ML17191A645

Insp Repts 50-237/98-09 & 50-249/98-09 on 980221-0403. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML17191A645
Person / Time
Site:	Dresden
Issue date:	05/03/1998
From:	Ring M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML17191A643	List: ML17191A642 ML17191A644 ML17191A645
References
50-237-98-09, 50-237-98-9, 50-249-98-09, 50-249-98-9, NUDOCS 9805140314
Download: ML17191A645 (33)

See also: IR 05000237/1998009

Text

{{#Wiki_filter:U.S. NUCLEAR REGULATORY COMMISSION Docket Nos: License Nos: Report No: Licensee: Facility: Location: . Dates: Inspectors: * Approved by: 9805140314 980503 PDR ADOCK 05000237 G PDR REGION Ill 50-237; 50-249 DPR-19; DPR-25 50-237/98009(DRP); 50-249/98009(DRP) Commonwealth Edison Company Dresden Nuclear Station Units 2 and 3 Executive Towers West Ill 6500 North Dresden Road Morris, IL 60450 February 21 through April 3, 1998 K Riemer, Senior Resident Inspector B. Dickson, Resident Inspector D. Roth, Resident Inspector C. Settles, Illinois Department of Nuclear Safety M. Ring, Chief Reactor Projects Branch 1

EXECUTIVE SUMMARY Dresden Nuclear Station Units 2 and 3 NRC Inspection Report No. 50-237/98009(DRP); 50-249/98009(DRP) Operations

The preparation and execution of sequential single recirculation loop operations were carefully planned and well-performed. (Section 01.2)

The licensee declared the Unit 3 High Pressure Coolant Injection system inoperable during this inspection period due to a gland seal leakoff condenser level control system failure. This repeat failure indicated that the lieensee's prior corrective actions to address the deficiency.were not completely effective. (Section 02.1)

The fuel movements from the reactor to the fuel pool were initially performed poorly. Consequently, one fuel bundle mispositioning and one fuel bundle misorientation occurred. Verbal verifications were not being performed in accordance with the fuel movement procedures. The licensee's response to the misorientation was weak because the licensee did not detect the mispositioning that had occurred previously. (Section 04.1)

The corrective actions taken to address the fuel bundle misorientation and mispositioning event were sufficient to prevent additional errors. The licensee cbmpleted the fuel reload on April 1, 1998, without any mispositionings or misorientations. (Section 04.1)

The control room operators performed in an excellent anti conservative manner when

• presented with information pertaining to the inoperability' of the scram discharge volume

level switches. (Section 04.2)

• *

Operators demonstrated a lack of attention to detail and weak operating practices during a reactivity management event. While the control rod mispositioning event had minimal safety significance, this event was similar in nature to the fuel bundle errors documented in Section 04.1 of the report. The licensee's prompt investigation into the event was thorough and appropriate. (Section 0~.3)

The inspectors did not identify any performance deficiencies during the Unit 2 shutdown activities. The operators completed the shutdown safely and correctly. (Section 04.4) Maintenance *

Maintenance department personnel performance during brush replacement on the Unit 3 reactor recirculation motor generator sets was good. (Section M1 .2)

The inspectors concluded that drywell housekeeping was adequate for the conditions* existing at the time (planf in cold shutdown) .. (Section M2.1) 2

Torus housekeeping practices appeared sufficient to prevent foreign material from entering the suppression pool and adversely affecting the emergency core cooling system suction strainers. The licensee's scaffold erection practices caused superficial damage to the torus internal protective coating. (Section M2.2)

The licensee commenced reactor shield block and drywell head removal using a procedure that could not be followed as-written because it did not indicate a safe load path. The safety consequences of the inadequate procedure were low because the mQvement of the heavy loads only passed over subsequently approved areas. (Section M3.1)

The foreign materials exclusion procedure could not be used as written. The Quality and Safety Assessment department identified additional examples of incorrect procedure usage subsequent to the inspectors' identification of problems. (Section M3.1)

• Engineering

The method used to C:alibrate emergency diesel generator time delay relays differed from that recommended by the vendor. The licensee subsequently demonstrated that the calibration* method used had resulted in similar values obtained by using the vendor's method; however, the deviation from the vendor's instructions was not addressed for several months. (Section .E2.1)

• *

Lack of engineering action to address design specification discrepancies during the initial repair of the shutdown cooling smallbore line represe.nted poor engineering performance regarding the recognition of nonconforming design specifications on equipment important to safety, (Se~Q.n. E2.~) . * . .. . .. __ *:>.,

.* . ~. . . .

Engineering department personnel challenged the control room operating crew by prematurely declaring the scram discharge volume instruments.inoperable. While the inoperability call was conservative, the conclusion resulted in the operating crew unnecessarily commencing a reactor shutdown on Unit 3. (Section E2.3) Plant Support

Overall, control and monitoring of refueling floor radiation protection activities were good. The inspectors did note one poor practice of using contaminated tape to secure equipment on a diver. (Section R4.1)

Drywell personnel demonstrated poor radiological protection practices on one occasion by not addressing a steady flow of non-contaminated water until prompted by the NRC. Additionally, the licensee did.not perform an inspection for potential equipment damage or document the awareness of this issue via the problem identification form process in a timely manner. (Section R4.2) 3

Radiological controls and radiation worker practices were weak at the beginning of the Unit 2 refueling outage. However, the inspectors noted that as the Unit 2 refueling outage progressed, radiological control and radiological worker performance improved. The improvem~nts were due to increased vigilance by the radiation protection technicians and an increased emphasis on discussing good radiation worker practices during pre-job briefs and tailgate meetings. (Section R4.3)

The inspectors identified one example where a fire door was blocked open without following the appropriate procedures. The door had been blocked open to allow a testing wire to be routed under the door. The licensee identified other examples of this type of issue. (Section F1 .1)

• • ,:-.
• .

~ 4

Report Details Summary of Plant Status Unit 2 started the period near full power. On March 6, 1998, operators commenced a reactor shutdown for refueling outage D2R 15. The unit remained shutdown for the remainder of the period for the refueling outage. Unit 3 remained near full power for most of the period except for brief decreases to support tests. ' On March 24, 1998, operators commenced a Technical Specification (TS) required shutdown due to inoperable scram discharge volume (SDV) level switche.s. Operators reduced reactor . power by approximately 100 MWe before the engineering department determined that the SDV level switches were not inoperable. Operators returned l,Jnit 3 to near full power where it remained for the rest of the period. Unit 3 power was limited to maintain the main turbine control valve position to below an average position of 85 percent open with no valve greater than 90 percent open. On both units, feedwater flow was limited to 9.735 Mlbm/h as a result of a review of the fuel cycle analysis performed by engineering personnel. Analyses to eliminate the derates were being done. I. Operations 01 Conduct of Operations 01.1 General Comments Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. Overall, the conduct of operations was safe and in accordance with procedures. During the inspection period, some events occurred for which the licensee was required by 10 CFR 50. 72 to notify the NRC. The events and notification dates are listed below: 3/11/98 3/24/98 3/27/98 (Unit 2) Reactor scram signal received from scram instrument volume level high. The unit was in Mode 5 and no control rod movement occurred as all rods were fully inserted with all control rod drives (CRDs) out of service. (Unit 3) Technical Specification required shutdown due to SDV level switches possibly being inoperable due to non-conservative setpoints. The licensee subsequently retracted the inoperability decision and associated 10 CFR 50.72 notification. (Units 2 and 3) Entry of an employee into the Protected Area who had no current authorization for unescorted access to the station. 5

3/30/98 (Unit 3) High Pressure Coolant Injection (HPCI) system declared inoperable due to failure of the gland seal leakoff (GSLO) condenser level control switch to control level in the GSLO condenser automatically. 01.2 (Unit 3) Single-Loop Operations a. Inspection Scope (71707) The licensee sequentially.secured and restarted each r~actor recirculation motor- generator (MG) set on February 28, 1998, for replacement of brushes. The inspectors observed portions of the planning and execution of the evolution. b. Observations and Findings The planning and preparations for the evolutions were good. Portions of the MG-set s~curing and restarts observed were in accordance with written instructions. The inspectors noted that the proeedures, Updated Final Safety Analysis Report (UFSAR), TS, and other documents were thoroughly reviewed prior to performing the evolution. The second reactor recirculation pump failed to complete its startup-sequence following completion of the maintenance. The licensee investigated and concluded that the temperature of the oil was too high in the 38 MG coupler. The 3A MG set had started with an oil temperature of 116°F, but the 38 MG set did not complete the start with an oil temperature of 120°F. Subsequently, the oil was cooled to 104°F, and the MG set started. The licensee intended to proceduralize keeping the oil below 115°F. The vendor's instructions did not provide recommendations regarding oil temperatures for . pump starts. . c. Conclusions The preparation and execution of sequential single recirculation loop operations were carefully planned and well performed. 02 Operational Status of Facilities and Equipment 02.1 (Unit 3) High Pressure Coolant Injection (HPCI) System a. Inspection Scope (71707) The inspectors reviewed the status of the Unit 3 HPCI system. b. Observations and Findings On March 30, 1998, the licensee declared the Unit 3 HPCI system inoperable due to.the failure of the GSLO condenser level control switch to automatically control level in the GSLO condenser hotwell. This event occurred during performance of the weekly surveillance of the GSLO level control system. Weekly testing of the HPCI GSLO level condenser was one of the licensee's corrective action commitments following a similar event that resulted in HPCI being declared inoperable on February 19, 1998, (Reference LER 249/98001). The licensee used Dresden Operating Surveillance (DOS) 2300-09, 6

"HPCI Gland Seal Leak Off Drain Pump and Condenser Hotwell Level Control Function Test," to perform this weekly test. As of the end of this inspection period the licensee was developing an action plan to replace the type of level switch used in the GSLO condenser with a more reliable switch design. c. Conclusions The licensee declared the Unit 3 HPCI system inoperable during this inspection period due to the GSLO condenser level *control system failure. This repeat failure indicated that the licensee's prior corrective actions to address the deficiency were not completely effective. 02.2 Unit 2 Shutdown Cooling (SDC) Pump a. Inspection Scope The inspectors performed plant tours and evaluated the material condition of safety- related equipment and structures. b. Observations and Findings On March 11, 1998, the inspectors identified a gross leak on a smallbore branch line on the SOC suction piping. At the time, operators were using the Unit 2 "C" pump in the spent fuel pool cooling mode and spent fuel movements were in progress. Besides its use as a system fill line, this branch line was also used as a cooling water supply to the seal cooler for the Unit 2 "C" SOC pump by using a tee connection. The leak was .... , jdeQtified at. that tee c:Onn~ction .. The inspectors .also noted excessive _vi~rations. of the* -* *: ** t>ranch 11r1e. * *

• * :* *** *
• . * . *

-

• • ** :*** , * .* *

Immediately after identification, the inspectors notified the operations staff of the teak. A s.hort time later, after the leak became visibly worse and water from the line. was spraying out into the SOC pump room and onto cabling trays, the licensee decided to stop fuel movements and repair the leak on this branch line. The inspectors questioned the engineering staff on the repair activities associated with the leak (reference Section E2.2 of this report for additional. information). The licensee replaced the branch line with a like-for-like fabrication of the as-found piping and

continued fuel movements. The shift manager then performed an operability evaluation per plant procedures and concluded that the "C" SOC train was operable. c. Conclusions The inspectors concluded that since the licensee suspended spent fuel moves until the leak was addressed, and both spent fuel cooling pumps were available, the safety significance of the leak on the SOC small bore branch line "T" was minimal. . 7

04 Operator Knowledge and Performance 04. 1 (Unit 2) Reactor Services and Fuel Handling a. Inspection Scope (71707) The inspectors evaluated the licensee's performance during reactor disassembly and fuel movement.. b. Observations and Findings The fuel movement from the reactor to the fuel pool was scheduled to begin sufficiently after shutdown in accordance with the UFSAR. Fuel moves directly observed were performed in accordance with procedures. Communications, command, and control were good. The licensee identified that two fuel handling errors occurred during one shift. On March 14, 1998, a fuel assembly was misoriented when it was placed in the fuel pool. *

• The mis-orientation error was identified immediately upon release of the fuel bundle. On

March 16, 1998, the licensee discovered a mispositioned fuel assembly that had been set in the wrong lo~tion in the fuel pool on March 14, 1998. Both events were caused by failures to accurately verify the fuel positions. The licensee performed prompt investigations for the two events. The prompt investigation of the misorientation event documented that the Senior Reactor.Operator ~*

. (SRQ) was perfQrming turnover. during .fuel movements a.nd was,Jherefore. ~i~ti;acte~. The investigation into the mispositioning event found procedural adherence problems . related to verbal verifications. The personnel carr)'ing out the fuel moves on March 14 were not following DFP 0800-10, uFuel Movement from the Reactor to the Spent Fuel Storage Pool." . The safety consequences of the mispositioned and misoriented fuel in the fuel pool were minor. The location of the spent fuel pool that received the mispositioned fuel was already designated to receive spent fuel during the off-load. After the misorientation error, the licensee did not re-verify all movements made by the crew. This was in contrast to the licensee's response to an identified misorientation during the previous Unit 2 refueling outage (02R14) core reload in January of 1996. In 1996, the licensee stopped work and performed a full core audit (reference Report No. 95015, Section 1.3}. The licensee concluded that a full audit was not necessary after identification of the 1998 misoriented bundle because the fuel was in the fuel pool, not the reactor, and an additional full audit was to be performed prior to reloading fuel into the reactor. The inspectors noted that the decision delayed detection of the mispositioned fuel assembly for several days. For corrective action after the mispositioning was found, the licensee audited the empty locations in the fuel pool to assure no other fuel was mispositioned. No other errors were located. The licensee performed appropriate training and discussions on the events. 8

On April 1, 1998, the licensee completed reloading Unit 2. No errors were identified during the reloading. The inspectors therefore concluded that the corrective actions taken for the two events were effective. The personnel carrying out the fuel moves on March 14 were not following verification procedures in DFP 0800-10; and, as a result, did not move fuel in accordance with the nuclear component transfer list. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50-237/98009-01 (DRP)). c. Conclusions The fuel movements from the reactor to the fuel pool were initially performed poorly. Consequently, one mispositioning and one misorientation occurred. The investigation into the events revealed that verbal verifications were not conducted *in accordance with

• the fuel movement procedures. The licensee's response to the misorientation was weak

because the licensee did not detect the mispositioning that had occurred previously. The corrective actions were sufficient to prevent additional errors. The licensee completed the fuel reload on April 1, 1998, without any additional mispositionings or misorientations. 04.2 Operator Conduct During Unit 3 Shutdown Activities a. Inspection Scope (71707) On March 24, 1998, engineering personnel informed the operations staff that the scram discharge volume (SDV) level switches would not be able to meet their TS setpoints arid . should be.declared inoperable. Operators declared the SDVleve!SY{i.tches inoperable -and entered a 12-hour to hot shutdown TS Limiting Condition for Operation (LCO). The inspectors observed initial operator response to the information and subsequent implementation of the required reactor shutdown. b. Observations and Findings On March 24, 1998, engineering personnel determined that the SDV level switches were inoperable due to non-conservative setpoints. Engineering personnel concluded that a complete operability determination could not be performed in a timely fashion and, therefore, recommended to the Operations department that the level switches be declared inoperable (Reference Section E2.3 of this report). * Operators entered the appropriate TS LCO and performed the required actions. These actions included: placing the affected components in a trip condition (half scram), and, placing the reactor in a hot shutdown condition within 12 hours. During the heightened level of awareness (HLA) briefing, the control room operators thoroughly disciJssed the required shutdown activities and potential vulnerabilities associated with the shutdown. For example, the control room operator requested that peer checks be performed when ranging down the intermediate range monitors (IRMs); with a half scram signal already inserted, an error while ranging IRMs would result in a full reactor scram. The operators initiated the reactor shutdown and dropped reactor power level by approximately 100 MWe. At that point, engineering personnel determined that the SDV level switches were not inoperable and the reactor shutdown was terminated. 9

c. . Conclusions The control room operators performed in an excellent and conservative manner when presented with information pertaining to the inoperability of the SDV level. switches. 04.3 .Unit 3 Control Rod Mispositioning a. Inspection Scope (71707) The inspectors reviewed the circumstances surrounding of a licensee identified control rod mispositioning error that occurred on March 3, 1998. b. Observations and Findings While pulling control rods for flow control line (FCL) adjustments, the reactor operator placed the rod out notch override (RONOR) switch in the "rod out notch override" position concurrent with placing the rod movement control switch in the "rod at" position.* Control rod drive (CRD) .F-12 was to be moved from Position 08 to. Position 10; the rod subsequently passed its target and settled at Position 12. The operator immediately ~ .: ":- . . recognized what had occurred, notified the unit supervisor (US), and the control room staff entered Dresden Operating Abnormal (DOA) Procedure 0300-12, "Mispositioned Control Rod." The US verified with the qualified nuclear engineer (QNE) that there was no challenge to the core and thus no safety significance to the event. The US discussed the matter with the reactor operator. The control room staff then completed the FCL rod pulls without further incident.

,.- . **The. US did not notify the .. staift manager (SM) oOhe. ~veni until aft~r the ro~ pulls were. * . - completed. *'The SM then stopped "an reaCtivity moves on both units until ope,..~ions . management completed a review of the event. The licensee removed the operator and the US from licensed duties, documented the occurrence via problem identification form (PIF) D1998-01376, and initiated an investigation. The licensee's investigation documented several causes. The operator failed to follow procedure by using the RONOR switch during single notch CRD withdrawals. Additionally, the US failed to promptly inform station management of the reactivity event because the crew focused on the possibility of a control rod double notching event rather than human error during reactivity manipulations. The personnel performing the reactivity management activities did not follow guidance contained in Dresden Operating Procedure (DOP) 0400-01, "Reactor Manual Control System Operation," concerning the use of the RONOR switch during CRD single notch activities. The inspectors considered the licensee's investigation to be thorough and appropriate. The failu"re to follow Procedure DOP 0400-01 is considered a violation of TS 6.8.a. This non-repetitive licensee identified and corrected violation is being treated as a non-cited violation consistent with Section Vll.81 of the NRC Enforcement Policy (NCV 50-249/98009-02 (DRP)). c. Conclusions The control rod mispositioning event had minimal safety significance and the licensee's investigation into the matter was thorough and appropriate. However, operators demonstrated a lack of attention to detail and weak practices during a reactivity 10

management event. This event was similar in nature to the fuel bundle errors documented in Section 04.1 of this report. 04.4 (Unit 2) Reactor Shutdown Activities a. Inspections Scope (71707) The inspectors conducted observations of the Unit 2 shutdown activities for Dresden Refueling Outage (D2R15). Procedures and documents reviewed included Dresden General Procedures (DGP) 02-01, "Unit 2 Shutdown,n and DGP 02-03, "Reactor Scram." b. Observations and Findings During the Unit 2 shutdown, the inspectors noted that the nuclear station operators performed shutdown activities in a careful and controlled manner .. Peer. checking and three-way communication were evident throughout the shutdown evolution. Hold points were strictly adhered to and the unit supervisor gave informative and timely HLA crew briefs. Additionally, control room distractions were held to a minimum level. c. Conclusions The inspectors did not identify any performance deficiencies during Unit 2 shutdown activities. Operators completed the shutdown safely and correctly. 06 Operations Organization and A~ministration 06.1 ... Development of Uniform Peer Groups at"Each Site a. Inspection Scope (37551) On March 28, 1997, the licensee provided the NRC with its response to the NRC's request for information under 1 O CFR 50.54(f) regarding safety performance at Commonwealth Edison. Part of the response contained a commitment {Nuclear Tracking System (NTS) Item 99-123-97-001068 or #68) to provide a status of peer groups and provide upd~ted examples where peer groups have developed and implemented safe, effective practices at each site. The inspectors reviewed the current status of that commitment. b. Observations and Findings On September 30, 1997, the licensee closed Commitment #68. The closure documentation stated that ten peer groups have been established. Inspector discussions * with Dresden management demonstrated involvement in developing standardized pre- outage milestones, operations standards, and common maintenance procedures. c. Conclusions The licensee followed through on commitments for peer groups and for performance initiatives regarding operations standards and human performance. Item 68 is implemented and considered closed. 11

........ ~-** ***-*---~-... ~--** - - 07 Quality Assurance in Operations 07.1 Management Review Meeting a. Inspection Scope (71707. 40500) , The inspectors observed Management Review Meetings (MRMs) conducted on February 11, 1998, and March 23, 1998. b. Observations and Findings The topics for the MRMs included general plant status, plant material condition assessment, human performance assessment, maintenance work backlogs, refueling outage plans, and Quality and Safety Assessment (Q&SA) issues. Site managers presented the topics to a panel of licensee senior executives. The inspectors observed the panel members ask probing and in-depth questions of the presenters. The panel provided feedback and eonstructive criticism to the panel presenters during the discussions. c. Conclusions The panel asked probing questions and did not accept easy answers from the presenters. The inspectors concluded that the MRMs were positive meetings and added value to plant operations. 08 Miscellaneous Operations Issues . * ' . .* .... '~-;., 08.1 (Closed) LER 23719701~00: 1',.;ad.vertent EXit From the Main Cont~t'Rooni due to Lo,ss of Focus Resulted in Inadequate Control Room Staffing. On August 17, 1997, the Shift Manager (SM) provided the Unit 2 Unit Supervisor (US) with an interim relief from the control room. The SM then left the control room without being relieved, reducing the control room staff below requirements specified in TS 6.2. B.2. This event was a repeat of a similar occurrence where SROs were absent from the control room due to personnel errors (Reference LER 237/95007 and LER 237/97006). The NRC issued a Notice of Violation (NOV) for the event described in LER 237/97006. Subsequent to the issuance of LER 237/97014, the NRC issued an NOV (VIO 50-237/249-97013-01A(DRP))*for inadequate corrective actions. This LER is closed and will be tracked under the NOV. 08.2 (Closed) URI 50-237/96002-01: Inadequate closure inspection of Unit 2 Drywall. This Unresolved Item was initiated to track the completion of the licensee's corrective actions for a number of issues related to inadequate inspections and control of the drywall. Subsequently, a Severity Level IV violation (50-237/249-96004-03) was issued for inadequate closeout of the Unit 3 drywall. This unresolved item is therefore closed. 08.3 (Closed) IFI 50-237/249-95012-0HDRP): Operation of station blackout (SBO) diesel generator console. This IFI was initiated to track the completion of the licensee's study of the best way to operate the SBO. The licensee ci>mpleted this study in 1996. 12

II. Maintenance M1 Conduct of Maintenance M1 .1 (Units 2. 3) General Comments (62707. 61726) Maintenance work observed was performed in accordance with procedure. Workers- used the correct procedures and work requests, were knowledgeable of the jobs and activities, and performed the tasks correctly. Tasks observed included:

Installation of Main Steam Line Plugs Local Leak Rate Test on Drywell Head Main Condenser Bellows Replacement Main Steam Isolation Valve Maintenance CCSW Heat Exchanger Repair and Cleaning Feedwater Heater Elbow Erosion/Corrosion Testing Control Rod Drive Hydraulic Control Unit Repairs Reactor Water Cleanup Maintenance High Pressure Coolant Injection System Maintenance M1 .2 (Unit 3) Reactor Recirculation Motor Generator Set Brushes a. Inspection Scope (62707) Ttle inspectors observed the replacement of brushes *on the Unit 3 rea~Qr_ n!circulatiofl MG sets.

- *

b. Observations and Findings The maintenance planning and execution of the brush replacement was performed correctly. The licensee demonstrated attention to detail thro.ugh_careful job performance, by maintaining foreign material exclusion areas, and by reviewing previous brush replacement activities. c. Conclusions Maintenance department personnel performance during brush replacement on the Unit 3 MG sets was good. M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Drywell Housekeeping a. Inspection Scope (62707.71707) The inspectors performed routine drywall inspections during the outage to assess licensee housekeeping and material control effectiveness. 13

.. b.

• Observations and Findings

On March 20, 1998, the inspectors toured the drywell and identified that, while housekeeping conditions were adequate for the mode the plant was in at the time, overall housekeeping practices were weak. Some of the housekeeping deficiencies identified by the inspectors included the following: multiple loose tie- wraps, especially at the lower levels, tape material, tags, loose rags, hard hats, and miscellaneous loose tools. After the inspectors discussed their concerns, housekeeping personnel subsequently removed several bags of trash and debris from the drywell; however, the inspectors were concerned with the.potential for debris to impact the emergency core cooling system suction strainers, if satisfactory housekeeping conditions were not reestablished prior to plant startup. The licensee informed the inspectors that the drywell would be completely cleaned prior to plant startup from the refueling outage. Subsequent to the inspectors' drywell inspection on March 20, the Q&SA department identified additional deficient conditions in the drywell. The licensee documented the deficiencies via PIF .01998-02132. Management reemphasized expectations to site wide personnel concerning drywall housekeeping standards and stated that the observed conditions would not be tolerated. In addition to the housekeeping weaknesses identified by the inspectors and the licensee, the inspectors also identified a radiation protection and potential equipment dam~ge concern as a result of the March 20 drywell inspection. This issue is discussed further in Section R4.2 of this report. c. . . . Conclusions The inspectors concluded that drywell housekeeping was adequate for the conditions existing at the time (plant in cold shutdown). However, drywell housekeeping would need to be improved to support a plant startup. Licensee management informed the inspectors that the drywall would be proper1y cleaned prior to closing out the drywall and

commencing a reactor startup. The inspectors will monitor the effectiveness of licensee containment housekeeping efforts as part of the routine inspections performed prior to plant startup following a refueling outage. M2.2 Torus Housekeeping and Material Condition a. Inspection Scope (62707.71707) The inspection assessed the licensee's torus housekeeping and work practices during the Unit 2 refueling outage. . b. Observations and Findings .. The inspectors toured the inside of the torus during the refueling outage. No significant amount of maintenance debris was noted and the licensee's housekeeping practices appeared adequate to prevent foreign material from entering the suppression pool and potentially adversely impacting the emergency core cooling system (ECCS) suction strainers. 14

The inspectors identified two minor instances where scaffolding erected in the torus had potentially aamaged the torus internal coating. In bay 2 of the torus, horizontally oriented scaffold poles were erected perpendicular to, and in close proximity to, the torus membrane. The inspectors could not determine if the poles were actually in contact with the torus, however, the torus protective coating appeared to be scratched or gouged near the pole. A similar situation existed in bay 13 of the torus. A horizontal scaffold pole appeared to be in close proximity to the torus shell. The protective coating also appeared to be marked in this area. The inspectors forwarded their concerns to licensee personnel and were informed that the areas in question would be inspected prior to final torus closeout. Subsequent to the end of the inspection period, licensee inspectors determined that the marks were superficial in nature and had not degraded the surface to the point where any coating was removed. The licensee inspectors observed no exposure of the carbon steel substrate. c. Conclusions Torus housekeeping practices appeared sufficient to prevent foreign material from entering the suppression pool and adversely impacting the ECCS suction strainers. The inspeCtors identified that the licensee's scaffold erection practices caused superficial damage to tlie torus internal protective coating. M3 Maintenance Procedures and Documentation M3.1 (Unit 2) Procedure Adequacy for Refueling Floor Activities a. Inspection Scope {62707) .*-* - --- ' - The inspectors evaluated the compliance with, and adequacy of,'the procedu-res in use - on the refueling floor. - b. Observations and Findings -Reactor Shield Block and Drywell Head Removal The licensee commenced disassembly of the reactor shield blocks on March 7, 1998. The procedure used was Dresden Maintenance Procedure (DMP) 1600-03, Revision 13, "Reactor Shield Block and Drywell Head Removal," effective February 9, 1998. On March 7, the inspectors reviewed DMP 1600-03, Revision 13, and noted that Step F.3 stated: "The safe load path for movement of the reactor shield block and the drywell head is shown on Figure 6, 613 Elevation Floor Plan. Any deviations to the load paths shown must be approved by the Onsite review process." However, Figure 6 of DMP 1600-03, Revision 13, did not show the "safe load path for movement," or any load paths at all. The inspectors informed the Reactor Services personnel who were disassembling the reactor of the error. The personnel informed the inspectors that the entire 613' elevation, except for the areas over the spent fuel pools 15

and the open reactor cavity, was analyzed to allow passage of heavy loads. Subsequently, on March 7, 1998, the licensee added this infonnation to Figure 6. No PIF was initially written to document the inadequate procedure. The Reactor Services manager indicated that the infonnation was a clarification; therefore, did not require a PIF. The licensee subsequently documented the clarification per the PIF process for trending purposes.

Foreign Material Exclusion The licensee used Dresden Administrative Procedure (DAP) 07-35, Revision 13, "Foreign Material Exclusion Program for the Unit 2/3 Refueling Floor," to provide specific controls to prevent intrusion of foreign materials into the reactor vessel. On March 17, *1998, the inspectors noted that revision 13 of DAP 07-35 stated that each person bringing material into the Area 1 Foreign Material Exclusion (FME) shall enter initials and date in the log attached to DAP 07-35. However, the actual log sheet of DAP 07-35 instead required the FME monitor (not each person) to ente~ the person's badge number. The inspectors discussed the issue with the assigned FME monitor. The inspectors were infonned that the monitor had not noticed the discrepancy before, and that practice was for the monitor to record the workers' badge numbers. The issue was documen.ted in PIF 01998-01842. In response, the licensee revised OAP 07-35 on March 17, 1998. On March 18, Q&SA identified that the FME controls on the 613' elevaJtion refueling floor were inadequate .. Issues identified by Q&SA included the use;of.mu!tip.le revisi9ns of OAP 07-35 and failure to have supervisors doeument reviews of log sheets frOm .*

March 9, 1998, to March 18, 1998. These additional issues were documented in PIF 01998-01912. Appendix B, Criterion V, of 10 CFR Part 50 required that activities affecting quality be prescribed by procedures of a type appropriate to the circumstances. Contrary to this, from at least February 9, 1998, to March 7, 1998, Procedure OMP 1600-03, Rev. 13, was not appropriate because it did not show a safe load path for movement even though it directed that the load path be followed. In addition, Procedure OAP 07-35, Rev. 13, was not appropriate because the log sheets attached to the OAP did not have the signature- blocks specified in the body of the procedure. These failures constituted a violation of minor significance and were being treated as a Non-Cited Violation, consistent with Section IV of the NRC Enforcement Policy (NCV 237/249-98009-03 (DRP)). c. Conclusions The licensee commenced reactor shield block and drywell head removal using a procedure that could not be followed as-written because it did not indicate a safe load path. The consequences of the inadequate procedure were low because the movement of the heavy loads only passed over subsequently approved areas. 16

The foreign materials exclusion procedure also could not be used as written. The inspectors were concerned about this issue since no licensee worker had identified and corrected the procedure even though the procedure was being used by multiple workers. Also, the Q&SA department identified additional examples of incorrect procedure usage subsequent to the inspectors' identification of problems. M3.2 (Units 2.3) Review of Licensee 10 CFR 50.54<0 Commitments a. Inspection Scope (62707) The inspectors reviewed and evaluated licensee commitments made in response to the NRC's 10 CFR 50.54(f) letter to Commonwealth Edison. b. Observations and Findings The inspectors reviewed the following licensee commitments: Commitment 48. A standard screening process in place at all sites to ensure maintenance work is proper1y classified and prioritized. The inspectors verified that the licensee had effectively implemented the procedure NSWP-WM-08, "Action Request Screening Process." The screening process, which included the prioritization and classification of all action requests, was accomplished daily by a multi-discipline screening committee. Commitment 49. Wo~ planning is evaluated for inefficiencies that keep work from being performed. Currently the licensee has integrated a Quality Check Team in the E-4 stage of NSWP-WM-09 "Maintenance Work Scheduling Process Week E-5.to E+1." This Quality Check Team is a multi-disciplined team made up of quality assurance, maintenance and regulatory assurance personnel. The licensee planned to fully implemented corporate wide Procedure NSP-WC-3005, "Maintenance Planning Process," by March 30, 1998. Commitment 50. All sites are implementing minimal work request process for minor maintenance. The inspectors verified that the licensee was carrying out a minimal work request process for minor maintenance using NSWP-WM-06 "Minor Maintenance Process." The inspectors noted that this procedure was being implemented by maintenance work analyst personnel only. The lieensee has developed an NTS item to train all first line supervisors on using NSWP-WM-06. This NTS item is scheduled to be completed on October 30, 1998. Commitment 51 .. FIN emergent work completed is measured to determine effectiveness. The inspectors verified that the licensee monitored Fix-It-Now (FIN) team production indicators to assess the effectiveness of the FIN process. The inspectors reviewed three graphs produced by the licensee. The first graph compared the number of completed FIN 17

emergent jobs verses the completed maintenance emergent jobs. The second graph categorized the emergent work completed by the FIN team into appropriate prioritization categories based on the urgency of the work. (A, B-1 and B-2) The final graph depicted the B-3 and C or lower priority wo~ done by the FIN Team. c. Conclusions The inspectors concluded that the licensee met the commitments for the above 10 CFR 50.54(f) items. MS Miscellaneous Maintenance Issues M8.1 (Closed) Violation (50-249/96009-01): Failure to follow approved procedures (SP) and provide an onsite review of a special procedure (SP) for testing Electrical Bus 33-1. The licensee reissued the SP, documented onsite review of the SP, and conducted training for the engineering personnel involved. This violation is closed. M8.2 (Closed) Violation (50-237/96006-01): Performance of work outside the scope of written and approved procedures during testing of the feedwater system. A similar event occurred November 18, 1997, and was documented in NRC Inspection Report No. 50-237/249-97024. A violation was not issued because the licensee had not had time to implement corrective actions for a similar violation. (50-237/249-97019-02A, 028, 02C) cited in Inspection Report No. 50-237/249-97019. The NRC documented concerns with negative trends in procedural adequacy and adherence in Inspection Reports No. 50-237/249-97019, 50-237/249-97024, and 50-237/249-98003 . .A management meeting was eondu~ed at the station between NRC and licensee .ma11agement on April.1, *1998, to discuss licensee planz to address the issue. The

• ucensee's root cause investigation (237-200-97.:04900) into the November 18, 1997,

event stated that the occurrence was almost identical to the May 31, 1996, transient. The inspectors will monitor licensee corrective actions, as discussed in the violation response and root cause report, for procedure adherence and feedwater system issues. This violation is closed. M8.3 (Closed) LER 237/94005-03: Manual Reactor Scram due to Loss of Instrument Air on April 30, 1994, From 99 Percent Power. Revision 0 of the LER was closed in Report No. 94011, and Revi.sions 1 and 2 were closed in Report No. 95010. On April 24, 1997, the licensee submitted the third revision to the LER. In the third revision, the licensee concluded that the failure of the instrument air system was caused by incorrect use of a threaded connection on the 2A instrument air receiver tank instead of a butt-welded connection. The LER stated that a butt-weld was the original design of the connection. The licensee replaced the connections on all the tanks or added weld overlays as appropriate. The inspectors noted that the leaking connection on the shutdown cooling (SOC) system was also caused by use of threads instead of welds (see Section 02.2 of this report for more information). The SOC system connection was not, however, an error from original construction. 18

The LER also discussed how the reactor vessel was overfilled and the HPCI and isolation condenser systems' steam piping flooded immediately after the scram. The LER stated that operators performed in accordance with procedures by taking manual -control of the feedwater regulating valves to attempt to stop the overfill. Although the licensee implemented corrective actions such as conducting additional training and installing system modifications, the inspectors noted that Unit 2 level control remained difficult. For example, the automatic scram of December 23, 1997, resulted in overfilling the reactor vessel, and the manual scram of July 27, 1997, was instigated by problems with the use of manual level control. The licensee planned to modify the feedwater control system during D2R15. Additional information regarding the response of both units' feedwater level control systems is in various inspection reports and in the LERs associated with the two 1997 scrams, so no additional information regarding the 1994 scram is needed. The licensee planned to perform an effectiveness review of.corrective actions associated with LER 237/94005-03 by September 30, 1998. LER 237/94005-03 is therefore closed. M8.4 (Closed) LER 237/97012-00: Inadvertent High Pressure Coolant Injection Isolation. On May 20, 1997, an instrument maintenance technician actuated HPCI system isolation logic during a surveillance test by inadvertently allowing test leads to touch terminal points. The HPCI system responded normally. A contributing factor was the configuration of the terminal points required to be used during the test. The LER also noted that this was the first time the technician performed this task alone, although the

• licensee did not consider that to be a contributing factor. Corrective actions included

establishing a "peer check program," and self-checking training on a simulator.* * . Personnel interviewed reported that the self-checking simulator was a useful training tool. . . - . .. -.. ~. , . The licensee's effectiveness review (ER), completed on December 12, conciu.ded that the

• corrective actions were effective overall. However, the ER noted that the configuration of

the terminal points was still not improved. The. licensee rescheduled an ER to be done by October 30, 1998, after installation of banana jacks at the terminal points. The inspectors concluded that the actions described il;i the LER were effective, based on a reduction of errors associated with Instrument Maintenance Department (IMO) performance. This LER is closed.

• M8.5

(Closed) LER 249/94013-00: Missed TS required Snubber Visual Inspection. The LER documented the discovery by the licensee on May 25, 1994, that a safety-related snubber was not inspected. The subsequent inspection showed the snubber to be operational. The snubber had been installed in 1990, but the modification package did not assure that the snubber inspection was added to the appropriate procedures. The inadequate modification package was prepared in 1988. Failing to perform the 18-month inspection of the snubber from 1990 to 1994 was a violation of T.S. 4.6.1.1.b. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. 19

Ill. Engineering E2 Engineering Support of Facilities and Equipment E2. 1 (Units 2, 3) Emergency Diesel Generator Relays a. Inspection Scope (37550) The inspectors reviewed the licensee's response to identified problems with time delay relays on emergency diesel generators. b. Observations and Findings In December of 1997, Commonwealth Edison's Quad Cities station identified potential problems with some time delay relays on its emergency diesel generators. Personnel from Dresden were present at Quad Cities and observed the problems first-hand. Dresden engineering personnel evaluated the performance of the relays at Dresden, and concluded that no immediate problem existed. Also, since the timing method at Dresden differed from that used by Quad Cities, the Dresden practices were not questioned. Review of several recent surveillances on the time delay relays at Dresden showed the as-found setting to be slightly longer that the accept~nce criteria, but no PIF was written documenting this. The procedure, Dresden Engineering Surveillance (DES) 6600-08, Revision 7, "Diesel Generator Electrical Maintenance Surveillance Inspection," did not explicitly state to write a PIF if the as-found values for the time delay relay were outside of the acceptance criteria. Nonetheless, a PIF would be appropriate in this case to facilitate trending:.

In March of 1998; the inspectors reviewed the vendor manual and noted that it specified a calibration method different from that of DES 6600-08, Rev. 7. The licensee subsequently demonstrated that the calibration method used had resulted in similar . values as those obtained by following the vendor's instructions. The inspectors were concerned that the deviation from vendor's instructions was not addressed for several months. This was a concern because the method used for calibration was a reason why Quad Cities was having problems with its time delay relays. c. Conclusions The station's method to calibrate emergency diesel generator time delay relays differed from that recommended by the vendor. The licensee subsequently demonstrated that the calibration method used had resulted in similar values obtained by using the vendor's method; however, the deviation from the vendor's instructions was not addressed for several months.

20

E2.2 (Unit 2) Shutdown Cooling System (SOC) "T" Leak a.

• Inspection Scope (37550)

The inspectors performed plant tours and evaluated the material condition of safety- related equipment and structures. b. Observations and Findings On March 11, 1998, the inspectors identified a gross leak on a smallbore branch line on the SOC suction piping (reference Section 02.2 of this report for additional information). The inspectors also noted excessive vibrations of the branch line. Based on preliminary conversations with the SOC system engineer, it appeared that the installed .piping broke at the tee connection, in part, due to vibration:* The.system engineer also stated that it was believed that the piping was not supported properly, therefore causing excessive vibration.

During work package preparation and fabrication of the replace*ment piping, the licensee identified that the as-found piping configuration did not agree with the standard design specification as shown, on the safety-related drawing. The design specifications of USAS 831.1 referenced Piping Design Table B (PDT-B) in Specification K-4080, which called for all fittings and unions on ~his line to be joined using a socket weld. The as- tound piping fittings contained threaded connections. Additionally, the inspectors and licensee both noted that the section of the line that supplied water to the seal cooler was not shown on the drawing. Upon further investigation, the *inspectors noted that this smallbore line had been replaced one week prior to the inspectors' identified failure due to a similar leak on the line. The inspectors questioned the engineering staff on why these issues were not addressed during repair of the initial failure. The inspectors noted that neither a PIF nor an engineering request had been written to identify any of these issues during the initial repair of this line. The inspector concluded that this represented poor engineering performance with respect to the recognition of potential nonconforming design characteristics of equipment important to safety. The licensee replaced the branch line with a like-for-like fabrication of the as-found piping and continued fuel movements. The shift manager then performed an operability evaluation per plant procedures and concluded that the "CD Train of SOC was "operable with potential concerns. D An engineering evaluation (ref. DOC ID #0005636522) performed by the licensee later concluded that the as-found piping was acceptable based on weight, thermal, and pressure loadings. However, the engineering evaluation recommended that the subject line be periodically monitored for excessive vibration since USAS 831.1 stated that threaded fittings shall not be used where severe vibration is expected. c. Conclusions Lack of engineering action to address design specification discrepancies during the initial repair of a shutdown cooling smallbore line represented poor engineering performance regarding the recognition of nonconforming design specifications on equipment important to safety. 21

E2.3 (Unit 3) Shutdown in Response to SDV Instrument Concerns a. Inspection Scope (71707) Based on information from Quad Cities, on March 24, 1998, engineering personnel informed the operations staff that the scram discharge volume (SDV) level switches would not be able to meet their TS setpoints and should be declared inoperable. The operators declared the SDV level switches inoperable and entered a 12-hour to hot shutdown TS limiting condition for operation (LCO). The inspectors reviewed the engineering department's performance with respect to the information provided to the Operations staff. b. Observations and Findings Based on information from Quad Cities, on March 24, 1998, engineering personnel determined that the SDV level switches were potentially inoperable due to non- conservative setpoints. Engineering personnel concluded that a complete operability determination could not be performed in a timely fashion and, therefore, recommended to the Operations department that the level switches be declared inoperable (Reference Section 04.2 of this report).

Engineers determined that new setpoints had not been installed on Unit 3 SDV level. switches as part of the Technical Specification Upgrade Project (TSUP). Therefore, the engineering department suspected that the non-TSUP calculation values were still the ~etpoints for the level switches. The as-left value for the Unit 3 switches, from the previous calibration .had not been determined. Instead, engineers focussed on . developing and implementing the new setpoint values for Unit 3. OUe, in part, to weak _ communieations between the engineering and operations departments, engineers had a self-imposed deadline of 8:00 a.m. to make an operability call to the operating shift. When the engineers determined that. a complete analysis of tlie SDV level switch issue could not be appropriately completed by 8:00 a.m., they recommended to operations that the equipment be declared inoperable because the limited information available at the . time indicated that the switches would not be able to meet TSUP requirements. The operators initiated the reactor shutdown and dropped reactor power level by. approximately 100 MWe. At that point, engineering personnel completed a more detailed review of the Issue and determined that the SDV level switches were not inoperable and the reactor shutdown was terminated. c. Conclusions

• Engineers challenged the control room operating crew by prematurely declaring the

scram discharge volume instruments inoperable. While the inoperability call was conservative in nature, the conclusion resulted in the operating erew unnecessarily commencing a reactor shutdown on Unit 3. 22

ES Engineering Staff Training and Qualification E5.1 Training in Engineering Tasks a. Inspection Scope (37551)

• On March 28, 1997, the licensee provided the NRC with its response to the NRC's

request for information under 10 CFR 50.54(f) regarding safety performance at Commonwealth Edison. Part of the response contained a commitment (NTS Item 999-123-97-001024 or #24) to provide additional training to address areas for improvement such as design basis adherence, configuration management implementation, operability determinations, and safety evaluation preparation. The inspectors reviewed the current status of that commitment.

• b.

Observations and Findings On November 14, 1997, the licensee closed commitment #24. The closure documentation *stated that the design basis programs department provided 10 CFR 50.59 training to about 400 personnel from all sites and corporate. The training addressed the concepts for design, operability, and safety evaluations. The inspectors reviewed the lesson plans for safety evaluations, 50.59 training, and for

• design basis initiative training and considered them to be thorough. The inspectors did

note that additional operability training was not provided subsequent to the 50.54(f) letter, because training on the topic had been given recently prior to the 50.54(f) commitment. . c. Conclusions The iicensee followed.though on training committed to in 50.54(f) comm.itment #24. EB Miscellaneous Engineering Issues E8.1 Issues related to excessive leakage from Main Steam Line Isolation Valve CMSIV>-drain* valves On May 30, 1997, the NRC issued a Severity Level Ill violation (EA 96-:391, VIO 50-249/96013-01) for issues associated with excessive leakage from MSIV drain valves. In the letter transmitting the violation, the NRC stated that no additional response to the violation was necessary because information regarding the reason for the violation and the corrective actions were already addressed on the docket. Therefore, the following three issues are closed: E8.2 (Closed) URI 50-237/249-95010-02: Safety significance of excessive leakage from MSIV Drain Valves 3-220-1 and 3-220-2. This issue was also discussed in S_ection 08.5 of Inspection Report 96006. Subsequently, this issue was identified as an apparent violation 50-249/96013-01. This unresolved item is closed. E8.3 (Closed) LER 249/95007-01: Leakage Limit Exceeded due to Valve Internal Damage Caused by Manual Operation of MOV. Revision 02 of this LER was issued on March 29, 1996. This Revision 01 is closed.

23

E8.4 (Closed) LER 249/95007-02: Leakage Limit Exceeded due to Valve Internal Damage Caused by Manual Operation of MOV. Review of this LER was documented in Section E2.1 of Inspection Report 96013, and this issue was identified as an apparent violation 50-249/96013-01. This LER is closed. E8.5 (Closed) LER 249/96002-00 and 01: High Pressure Coolant Injection (HPCI) Inoperable Due to A Through-wall Hole in the Inlet Drain Pot Line to the Condenser Caused by Fl.ow Accelerated Corrosion. On March 5, 1996, the Unit 3 HPCI System was declared inoperable due to a through- wall hole in the HPCI inlet drain pot line. This line, which constitutes part of the HPCI system steam. boundary, drains condensate from the HPCI turbine steam supply line to the main condenser. Before this incident, the licensee had experienced repetitive problems with steam drain line through-wall leaks on both Unit 2 and Unit 3. In the LER, the licensee made commitments to replace the section of .tine where the leak had developed and to develop an inspection plan to evaluate the material condition of the other various sections of the HPCI inlet drain pot line to determine if there w,ere any additional instances of pipe wall thinning. The commitments were tracked by the licensee under NTS Items No. 249-180-96-00201 and 249-180-96-00202. Instead of replacing only the affected section of piping and developing an inspection plan which would have led to repetitive testing and repairs, the licensee decided to replace existing piping made of a different material. The original piping was made of A 106 carbon steel; the newly installed piping was made of A335 P11, a flow accelerated corrosion resistant steel containing 2.5 percent chromium-molybdenum. * No other instances of through-wall leakage have been noted. The licensee also replaced the Unit 3 HPCI inlet drain pot line during the ongoing Unit 3 refueling outage. This issue is closed..

. ' . E8.6 (Closed) LER 249/96022-00 and 01: Emergency Core Cooling System Suction Strainers Not in Accordance With Design Basis. On December 20, 1996, the licensee reported that the differential pressure (dp) across the low pressure emergency core cooling system (ECCS) pump suction strainers was larger than assumed. A 1983 vendor calculation that . evaluated the structural adequacy of the ECCS suggested that the dp across the ECCS suction strainers for both Unit 2 and Unit 3 was 5. 8 feet of water. This was not consistent with the UFSAR and original vendor documentation that identified the dp across the ECCS strainers as 1 foot of water. The licensee concluded that the cause of this event . was inadequate design of the original torus suction strainers. After initial identification of this issue, the licensee submitted an emergency license amendment request to take credit for containment overpressure for assuring adequate net positive suction head (NPSH) during an accident. The emergency license amendmentwas approved on January 29, 1997. A second license amendment request was submitted to restore the Ultimate Heat Sink and suppression pool temperatures to 95 degrees Fahrenheit to take advantage of additional containment over pressurization and to implement an updated containment analysis. The second license amendment request was approved on April 30, 1997. Because of the potential for the ECCS suction strainers to be blocked by debris, (Reference NRC Bulletin 96-03), the licensee replaced the original ECCS suction strainers for Unit 3 with a different design with larger strainers. This occurred during a 24

Unit 3 refueling outage (D3R14). Unit 2 ECCS suction strainers were scheduled to be replaced during Unit 2's refueling outage (D2R14). D2R14 was in progress throughout this inspection period. Additional corrective actions such as the reconstruction of the design basis for systems important to safety were being tracked by the licensee under NTS Items 237121960168 and. 237180960220101, respectively. Additional licensee commitments and corrective actions were addressed during the * NRC's Independent Safety Inspection completed on October 11, 1996, (Reference IR 96-201), and for this reason and considering the information mentioned above, both LERs are closed. IV. Plant Support Areas R4 Staff Knowledge and Performance in Radiation Protection (RP) R4.1 Refuel Floor Support a. Inspection Scope U1750) The inspectors observed the work of radiation protection personnel on the refueling floor. b. Observations and Findings Generally the support was good. The refueling floor was monitored by RP personnel. * The inspectors observed no problems with equipment control or control of contamination boundaries. One concern regarding support to the diver installing the main steam line plugs was identified .. A diver was used to install main steam line plugs on March 9, 1998. Radiation protection personnel briefed the diver on the hazards and set up remotely-monitored dosimetry for the diver. The inspectors observed an RP technician use a piece of tape from the contaminated floor to secure part of the diver's equipment to the back of the dive suit. The inspectors informed the technician monitoring the diver's remote dosimetry, and the technician concluded that since.the remote dosimetry did not show an increase, the tape was not a hazard. The technician monitoring the diver immediately questioned the radiation protection technician (R~T) who had used the tape, and the RPT was unconcerned. The RPT monitoring the diver remotely noted that no increase in the diver's dose rates occurred, and was also aware that the floor from which the tape had been removed was not highly contaminated. Although the inspectors immediately informed the radiation protection personnel monitoring the diver of their concern, and subsequently, radiation protection management, a PIF was not written for several days. 25

c. Conclusions Overall, the radiation protection control and monitoring of the refueling floor activities was good. The inspectors did note one poor practice of using contaminated tape to secure equipment on a diver. R4.2 Water Flow in Unit 2 Drywell a. Inspection Scope (71750) The inspectors assessed plant staff radiation worker practices during a tour of the Unit 2 drywall. b. Observations and Findings During a drywall tour on March 20, 1998, the* inspectors observed water running down the side of the biological shield wall. The.water was noticeable immediately upon entry into the drywall via the main equipment hatch. The water was running onto a cable tray and appeared to have been flowing for some time based upon the amount of water present. The water was following the cable tray run and being spread to other locations in the drywall. The inspectors immediately informed the radiation protection (RP) technician assigned to the drywell about the running water. The RP technician informed operations personnel about the overflow and a catch funnel was subsequently installed to contain

• and collect the water flow.

The inspectors identified several concerns with the situation described above. Though the water flow was readily apparent to personnel working in the area, no one had informed operators or outage management personnel about the steady water stream. Additionally, when the inspectors questioned the RP technician assigned, the technician did not know the origin of the leak or if the water was contaminated. However, the RP technician had also been splashed by the water. A catch bag was not installed to contain the water until the inspectors prompted plant personnel. Subsequent discussions between the inspectors, RP, and operations management personnel could identify no prior action taken until the NRC inspectors questioned the RP technician. Subsequently, the licensee determined the water to be uncontaminated water from testing of an HPCI system valve. The licensee reported that a catch basin had been placed under the HPCI valve around March 8, 1998, but it had been moved. The inspectors were also concerned .with the fact that a PIF was not written to capture and resolve potential damage to electrical equipment until subsequent prompting by the NRC. The licensee did not document the occurrence via the PIF process (PIF 01998-02358) until March 31, 1998. The licensee inspected equipment for damage on April 1, 1998, and no evidence of damage was found during that inspection. Criterion XVI, "Corrective Action," of 10 CFR Part 50, Appendix B, requires measures to be established to assure conditions adverse to quality are promptly identified and corrected. The failure to promptly identify and correct the water leaking into the drywall, a condition adverse to quality, is considered a violation of Criteria XVI. (VIO 50-237/98009-05(DRP}) 26

c. Conclusions Drywell perso*nnel demonstrated poor RP practices by not addressing a steady flow of water into the drywell until prompted by the NRC. Additionally, the licensee did not perform an inspection for potential equipment damage or document the awareness of this issue via the PIF process in a timely manner. R4.3 Refueling Outage Radworker/Radiological Controls (Unit 2) a. Inspection Scope (83729) The inspectors reviewed radiological controls implemented in the Unit 2 refueling outage and discussed specific practices with radworkers and various radiation protection (RP) technicians. The following activities were obs.erved in progress:

local leak rate testing for the Unit 2 high pressure core injection (HPCI) 2-2301-64/65 valve

control rod drive (CRD) system maintenance and inspection

reactor disassembly and refuel floor activities. The inspectors also made tours of the radiologically protected area (RPA), including the Unit 2 drywall .and Unit 2 HPCI Room. b. Observations and Findings During the initial start of D2R15 the inspectors identified several examples of poor. radworker practices. For example, while observing CRD maintenance activities the inspectors observed tools lying across the radiological boundary and workers inside and outside the radiological boundary reaching over the boundary. Additionally, the inspectors identified several instances where hoses that crossed a radiological boundary were not taped at the boundary. The following were examples of these instances:

Drain hose attached to the low pressure coolant injection (LPCI) heat exchanger in the east LPCI comer room and draining into the east LPCI room sump.

Drain hose attached to catch basin under hydraulic control unit (HCU) D-2 not taped at the boundary of the contaminated area.

Clear hoses used during HPCI local leak rate test (LLRT) not taped at radiological boundary.

Drain hose attached to instrument rack not taped at contamination boundary into the drain hole. In all cases, ttie inspectors promptly informed the radiation protection personnel and verified that the nonconforming conditions were corrected. A search of PIFs revealed other examples of untapped or improperly marked hoses (Reference PIFs No. 01998- 01652, -01879 08607). This practice was contrary to requirements stated in Dresden Administrative Procedure (OAP) 03-07, Rev. 09, "Control of the service air and domestic water systems and hoses for general station use." Step F.3.e. stated, "IF a RED, .WHITE, 27

.. OR CLEAR hose must cross the boundary between a contaminated area AND a non- contaminated area, THEN the hose must be secured at the boundary using Radioactive Materials Tape." Although the actions were contrary to procedures, no viol_ation was issued because the violation would be expected to be encompassed by licensee corrective actions to a recently issued violation for radiation workers not following this procedure (50-237/249-97028-03). Additionally, the inspectors noted that during the latter half of the outage this problem was less prevalent. The licensee identified examples in which poor planning and coordination resulted in unnecessary dose. For example, poor coordination of activities resulted in a craftsman receiving dose unnecessarily on March 13, 1998. On this date, the craftsman entered into the reactor water cleanup demineralizer high radiation pipeway to repair and/or replace a universal joint and to cycle a valve. When the valve was located, it was discovered that the reach rod needed to complete this task was not there. Personnel

• -*

who conducted the pre-walk of the job did not inform the craftsman-that-the .reach rod was not there, which resulted in the worker receiving 90 mrem *over an eight-minute __ , **

• -period_--,These unnecessary dose issues were identified by the.radiation1protection-{RP)

department, indicating some success in overall RP efforts to improve overall RP awareness. c. Conclusions Radiological controls and radiation worker practices were weak at the beginning of the Unit 2 refueling outage. However, the inspectors noted that as the Unit 2 refueling outage progressed, radiological control and radiological worker performance improved. The improvements were due to increased vigilance by the radiation protection technicians

• and an increased emphasis on discussing.good radiation worker practices during pre-job

"briefs and tailgate me~tings. . . . - .

• . .

. F1 Control of Fire Protection* Activities F1 .1 Fire Door lmproper1y Blocked Open a. Inspection Scope (64704) The inspectors monitored fire.protection activities during tours of the Unit 2 reactor building. b. Observations and Findings

• On March 5, 1998, during a tour of the Unit 2 east LPCI comer room and the Unit 2 HPCI

pump room the inspectors identified the Unit 2 HPCI room fire door blocked open by licensee maintenance personnel to allow an electrical test cable for HPCI maintenance to run under the door. The inspectors asked licensee personnel whether the work execution center (WEC) or the control room had been contacted to inform them that the fire door would be blocked open. The licensee personnel stated that they had not, but explained that there was a fire watch in the area for different on-going work activities for the HPCI system. Afterwards, the inspectors contacted the WEC and the outage control center operation manager (OCC) to see if they were aware of the fire door being blocked open. 28

The WEC and the OCC operation manager stated they were unaware of the door being blocked open. A search of PIFs revealed three other examples where fire doors were blocked open without WEC or the Safety and Property Loss Prevention (S&PLP) supervisor being aware of it. Dresden Station TS 6.8.a, required that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Appendix A of Regulatory Guide 1.33, Revision 2, February 1978, references Plant Fire Protection Program procedures. Both the DFPPs 4100-03, "Fire Watch Procedure," and 4175-01, "Fire Barrier Integrity and Maintenance," stated that: "All fire watches established onsite shall be administratively controlled by the Operations Department Work Execution Center. Concurrence of the S&PLP supervisor MUST be received prior to establishing OR terminating any fire watch." In this case neither had been done. The failure to contact the WEC and S&PLP supervisor before blocking open fire doors was a violation of both DFPP 4100 03 and 4175-01 (VIO 50-237/249-98009--04 (DRP)). c. Conclusion The inspectors identified one example where a fire door was blocked open without following the appropriate procedures. The door had been blocked open to allow a testing wire to be routed under the door. The licensee identified other examples of this type of issue. The safety significance of these issues was minor. However, the inspectors were concerned with the lack of attention to detail exhibited by the plant staff to fire protection controls. 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 April 3, 1998. On April 30, 1998, an additional exit meeting was conducted with members of licensee management to present a change in inspection results involving Violation 50-237/98009-05. 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 identified. 29

PARTIAL LIST OF PERSONS CONTACTED Licensee

• G. Abrell, Regulatory Assurance
• L. Aldrich, Rad Protection Manager
  • s. Barrett, OPS Manager
• T. Bezouska, Staff Assistant
• L. Coyle, Shift Operations Supervisor
• R. Freeman, Site Engineering Manager
• K. Hayes, Acting Maintenance Manager
• M. Heffley, Site Vice President
• L. Jordan, Training Supervisor
• M. Paulis, Work Control Outage Manager
• P. Stafford, Station Manager
• D. Winchester, Q&SA Manager
• B. Zank, Unit 1 OPS Manager
• K. Riemer, Senior Resident Inspector
• *B. Dickson, Resident Inspector
• D. Roth, Resident Inspector

Illinois Department of Nuclear Safety

• C. Settles
• Denotes those attending the meeting on April 3, 1998.

30

INSPECTION PROCEDURES USED IP 37550: Engineering IP 37551: Onsite Engineering IP 40500: * Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP 61726: Surveillance Observations IP 62707: Maintenance Observations IP 64704: Fire Protection Program IP 71707: Plant Operations IP 71750: Plant Support Activities IP 83729: Occupational Exposure During Extended Outages Opened 237-249/98009-01 237-249/98009-02 237-249/98009-03 237-249/98009-04 237/98009-05 Closed . 237:.249/98009-01 237-249/98009-02

• 237-249/98009-03

237/97014-00 237/96002-01. 237-249/95012-01 249/96009-01 237/96006-01 237/94005-03 237/97012-00 . 249/94013-00 237-249/95010-02 249/95007-01 & 02 249/96002-00 & 01 249/96022-00 & 01 ITEMS OPENED, CLOSED, AND DISCUSSED NCV NCV NCV VIO VIO Failure to Move Fuel in Accordance With Nuclear Component Transfer List Failure to Follow Guidance During Control Rod Single Notch Activities Procedural Inadequacies for Refueling Floor Activities Failure to Follow Fire Protection Program Procedures Failure to Identify and Correct Condition Adverse to Quality NCV Failure to Move Fuel in Accordance With Nuclear Component Transfer Lisf NCV. Failure to Follow Guidance During Control Rod Single Notch Activities NCV Procedural Inadequacies for Refueling Floor Activities LER * Inadvertent Exit From the Main Control Room due to Loss of Focus Resulted in Inadequate Control Room Staffing URI Inadequate closure inspection of Unit 2 Drywall IFI Operation of station blackout diesel generator console VIO Failure*to follow approved procedures and provide an onsite review of a special procedure for testing Electrical Bus 33-1 VIO Performance of work outside the scope of written and approved procedures during testing of feedwater system LER Manual Reactor Scram due to Loss of Instrument Air on April 30, 194 from 99 percent Power LER Inadvertent High Pressure Coolant Injection Isolation LER Missed TS Required Snubber Visual Inspection URI Safety significance of excessive leakage from MSIV Drain Valves 3-220-1 and 2 LER Leakage Limit Exceeded due to Valve Internal Damage Caused by Manual Operation MOV LER High Pressure Coolant Injection Inoperable Due to a Through-wall Hole in the Inlet Drain Pot Line to the Condenser Caused by Flow Accelerated Corrosion

LER Emergency Core Cooling System Suction Strainers Not in Accordance With Design Basis 31

Discussed 249/98001 LER 237/95007 LER 237/97006 LER 237/97014 LER 237/249-97013-01A VIO 237/249-960009-03 VIO 2371249-97019-02A 028, 02C VIO 249/96013-01 VIO 237/24997028-03 VIO HPCI Declared Inoperable SRO Absent from Control Room SRO Absent from Control Room SRO Absent from Control Room SRO Absent from Control Room Inadequate Closeout of U3 Drywell Performance of Work Outside Procedure Scope Leakage Limit Exceeded Rad Workers not Following Procedure 32

CRD DAP DES DFPP DGP DIS DMP DOA DOP DOS ECCS EMO. FCL FIN FMEA GSLO HLA HPCI IFI IMO IRM kV kW LCO LER LLRT LOCA LPCI MG MMD MRM MSIV NSO NTS occ PIF Q&SA QNE RP S&PLP SBO soc SDV SM SRO TS TSUP UFSAR LIST OF ACRONYMS USED Control Rod Drive Dresden Administrative Procedure Dresden Engineering Surveillance Dresden Fire Protection Procedures Dresden General Procedure Dresden Instrument Surveillance Dresden Maintenance Procedure Dresden Operating Abnormal Dresden Operations Procedure Dresden Operations Surveillance Emergency Core Cooling System Electrical Maintenance Department . Flow Control Line Fix-It-Now Foreign Material Exclusion Program Gland seal leakoff Heightened Level of Awareness High Pressure Coolant Injection Inspector Followup Item Instrument Maintenance Department

• Intermediate Range Monitors

Kilovolt. Kilowatt -Limiting Condition for Operation Licensee Event Report Local Leak Rate Test Loss Of Coolant Accident Low Pressure Coolant Injection Motor Generator Mechanical Maintenance Department Management Review Meetings Main Steam Line Isolation Nuclear Station Operator Nuclear Tracking System Operation Control Center Problem Identification Form Quality & Safety Assessment Qualified Nuclear Engineer Radiation Protection Safety & Loss Prevention Station Blackout Shut Down Cooling Scram Discharge Volume Shift Manager Station Room Operator Technical Specifications

• Technical Specification Upgrade Projects

Updated Final Safety Analysis Report 33 }}