IR 05000254/1998020
| ML20198N429 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 12/28/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20198N409 | List: |
| References | |
| 50-254-98-20, 50-265-98-20, NUDOCS 9901060126 | |
| Download: ML20198N429 (20) | |
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l U. S. NUCLEAR REGULATORY COMMISSION REGION lll
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- Docket Nos.:
50-254;50-265 l
License Nos.:
j-Report No.:
50-254/98020(DRP); 50-265/98020(DRP)
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Licensee:
Commonwealth Edison Company l
Facility:
Quad Cities Nuclear Power Station, Units 1 and 2 Location:
22710 206th Avenue North Cordova, IL 61242 Dates:
October 14 through December 1,1998 Inspectors:
C. Miller, Senior Resident inspector K. Walton, Resident inspector L. Collins, Resident inspector D. Roth, Resident inspector, Dresden R. Ganser, Illinois Department of Nuclear Safety Approved by:
Mark Ring, Chief Reactor Projects Branch 1
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l 9901060126 981220 PDR ADOCK 05000254
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EXECUTIVE SUMMARY Quad Cities Nuclear Power Station, Units 1 & 2
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NRC Inspection Report 50-254/98020(DRP); 50-265/98020(DRP)
This inspection included aspects of licensee ope. itions, engineering, maintenance, and plant support. The report covers a 6-week period of reCent inspection.
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Operations -
The operators did not fully understand the requirements on cooldown rates for the l
l reactor vessel metal prior to vessel flood up and subsequently had to lower vessel level to try to control cooldown rates (Section 01.2).
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A weakness was noted in logging potential cooldown issues. Station Nuclear Oversight
noted similar log keeping weaknesses (Section 01.2).
l Operators detected and responded appropriately to a leak in the Unit 2 electrohydraulic
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control system. The leak resulted in operators removing the turbine from service for a short time and reducing reactor power to approximately 30 percent of rated power, which was an unnecessary challenge to the operations staff. Licensee review indicated a maintenance error during a previous reassembly of the manifold may have caused the leak. Maintenance personnel repaired the leak. The licensee tracked the poor performance of the electrohydraulic control system using the maintenance rule and system health indicator programs (Section 01.3).
Operators continued to identify equipment configuration errors, such as a stand by gas
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treatment switch in the wrong position and a diesel generator valve not in the proper configuration. In one instance, the licensee did not establish the necessary administrative controls to address the Technical Specification surveillance requirement for equipment inoperability. This resulted in a non-cited violation.. The other
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configuration control events did not result in equipment inoperability. The licencee's planned corrective actions for each event appeared to be appropriate (Section 01.4).
Operators on the refuel bridge generally adhered to established practices for moving
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fuel. However, problems with operator control of system configuration occurred. In two
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instances, the same refuel bridge crew failed to place a fuel bundle in the proper coordinates in the spent fuel pool. This was an indication that corrective actions were not properly implemented by the crew. The licensee's subsequent corrective actions for
these events were appropriate. As a result, this was a non-cited violation (Section O4.1).
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The weekly Technical Specification surveillance test to verify the position of the reactor
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building to suppression chamber vacuum breakers was not adequate because only one I
of the two valves in each line was checked. Once the station identified the discrepancy, the valve positions were immediately verified, and the verification was added to the surveillance test program. This was a non-cited violation (Section 08.7).
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. Maintenance Licensee review of a forced turbine generator shutdown identified that a maintenance
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error during previous maintenance may have caused the leak on the electrohydraulic control system manifold to Number 4 control valve to occur (Section 01.3).
The work activities observed were being performed in accordance with procedures. The
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workers were usually knowledgeable and applied proper measures to prevent foreign materials from entering equipment. Outage work control was effective in ensuring timely completion of work requests. Poor understanding and coordination of reactor recirculation pump seal work by maintenance workers resulted in a spread of contamination and personnel contamination (Section M1.1).
The licensee addressed fcur snubber test failures appropriately. The licensee's long
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term corrective actions to address snubbers exhibiting a shortened service life were planned for the next Unit 1 refueling outage. The plans included the performance of a modification to replace mechanical snubbers with hydraude snubbers (Section M1.2).
The inspectors concluded that three different isolation and injection logic test
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procedures were appropriately reviev7d, and the tests were executed without noticeable errors (Section M4.1).
Plant Support One event involving poor maintenance worker knowledge that a line being cut contained
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reactor coolant water resulted in the spread of contamination and a personnel contamination (Section R1.1).
During a flushing evolution of the fire protection header, the turbine bearing deluge
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systems for both units and the Unit 2 recirculation motor generator set deluge system were actuated. The adjacent safety-related 4160 voltage switchgear (Bus 23-1) was also wetted. Subsequent walkdowns of the wetted areas and sampling of the turbine bearing oilindict.ted that equipment was not adversely affected by this event. The licensee attributed this event to inadequate procedure development by fire protection engineers. The licensee entered the event into their formal tracking system for the operations department to consider adding the item to operator training (Section F4.1),
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l, Operations r
Conduct of Operations i
01.1 Summary of Plant Status Operators maintained Unit 1 at full power until November 7,1998, when the unit was taken to cold shutdown in preparation for refueling outage (Q1R15). The unit remained in a refueling outage at the end of the period.
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- Operators maintained Unit 2 at full power operation during mest of the inspection period.
j On November 8,1998, operators removed the Unit 2 main turbine from operation to
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repair a turbine control system hydraulic oil leak. The unit was returned to operation less than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> later.
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01.2 Routine Operations a.
insoection Scope (71707]
l The inspectors conducted routine plant tours and frequent tours in the control room to
verify operator knowledge of plant status, compliance with procedures, log keeping, and
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~ problem identification. The inspectors also assessed the impact of plant material condition on operating performance.
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Observations and Findinas i
b.1.
Routine Ooerations Overall, the operators were attentive to their duties and conducted operations in a safe manner. Operators used good communication techniques. The operators appropriately referenced procedures, performed self-checks and peer-checks, and used good place keeping techniques. Some problems with configuration of equipment and improper I
authorization of work are discussed in Sections 01.4 and 04.1. A forced turbine and generator outage on Unit 2 was a plant challenge which was caused by a previous maintenance error and handled well by the operators. This is discussed in Section 01.3.
During routine plant tours, the inspectors noted some issues that should have been
- identified by non-licensed operators, engineers or managers during routine rounds and plant tours. Housekeeping problems, scaffolding erected in the path of emergency lighting, and watertight doors to emergency core cooling rooms not remaining intact were some issues which did not pose significant safety problems, but indicated less than adequate attention to overall plant condition.
b.2.
Potential Excessive Rate of Cooldown During shutdown for the Unit i refueling outage on November 7,1998, the licensee L
failed to maintain the cooldown rate of the reactor vessel metal under 100*F/hr. This l
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occurred when the operators deliberately raised the water in the vessel to above the i
vessel flange area to speed cooling of the vessel flange. This action was taken in order to minimize plant cooldown time for a short refueling outage, and was not a routine practice of past refueling outages. One metal temperature thermocouple showed a rapid drop from 361*F. The operators lowered reactor vessel level to try to slow the temperature drop, but the temperature still decreased from 361*F to 258'F in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
The licensee documented the potential problem !n Problem Identification Form Q1998-04847..
Technical Specificatio7 3.6.K.2.a. required that, "The reactor vessel meta! temperature
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and pressure shall be maintained within the Acceptable Regions as shown of Figure 3.6.K-4." Figure 3.6.K-4 showed the " acceptable region" as a function of reactor
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vessel metal temperature and pressure in the reactor vessel top head. The " acceptable region" had a footnote that stated, " Temperature Change Rate [is less than or equal to]
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100'F/hr." Paragraph 3.6.K.2.b. of the Technical Specifications stated that "the rate of change of the primary system coolant temperature shall be [less than or equal to]
100*F/hr." Section 5.3.2.1 of the Updated Final Safety Analysis Report referred to a similar figure and stated, "The curve provides the minimum reactor vessel metal temperatures based on the most limiting vessel stress. The maximum heatup/cooldown rate of 100*F/hr is applicable."
The inspectors found that licensee engineers and operators considered the 100*F
. temperature limit to be based on water, not metal, temperatures. In the problem identification form, the shift engineer stated that the Technical Specifications were met because the coolant temperature remained within a 120 to 140*F band. The shift
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engineer wrote that the Technical Specifications only inferred (vice required) that the 100*F/hr limit existed for vessel metal temperatures. The problem identification form did not discuss any statements from the updated final safety analysis report. Licensee engineers indicated that the change in water temperature was the best indicator of
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cooldown rate in this situation.
The inspectors also found that Section 3.9.1.1.1 of the Updated Final Safety Analysis Report considered that batch additions of feedwater during plant cooldown was not applicable for either Unit 1 or Unit 2. This consideration was used to predict fatigue cycles for the reactor pressure vessel fatigue evaluation. Engineers and operators interviewed at the end of the inspection period had not considered the additional fatigue on the vessel due to this change in refueling outage cooldown practice.
The licensee assigned Nuclear Tracking System item 25420198CAQO2841 to " Evaluate cooldown of [ reactor pressure vessel) flange /shell and metal temperature cooldown" with a due date of November 30,1998. Results of this action were not complete on November 30,1998. The inspectors scheduled a meeting to review the licensee's evaluation of the cooldown event. The resolution of the following issues will be tracked
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adequacy of procedure for cooldown using vessel flood up,
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evaluation of Technical Specification 3.6 compliance,
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adequacy of engineering review of vessel fatigue issues related to plant
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cooldown, and the number of cycles nf this type which have occurred on the reactor vessel.
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The circumstances that led to the problem indicated a lack of preparation for changes in
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operational practice. Since the operators were uncertain about how to apply the cooldown rate limit, better procedural guidance and a final interpretation of the applicability of the cooldown rate limit to the reactor vessel metal temperature should have been developed prior to vessel flood up. The inspectors were concerned that the l
l actions taken by the operators on November 7 may have resulted in an unplanned entry l
into a limiting condition for operation, b.3.
Loa Keepina The inspectors' review of the control room logs showed no information was recorded to document the potential excessive cooldown rate that occurred on November 7,1998.
Since there was a potential to be in a limiting condition for operation, and since the operating crew took significant actions to try to prevent the cooldown, the information should have been recorded. Failure to record this type of event could have led to an inaccurate assessment of pressure vessel fatigue over the life of the plant.
On November 11,1998, the licensee's Nuclear Oversight independently identified similar instances of weak and missing log entries. The issues were documented in Problem identification Form Q1998-04927, " Nuclear Oversight Identified that Operations' Logs Lack Details on Problems." The inspectors considered the lack of an entry regarding the cooldown rate to be similar to the issues identified by nuclear oversight.
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Oonclusions Preparations for a change to vessel cooldown methods were weak. The operators did not fully understand the requirements on cooldown rates for the reactor vessel metal before challenging the cooldown limits. A new method of early vessel flood up was not
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accompanied by appropriate procedural guidance and engineering evaluation.
A weakness was noted in logging significant issues such as vessel cooldown cycles.
The station's Nuclear Oversight organization noted similar log keeping weaknesses.
01.3 Unit 2 Generator Outaae Due to Turbine System Oil Leak a.
Insoection Scope (71707)
The inspectors reviewed logs and spoke to operators regarding a turbine electrohydraulic oil leak and observed control room operators return Unit 2 to service.
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Observations and Findinon On November 8,1998, an equipment operator identified a level decrease in the Unit 2 electrohydraulic control system reservoir indicating a leak in the system. Operators later identified electrohydraulic oil leaking from the Number 4 control valve manifold.
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Maintenance personnel unsuccessfully attempted to tighten the manifold with the turbine operating. Control room operators reduced reactor power to about 30 percent of rated power and removed the turbine from service to effect repairs. Maintenance personnel replaced the manifold on the control valve. Less than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after removing the turbine from service, control room operators synchronized the Unit 2 turbine generator to the grid.
The operators appropriately responded to the condition, but maneuvering the unit presented a challenge to the operating staff. The licensee's system health indicators program had previously rated the electrohydraulic control system as a problem system due to the number of plant deratings the system had caused, the number of backlogged work requests written against the system and the system not meeting raaintenance rule performance (10 CFR 50.65(a)(2)] criteria. The licensee continued to in /estigate the cause of the event and tentatively identified a possible error during a previous maintenance activity which could have caused the leak to occur.
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Conclusions Operators detected and responded appropriately to a leak in the Unit 2 electrohydraulic control system. The leak resulted in operators removing the turbine from service for a short time and reducing power to approximately 30 percent of rated power, which was an unnecessary challenge to the operations staff. The licensee tracked the poor system performance in the maintenance rule and system health indicator programs. Licensee review indicated a maintenance error during a previous reassembly of the manifold may have caused the leak to occur.
01.4 Eauioment Confiauration Problems a.
Insoection Scope (71707)
The inspectors reviewed control room logs, problem identification forms, prompt investigation reports, and interviewed plant personnel concerning problems related to plant operations.
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Observations and Findinas b.1 Imoroper Authorization of Maintenance on Primary Containment Isolation Valve On October 13,1998, operators authorized repair of a primary containment purge isolation valve (1-1601-21). Operations personnel did not review the work package to determine the extent of work and did not consider the valve to be inoperable for the activity. On October 22, operators identified that maintenance personnel tightened packing on valve 1-1601-21, and the valve had not been stroke time tested as required by Technical Specification 4.7.D.1. The licensee later stroke time tested the valve satisfactorily.
The licensee attributed the cause of this event to misidentification of the activity when it was added to the schedule and inadequate determination of the work scope when
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authorized by operators. Corrective actions included disciplinary actions, and plans to include procedure changes and training to operations personnel. The licensee planned to have the corrective actions implemented by March 11,1999; the inspectors considered this time frame appropriate.
Valve 1-160121 remained in its closed position. However, Technical Specification 4.7.D.1 required the licensee to declare the valve inoperable until performance of a cycling test and verification of isolation time. This was a violation of Technical Specification 4.7.D.1 since the valve was still considered operable without satisfactory completion of a stroke time test after compietion of the maintenance activity.
This non-repetitive, licensee-identified, and corrected violation is being treated as a Non-Cited Violation (50/254-98020-02; 50-265/98020-02), consistent with Section Vll.B.1 of the NRC Enforcement Policy.
b.2 Standby Gas Treatment Out-of-Service Problem On October 12,1998, during a turnover, an oncoming senior reactor operator identified the standby gas treatment system was in an abnormallineup. After performance of an out-of-service tagout on the "B" system which left the "B" system control switch in "off," a control switch for the "A" system was left in the " standby" mode. The oncoming senior reactor operator recognized through past performance of surveillance tests and training, that this condition was not desirable since the standby gas treatment "A" train would not start immediately after an initiation signal was present. The "A" system would start after a delay of 25 seconds after the initiation signal was present. If the "A" train control switch was positioned to " primary," the system would have responded immediately.
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The licensee previously evaluated this condition as not affecting operability of the system. This condition was identified about 4 minutes after hanging the out-of-service tagout. The licensee documented and investigated this condition on Problem identification Form Q1998-04366. The licensee evaluated this condition as not being significant with respect to the amount of radioactive material released after an accident.
Licensee corrective actions included adding a statement of checking standby gas treatment switch positions each time an electronic out-of-service would be implemented for the system.
The inspectors considered this not to be a violation of Technical Specifications or plant procedures and noted the standby gas treatment was able to fulfill the design function.
However, this condition reflected a weakness in establishing the proper plant conditions necessary to support the out-of-service.
b.3 Valve Found Out of Position An equipment operator performing rounds on the shared emergency diesel generator identified that valve 6699-147 (air box drain to oil separator valve) was not lockwired.
The valve's position was checked and identified as being full open. The system valve lineup required the valve to be throttled 3 turns open from full closed and lockwired. The operator and supervisor returned the valve to the proper position and documented the discrepancy on a Problem IdentificatDn Form Q1998-04871. After further investigation,
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the licensee identified a discrepancy between the valve's position as stated on the lineup
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sheets and the system drawings.
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The licensee could not determine how or when the valve was mispositioned. Corrective actions planned included changing the valve position to shut and having operators on rounds periodically open the valve to check for leakage. The valve being out of position did not affect operability of the emergency diesel generator.
Quad Cities Operating Procedure 6600-04, " Diesel Generator % Preparation for Standby Operation," Revision 14, Step F.2.i and Quad Operating Mechanical (Quad Cities Operations Manual %-6600-01), Revision 5 required valve %-6600-147 to be throttled 3 turns from full open. The valve was discovered to be full open. This was a violation of Technical Specification 6.8.A.1 and Regulatory Guide 1.33, Appendix A, Section 4.w.a, Electrical System-Emergency Power Sources.. This violation constitutes
a violation of minor significance and is not subject to formal enforcement action.
However, the configuration control problem with an emergency diesel generator valve was a concern because previous mispositioning of emergency diesel generator valves had occurred, and because the cause of the problem was not identified.
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Conclusions
Operators continued to identify equipment configuration errors such as a stand by gas treatment switch in the wrong position and a diesel generator valve not in the proper configuration. In general, the causes were associated with human error. in one instance, the licensee did not establish the necessary administrative controls to address the Technical Specification surveillance requirement for equipment inoperability. This resulted in a non-cited violation of Technical Specifications. The other configuration control events did not result in equipment inoperability. The licensee's corrective actions for each event appeared to be appropriate.
Operator Knowledge and Performance 04.1 Two Fuel Misoositionina Events j
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Lnstection Scooe (71707)
The inspectors witnessed core off-load and core reload operations from the refuel bridge. The inspectors observed the use of procedures and verifications to ensure the fuel bundles were appropriately handled, b.
Observations
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On November 11,1998, during defueling of Unit 1, a fuel handling crew placed a fuel
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bundle in the incorrect position in the refuel pool. The inspectors noted the fuel handling
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bridge was on the proper coordinates for the fuel move and was independently verified to be in the proper position. However, the bundle was placed one cell out of position.
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The condition was detected after the fuel assembly was unlatched and the bridge was moving towards the core for the next fuel move. Operators placed the bundle back in the correct location.
l A subsequent investigation determined the coordinates marked on the refuel floor and refuel bridge could not be used to positively verify the bridge was in the correct pool location. Corrective actions included verifying the fuel handling bridge was in the correct location using floor coordinates and verifying the fuel enters into the proper storage cell by counting cells and comparing this to a spent fuel pool matrix. Other corrective
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actions included disciplinary actions for the affected crew and adding a second verifier to ensure final fuel position in the spent fuel pool. All refuel handlers received additional training on this event.
On November 12,1998, the same fuel handling crew placed a fuel asserrbly in the wrong location in the spent fuel pool. The crew failed to implement the corrective actions from the previous event properly. This event occurred when the crew miscounted the spent fuel cells and failed to ensure the fuel handling bridge was in the
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proper position by floor coordinates. The crew discovered the condition after the fuel
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bundle was unlatched. A subsequent investigation determined the crew was not.
focused on the job (inattention to detail) or incorrectly interpreted what to use for
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verification of location, immediate corrective actions included removin0 the crew from
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duty, and adding a third independent fuel position verifier. The licensee determined there was little safety significance to either mispositioning event. The inspectors noted that the design of the spent fuel pool allowed any bundle to be placed in any position of
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the pool. However, the misplaced bundles were indicators that future fuel mispositionings were possible, and increased the possibility that a fuel bundle could be j
improperly located from the spent fuel pool into the reactor core.
Quad Cities Test Procedure 0941-04, " Preparation and Use of Nuclear Component l
Transfer Lists," Step F.5, required changes to the Nuclear Component Transfer Lists be made by a nuclear engineer in advance. Since this core alteration did not receive advanced approval, the inspectors considered this to be a violation of Technical Specification 6.8.A.1., and Regulatory Guide 1.33, Appendix A, Section 2.1, Refueling and Core Alteration Procedures. These non-repetitive, licensee-identified and corrected violations are considered a Non-Cited Violation (50/254-98020-03; 50-265/98020-03),
consistent with Section Vll.B.1 of the NRC Enforcement Policy."
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Conclusions The inspectors concluded that operators on the refuel bridge generally adhered to established practices for moving fuel. However, problems with operator control of system configuration occurred. In two instances, the same refuel bridge crew failed to place a fuel bundle in the proper coordinates in the spent fuel pool. These events were an indication that corrective actions were not effectively implemented by the crew and a violation of regulatory requirements. The licensee's corrective actions for these events were appropriate,
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Miscellaneous Operations issues (92700)
08.1 - (Closed) Violation 50-254/97014-05: 50-265/97014-05: Design Basis Information.
Design Basis Information for the 250 Vdc battery was not correctly translated into procedures and specifications. There were two examples. The first example was that a generic value of 60'F was used in the upgraded Technical Specifications instead of the design basis temperature of 65'F. The second issue was that the battery load profile
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t was incorrectly revised when one load was removed. Instead of the lower profile, a more conservative scenario of battery loads should have been applied. The inspector reviewed the licensee's commitments to revise procedures, revise the Technical Specifications, and to provide training to the engineering staff. The actions specified had been taken and a Technical Specification revision was approved and near -
l-implementation. This item is closed.
08.2 (Closed) Violation 50-254/97028-01: Emergency Diesel Generator Cooling Water Valve
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Mispositioned. The licensee response and corrective actions for Licensee Event Report 50-254/98003-00 were reviewed. See the paragraph for Licensee Event Report 50-254/98003 in this report. This item is closed.
08.3 (Closed) Violation 50-254/97028-03: Ventilation Fan Removed From Service Without Completing a Safety Evaluation. The cause of this was attributed to poor performance
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by personnel. The performance issues were resolved with the individuals involved and the out-of-service review procedure was revised to clarify the expectations for the review of active out-of-services. This item is closed.
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08.4 (Closed) Licensee Event Report 50-254/98003-00: Technical Specification Limiting Condition for Operation Was Exceeded When Both Standby Gas Treatment Subsystems Were Inoperable. This was the result of mispositioning the Unit 2 emergency diesel generator cooling water control valve following maintenance.
Corrective actions taken were appropriate < The inspector verified that procedure revisions were made and training of operators was documented. This item is closed.
l 08.5 (Closed) Licensee Event Report 50-254/98024: Maintenance on Primary Containment Isolation Valve Without Declaration of Inoperability. This issue was discussed in Section 01.4.b.1. This Licensee Event Report is closed.
08.6 (Closed) Violation 50-254/97006-03: 50-265/97006-03: Failure to identify Quality Records and Establish Retention Schedules. The master record retention schedule was out-of-date, did not identify which documents were quality records, and did not specify retention periods for records. The inspectors reviewed a current paper copy of the l
master retention schedule. The living document was maintained on the licensee's computer system. The inspectors noted that many improvements had been made
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including an updated list of required records and a designated retention period.
Administrative procedures were also changed to require a review of the retention schedule every 6 months. These corrective actions were appropriate and resulted in an improved master record retention schedule. This violation is closed.
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08.7 (Closed) Licensee Event Report 50-254/98021: Weekly Position Verification of Reactor
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Building to Suppression Chamber Check Valve Vacuum Breakers Was Not Performed.
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The licensee concluded that Technical Specification surveillance requirement 4.7.F had not been met because only the position of the air-operated valve had been checked, not the check valve position. The question of whether the check valve position siso needed to be verified to satisfy the surveillance had been identified by the station previously during review of Technical Specification surveillance requirements, but the station incorrectly concluded that the surveillance was satisfied by only verifying the position of the air-operated valve. Upon discovery, the check valves were verified closed and a procedure developed to verify the valve positions weekly. Although a number of missed
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surveillance tests were previously identified, the inspectors considered the cause of this violation to be different from previous violations and therefore was not likely to have been prevented through previous corrective actions. Additionally, the licensee's corrective actions included a review of all other questions raised during previous reviews
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of surveillance requirements. The failure to perform Technical Specification Surveillance Requirement 4.7.F was considered to be a violation. This non-repetitive, licensee-identified, and corrected violation is being treated as a Non-Cited
Violation (50-254/98020-04; 50-265/98020-04), consistent with Section Vll.B.1 of the NRC Enforcement Policy. This Licensee Event Report is closed.
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II, Maintenance M1 Conduct of Maintenance M1.1 General Comments a.
Inspection Scope (62707. 61726)
The inspectors reviewed outage and non-outage work in progress during routine plant tours. The inspectors assessed the worker knowledge of the maintenance, use of
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procedures, and control of work area.
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Observations and Fir.dinas Maintenance work observed by the inspectors was performed according to procedure.
Workers used the correct procedures and work requests, were knowledgeable of the jobs and activities, and performed the tasks correctly. The inspectors usually noted good control of work areas through use of covers to prevent foreign materials, asbestos, and other material from entering equipment. The inspectors noted that the drywellin particular was thoroughly covered. However, one maintenance repair job on a reactor recirculation pump seal involved poor job planning, incomplete knowledge of the seat lines by the technicians and differing understanding of tne job scope by maintenance and radiation protection personnel. Spread of contamination and a personnel contamination resulted as described in Section R1.1.
The outage control center closely tracked the progress of outage-related work. The outage generally followed the schedule, indicating good planning. Communication
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between maintenance, engineering, operators, and radiation protection personnel contributed to timely completion of work requests.
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Conclusions The work activities observed were being performed in accordance with procedures. The
workers were usually knowledgeable and applied proper measures to prevent foreign materials from entering equipment. Outage work control was effective in ensuring timely completion of work requests. Poor understanding and coordination of reactor recirculation pump seal work by maintenance workers resulted in a spread of contamination and a personnel contamination.
M1.2 Snubber Failures a.
Irisoection Scope The inspectors reviewed the results of required snubber testing in light of the requirements of Technical Specification 3/4.8.F.
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Observations and Findinas The Unit 1 snubber inspection scope included a Technical Specification required 10 percent sample consisting of 12 snubbers and 8 additional snubbers as part of the required service life monitoring program. All snubbers included in the 10 percent sample passed the functional test. However,4 of the 8 snubbers under the additional scope tested for the service life monitoring program failed and were replaced.
Through discussions with the engineers and a review of past test results, the inspectors fowa that the additional snubbers were selected for testing based on past failure
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history. All of these snubbers were located in the drywell and connected to high vibration systems. The licensee's long term plans were to replace these mechanical l
snubbers with hydraulic snubbers. Since the licensee could not perform a like-for-like replacement of mechanical snubbers with hydraulic snubbers, replacement mechanical -
l snubbers were installed during the refueling outage. The licensee's long term corrective actions were to perform a modification and replace the mechanical snubbers with hydraulic snubbers during the next Unit 1 refueling outage.
Technical Specification 4.8 required a sample expansion if a failure occurred during the testing of the 10 percent sample. The inspectors reviewed the requirement to see if a sample expansion was required as a result of the failures associated with the service life
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monitoring program. The inspectors concluded that a sample expansion was not required and that the service life program, which was implemented to ensure that the service life was not exceeded between surveillance inspections, was properly focused on snubbers with a shortened service life. Planned corrective actions to modify the snubbers appeared to be an appropriate long term solution.
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Conclusion The licensee addressed four snubber test failures appropriately. The licensee's long term corrective actions to address snubbers exhibiting a shortened service life were l
planned for the next Unit i refueling outage. The plans included the nerformance of a modification to replace mechanical snubbers with hydraulic snubbers.
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M4 Maintenance Staff Knowledge and Performance M4.1 Work Reouests and Surveillance Observations I
a.
Inspection Scope (61726. 62707)
The inspectors attended licensee procedure review boards and test briefings and observed portions of the Quad Cities Operating Surveillance (QCOS) logic tests listed below.
OCOS 1300-23 Reactor Coolant Isolation Cooling Logic Test QCOS 1600-27 Refueling Outage Primary Containment isolation Group 1 Isolation Test QCOS 2300-29 High Pressure Coolant injection Logic Test b.
Observations and Findinas Previously, the logic tests listed above were performed with the unit shut down. In an attempt to reduce outage time, the licensee planned to perform the logic tests with the unit operating. The licensee reviewed the logic tests to ensure the tests could be performed without causing a transient on the operating unit. However, other delays resulted in only QCOS 1600-27 and QCOS 2300-29 logic tests being performed with the unit operating.
The inspectors observed portions of the above logic tests. The tests did not cause transients on the unit in either the operating mode or shutdown mode. The maintenance personnel and test directors were knowledgeable of the relays and electrical drawings of the systems. The briefings and tests were conducted with all required personnel in attendance. The test directors and maintenance personnel were cautious of landing and lifting leads from the proper termination points. The inspectors noted good use of independent verifications and peer checks to ensure error-free activities. No errors were observed, and good communications between the control room operators and test personnel in the auxiliary electric room were practiced. Deficient conditions identified during testing were properly addressed.
c.
Conclusions The inspectors concluded the logic test procedures were appropriately reviewed and the tests were executed with no observed errors.
l lil. Enaineerina E8 Miscellaneous Engineering issues (92902)
E8.1 (Closed) Violation 50-254/97006-07: 50-265/97006-07: Failure to Evaluate Degraded Safety-Related Room Cooler. In October 1996, the licensee identified a degraded performance trend with the Unit 2 "B" Core Spray Room Cooler since June 1996. This condition was not properly trended by engineering and not analyzed for operability. In March 1997, the licensee inspected and identified significant fouling on the service water side of the room cooler. Operations then considered the room coolerinoperable since June 1996. The licensee cleaned the cooler and developed an administrative procedure to ensure proper trending of room cooler performance. The inspectors reviewed the J
administrative procedure, and interviewed cognizant personnel. In addition to better trending, the licensee started to install flow meters to certain safety-related room coolers in order to better determine cooler performance. This item is closed.
E8.2 (Closed) Licensee Event Report 50-254/94002. Revision 1: Excessive Cycling of Control Room Ventilation Refrigeration Control Unit Compressor. The inspectors noted a deviation from the commitments in revision 0 of this Licensee Event Report and a Notice of Deviation was issued in Inspection Report 50-254/97014; 50-265/97014. This revision was issued to retract the previous commitment to install a hot gas bypass system to eliminate the cycling problem and to make a new commitment to relocate the temperature sensor in the system. The inspectors verified that the temperature sensor j
was installed. This Licensee Event Report is closed.
E8.3 (Closed) Deviation 50-254/97014-08: 50-265/97014-08: Hot Gas Bypass System Not
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Installed. In reviewing Licensee Event Report 50-254/94002, the inspectors noted that the hot gas bypass system had not been installed as planned by the licensee. The licensee had changed plans and intended to relocate a temperature sensor. This appeared to be a reasonable corrective action alternative, but the change had not been communicated to the NRC A revised Licensee Event Report was submitted, and the i
modification was completed. This Deviation is closed.
E8.4 (Closed) Licensee Event Report 50-254/97012. Revision 0 and Revision 1: The Refuel Bridge Monorail Hoist Could Perform Core Alterations Without an interlock Actuation.
After a design change to the refuel bridges for Unit 1 and Unit 2 in 1986, refuel bridge position interlock trip plates were relocated such that the monorail hoist could be located over the reactor core with no control rod block. Upon discovery of the condition, the licensee used administrative controls to prevent fuel movement with the monorail hoist and initiated a design change to reposition the interlock trip plates. The Unit 1 design change was completed in October 1998 under Work Request 980026275. Unit 2 was not yet completed, but the design had been issued and the work was scheduled for early 1999. This Licensee Event Report is closed.
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IV. Plant Support l
R1 Radiological Protection and Chemistry Controls
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R1.1 General Comments (71750)
During routine inspections in radiologically controlled areas, the inspectors assessed the performance of the licensee. Overall, the licensee's radiation protection staff enforced radiological control standards. The licensee used personnel functioning as " greeters" to assure that workers entering the radiologically controlled area were aware of dose rates l
and radiation worker protection requirements during some portions of the refueling outage.
l A number of low significance radiation worker weaknesses led to personnel contaminations which exceeded the outage goal of less than 100 by about 50 contaminations. Toward the beginning of the outage, the licensee documented several personnel contamination events each day. One event near the end of the outage resulted in contamination to a maintenance technician working on a reactor i
recirculation pump seal and a spread of contamination in the drywell. Maintenance and health physics technicians falsely assumed the contents of a line to be cut was non-contaminated cooling water. When the line was cut, reactor coolant water contaminated a worker and the surrounding area.
To reduce the number of personnel contaminations, the licensee issued additional requirements for protective clothing. For example, ski-mask type protective clothing was issued to a group that had four facial contaminations in 1 day. Additional protective clothing requirements for the drywell were required. The inspectors concluded that the licensee implemented appropriate corrective actions to the contamination events.
The outage dose goal of about 294 person-rem was exceeded. Actual outage dose was about 410 person-rem. This was due in part to about 117 person-rem used for repairs
on reactor recirculation piping cracks.
F4 Fire Protection Staff Knowledge and Performance F4.1 Inadvertent Actuation of Fire Protection Deluae (71707)
The inspectors reviewed licensee documentation involving an inadvertent deluge on operating equipment. On November 1,1998, operators used an interim procedure to flush two fire protection valves in preparation for using the valves as out-of-service boundary valves. The interim procedure cautioned that deluge systems could be l
inadvertently actuated by the procedure. During the flushing evolution, the turbine bearing deluge systems for both units and the Unit 2 recirculation motor generator set deluge system were actuated. The adjacent safety-related 4160 voltage switchgear
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I (Bus 23-1) was also wetted. The licensee documented and investigated this event on Problem Identification Form Q1998-04722. Subsequent walkdowns of the wetted areas and sampling of the turbine bearing oilindicated that equipment was not adversely affected by this event. However, this event had the potential to adversely affect safety-
related equipment. The licensee attributed this event to inadequate procedure development by fire protection engineers. The licensee entered the event into their formal tracking system for the operations department to consider adding the item to operator training. The inspectors will monitor the effectiveness of the licensee's corrective actions during core inspections of the conduct of operations.
V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management ht the conclusion of the inspection on December 1,1998. The licensee acknowledged the findings presented.
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l INSPECTION PROCEDURES USED IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 71707:
Plant Operations IP 92700:
Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor Facilities
. IP 92902:
Follow-up - Engineering ITEMS OPENED, CLOSED, AND DISCUSSED Opened'
50-254/98020-01 URI Cooldown Rate 50-254/98020-02;50-265/98020-02 NCV Inoperable Containment isolation Valve 50-254/98020-03;50-265/98020-03 NCV Fuel Bundles Mispositioned 50-254/98020-04;50-265/98020-04 NCV Missed Vacuum Breaker Surveillance Closed 50-254/98020-02;50-265/98020-02 NCV Inoperable Containment isolation Valve
'50-254/98020-03;50-265/98020-03 NCV Fuel Bundles Mispositioned-50-254/98020-04;50-265/98020-04 NCV Missed Vacuum Breaker Surveiliance 50-254/97014-05; 50-265/97014-05 VIO Design Basis Information 50-254/97028-01 VIO Emergency Diesel Generator Cooling Water Valve Mispositioned
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50-254/97028-03 VIO Ventilation Fan Removed From Service Without Completing a Safety Evaluation 50-254/98003-00 LER TS LCO Exceeded (SBGT)
50-254/98024 LER Maintenance on Primary Containment isolation Valve Without
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Declaration of inoperability 50-254/97006-03; 50-265/97006-03 VIO Failure to identify Quality Records and Establish Retention Schedules 50-254/98021 LER Weekly Position Verification of y
Reactor Building to Suppression Chamber Check Valve Vacuum Breakers Was Not Performed 50-254/97006-O'7; 50-265/97006-07 VIO Failure to Evaluate Degraded Safety-Related Room Cooler is
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50-254/94002, Revision 1 LER Excessive Cycling of Control Room Ventilation Refrigeration Control Unit Compressor 50-254/97014 08;50-265/97014-08 DEV Hot Gas Bypass System Not Installed 50-254/97012, Revision 0 and Revision 1 LER The Refuel Bridge Monorail Hoist Could Perform Core Alterations Without an Interlock Actuation
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LIST OF ACRONYMS AND INITIALISMS USED CFR Code of Federal Regulations Comed Commonwealth Edison Company DEV Deviation GL Generic Letter IDNS lilinois Department of Nuclear Safety IFl Inspection Follow-up item IP Inspection Proecedure LER Licensee Event Report NCV Non-Cited Violation PDR Public Document Room RG Regulatory Guide
- URI Unresolved item
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Vdc Volts Direct Current VIO Violation
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