IR 05000237/1999003

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Insp Repts 50-237/99-03 & 50-249/99-03 on 990110-0226. Non-cited Violations Identified.Major Areas Inspected: Aspects of Licensee Operations,Engineering,Maint & Plant Support
ML17191B299
Person / Time
Site: Dresden  Constellation icon.png
Issue date: 03/25/1999
From:
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML17191B298 List:
References
50-237-99-03, 50-237-99-3, 50-249-99-03, 50-249-99-3, NUDOCS 9903310067
Download: ML17191B299 (31)
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Text

U.S. NUCLEAR REGULATORY COMMISSION

Docket Nos:

License Nos:

Report No:

Licensee:

Facility:

Location:

Dates:

Inspectors:

Approved by:

9903310067 990325 PDR ADOCK 05000237 G

PDR REGION 111 50-237; 50-249 DPR-19; DPR-25 50-237 /99003(DRP); 50-249/99003(DRP)

Com Ed Dresden Nuclear Power Station, Units 2 and 3 6500 N. Dresden Road Morris, IL 60450-9766 January 10, 1999, through February 26, 1999 K. Riemer, Senior Resident Inspector B. Dickson, Resident Inspector D. Roth, Resident Inspector R. Lerch, Project Engineer R. Langstaff, Reactor Inspector J. Roman, Illinois Department of Nuclear Safety M. Ring, Chief

Reactor Projects Branch 1 Division of Reactor Projects

  • ,

EXECUTIVE SUMMARY Dresden Nuclear Power Station, Units 2 and 3 NRC Inspection Report 50-237/99003(DRP); 50-249/99003(DRP)

This routine inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 6-week period of resident inspection with augmentation by a Project Engineer and by an inspector from the Illinois Department of Nuclear Safet Operations

The plant management personnel provided proper oversight of the outage activities on Unit 3 while maintaining Unit 2 operating at full power. (Section 01.2)

  • .

Spurious operation of the shutdown cooling high temperature isolation twice caused losses of shutdown cooling: The operators responded appropriately and restored cooling. (Section 02.1)

Due to a combination of procedural problems and a repetitive material condition challenge, operators were unable to immediately perform the actions of the annunciator response procedure. As a result, the length of time that the isolation condenser, a relatively high worth system in the plant's Probabilistic Risk Assessment, was in an alarm status was unnecessarily lengthened. (Section 02.2)

The station failed to ensure that the latest revision of a procedure was available to control room operators prior to performance of a test. Operators did not document the occurrence via the Problem Identification Form (PIF) process until questioned by the inspectors. (Section 03.1)

Operators completed the Unit 3 shutdown safely and correctly. (Section 04.1)

Operators performed well during the conduct of the rea_c.to_r_star:tup.-T.t:ie-013eFators------

CORGlt-.1eted-good-heightenea-:1evel of awareness briefs, and communicated well and executed tasks in a conservative and deliberate manner. (Section 04.2)

Overall operator performance was good. In general, the operations staff followed procedures correctly, used good command and control, and took correct actions. This resulted in generally smooth operations, and contributed to good housekeeping in the

  • plant. (Section 04.3)

Operator performance in opening an instrument valve during restoration from the Unit 3 hydrostatic test led to an unplanned full scram while the reactor was shutdow (Section 04.3)

Procedural inadequacies contributed to the licensee inadvertently exceeding a Technical Specification limitation for drywell..:to-torus leakage and the subsequent entry into the *

drywell-to-torus differential pressure limiting condition for operation (LCO). The inspectors also noted that the operator failed to recognize that the valve manipulation being performed on this system would cause equalization between the drywell and the torus. (Section 04.4)

There were no identified fuel handling errors such as mispositions and misorientations during either the partial offload or fuel shuffle evolutions. Inspectors also reviewed a video tape of the final reactor core loading audit and identified no errors. (Section 04.5)

The inspectors concluded that housekeeping in both the drywell and torus was good as evidenced by closeout inspections which only found minor discrepancie (Section 04.6)

Five instances occurred during the inspection period where actions by station personnel resulted in inadvertent LCO entries. While no LCO time clocks or action statements were violated, the items presented an unnecessary challenge for control room operators. The events were similar in nature to four items documented in the prior NRC inspection report. (Section 04.7)

Maintenance

The inspectors noted continuing improvements in the material condition and the performance of both the Unit 2 and Unit 3 HPCI systems. (Section M2.1)

Maintenance department personnel performed well during the outage and outage work was generally free from human performance errors. (Section M4.1)

The work observed by the inspectors during the Unit 3 refueling outage was performed correctly. The workers had the necessary procedures and were following them. No inadequacies were noted in the procedures. (Section M4.2)

Five out-of-service errors occurred during maintenance work performed during the Unit 3 refueling outage. None of the out-of-service violations resulted in injury to personnel or adverse impact to plant equipment. Initial corrective actions taken by the licensee in response to the errors were not completely effective in preventing future errors. (Section M4.3)

The licensee experienced problems with main turbine alignment due to the removal and reinstallation of condenser support struts. Personnel performing the work did not follow station expectations by performing the work without an approved work packag (Section M4.4)

Personnel error during the performance of a surveillance procedure resulted in a locked-

. in (continuously energized) main control room annunciator on Unit 3. The annunciator presented an unnecessary distraction to control room operators. (Section M4.5)

Engineering

The licensee's initial plans, to establish an alternate method of decay heat removal during the refueling outage, did not comply with the requirements specified in the plant Technical Specifications. While the plans had not formally received a final review by the Operations department or station senior management, the Engineering department missed several earlier opportunities to catch the inconsistency between the Technical Specification requirements and the methodology specified in the original outage plan (Section E4.1)

The licensee's implementation of the plans to establish an alternate method of decay heat removal during the refueling outage presented a challenge to the operator Engineering support to the Operations department in this case was not stron (Section E4.2)

Plant Support

Radiation Protection personnel performed well during the Unit 3 refueling outage. The station cumulative dose was less than that planned for prior to the outag (Section R 1.1)

Report Details

Summary of Plant Status Unit 2 began this inspection period near full power, and remained at full power for the duration of the inspection perio Unit 3 began this period near full power. Refueling outage D3R 15 started on January 30, 199 On February 24, 1999, the licensee made Unit 3 critical, and on February 25, 1999, Unit 3's output breaker was closed and outage D3R15 completed. At the end of the inspection period, power ascension and post-outage testing were still in progres I. Operations

Conduct of Operations 0 General Comments (71707)

Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was professional and safety-conscious; specific events and noteworthy observations are detailed in the sections belo During the inspection period, three events occurred 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 belo /14/99 01/16/99 02120199 (Units 2, 3) There was an unauthorized entry into the protected are Immediate compensatory measures were taken upon discover (Unit 2) Loss of Drywell-to-Torus differential pressure during Quarterly:

Valve Timing due to Poorly Structured Technical Procedure Ste (Unit 3) While the reactor was already shut down with all rods inserted, a full reactor scram occurred during restoration lineups after a hydrostatic tes.2 Management Oversight of Operations Inspection Scope (71707)

The inspectors assessed overall management of the plant and outage operations by observing activities in the Outage Control Center (OCC) and by attending various outage turnover meetings, plan of the day meetings, and problem screening meeting Observations and Findings Much of the licensee's efforts during this period were geared toward achieving a short refueling outage on Unit 3. Management closely monitored the progress of the outag The licensee staffed its OCC to provide management staff readily available.. The

personnel in the OCC monitored the progress of the outage, coordinated to resolve

. emergent issues, and, in general, ensured that the required resources were read As the outage progressed, the inspectors tracked the level of oversight Unit 2 receive The inspectors observed that licensee management discussed issues on Unit 2 during the routine Plan of the Day meeting, during the morning Shift Manager meetings, and during routine operations turnover meetings. The inspectors identified no instances*

where issues on Unit 2 were not addressed because of resources being concentrated on Unit The inspectors attended several Plant Operations Review Committee (PORC) meetings and assessed the meetings' quality. The PORC members, who are licensee *

management, performed critical reviews of issues, and asked challenging and probing questions.. The inspectors had no concerns with the POR Conclusion

0 a..The plant management personnel provided proper oversight of the outage activities on*

Unit 3 while maintaining Unit 2 operating at full powe Operational Status of Facilities and Equipment (Unit 3) Losses of Shutdown Cooling (SOC)

Inspection Scope (71707)

The inspectors assessed the causes, impacts, and response to two losses of shutdown coolin Observations and Findings Two short-duration, unplanned losses of shutdown cooling occurred on Unit 3. On*

February 1, 1999, the Unit Supervisor's log recorded that a loss of SOC to the reactor vessel occurred due to a spurious 350° F recirculation loop temperature* isolation (coolant temperature was well below 350° F). On February 2, 1999, the inspectors noted that the logs again recorded a loss of shutdown cooling due to a spurious 350° F recirculation loop temperature isolation. In both cases, the operators were able to reset the isolation immediately and restore shutdown cooling in six to eight minutes. The operators also entered the Dresden Abnormal Operating *Procedure (DOA) 1000-01 for residual heat removal alternatives. Also, in both cases, one loop of shutdown cooling was running in fuel pool cooling. Following the second spurious isolation, the operators revised the abnormal operating procedure to permit bypassing the interloc The inspectors requested that the licensee provide the problem identification form (PIFs) associated with the event. The licensee was unable to find a PIF for the first occurrence, and subsequently had a PIF writte The inspectors were concerned by the events because the licensee theorized that the isolations may have been caused by workers bumping instrumentation lines. The losses of shutdown cooling may have been the consequences of worker practices in the fiel *

  • Additional issues related to unplanned consequences caused by work in the field are discussed in section 04. 7 of this repor Conclusions *

Spurious operation of the shutdown cooling high temperature isolation twice caused losses of shutdown cooling. The operators responded appropriately and restored cooling. The inspectors were concerned because work in the field may have caused losses of shutdown cooling on two occasion.2 (Unit 3) Operator Delay in Performing Annunciator Response Procedures Due to Procedure and Material Condition Concerns

  • Inspection Scope (71707)

The inspectors reviewed a Unit 3 issue where the control room operators were delayed in implementing annunciator response procedures due to a combination of procedural and material condition concern Observations and Findings On January 12, 1999, Unit 3 operators authorized maintenance personnel to perform Dresden Instrument Surveillance 2300-04 (HPCI Logic Tests).

  • The testing was authorized to begin at 9:00 a.m, on January 12, 1999, and required that the operators declare high pressure coolant injection (HPCI) inoperable until the testin was completed. At 11 :00 p.m., of the same day, operafors noted that isolation condenser temperatures were rising, indicating leakage past the 3-1301-3 valve (Unit 3 isolation condenser condensate return outboard isolation valve). Leakage past the 3-1301-3 valve was a repeat issue and an ongoing challenge to the operators. The NRC first tracked the concern following the April 9, 1998, reactor scram and most recently discussed the concern in IR 98021. To address the high temperature condition, operators would declare the Isolation condenser inoperable and cycle valves to attempt to seat the 3 valve to arrest the temperature increas Station personnel encountered an unexpected response during the HPCI system logic test, stopped, informed supervision, and contacted engineering personnel. Subsequent licensee investigation (PIF 01998-00161) determined that the unexpected response was

. due to performing the procedure on-line for the first time; the procedure had historically been performed during an outage. Personnel restarted the test at approximately 1:11 a.m., on January 13, 1999, and operators received the isolation condenser temperature hi alarm at 1:50 a.m., on January 13, 199 Clearing the high temperature condition on the Unit 3 isolation condenser would involve declaring the isolation condenser inoperable to cycle the valves. Based on the fact that the condition was indicative of historical 3 valve leakage, which did not threaten isolation condenser operability or valve isolation functions, operators eleCted to restore HPCI to an operable status following completion of the logic testing and then address the hi temperature alarm associated with the isolation condenser.

Operators subsequently declared the HPCI system operable at approximately 9:24 a.m, on January 13, and shortly thereafter declared the isolation condenser inoperable in order to perform the actions necessary to clear the high temperature condition on the isolation condense The licensee subsequently identified that the torque switch setting for the Unit 3 valve

  • required a change in order to properly seat the valv * Conclusions Due to a combination of procedural problems and a repetitive material condition challenge, operators were unable to immediately perform the actions of the annunciator response procedure. As a result, the length of time that the isolation condenser, a relatively high worth system in the plant's probabilistic risk assessment, was in an alarm status was unnecessarily lengthene Operations Procedures and Documentation 0 Operator Use of Incorrect Procedure Revision Inspection Scope (71707)

The inspectors reviewed the circumstances concerning an evolution where operators did not have the most current procedure revision in the main control room while performing testing activitie Observations and Findings During a routine review of control room logs, the inspectors noted the following*

information. On February 21, 1999, while performing Dresden Operating Surveillance 1600-13, "Pressure Suppression Chamber to Reactor Building Vacuum Breaker Full Stroke Exercise 2(3)-160f-31 A and B," operators documented that the torque value

  • required to open the 3-1601-31NB valves (reactor building to torus vacuum breakers)

exceeded the procedurally listed acceptance criteria. Operators entered the valves in the degraded equipment list and notified the outage control center of the problem. Later in the shift, operators were informed that a procedure revision had been issued the night before and the new revision had not been received by Operations personnel when the test was performed. The new revision took into account work that had been performed on the valves during the outage and listed revised torque values for the valves. The as-tound torque values for the valves were within the acceptance criteria of the revision to the procedur The inspectors were concerned about several aspects of the situation. First, the operators performed a procedure from the control room that was not the most current revision. In this case, no adverse consequences resulted from performing a procedure that did not contain the most current revision. However, it was fortuitous that the procedure revision only contained revised acceptance criteria and not pertinent operating information. Also, neither operators nor other station personnel documented the occurrence via the PIF process until questioned by the inspectors. The inspectors were concerned with the apparent acceptance of a situation that led to control room operators performing a test that did not contain the latest revision. After questioning by

,*

  • the inspectors, the station entered the item into their corrective action process via PIF 01999-01051. The inspectors considered this violation of procedures to be of minor significance and now entered into the licensee's corrective action program. As a result, this issue was not subject to formal enforcement actio Conclusions The station failed to ensure that the latest revision of a procedure was available to control room operators prior to performance of a test. Operators did not document the occurrence via the PIF process until questioned by the inspector Operator Knowledge and Performance 0 Reactor Shutdown Activities (Unit 3) Inspection Scope (71707)

The inspectors conducted observations of the Unit 3 shutdown activities for Dresden Refueling Outage (D3R15). Procedures and documents reviewed included Dresden General Procedures (DGP) 02-01, "Unit Shutdown," and DGP 02-03, "Reactor Scram." Observations and Findings The inspectors observed the reacto~ shutdown activities and noted that the nuclear station operators performed the activities in a careful and controlled manner. Peer checking and three way communication were evident throughout the shutdown evaluation. Operators adhered to procedures-and the unit supervisor provided effective oversight of the evaluation. Additionally, control room distractions were held to a minimum leve Conclusions The inspectors did not identify any performance deficiencies during the Unit 3 shutdown activities. Operators completed the shutdown safely and correctl.2 Reactor Startup Following Completion of Refueling Outage (Unit 3) Inspection Scope (71707)

The inspectors conducted observations of the Unit 3 startup activities following completion of Dresden refueling outage D3R15. Procedures and documents reviewed included Dresden Administrative Procedure (OAP) 01-01, "Unit Startup," and OAP 03-04, "Control Rod Movements." Observations.and Findings

  • On February 24, 1999, the licensee commenced a startup of the Unit 3 reactor following completion of the refueling outage (D3R15). The inspectors observed portions of the licensee's startup activit *

The inspectors noted good communications by the operators, and effective overall control of the startup by Operations department personnel. The operators encountered problems such as minor steam leaks and condenser air in-leakage. The operators appropriately addressed these issues as the startup commence The station used extra senior reactor operators, who were unit supervisors qualified to act as test directors, for several post outage testing evolutions. The extra senior reactor operators (SROs) did an excellent job with respect to knowledge of their assignments and ensuring the unit supervisor had all relevant information to coordinate startup activities. The SROs interfaced well with each other and functioned well as a tea Operations made the reactor critical on February 24, 1999, and synchronized the unit to the electrical grid on February 25, 1999. Power ascension and startup testing evolutions were in progress at the end of the inspection period. The inspectors will continue to monitor overall startup activities and plant equipment and material condition response during routine core inspection activitie Conclusions Operators performed well during the conduct of the reactor startup. The operators conducted good heightened level of awareness briefs, communicated well and executed tasks in a conservative and deliberate manne *

0 General Operations Performance (Units 2. 3) Inspection Scope (71707)

The inspectors observed the performance of the Operations department during a variety of routine and outage operation Observation and Finding Control Room Performance In general, the operators performed well. The crews practiced good communications, had productive turnover meetings, and maintained clear logs. The inspectors observed.

that operators correctly referenced procedures. The licensee staff maintained a quiet and orderly control room, even when extra personnel were present in the control roo The inspectors observed good command and control by the supervisory staf One exception to good control room performance was an error during a surveillance that resulted in the equalization of the torus and drywell pressures. (Reference Section 04.4)

Field Pf3rformance The inspectors accompanied non-licensed operators in the field during various task The non-licensed operators followed referenced procedures appropriately, maintained communications with the control room, and performed assigned tasks correctly. In addition, the inspectors did not identify any significant items that should have been identified by non-licensed operators. *From that, the inspectors inferred that the non-licensed operators were identifying issues in the field correctl *

., An exception to good field performance resulted in an unplanned full scram. On February 20, 1999, while the reactor was already shut down with all rods inserted, a full reactor scram occurred during the restoration lineup after the Unit 3 hydrostatic tes Part of the recovery from the reactor pressure vessel hydrostatic test required manipulation of valves on instrument racks. Historically, this had been done by instrument maintenance staff. However, early findings by the licensee indicated that the operators were performing the alignment without the strict controls and briefs usually associated with manipulating valves on instrument racks. The inspectors noted that the event was similar to a full scram on Unit 2 that occurred in 1998 during instrument rack valve manipulation. At the end of the inspection period, the licensee was still researching and preparing a Licensee Event Report to document the event. The inspectors will assess the issue fully following receipt of the Licensee Event Repor Conclusions Overall operator performance was good. In general, the operations staff followed procedures correctly, used good command and control, and took correct actions. This resulted in generally smooth operations, and contributed to good housekeeping in the plant. However, operator performance led to an unplanned full scram while the reactor was shutdow.4 Drvwell-to-T orus Differential Pressure Inspection Scope (71707)

The inspectors reviewed operation staff's performance in regard to an unrecognized Technical Specification limiting condition for operation entry for the suppression chamber and the drywell-to-torus differential pressure, which occurred on January 16, 199 Observations and Findings On January 16, 1999, while a nuclear station operator (NSO) was performing valve*

timing for a block of valves in the drywell-to-torus pressure control (pump back) system (3-6101-55 and 56) and the primary containment venting system (3-1601-21 and 22), an alarm was received in the main control indicating that drywell-to-torus differential pressure (dp) had decreased below the alarm setpoint of 1.05 psid. Upon receiving the alarm, the NSO noted that the drywell to torus dp had decreased to 0.85 psiq. Dresden Technical Specification 3.7.H required that the dp between the drywell and the torus be greater than or equal to 1.0 psid. Also, Dresden Technical Specification 3.7.K.3 stated that the suppression chamber shall be operable with a total leakage between the suppression chamber and drywell of less than the equivalent leakage through a 1 inch diameter orifice at a differential pressure of 1.0 psid. The flow path in which the leakage occurred was through an 18-inch diameter section of piping. The NSO took immediate corrective steps to close the subject valve to stop the greater than allowed leakage

. between the drywell and the torus, and to reestablish drywell to torus differential pressure An investigation performed by the licensee determined that the apparent cause of this event was inadequately/poorly written procedural steps, which "distracted"*the NSO during the performance of the surveillance, in particular steps 1.4 and 1.5 of l)resden

j'

Operability Surveillance (DOS) 1600-03, "Quarterly Valve Timing (Unit 2)." These steps directed the NSO to perform certain valve manipulations based upon plant condition However, due to the compound structure of the decision statements for both steps, the NSO became focused on the conditions for the performance of the step rather than the results of the actions, if taken. The NSO inappropriately performed step 1.5. Performing steps in 1.5 required that the reactor be shutdown, de-inerted, and the differential pressure already equalized; however, the step entry statement contained the opposite condition. This led to the NSO opening both the 3-1601-21 and the 3-1601-56 valves, and inadvertently allowed the approach to pressure equalization between the drywell and the torus. The operators restored the drywell-to-torus dp to the Technical Specification required value within the 24-hour limitation provided in the action statement of the Technical Specificatio Dresden Technical Specification 6.8.A, stated that'written procedures shall be established, implemented, and maintainep covering the activities referenced in Appendix A, of Regulatory Guide 1.33, Revision 2, February 1978. Appendix A, of

  • Regulatory Guide 1.33, referenced procedures for maintaining the containment integrit Contrary to the above, this event revealed that the procedure developed by the licensee was inadequate and was the major contributor to exceeding containment integrity-related Technical. Specification limits on drywell to torus leakage rate and dp. This Severity Level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy (NCV 50-237/249/99003-01 (DRP)). The violation is in the licensee's corrective action program as PIF No. 01999-00228. The.

licensee has also submitted an LER as required by 10 CFR 50.73 (a)(2)(i). The LER is documented as LER 50-237/99001-00 entitled, "Unit 2 Loss of Drywell to Torus dP during Quarterly Valve Timing due to Poorly Structured Technical Procedure Step."

In this LER the licensee discussed corrective actions to prevent recurrence of this even The following were some of the corrective actions discussed in the LER: 1) the

procedure was revised to delete confusing compound decision statements, 2) the policy on pre-job briefs was revised to include a step for a peer review of all surveillance tests before the task, 3) Dresden Administrative Procedure (OAP 09-02) "Procedure and Revision Process," Checklist A would be revised to include an initial block to require the user to assure that action statements added meet the established licensee writing standards, and 4) Operations department personnel performed a cursory review of other operating surveillance procedures to find other compound or potentially misleading action statement The inspectors also noted that the operator did not recognize that the procedural action being taken would exceed the Technical Specification allowed leakage between the torus and the drywell and eventually equalize the pressure between the two. In the past, the operator performance and system knowledge have been sufficient to recognize and appropriately disposition similar procedural problem This was the second loss of dp between the drywell and the torus event within the last year. The first event occurred on June 23, 1998, (Reference IR 98019) and shared similarities with this event in that the Operations department pre-job brief process was inadequate and the NSOs allowed Technical Specification requirements to be exceeded in that case, as wel **

  • The inspectors plan follow up of the corrective actions described in the LER over the next several six-week inspection period Conclusion Procedural inadequacies contributed to the licensee inadvertently exceeding a Technical Specification limitation for drywell-to-torus leakage and the subsequent entry into the

. drywell-to-torus differential pressure limiting condition for operation. The inspectors also noted that the operator failed to recognize the valve manipulation being performed on this system would cause eq1;1alization between the drywell and the toru.5 (Unit 3) Reactor Services and Fuel Handling Inspection Scope (71707) The inspectors evaluated the licensee's performance during reactor disassembly and fuel movemen Observations and Findings The licensee refueling plan included a partial core offload followed by a core shuffl The licensee commenced fuel movements from the reactor to the fuel pool approximately 66 hours7.638889e-4 days <br />0.0183 hours <br />1.09127e-4 weeks <br />2.5113e-5 months <br /> following a reactor shutdown. The licensee completed a 10 CFR 50.59 safety evaluation prior to the move since the 66 hours7.638889e-4 days <br />0.0183 hours <br />1.09127e-4 weeks <br />2.5113e-5 months <br /> conflicted with the updated safety analysis report (USAR) which stated that fuel move would commence 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> after reactor shutdown. The inspectors reviewed the 50.59 safety evaluation and identified no concerns or unresolved safety question Fuel moves directly observed by inspectors, were performed in accordance with procedures. The inspectors also noted that licensee staff used good communications, and command and control throughout each evolutio Conclusion There were no identified fuel _handling errors such as mispositions or misorientations during either the partial offload or fuel shuffle evolutions. The inspectors also reviewed a video tape of the final reactor loading audit and identified no error.6 Drvwell and Torus Closeout Inspection Inspection Scope (71707) The inspectors assessed the housekeeping of the Unit 3 drywell and torus. These inspections were performed after the licensee informed the inspectors that the drywell was ready for closur *

Observations and Findings During the torus inspection the inspectors identified a small amount of debris floating in the suppression pool. This debris was small pieces of a plastic-like materiaL The

inspectors also identified evidence of scaffolding in contact with the torus inner shell in

  • different locations inside the torus. However, due to torus lighting, the inspectors could not fully ascertain if the torus inner coating had been damaged. The inspectors informed the licensee of these observations. The licensee removed the debris floating in the pool. The licensee also investigated the torus inner coating and concluded that the marks on the torus inner wall were only superficial and the torus inner coating had not been.removed in those place During the closeout inspection of the drywell, the inspectors identified minor material condition housekeeping issues. The identified housekeeping issues included several strips of tape and paper, multiple unused welding rods, writing utensils, a loose flashlight, and a loose pipe fitting down the Bay 13 downcomer. The overall amount of material identified by the inspectors was small. The inspectors also identified material condition issues, which included exposed cable near the reactor recirculation riser and a missing nut on the 3D drywell damper linkage. The inspectors informed the licensee of the findings and the licensee removed the debris and properly dispositioned the other material condition issue Conclusion The inspectors concluded that housekeeping in both the drywell and torus was goo.7 Technical Specification and Dresden Administrative Technical Requirement Issues Inspection Scope (71707)

The inspectors verified the continuance of a negative trend, first documented in the prior inspection report (IR 98030) associated with inadvertent entries into Technical Specification (TS) and Dresden Administrative Technical Requirement (DATR) limiting conditions for operation (LCOs). Observations and Findings

. Inspection report 98030 documented four examples where TS and DATR LCO time limits were not met, either because station personnel did not understand the impact of their activities on those requirements, or station personnel did not realize conditions had changed, which warranted an entry into the LCO action statements. No active violations of TS requirements occurred during this inspection period, nor were the LCO time limits exceeded in.the examples discussed below. However, five instances occurred during this period where actions committed by station personnel resulted in inadvertent LCO entries. Similar to the examples documented in IR 98030, the inadvertent TS and DATR LCO entries resulted when station personnel did not realize the impact of their activities on the TS and DATR requirements. The examples are listed belo Inappropriate Out-of-Service Temporary Lift Leads to Forced LCO Entry On January 26, 1999, operators entered TS 3.8.D for the control room emergency ventilation system when the system spuriously isolated from the toxic gas analyzer due to a false high ammonia signal. The isolation occurred after maintenance was performed on the system. In the past, station personnel temporarily lifted the maintenance out-of-service to allow a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> heat up of the system prior to final calibration. In this case, the temporary lift of the out-of-service differed from past

practice in that two relays were re-installed during the temporary lift (past practice did not include reinstallation of these relays during the temporary lift of the out-of-service).

Re-installing the relays allowed the isolation of the control room ventilation system when the toxic gas analyzer received spurious indications during the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> heat up perio Operators entered the appropriate limiting condition for operation (restore the system to operable within seven days) and documented the occurrence via PIF 01999-0041 Preliminary investigation by the licensee determin.ed that contributing causes to the inappropriate relay installation included human error in initiating a temporary lift request without reviewing past requests, inadequate training in the proper performance of toxic gas analyzer maintenance activities, and infrequent performance of the activit Inadvertent DATR LCO Entry due to Inadequate Work Instructions On January 29, 1999, operators were informed that work on traversing in-core probe (TIP) tube demolition may have inadvertently degraded a fire barrier. The barrier was the TIP room wall between the reactor building and the Unit 3 TIP room. The work instructions for TIP tube demolition directed dismantling of the TIP room wall, but did not identify the wall as a fire barrier. When operators became aware of the work, they entered the appropriate OATR LCO (OATR.3.1.6.1) to establish a continuous dedicated fire 0watch within one hour and to restore the barrier to an operable status within seven days. The operators back dated the LCO entry to January 28, 1999, when work began and documented the occurrence via PIF 01999-00438 and PIF 01998-00440. Station personnel determined that there were workers in attendance at the job site at all times, therefore, the requirements for a continuous fire watch were me Unplanned DATR LCO Due to Fire Sprinkler Damage On January 31, 1999, personnel performing scaffold work in the Unit 3 low pressure heater bay, damaged and broke a sprinkler head, which initiated fire water system flo Operators isolated the system and entered OATR 3.1.3.1, which required the establishment of a once per hour fire watch. Station personnel repaired the sprinkler head and documented the occurrence via PIF 01999-0048 Two Unplanned DATR LCOs Due to Tripped Breakers on the Turbine Floor On two separate occasions on January 31, 1999, regular lighting circuit 11 tripped due to excessive loading on the turbine floor. The trip of the lighting circuit caused a trip of safe shutdown lights, which placed operators in a seven day OATR LCO. Operators documented the occurrences via PIF 01999-00486. The lighting circuit breaker was reset and the.LCO was exite c, Conclusion Five instances occurred during the inspection period where actions by station personnel resulted ih inadvertent LCO entries. While no LCO time clocks or action statements were violated, the items presented an unnecessary challenge for control room operators. The events were similar in nature to four items documented in the prior NRC inspection repor *

Miscellaneous Operations Issues 0 (Closed) I Fl 50-2371249/97004-01 (DRP): The effectiveness of the equipment operator tours in identifying material condition deficiencies. Follow up inspections documented in routine reports have assessed non-licensed (equipment) operator performance. The licensee has taken steps to address areas where the inspectors identified weaknesse This item is close II. Maintenance M2 Maintenance and Material Condition of Facilities and Equipment M (Unit 2. 3) High Pressure Coolant Injection (HPCI) System Operability Surveillance Test Inspection Scope (61726. 62707)

The inspectors performed both in-plant and main control room observations for all or portions of four HPCI operability surveillance tests performed during this inspection period. The inspectors assessed the material condition of the system and reviewed the resulting in-service testing (IST) data collected during the performance of the surveillance tests. The following is a listing of activities observed by the inspectors:

WR 980112661-0 Unit 2 Quarterly HPCI Fast Start Operability Verification Surveillance (DOS 2300-03, Rev. 54)

WR 990006395-01 Unit 2 Technical Specification HPCI Pump Test IST Surveillance (DOS 2300-03, Rev. 54)

WR 980117097-01 Unit 3 Technical Specification HPCI Pump Test IST Surveillance (DOS 2300-03, Rev. 55).

.

DOS 2303-03 Unit 3 HPCI Operability Run at Rated Pressure (DOS 2300-03, Rev. 56) Observations and Findings Unit 2 HPCI System

  • During in-plant observations of the Unit 2 HPCI system surveillance test (WR 890112661-01) on January 15, 1999, the inspectors noted that the material condition of the system had improved. In a previous inspection report (IR 97019), the inspectors noted significant water and oil leaks from various valves and other locations throughout the HPCI system. On the January 15 run, the inspectors noted no adverse oil, steam, or water leaks. Using the oil temperature indicators on the front standard of the HPCI system, the inspectors also noted that the oil temperature measurements at various locations in the HPCI system were well within procedural and design limits. The inspectors also confirmed that the condensate level in the gland seal leakoff (GSLO)

condenser was being adequately controlled by the level control system (by using a sight glass attached to the GSLO condenser).

During this surveillance, however, the licensee identified that the vibration measurement in the horizontal direction for the HPCI main pump was in the IST program "ALERT" range. The licensee established a vibration range of 0.325 in/sec to 0.700 in/sec, as the

"ALERT" range for that particular location of the HPCI system. Licensee personnel measured vibrations of the main pump in the horizontal direction to be.337 in/se Once in the "ALERT" range the licensee's IST program required an increase in the frequency of HPCI operability surveillance tests. The frequency was doubled from quarterly to once every 45 day The inspectors, along with the licensee, also noted that a local pressure indicatqr (Pl)

found directly downstream of 3-2301-46 (HPCI Cooling Water Pressure Control Valve)

was pegged high off scale (Pl scale ranged from 0-65 psig). This reading indicated that the header pressure for the cooling water line was outside the established test acceptance criteria. The acceptance criteria stated that 3-2301-46 valve must maintain

. pressure between 35 and 60 psig. The flow path for this line was from the discharge of the GSLO condenser drain pump to the suction side of the HPCI booster pump. This acceptance criterion was established to ensure that the GSLO drain pump had developed a sufficient discharge pressure head to pump against the HPCI booster pump suction line. The HPCI booster pump suction was usually maintained at 28 to 30 psi If the pressure control valve failed closed, the pressure indicator would give immediate indication that the GSLO drain pump would not be able to perform its safety-related function of adequately controlling the condensate level in the GSLO condense Following this surveillance, the licensee's engineering personnel determined that this acceptance criteria was too conservative and changed it. The acceptance criteria was changed to state th~t the pressure control valve maintains pressure greater than 35 psig. In addition, the overranged indicator was checked to erisure it had not been damaged and its calibration-was satisfactory. The inspectors reviewed the licensee determination and noted no concerns. At 35 psig or greater controlling pressure the drain pump should be effectively pumping against the booster pump suctio During the surveillance (WR 990006395-01) performed on February 23, 1999, the HPCI system passed its surveillance test and the IST vibration data for the main pump was measured by the licensee to be in the "ACCEPTANCE" range. The vibration measurement in the horizontal direction was 0.314 in/se Unit 3 HPCI System The inspector identified no performance or adverse material condition issues during the Unit 3 HPCI surveillance tests performed on January 22, 1999 or February 25, 1999. A review of both tests' IST data showed all vibration readings were in the IST

"ACCEPTANCE" rang Conclusion The inspectors noted continuing improvements in the material condition and the performance of both the Unit 2 and Unit 3 HPCI systems. * No significant material condition concerns were identified during observance of multiple HPCI system operability surveillance tests performed this inspection period.

  • .

M4 Maintenance Staff Knowledge and Performance M General Maintenance Staff Performance Inspection Scope (62707)

The inspectors assessed maintenance staff performance through direct observation and through monitoring the effectiveness of maintenance performe Observations and Findings The inspectors performed a variety of spot checks of maintenance in the field, and discussed the status of work with maintenance staff. The workers observed were all knowledgeable of their work. The workers had the correct work materials with them and were properly following the procedures. The inspectors saw good communications and coordination during bigger and more complex jobs, such as the undervoltage tests and the reactor pressure vessel hydro tes Equipment worked on generally was returne.d to service correctly and worked properl The maintenance staff kept the plant housekeeping clean and exercised proper controls.

to prevent the spread of.contaminatio The Unit 3 outage was mostly free from human performance errors such as miswired controls or incorrectly lifted leads. Nonetheless, there were some problems associated with unplanned entry into TS and DA TR LCOs caused by maintenance staff and discussed in Section 04. 7 of this repor Another area in which maintenance staff sometimes performed weakly was in the out-of-service process. There were several occasions during the outage in which maintenance

  • staff failed to use the out-of-service process correctly. Workers were required to "sign on" to an out-of-service to work on equipment. Several times during this period, workers failed to sign on to an out-of-service prior to performing work, or didn't verify that an'out-of-service was still in effect. This resulted in work being done on energized systems*,.

and contributed to at least one low-voltage shock (Ref. Section M4.3 for details). Conclusions Maintenance department personnel performed well during the outage and outage work was generally free from human performance errors. However, there were several occasions during the outage in which maintenance staff failed to use the out-of-service process correctl M Maintenance Performance During Refueling Outage Inspection Scope (61726. 62707)

The inspectors observed various maintenance activities and assessed the workers'

performance and compliance with plant requirements and management expectation The inspectors observed all or portions of the following work activities and work requests (WR):

. WR 960098430-01 WR 970077502-01 B WR 9900013432-01 Disassembly of LPCl/CCSW heat exchanger Retorque body to bonnet bolts on HCU cooling water valves (104)

Replace 38 CRD flow control valve Repair HCU Valve 3-0305-02-39-105 Repair HCU Valve 3-0305-26-07-113 Repair HCU Valve 3-0305-46-07-113 Loosen HPCI control valve spring pressure Perform SRM-24 discrimination adjustment The inspectors also observed portions of the following surveillance activities and assessed the workers' performance and compliance with plant requirements and management expectation DIS 0600-06 DIS-2300-06 DIS-0250-12 DIS-0250-01 DIS-3200-07 Observations and Findings U2(3) Main Steam Line Flow Transmitter Calibration HPCI Turbine Area Temperature Switch Functional Test Main Steam Line Low Pressure Switch Calibration Main Steam Line High Flow Isolation Switch Calibration HPCI Steam Line Area Temperature Switch Calibration The maintenance activities observed by the inspectors were performed in accordance with work packages and within procedural requirements. The inspectors also noted that first line maintenance supervisors and system engineers monitored job progress and appropriate radiation control measures were in place. When challenges were encountered or issues emerged, the workers stopped and communicated the problems with their supervisor or outage management personnel. In all cases witnessed by the inspectors, conservative, safety-conscious action plans were devised to resolve problem While observing maintenance activities in the control room, the inspectors noted no additional risk impact activities outside the licensee's planned maintenance activitiesi being.performed. The inspectors also noted that access into the control room by maintenance and engineering personnel was controlled so as to minimize the impact on operations. Work activities were screened through the work execution center with final work start approval by the unit supervisors. The maintenance personnel were* observed to be very quiet and, for the most part non-intrusive, which aided in reducing distractions to the operator Conclusions The work observed was performed correctly. No instances of incorrect work were noted by the inspectors. The workers observed had the necessary procedures and were following them. No inadequacies were noted in the procedure **

.,

M Out-of-service Errors Associated With Refueling Outage Work Inspection Scope (62707)

The inspectors reviewed the circumstances surrounding five ouf-of-service (OOS) errors that occurred during the conduct of refueling outage maintenance activitie Observations and Findings On February 2, 1999, three separate out-of-service errors occurred. The first occurred during valve maintenance work on the high pressure coolant injection system. Afront line supervisor for the local leak rate testing group requested that an out-of-service tag be temporarily lifted from a particular valve to support testing activities on the syste The out-of-service tag was in place to support other, separate valve maintenance activities on the same system. The front line supervisor for the valve maintenance group agreed with the request and released the out-of-service so that the temporary lift could be performed. However, valve maintenance work was in progress which used the out-of-service tag for boundary protection; this work continued while the out-of-service tag was temporarily lifted. The valve maintenance front line supervisor failed to recognizeJhe implications of the temporary lift for the maintenance that was in progres Valve maintenance personnel started work to unbolt and replace a valve in the system and noted water running from the line. The workers contacted the Operations department and outage control center to inform them of the situation and were directe to re-tighten the bolts just loosened and stop work. No adverse consequences resulted from the error. The. licensee documented this error via PIFs D1999-00516. and D1999-0051 Dresden TS 6.8.A required th~t written procedures be implemented covering the applicable procedures _recommended in Appendix A of Regulatory Guide (RG) 1.33, Revision 2, February 1978. Appendix A of RG 1.33 recommended procedures for equipment control (e.g., locking and tagging).

Step F.9.c of Dresden Administrative Procedure 03-05, "Out-of-Service Program,"

stated that all supervisors in charge of the work will review the outage to verify the temporary lift will NOT: (1) compromise personnel safety, (2) cause equipment damage, and (3) cause any other adverse consequence Contrary to the above, on February 2, 1 ~99, the valve maintenance front line supervisor authorized the temporary lifting of an out-of-service without verifying that the temporary lift would not compromise personnel safety or cause other adverse consequence Failure to follow procedures for temporarily lifting the out-of-service was considered a violation of TS 6.8.A (NCV 50-237/249/99003-02(DRP)). This Severity Level IV,violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy. The violation is in the licensee's corrective action program via PIFs No. D1999-00516 and D1999-00519. *

The second out-of-service error occurred during maintenance on a control rod drive hydraulic control unit. A second out-of-service was prepared to replace the initial out-of-service in order to decrease the boundary size of the tagout. The valve maintenance front line supervisor, who had signed on the original out-of-service, did not sign on to the

replacement out-of-service. An outage maintenance superintendent, erroneously believing that the front line supervisor was signed on to the new out-of-service, directed a contract mechanic to complete installation of the valve packing. The contract mechanic completed the packing installation, and, when he informed the front line supervisor that the work was complete, the front line supervisor notified the mechanic and outage maintenance manager that he was not signed on to the out-of-service because it was being replaced by a new out-of-service. The licensee documented this error via PIF 01999-0052 The third out-of-service error 'occurred during work on a steam jet air ejector solenoid valve. There were two out-of-services associated with the task; a mechanical isolation for the air side of the valve and an electrical isolation for lifting of the solenoid lead Maintenance personnel _replaced the solenoid valve; however, the front line supervisor was only signed on to the mechanical out-of-service. The licensee documented this occurrence via PIF 01999-0053 The licensee, in addition to documenting the out-of-service violations via the PIF process, performed a Prompt Investigation to im~estigate the events. Other corrective actions included providing a tailgate session on the out-of-service program to all outage personnel, conducting briefing sessions with mechanical and valve maintenance front line supervisors, and establishing out-of-service "greeters" at the entrance to the radiologically protected area to question workers about their out-of-servic Despite the station's corrective actions, another similar out-of-service error occurred on February 6, 1999. Personnel completed main turbine stop valve work without signing on to the out-of-service. The licensee documented this occurrence via PIF 01999-00643.

A fifth out-of-service error occurred on February 16, 1999. A mechanic received an electrical shock while setting up a job to repair a leak in the rectifier cooling syste The system was properly mechanically isolated for the work; however, not all systems were electrically deenergized in the vicinity of the work area. The mechanic received a minor electrical shock when his arm made contact with an energized component in the vicinity of his work area. The licensee documented the occurrence via PIFs 01999.-

00910 and 01999-00912, and initiated a Prompt Investigation to investigate the matte None of the out-of-service violations resulted in injury to personnel or adverse impact to plant equipment. The licensee captured the items via the PIF process and appropriately entered the occurrences into the corrective action program. While some of the errors occurred during work on nonsafety-related equipment, they were similar in nature to the errors committed on the safety-related equipmen Conclusion Five out-of-service errors occurred during maintenance work performed during the Unit 3 refueling outage. None of the out-of-service violations resulted in injury to personnel or adverse impact to plant equipment. Initial corrective actions taken by the licensee in response to the errors were not completely effective in preventing future error.,

M Turbine Misalignment Inspection Scope {62707)

The inspectors reviewed the licensee's response to a turbine misalignment that was caused by performing work without an approved work package and without incorporating contractor supplied engineering direction Observation and Findings The licensee performed routine maintenance activities on one of the low pressure turbine rotors during the refueling outage. During reassembly of the turbine assembly, the licensee identified that the turbine alignment was out of tolerance. The licensee documented this occurrence via PIF D1999-00888 and initiated a Prompt Investigation into the matter. The licensee's investigation results revealed that the misalignment was due to the removal, and subsequent reinstallation, of three structural struts in the lowe turbine hoods. The struts were removed to support the condenser bellows assembly project. During the investigation, Nuclear Oversight identified that the strut removal was performed without a work package. The strut removal was performed based on verbal directions only. The removal was completed before site engineering personnel reviewed contractor supplied documents and instructions for the strut removal. Nuclear Oversight documented the failure to work per an approved work package and the failure to obtain engineering concurrence prior to starting work via PIF D1999-00628. The turbine alignment problems arose when the sequencing of the turbine rotor installation and the reinstallation of the *struts was not evaluated. Licensee personnel performed alignment checks of the turbine tolerances and made adjustments as necessary. The inspector verified that the turbine vibration levels after plant startup were at or below the levels experienced prior.to the refueling outage. This issue illustrated the problems associated with performing work without an approved work packag Conclusions The licensee experienced problems with main turbine alignment due to the removal and reinstallation of condenser support struts. Personnel performing the work did not follow station expectations by performing the wqrk without an approved work packag M Configuration Control Error Results in Locked in Alarm {Unit 3) Inspection Scope {62707)

The inspectors monitored licensee troubleshooting effects to resolve a locked in alarm on the Unit 3 main control room panel Observations and Findings Operators shut down the Unit 3 reactor on January 30, 1999, to support the planned refueling outage. After inserting the manual scram, operators received the expected annunciator (alarm E-1 on the 903-5 panel) for scram discharge volume high leve When operators subsequently drained the scram discharge volume, the "West Scram Inst Vol Not Drained," annunciator would not reset. Station personnel initiated paperwork to troubleshoot the level switch during the refueling outag *

On February 7, 1999, maintenance personnel initiated troubleshooting activities to determine the cause of the locked in control room alarm. The licensee identified that the lower isolation valve for the level switch was in the incorrect position. The lower isolation valve was "locked closed" instead of its required "locked open" position. The level switch, one of four associated with the scram discharge volume, provides an alarm function only and does not impact any automatic actuations associated with the scram discharge volume. Licensee personnel informed operators and obtained permission to correctly re-position the valve to "locked open." After opening the valve, the control room alarm cleared as expecte The licensee documented the discovery via PIF D1999-00667 and initiated a Prompt Investigation to determine causes of the event. The licensee, through their investigation, concluded that the valve was most likely mispositioned on January 28, 1999, during the performance of DIS 0500-10, "Scram Discharge Volume Level Functional Check." The level switch isolation valve was manipulated during the

  • surveillance. The valve is a locked valve and licensee records indicated that no other work groups had checked out the key since the instrument Maintenance department checked out the key January 28, 1999, to perform the surveillance. The licensee concluded that an improperly performed independent verification may have contributed to ttie event. The NRC had earlier documented concerns with the independent verification process in a prior inspection report (98021 ), and issued a Notice of Violation regarding an instrument surveillance error that resulted from improperly performed independent verification Dresden TS 6.8.A, required that written procedures be implemented covering the applicable procedures recommended in Appendix A of Regulatory Guide (RG) 1.33, Revision 2, February 1978. Appendix A of RG 1.33 recommended procedures for surveillance and calibration test Step I. 20.0 of DIS 0500-10, a procedure for surveillance testing the scram discharge volume, required that personnel "open AND lock the instrument isolation valve, 301-151D."

Contrary to the above, on January 28, 1999, the licensee incorrectly positioned the 301-151 D instrument isolation valve against the requirements of Dresden Instrument Surveillance 0500-10 and caused an alarm to remain locked in*on the main control room panels. This failure to follow procedures was considered a violation of TS 6. (NCV 50-237/249/99003-03(DRP)). This Severity Level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy. The violation is in the licensee's corrective action program as problem identification form (PIF) No. D1999-0066 Conclusion Personnel error during the performance of a surveillance procedure resulted in a locked-in (continuously energized) main control room annunciator on Unit 3. The annunciator p_resented an unnecessary distraction to control room operators.

  • Ill. Engineering E4 Engineering Staff Knowledge and Performance E Refueling Outage Alternate Decay Heat Removal Plans Inspection Scope (37551)

The inspectors reviewed the licensee's plans for establishing alternate methods of decay heat removal during the outage. The inspectors reviewed the pl.an's compliance

  • with the plant Technical Specifications and other plant procedure Observations and Findings
  • The licensee presented information to the inspectors concerning the method by which the station intended to establish an alternate method of reactor decay heat removal during the refueling outage. On January 21, 1999, station engineering personnel and a representative from the utility's corporate office presented specific methods and plans to allow for the removal from service of the shutdown cooling system in order to perform outage maintenance activities on the syste The inspectors reviewed the plan and were concerned that the method as presented did not comply with the Technical Specification requirements for demonstrating the operability of an alternate method of decay heat removal. Engineering personnel informed the inspectors that the alternate decay heat removal method was proven by industry experience and that utility calculations showed that the alternate system would be capable of removing decay heat loads when the primary shutdown cooling syste would be removed from service for maintenance. The inspectors were informed that operability testing of the system would be performed in parallel with the shutdown cooling system maintenance. The inspectors were also informed that the first approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of shutdown cooling system maintenance would be easy to restore from, if the alternate method was not capable of removing the decay heat load The inspectors were concerned that the plan to physically remove the shutdown cooling system and make it inoperable for maintenance, in parallel with demonstrating the alternate method of decay heat removal, did not comply with the requirements of Technical Specification 3.10.K. Technical Specification 3.10.K, required, in part, that with no shutdown cooling loops operable within one hour and at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter, demonstrate the operability of at least one alternate method of decay heat removal. The inspectors' position was that the plan to perform c"alculations prior to testing the alternate method, did not meet the Technical Specification requirement to demonstrate the capability of the syste The inspectors reviewed licensee documentation with respect to the outage shutdown cooling plans and noted that a station prepared 50.59 evaluation, completed and approved by an Engineering department head on October 30, 1998, did not identify the potential conflict with Technical Specification requirements. Also, the inspector reviewed PORC meeting minutes dated January 14, 1999, and noted that a brief overview of the shutdown risk review plans was presented to the PORC. The PORC meeting minutes discussed the fact that decay heat removal would be out-of-service for approximately four days and that evaluation results based on calculations that had been performed by the utility concluded that natural circulation would handle the decay heat
    • load seven days after the shutdown. The inspectors concluded that two potential opportunities to identify the discrepancy had been missed." The inspectors discussed their concerns with Operations department management prior to the start of the refueling outage. The licensee modified the outage plans to demonstrate the operability of the alternate method of decay heat removal prior to actually removing the shutdown cooling system from servic *

Conclusions The licensee's initial plans, as presented to the inspectors, to establish an alternate method of decay heat removal during the refueling outage, did not comply with the requirements specified in the plant Technical Specifications. While the plans had not formally received a final review by the Operations department or station senior management, the Engineering department missed several earlier opportunities to catch the inconsistency between the Technical Specification requirements and the methodology specified in the original outage plan E Demonstration of Alternate Decay Heat Removal Operability Inspection Scope (37551)

The inspectors observed the licensee's operability testing of the alternate method of decay heat removal during the outage. The inspectors reviewed the procedures used and the engineering support provided to the operators during the evolutio Observations and Findings The licensee demonstrated the operability of the alternate method of reactor decay heat removal by use of a special procedure. After 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of testing per the special procedure, engineering personnel concluded that the capability of the alternate method had been demonstrated and met the special procedure's acceptance criteria. The Engineering department staff recommend to the Operations department staff that the alternate method of decay heat removal be considered operable. The inspectors reviewed the data from the special procedure and did not agree with this conclusio The Operations department personnel, independent of the inspectors, also concluded that the operability of the alternate system had not been satisfactorily demonstrated and did not accept the recommendation from the Engineering department. The licensee subsequently adequately demonstrated the operability of the alternate system and removed the shutdown cooling system from service for planned maintenance activitie The Nuclear Oversight department reviewed the outage plans for alternate decay heat removal and reviewed the performance of the special procedure. The Nuclear Oversight department documented various concerns with the overall approach via PIFs 01999-00.756, 01999-00758, OF1999-00790, 01999-00822, and 01999-00925. Based on the number of concerns identified prior to, and during, the evolutions to establish an alternate method of decay heat removal, the licensee ifiitiated a formal root cause evaluation to investigate problems and causes associated with the overall process. The

. inspectors plan to perform a detailed review of the licensee's final root cause report as.

part of the core inspection program to evaluate licensee corrective action programs and processe * *

  • c.

E8 Conclusions The licensee's implementation of the plans to establish an alternate method of decay heat removal during the refueling outage presented a challenge to the operators. In this case, engineering support to the Operations department was not stron Miscellaneous Engineering Issues E (Closed) Unresolved Item 50-237/249/94003-04: Piping stress for the low pressure core injection (LPCI) piping system. The inspectors had identified that the original piping analyses for the LPCI system had only considered one uniformly hot temperature and did not consider the various operating modes for thermal stresses. By letter dated June 10, 1994; Com Ed stated that additional analyses were performed and that the revised loads were within the load limit criteria specified by Primera Engineers Report 93173-1, "Limit Criteria for Piping Reaction Load Changes, "Revision 3, dated November 26, 1993. During this inspection, the inspectors reviewed Primera Engineers Report 93173-1 and determined that the report was intended to allow minor load changes (i.e.; less than 20 percent) without requiring revised piping and support stress calculations. Design engineering staff informed the inspectors that the technical basis for Primera Engineers Report 93173-1 was Electric Power and Research Institute (EPRI) Report NP-5639, "Guidelines for Piping System Reconciliation (NCIG-05, Revision 1 ), " dated May 1988 which had been endorsed by the NRC by letter dated February 3, 1988. The inspectors noted that the NRC's endorsement was limited to what EPRI Report NP-5639 was intended for,.i.e., reconciling as-built differences from design. The inspectors concluded that the use of Primera Engineers Report 93173-1 for reconciling a design analysis weakness, such as the original LPCI system piping analyses, was beyond what had been endorsed by the NRC. However, the inspectors reviewed the additional analyses performed for the LPCI piping system, Calculation NED-P-MSD-068, "Analysis of LPCI Piping System to Assess the Effect of Operating Thermal Modes," dated May 11, 1994, and determined that the analyses were acceptable. In addition to determining changes in loadings, Calculation NED-P-MSD-068 had determined what the maximum piping stresses would be and demonstrated that stresses would be within allowable limits. The calculation considered the suppression cooling and LPCI injection thermal modes of the LPCI system in addition to a uniformly hot temperature considered by the original analyses. Based on this information, the inspectors conCluded that the piping stresses for the LPCI system were within acceptable limits. Design engineering staff stated that in response to the inspectors'

questions concerning the application of Primera Engineers Report 93173-1, they had *

reviewed a sample of calculations performed during the 1996 through 1998 time period and had only identified one calculation, Calculation DRE96-0028, "Evaluation of Core Spray Piping due to added HVAC [Heating, Ventilation, and Air Conditioning] Duct Weight," revision 0, dated February 16, 1996, which had used the report as a basis for acceptance. The inspectors reviewed Calculation DRE96-0028 and determined-that the calculation was an as-built reconciliation which was within the guidance endorsed by the NRC and was acceptable. The inspectors concluded that the use of Primera Engineers Report 93173-1 for acceptance of conditions was limited and appropriately controlle This item is close E (Closed) Licensee Event Report 249/94011-01: Loss of Power to Bus 34 Resulted in Auto-start of Unit 3 Emergency Diesel Generator Due [To] Lack of Preventive Maintenance on Bus Pots. The supplement to the LER documented the event of

E E March 25, 1994, during which 4-kV bus 34 lost power and deenergized safety-related equipment and caused a start of the Unit 3 emergency diesel generator. The original LER was closed in report 95010. The supplement to the LER updated the corrective actions by changing the frequency of inspections and cleanings based on a performance-centered maintenance review. The inspectors had no concerns with the supplement. This item is close (Closed) Licensee Event Report 249/95018-00: Manual Trip of High Pressure Coolant Injection (HPCI) Turbine Due to Exhaust Drain Pot High Level Alarm Caused by Procedural Deficiency. The LER documented the event of October 12, 1995, during which the Unit 3 HPCI system's exhaust drain pot filled too high. Operators tripped the HPCI system in accordance with procedures. The licensee concluded that the root cause was that the surveillance procedure used during the event failed to included draining of the exhaust drain pot, therefore, the licensee revised the procedure. The inspectors had no questions regarding the LER. This item is close (Closed) Licensee Event Report 237/96002-00: Unit 2 Shutdown Performed Because of Inability to Meet Allowed LCO Time for High Pressure Coolant Injection System Testin The LER documented the event of April 18, 1996, during which Unit 2 was shut down during unit startup because of a failure of the high pressure coolant injection system indicated by high HPCI discharge line temperature. The licensee found a steam leak from a main steam line drain bypass line orifice plate that was heating the HPCI discharge line. Also, the licensee concluded that some leakage past a check valve was also heating the dis_charge line. The licensee repaired the steam leak and evaluated

The inspectors had no questions about the LER. This item is close IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Refueling Outage Radiological Protection Coverage The inspectors. observed overall good performance by Radiation Protection personnel during the Unit 3 refueling outage. Station dose for the outage was less than the planned goal and was the lowest dose accumulated during refueling outages at the station. Complete details concerning NRC observations of outage radiological protection activities are documented in NRC inspection report 9900 S1 Conduct of Security and Safeguards Activities S Unauthorized Protected Area Entry On January 14, 1999, there was an unauthorized entry into the protected area. The entry was not malevolent in nature and the licensee ensured that immediate

1: *

.

.-

compensatory measures were taken upon discovery. Further details concerning this event, and the NRC follow-up, are documented in inspection report 99007.

V. Management Meetings X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the *

conclusion of the inspection on February 26, 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,,-

PARTIAL LIST OF PERSONS CONTACTED Licensee G. Abrel, Regulatory Assurance NRC Coordinator L. Aldrich, Radiation Protection Manager J: Almon, Training Manager D. Ambler, Senior Licensing Engineer S. Barrett, Shift Operations Manager K, Bowman, Outage Manager P. Boyle, Chemistry Manager P. Chabot, Site Engineering Manager L. Coyle, Shift Operations Supervisor R. Fisher, Maintenance Manager P. Garret, Self Assessment Lead J. Heffley, Site Vice President J. Harlach, Support Services Manager K. Ihnen, Lead Assessor R. Kelly, Reg Assurance NRC Coordinator W. Lipscomb, Site Vice President Assessor J. Lizalek, Nuclear Oversight Assessor D. Miller, Radiation Protection Supervisor J. Moser, Radiation Protection D. Nestle, Radiation Protection M. Pacilio, Work Control and Outage Manager M. Porter, QC Supervisor

. D. Schupp, Operations Support Manager F. Spangenberg, Regulatory Assurance Manager S. Stiles, Assessment Manager

. P. Swafford, Plant Manager D. Winchester, Nuclear Oversight Manager B. Dickson, Resident Inspector K. Riemer, Senior Resident Inspector M. Ring, Chief, Reactor Projects Branch I, Region Ill D. Roth, Resident Inspector Illinois Department of Nuclear Safety J. Roman, Resident Engineer

INSPECTION PROCEDURES USED IP 37551:

IP 61726:

IP 62707:

IP 71707:

Onsite Engineering Surveillance Observations Maintenance Observation Plant Operations IP 71750:

Plant Support Activities Opened 50-237/249/99003-01 50-237 /249/99003-02 50-237 /249/99003-03 Close /249/99003-01 50-237 /249/99003-0 /249/99003-03.*

50-249/95018-00 50-249/94011-01 50-237 /96002-00 50-237/249/97004-01 Discussed 50-237/99001-00 ITEMS OPENED, CLOSED, AND DISCUSSED NCV Inadequate procedure major contributor for exceeding TS limit NCV *Failure to follow procedure for signing on to the OOS NCV Failure to follow procedure for valve position NCV * Inadequate procedure major contributor for exceeding TS limit NCV Failure to follow procedure for signing on to the OOS NCV Failure to follow procedure for valve position LER Manual Trip of HPCI Turbine LER Loss of Power to Bus 34 LER Shutdown Performed Because of Inability to Meet Allowed LCO Time for HPCI Testing IFI Effectiveness of Equipment Operator Tours LER l.Jnit 2 loss of drywell to Torus DIP

(

/'

OAP DATR DGP DOA EPRI GSLO HPCI HVAC IFI IR LCO LER NCV NRC NSO ace oos PIF PORC RG TS UFSAR VIO LIST OF ACRONYMS USED Dresden Operating Procedure Dresden Administration Technical Requirements Dresden General Procedure Dresden Operating Procedure

Inspection Report

Limiting Condition for Operations

Licensee Event Report

Non-Cited Violation

Nuclear Regulatory Commission

Nuclear Station Operator

Outage Control Center

Out-of-Service

Problem Identification Form

Plant Operation Review Committee

Regulatory Guide

Technical Specification

Updated Final Safety Analysis Report

Violation

31

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