAILS Summary of Plant Status Unit 2 entered the period at full power. On February 8, load was reduced to 550 MWe for surveillance testing. During the testing, a control rod was l mispositioned. This power level was held until initiation of corrective action on February 12. On February 14, load was decreased to support minor maintenance and a drywell entry. Load increase began on February 16. On February 27, load was decreased about 10 percent to bring feedwater inlet temperature to within the Updated Final Safety Analysis Report (UFSAR) indicated values. This issue was '

resolved March 10. Full power was not restored until March 11 after an engineering review and assessment of a Unit 3 pressure regulator drift problem to assure it did not affect Unit Unit 3 began a startup on January 29 and completed it February 8. Power was .

then maintained at maximum "coastdown" leve I 1. Operations 01 Conduct of Operations *

01.1 General Comments (71707)

The inspectors conducted frequent reviews of plant operations. Overall, the conduct of operations was safe and in accordance with procedures. During control room tours, the inspectors assessed operator performance that included communications, command and control, control of work activities, and adherence to procedure During the inspection period, several events occurred, some that required prompt notification of the NRC per 10 CFR 50.72 or licensee event reports (LERs) per 10 CFR 50.73. The events are listed below:

January 27 Several piping systems found outside code allowable per NRC generic f letter (GL) 96-0 February 8 High voltage operator inside round found to have incorrect surveillance frequency for check of reactor level and pressure check February 9 High pressure coolant injection (HPCI) system pump min-flow switch found out-of-toleranc !

February 10 Reported tampering of security equipmen !

Febrmy 11 Backup Unit 1 chimney air sampler tripped while in us ,

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February 13 HPCI system Hl/LO flow switch found out of Technical Specification Limit ,

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February 26 Low pressure coolant injection (LPCI) loop select logic permissive set non-conservativel February 26 Unit Supervisor leaves control room for six minute >

i February 28 Shift Manager identified reportable issue with Unit 2 standby liquid i i

control discharge check valve while reviewing operability evaluation I

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i Preliminary assessment of the licensee's responses to these events determined the '

responses to be adequate. Final review of some of these events was documented t

in this report, other reviews will be done after receipt of the associated LER .2 Startun (Unit 3) i

Insoection Scone (71707) l The inspectors conducted direct observations of control room and field activities i

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during all shifts. The activities included sampling of all star.up activities, not just those of the Operations department. The inspectors reviewed the procedures used j during the startu .

Observations and Findinas

Control Room Observations The inspectors observed good communications both in the control room and between control room staff and staff in the field. Good pre-job and pre-evolution '

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briefings were observed. In particular, good control room preparation for the testing of the high pressure coolant injection (HPCI) system was note :

Management was present observing each shift as were personnel from site quality verification. Good command and control were evident during the Unit 3 startu ,

The inspectors observed that the operators were attentive to the panels,  ;

knowledgeable of the reasons for lit annunciators, and aware of activities in the plan '

Field Observations l

l During direct observations of field activities, the inspectors noted that personnel

were doing all required steps. Good performance was observed during preparations  !

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for starting a reactor feed pump and for testing the HPCI system. in-field 1 operations response to an unusual noise coming from the reactor water cleanup i

(RWCU) system was good. The inspectors had independently noted the noise, ,

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however the field operator had resolved it before the inspectors discussed it with  !

plant managemen j i )

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l System engineers were observed to be providing in-field support to plent i operations. For example, the appropriate system engineers were present in the

! plant supporting operations during startup of the steam jet air ejectors and the 4 recombiner, during turbine roll-up, and walking down the accessible portions of the electro-hydraulic control (EHC) system piping.

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j Procedure Adeouacy The inspectors audited a sample of procedures revised to incorporate recent

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technical specification (TS) amendrnents including amendments needed to address 3 adequate net positive suction head (NPSH) for the emergency core cooling systems j (ECCS). All the procedures reviewed had been correctly change The inspectors reviewed the procedures used for various startup activities. One

conflict, between the general startup procedure (DGP 01-01) and a specific

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operational procedure (DOP 5400-02), was identified; however, the operating shift had indepo$ntly identified and corrected the same conflict. All other procedures appeared correct end adequat Known Material Condition Problems l Some equipment problems associated with material condition were self-evident l during the startup and affected the startup schedule or created emergent work. For l example, the 3A containment cooling service water (CCSW) pump motor bearing i fait rJ whh 8t was being used for torus cooling. This placed the station in a 30-day i TS limiting adition for operation (LCO). The HPCI system turbine had a known l stea m 1e 0 .., ming out one throttle block bolt spraying out almost a foot with the j plume about 3 feet. This affected room accessibilit J Problems not recoonized During the startup, the inspectors identified several material condition problems that were not recognized by plant personnel. For example, the inspectors noted that an emergency light in the Unit 2 HPCI system room was on. The licensee determined that the light was on because a breaker had tripped. The breaker was reset. The inspectors also noted a fire alarm horn that was buzzing near the Unit 3 generator hydrogen seal-oil skid. The inspectors identified that a rag had been stuffed into the horn so the sound was muffled. The inspectors notified the unit supervisor (US), who determined that the particular fire protection system was out of servic The inspectors verified that the fire protection system was out of, service. The US documented the rag stuffed in the fire hom in a potential improvement form (PlF).

Based on these two examples of material condition deficiencies, the~ effectiveness of the equipment operator tours in identifying material condition deficiencies is considered an inspection followup item pending further review by the NRC (No. 50-237:249/97004-01 (DRP)).

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l Distractions to Ooerations

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l The inspectors have noted that jobs were stopped or disallowed by the operating crew. For example, routine review of the US's logs for February 10 and 11 showed that operations stopped, disallowed, or discovered a modification that would have made off-gas fire extinguishing unavailable, an instrument surveillance that did not identify all valves that would be repositioned, that chemistry was using an 1 estimated flow to calculate off-gas, and surveillances on the isolation condenser and the main steam line rad monitors that were scheduled simultaneously thus increasing the potential for a main steam line (MSL) isolation without the isolation j condenser being available for pressure control. Some of these items were also

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documer?.ed in PlFs. The inspectors concluded that the unit supervisors were doing

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careful reviews and following through on questions. However, the inspectors were

, also concerned that the USs were being challenged too much by such issues.

i 01.3 Licensee Identified Performance issues l l Insoection Scone (71707) )

The inspectors reviewed and evaluated the licensee's assessment of performance-related events and issues. Included in this review was the licensee's responses to )

the events and issues, including the root cause report l

! Observations and Findinas

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Based on the following events and issues that occurred during the Unit 3 startup and day to day operational activities, the licensee concluded that performance has declined in operations. Some of the startup issues were the problems revealed during core flow calibrations. During the calibrations, a greater flow discrepancy than anticipated was found, so operations suspended reactivity changes on both units and investigated. As described in Section E4.1, problems with procedures were found. A second performance issue was poor control of main turbine lobe oil temperature. Rolling the main turbine was delayed due to problems controlling the temperature. The following events and issues were also part of the licensee's assessment of operations performanc Use of Short-Duration Time Clock (Unit 2)

On January 23, while performing Unit 2 main steam line (MSL) high flow switch calibrations, operations did not apply a TS limiting condition for operations (LCO)

time clock for 11 of 16 switches. The short-duration time clock 'was supposed to be used to ensure that the TS-Table 3.1.A-1 requirement of providing a trip if a channel was inoperable for longer than two hours was met. No TS violations resulted because the switches were all returned to operable within two hour The error started on the afternoon shift. The US and the Shift Manager (SM) both reviewed the time-clock requirements before the start of the calibrations, but misunderstood the trip logic, and therefore concluded that the short-duration time

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clock did not apply. As the job progressed to the midnight shift, the midnight shift l US questioned why the short-duration time clock was not being used, but after -

! discussions with the afternoon shift US, became convinced that it was not i* required. During turnover from midnights to days, the day-shift US questioned why the clock was not entered. After tumover, day-shift US determined that the clock

did apply. The day-shift US reviewed the alarm printout and determined that no channel was inoperable for more than two hours, so the TS was not violate ,

i The root cause investigation report (NTS No. 237-200-97-00700) identified failing ,

to use all available information and lack of an independent peer review as root i causes for the event. The inspectors concluded that some operators did not

] thoroughly follow through when they felt the time clock was not being used

{ correctly. The licensee's corrective actions included creation of a procedure to ,

] assist in identification of documents related to placing instruments in a tripped

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I The use of short-term time clocks was controlled by DAP 7-45, "Short Duration i Time Clocks." The failure to enter DAP 7-45 is considered a violation of 10 CFR l 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings."

i However, the inspectors reviewed the corrective actions and view this as a  !

l Non-Cited Violation, consistent with Section Vll.B.1 of the Enforcement Policy l

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(NCV No. 50-237/97004-02(DRP)).

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I Core Flow Calibration l I

! During core flow calibrations during the Unit 3 startup, a greater than anticipated error was revealed. Discussions of the engineering aspects of this are in Section E4.1. Operations response of promptly investigating the event and its ,

circumstances were considered conservative and insightful. However, it revealed some log keeping and communication problems between operations and engineerir Control Rod Misoositionina and Subseauent Miscommunication (Unit 2) ,

l On February 8, during control rod exercising, a nuclear station operator (NSO)

mistakenly moved a rod from notch 12 to notch 10 instead of notch 14. The operator notified the US of the mispositioning and DOA 300-12, "Mispositioned i Control Rod" was entered. However, the communication between NSO and US was inadequate and the US believed that rod had " double-notched" from notch 14 '

to notch 10. The US directed that the rod be returned to notch 14 then exited the DOA. These actions would have been correct if the rod had double-notche About half an hour later, the NSO re-discussed the event with the US, and the US then understood what happene The inspectors concluded this event revealed an error in communications that resulted in initially performing the incorrect steps of DOA 300-12. The failure to follow DOA 300-12 is considored a violation of 10 CFR 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings." However, the inspectors

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reviewed the corrective actions that included reentering Procedure DOA 300-12 an

placing all reactivity maneuvers on hold. The failure to follow Procedure DOA 300-12 is a Non-Cited Violation, consistent with Section Vll.B.1 of the Enforcement

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Policy (NCV No. 50-237/97004-03(DRP)). '

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Operations Resnonse I >

j While reactivity changes were on hold because of the rod mispositioning event,

operations management concluded that operations adherence to standards was j slowly decreasing. This was indicated by feedback from overviews and from noting that eleven events that involved operations had occurred during the past six week !

j Corrective actions were implemented to reemphasize operations standards, reduce control room distractions, and improve support to the control room including support from the work execution center (WEC). Examples of specific actions -

included institution of heightened level of awareness briefs for any planned power i change of 25 MW(th) or more, requirements for a senior reactor operator (SRO) to ,

! be present in the horseshoe during reactivity changes. The inspectors concluded

that these corrective actions were timely and had the potential to restore operations

! performance. On February 12, when operations management was satisfied with

initial implementation of improvement programs, the reactivity hold was lifte

i Power was not immediately increased on Unit 2 because Unit 3 had one reactor

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protection system (RPS) channel tripped due to a failed MSL radiation monitor, and j operations did not want to have the potential for responding to a reactor trip on ,

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! Unit 3 while performing reactivity changes on Unit 2. The inspectors concluded

] that this demonstrated a conservative operations approac ;

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Unit Suoervisor Leaves Control Room -

i l On February 26, the afternoon shift Unit 3 US was relieved by the out-of-service

! supervisor to attend a meeting. The relief US and the shift manager (SM) together !

j worked on an operability concern for low pressure coolant injection (LPCI) loop '

! select logic that resulted in an emergency notification system (ENS) call to the NR !

i The SM and relief US left the control room to review some LPCI logic ,

documentation. About six minutes later, the Unit 2 US noticed that the relief US !

had left the control room and immediately contacted the relief US. The upgraded technical specifications (TSUP) 6.2.B.2 required one licensed SRO per operating ;

unit, so the relief US's absence was reportable to the NRC as a Licensee Event !

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Report (LER) Note that the previous TS that were in place until January 13,1997, I permitted one SRO to leave the control room for short periods. Preliminary review

of this event indicated that the relief US did not remain focused on overall

monitoring of the unit for which he was in charge. Final review will be done after

receipt of the LE l l

01.4 Conclusions on Conduct of Ooerations i'

Overall, the licensee completed the startup of Unit 3 safely with good communications, and command and control observed by the inspectors with

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exception of the issues pertaining to core flow calibrations and the poor control of main turbine lube oil temperature. The procedures reviewed by the inspectors were noted as adequate. The inspectors also observed that the operators were attentive to the panels, knowledgeable of the reasons for lit annunciators, and aware of activities in the plant. However, the inspectors also noted that jobs had to be stopped or disallowed by the operators due to poor work planning. The inspectors noted some examples of good performance during routine control room and fiel .

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observations, however at the same time as the licensee the inspectors concluded '

that a number of recent events and issues were indicative declining performance in operations. There were examples of issues involving poor communications and failing to follow through on questions during day-to-day operational activities (non-startup). This was a notable decrease from the previously observed level of ,

performance. As stated previously, plant management recognized this and took !

steps to reinforce operational standards. However, soon after the reinforcement of operations standards, a unit supervisor became distracted from his duties and left the control room. The corrective action to this event will be assessed during the :

associated LE Quality Assurance in Operations

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07.1 Site Quality Verification Trendino f40500)

The site quality verification (SQV) department also identified a decrease in overall '

station performance during this inspection period. This was based on increased personnel errors and LERs. SOV indicated that the decline is being discussed with each department. Also, the licensee planned to bring in a root-cause assessment ;

contractor. The inspectors considered the SOV identification to be timel ,

11. Maintenance

M1 Conduct of Maintenance M1.1 General Comments  ;

The maintenance activities directly observed by the NRC were performed correctl Additionally, the workers were observed to practice good communication and good ,

radiation worker practices. However, during this inspection period there were several licensee-identified problems in maintenance activities that displayed poor l

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attention to detail. Sorns of which were discussed in Sectiori M4.1 and M belo !

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! Maintenance Staff Knowledge and Performance j-1 M4.1 General Work Performance i Insoection Scoos (62707)

! The inspectors reviewed and observed maintenance and reviewed the work j packages for emergent work on the HPCI system and on a CCSW pum ;

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Procedures reviewed included  ;

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DAP 15-06, " Preparation, Approval, and Control of Work Packages and

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l DAP O2-27, "The Integrated Reporting Process (IRP)."  !

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WR # 970003382 Unit 2 HPCI MSL drain pot level switch steam leak,  !

WR # 970011660 Unit 3 3A CCSW pump motor repair, j

WR # 960031601 Surveillance test DlS 2300-08, Unit 2/3 CCST and Unit

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2 torus level switches functional test, j

WR # 970005856 Unit 2 HPCI steam line drain leak repai !

Observations and Findinas 7

I l Overall, the maintenance staff was following the procedures and performing work i correctly. The inspectors noted good radiological awareness, as evidenced by use j j of low dose areas for discussion !

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Package review for work on the Unit 2 HPCI MSL drain pot level switch steam leak l

revealed that the maintenance workers identified that the valve numbers were  !

wrong. The workers had the work package revised in the field to correct the valve numbers. Discussions with the work analyst who walked down the job before j l issuing the package revealed that the valve numbers had not been checked dunng

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the work analysts' walkdown, and that the work package with the incorrect valve l

numbers had been developed from a previously used work package. The inspectors  ;

considered not checking the valve numbers during the walkduwn to be minor  !

because the error was detected by the workers. A review of the completed work ]

i package revealed that OC initially rejected it due to the bill of materials not being

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signed and the quality roi.,6pt inspection (ORI) number not being included. As discussed in Section 01.2, the inspectors identified that workers in the Unit-2 HPCI

room did not recognize a lit emergency light as indication of a problem.~ Overall, the inspectors concluded the work was satisfactory, but also noted some inattention to detail and lack of questioning attitud l >

Observation of work and package review for the 3A CCSW motor bearing revealed no discrepancies. The motor bearing had started to fail while it was being used for

] torus cooling during the Unit 3 startup. Discussions with station management

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l; showed that the work was receiving sufficient attention such that it would be done in about half the LCO time. The inspectors concluded that actions taken to i i complete the job within the LCO time seemed reasonable, and the resources being

used by the licensee were appropriate to the syste !

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j No disciapancies or issues requiring specific comment were noted during inspection  !

of other work.

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The work reviewed was performed correctly. Workers followed the work package l Good radiological practices were noted. Some minor inattention to detail and lack j of questioning attitude were noted.

M4.2 Hiah Pressure Coolant Iniection (HPCII Low Flow Setooint Miscalibration (Unit 3)

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Insoection Scone (927001 l i  !

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f The inspectors performed a follow-up inspection of a Unit 3 HPCI low-flow switch i miscalibration identified by the licensee during surveillance testing on February 9, (

] 1997. The miscalibration was reported to the NRC in accordance with 10 CFR i 50.72. The inspectors reviewed TS, the updated final safety analysis report ,

j (UFSAR), and dis 2300-02, "High Pressure Coolant injection Flow Calibration" and i held discussions with instrument mechanics and supervisor .  ; Observations and Findinas f

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On February 9,1997, during performance of the DlS 2300-02 surveillance test, the ,

, licensee found the low-flow setpoint to be 2.2 inches water column (in WC), l

outside the TS limit of a: 600 g.p.m. (equivalent to 2.82 it'. WC). A review of the  ;

maintenance history revealed that the low-flow switch setpoint had not been  !

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adjusted and had been left outside acceptable limits due to a data transposition ,

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while performing DlS 2300-02 on November 14,1996. The technician had inadvertently recorded the low flow switch reset value as the as-found trip value l and the low-flow switch trip setpoint value as the as-found reset value. The high  ;

flow trip and reset points were recorded correctly. The as-found reset point was

within the tolerance specified for the as-found trip setpoint. However, the L relationship between the trip and reset values were reversed from the indicated

relationship in the surveillance procedure. The data transposition was not identified j by the technicians during data taking and reviews or during reviews by the ,

instrument maintenance department (IMD) supervisor and the U l

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i The HPCI system's ability to perform its safety function was not degraded by the I miscalibration as the high-flow switch was calibrated correctly. The miscalibrated

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low-flow switch would have caused the minimum flow possibly to be too low if the HPCI flow was reduced following an HPCI actuation, creating the potential for pump over heating and possible degradatio ;

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The corrective actions included changing data recording practices for the IMD personnel to require two independent data recorders and a separate subsequent revie '

The technicians failed to follow the procedure, and the reviewing supervisors failed adequately to verify that the expected results were obtained. A similar instance of data transposition was discussed in inspection Report (IR)50-010; 237:249/96016(DRP), Section M3.2, and is further discussed in Section below. This second data transposition actually occurred before discovery of the first, so it could not have been prevented by previous corrective actions. This licensee-identified failure to follow procedure DlS 2300-02 is considered a violation l of 10 CFR 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings." l However, the inspectors reviewed the corrective actions in the associated LER and '

view this as a Non-Cited Violation, consistent with Section Vll.B.1 of the Enforcement Policy (50-249-97004-04(DRP)).

I Conclusions  ;

The inspectors' review indicated that the licensee's initial response, immediate I

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corrective actions, and prompt investigation were good. However, this was the second licensee-identified TS violation caused by transposing data during equipment surveillance tests within 3 month I

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M7 Quality Assurance in Maintenance Activities M7.1 Use of Intearated Reoortina Process (40500) ]

The inspectors reviewed the potential improvement forms (PlFs) to determine if PlFs had been written for problems encountered during work described in Section M The inspectors also reviewed DAP 02-72, "The Integrated Reporting Process (IRP),"

to assess guidance on when a PlF should be written. The inspectors found that PlFs were written to guidance identified in DAP 02-07. However, a PIF was not written documenting the issuance of a work package with incorrect valve number No specific guidance in DAP 02-72, required that one be written. The inspectors discussed the issue with SOV management. The SOV management reviewed the issue with maintenance management and both concluded that a PlF would be appropriate for such an issue. There is an open corrective action record (CAR) for failure to generate PlFs (CAR 12 96-069) that the licensee is using to track and correct station use of the IRP. The site integrated reporting process was planned to be replaced by a corporate process at the start of April, and training will be given to all individuals on this new process. The inspectors concluded that PlFs for maintenance activities were being written in accordance with the guidance in DAP 02-0 I i

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M8 Miscellaneous Maintenance issues (92903)

M8.1 (Closed) URI 50-237/96016-01(DRP): evaluation of miscalibration of Unit 2 turbine first stage 45-percent scram-bypass switches. This event was discussed in IR 50-10:237:249/96016, Section M3.2, and was unresolved pending receipt and review of the LER. The LER was submitted to the NRC, and is discussed in Section M8.2 below. This unresolved item is close M8.2 (Closed) LER 50-237/97002: miscalibration of Unit 2 turbine first stage 45-percent scram-bypass switches. On January 9,1997, a technician failed to follow DIS 0500-07, "45 Percent Core Thermal Power Scram Bypass Pressure Switches Calibration and Functional Checks," Revision 8, as written and failed to verify that the procedure achieved the expected results. The technician transposed the trip and reset values on four channels, resulting in exceeding TS limits until the error was found and corrected on January 13,199 Corrective actions included reviewing the event with all IMD management and technical personnel to reinforce expectations regarding surveillance performance and revie This licensee-identified failure to follow procedure DlS 0500-07 is considered a violation of 10 CFR 50, Apodix B, Criterion V, " Instructions, Procedures, and Drawings." However, the inspectors reviewed the corrective actions in the associated LER and view this as a Non-Cited Violation, consistent with Section Vll.B.1 of the Enforcement Policy (50-237-97004-05(DRP)).  :

M8.3 (Closed) LER 50-249/97001: high pressure coolant injection low-flow switch i setpoint miscalibration. This LER was discussed in Section M4.2 of this report and was determined to be a Non-Cited Violation. This LER is close Ill. Enoineerina E4 Engineering Staff Knowledge and Performance E Core Flow Calibration Insoection Scoos (37551)

The inspectors reviewed the ongoing investigation into a greater-than-expected mismatch in core flow during Unit 3 startu Observations and Findinas During core flow calibrations, the actual core flow exceeded the indicated flow by 17 Mlbm/h, much greater than the anticipated error of 6 Mlbm/n. Operations management suspended planned reactivity changes on both units pending

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investigation and corrective actions. The safety significance was reviewed and it l was determined that no limits were exceede ;

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Preliminary investigation into the root cause revealed that the cold calibration of the l core flow calibration was based on incorrect data and actually introduced an erro '

The subsequent calibration under hot conditions removed the error because the hot calibration was based on correct dat !

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The error in the cold calibration resulted from use of a span of 0 to 6 Mibm/h in DlS l 0260-01, consistent with the GE design specification data. However, the GE data !

sheet was inconsistent with the GE startup data, which indicated that the span l should be O to 7.5 Mlbm/h. (The UFSAR, Section 5.4.1.5.2, stated that detailed performance tests were made at cold, hot standby, 25%,50%,75%, and 100% l power). Since the DlS used 0-6 Mibm/h, it introduced the error during a cold calibration. The qualified nuclear engineers used 0-7.5 Mibm/h during hot !

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calibration and eliminated the error. The hot calibration was effectively an engineering work around for the flawed cold calibratio i The error was more evident during this startup because of how the calibration was !

scheduled and for the startup. Previously, this calibration was done at refueling, i then at about 50% power using procedural guidance. However, it had been ,

rescheduled and done during the forced outage from which the unit was startin Because it was a forced outage startup, the guidance for a 50% power calibration !

did not exist. Instead, engineering planned to perform the final calibration near full '

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flo The event revealed potential errors or deficiencies in design data and monitoring I secondary indications during the power increase. Prompt corrective actions included operations and engineering procedure enhancements to assure monitoring of secondary core flow indications and to add acceptance criteria and institution of heightened level of awareness (HLA) briefings for significant reactivity maneuver The licensee also considered this event to demonstrate a non-conservative mind set when the engineers chose the flow level for hot calibration Errors in the accurate translation of design data into procedures have been previously identi.fied at the site. During the NRC Independent Safety inspection (ISI)

(50-10:237:249-96201), deficiencies in translating design data into procedures were documented (Deficiency 50-237(249)/96201-22). There are other examples of similar errors (e.g., ENS call on February 26 regarding LPCI Loop Select 900 psig permissive being set non-conservatively due to inaccurate transla. tion of design documents into procedure).

Because of these known deficiencies, the licensee has been systematically reviewing, and, as necessary, correcting design information. However, it was not i

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clear if the error in the information used to make the DIS would have been found during the current or planned engineering design reviews. The long-term corrective actions for this event included reconstituting the jet pump and core flow calibrations. At the end of this

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reporting period, the licensee had not completed its root cause investigation (NTS 249-200-97-00200). This issue is considered unresolved pending assessment of the final root cause (Unresolved item 50-249/97004-06(DRP)).

I Conclusions j i

The core flow calibration introduced an error during the cold calibration due to the

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incorporation of incorrect data. The error was subsequently removed during hot calibrations. The magnitude of the error during this startup was due to the scheduling of the cold calibration and the hot calibrations. The licensee response to the large error was good, resulting in detection of the incorrect design data, and improvements to' procedures to preclude recurrence. The use of other incorrect ,

design data was a known issue for which the licensee was taking corrective actio IV. Plant Suncort R4 Staff Knowledge and Performance in Radiation Protection and Chemistry R4.1 Performance of Staff and Workers Insoection Scoos (71750)

During routine tours of the radiologically protected area (RPA) and observations of maintenance and surveillance activities, the inspectors assessed performance of radworkers and radiation protection staf Observations and Findinas Workers were following good radiological practices. Maintenance workers discussing procedures were observed to go to designated low-dose waiting area The radiation protection staff enforced station policies regarding the radiation protection area by directly challenging workers as they entered the RPA. This was done by use of a " greeter" who quizzed workers before allowing them access to the RPA. Workers who were not complying with station policy were then locked out of the RPA pending meeting with radiation protection management, and the lockout was documented in a PIF. Radiation protection personnel also challenged and quizzed workers already in the RPA. During high-traffic periods, a guard posted at the security egress verified that personnel who set off the radiation monitors did not exi Conclusions Workers were following good radiological practices. The use of a " greater" to challenge workers reinforced station standard .

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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 7,1997. The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie Partial List of Persons Contacted Licensee Steve Perry, Site Vice President Mike Heffley, Station Manager Robert Holbrook, Training Manager Carl Richards, Site Quality Verification Director (acting)

Tim O'Connor, Operations Manager Steve Barrett, Assessor Frank Spangenberg, Regulatory Assurance Manager e

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List of Inspection Procedures Used I

IP 40500: Effectiveness of Licensee Controls in identifying, Resolving, and Preventing l Problems IP 62707: Maintenance Observation IP 71707: Plant Operations IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92903: Followup - Maintenance IP 37551: Onsite Engineering l IP 71750: Plant Support Activities ]

List of items Ooened Closed, and Discussed Opened 50-237/97004-01(DRP) IFl Effectiveness of the equipment operator tours 50-237/97004-02(DRP) NCV Failure to follow DAP 7-45 50-237/97004-03(DRP) NCV Failure to follow procedure DOA 300-12 50-249-97004-04(DRP) NCV Unit 3 HPCI System low-flow switch setpoint miscalibratio j

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50-237-97004-05(DRP) NCV Miscalibration of Unit 2 turbine first stage 45-percent scram-bypass switche /97004-06(DRP) URI Errors identified during core flow surveillanc Closed i

50-237/97004-02(DRP) NCV Failure to follow DAP 7-45 50-237/97004-03(DRP) NCV Failure to follow procedure DOA 300-12 50-249-97004-04(DRP) NCV Unit 3 HPCI System low-flow switch setpoint miscalibratio (DRP) NCV Miscalibration of Unit 2 turbine first stage 45-percent scram-bypass switche /96016-01(DRP) URI Evaluation of miscalibration of Unit 2 turbine first stage 45-percent scram-bypass switche /97002 LER Miscalibration of Unit 2 turbine first stage 45-percent scram-bypass switche /97001 LER HPCI System low-flow switch setpoint miscalibratio Discussed 50-237:249/96201-22 DEF The failure to have appropriate design input informatio l

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LIST OF ACRONYMS AND INITIALISMS USED CAR Corrective Action Record CCST Contaminated Condensate Storage Tank CCSW Containment Cooling Service Water CFR- Code of Federal Regulations DAP Dresden Administrative Procedure l DGP Dresden General Procedure DlS Dresden instrument Surveillance DOA Dresden Operating Abnormal Procedures DOP Dresden Operations Procedure DRP Division of Reactor Projects EHC Electro Hydraulic Control ENS Emergency Notification System GE General Electric GL Generic Letter GPM Galoons per minutes, HLA Heightened level of awareness-HPCI High Pressure Coolant injection IMD instrument Maintenance Department

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IFl Inspection Followup Item IP inspection Procedures IR inspection Report IRP Integrated Reporting Process ISI independent Safety inspection LCO Limiting Condition for Operation

! LER Licensee Event Report l LPCI Low Pressure Coolant Injection l Mibm/h Megapounds-mass of water per hour l MSL Main Steam Line i M W(th) Megawatts thermal i MWe Megawatts electric NCV Non-cited Violation NOV Notice of Violation NPSH Net Positive Suction Head NRC Nuclear Regulatory Commission NSO Nuclear Station Operator NTS Nuclear Tracking System PDR Public Document Room PIF Performance improvement Form OC Ou:Aty Control ORI Gusty Receipt inspection RPA Rade!ogically Protected Area 1

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SPS Reactor Protection System RWCU Reactor Water Cleanup SM Shift Manager SOV Site Quality Verification SRO Senior Reactor Operator

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• TS Technical Specification TSUP Technical Specification Upgrade Program UFSAR Updated Final Safety Analysis Report URI Urwesolved item US Unit Supervisor WC Water Column WEC Work Execution Center l

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