IR 05000461/1993009
| ML20045J102 | |
| Person / Time | |
|---|---|
| Site: | Clinton  |
| Issue date: | 07/12/1993 |
| From: | Hague R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20045J094 | List: |
| References | |
| 50-461-93-09, 50-461-93-9, NUDOCS 9307230047 | |
| Download: ML20045J102 (15) | |
Text
{{#Wiki_filter:p - . , U.S. NUCLEAR REGULATORY COMMISSION .
REGION III
Report No.
50-461/93009(DRP) 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, Illinois Inspection Conducted: May 18 - June 28, 1993 . Inspectors: P. G. Brochman ' F. L. Brush ' Z. Falevits Approved By: . ' 7[F[[3
Richaffil.
affue, Chief Date Reactor Pr 6 cts Section 1C Inspection Summary Insnection from May 18 throuah June 28. 1993. (Report No.- 50-461/93009(DRP)) Areas Inspected: Routine, unannounced safety inspection by resident and regional inspectors of licensee actions on previous _ inspection findings, plant
operations, maintenance and surveillance, and engineering and technical , support.
Re_sul ts: Of the four areas inspected,_ two violations were identified in the following areas: (failure to have adequate writteri. instructions-paragraphs - - 4.'a and 5.c; inoperable post-accident monitoring instrumentation - paragraph 5.c).
One non-cited violation wasLidentified in the following area (failure to perform activities in accordance with written instructions-paragraph' 3.d).
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9307230047 930719-PDR ADOCK 05000460 0-PDR- -
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r-- - . Executive Summary Plant Operations The plant operated at power levels up to 100 percent for the entire
report period.
On June 8,1993, one of three offsite 345 kV distribution lines was
seriously damaged in a storm.
Repairs to the line were scheduled to be completed by October 1,1993. The remaining distribution system is stable. Guidance was issued to reduce Clinton's output by approximately 200 MWe if a second line should be lost.
On June 9,1993, Division III 4.16 kV, safety-related bus 1C1 was lost
for 27 minutes due to a maintenance error. During restoration, the "B" reactor recirculation pump tripped. The unit entered single loop operation and was stabilized at 70 percent power. The unit was restored to two loop operation and returned to full power later that day. All ' equipment functioned as designed.
Operations personnel did an excellent job in stabilizing the plant and evaluating this event.
Performance during a fire brigade and injured-man drill was good.
- A fire hose burst during a surveillance test. The cause was attributed
to aging and an incorrect hydrostatic test by a vendor.
Maintenance and Surveillance A personnel error during reinstallation of the cover on an overcurrent
protective relay (IJCV) caused the loss of vital 4.16 kV bus 1C1. The licensee's investigation was' prompt and thorough. The procedure for energizing the reactor protection system bus was deficient in failing to recognize a recirculation pump trip. (NV4 461/93009-01a(DRP)) A reverse power protective relay (GGP)'on the Division III diesel
generator did not work properly, even though it was in calibration.
The relay was replaced and the diesel retested satisfactorily.
Enaineerina and Technical Support Licensee efforts at monitoring the performance of the RCIC turbine
governor were effective at identifying an impending failure.
Both drywell and containment H,/0, analyzers were inoperable, since
original plant licensing, due to a design error. (NV5 461/93009-02(DRP)) The procedure for calibrating the H,/0, analyzers was deficient. (NV4 461/93009-Olb(DRP))
F - .. The licensee monitored portions of the shutdown service water (SX)
, system to accurately measure pressure transients after damage to the control room ventilation chiller was discovered and several relief valves had lifted. A detailed analysis of the data was in progress.
{IFI 461/93009-03(DRP)) , h
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p , - . DETAILS 1.
Persons Contacted . 1]linois Power Company (IP) J. Perry, Senior.Vice President i
- J. Cook, Vice President and Manager of Clinton Power Station (CPS)
J. Miller, Manager - Nuclear Station Engineering Department (NSED)- i
- R. Wyatt, Manager - Quality Assurance
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- R. Morgenstern, Manager - Training
- J. Palchak, Manager - Nuclear Planning and Support
- F. Spangenberg, III, Nuclear Strategic Change Leader
- R. Phares, Director - Licensing
- L.
Everman, Director - Radiation Protection
- P. Yocum, Director - Plant Operations
- W. Clark, Director - Plant Maintenance
- K. Moore, Director - Plant Technical
- W. Bousquet, Director - Plant Support Services
- C, Elsasser, Director - Planning & Scheduling R. Kerestes, Director - Nuclear Safety and Analysis
- D. Korneman, Director - Systems and Reliability, NSED J. Langley, Director - Design and Analysis, NSED
- J. Sipek, Supervisor - Regulatory Interface I
The inspectors also contacted and interviewed other licensee and t contractor _ personnel during the course of this inspection.
Denotes those present during the exit interview on June 28, 1993.
- 2.
Action on Previous Inspection Findinas (92702) ' , (Closed) Unresolved Item (461/93006-02(DRP)): Were the . drywell/ containment atmosphere H,/0, analyzers inoperable, with their . backup air compressors' flywheels missing? The licensee determined that ! the analyzers would not have functioned following a loss of instrument air, rendering them inoperable. The inoperable analyzers are a violation of technical specifications; consequently, the unresolved item is considered closed. The violation is discussed further in paragraph - 4.a.
No deviations were identified.
However, one violation was identified.
3.
Plant Operations The unit operated at power levels up to 100 percent for the entire ' report period.
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Onsite Event Follow-up (93702) The inspectors performed onsite follow-up activities for an event which occurred during June 1993.
Details of the event and the i licensee's corrective actions developed through the inspectors' follow-up are provided below: , Loss of the Division III Vital Bus and Trio of the "B" Reactor Recirculation PumD At 3:15 a.m. on June 9, 1993, during planned maintenance _on Division III protective relays, the normal feeder breaker to Division III 4.16 kV bus 101 tripped. The alternate feeder breaker failed to close. The diesel generator did not start because it was out-of-service for maintenance. The bus was deenergized for 27 minutes. During the reenergization of bus 1C1-loads, the B reactor recirculation (RR) pump shifted to_ slow speed and then tripped. The unit entered single loop operations'and the reactor was stabilized at 70% power. The RR pump was restarted in fast speed at 11:40 a.m.
The unit was subsequently returned-to 100 percent power.
The cause of the loss of power to bus 101 was an error by an electrician as he installed the cover for a protective relay (General Electric type IJCV overcurrent relay).
The electrician inadvertently caught the seal-in. relay contact with the flag reset linkage. This action also reset the relay within 0.5 seconds.
' When the relay contacts closed, it tripped the normal feeder breaker to bus 1C1.
The alternate feeder was also prevented from , closing. The emergency feeder breaker ~was racked out for the ' diesel maintenance.
The cause of the RR pump trip was a procedure deficiency, which j did not account for a design feature of the reactor protection system (RPS). When the Division III RPS bus was reenergized, the " power on initialization" feature of _the end-of-cycle recirculation pump trip (E0C-RPT) card sent a trip signal to RR breaker 4B, causing the pump to down shift to slow speed. The pump's protective relays then' sensed an incomplete sequence!and tripped the pump. The incomplete sequence was sensed because only the B RR pump received a. signal. When an RPS card is initially , energized, the_ power on initialization' feature causes the' card to
send an output signal for 0.5. seconds in the " safe" condition.
For the Div III E0C-RPT trip, the safe condition was to trip RR pump breaker 4B.
The licensee's investigation was detailed and was able to repeat j the initiating' sequence during a bench test. The licensee concluded that all equipment had functioned as designed,. except for the indicating flags on the 1st and 2nd level undervoltage relays for bus 101.
These relays were successfully bench tested.
The licensee concluded that the flags had not dropped due to a ' '
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f" ~. - . high circuit impedance. This was not considered significant as both relays actuate annunciators in the main control room. The inspector. concluded that the operators response to this event was s prompt and effective at stabilizing the unit. This event is discussed further in paragraph 4.b.
b.
Loss of Offsite Transmission Line (71707) On June 8, 1993, a severe storm passed south of the station and knocked down 17 miles of the Latham line. The Latham line was one of three, 345 kV, transmission lines that transfer power from Clinton station to the Illinois Power grid. Repairs to the line were scheduled to be completed by October 1,1993.
The licensee performed a stability analysis on the remaining two lines and determined that the transmission system would remain.
stable. The licensee also determined that should an additional line be lost, the transformers at the other end of the remaining line might exceed their thermal overload rating, because the station's output would exceed the ratings of the 450 MVA transformers at the Oreana, Ridng, or Brokaw' substations.
Since the problem would be with the transformers and not the transm'ssion lines, the licensee changed protective relay settings at some of these substations to ensure that the lines would remain closed during the initial transient. Operators would then receive guidance from the Decatur power generation dispatcher to reduce load by 200 MWe in approximately 5 minutes. Operators were briefed on this information and it was entered into the operations standing orders. The licensee was also evaluating the increased risk from the loss of the Latham line, with regards to the scheduling, as well as desirability, of certain maintenance and refueling activities. The inspectors did not identify any concerns.
c.
Operational Safety (71707) The inspectors observed control room operation, reviewed applicable logs, and conducted discussions with control room operators. During these discussions and observations, the operators were alert, cognizant of plant conditions, attentive to changes in those conditions, and took prompt action when appropriate. The inspectors verified the operability of selected emergency systems, reviewed tagout records, and verified the proper return to service of affected components.
Tours.of the circulating water screen house and auxiliary, containment, control, diesel, fuel handling, rad-waste, and turbine buildings were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, excessive vibrations, and to verify that maintenance requests had been initiated for equipment in need of maintenance.
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_ -. _ . - . The inspectors observed plant housekeeping and cleanliness conditions and verified implementation of radiation protection , controls and physical security plan. Housekeeping has generally
improved in the readily accessible areas, such as the containment- ' and auxiliary buildings. However, some ar1as such as bedplates of a few pumps still tave water, oil, and minor debris on them.
, d.
Valve Found Out of Position due to Personnel Error (71707) . On June 9, 1993, valve OSX008 was found out of position - closed - i ' by an auxiliary operator performing a preventive maintenance-(PM) task.
Valve OSX008 was a drain path,.with downstream loop seal, between a fire protection deluge valve and standby gas treatment , (VQ) train "A" charcoal adsorber bed. When the valve was opened, approximately 50 gallons of water issued from the drain.
The charcoal bed was subsequently inspected and-verified to be dry.
. The PM required that valve OSX008 be closed, the downstream loop seal refilled, and OSX008 reopened. These actions were-accomplished using CPS procedure 3319.01, section 8.1.4.5.
The valve had last been manipulated on May 9,1993, to perform this , PM. The operator was interviewed and did not remember leaving the
valve closed. No separate sign off or independent verification was required by the procedure.
The licensee concluded that the operator had failed to reposition the valve during the previous performance of the PM. As corrective action the licensee reviewed r this event with all operating crews.
Procedure 3319.01 will be . reviewed to change the way reopening the valve is signed for.
! Other procedures, where the failure to reposition a piece of equipment would not be self disclosing, will also be evaluated.
i Part 50 of Title 10 of the Code of Federal Regulations, Appendix B, Criterion V, requires that activities affecting i quality shall be accomplished in accordance with documented instructions or procedures. The failure to open valve OSX008 as directed by procedure 3319.01, section 8.1.4.5.3, is a violation j of Criterion V.
However, the violation is not being cited because the criteria specified in Section VII.B.1 of the " General Statement of Policy and Procedures for NRC Enforcement' Actions," (Enforcement Policy, 10 CFR Part 2, Appendix C) were met, e.
Fire Briaade Drill (71707) The inspector observed an unannounced fire brigade drill with an injured victim. The fire brigades performance was good, although their arrival at the fire scene was slower ~ than the licensee's goal. As several of the fire brigade members had to stabilize actions they were performing and respond from remote locations, licensee management concluded that the response time was-
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' . i reasonable.
The response of the security personnel in treating and transporting the victim was very good.
The inspector identified some minor issues and discussed them with licensee ' management.
No concerns were identified.
f.
Fire Hose Fails Durina Surveillance Test (71707) During performance of a standpipe flow test on May 28, 1993, the fire hose that was being used burst. The hose separated at the female coupling connected to the standpipe. This hose had been in use for three years and had just recently been returned after
passing a vendor's hydrostatic test. The licensee concluded that , the hose had failed due to normal aging. However, the vendor had not tested the hose at the required pressure.
I The hose was only tested to 150 psig, rather than the 250 psig specified in the requisition and consequently its degraded
condition was not revealed.
As corrective action, the licensee notified all fire brigade members of this problem and inspected all fire brigade cages and hose stations.
No problems were found.
, The licensee concluded this event was not reportable under 10 CFR Part 21.
The licensee has changed vendors.
The inspector ' discussed this issue with the fire protection engineer and no concerns were identified.
, No deviations were identified. One violation was identified.
4.
Maintenance and Surveillance ' a.
Personnel Error Causes Loss of Bus 101 (62703) J On June 9,1993, during reinstallation of a Div Ill DG protective relay cover (General Electric Type IJCV), the reserve auxiliary transformer feed breaker to Div Ill 4.16 kV bus 101 tripped.
Operational aspcets of this event are discussed in paragraph 3.a.
The licensee's extensive root cause investigation of this event-concluded that the electrician actuated and then immediately reset the IJCV relay contacts. This evolution occurred in less than 0.5 l seconds, since the K6-time delay relay did not energize and lock out the diesel generator.
l The inspector reviewed electrical design drawings, operating and ! ' maintenance procedures, licensee critiques of this event, and vendor relay manuals.
In addition, the inspector interviewed i engineering, maintenance, and operating personnel.
Based on this ' information, the inspector agreed with the licensee's root cause for this event.
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m -- . ~ . The inspector identified the following issues: Although he had been trained and qualified to work on this
type of relay, the electrical maintenance technician had not worked on one before. The relevant procedure, CPS No.
8502.16, "IJCV Relay Inspection, Calibration and Functional Test", Rev. 2, did not contain any caution notes relative to reinstalling the relay cover.
The procedure for reenergizing the nuclear system protection
- system (HSPS) inverter and RPS bus, CPS No. 3509.01, Instrument Power System, Rev. 9, Appendix E, Part B, did not contain any steps to bypass the E0C-RPT trip nor contain any caution notes on the power on initialization (POI) feature.
However, engineering personnel were aware of the P01 . feature, but failed to ensure that this requirement was incorporated into the appropriate operating procedures.
Part 50 of Title 10 of the Code of Federal Regulations, Appendix B, Criterion V, requires that activities affecting quality shall be prescribed by documented instructions or procedures. The failure to include pertinent operating requirements in procedure 3509.01 is a violation of Criterion V (461/93009-Ola(DRP)). Although the bus 1C1 undervoltage (UV) relays picked up
during this event, none of the targets on the four UV relays dropped. The licensee investigated and concluded that during the simultaneous operation of all four relays, _ a high circuit impedance prevented the flag coils from energizing.
This did not have an impact on this event, as the relays actuated annunciators in the main control room. This condition only affected the UV relays for bus 101.
, The electrical schematic diagrams for bus 101 relays were
very difficult to follow. The licensee has not written down how the relay contacts, permissives, and time delays
functioned together.
Instead the engineers must research r the prints each time a question arises.
The inspector noted that written descriptions of the plants design basis might be helpful to less experienced engineers or in the time pressure of an ongoing event.
For example, the system engineer was initially less than familiar with the automatic power supply transfer feature for the NSPS inverters.
, Specifically, the automatic transfer of power will only occur from the primary to the alternate source; not the reverse.
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, The inspectors noted that the licensee had not tested the de
supervisory circuit on the bus ICI second level undervoltage-relay since installation in 1985.. The supervisory circuit prevented false tripping, due to DC bus transients. This condition was identified by the engineering department in March 1993 as part of corrective actions for a previous problem. This included a top down review of all relays to . ensure that all vendor recommended attributes were.being checked. The surveillance procedure was being revised to add this attribute.
The setpoint of this circuit was 81 - 87 Vdc.
The as-found value was 80 Vdc. The nominal setpoint _was' lower than the low voltage alarm on Div III de bus and was below the minimum voltage necessary to actuate the breaker trip coils (nominal 105 Vdc) if the supervisory circuit would generate
a trip signal.
Consequently, the licensee concluded that the low voltage setting had no impact on the event and the actions taken after identifying the omission of supervisory circuit check was reasonable.
As corrective action for this event, all electrical and control and instrument technicians were briefed on the relay problems, all relay procedures will be re/iewed to determine if additional , guidance is warranted, and new impact matrices will be developed for all relays.
Based on the results of the impact matrices, relay calibrations may be scheduled to coincide with bus outages, rather than being performed on line.
Engineering management issued a memorandum to all engineers to ensure that obscure design ! information, which can impact plant operation, is communicated to operations, training, and system expert personnel.
The inspectors concluded that engineering and maintenance personnel did a thorough job in evaluating this event and in verifying that equipment performed an designed. Management support was very good and all of the NRC's concerns were addressed.
Based on the corrective actions taken, the inspectors have no further concerns on these issues.
b.
Reverse Power Trios of Division I Diesel Generator (61726) On June 23, 1993, the inspector observed two Division I DG trips , on reverse power. The DG was being run for a routine monthly surveillance per CPS procedure 9080.01. When the reactor operator
attempted to parallel the DG with the offsite grid, the DG tripped on reverse power. _The lockouts were reset and the DG was restarted within 10 minutes. However, the DG again tripped on reverse power as the operator attempted to parallel it. The DG was declared inoperable. The Division _Il and III DGs were - verified operable.
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. The-inspector was monitoring the reverse power relay on the second trip and identified questions on the way the relay operated. The relay was a General Electric type GGP. The relay was removed and checked. The_ relay was in calibration and was reinstalled. The diesel was tested and again failed twice. A new relay was calibrated and installed.
The new relay was a model C, versus the , previous model B.
The inspector observed the successful test.
The failed relay will be sent to an offsite facility _for a detailed failure analysis. Management, maintenance, and system and design engineering's support to resolve this problem was excellent.
c.
Observations Of Work Activities (61726 & 62703) ' The inspectors observed maintenance and surveillance activities of . both safety-related and nonsafoty-related systems and components .! listed below. These activities were reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides, industry codes or standards, and in conformance with technical specifications.
Document Activity D03216 Div III diesel generator (DG) space heater repair D25279 Repair valve IVY 10A D32797 Inspect cooling coil in MSIV blower room D33202 ISA002 check valve temporary modification D33736 Replacement of RCIC governor valve stem 1E51F610 D34497 Inspect and cddy current test heat exchanger . IDG13A D51957 Replace Div III DG GGP relay 9382_10 Div III battery charger capacity test
9080.01 Div I DG monthly test No deviations were identified. One violation was identified.
' 5.
Enoineerina and Technical Sucoort r a.
Motor Operated Valve (MOV) Gear Replacement (62703) As part of the licensee's Generic Letter (GL) 89-10 program,.it determined that the torque supplied by the actuator for containment isolation valve ICY 016 needed to be increased.
During installation of the new motor pinion and worm shaft gears, the inspectors noted that a second set screw hole was drilled for the
motor pinion gear. The-inspector asked'if any guidance existed on.
how many set screw holes could be made in the pinion shaft. No
licensee guidance existed on this issue. The licensee contacted the MOV vendor and was informed that no more than two set screw holes should be drilled in the motor pinion shaft.
The licensee will revise its procedures to reflect the vendor's recommendation.
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The inspectors asked if'any other motor pinion shafts had_ more . than two holes drilled, during previous work. The licensee l' reviewed various work packages and discussed this issue with maintenance personnel.
It concluded that no actuators had more than two holes drilled in their_ pinion shafts.
The inspectors - have no further concerns.
. b.
Replacement of the RCIC Turbine Governor Valve Stem (62703) On June 5,1933, an auxiliary operator was unable to manually stroke the governor valve stem for the reactor core isolation a cooling (RCIC) turbine - valve IE51F610. This valve was stroked , by hand every day, to ensure freedom of movement. Two weeks before the valve seized up, the operators had noticed increasing resistance. Maintenance began preparing to replace the valve stem with one of similar material. The stem was replaced and the turbine tested satisfactorily.
The problem with the governor stem has been observed at other facilities and was due to moisture interacting with the. graphite packing and causing pitting of the nitrided type 410 stainless steel stem. The pitting causes the stem to bind with the packing washers. The licensee believed that the packing dried out when the moisture source was eliminated and pitting then began. This increased the stem friction and caused the valve to seize up. The licensee had repaired the steam admission valves 1E51F095 and F045 on April 21, 1993, due to excessive leakage; thereby reducing the source of moisture.
The system engineer was aware of industry problems with binding of the governor stem. He had discussed the issue with the inspectors-(see inspection report 461/92022(DRP)) and had initiated the daily.
check for' freedom of movement. The engineering and operating' departments' initiative resulted in the prompt identification of-safety-related equipment inoperability.
The valve was then repaired in a timely manner.
c.
Inoperable Drywell and Containment Atmosphere Analyzers The licensee had previously determined that both of the drywell and containment H,/0, analyzers would have been unable to perform their post-accident monitoring function.
The analyzers used instrument air as a motive source for operating valves.
Each analyzer had a safety-related backup air compressor to. supplant the nonsafety-related IA system in the post-accident environment.
The absence of the compressor flywheels and the caps installed on the vent lines created a condition where the motor would draw excessive current and subsequently trip on thermal overload-rendering the analyzers-inoperable.
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- , f The following are the licensee's responses to questions asked in inspection report 50-461/93006.
What was the safety significance of having both analyzers
inoperable? There was no safety significance. The analyzers only perform a post accident function.
If they were not available, the emergency operating procedures direct that manual sampling be implemented. Additionally, the probability risk assessment, which has been accepted by the NRC, assumed that the analyzers were unavailable.
What acceptance criteria was used to determine that the
compressor passed its periodic surveillance test? The surveillance procedure required confirmation that the air compressor starts when instrument air was isolated and stops when it was restored.
The response to the next question discusses the air pressure acceptance criteria.
There was no run time specified in the procedure.
' Had any changes to the surveillance procedure been
appropriately reviewed or recommended changes incorporated? A review of past revisions determined that changes had been , made to the air compressor's running pressure'. Initially, , the acceptance criteria was 40 psig (35-45).
It was changed to 2 35 psig in 1987. However, during a later procedure change for an unrelated reason, the a sign was inadvertently dropped. Maintenance personnel stated that even though the procedure's acceptance criteria was 35 psig, they- , interpreted it as a minimum value.
Additionally, the cap on the bleed line for the backup-air compressor's storage tank went undiscovered because of the change in the air compressor's running pressure acceptance criteria.
The licensee changed the surveillance' procedure to restore the original acceptance criteria of 40 psig (35-45) and notify supervision if the pressure is not within that range.
Did the increased air pressure, during backup air compressor
operation, affect the operability and/or service life of the .' analyzer valves? The H /0, analyzer's air system had a relief valve-which was
set at 80 psig. The analyzer's solenoid operated valves are Y
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. rated for a working pressure of 300 psig. The air pressure on the analyzer reached 65 psig with the cap on the bleed line.
Therefore, there was no effect on the service life or operability of the analyzer.
Part 50 of Title lo of the Code of Federal Regulations,. Appendix B, Criterion V, requires that activities affecting quality shall be prescribed by documented instructions or procedures.
Procedure 9437.17, section 8.3.1.6, revision 22 specified an acceptance criteria of "...approximately 40 PSIG (35-45)." This was changed on February 26, 1987, to a 35 psig.
Consequently, the technicians would not have identified the problem with the air compressors. The failure to specify the correct acceptance criteria in procedure 9437.17 is a violation of Criterion V (461/93009-Olb(DRP)). Technical Specifications 3.3.7.5, Table 3.3.7.5-1, Instrument 7, required that both the Division I and II containment and drywell - H,/0, analyzers be operable in Operational Conditions 1, 2, and 3.
This condition had existed since initial plant licensing (September 29, 1986). The failure to have both H,/0, analyzers operable was a violation of Technical Specification 3.3.7.5 (416/93009-02(DRP)). The licensee's corrective actions included: installing flywheels, remcving the vent caps, and-revising the surveillance procedure to correct the acceptance criteria d.
Pressure Transients in the Shutdown Service Water System , On May 25, 1993, the licensee identified that the performance of the "A" control room ventilation system.(VC) chiller (0VC13CA) had , degraded.
Inspection of the chiller revealed that a divider plate in the condenser was bent. This changed the condenser from a three pass to a single' pass heat exchanger and had the effect of
reducing the heat transfer area of the condenser.
The damage was ! on the tube (SX) cide of the. condenser and indicated that the SX system had unde nnre some type of pressure transient.
No other indications of damage, such as bent struts and snubbers, or loose embedment plates and supports, were found. The licensee' performed a calculation to verify if the chiller could perform its design function,.with the degraded condenser.
The calculation indicated.
+ the chiller would perform satisfactorily. The inspector reviewed
the calculation and agreed with it.
The inspectors had previously identified two instances where a i relief valve in SX Division III appeared to have undergone a pressure transient. To evaluate this problem, the licensee - instrumented the SX system with pressure recorders;'and monitored SX pressure during pump shifts, to support routine chemical.
treatment of the SX system.
Pressure transients were observed.
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Ho' wever, initial calculations indicated they were not severe enough to cause damage to the system. The. licensee was performing
more detailed calculations. The inspector will review those calculations when they are completed. ' This issue will be tracked i as inspection followup item (461/93009-03(DRP)). No deviations were identified. One violation was identified.
6.
Inspection Follow-uo Items Inspection follow-up items are matters which have been discussed with i the licensee, which will be reviewed further by the inspector, and which involve some action on the part of the NRC or licensee or both.- An , inspection follow-up item disclosed during this inspection is' discussed in Paragraph 5.d.
7.
Non-Cited Violation - The NRC uses the Notice of Violation to formally document failure -to meet' a legally binding requirement.
However, becau'se the NRC wants to encourage and support licensee's initiatives for self-identification and
correction of problems, the NRC will not issue a Notice of Violation if - the requirements set forth'in 10 CFR Part 2, Appendix C, are met..A violation of regulatory requirements identified during the inspection, for which a Notice of Violation will not be issued, is discussed in paragraph 3.d.
8.
Exit Interview The inspectors met with the licensee-representatives denoted ~in
paragraph 1 at the conclusion of the inspection on June 28, 1993.
The inspectors summarized the purpose and scope of the inspection and the findings.
The inspectors.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 such documents or processes as proprietary.
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