IR 05000461/1989014
| ML20244E440 | |
| Person / Time | |
|---|---|
| Site: | Clinton  |
| Issue date: | 06/08/1989 |
| From: | Ring M Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20244E428 | List: |
| References | |
| 50-461-89-14, GL-88-11, GL-88-14, IEB-79-18, NUDOCS 8906200341 | |
| Download: ML20244E440 (30) | |
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION III
Report No. 50-461/89014(DRP)
I Docket No. 50-461 License No NPF-62 Licensee:
Illinois Power Company 500 South 27th Street Decatur, IL 62525 Facility Name:
Clinton Power Station Inspection At:
Clinton Site, Clinton, IL
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Inspection Conducted: March 16, 1989, through May 30, 1989
Inspectors:
P. Hiland l
S. Ray A. Gautam
Approved By:
M. A. Ring, Chie
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Reactor Projects Section 3B Date
Inspection Summary Ins)ection on March 16, 1989, through May 30, 1989 (Report No. 50-461/89014 (DR)))
Areas Inspected:
Routine, unannounced safety inspection by the resident inspectors of licensee action on previous inspection findings; regional requests; NRC compliance bulletin and generic letter followup; operational safety verification; monthly maintenance observation; monthly surveillance observation; onsite followup of events at operbting reactors; environmental qualification of electrical equipment; and Temporary Instruction 2515/100.
Results: Of the nine areas inspected, five violations ar.d an apparent violation were identified. One was in the area of followup of previous inspection findings concerning improper mounting of the Division III Diesel Generator Service Water Heat Exchanger (Paragraph 2d). Three were adequately control the Service Air Sy!, tem (Paragraph Sc)g failure to in the area of operational safety verification concernin
, failure to bypass thermal overload protectior, on active safety-related valves (Paragraph 5d),
and failure to control locked valves (Paragraph 5f). The remaining violation was in the area of onsite followup of events at operating reactors concerning j
inadequate procedures for control of plant testing (Paragraph 8b(1)). One apparent violation of 10 CFR 50.49 (with several exantples) concerning failure I
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toLqualify electrical equipment important to safety for postulated harsh
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environments ~during an accident was also identified (Paragraph 9).
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e addition, one." licensee ' identified" violation was discussed in the area of
operational safety verification concerning inadequatr testing of Average Power I
Range Monitors.. One unresolved' item was identified in the area of operational safety verification concerning missing conduit scals in secondary containmen.
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-penetrations.
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.4-DETAILS g
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Personnel Contacted Illinois Power Company (IP)
W. Kelley President
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W. Gerstner, Executive Vice President
- D, Hall, Vice President - Nuclear J. Perry, Assistant Vice President
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- 'K. Baker, Supervisor - I&E Interface
- R. Campbell, Manager - Quality Assurance
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- J. Cook, Manager - Nuclear Planning and Support
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R. Freeman, Manager - Nuclear Station Engineering Department
- #D.. fioltzcher, Acting Manager - Licensing & Safety
- J. Miller, Manager - Scheduling & Outage Management R. Schultz, Director - Planning'& Programming
- J. Weaver, Director - Licensing
- J. Wilson, Manager - Clinton Power Station
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- R. Wyatt, Manager - Nuclear Training Soyland J. Greenwood, Manager - Power Supply Nuclear Regulatory Comission R. Cooper, Chief. Engineering Branch, Region III
- P. Hiland, Senior Resident Inspector, Clinton
- H. Miller, Director, Division of Reactor Safety, Region III
- fS.~ Ray, Resident Inspector, Clinten
- M. Ring, Chief, Division of Reactor Projects Region III
- Denotes those attending the monthly exit meeting on May 12. 1989.
- Denotes those attending the exit meeting on May 30, 1989.
- Denotes those attending the management meeting on March 21, 1989.
The inspectors also contacted and interviewed other licensee and contractor personnel.
2.
Previously Identified Items (90712)(92700)(92701)(92702)
a.
(Closed) 0?en Item (461/88014-03): Defective Installation of
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Secondary Containment Boot Seals.
This item was discussed in Inspection Report 50-461/88014 Paragraph 8.b.
The item remained open pending installation of backing rings to several secondary containment boot seals during
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the current refueling outage.
Inspectors' field observations during the outage confirmed that the backing rings have been installed.
This item is closed.
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b.
(Closed) Unresolved Item (461/88030-02):
Uninsulated Butt Splices in Environmentally Qualified Equipment.
Followup of this item was documented in Inspection Report 50-461/89006, Paragraph 3, by a regional specialist and was being tracked by Unresolved Item 461/89006-01.
Unresolved Item 461/88030-02 is closed.
c.
(Closed) Open Item (461/88030-03):
Licensee Response to Part 21 Notification Concerning White Melamine Torque Switches.
This item was adequately addressed and the issue closed in Inspection Report 50-461/89006, Paragraph 5, by a regional specialist. This item is closed.
d.
(Closed) Unresolved Item (461/89008-04) and LER 89-017-00 (461/89017-LL):
Failure of. Division III Diesel Generator Heat Exchanger to Meet Seismic Qualifications.
This item was previously discussed in inspection report 50-461/89008, Paragraph 5.g.
At the time of that inspection the item was left unresolved pending the licensee's determination of the cause of the missing mounting hardware and its effect on diesel generator (DG) operability.
The licensee completed their investigation and issued Licensee Event Report (LER) 89-017-00 dated April 27, 1989.
The LER reported that the Division III DG and therefore the High Pressure Core Spray (HPCS) System had been technically. inoperable since the beginning of plant operation. Three of the four mounting bolts for the diesel's Shutdown Service Water (SX) System Heat Exchanger had not been installed properly.
The result was that the diesel did not meet seismic qualification requirements and may not have been able to perform its design function.
Thus in the case of a loss of offsite power, a design basis earthquake, and a loss of coolant accident, the HPCS system might not have been available.
Technical Specification 3.8.1.1.b required that three separate and independent diesel generators be OPERABLE.
Technical Specification 3.5.1.c further required that the HPCS system be OPERABLE.
Failure of the licensee to maintain the Division III DG and the HPCS system OPERABLE from initial plant operations in February 1987 until the SX Heat Exchanger was properly mounted on March 2, 1989, is considered a Violation (461/89014-01).
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The inspectors reviewed the licensee's evaluation of the cause of the event and the corrective action taken as described in LER 89-017-00. The cause was believed to be the bolts being removed ard not properly reinstalled during ennstruction. Records of the material receipt inspection showed that the heat exchanger wts specifically inspected with satisfactory results. No maintenance activities had been performed that would have resultcd in the removal of the bolts after plant operations began.
Corrective actions included installing the bolts under Maintenance Work Request D05148 and inspecting the other DGs to verify that similar conditions didn't exist. Both actions have been completed.
Based on the inspectors' review of the corrective actions for this violation, no additional response is required and this violation is closed. Related Unresolved Item 461/89008-04 and LER 89-017-00 (461/88017-LL) are also closed.
JClosed)UnresolvedItem(461/89008-08): Potential Deviation e.
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from Regulatory Guide 1.105.
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This item was discussed in Inspection Report 50-461/89008,
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Paragraph 5.j.
The issue involved the licensee's discovery that their architect-engineer, Sargent and Lundy Engineers (S&L), had used a six month calibration frequency when calculating the drift rate and setpoints for many Technical Specification instruments and other instruments in systems important to safety. The Technical Specifications required that the instruments be calibrated on at least an 18 month frequency. Regulatory Guide 1.105, Revision 1, to which the licensee was committed by Section 1.8 of their Updated Safety Analysis Report, required that setpoints on instruments important to safety be established with sufficient margin between the Technical Specification limit for the process variable and the nominal trip setpoint to allow for the instrument drift that could occur during the interval between calibrations. Thus for instruments that were being calibrated every 18 months, the setpoint l
may have drifted beyond the allowed Technical Specification limit.
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The licensee originally documented the concern in Condition
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Report 1-87-12-071 dated December 29, 1987. The inspectors reviewed the engineering disposition and action plan for the condition report dated April 5, 1989. The licensee included 268 instruments in the original Regulatory Guide 1.105 scope after accounting for additions and deletions due to modifications. Of these, 146 instruments were not included in the Technical Specifications. Because of certain ambiguities in the wording of Regulatory Guide 1.105, Revision 1, concerning the scope of i
l iisstruments it covered, the licensee contacted the NRC's Instrumentation and Control Systems Branch Chief in NRR on March 9, 1989. These comments were documented in Record of Coordination Y-210304 by the licensee. NRR stated that the intended scope of Regulatory Guide 1.105, Revision 1, was instruments that are listed in the plant Technical Specifications.
This scope was clarified in Revision 2 of the Regulatory Guide.
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NRR stated that the remainder of plant instruments should be 1-maintained under a program umbrella which exercised sound engineering judgement for establishing setpoint and calibration criteria.
For the Technical Specification instruments, the licensee found that 50 had setpoints that would support the 18 month surveillance interval listed in the Technical Specifications.
The remainder had setpoint calculations that would support only a six month interval.
For those instruments the licensee instituted a six month calibration frequency. They also intended to submit a proposed change to the setpoints in the Technical Specifications to support an 18 month calibration frequency by late 1989. The licensee investigated the safety significance of allowing surveillance intervals for Technical Specification instruments that were longer than the intervals that could be supported by the setpoint drift calculations.
Their conclusion was that none of the Technical Specification instruments had "as found" setpoints that were outside the allowed range even when calibrations had been perfonned at longer than six month intervals. The inspectors reviewed the licensee's findings and determined that their conclusion that the issue had not been safety significant was reasonable.
During the licensee's investigation of this issue they discovered that over 100 instruments in non-Technical Specification systems did not have any existing surveillance or preventative maintenance procedures. Most of these instruments were on vendor supplied equipment such as air conditioning refrigeration units. Most of the equipment affected was-considered support equipment for Technical Specification systems such as switchgear heat removal systems and area room coolers. The licensee calibrated all the-affected instruments in the current refueling outage and was developing appropriate preventative maintenance programs to maintain their calibration at frequencies supported by sound engineering judgement. The licensee also upgraded the seismic qualifications of some of the support instruments.
The root cause for the problems identified in instrument setpoints was attributed to poor communication between the licensee and S&L concerning calibration intervals and inadequate review by the licensee's engineering and maintenance staffs of S&L's scope and the results of their calculations. Although the condition was originally identified on December 29, 1987, aggressive corrective action did not begin until February, 1989. The reason for the delay was that the Nuclear Station Engineering Department had made a preliminary determination that the instruments' setpoints would support an 18 month calibration interval based on recalculating
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the drift for two randomly selected instruments.
S&L was then tasked to perform all the applicable drift calculations again but was given until February 15, 1989, to complete the task.
The licensee apparently did not become aware that the drift calculations for many of the instruments showed that an 18 month interval could not be supported until the entire task was completed. Once the licensee became aware of the problem, the inspectors noted that rapid, extensive, and sound actions to resolve the issues were taken. The licensee kept the inspectors informed of the progress with periodic updates.
This item is closed.
f.
(0 pen) Violation (461/89008-09d):
Spill of Reactor Water During Restoration of System from Testing.
This event was discussed in Inspection Report 50-461/89008, Paragraph 8.b.(9).
The associated Notice of Violation required that the licensee respond within thirty days of the date of the Notice (April 12,1989) pursuant to the provisions of 10 CFR 2.201.
l In light of similar events discussed in this inspection report, NRC
regional management suggested that the licensee delay the response to Violation 461/89008-09d and submit it concurrently with the response to the violations ident,iied in this report.
One violation was identified.
3.
Followup of Regional Requests (92701)
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Due to problems noted at the Perry Nuclear Plant with high temperatures in the upper portion of the drywell, the inspectors reviewed the licensee's response to those concerns.
General Electric issued Rapid Information Communication Service Information Letter No. 41 on March 31, 1989, to report the problem. The licensee responded with memorandum Y-91151 from R. D. Freeman dated April 10, 1989. The memorandum discussed actions the licensee had previously taken-to monitor drywell temperatures and improve temperature controls.
The memorandum also discussed inspections of equipment in the drywell as a result of the drywell wetting event discussed in Paragraph 5.c below.
No evidence of damage to electrical cables was noted.
The inspectors conducted a field walkdown of the area of interest and noted tha;, Clinton has very few safety related cables or other devices in this area that could be affected by radiative heat from the refueling bellows.
The inspectors did note one safety-related mechanical snubber in the zone.
Discussions with the licensee indicated that the snubber (1RE315295) had been one of the ones that had failed during the inspection program in the refueling outage.
The failure was thought to be similar to other snubber failures and was attributed to construction activities.
The inspectors suggested that this particular snubber failure be
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reexamined in light of the fact that Perry had found two similar snubbers that had failed due to excessive temperatures.
The licensee provided memorandum Y-91279 from S. R. Bell dated April 21, 1989, which documented observations noted about the condition of the snubber during disassembly.
No damage attributed to excessive heat was noted.
The replacement snubber was required to be retested during the next refueling outage.
The results of that testing were to determine if additional actions were needed.
b.
In response to a potential safety problem with the location of hydrogen storage tanks identified at the Trojan Nuclear Plant, NRC regional management requested that the inspectors confirm that a similar problem did not exist at Clinton.
Details of the problem at Trojan were contained in IE Information Notice 89-44,
" Hydrogen Storage on the Roof of the Control Room."
Specifically regional management requested that the inspectors obtain the following information:
(1) The distance from the hydrogen storage facility to the nearest safety-related structure or air intake; (2) The maximum volume of gaseous or liquid hydrogen stored onsite in standard cubic feet or gallons respectively.
The licensee provided the following information:
(1) The distance from the hydrogen storage facility to the nearest safety-related structure was 432 feet.
The distance to the nearest safety related air intake was about 560 feet.
The distance to the nearest non safety-re'ated air intake was about 190 feet; (2) The maximum volume of gaseous or liquid hydrogen stored onsite was 60,800 standard cubic feet.
The inspectors confirmed the above information by direct field observation.
No violations or deviations were identified.
4.
IE Bulletin and Generic Letter Followup (92703)
a.
(Closed) IE Bulletin 79-18 (461/79018-BB):
Audibility Problems Encountered on Evacuation of Personnel From High-Noise Areas.
This bulletin was previously discussed in the following Inspection Reports:
50-461/84019, Paragraph 2.a; 50-461/86048, Paragraph 2.f; 50-461/86055 Paragraph 4; 50-461/86059, Paragraph 2.d; 50-461/86060, Paragraph 2.i; and 50-461/86072, Paragraph 2.d.
The remaining commitments were to conduct surveys of high noise areas during the l
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startup test program and complete all necessary corrective actions prior to the end of the first refueling outage. The inspectors reviewed Maintenance Work Requests (MWRs) C50374, C40941, C55233, and D00329 as well as Field Problem Report 201794, and Field Alteration CQF001.
In some areas of the plant the licensee was unable.to provide adequate public address coverage due to high noise.
For those areas a sign was installed at the entrances stating " CAUTION LIMITED GAITRONICS AREA USE ALTERNATE COMMUNICATIONS." The inspectors noted that no training commitments were in place to ensure plant personnel were trained on the meaning of $he signs and the actions they should take if working in the high noise areas.
The licensee provided Memorandum Y-210673 which committed to add training on the meaning and use of the signs to their training program.
Based on the licensee's commitment this
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item is closed.
b.
(Closed) Generic Letter 88-11 (461/88011-GL):
NRC Position on Radiation Embrittlement of Reactor Vessel Materials and Its Impact on Plant Operations.
Tha licensee submitted Letter U-601317 dated December 6, 1988, in responte to the generic letter. The letter cutlines the licensee's intended actions to comply with Regulatory Guide 1.99, Revision 2.
In a letter dated May 8, 1989, John Hickman, NRR Project Manager
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for Clinton, stated that the staff considered the commitments satisfactory. This item is closed.
c.
(Oper) Generic Letter 88-14 (461/88014-GL):
Instrument Air SeppiySystemProblemsAffectingSafety-RelatedEquipment.
The licensee submitted Letter U-601384 dated April 6, 1989, in respon e to tha generic letter.
The letter outlined the licensee's review of NUREG-1275 and action they had taken and
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inte Med to ta h to maintain proper instrument air quality.
In a lettee dated May 3, 1989, John Hickmaa, NRR Project Manager
'for Clinton, stated that the issue would be closed when thu staff was informed of the completion of modifications (JAF007)
which will help alleviate moisture accumulation and allow testing of individual dryer air quality.
5.
Operational Safety Wrification (71707)
The inspectors observed control room operations, attended selected pre-shift briefings, reviewed applicable logs, and conducted discussions with control room operators during the inspectica period.
The inspectors verified the creiability of selected emergency systems and verified tracking of LCOs.
Routine tours of the auxiliary, fuel, containment. control, diesel generator, and turbine buildings and the screenhouse were conducted to observe plant equipment conditions including the potential for fire hazards, fluid leaks, and operating
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conditions (i.e., vibration, process parameters, operating temperatures, etc).
The inspectors verified that maintenance requests had been initiated for discrepant conditions observed.
The inspectors verified by direct observation and discussion with plant personnel that security procedures and radiation protection (RP) controls were being properly implemented.
Inspections were routinely performed to ensure that the licensee conducted activities at the facility safely and in conformance with regulatory requirements.
The inspections focused on the implementation and overall-effectiveness of the licensee's control of operating activities, and the performance of licensed and nonlicensed operators and shift technical advisors.
The following items.were considered during these inspections:
Adequacy of plant staffing and supervision.
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Control room professionalism, including procedure
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adherence, operator attentiveness and response to alarms, events, and off-normal conditions.
Operability of selected safety-related systems, including
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attendant alarms, instrumentation, and controls.
Maintenance of quality records. and reports.
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During the entire inspection period the plant remained in 0PERATIONAL CONDITION 4 (Cold Shutdown) for the first refueling outage.
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a.
On March 12, 1989, while conducting Surveillance Procedure CPS No. 9080.03, " Diesel Generator 1A(1B) Operability - 24 Hour and LOP Test," the Division II Diesel Generator (DG) experienced a valid test failure. The failure was attributed to reduced fuel oil pressure.
The licensee reported the failure as Special Report U-601421 dated April 12, 1989, in accordance with Technical Specification 6.9.2.
The licensee reported that the fuel oil problem was caused by a crack in the 5/8" diameter inlet tubing on the engine-driven fuel oil pump of the 16-cylinder engine.
The crack was located on the inner radius of a bend in the tubing which was bent beyond an acceptable limit (kinked) during installation.
The root cause of the crack was believed to be fatigue due to normal vibration during operation. This event was the second valid failure of the Division II DG in the last 20 valid tests of the i
unit.
Thus the test frequency for the DG was changed from at least once per 31 days to at least once per 7 days in accordance with Technical Specification Table 4.8.1.1.2-1.
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The. inspectors noted that IE-Information Notice 89-07 issued January 25, 1989, discussed similar. failures in small diameter ja tubing-in fuel oil systems as well as other safety-related systems.
The inspectors confirmed that the licensee had received the Information Notice and that it was being evaluated by the Nuclear Station Engineering Department.
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On March 13, 1989, the licensee identified that the-Average Power Range Monitor (APRM) surveillance, which had been conducted on
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March 11, 1989, had been conducted improperly. Thus the APRMs were all considered inoperable and the plant had been in violation of its Technical Specifications.
Tt"? licensee reported the event as Licensee Event Report (LER) 89-015-00 dated April-10, 1989.
The cause of the event was attributed to inadequate review of the Technical
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Specification requirements by the Line Assistant Shift
Supervisor (LASS).. On March 11, 1989, the LASS had directed the Control Room Operator to perform only Section 8.3 of Surveillance Procedure CPS No. 9031.12, "APRM Channel Functional." Section 8.3 provided instructions for. performing APRM neutron flux'"setdown" scram and rod block functional testing.
Section 8.4 of the same procedure, which provided the instructions for performing APRM " inoperative" scram and rod block functional testing, should also have been specified.
The completion of both sections of the surveillance was necessary to-demonstrate APRM operability for the existing plant conditions.
Technical Specification 4.3.1.1 required, in part, that each reactor-protection instrumentation channel be demonstrated OPERABLE by the performance of CHANNEL FUNCTIONAL TESTS for the OPERATIONAL CONDITIONS and.at the frequencies shown in Table 4.3.1.1-1.
That table required that in OPERATIONAL CONDITIONS 3,4,and 5, the two APRM protective features discussed above be demonstrated at least weekly. The time limit for the. surveillance had expired at 6:50 p.m. on March 11, 1989.
Section 8.4 of the surveillance was not completed until 3:15 p.m. on March 13.
Since all control rods were inserted during that entire time. period, and the surveillance performed on March 13 lndicated that the APRMs had been functional between March 11 and March 13, the safety significance of the violation was minor. This event was considered a " licensee-identified" Violation (461/89014-02) for which a notice of violation was not issued in acccrdence with 10 CFR 2, Appendix C,Section V.G.I.
This item is closed.
The inspectors will review the corrective actions for the LER separately.
c.
On March 20, 1989, with the reactor plant in OPERATIONAL CONDITION 4 (Cold Shutdown), about 40,000 gallons of water was gra'vity drained from the containment refuel pool into the
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drywell. The gravity drain of water into the drywell occurred when Service Air (SA) was isolated to the containment resulting in a loss.of seals on the gate separating the dryer storage pool
.from the reactor cavity pool. The drywell head was installed j
but not fully torqued.
At the time of event occurrence, the inspector was monitoring control room activities and observed plant operators respond to the event.
Plant operators attempted.to reduce the ingress of water into the drywell by draining the reactor cavity to the main condenser.
In addition, appropriate announcements were made over the plant public address system to advise personnel of the event and direct them to stay clear of the drywell.
Plant-operators restored SA to the containment, which was effective in
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stopping the leakage past the gate seals.
A subsequent critique of this event identified that the SA tagout had not been adequately evaluated for plant impact prior to implementation.
In addition, the schedule for hanging the SA tagout showed the activity was not to be performed prior to filling both upper pools.
Technical Specification 6.8.1.a required that written procedures be established,' implemented, and maintained covering the Authorities and Responsibilities for Safe Operation and Shutdown.
Administrative Procedure CPS No. 1401.01, " Conduct of Operations," Revision 16, dated December 14, 1988, Paragraph 8.5.5.1.b, required, in part, that prior to removing a system from service the Shift Supervisor / Assistant.
Shift Supervisor evaluate the impact on other equipment and on plant operations.
Failure of the Shift Supervisor / Assistant Shift Supervisor to adequately evaluate the impact of removing the Service Air system from service is a Violation (461/89014-03).
The inspectors noted that the licensee establishe'd and implemented an inspection plan to verify that no damage to safety-related components occurred as a result of this event.
That plan included a visual inspection of the following equipment located in the drywell:
ASCO solenoid valves; Valcor solenoid valves; NAMCO limit switches; Drywell pull. boxes; Drywell junction boxes; Motor operated valves; Hydrogen ignitors; and HVAC components. The preliminary results of that inspection identified no eouipment damage from the drywell spray event; however, three IE pull boxes, three non-1E pull boxes, and,two non-1E junction boxes were found to contain standing water.
d.
On Apri? 6, 1989, the licensee identified a number of motor operated valves with installed thermal overload protection that,
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contrary to the licensee's commitment to Reg'ulatory Guide 1.106, i
were not bypassed when required to perform an active safety function.
As documented in Condition Report 1-89-04-026,_the following
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valves were found by the licensee to have installed thermal-overloads that were not bypassed in the direction noted:
VALVE NUMBER SYSTEM DIRECTION 1E32-F001A,E,J,N MSIV LEAK CONTROL OPEN 1E32-F002A,E J,N OPEN
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i 1E32-F003A E,J,N OPEN
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1E32-F006,7,8,9 OPEN
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IC11-F083 CONTROL R0D ORIVE CLOSE I
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1HG-001 COMBUSTIBLE GAS CONTROL CLOSE l
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1 Elk-F009 RESIDUAL HEAT REMOVAL OPEN
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p Clinton Power Station Updated Safety Analysis Report (USAR),
Paragraph 8.1.6.1.19 detailed the licensee's commitment to Regulatory Guide 1.106.
That commitment was stated "Clinton
Power Station complies with position C.1.a, continuously
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bypassing in the safety direction (i.e., open or closed circuit)
the thermal overloads..."
In addition USAR Table 6.2.47 identified the following " POST
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LOCA" valve positions for containment penetration isolation valves:
VALVE POST LOCA POSITION 1E32F001A,E,J,N OPEN/ SHUT IC11-F083 OPEN/ SHUT I
1HG-001 OPD'/ SHUT CPS Technical Specification Table 3.8.4.2-1 listed motor operated valves with thermal overloads bypassed continuously.
All of the above motor operated valves (except IC11-F083) were listed in Table 3.8.4.2-1 as having thermal overloads bypassed in one direction only.
10 CFR 50, Appendix B, Criteria III stated, in part, that measures shall be established to assure that applicable regulatory require-I
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ments and the design basis as specified in the license arolication are correctly translated into specifications.
Failure of the licensee to translate from their design basis and commitment to Regulatory Guide'1.106 the requirement to bypass thermal overloads in the safety direction of the above motor operated valves is a Violation (461/89014-04).
e.
On April 10, 1989, while in the process of drilling weep holes in electrical pull boxes, the licensee discovered air _ blowing out of two pull boxes in the secondary gas control boundary extension area in the southeast corner of the 781' elevation of the Auxiliary Building. The licensee's investigation determined that five conduit penetrations through the. secondary containment in that area did not have internal ventilation seals installed.
The licensee installed the penetration seals under Maintenance Work Request D01060.
The licensee determined that the condition had existed since initial plant construction but had not been safety significant because, although leakage paths existed through the secondary containment, any bypass leakage had already been
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accounted for in preoperational secondary containment drawdown tests.
In addition periodic surveillance testing had. verified that secondary containn.ent bypass leakage was less than the design basis and low enough that the Standby Gas Treatment system was able to perform its design function.
The inspectors reviewed the licensee's actions in response to the finding and noted that the licensee had not' reported the event to the NRC even though LER 89-006-00 had been issued to report three similar secondary containment penetrations which were missing their internal ventilation seals.
Corrective actions for that LER included a review of an additional 127 secondary containment electrical penetrations to insure they had their internal ventilation seals.
However, the scope of that corrective action was limited to penetrations through secondary containment airlock walls and not other walls in the secondary containment.
The inspectors also noted that there was no indication that the licensee had investigated other penetrations in the secondary gas control hem.dary extensions to see if internal ventilation seals were installed.
The inspectors' field verifications indicated that other penetrations in the four boundary extension areas. appeared to be identically constructed to the ones that were found to be missing their seals. The inspectors also noted that the five penetrations were among nine that had been noted to have their external boot seals improperly installed as discussed in Inspection Report 50-461/88014, Paragraph 8.b.
Unresolved Item 461/88014-04 was written pending the licensee's determination of the root cause of the improper boot seals.
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'The inspectors requested that the licensee further' evaluate the
potential generic implications of missing conduit seals.
This ij was considered an Unresolved Item (461/89014-05) pending further
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review of licensee actions.
. f.
On April 20, 1989, the inspectors notified the Shift Supervisor i
that they had noted several valves in the Scram Discharge Volume (SDV) instrumentation that were not locked in position. The valves noted were,IC11-155A&B, IC11-158A&B, 1C11-362A&B, IC11-163A&B, IC11-164A&B, and 1C11-165A&B.
All the valves had
" Locked Valve" signs attached.
The inspector's review determined that both Operating Procedure CPS No. 3304.01V001,
" Control Rod Hydraulic and Control Valve Lineup," performed on February 24, 1989, and CPS No. 3001.01V001, " Locked Valve List,"
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performed on April 11, 1989, indicated that the valves were locked in position.
The licensee performed the entire CPS No. 3301.01V001 procedure again and noted that all other valves were locked in their proper positions.
They initially indicated that they were unable to determine the cause of the SDV valves being unlocked.
This finding was similar to a previously identified Violation (461/87031-05)' discussed in Inspection Report 50-461/87031, Paragraph 8.f in which the inspectors noted several of the same valves unlocked. Corrective actions for that violation included installation of the " Locked Valve" signs and training of-operating and maintenance personnel.
That violation was also discussed in Inspection Report 50-461/87032, Paragraph 2.g, and closed in. Inspection Report 50-461/87039, Paragraph 2.c.
Technical Specification 6.8.1.a required that written procedures be established, implemented, and maintained covering equipment control (e.g., locking and tagging). Administrative Procedure CPS No.1401.01, " Conduct of Operations," required, in part, the Shift Supervisor / Assistant Shift Supervisor authorize the manipulation of a locked valve, through either the safety tagging program, or an approved operating or surveillance procedure that contains the proper controls to ensure that valve is returned to its proper position and relocked.
At some time between April 11, and April 20,-1989, 12 locked valves in the Scram Discharge Instrument Volume were unlocked without proper controls to ensure they were relocked.
Failure to properly implement Administrative Procedure 1401.01 is a Violation (461/89014-06).
Although the valves involved in this violation were found to be in their correct positions, the apparent lack of rigorous administrative controls over locked valves despite a previously identified violation is considered significant.
In their
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response to this violation the licensee was requested to provide the results of their investigation into the specific cause of the valves being unlocked.
g.
During the report period, a NRC maintenance team inspection was conducted at CPS.
The results of that inspection were documented in Inspection Report 50-461/89003.
During that inspection effort it was noted that calibrations were being performed on Intermediate Range Monitors (IRMs) with test equipment (M&TE) that specified a
" limited use calibration." The NRC maintenance team inspector identified that plant technicians did not verify the required 123 VAC.+/- 1 VAC line voltage prior to using the M&TE for the IRM Mean Square Analog Module. That observation was considered a procedural violation in Inspection Report 50-461/89003 for which the licensee was taking corrective action by revising the calibration procedure and training plant technicians.
The inspectors, with support from a Region III specialist, reviewed the impact on past IRM calibrations with the licensee assuming that the M&TE for the Mean Square Analog Module was not used within the desired line voltage range.
As documented in IP Memoranda Y-91087, dated April 3, 1989, the licensee evaluated the impact on IRM calibrations assuming a 5 VAC deviation of the power supply used by the M&TE. That evaluation showed that a maximum deviation of 9 milli-volts (mv) would occur with a 5 VAC power supply deviation.
The 9 mv deviation was within the design value acceptable deviation of 50 mv.
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After the Mean Square Analog Module was calibrated with its i
specific M&TE, the card was reinstalled into its proper drawer I
and a loop calibration was performed to remove any errors.
Based on the above evaluation, the inspectors concluded that the past IRM calibrations would not have been significantly impacted l
by using the Mean Square Voltage Test Fixture with a power supply voltage 5 VAC outside the 123 +/- 1 VAC specified range.
Three' violations and one unresolved item were identified.
One additional violation was identified for which a Notice of Violation was not issued in accordance with 10 CFR 2, Appendix C, Section
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6.
Monthly Maintenance Observation (62703)
Selected portions of the plant maintenance activities on safety-related systems and components were observed or reviewed to ascertain that the activities were performed in accordance with approved procedures, regulatory guides, industry codes and standards, I
and that the performance of the activities conformed to the Technical Specifications.
The inspection included activities associated with preventive or corrective maintenance of electrical, instrumentation l
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and control,. mechanical equipment, and systems.
The following iteins were considered during these inspections:
the limiting conditions for operation were met while components or systems were removed from service;. approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were I
inspected as applicable; functional testing and/or calibration was
' performed' prior to returning the ccmponents or systems to service;
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parts and materials that were used were properly certified; and appropriate fire prevention, radiological, and housekeeping
. conditions were maintained.
The inspectors observed / reviewed the following work activities:
Maintenance Work Activity
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Procedure No.
D04722 Installation of Raychem Splices in Hydrogen Igniters D14375 Installation of Raychem Splices in H22 Panels CPS No. 8502.14 CEH Relay Inspection, Calibration and Functional Test D02951 At.unciator ground fault D06288 Pull Box and Junction Box Inspection D04673 Overspeed Test of Division I Diesel D04673 Overspeed Test of Division III Diesel D02961 SRM-C Troubleshooting Several additional maintenance activities were observed by regional inspectors during this period including a Maintenance Team Inspection documented in Inspection Report 50-461/89003.
No violations or deviations were identified.
7.
Monthly Surveillance Observation (61701) (61720) (61726)
An inspection of inservice and testing activities was performed to ascertain that the activities were accomplished in accordance with applicable regulatory guides, industry codes and standards, and in conformance with regulatory requirements.
Items which were considered duri,g the inspection included whether adequate procedures were used to perform the testing, test instrumentation was calibrated, test results conformed with Technical Specifications and procedural requirements, and tests were performed
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within the required time limits. The inspectors determined that the l
test results wereLreviewed by someone other than the personnel
' involved with the performance of the test, and that'any deficiencies identified during the testing were reviewed and resolved by appropriate management personnel.
The inspectors observed / reviewed the following activities:
Surveillance / Test Procedure No.
Activity
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CPS No. 9861.02D025 Drywell Air Lock Barrel Leak Rate Test CPS No. 9861.07 Drywell Bypass. Leak Rate Test CPS No. 9080.01 Diesel Generator 1A Operability - Manual CPS No. 9053.03 ECCS Division 2 Simulated Auto Actuation CPS No. 9432.23
- Primary and Secondary Containment Isolation Logic System Functional CPS No. 9438.04 feedwater Reactor Vessel Water Level Logic System Functional Test CPS No.'9479.01 Steam Bypass and Pressure Regulations System Functional and Time Response Test CPS No. 9843.01 ISI Category "A" Valve Leak Rate Test on 1821F032A CPS No. 9981.01 Diesel Fuel Oil Sampling and Analysis (Div. III)
Several additional surveillance activities were observed by re'gional inspectors during this period including a Maintenance Team Inspection documented in Inspection Report 50-461/89003.
No violations or deviations were identified.
8.
Onsite Followup of Events at Operating Reactors (93702)
a.
General The inspectors performed onsite followup activities for events which occurred during the inspection period.
Fo llowup inspection included one or more of the following:
reviews of operating logs, p*ocedures, condition reports; direct observation of licensee actions; and interviews cf licensee personnel.
For each event, the inspectors reviewed one or more
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of the following:
the sequence of actions; the functioning of safety systems required by plant conditions; licensee actions to verify consistency with plant procedures and license conditions; and verification of the' nature of the event.
Additionally, in some cases, the inspectors verified that licensee investigation had identified root causes of equipment malfunctions and/or personnel errors and were taking or had taken appropriate corrective actions. Details of the events and licensee corrective actions noted during the inspectors' followup are provided in paragraph b below.
b.
Details (1) Safety Relief Valve Actuation and Containment Isolation due to Pressure Transient from a Scram in " Solid" Plant
[ ENS No. 15060]
On March 19, 1989, the licensee informed the NRC via the Emergency Notification System (ENS) of the unexpected automatic actuation of the Safety Relief Valves (SRVs) and Containment Isolation System.
The plant was in OPERATIONAL CONDITION 4 (Cold Shutdown) with a Reactor Coolant System Leakage Test in progress.
The test required the reactor pressure vessel (RPV)
to be completely filled with water (" solid") and pressurized.
Concurrently with the leakage test, the operators were conducting individual contrc: rod scram testing since the prerequisites for the scram time testing also required that the RPV be pressurized to greater than or equal to 950 psig.
Restoration from the scram testing required that the reactor mode switch be moved from the Refuel to the Shutdown position.
The operators knew that this would cause a reactor scram signal, which would cause the opening of all scram inlet and exhaust valves.
Believing that the scram would result in the addition of water to the vessel and a possible pressure increase, the operators. lowered RPV pressure to 900 psig and instructed the operator stationed at the local test gauge for the leakage test to discharge water as necessary to maintain RPV pressure less than 1000 psig.
When the reactor mode switch was placed in Shutdown and the scram signal was generated, the resultant pressure increase was more rapid than the operators had anticipated.
Pressure increased at a rate of about seven psig per second.
Pressure reached the setpoint of the SRVs and four of the valves opened and shut as designed to relieve pressure. The scram was immediately reset and pressure stabilized at about 800 psig.
The maximum pressure reached was 1130 psig as noted at the local test gauge for the leakage test.
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As a result of the SRVs lifting and shutting, a high differential pressure condition occurred in the main steam lines causing the actuation of the Group 1 Containment
' Isolation valves.
The inboard Main Steam Isolation, Main Steam Drain, and Main Steam Bypass valves closed as designed.
The outboard isolation valves were already closed for the leakage test.
The licensee documented the event in Licensee Event Report (LER) 89-016-00 dated April 18, 1989. The licensee attributed the cause of the event to inadequate procedures.
Surveillance
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Procedure CPS No. 9813.01, " Control Rod Scram Time Testing,"
was inadequate in that it did not contain a restoration section or provide cautions associated with performance of the surveillance test during " solid" plant conditions.
Technical
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Procedure CPS No. 2800.03, " Reactor Coolant System Leakage
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Test," was inadequate in that it did not provide precautions
concerning the implications of " solid" plant conditions or
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limit other evolutions which would be allowed to be performed concurrently with the leakage test.
Technical Specification 6.8.1.d required that written procedures be established, implemented, and maintained covering surveillance and test activities of safety-related equipment.
Failure of the licensee to have adequate
procedures for the control of the Reactor Coolant System
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Leakage Test and Control Rod Scram Time Testing is a Violation (461/89014-07). The inspectors will review the
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LER in a subsequent report.
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(2) Possible News Media Interest in Transportation Accident
[ ENS No. 15295]
On April 12, 1989, the licensee reported to the NRC via the ENS that they expected possible news media interest and a
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news release about a transportation accident that had I
occurred approximately 30 miles from the plant.
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The licensee was informed by the Illinois State Police that a radwaste container had fallen from a truck that was enroute to Clinton Power Station.
Since the initial report was not clear as to the type of container, the on-duty
Shift Supervisor directed that plant health physics
personnel respond to the scene of the accident and provide i
J assistance to the State Police.
The inspectors observed health physics technicians conduct surveys on the radwaste
container, which was determined to be new and not i
radiologically contaminated. The accident occurred at about 3:00 a.m. and involved loss of the radwaste container from the transport truck only.
No other vehicles were l
involved.
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The inspectors noted that the decision of the Shift
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Supervisor to send health physics personnel to the accident
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scene was conservative.
(3) Control Room Ventilation System Operating Outside of the Design Basis [ ENS No. 15335]
On April 14, 1989, the licensee informed the NRC via the ENS that the Main Control Room Ventilation System (VC) had been operating outside its design basis because under certain conditions unmonitored airborne radioactivity could have entered the ductwork.
As documented in Condition Report No. 1-89-04-073, the licensee identified that the storage location for contaminated material may present a concern for the Control Room environment in the event of a fire.
During the r
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current first refueling outage, the licensee had (
established a work area at the 702' elevation in the Control Building to prepare contaminated equipment for shipment.
In particular, the Main Steam Safety Relief Valves which had been replaced during the refueling outage were being worked on in that area prior to shipment to an l
offsite lab.
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The licensee's evaluations of the effects of a fire at the 702' elevation in the Control Building concluded that airborne radioactive material could enter the negative pressure VC ductwork and enter the Control Room.
The ductwork was not welded or sealed with silicone sealant material.
The ventilation system radiation monitors were located outside the building near the air intake openings and would not have been able to detect the radioactivity.
The licensee considered the above condition to be unanalyzed and reported this event in accordance with 10 CFR 50.72.
Immediate action included removal of the contaminated material from the area of concern.
More appropriate areas for storage of contaminated inaterial have been designated.
Later analysis by the licensee concluded that the potential for airborne radioactivity in the Main Control Room could be limited to less than the Maximum Permissible Concentrations in 10 CFR 20 provided certain administrative controls were instituted.
In Memorandum JW-0243-89, the Manager - Clinton Power Station committed to revise Administrative Procedure CPS No. 1024.30 (CCT 050737) to limit the maximum amount of loose surface contamination on material stored on the 702' and 825'
elevations of the Control Building to 50,000 dpm/100 cm squared.
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I Fixed and loose contamination was to be limited to 100,000 dpm/.
100 cm squared. As an interim measure, the above limits were incorporated in Radiation Protection Night Orders.
(4) Unanticipated Reactor Scram during Troubleshooting on Source Range Monitors [ ENS No. 15336]
On April 14, 1989, the licensee informed the NRC via the ENS that an unexpected reactor scram had occurred during troubleshooting of the "C" channel of Source. Range Neutron Monitors (SRM). The reactor was in OPERATIONAL CONDITION 4 (Cold Shutdown) with all control rods fully inserted at the time of the event so no actual rod motion occurred.
The licensee's initial evaluation of the cause of this event was described in LER 89-018-00 dated May 11, 1989.
The scram signal was generated when a high neutron flux signal occurred on Intermediate Range Monitor (IRM) "C" while troubleshooting SRM "C" ih the same cabinet. The licensee concluded that the most probable cause of the high flux signal'on IRM "C" was a recessed connector center pin for the IRM "C" signal lead.
It was believed that while troubleshooting in the cabinet, the. technician moved the IRM "C" signal lead which caused intermittent contact and the resultant high flux signal.
Since IRM-D had been previously placed in a trip condition, the 2 out of 4 coincidence logic was satisfied, resulting in a scram signal.
The inspectors will review the required Licensee Event Report in a subsequent inspection report.
(5) Unanticipated Reactor Scram during Turbine Control and Stop Valves Scram Response Time Testing [ ENS No. 15347]
On April 15, 1989, the licensee informed the NRC via the ENS tnat an unexpected reactor scram had occurred during the performance of Surveillance Procedure CPS No. 9431.21,
" Turbine Control and Stop Valves Scram Response Time Test."
The reactor was in OPERATIONAL CONDITION 4 (Cold Shutdown)
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with all control rods fully inserted at the time of the L
event so no actual rod motion occurred.
The licensee's evaluation of the cause of this event, as reported in LER 89-020-00, dated May 11, 1989, concluded that plant technicians performing the above surveillance inadvertently shorted test leads to ground causing loss of the Division 2 Reactor Protection System (RPS) power o
supply.
Since a Division 4 RPS trip signal was present (IRM-D in trip), the 2 out of 4 coincidence logic was
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I satisfied resulting in a scram signal.
The LER reported that the root cause was attributed to personnel error on
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the part of the technician's supervisor.
He was aware that the surveillance had the potential to cause a short while I
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attaching or detaching test leads but had failed to j
properly evaluate the possible consequences.
The inspectors will review the corrective actions discussed in tne LER in a subsequent report.
(6) Unanalyzed Condition due to Com)onents not Being Environ' mentally QuafiTied [ ENS io. 15474]
On April 28, 1989, the licensee informed the NRC via the ENS the the plant had operated in an unanalyzed condition due to the Safety Relief Valves (SRVs) not being installed in the same configuration in which they had been environmentally qualified.
Subsequent to the above ENS notification, the licensee submitted IP Letter U-601443, dated May 4, 1989, in accordance with 10 CFR 21. As discussed in that letter, the licensee identified that the SRV air pilot valve solenoid power supply connection was not installed with a
"Raychem" heat shrink sleeve. The licensee identified the as-installed configuration during review of EQ files in response to NRC inspections discussed below in Paragraph 9.
One violation was identified in the reviews of this functional area.
9.
Environmental Qualification of Electrical Equipment (92702) (71707)
During the report period, a number of issues regarding the Environmental Qualification (EO) of electrical equipment had been discussed between the licensee and the staff.
As documented in Inspection Report 50-461/89006(DRS), a Region III specialist inspector performed onsite inspections between February 6 and March 3, 1989.
That inspection effort resulted in the identification of an apparent violation due to inadequate corrective action to a previous EQ violation (ref:
Inspection Reports Nos. 50-461/87026(DRS) and 50-461/88010(DRS)).
The :;pparent violation was discussed at an Enforcement Conferer.ce held at the Region III Office in Glen Ellyn, Illinois on March 21, 1989. The results of that enforcement action were under staff review and will be presented in subsequent communications to the licensee.
Subsequent to the enforcement conference and during a Region III a.
review (including an April 20-21 plant walkdown) which was performed to assure the adequacy of the licensee's corrective action for previously identified EQ deficiencies several new deficiencies were identified by the NRC and the licensee.
Details are noted below:
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(1) Hydrogen Igniters:
Field connections for numerous hydrogen 1gniters were found to have unqualified taped splices. EQ files required Raychem splices.
In addition, an engineering review had approved the use of these unqualified. splices.
The licensee has subsequently reported the completion of the replacement of these splices with Raychem splices..
(2) Vendor Termination Boxes On MSIVs: Design required Raychem splices for solenoid valve leads. Further, the field review did not replace these splices as required by MWR. The licensee has subsequently reported to have installed Raychem splices.
(3) GE Instrument Racks:
Numerous instrument circuits landed on terminal blocks inside the containment were not justified for leakage current during an accident. The licensee has subsequently reported to have installed Raychem splices.
(4) Perforated Taped Splice: Oversized taped splice found perforated in condulet due to penetration of condulet cover bolt. The licensee replaced the damaged splice and reviewed other condulets for similar deficiencies.
(5) Solenoid Valve Leads: ASCO solenoids associated with safety relief valves have leads connected to Cannon plugs.
Tested configuration requires Raychem splices on the plugs for postulated environment. The licensee has reported installing Raychem splices and reviewing other such installations for similar deficiencies. The licensee has also reported filing a report pursuant to 10 CFR Part 21 concerning this. condition.
(6) Damper Assembly: Damper assembly not qualified for use in 100% relative humidity. Qualification required sealing of electrical connections on the limit switches from moisture intrusion.
In addition, this damper was excluded from the EQ program. The licensee reported installing seal assemblies on the affected circuits and reviewing other installations for similar deficiencies.
(7) Magnatrol Level Switches: Leads landed on terminal blocks in switch enclosure.
Enclosure is subject to submergence but is installed with no drain holes. Licensee reported subsequently installing seal assemblies on all appropriate Magnatrol Level switches.
(8)
ITT Valve Actuator:
Leads landed on terminals in actuator enclosure. Enclosure is subject to submergence but is installed with no drain holes.
Licensee reported subsequently providing drainage for all appropriate ITT actuators.
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(9) Electrical Enclosures:
Numerous junction boxes, pull boxes, condulets and end use equipment enclosures, whose i
contents are subject to submergence were found installed o
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The licensee has subsequently installed drain holes in appropriate enclosures.
(10) Posting Of FCN/ECNs:
One FCN identifying an EQ enclosure was not posted on the appropriate design drawing.
The licensee has reported this to be an isolated deficiency.
(11) Vacuum Breaker Limit Switches:
Field connections were
found to have unqualified Kynar butt splices. Work-
requests did not allow these boxes to be opened. The licensee j
has reported installing Raychem splices and reviewing other
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equipment for similar deficiencies.
(12) Motor Heaters On ECCS Pump Motors:
Unqualified Kynar butt splices found on leads fur pump motor heaters.
The licensee
has subsequently reported installing Raychem splices and l'
reviewing other equipment for similar deficiencies.
.(13) Conax Electrical Penetration Enclosures:
Some enclosures i
found installed with top cable entry,in a configuration that allows containment spray to impinge on terminal blocks
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having instrument and control circuits.
Two enclosures
with bottom cable entry were found to be slightly warped i
along flanges which could allow containment spray to impinge j
on terminal blocks.
In additional numerous instrument
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I circuits found landed on Kulka terminal blocks on the penetrations could not be adequately justified for leakage current.
This is further addressed in Section 9.b of this
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report.
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This licensee acknowledged the above deficiencies and took immediate,
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aggressive corrective action.
For the items listed above the licensee
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provided a root cause analysis in a May 16, 1989 letter which also discussed corrective actions and an implementation schedule for the noted deficiencies.
In this letter the licensee committed to completing corrective action prior to entering Mode 2 (Startup)
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and notifying the Region III Regional Administrator of the results of that effort.
The licensee subsequently confirmed the corrective action had been completed.
b.
Qualification of KULKA terminal blocks for Instrument Circuits
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During review of electrical enclosures in the containment, the
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inspectors noted that various instrument circuits were terminated on KULKA terminal blocks mountad on the Conax penetrations. On review of Conax test reports IPS-692 and IPS-650, the inspectors were l
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concerned that the test did not simulate the condensation expected due to the 100% humidity, 185 F, and subsequent containment spray postulated during an accident.
Resolution of this issue was deferred to NRR.
A meeting was held between the licensee and the NRC on May 9, 1989 at the NRC office in White Flint, Maryland.
This meeting was to discuss NRC concerns regarding excessive leakage current compromising instrument circuits terminating on Conax penetration KULKA terminal blocks.
In particular, the NRC was concerned that the leakage current anticipated during accident conditions may compromise the required accuracy or cause a failure of the affected instruments for plant applications.
As a result of this meeting, the licensee was required to address the following areas:
(1) Provide documentation on acceptance threshold of leakage current for the affected instruments.
(2) Provide a qualitative or quantitative analysis that compares the containment environment under accident conditions to the test chamber environment and how the differences may affect test results.
(3) Provide documentation of the moisture deposition tests run on 5/8/89 at Conax and their applicability to the qualification test run on the electrical penetration.
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(4) What is Illinois Power's course of action to resolve NRC concerns on the qualification testing involving terminal blocks? Provide the scope and schedule.
The licensee submitted a " Basis for Plant Startup" and committed to
installing Raychem splices on all affected circuits during their
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next refueling outage.
NRR is continuing to review concerns on this issue.
The concerns described in Section 9.a.(1), (3), (5),
)
(6) and (13) are considered examples of an apparent violation (50-461/89014-08(DRS)) of 10 CFR 50.49, Paragraph (f), failure to qualify electrical equipment important to safety for postulated harsh environments during an accident.
The evaluation and disposition of this apparent violation will be addressed in future communications.
10. Temporary Instruction 2515/100:
Proper Receipt, Storage, and Handling of Emergency Diesel Generator (EDG) Fuel Oil During the report period, the inspectors reviewed the licensee's program to maintain adequate quality of emergency diesel generator (EDG) fuel oil that was stored on site. The inspectors conducted i
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lthis review through interviews with cognizant licensee personnel,
direct field observation of installed equipment, and observation of
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fuel oil surveillance activities.
j Results of the inspector's review are discussed below and correspond-
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with Temporary Instruction (TI) 2515/100, Appendix.A, questions 1
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through 15.
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a.
(TI 2515/100 Q1):
The licensee completed their review of Infor: nation Notice 87-04 as documented in IP Memorandum i
e Y-206322, dated October 29, 1987.
The inspectors had previously l
reviewed the licensee's' actions in response to Information
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d Notice 87-04 in Inspection Report 50-461/87030, Paragraph.3.a.
As documented.in that report, the licensee had adequately i
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reviewed Information Notice 87-04.
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b.
(TI 2515/100 Q2):
The licensee did not have a " permanent" Fuel
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Oil (FO) storage tank recirculation system to remove accumulated j
. particles.
However, Operating Procedure CPS No. 3506.01, j
Revision 13, dated March 20, 1989, Paragraph 8.1.7, detailed the
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method used to recirculate F0 storage tanks to disperse the l
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NALCO 8256 biocide. The method described used the F0 transfer pump.in an appropriate lineup to recirculate the F0 storage tank.
c.
(TI 2515/100 Q3): The licensee had prepared Surveillance Procedure CPS No. 9281.05, " Emergency Diesel Fuel Oil Storage Tank Cleaning,". revision 21. dated March 7,'1988,'to clean and inspect F0 storage tanks. c,iace Clinton Power Station was a recently licensed plant, the 10 year inspection had not yet been performed.
The inspectors verified the surveillance was scheduled to be performed in March 1995 and March 1996, d.
(TI 2515/100 Q4): The licensee's F0 storage tanks were sampled on.a quarterly basis. The inspectors witnessed sampling of the
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Division.III F0 storage tank in accordance with Surveillance Procedure CPS No. 9981.01, " Diesel Fuel Oil Sampling and Analysis," revision 23, dated August 9, 1989.
The inspectors observed that the sample collected from the F0 storage tank was taken from about 6 inches from_the tank's bottom, the middle, and the surface.
Drawing a sample about 6 inches from the F0
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storage tank bottom was performed since the F0 transfer pump j
suction is located about 6" from the bottom.
Sampling for
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accumulated water in the F0 day tanks was performed after each monthly surveillance as required by CPS No. 9080.01, " Diesel Generator Operability," revision 31, dated March 17, 1989, Paragraph 8.2.15.
During the report period, the inspectors witnessed plant operators test for water in the F0 day tank after a maintenance run.
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e.
(TI 2515/100 Q5):
The licensee added NALC0 8256 biocide as
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a fuel stabilizer.
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b f.
(TI 2515/100 Q6): Once per quarter the licensee sampled all F0 storage tanks for high particulate concentrations. The inspectors concluded that these quarterly samples had been effective as evidenced by the licensee identifying degraded fuel oil in the Division III F0 storage tank in August 1987.
g.
(TI 2515/100 Q7):
Day tanks were checked for water monthly in accordance with Surveillance Procedure CPS No._9080.01, Paragraph 8.2.15.
In addition, Operating Procedure CPS No. 3506.01,
" Diesel Generator and Support Systems," Revision 13, dated March 20, 1989, required in Paragraph S.1.5.10 that the F0 day tank be checked for accumulated water after each diesel operation.
h.
(TI 2515/100 QB):
Procedure instructions discussed above for checking day tanks for accumulated water required immediate removal of any water found.
i.
(TI 2515/100 Q9):
The inspector's review noted that the Division III Fuel Oil storage tank inventory was replaced in four days after degraded fuel was identified in August 1989.
j.
(TI 2515/100 Q10):
Fuel Oil filters were inspected on a periodic basis (annually) through the liccnsee's Preventive Maintenance program (ref: PMMDGA026,7,8).
k.
(TI 2515/100 Q11):
The licensee had recommended the addition of Preventive Maintenance activities to clean and inspect F0 strainers every other refuel outage (ref: CR #2-88-12-079).
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(TI 2515/100 Q12): The Clinton Power Station F0 system used dual element filters that permitted on-line cleaning. However, the F0 strainers were not dual elements.
m.
(TI 2515/100 Q13): The Clinton Power Station F0 nstem duplex filter had a differential pressure indicator whicn.orovided local indication and control room alarm.
n.
-(TI 2515/100 Q14):
Fuel Oil alarms were incorporated into a general control room trouble alarm " TROUBLE DG1A [B/CJ" with local individual alarms.
o.
(TI 2515/100 Q15): The licensee stated that the six level transmitters (two per division) that perform a control function were seismically qualified.
No violations or deviations were identified.
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11.
Management Changes (30702)
During the report period, the licensec announced th2 following changes in their corporate management:
Mr. Larry D. Haab was elected President of Illinois Power.
Mr. Haab succeeded Mr. Wendell J. Kelley as company president.
Mr. Kelley was to continue as Chairman of the Board and Chief Executive Officer.
In addition, Mr. William C. Gerstner, Executive Vice President, had elected to retire July 1, 1989.
Upon the retirement of Mr. Gerstner, Mr. Donald P. Hall, Senior Vice President responsible for Clinton Power Station will report directly to Mr. Kelley.
12.
Management Meeting (30702)
On March 21, 1989, following an enforcement conference, 111inoi.s Power Company senior management met with the NRC Region III management (denoted in Paragraph 1) at the Region III offices.
The purpose of the meeting was to allow the parties to discuss recent events at the plant, particularly the drywell flooding event of March 20, 1989.
The licensee provided their initial assessment of the causes of the events and agreed to provide a letter clarifying the causes and corrective actions for this and other operator induced events that occurred during the first refueling outage.
The licensee submitted Letter U-601431 dated April 24, 1989, detailing their conclusions.
The letter dealt primarily with three operational events that were the subjects of Violations 461/89008-09d, 461/89014-03, and 461/89014-07.
The inspectors discussed the letter with the licensee's staff and requested that clarifications of some points be included in the response to the violations.
Specifically the inspectors asked that the licensee clarify and expand their discussion of corrective actions to mitigate the " subjective factors" which influenced the performance of employees.
Also the inspectors requested that the licensee clarify ti.e letter's statement, "It is noted that the causes of these events are different than the causes of the refueling errors that occurred eaclier in the outage." NRC management noted that some of the earlier refueling events were quite similar to the more recent events and were attriouted to errors by operating shift supervision.
13.
Violations For Which A " Notice of Violation" Will Not Be Issued The NRC uses the Notice of Violation as & standard method for
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formalizing the existence of a vio'iation of a legally binding requirement.
However, because the NRC wants to encourage and support licensee's initiatives for self-identification and correction of problems, the NRC will not generally issue a Notice of Violation l
for a violation that meets the tests of 10 CFR 2, Appendix C,Section V.G.I.
These tests are:
(1) the violation was identified by the licensee; (2) the violation would be categorized as Severity Level IV l
or V; (3) the violation was reported to the NRC, if required; '4) the
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violation will be corrected, including measures to prevent recurrence,
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within a reasonable time period; and (5) it was not a violation that could reasonably be expected to have been prevented by the licensee's corrective action for a pr:*'ious violation.. A violation of regulatory requirements identified during the inspection for which a Notice of Violation was not issued was discussed in Partgraph 5.b.
14.
Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations, or deviations. An unresolved item disclosed during this inspection was discussed in Paragraph 5.e.
15.
Exit Meetings-(30703)
The inspectors met with licensee representatives (denoted in Paragraph 1) throughout the inspection and on May 12, 1989 and May 30, 1989. The inspectors summarized the scope and findings of the inspection activities.
The licensee acknowledged the inspection findings.
The
inspecters also discussed the likely informational content of the.
inspection report with regard to documents or processes reviewed by the inspectors during the inspection.
The licensee did not identify any documents / processes as proprietary.
The inspectors also attended exit meetings held between regional / headquarters based inspectors and the licensee as follows:
Inspector Date K. Ward March 23,-1989 H. Walker April 7, 1989 A. Gautam April 21, 1989 P. Rescheske April 27, 1989 L
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