IR 05000331/1993015
| ML20059K856 | |
| Person / Time | |
|---|---|
| Site: | Duane Arnold  |
| Issue date: | 11/03/1993 |
| From: | Lanksbury R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20059K813 | List: |
| References | |
| 50-331-93-15, NUDOCS 9311160217 | |
| Download: ML20059K856 (32) | |
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U. S. NUCLEAR REGULATORY COMMISSION l
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REGION III !
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Report No. 50-331/93015(DRP) ,
i Docket No. 50-331 License No. DPR-49 i
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Licensee: Iowa Electric Light and Power l Company i IE Towers, P. O. Box 351 Cedar Rapids, IA 52406 facility Name: Duane Arnold Energy Center ll t
Inspection At: Palo, Iowa- .j Inspection Conducted: August 24 through October 14, 1993
i Inspectors: J. Hopkins j C. Miller '
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Approved: d w ltl 3 h'>
R. D. Lanksbury cgfdeT' ' D'te a !
Reactor Pro 3ects Section 38 Inspection Summary -
l Inspection on Auaust 24 throuah' October 14. 1993 '!
(Report No. 50-331/93015(DRP)) i Areas Inspected: Routine, unannounced inspection by the resident inspectors of followup, followup of events, operational safety, maintenance, surveillance, regional request, temporary instruction, and report revie Results: An executive summary follows: ,
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9:)',1160217 931105 i POR ADOCK 05000331 i G PDR l
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EXECUTIVE SUMMARY Plant Operations
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The plant was in cold shutdown with the reactor defueled for refueling outage 1 (RFO) 12 at the beginning of the period. Refueling outage 12 concluded with )
the final synchronizing of the turbine generator to the bus on ,
October 13, 199 j Foreign material exclusion problems resulted in unwanted objects entering the reactor vessel and the spent fuel pool (SFP) cooling' system. One Severity -;
Level IV violation was issued because of a lack of cleanliness controls. In *
addition, the corrective actions for debris in the "A" SFP cooling water. pump suction strainer were narrowly focused, and did not address the root.causes of the debris (section 2.b). Inadequate operating procedures resulted in a shutdown cooling isolation and the attempted start of a core spray pump with its suction valve closed (section 2.a). l Maintenance / Surveillance An apparent violation was identified for the "B" standby diesel generator *
(SBDG) being out of service when required to be operable by technical .
specifications (TS) due to an inadequate 4160 Vac circuit breaker: maintenance procedure (section 4). A non-cited violation was issued for an inadequate motor operated valve maintenance procedure (section 2.a). Refueling ;
activities were accomplished successfully with an appropriate emphasis on shutdown risk management (section 5.b).
Enaineerina
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Lack of engineering review of vendor recommendations led to a procedure change which caused four motor operated valves to have incorrect thrust data. The high pressure coolant injection (HPCI) system was declared inoperable on -
October 5,1993, due to its outboard steam isolation valve (M0-2239) breaker tripping. An unresolved item was issued to evaluate the adequacy of the'- :
engineering review for increasing the torque switch setting for M0-2239 !
(section 6). Engineering support was effective in resolving many emergent ,
outage issues, including the timely implementation of a reactor vessel water level instrumentation modificatio Plant Stoport
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One Severity Level IV violation with several examples was issued for failure -
to properly implement procedures. These examples resulted from personnel ;
errors which could have been prevented, in general, by an adequate second '
person review. Minor cleanliness and radiological control problems were noted during the refueling outage (section 4). The licensee's control of overtime activities was reviewed, and appeared appropriate. The licensee had several different processes to address employee concerns (section 8 and Attachment A). ;
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DETAILS ;
1. Persons Contacted j
- R. Anderson, Operations Supervisor !
- R. Anderson, Outage Project Manager :
R. Baldyga, Supervisor, Maintenance Engineering P. Bessette, Supervisor, Regulatory Communications ,
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- J. Bjorseth, Maintenance Superintendent D. Blair, Quality Assurance Assessment Supervisor 1 C. Bleau, Supervisor, Systems Engineering .
D. Engelhardt, Security Superintendent
- J. Franz, Vice President Nuclear j R. Hannen, Outage Manager ?
C. Kardos, Supervisor, Reactor and Computer Performance i
- J. Kozman, Supervisor, Configuration Control Engineering
- D. Lausar, Supervisor, Project Engineering J. Loehrlein, Engineering Supervisor
- H. McDermott, Manager, Engineering K. Peveler, Manager, Corporate Quality Assurance K. Putnam, Supervisor, Technical Support !
A. Roderick, Supervisor, Testing and Surveillance P. Serra, Manager, Emergency Planning
- N. Sikka, Supervisor, Electrical Engineering
- A. Steen, Assistant Operations Supervisor
- S. Swails, Manager, Nuclear Training 1
- J. Thorsteinson, Assistant Plant Superintendent, Operations Support ;
- G. Van Middlesworth, Assistant Plant Superintendent, Operations and i Maintenance !
- T. Wilkerson, Radiation Protection Manager
- D. Wilson, Plant Superintendent, Nuclear :
- K. Young, Manager, Nuclear Licensing :
In addition, the inspectors interviewed other licensee personnel :
including operations shift supervisors, control room operators, i engineering personnel, and contractor personnel (representing the licensee). ;
- Denotes those present at the exit interview on October 14, 199 I
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2. Followun (92701)
l IClosed) Unresolved Item 331/93009-01(DRP): Incorrect Maintenance i Procedure. This unresolved item dealt with_a maintenance !
procedure for motor operated valves which was modified with an l incorrect calculation. Four valves were tested with the procedure, which led to erroneous thrust value indications when a- ;
test clamp was used for thrust measurement !
The maintenance staff reviewed a vendor customer service bulletin !
regarding the use of a motor operateo valve (MOV) calibrating !
clamp as an auxiliary sensor to measure thrust levels, and ,
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subsequently modified maintenance procedure Valvop-L993-001,
" Liberty Technological Center Inc. MOV Test Equipment (VOTES)," to allow the use of a calibrating clamp as a thrust sensor. The .
change was initially made using Temporary Document Change Form (DCF) 91-T-0417 on October 28, 199 The change, which involved the use of conversion calculations from sensor readout to thrust in pounds,_resulted in an improper thrust value when using one of the clamps as an auxiliary sensor. The calculations were not reviewed by engineering staff. The 10 CFR 50.59 applicability review on the DCF incorrectly indicated that the procedure change could not have had an effect on plant safety. The improper conversion caused the licensee to have i inaccurate thrust values recorded for four safety-related motor operated valves; the "A" control building chiller well water supply isolation valve (MD-2039A), the "A" control building chiller discharge to well water isolation valve (M0-2077), the core spray loop "B" outboard injection valve (MO-2135), and the RHR loop "A" torus header isolation valve (M0-2006). Although the four valves were left with torque values in an acceptable range, the potential for improper torque switch settings and torque value outside the acceptable range for valves tested by this method clearly existe '
The improper conversion calculations were considered a violation of 10 CFR Part 50, Appendix B, Criterion V, which required that procedures shall include appropriate quantitative acceptance .
criteria for determining that important activities have been satisfactorily accomplished. This violation was not cited because the licensee's efforts in identifying and correcting the violation meet the criteria specified in Section VII.B of the " General Statement of Policy and Procedure for NRC Enforcement Actions" (Enforcement Policy, 10 CFR Part 2, Appendix C).
Licensee corrective actions included reviewing and correcting the maintenance procedure, reverifying the acceptability of thrust values for the four valves which were previously tested using the improper auxiliary sensor calculations, and verifying that no other valves were affected. In addition, the licensee modified their method of treating vendor information updates so that it ;
received the same level of attention as operating experience review, and emphasized the need to engage early engineering involvement in any significant maintenance process chang Unresolved Item 331/93009-01(DRP) is close The inspectors also noted several other instances where procedures had been inadequate to perform the intended functio * During preparation for and performance of surveillance test procedure (STP) 48A002-CY, " Standby Diesel Generators and '
Emergency Service Water System Automatic Actuation Test,"
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the inspectors noted several examples where operator l experience and memory were relied upon to complete ,
! prerequisites which were not included in the procedure. In >
one case, the "B" core spray pump received a start signal ;
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with the pump suction valve tagged shut. No damage to the pump occurred. Neither core spray pump flow path was ;
l required to be verified by the procedure. Operators had previously verified the proper lineup.for "A" core spray i pump, for which the suction valve was also tagged shut prior to the ST o On September 21, 1993, following transfer of the "A" reactor :
protective system (RPS) from alternate to normal power '
supply in accordance with operating instruction (01) 358, !
the "A" residual heat removal (RHR) inboard injection valve ]
(M0-2003) closed, interrupting shutdown cooling. The
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procedure did not specify the proper steps to be taken to ,
prevent M0-2003 from closing. Shutdown cooling was lost for !
approximately 19 seconds, and reactor system coolant !
temperature remained steady at 146 degrees fahrenheit.
l e On September 16, 1993, the licensee discovered that the "B" .!
SBDG output breaker would not automatically close.to supply-essential bus IA4 due to inadequate maintenance of 4160 volt circuit breakers. This event and the licensee's corrective actions are discussed in section 4 of this report. -One of the primary causes of this event was a maintenance procedure which had not adequately addressed the requirements of the General Electric (GE) 4160 Volt Switchgear technical manua The procedure failed to include a check of the breaker plunger to auxiliary operating rod clearance, even though this check was recommended by the GE switchgear technical manua j
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These procedure problems collectively point to the need for an i'
increased review of plant maintenance and operating procedures, and an increased emphasis on correcting procedure problems when !
they are identified. The inspectors will continue to follow the '
licensee's efforts in improving procedures in future inspections ,
and as part of corrective action for the inoperable "B" SBDG l discussed in section 4 of this repor b. (Closed) Unresolved Item 331/91ClQ-91(DRP): Cleanliness Control Progra The inspectors issued this item to address weaknesses in the cleanliness control program at Duane Arnold Energy Center (DAEC). During RFO-12, several items were found floating in the reactor cavity during flood-up, including a small piece of wood i and several tie wraps. In addition, the licensee found one tie l wrap on top of a fuel bundle in the core during defueling and found other tie wraps in the dryer and separator pit and SFP during cleanup operations prior to fuel reload. During the
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cleanup operations, the licensee vacuumed very small particles l from a feedwater sparger bracket removal job performed during RF0 '
12, and removed a nail from the annulus region of- the vessel. The origin of the nail was not known, but was not expected to have i been introduced in the previous three refueling outages. The i licensee performed cleanup operations, filmed the core and annulus- l 1 regions of the reactor, and verified that no other debris remaine :
The tie wrap intrusions appeared to have been caused by inadequate !
control and inspections of the dryer and separator pit prior to removal of the reactor head and subsequent flood-up. The i refueling floor supervisor indicated that a detailed inspection of the dryer and separator pit was not performed, when an inspection was required by Nuclear Generation Division (NGD) procedure :
1408.11, " House Keeping Control Procedure, Normal Operations and Maintenance," Section 6. i
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Inadequate cleanliness control caused problems in the SFP cooling system during RF0 12. On August 13, 1993, the "A" SFP cooling water pump tripped on low suction pressure. The reactor was 1 1 defueled with all fuel assemblies in the SFP. Decay heat was l I
being removed by both trains of SFP cooling prior to the pump '
trip. A black rubber overshoe was in the suction strainer of the i
"A" SFP cooling water pump. The overshoe was removed, and the "A" 1 I train of SFP cooling was restored on August 14. The temperature i in the SFP increased approximately 7 degrees Fahrenheit (F) to i 119 degrees F before the "A" train of SFP cooling was restore ;
The inspectors determined that the pump had tripped four times on low suction pressure since March 1992. The pump suction strainer had been fouled with various materials including tape, paint chips, a rag, and a rubber overshoe. In each case the licensee's corrective actions were shallow in that they cleaned the pump suction strainer and returned the "A" SFP cooling water pump to service, but did not address long term actions to prevent recurrence. Based on the August 13, 1993, SFP pump trip, the licensee was evaluating the need for the suction strainer on the
"A" pump (the "B" pump does not have a strainer) and was planning to inspect and modify (as needed) the SFP skimmer surge tank The licensee was also planning to address the reason why the strainer for the "A" SFP pump was not on piping and instrumentation diagrams for the SFP cooling syste ,
Other areas of the plant also were not being controlled in I accordance with NGD procedure 1408.11 and procedure 1408.12,
" Refuel Floor Housekeeping Control." In addition to the ,
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inadequate postings and cleanliness control mentioned in inspection report (IR) 331/93010, the inspectors observed other instances of housekeeping zones not properly posted and cleanliness conditions not properly maintained, including maintenance on a safety relief valve and the high pressure coolant
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l l injection (HPCI) turbine repair. Failure to adequately control'
cleanliness of the reactor cavity was a violation of 10 CFR Part 50, Appendix B, Criteria II, " Quality Assurance Program" (331/93015-01(DRP)).
Many of the problems appeared to be due to the confusion of ;
authority between the two housekeeping procedures, the confusion i between " requirements" and " suggested techniques", and the failure i of procedure NGD 1408.12 to address cleanliness requirements I during non-outage periods. The licensee was addressing many of )
t the inspector's. concerns as part of quality deficiency report i l
(QDR)93-073, and was in the process of developing a new refueling j floor cleanliness procedure at the close of the perio Unresolved Item 331/93010-01 is close j
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c. (Closed) Unresolved Item 331/93010-03(DRP): Followup of Personnel Errors. Four specific examples of personnel errors during the -!
conduct of maintenance and surveillance activities were identified- !
in the previous resident inspector's report. During this report :
period, additional personnel errors were identified during the I conduct of maintenance activitie !
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"A" Emeraency Service Water (ESW) Pumo: ,
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On August 18, 1993, noise and high motor vibrations were identified during post-maintenance testing of the "A" ESW pum '
The licensee's evaluation determined that on August 10, 1993, the upper motor bearing had been installed upside down. The '
licensee's immediate corrective action was to determine if there was any damage to the motor or lower bearing. Both the upper and ,
lower "A" ESW motor bearing had to be replaced. No other i deficiencies were identified. The "A" ESW pump was repaired and j l returned to service on August 21.
l During the 1992 refueling outage, the "B" ESW pump upper motor '
bearing had been installed upside down. The licensee's corrective '
action had been to revise maintenance department procedure i Motor-G080-002, " General Electric High Thrust Vertical Induction ;
Motors." The revision consisted of: (1) an additional step which '
required that the technician verify the bearing was orientated properly, and (2) the addition of a simplified drawing which attempted to depict the correct bearing orientation. The "
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inspectors noted that the drawing was too general to provide usable information.
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pump in August 1993 contained the revision. The technician that l made the error in 1992 was also the same technician that made the ,
l mistake in August 1993. The electrical maintenance supervisor had l l conducted a pre-job brief which emphasized the importance of l proper bearing orientation. Additional maintenance instruction 1 l
steps were added to the work package which required a Quality
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Control (QC) inspector to " witness" the correct bearing-orientation during' motor assembly. The licensee determined that a contributing factor was that the replacement bearing had different .
physical characteristics because it was made by a different ;
manufacturer. Based on interviews, the QC inspector indicated -
that he had agreed with the technician that the bearing ,
orientation was correct. The licensee's long term corrective t action was to review applicable maintenance procedures that ;
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required noting bearing orientation when a motor was disassembled, and to add a maintenance engineer or supervisor witness poin ;
Additionally, the licensee planned to review other maintenance procedures that assembled components that had the potential for +
improper orientatio Technical specification (TS) 6.8.1 specified that written procedures covering areas of normal startup, operation, and shutdown of systems and procedures be implemented. Maintenance Department Procedure, " Motor-G080-002," step 5.3.4(2), required that the upper motor bearing be installed in the correct ;
orientation. Installing the "A" ESW pump motor upper bearing upside down was an example of a violation of TS 6. l (331/93015-02a(DRP)).
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Reactor Water Cleanuo Outboard Isolation Valve (M0-2740):
i On August 18, 1993, during post-maintenance testing, the licensee determine that the clutch tripper fingers for the motor operator ,
on valve M0-2740 were installed upside down during maintenance performed from August 14 to 17, 1993. The clutch tripper fingers being installed upside down would not have affected the remote ;
and/or automatic operation of the valve, only the local hand-wheel ,
operation. The licensee's corrective action ensured that the clutch tripper fingers were installed correctly, and the valve '
successfully passed post-maintenance testin Technical specification 6.8.1 specified that written procedures covering areas of normal startup, operation, and shutdown of systems and procedures be implemented. Maintenance department procedure VALV0P-L200-007, "Limitorque Valve Operator Type SMB-0, SMB-1, SMB-2, SMB-3, SMB-4, and SMB-4T," step 5.3(14), required that the clutch tripper fingers be installed in the correct orientatio Installing the clutch tripper fingers for valve l M0-2740 upside down was an example of a violation of TS 6. (331/93015-02b(DRP)).
Low Pressure Coolant in.iection "B" Loop Select Loaic Desian Chanae Packaoe:
On August 19, 1993, during the performance of maintenance acceptance testing (MAT) for the design change package (DCP-1537)
for the low pressure coolant injection (LPCI) "B" loop select
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logic, the licensee identified that wire "BE-1" was connected to termination point "BE-10" vice the correct termination point ,
"BE-13." The inspectors determined that wire "BE-1" was :
incorrectly connected on August 14, 1993. Wire "BE-1" was J correctly connected to terminal "BE-13" on August 19. Based on interviews, the insnactors determined that-the technicians who connected wire "PC-1" and the QC inspector who verified the job .
were using self-checking techniques and " repeat backs" during !
communications. Additionally, no job performance or communication I concerns were identified when the technicians' supervisor >
witnessed portions of the job. The technician and QC inspector . ,
were not able to explain why or how the error occurre Technical specification 6.8.1 specified that written procedures covering areas of normal startup, operation, and shutdown of systems and procedures be implemented. Work package 1537-03, step number 10, of DCP-1537 for the LPCI "B" loop select logic, required that wire "BE-1" be connected to termination point-
"BE-13." Failure to connect wire "BE-1" to termination point i
"BE-13". was an example of a violation of TS 6. i (331/93015-02c(DRP)).
Discharae Volume Hiah Water Level Instrument Functional Test / Calibration:
On August 21, 1993, during the performance of farveillance test procedure (STP) 41A006.2, "(Scram) Discharge v alume High Water Level Instrument functional Test / Calibration," a half-scram signal on the "B-1" channel of the RPS was received due to a personnel error. The reactor was defueled at the time of the event, and no equipment actuated as a result of the half-scram signal. The test ~
was stopped to determine the root causes for the event. The STP was successfully completed on August 2 The licensee's initial investigation determined that section of the STP that tested half-scram channel "A-1" was completed and no problems were identified. Next, the instrument and control (I&C) technician in the control room attached a jumper in accordance with section 7.2 of the STP to support the test of half-scram channel "A-2." The I&C technician at the local instrument rack attached the calibration unit to the level switch for half-scram channel "B-1." Section 7.3 of the STP tested half-scram channel "B-1." The I&C technician at the local instrument rack continued with section 7.3 and a half-scram signal on the
"B-1" channel of the reactor protection system was received. It :
should be noted that the level switches for half-scrsm channels i j "A-1" and "B-1" were both located on r. ace instrument rack (1C122).
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The licensee determined that the root causes for the event were l l inadequate pre-job briefing and communications during the STP. A l contributing factor was that the STP allowed testing to be
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performed in any convenient order provided only one channel'was j tested at a time. The licensee planned to modify the STP to i mandate the order in which the channels could be performe l Technical specification 6.8.1 specified that written procedures ,
covering areas of normal startup, operation, and shutdown of I systems and procedures be implemented. Surveillance test procedure 41A006.2, step 4.1, required that only one channel be - '
tested at a time. Failure to complete testing on half-scram channel "A-2" prior to beginning testing on half-scram channel
"B-1" was an example of a violation of TS 6. ;
(331/93015-02d(DRP)). ;
An additional example of a violation of TS 6.8.1 is identified in section 5. Although this violation meets the criteria for a non-cited violation, this option was not exercised because of the number of occurrences, and because nearly every occurrence could have been prevented by a second person who was available to provide back-up verification for the activities which were taking plac These examples of a break down in the verification process had the potential to affect the overall quality of plant activities. Unresolved Item 331/93010-03 is close ;
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One violation with four examples and one non-cited violation were identified in this are No deviations were identifie ,
3. Followun of Events (93702)
During the inspection period, the licensee experienced several events, some of which required prompt notification of the NRC pursuant to 10 CFR 50.72. The inspectors pursued the events onsite with licensee i and/or other NRC officials. In each case, the inspectors verified that ,
the notification was correct and timely, if appropriate, that the i licensee was taking prompt and appropriate actions, that activities were !
conductea within regulatory requirements, and that corrective actions j would present future recurrence. The specific events are as follows:
August 23, 1993 -
Glycol leak into drywell sump ,
September 6, 1993 - Control rod blade 26-19 handle found ben !
September 16, 1993 - Failure of "B" standby diesel' generator output '
breaker to close during surveillance testin j September 30, 1993 - Inadvertent actuation to portions of the fire i deluge system in the low level radioactive waste ;
storage buildin !
October 5, 1993 -
HPCI inoperable due to outboard steam supply valve (MO-2239) failur l
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October 6, 1993 -
Ground fault trip of circuit breaker CB-5980' due- i to personnel error in grounding an energized 34.5 KV lin On October 6, 1993, contract linemen performing maintenance on -
34.5 Kilovolt (KV) supply lines in the DAEC owner controlled area mistakenly grounded an energized 34.5 KV line. This caused a loss of power to variour equipment and buildings onsite,-including the instrument air compressors. No personnel injuries or equipment damage occurre The 34.5 KV line was part of the distribution system outside of DAEC's switchyard and protected area. Work on this equipment was normally controlled by fowa Electric's Cedar Rapids Operating (CR0P) personnel and not DAEC personnel. The tagout for the work was proper, and had been concurred upon by a DAEC electrical maintenance supervisor. The CR0P worker was attempting to ground the de-energized line at a pole which also carried an energized line. After the workar did not detect voltage using a buzz stick (an insulated device which was intended to make noise when placed near an energized line), the lineman grounded the energized line. The subsequent trip deenergized loads in the DAEC data acquisition center, training center, badging center, air compressor building, and the low level radiation processing and storage facilit The trip did not significantly affect plant operation because of alternate power available to the 'istrument air compressor The licensee stopped the work activity until the cause for the error was investigated. Personnel error and an inadequate pre-job briefing .
appeared to be the major contributors. In the future, the licersee
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plans to require the use of improved high voltage detection devices and additional controls for electrical work on components in the vicinity of DAEC. The inspectors will continue to follow the licensee's actions to >
prevent future problems in this are No violations or deviations were identified in this area.
4. Operational Safety Verification (71707) (71710)
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The inspectors observed control room operations, reviewed applicable logs, and conducted discussions with control room operators during the inspection. The inspectors verified the operability of selected emergency systems, reviewed tagout records, and verified proper return to service of affected components. Tours of the reactor building and ;
turbine building were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations and to verify that maintenance requests had been initiated for equipment in need of maintenance. It was observed that the Plant Superintendent,. *
Assistant Plant Superintendent of Operations, and the Operations Supervisor were well-informed of the overall status of the plant and that they made frequent visits to the control room. The inspectors, by observation and direct interview, verified that the physical security 1'
plan was being implemented in accordance with the station security pla !
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The inspectors observed plant housekeeping and cleanliness conditions and verified implementation of radiation protection controls. During the inspection, the inspectors walked down the accessible portions of the reactor core isolation cooling (RCIC) system to verify operability by comparing system lineup with plant drawings, as-built configuration -
l or present valve lineup lists; observing equipment conditions that could degrade performance; and verifying that instrumentation was properly
- valved, functioning, and calibrated.
l l These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under technical specifications, Title 10 of the Code of Federa7 Regulations, and administrative procedure Housekeepina During various tours of the plant, the inspectors noted minor '
housekeeping and radiological control practices which were not in keeping with acceptable housekeeping' practices. Numerous i abandoned hard hats and some abandoned anti-contamination clothing ,
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and tools were found during tours of the drywell and emergency l core cooling system (ECCS) pump rooms, even in areas marked as l housekeeping zone Contamination control boundaries were not clear in some areas, where bags, hoses, cords, and miscellaneous equipment straddled the contamination boundary markings. On two occasions, health physics technicians had to be prompted by the inspectors to give
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i the proper information regarding alarming dosimeter parameters, such as accumulated dose, dose rate settings and alarms. When the -
inspectors brought these to the attention of DAEC management, the licensee took appropriate corrective actions to bring the practices up to the normal expected cleanliness and radiological protection standard Response to Control Room Annunciator l
On September 14, 1993, with the reactor in Cold Shutdown, during ,
the morning control room shift briefing, annunciator IC06A, D-2, i "B" Residual Heat Removal Service Water and Essential Service 4 Water (RHRSW/ESW) Pit Low Level" alarmed. The RHRSW/ESW pit was being maintained below normal operating level to support i maintenance activities in the circulating water pit. The l, circulating water pit was supplied by the overflow from the ;
RHRSW/ESW pit. The crew briefing was halted while the RHRSW/ESW pit level recorder was observed, and a licensed reactor operator manually adjusted a makeup supply valve that restored water' leve The automatic actions associated with the annunciator were not verified by the licensed operator. Based on the annunciator response procedure (ARP), two valves that supplied makeup water to the RHRSW/ESW pit automatically open and two other valves that i divert flow from the pit automatically shut. The valves did not ;
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reposition. The licensee determined ihat the' thi re were two micro-switches on.the RHRSW/ESW 1evel switch; one for the annuncia tor and one for the automatic valve functions. The level switch wts recalibrated so that both micro-switches actuated at the same tim The inspecters were concerned that the licensed operator and the crew had not responded to the annunciator appropriately. The Operations Supervisor stated that management's expectation was that the crew acknowledge the annunciator alarm and verify that the automatic actions for the annunciator, as described in the ARP, had occurred. The licensee's short term corrective actions were to brief each operating crew on the event and to issue a letter to each person in the operations department describing the issue and management's expectations. The licensee further planned to incorporate additional annunciator response training in the next simulator requalification training cycle. The inspectors will continue to follow the licensee's actions to ensure that the conduct of operations in the control room meets DAEC management's expectation c. "R" Standby Diesel Generator Inocerable On September 28, 1993, the licensee determined that the "B" standby diesel generator (SBDG) had been innperable from July 21, 1993, to September 25, 1993, due to the inability of its output breaker to automatically close on to essential bus lA During surveillance testing on September 16, 1993, the "B" SBDG supply breaker (IA411) to essential bus lA4 failed to close after a loss of offsite power (LOOP) and loss of coolant accident (LOCA)
signal was simulated. After a repeat failure of the breaker to close on September 22, troubleshooting determined that the auto-closing logic for breaker IA411 was not being completed. An auxiliary "b" contact that provided position indication to the "B" SBDG circuit breaker automatic closing logic from the standby transformer supply breaker (IA401) indicated that breaker 1A401 was closed, when breaker 1A401 was actually open. This made the
"B" SBDG inoperable since its circuit breaker would not automatically close on a loss of power to bus IA4. An improperly adjusted clearance between the breaker' operating plunger and the auxiliary contact switch operating rod caused a "b" contact for breaker IA401 to remain open with the breaker open. On September 24, the plunger clearance was adjusted and the surveillance testing was completed satisfactorily. The "B" SBDG was declared operable on September 2 On July 21, 1993, routine preventive maintenance was performed on breaker IA401 in accordan e with maintenance procedure CKTBKR-G080-002, "Generai Electric Company'4160 Volt Circuit Breaker (Magne Blast) Model AM-4.16." The clearance of 0 to
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l 1/8 inch between the breaker operating' plunger to switch operating
! rod, as referenced in the General Electric Metal-Clad Switchgear l Technical Manual for Magne-blast Air Circuit Breakers, was not in i the procedure and was not part of the required post-maintenance ,
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measurements. The post-mainter.ance testing consisted of cycling the circuit breaker several timu in the test position. This had i not tested the operation of the aciliary contact However, the procedure included a requirement to measure the vertical height of i the plunger above the circuit breaker lifung rail (117/32 to 11 11/32 inches). In the as-left condition, the breaker operating plunger was pushing up on the auxiliary switch operating rod approximately 3/16 inches (i.e. a negative gap), with the breaker
" racked-in" and in the open positio .
. On September 24, the licensee identified the "a" and "b" auxiliary-l contacts that were safety-related or important to plant operation on all of the 4160 Vac circuit breakers. The licensee further-reviewed the maintenance history of all 24 essential 4160 Vac-circuit breakers to determine when maintenance in accordance with ,
procedure CKTBKR-G080-002 was last performed, and if the functions of the "a" and "b" contacts had been tested since then. . Ten circuit breakers with auxiliary contacts that were safety-related or important to plant operation that had not been tested by other surveillances were identified. Corrective action maintenance request (CMAR) A18888 was issued to test the contacts on the.10 circuit breakers. All of the contacts passed the functional test by September 27. The licensee performed these tests to verify that the circuit breakers and contacts were " operable" in the as-found conditio The licensee discussed a concern with General Electric (GE) about potential problems with the GE technical manual. specified pluncer gap and modified the plunger gap acceptance criteria to.0.001 to-1/8 inch to ensure no negative gap existed. Additional dimensional checks (not in the GE technical manuals) were developed by GE to provide additional assurance that the auxiliary-contacts operated properly. On September 28 the licensee completed measurements on all 49 of the 4160 Vac circuit breakers, and identified 26 (including breaker 1A401) that were outside of the acceptance criteri The licensee determined that 10 of the 26 circuit breakers had I auxiliary contacts that were safety-related or important to plant
! operation. Based on some inconsistencies in GE'.s additional dimensions, the licensee initially modified the plunger gap criteria to 0.001 to 1/16 inch to provide further assurance of proper auxiliary contact operation and adjusted the 10 circui breakers by October 2. Auxiliary contacts'that were adjusted in a non-conservative direction (i.e. to eliminate'a negative gap) were
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retested. Due to delays in plant startup, five of the non-
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essential circuit breakers were also adjusted. The licensee planned to adjust the remaining 10 circuit breakers when plant conditions would support i In addition to the immediate corrective actions described above, the licensee issued a temporary change to procedure CKTBVsR-G080-002 to incorporate the plunger gap criteria. "Startup- :
and Shift Orders" were issued that required electrical maintenance ;
verification of correct breaker plunger gap when a 4160 Vac breaker was racked back inte the switchgear cubicle. Electrical schematic drawings and the plant simulator were used to verify that breaker IA411 could have been closed from the control room using existing procedures. Longer term planned corrective actions to prevent recurrence included a commitment to adjust the remaining 10 4160 Vac breakers by the end of refueling outage 13, to buy a circuit breaker cubicle to provide maintenance and i operator training, to permanently revise the circuit breaker operating instructions, and to resolve the questions concerning the additional GE dimensional criteria. The licensee was in the -
process of evaluating the probabilistic risk assessment of the inoperable SBDG and the 10 CFR Part 21 applicabilit From July 21, 1993, with the plant operating at approximately 1 75 percent power, until July 31, when the reactor was placed in i cold shutdown for refueling outage 12, both SBDGs were required to be operable by technical specification (TS) 3.5.G.I. Duane Arnold j Energy Center TS required that with one SBDG inoperable, continued
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reactor operation was permissible for the succeeding 7 days unless that SBDG was made operable soone If that condition was not 4 met, an orderly shutdown should have been conducted and the ;
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reactor should have been taken to hot shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and taken to cold shutdown w' thin the following 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Failure to shutdown the reactor to hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and cold shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the "B" SBDG was inoperable was an example of an apparent violation of TS 3.5. From August 7 to 11, 1993, with core alterations in progress, the
"A" SBDG was inoperable for maintenance and the "B" SBDG was being relied upon to meet TS 3.9.D.1 requirements. The TS required that'
one SBDG be operabl If the requirements of the TS were not met, core alterations were not permitted. Failure to halt core alterations with both SBDGs inoperable was an example of an apparent violation of TS 3.9.D.1-.
One apparent violation with two examples was identified in this are No deviations were identified in this are . Monthly Maintenance Observation (62703)
Station maintenance activities of safety-related systems and components l
listed below were observed and/or reviewed to ascertain that they were l
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t conducted in accordance with approved procedures, regulatory guides, and industry codes or standards, and in conformance with technical:
specifications (TS). ;
The following items were considered during this review: the limiting l 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 inspected as applicable; functional _ testing and/or calibrations were performed prior to returning components or systems to service; quality
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control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; i radiological controls were implemented; and fire prevention controls were implemente '
Work requests were reviewed to deternine status of outstanding jobs and to assure that priority was assigned to safety-related equipment maintenance which might affect system performanc ,
Portions of the following maintenance activities were observed and/or reviewed:
- HPCI turbine repairs
- Reactor core isolation cooling (RCIC) pump overhaul
- Reactor recirculation pump seal repair
- Main steam isolation valve repairs
- Main steam safety relief valve repairs ;
- 4160 volt breaker troubleshooting and repair Installed Incorrect Orientation of Control Rod Blade Guid On September 5,1993, during core reload, a control rod blade '
guide was installed with the wrong orientation. The fuel moving plan (Fuel and Reactor Component Handling Procedure (FRCHP)
Number 5, " Procedure for Moving Core Components Between Reactor Core and Spent Fuel Pool, within the Reactor Core, or within the +
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Spent Fuel Pool," Attachment 1) specified a southeast (SE)_
orientation and the blade guide was installed in with a southwest 1 (SW) orientation. The senior reactor operator in charge of the '
refueling operations on the refuel floor and the reactor performance engineer had both signed that the blade guide was in ;
the correct orientation in accordance with the fuel moving' pla l The blade guide was in the proper fuel cell location. There'were .
no fuel assemblies in the fuel cell, and the control rod blade was !
fully withdrawn. The incorrect orientation was' identified by the ,
reactor performance engineer prior to moving fuel from the SF l The next fuel assembly had already been lifted from the SFP i
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storage rack but had not been moved into the reactor vessel are The fuel assembly was returned to its proper location in the SFP and the blade guide was repositioned to its correct orientatio The remainder of the core reload occurred without inciden Technical specification 6.8.1 specified that written procedures covering areas of normal startup, operation, and shutdown of systems and procedures be implemente Procedure FRCHP 5, Attachment 1, specified a SE orientation of the blade guide that was supposed to be installed in core location 10-27. Failure to install the control rod blade guide at core location 10-27 in a SE orientation was an example of a violation of TS 6. (331/93015-02e(DRP)).
b. Refuelina Outaae The licensee began RF0-12 with a reactor _ shutdown on July 28,1993. The planned 59 day outage extended until October 13, 1993, when the turbine generator was synchronized to the grid for the final time; ending a 77 day shutdown. Outage work, in addition to refueling, included modifications to correct instrumentation inaccuracies discussed in NRC Bulletin 93-03,
" RESOLUTION OF ISSUES RELATED TO REACTOR VESSEL WATER LEVEL INSTRUMENTATION IN BWRs," 36 control rod blade replacements for stellite reduction, 4160 VAC switchgear bus insulation replacement, main steam isolation valve (MSIV) repairs, HPCI turbine overhaul, reactor core isolation cooling (RCIC) pcmp and turbine overhaul, containment integrated leak rate test, and motor operated valve dynamic and static testin Outage risk management continued as a strength this outag Required systems for various plant configurations were developed using the aid of a probabilistic shutdown safety assessmen These systems were then maintained off limits for work by control room personnel, and were listed in the daily o'* 1ge flyer as off-limits. Outage planning appeared effective ir ntrolling the outage work scope while providing contingencies for required emergent work such as MSIV and RCIC repair Integrated leak rate testing results appeared to be the best ever for DAEC with adjusted "as found" leakage at about 0.51 percent per day, and "as left" leakage at 0.25 percent per day. This compares very favorably with RF010 leakage of 1.7 percent per day and 1.2 percent per day respectively. Local leak rate testing of the "A" and "D" outboard MSIVs indicated very good post maintenance results. As left, leakage on these valves was 1672 standard cubic centimeters per minute (SCCM) on "A" and 344 SCCM on "D", as compared to the limit of 5428 SCC ]
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Motor operated valve testing proceeded according to schedule '
during the outage. The licensee performed static baseline tests on 43 valves during the outage and dynamic testing on several valves just prior to the outag Overall, the licensee's outage work appeared successful. Timely '
engineering support and good coordination with the maintenance and operations departments were key in resolving many emergent outage ;
equipment problems. Some problems with cleanliness control, '
procedure problems, and personnel errors are discussed elsewhere in this report. The inspectors will continue to observe equipment performance during operating cycle 13 as one of the clearest indicators of outage succes One example of a violation and no deviations were identified in this are , Monthly Surveillance Observation (61726)
The inspectors observed technical specification (TS) required surveillance testing and verified that testing was performed in ;
accordance with adequate procedures, that test instrumentation was calibrated, that limiting conditions for operation were met, that removal and restoration of the affected components were accomplished, that test results conformed with TS and procedure requirements and were' ,
reviewed by personnel other than the individual directing the test, and '
that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personne The inspectors also witnessed portions of the following test activities:
STP-42A002-Q - RHR Shutdown Cooling System - Reactor Vessel Pressure
, (High) Quarterly Instrument functional Test and Calibration STP-450001-CY - HPCI System Cycle Operability Test -
STP-46G022 -
Non-Nuclear Heat Class 1 System Leakage Test STP-48A002-CY - Standby Diesel Generators and Emergency Service' Water l System Automatic Actuation Test -
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Control Rod Drive Friction Testing Hiah Pressure Coolant Injection (HPCI) Inonerable On October 5, 1993, during reactor startup testing after the refuelin outage, STP 450001-CY, "HPCI System Cycle Operability Test," was-performed prior to exceeding 150 psig reactor pressure. During the STP, the circuit breaker for the motor operator on the HPCI outboard steam isolation valve, M0-2239, tripped on overcurrent when the valve was shut. The HPCI system was declared inoperable, and an event
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notification was made. Troubleshooting determined that' the torque switch in the motor operator had not opened when the valve was shu (The purpose of the torque switch was to stop the motor operator after the proper closing force was applied to the valve.) The root cause for the torque switch failure was not determined. On October 6, the torque switch was replaced, valve M0-2239 was retested, the HPCI system was declared operable, and reactor startup testing continued. At 400 psig reactor pressure, several small steam and water leaks were identified, and the reactor was shutdown to repair the leaks. On October 7, valve NO-2239 automatically shut on low steam line pressure (100 psig reactor pressure), as designed. The circuit breaker for the motor operator again tripped on overcurrent. The HPCI system was declared inoperable, and an event notification was mad Troubleshooting again determined that the torque switch in the motor-operator had not opened when the valve was shut. The licensee determined that the closing thrust value for valve M0-2239 may have been too close to the design limits of the motor. The closing thrust value had been raised from approximately 47,000 to 70,000 pounds of force to improve the margin above the minimum requirements of Generic Letter (GL) 89-10, " Safety-Related Motor Operated Valve Testing and Surveillance,"
on September 16, 1993. On October 8 the licensee presented their action plan to Region III to repair valve M0-2239 and restore HPCI to an operable status. The plan included: (1) replacing the motor on valve M0-2239, (2) lowering the thrust value for the valve, (3) testing the valve during the plant startup, (4) verifying the bases for adjusting the closing thrust setpoints on all valves adjusted during the refueling outage, and (5) reviewing the degraded voltage criteria contained in GL 89-10._ On October 9, the motor on valve M0-2239 was replaced, the closing thrust set at approximately 53,000 pounds of force, HPCI was declared operable, and the reactor startup was resume The adequacy of the licensee's root cause determination, trouble shooting efforts, and MOV program were planned to be evaluated by Region III MOV specialists during a future inspection. Pending this review, the adequacy of the engineering evaluation that increased the closing thrust value for valve M0-2239 was considered an unresolved item (331/93015-03(DRS)).
No violations or deviations were identified in this area. One unresolved item was identifie . Reaional Reouests (92701)
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Control of Overtime t
The inspectors reviewed the licensee's control of overtime during the refueling outage and determined that the overtime guidelines were being followed and were consistent with current regulatory requirement There were a few examples where personnel exceeded the overtime guidelines without prior approval. The licensee reviewed the events and
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determined that prior approval would have been granted. These examples i were not indications of a breakdown of the licensee's control-of .
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overtim A list of specific questions concerning the licensee's control. of overtime was provided by Region III management. .The questions and 1
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-answers are provided below:
1) Were overtime guidelines contained in the licensee's technical specifications (TS)? ,
Yes. Technical specification 6.8.1.13 stated that administrative l procedures for shift overtime for operations personnel were ' !
consistent with the Commission's policy. statement dated June 15, 1982. The licensee's overtime guidelines were implemented b j
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Nuclear Generation Division (NGD) procedure 101.4, " Overtime :
Limits and Requirements." However, the Commission's policy statement was not in the TS and procedure NGD 101.4 was not r
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referenced in the T ) Were the licensee's overtime guidelines applied during all 1 operating and shutdown canditions?
Ye The requirements in procedure NGD 101.4 were applicable at
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all time ) Were the overtime guidelines extended to all personnel, including ,
contractors, who performed safety-related activities?- (This !
question excluded engineers.) -
Ye Procedure NGD 101.4 applied to salaried, hourly, and union ,
personnel working at- the Duane Arnold Energy Center (DAEC) in the Nuclear Division and Quality Assurance Organizations in first-line supervisory positions and below. The procedure also applied to *
operations shift supervisors and all contract personne Additionally, the licensee determined that procedure NGD 101.4 was i not consistent with' the purpose of the overtime guidelines since it was not applicable to positions above first-line superviso The licensee committed to change procedure NGD 101.4 to includ i all personnel working at DAE l I
4) Were the overtime guidelines applied to both licensee and contractor engineers? j
Yes. The overtime guidelines in procedure NGD 101.4 were )
applicable to the licensee's engineers in first-line supervisory positions and below and all contract engineer No violations or deviations were identified in this are >
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. Temocrary Instruction (TI) 2500/028. Employee Concerns Proara .
The inspectors reviewed the licensee's policies related to addressing employee concerns. Duane Arnold Energy Center had no formal employe concerns program under one governing document. Rather, there wer number of separate policies and procedures which were able to be used to evaluate different types of concerns. The questior, aire included in the TI was completed by the inspectors on September 8,1993, and serves to
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document the status of the employee concern program at DAEC. The questionnaire and its answers are included. as Attachment A to this repor No violations or deviations were identified in this are . Report Review (90713)
During the inspection period, the inspectors reviewed the licensee's-monthly operating reports for August and September 1993. The. inspectors 1 confirmed that the information provided met the requirements of ;
TS 6.11.1.C and Regulatory Guide 1.1 No violations or deviations were identified in this are l
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10. 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 the inspection is discussed in Section 6, 11. Violations For Which A " Notice of Violation" Will Not Be Issued The NRC uses the Notice of Violation to formally document the failure to meet a legally binding requirement. However because the NRC wants to encourage and support license initiatives for self-identification and correction of problems, the NRC will not issue a Notice of Violation if the criteria set forth in Section VII.B of the " General Statement of Policy and Procedure for NRC Enforcement Actions," (Enforcement Policy, 10 CFR Part 2, Appendix C) are met. Violations of regulatory requirements identified during the inspection for which a Notice of i Violation will not be issued are discussed in Section '
12. Exit Interview (30703) i The inspectors met with licensee representatives (denoted in Section-1) :
on October 14, 1993, and informally throughout the inspection period and ;
summarized the scope and findings of the inspection activities. The !
inspectors also discussed the likely information content of the :
inspection report with regard to documents or processes reviewed by the l inspectors. The licensee did not identify any such documents or
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processes as proprietary. The licensee acknowledged the findings of the i inspectio l
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ATTACHMENT A EMPLOYEE CONCERNS PROGRAMS PLANT NAME: DAEC LICENSEE: DPR-49 DOCKET #: 50-331 PROGRAM: Does the licensee have an employee concerns program?
(Yes E No/ Comments)
There is not a single program as such, but rather a collection of policies and programs which are available to help in the resolution of concern . Has NRC inspected the program? Report #
The NRC has not' inspected "the program" as such. The NRC has inspected portions of programs such as 10 CFR 21 reporting, quality deficiency reports (QDRs), deviation reports (DRs), and maintenance action requests (MARS) on numerous occasion SCOPE: (Circle all that apply) Is it for: Technical? (Yes,No/ Comments) Administrative? (Yes,No/ Comments) Personnel issues? (Yes,No/ Comments)
The scope of the concerns which may be addressed' could include technical, administrative, or personnel issue . Does it cover safety as well as non-safety issues?
(Yes g No/ Comments)
Nuclear Safety, industrial safety and non-safety issues are addressed by the license . Is it designed for: Nuclear safety? (Yes,No/ Comments) Personal safety? (Yes,No/ Comments) Personnel issues - including union grievances?
(Yes E No/ Comments)
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The licensee has policy statements and processes to address nuclear safety via line management, QDRs, MAPS, or DRs. Personal safety concerns are addressed by line management, the onsite safety. representative or the Safety Committee. Personnel issues not related to safety concerns are normally handled by Human Resources personnel or the Equal Employment Opportunity representativ . Does the program apply to all licensee employees? J (Yes E No/ Comments) !
Ye . Contractors?
(Yes o_C No/ Comments)
Contractor concerns are covered by normal site pnlicies and are also handled at termination of contractor F .ployment by the Safety-on-Site progra . Does the licensee require its contractors and their subs to have a-similar program? ,
(Yes E No/ Comments) l No, but a general contract agreement includes protection for )
whistleblower activities by contract employee !
'I Does the licensee conduct an exit interview upon terminating l employees asking if they have any safety concerns? ;
(Yes E No/ Comments) ,
u Yes, the Safety-on-Site program provides this opportunity, !
although it is not mandator I C. INDEPENDENCE:
) What is the title of the person in charge? i
Line management are responsible for concerns brought up by their-- I subordinates. The Safety Committee (SC) Chairman can be contacted j when independence from management is. imperativ i Who do they report to?
The SC Chairman reports directly to the Chief Operating Officer of-Iowa Electri U l
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' Are they independent of line management?
Line management address most of the Joncerns. The SC Chairman or other independent management can be appointed, as the situation merit i Does the ECP use third party consultants?' !
Third party consultants have been used in the past to resolve technical concern , How is a concern about a manager or vice president followed up? ;
These concerns would be addressed as . indicated abov ;
D. RESOURCES;
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, What is the size of the staff devoted to this program?
Line management are use . What are ECP staff qualifications (technical training, 1 interviewing training, investigator training, other)? l Line management are used. Technical Support and Quality Assurance personnel are trained in interviewing skills. Technical Support personnel also are trained on conducting root-cause analyse ,
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E. REFERRALS: Who has followup on concerns (ECP staff, line management, other)?
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Line management I
F. CONFIDENTIALITY: Are the reports confidential? ;
(Yes or No/ Comments)
The reports can be made confidential, if neede ' Who is the identity of the alleger made know to (senior i management, ECP staff, line management, other)?
(Circle, if other explain) .
Generally, identity of an alleger would be made know to the '
management representative to whom he reported the issue, an senior management if neede +
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.i Anonymous? (Yes, No/ Comments). l Report by phone (Yes, No/ Comments) -!
The Safety-on-Site program and'line management are expected to be -
able to address anonymous and phone concern G. FEEDBACK .
) Is feedback given to the alleger upon completion of the followup?
(Yes E No - If so, how?)
i Feedback is expected to be given, and has bean in the pas ) Does program reward good ideas? -
Rewards have been given in the pas . Who, or at what level, makes the final decision of resolution? l Line management or the SC Chairman for most issues, or the Plant Superintendent for Safety-on-Site concern , Are the resolutions of anonymous concerns disseminated? ;
They may be disseminated through generic communications, q Are resolutions of valid concerns publicized (newsletter, bulletin board, all hands meeting, other)?
Resolutions have been published in a weekly site newslette ;
H. EFFECTIVENESS:
- How does the licensee measure the effectiveness of the program?
l There is no formal measurement tool. One Quality Assurance :
surveillance was conducted in 1993 to evaluate the Safety-on-Site- )
progra . Are concerns: ! Trended? (Yes E No/ Comments)
! Used? (Yes E No/ Comments) )
l' l There is no formal trending progra r & r egy+-
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- In the last three years how many concerns were raised? ,
Of the concerns raised, how many were closed? What percentage were substantiated? ,
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Twenty concerns were documented through the Safety-on-Site program. Nineteen were closed. Twenty percent were '
substantiate ! How are followup techniques used to measure effectiveness (random ,
survey, interviews, other)? ;
One Quality Assurance surveillance was conducted at the request of ;
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the Plant Superintenden . How frequently are internal audits of the ECP conducted and by whom?
There is no requiremen ; ADMINISTRATION / TRAINING: i Is ECP prescribed by a procedure? (Yes gr No/ Comments)
There is not one comprehensive employee. concern program covered by one procedure. Many different procedures cover different area . How are employees, as well as contractors, made aware of this program (training, newsletter, bulletin board, other)?
Plant policy for employee concerns is published on an annual ,
basis. Bulletin boards post this and other information applicable "
i to employee concerns, including NRC Form General employee training covers methods of reporting non-compliances. Termination interviews solicit employee concern !
ADDITIONAL COMMENTS: (Including characteristics which make the program ;
especially effective, if any) !
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NAME: TITLE: PHONE #: !
C. G. Miller / Resident Inspector. / 319-851-5111 DATE COMPLETED: 09/08/93 ,
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