IR 05000341/1988021: Difference between revisions

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{{Adams
{{Adams
| number = ML20204K117
| number = ML20246A161
| issue date = 10/12/1988
| issue date = 06/27/1989
| title = Insp Rept 50-341/88-21 on 880716-0831.Violations Noted. Major Areas Inspected:Action on Previous Insp Findings, Operational Safety,Maint,Surveillance,Followup of Events, LER Followup,Personnel Qualifications & Regional Requests
| title = Informs of Postponement of Decision Re Whether or Not to Withdraw Violation Noted in Insp Repts 50-341/88-21 & 50-341/86-39.Listed Values for LPCI & Core Spray Sys Requested within 60 Days of Receipt of Ltr
| author name = Cooper R
| author name = Greenman E
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
| addressee name =  
| addressee name = Sylvia B
| addressee affiliation =  
| addressee affiliation = DETROIT EDISON CO.
| docket = 05000341
| docket = 05000341
| license number =  
| license number =  
| contact person =  
| contact person =  
| case reference number = RTR-NUREG-0737, RTR-NUREG-737
| document report number = NUDOCS 8907060171
| document report number = 50-341-88-21, NUDOCS 8810250349
| document type = CORRESPONDENCE-LETTERS, NRC TO UTILITY, OUTGOING CORRESPONDENCE
| package number = ML20204K112
| page count = 2
| document type = INSPECTION REPORT, NRC-GENERATED, INSPECTION REPORT, UTILITY, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
| page count = 18
}}
}}


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  . .i r   UNITED STATES
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U.S. NUCLEAR REGULATORY COMMISSION
 
==REGION III==
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Report No. 50-341/88021(DRP)
Docket No. 50-341    Licerise No. NPF-43 Licensee: Detroit Edison Company 2000 Second Avenue Detroit, MI 48226 Facility Name: Fermi 2 Inspection At: Fermi Site, Newport, Michigan Inspection Conducted: July 16 through August 31, 1988 Inspectors: W. Rogers T. Silko S. Stasek K. Ridgeway Approved By: R. Cooper 5
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ReactorProjectsSection3B Date Inspection Summary Inspection on July 16 to August 31, 1988 (Report No. 50-341/88021(DRP)) ;
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Areas Inspected: Action on previous inspection findings; operational safety; maintenance; surveillance; followup of events; LER followup; startup test !
observation; personnel qualifications; regional requests; and review of allegation Results: Two violations were identified (Paragraph 3). One unresolved item Ta's identified (Paragraph 6) and four open items were identified ,
  (Paragraphs 3, 4, 7 and 10).
 
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i 8910250349 881014 DR ADOCK0500gg41
 
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DETAILS
      : Persons Contacted
> . Detroit Edison Company
   *P. Anthony, Licensing i  L. Bregni, Senior Licensing Engincor R. Bryer, Safety
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NUCLEAR RE7ULATORY COMMisslON
  *S. Catola, Vice President, Nuclear Engineering and Services !
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T. Dong, Safety    '
ge S REGION lli E  799 ROOSEVELT ROAD r -s /' , rp       '
C. Gelletly, Nuclear Engineering General Supervisor
  *D. Gipson, Plant Manager    i
  *L. Goodman, Licensilig    i D. Grimes, Fluids Systems Engineer  !
G. Hunt, MTE Support R. Lenart, Nuclear Engineering General Director P. McComish, Safety R. Matthews, I&C General Superintendent T. Meesseman, Training
  * Orser, Vice President, Nuclear Operations
, * Preston, Operations Engineer i  *T. Riley, Supervisor Compliance  l
  ,  J. Sabo, Plant Engineer    l 1  H. Sierra, Technical Staff Engineer  i
  *R. Stafford, Director NQA and PS  J W. Terrasi, General Supervisor Chemistry  i
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  *W. Tucker, Operations Superintendent J. Wald, Production Quality Assurance Supervisor E. Wilds, Lead Engineer Fluids L. Wooden, Nuclear Engineering Staff
! U.S. Nuclear Regulatory Commission K. Ridgeway, Senior Resident Inspector, Lacrosse
  * Rogers, Senior Resident Inspector T. Silko, Inspector
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  * Stasek, Resident Inspector
* Denotes those attending the exit meeting on [[Exit meeting date::September 20, 1988]].
The inspectors also interviewed others of the licensee's staff during this inspectio . Followup on Inspector Identified Items (92701)
l (Closed) Unresolved Item 341/88003-07: Adequacy of locked valve i guidelines. In a previous inspection, the inspector questioned why Valves B21-F077A/B, 821-F104A/B/C/D, P44-F400A/B and numerous i other valves were not identified in the licensee's locked valve :
program. The inspector requested that the locked valve guidelines be provide The guidelines provided were from Procedure 21.000.14, l
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"Locked Valve Guidelines." This procedure stated that val'es v without position indication in the control room in ESF systems where misalignment could defeat the safety function of the system or decrease its capacity or state of readiness should be in the program. The valves identified by the inspector met this criteria but were not in the program. This procedure was used to implement a NUREG-0737 item as disCJssed in the FSAR Section H.II.K.1. Therefore, this is considered a violation (341/88021-01) of Technical Specification 6.8.1.b for failure to implement Fermi 2 cotlitments made in response to NUREG-0737 requirements. Presently, '
the licensee is reviewing ESF systems versus the locked valve criteria, (Closed) Unresolved Item 341/87009-02: Testing of main steam isolation valve leakage control system (MSIVLCS) deactivate circuits. The inspector requested NRR review of this circuit as to is applicability under Technical Specification surveillance testing. In a memorandum dated June 12, 1988, NRR responded that the circuit is required to be tested under Technical Specification requirements. The inspector informed the licensee of this position which the licensee acknowledged and showed the inspector a revised surveillance procedure reflecting appropriate circuit testin The
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procedure had been revised and performed prior to issuance of the NRR letter. Since the matter was corrected and did not appear to have generic significance, this matter is considered resolve (Closed) Unresolved Item 341/87026-05: UFSAR accuracy. The licensee reviewed the Safety Evaluation. Logs for 1985, 1986 and 1987 l
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and determined that 87 entries needed further review to determine whether they were incorporated into the UFSAR. Four entries were determined to need incorporation. The inspector determined that these actions were sufficient to resolve the inspector's concern (Closed) Open Item 341/80003-03: Feedwater control system problem The licensee discovered and repaired a large oil leak and performed troubleshooting / tuning of the control system circuitry. Following
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these actions the licensee was able to successfully pass feedwater control testing. This matter is considered close (Closed) Unresolved Item 341/88003-04: Independent verification deficiencies. Violations 88012-02 and 10 superseded this matter by eleveting independent verification concerns to the violation category. This matter is considered closed based on issuance of these violation (0 pen) Open Item 341/87020-01: EX0-Sensor Action Pla To resolve reliability concerns reported under a Part 21 report, the licensee 1 implemented an action plan to assure operability of the drywell H2/02 sensors in the Post Accident Monitoring Syste This plan i consisted of:
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  (1) Performing a function test of the sensors every 31 day (2) Changing out the sensore every six month (3) Reducing sensing line heat trace temperature ?.0+F to reduce loss of electrolyte .
. (4) Pursuing with the vendor a new membrane made of a different
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materia Monthly functional tests conducted during 1988 have shown no problems with the sensors; however, several procedural problems had to be resolved during this periou. Deviation Event Report (DER) 88-1237, was issued on June 29, 1988, when the six month changeout of the H2 sensor could not be made since it was on a QC hold because the vendor source surveillance check had not been completed prior to deliver It was returned to the vendor for the source check, but it was not .
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available at the site in time to meet the scheduled six month replacement. A change in the vendor's ownership in late 1987 has complicated the quality control, and a. vendor inspection by.DEC0 when the sensor was returned showed several deficiencies in the new vendors quality program. Corrective actions'are underwa The reduction in sensing'line neat tracing temperature has been initiated to decrease the loss of sensor electrolyt The electrolyte loss for the first sensor exchange in July was not yet availabl '
Discussions have been held with the' vendor on possible new membrane
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material, but this will be a long term ite * (Closed) Unresolved Item 341/86039-05: Emergency core cooling flow control setpoint In Inspection Report No. 86039, the inspector - ,
documented that the licensee considered the ECCS flowrates in the !
Technical Specifications as nominal values instead of absolute values. As such the licensee did not account for instrument inaccuracy in assuring the appropriate flowrate was achieve to the reactor vessel for HPCI & RCIC. The inspector requested
;  confirmation from NRR that the Technical Specification values were absolute instead of nominal. In a memorandum dated June 22,  l
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1988, NRR confirmation was received which stated in part "All numbers in the TSs should be considered absolute unless otherwise noted."  i Therefore, the licensee did not meet Technical Specification Surveillance Requirement 4.5.1.a.3 for having the HPCI flow  i controller in the correct position or 4.7.4.a.3 for the RCIC flow controller. The difference was 40 gpm for RCIC and 200 gpm for HPC This is considered a violation (341/88021-02) of Technical Specifications 4.5.1.a.3 and 4.7.4.a.3. The generic implication of using nominal in lieu of absolute values for establishing controller ,
setpoints is also of concer .- : \
No other violations or deviations were identified in this are I 4    )
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, Operational Safety Verification (71707)
The inspectors observed control room operations, reviewed applicable als and conducted discussions with control room operators during the period from July 16 through August 31, 1988. The inspectors verified the operability of selected emergency systems, reviewed tagou'; records and verified proper return to service of affected components. Tours of the reactor building and turbine building were conuucted 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 maintenanc The inspectors, by observation and direct interview, verified that the physical security plan was being implemented in accordance with the station security pla The inspectors observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls. During the inspection, the inspectors walked down the accessible portions of the standby gas treatment and standby liquid control systems to verify operability by comparing system lineup with plant drawings, as-built configuration or present valve lineup lists; observing equipment conditions that could degrade performance; and verified that instrumentation was properly valved, functioning, and calibrate The inspectors also witnessed portions of the radioactive waste system controls associated with radwaste shipments and barrelin These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under Technical Specifications, 10 CFR, and administrative procedure During these reviews: A discussion was held between the inspector and the licensee regarding HPCI and RCIC oil sampling. At the time of the discussion, if an oil sample showed a high particle count, instructions would be provided to operations for a method of cleaning the oil, but guidance was not offered as to whether the system should be declared inoperative. Procedure 71.000.15, Attachment 2, "Oil Change Data Sheet," was revised such that if the results of the oil sample show a particle count greater than that specified in the "out of specification" range, the system is to oe declared inoperative per '
Technical Specifications by the NSS, until such time that oil purity has been restored to at least the "requiring purification" rang The inspector has no further questions in this area, The inspector discussed with the licensee the placing of the HPCI and RCIC pumps physically inoperative when the external purifier (non-seismic) is added to the system. The licensee is considering declaring the system administratively inoperative rather than physically removing the system from service and declaring the
 
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system inoperative when the external purifier is in use. The inspector concurs that administrative 1y declaring the system out of sarvice, rather than physically removing the system from service is a more prudent action and will increase the availability of the system to perform its intended safety functions. The. inspector has no further questions in this are The inspector noted during walkdowns in the con',ro' room, that area lighting levels varied significantly shift to s' r When questioned about the variance, operatcrs stated that nn " s was currently
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provided and, therefore aach shift adjustas .evel of lighting l to that which seemed mos,t appropriate and c ,rtabl Some shifts preferred subdued lighting levels to allow toe easier identification of indict. ting light status on the panels while others preferred more  ,
light to better read equipment tags and indicators / recorders. Also, the operators indicated that due to the design and/or placement of the temperature controller (s) in the CCHVAC system, area temperature levels become uncomfortably low at times and that by adjusting  ,
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lighting levels, an alternate method of temperature control could be achieve The inspector then questioned licensee management whethe :
this situation was in accordance with the guidance in NUREG-0700 or
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with the licensee's Detailed Control Room Design Review (DCRDR)
conducted previously. In response, an evaluation of control room
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lighting was initiated, illumination limits were established and  [
operators were instructed on maintaining lighting within the appropriate limits. The evaluation was conducted by engineering and new limits communicated to the operators via a plant night order. This will remain an open item pending inspector review of the newly specified limits and of the results of the licensee's DCRDR relative to this concern (341/880021-03 (DRP)). At 0020 hours, July 23, 1988, with the reactor at approximately 90 percent power, a power reduction / shutdown was initiated due to increasing Drywell (0/W) unidentified leakage. At 0106 hours, calculated D/W unidentified leakage exceeded the Technical Specification limit of 5.0 gpm (actual 5.4) and at 0505 hours, in accordance with the licensee's approved Emergency Plan, an Unusual Event was declared. At 1516 hours, the reactor was manually scrammed from 10 percent power. The licensee subsequently determined the source of the leakage as the RCIC Inboard Steam  t Supply Isolation Valve and the RWCU vessel drain line valve (G33-F100). l The inspector observed various stages of the reactor S/D and verified ;
licensee actions as being in accordance with Technical Specification t i
During the react)r shutdown, the inspector discussed the following  l issues with the ifcensee:
(1) Drywell de-inerting via the Torus-to-Orywell vacuum Breaker I Whilo at approximately 10 percent power, the licensee planned  I to enter the D/W and investigrte the source of the leakag Failure to de-inert the D/W due to an inoperable T4803-F602  l
  "D/W Exhaust Inboard IsolatNn Valve," rendered D/W access  j wcile in Modes 1 and 2 impos e l )
 
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Due to the inoperative F602, Primary Containment was inerted on May 17, 1988, via the process of opening the D/W to torus-vacuum breakers (refer to Inspection Report No. .50-341-88012)
and adding nitrogen to the torus free air space. Inerting the Drywell via this flow path is discussed in a note to Technical t Specification 3.6.4.1 which allows:"the suppression chamber ;
Drywell. vacuum breakers be manually opened for.inerting containment," but does not state the appropriateness of this flow path to de-inert. The Office of Nuclear Reactor e
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Regulation (NRR) was. contacted for an interpretation of this noie. NRR's interpretation was that under the current 3.6. Technical Specification, the Drywell-to-Torus' vacuum breakers will not be used during the de-inerting process. This interpretation was discussed with, and acknowledged by the license (2) Requirement for Containment Airborne Particulate Monitorin During the reactor S/D, the inspector questioned an apparent disciepancy between the UFSAR Appendix A, Technical Specifications, and Regulatory Guide 1.45 regarding airborne particulate monitoring of the primary containment atmospher The UFSAR states that in accordance with Regulatory Position 3 '
of Regulatory Guide 1.45, containment monitored parameters include, but are not limited to, sump level, sump level flow, and airborne particulate rates. In actuality, no on-line containment ] articulate monitor exists. Further investigation determined t1at a July 1981 Fermi Safety Evaluation Report '
(SER), NUREG-0998, discussed on Pages 5-18 and 5-19 the subject <
of leakage monitorin The SER acknowledged that monitoring of '
airborne particulate is not performed, but that other systems being used are sufficient to meet the intent of Regulatory Guide 1.4 The other systems used to monitor for leakage are (1) sump level and flow monitoring, (2) a supplementary Drywell sump level monitor, and (3) airborne gaseous radioactivity monitorin The inspector concluded that the above monitoring methods with *
the stated alternative comply with the intent of Regulatory Guide 1.4 Additionally, pressure temperature, and humidity j measuringdevicesarealsousedtoIndicatetheexistenceof '
leakage.
 
; The licensee identified to the inspector that a clarification ,
of the UFSAR was previously identified as documented in i UFCN 88-068 drafted June 7, 198 UFCN 88-068 was reviewed by the inspector and it adequately addressed the requi'ed clarification and was currently in the normal approvai proces l (3) Weaknesser, in the coordination in determining the leakage I source. The licensee also recognized that the organizational i
; response to leaks needed improvement in the radiochemistry analysis area and the communication of that analysis to the
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JN'SS and plant managemen Numerous procedure changes were ,
enacted to provide clearer direction to personnel taking the samples and what to evaluate the samples for and from what  ,
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location samples should be extracted. Personnel were briefed-on thir, event to provide a stronger perspective as to what is needed.
 
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r t No violations or deviations were identified in this area  '
l Monthly Maintenance Observ'ation (62703)
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,  Station maintenance activities on safety-related systems.and components listed below were observed to ascertain that they were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with Technical Specification ;
The following items were considered during this review: the limiting conditions for operation were met.while components or systems were
  < removed from service; approvals were obtained prior to initiating the  ,
  .work; activities were accomplished using approved procedures and were
  ' inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by
,  qualified personnel; parts and materials used were properly certified;  .
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radiological controls were implemented; and fire prevention controls were implemented.
 
Work requests were reviewed to determine the status of outstanding jobs and to assure that priority is assigned to safety-related equipment  !
maintenance which may affect system performuc e The following maintenance activities'were observed:  l
  * Troubleshoot and repair Drywell Exhaust Inboard Isolation  i Valve T4803-F602 (WR 02280517).
 
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  * Troubleshoot.and repair Drywell Vent / Inboard Isolation  i Valve T4803-F601 (WR 00180728). i
 
  * Leak repair to RCIC steam supply inboard Isolation  l Valve E61-F00 * Troubleshooting of B Recirculation pump discharge  ,
Valve B31-F0318 failure to close from the Control  '
Room (WR 00380828).
 
-  * Troubleshooting activities into the cause of the scram of  l 24 control rods (WR 002B0802). j
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Following completion of maintene ce on tiie RCIC valve, the inspectors verified that the system had bevi returned to service properl j i
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While observing post-maintenance testing on the High Pressure Coolant Injection (HPCI) System, the inspector noted the verification of system operability was conducted using certain sections of Operating Procedure 23.202, "High Pressure Coolant Injection System." However, since 23.202 is a system operating procedure and provides no step-by-step signoff of the activities the control room operator needed to do as part of the test, the operator with the concurrence of the Nuclear Assistant Shift Supervisor (NASS) utilized appropriate portions of Surveillance Procedure 24.202.01, "HPCI Pump Operability and Flow Test at 1000 psig and Valve Operability" to document the test performance. The decision to do this was made at the time the test was tc be performed and subsequently resulted in the operator working with two procedures  !
simultaneously; 23.202 to conduct the test and 24.202.01 to document the ,
test. The inspector had two concerns with this approach. First, the use  ;
of two procedures simultaneously to perform testing could lead tc confusion on the part of the operator. Second, due to the lack of specific  i instructions or preplanning provided by the work package to properly  r conduct the test, the operator (with the NASS) developed, on the spot, a means of conducting a test by using segments of two existing procedure ,
The licensee recognizes the potential for error using such an approach to l testing and is currently evaluating whether alternate methods may be  l better suited in the future. This is considered an open item pending  '
completion of licensee actions (341/88021-04(DRP)).
No violations or deviations were identified in this are j
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5. Monthly Surveillance Observation (61726)
The inspectors observed surveillance testing on the high pressure cooling system per Procedure 24.202.01, "HPCI Pump Operability and Flow Test at 1000 psig and Valve Operability" required by Technical Specifications and verified that: testing was performed in accordance with adequate
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procedures, test instrumentation was calibrated, limiting conditions for operation were met, removal and restoration of the affected components
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were accomplished, test results conformed with Technical Specifications  ,
and procedure requirements and were reviewed by personnel other than the  i individual directing the test, and any deficiencies identified during the  '
testing were properly reviewed and resolved by apropriate management personne '
The inspectors also witnessed portions of the following test activities:
i  24.413.03  Control Room Emergency Filter Monthly Operability Test.
 
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24.404.02  SGTS Filter Ponthly Operability Tes No violations or deviations were identified in this area, i
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CLEN ELLYN. BLUNot$ 60137
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6. Followup of Events (93702)
JUN 271989 Docket No. 50-341     l The Detroit Edison Company ATTN: B. Ralph Sylvia Senior Vice President Nuclear Operations 6400 North Dixie Highway
l During the inspection period, several events occurred, some of which required prompt notification of the NRC pursuant to 10 CFR 50.72. The inspectors pursued the events onsite with licensee and/or other NRC official In each case, the inspectors verified that the notification was correct and timely, if appropriate, that the licensee was-taking ;
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prompt and appropriate actions, that activities were conducted within
Newport, MI 48166 L Subject: ECCS SETPOINT ISSUE
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regulatory requirements and that corrective actions would prevent future recurrence. The specifit, events are.as follows:
50.72 Events     ,
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* July 19, 1988 ESF actuation when RPS "B" EPA breaker opened i  and deenergized RPS Bus "B".
 
* July 21, 25, Reports on inaccessible or unsatisfactory l
,  26, 28 and testing of flanges from West Jersey '
August 4, 1988 Manufacturing Compan * July 23,1988 Determined unidentified drywell leak based on i  30 minute sample of 5.4 gpm. Reduced reactor
,  power; leak based on one hour sample of 5.6 gp Unusual event declare * July 23, 1988 Reactor placed in shutdown condition by manual i scram due to unidentified leakage in drywel t i
i * July 24, 1988 Terminated unusual even Preparing to place i plant in shutdown coolin !
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: * July 25, 1988 Retractio1 of April 9,1988, event report af ter l
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being determined not reportabl !
 
* July 27, 1988 FSF actuation when I&C repairman shorted across
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two terminals and caused an auto initiation of Div 1 EECW.
 
l * July 27, 1988 HPCI E41 F006 valve open circuit grounded preventing operatio l
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* August 14, 1988 Trip of main turbine generator causing a reactor
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j  scram.
 
* August 21, 1988 Declaration of Unusual Event and initiation
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of a plant shutdown due to recirculation Pump B ;
;  discharge valve being inoperabl '
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* August 22, 1988 ESF actuation when RWCU system pumps tripped l
 
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on low flo G33-F001 and G33-F001 valves closed upon receipt of delta flow isolation signa ,
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* August 28, 1988 Declaration of Unusual Event and initiation of a plant shutdown due to recirculation Pump B discharge valve being inoperabl On July 25, 1988, via the ENS, the licensee retracted the April 9, 1988, 10 CFR 50.72 event notification on loss of RHR cooling which occurred when the shutdown (S/D) cooling injection valve (E11-F015B)
automatically closed. The licensee determined this event was not reportable because the closure signal for the F015B valve did not  i originate from ESF logic. The inspector discussed with the licensee that although the event was not reportable as an ESF activation, the event is reportable as loss of residual heat removal. The inspector noted under 50.72 (b)(2)(iii)(B), that any event that alone could have prevented the fulfillment of the safety function of' structures or systems that are needed to remove residual heat is reportable as a four-hour report. The inspector identified two additional items that raise the
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significance of this event: (1) the loss of S/D cooling on the "B" loo i occurred at a time when the "A" loop of 5/D cooling was out-of-service,p
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(2) the loss of S/D cooling occurred for 30-35 minutes prior to being identified by the control room operators. Following the discussions,  ;
the licensee agreed to submit an LER on the even '
l Following the main turbine trip that occurred on August 14, 1988, the  '
inspector noted that credit was taken for performance of Surveillance l Procedure 24.109.001 "Turbine Steam Valves Weekly Test" due to the even When questioned about the advisability of doing this, licensee management i responded that a review was performed at the time and the Technical
, Specification surveillance requirements which POM 24.109.001 implements
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were verified as having been met. Additionally, it was stated that this 1 was not the first time this philosophy was implemer+ed and that the i
licensee intended to continue the practice. The in vector expressed
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concern that a surveillance procedure may address surveillance  '
requirements / commitments beyond those in Technical Specifications and r as such, if credit is to be taken for performance of a surveillance as  ,
i a result of an operational event, all portions of the procedure need
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addressingIonsurveillancerequirements.not Specificat  just those The inspector portions directly relating t reviewed 24.109.001 and, in that case, found no additional requirements beyond those the licensee had verified in accordance with the Technical  '
Specifications. However, the inspectors will continue to review
; this practice as future examples occu l j Deviation Report Events    !
The inspector revieved DER 88-1520 which identified that a HPCI
; discharge valve had not been tested at the required time interval for  t alert testin Thr6 inspector confirmeo through discussion with licensee perronnel that the ASME Section XI for valve testing had not been
; proporly implemented for the HPCI discharge valve. The inspector evaluated this violation to 10 CFR 2, Appendix C V.G. and determined:  l l      7 u
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. . The violation was identified by the licensee, The violation did not render the HPCI system incapable of injecting the required water flow into the reactor vessel in the required maximum permissible time frame, At the end of the inspection period the time frame for LER submittal had not expired.
 
l Corrective actions were still being formulate A violation of similar nature had not occurred in the last two year This matter is considered unresolved (341/88021-05) contingent upon corrective action review and LER submitta No violations or deviations were identified in this are . Licensee Event Reports Followup (92700)
l Through direct observations, discussions with licensee personnel, l and review of records, the following event reports were reviewed to determine that reportability requirements were fulfilled, immediate corrective action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with Technical l Specifications, (Closed) LER 88002: Main steam line radiation monitor surveillance procedure inadequacy causes MSIV closure. This event which was l described in detail in Inspection Report No. 50-341/88003 was caused by accidental snorting of a fuse in the MSIV DC logic while changing another adjacent fuse. The I&C technician who replaced the fuse
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was not awsre that the circuit needed resetting and the MSIV DC half I closure trip logic was in effect when a surveillance to check the
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functioning of the high radiation closure of MSIVs was started the following day. The technician performing this test misinterpreted
Gentlemen:
This refers to the NRC Notice of Violation (341/88021-02) concerning emergency core cooling flow control setpoints issued with NRC Inspection Report N and also discussed in Inspection Report No. 86039. We have received your letters dated December 2,1988 and January 25, 1989, in response to the violation wherein Detroit Edison denies the violation and. presents justification for that position. We believe we understand your arguments with
  ' regard to the instrument inaccuracy allowances specified in the GE Design Specification Data Sheets and the analysis of the effects of a flow short fall
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the step in the procedure to verify that amperage was present on l both the DC and AC circuits before proceeding. The actions taken to prevent recurrence of this condition were threefold.
up to the instrument inaccuracy allowance maximum for HPCI and RCIC. We have
 
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also received confirmation from NRR (dated June 9, 1989) that the agency's position regarding all numbers in Technical Specifications is unchanged from
First, surveillance procedure 44.101.028 was revised to assure that there is current on both the AC and DC circuits if the HSIVs are open; this has been completed by Revision 22 to the abcVe procedure.
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that which was stated in.IR 88021, that is, "All numbers in TSs should be considered absolute unless otherwise noted." NRR also noted, however, that
l In addition, 52 of the MSIV surveillance procedures were revised i to remove similar ambiguities. The second corrective action was i to place labels on Panels R325064B and R3250618 to indicate that Circuits 2 and 11 power MSIV logic and to notify the Nuclear Shift Supervisor if they are or have been deenergized. The inspector l verified the installation of the label The third corrective action was to improve I&C technician training. The "lessons l
  - the safety significance of the improper setting of the HPCI and RCIC flow setpoints is not great, consistent with the arguments you presented in your letters noted above. Accordingly, we believe continued debate on the specifics of this violation does not serve a useful purpose and we are postponing a decision on whether or not to withdraw the violation. The reason that we are postponing the decision is that withdrawal of the violation because the setpoints -for the specific systems cited do not have great safety significance simply foresta11s the same questions for systems of greater safety significance, such as LPCI and Core Spray. Therefore, we are requesting you to provide to us within 60 days of receipt of this letter similar values for the LPCI and the Core Spray systems. Those values are:
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  (1) the values of flow and pressure assumed by your accident analysis to be
 
  :  necessary to be provided by LPCI and by Core Spray at the point where these systems enter the reactor vessel, (2) the values assigned for all losses (including line losses due to piping length, reducers, elbows, etc.) between the point where these two systems enter the vessel and the point where flow and pressure are measured for surveillance or other tests, and (3) the instrument inaccuracy allowance assigned to measure flow and pressure at this point in LPCI and Core Spra JFI PDR ADOCK 05000341    i Q  PDC
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learned" from this event were reviewed by all I&C personnel; and in addition, after reviewing the I&C training program, it was decided that:
  (1) I&C training course CP-IC-336 would be implemented in August 198 (2) The on-the-job I&C course, CP-IC-331 would be revised to include:
  (a) emphasizing the initial conditions prior to testing, (b) actions to be taken if initial conditions cannot be met, and (c) action to be taken when one channel inadvertently trips while testing the other channel. This course is to be complete by the end of 198 (3) The I&C repairman oualification program description, PD-IC-720, will be revised to mandate completion of 1 above and applicable portions of 2 above prior to performing surveillances. This change is in the approval chai Since the corrective actions appear to be adequate to prevent recurrence of this type of event the LER was closed; however, l
the completion of the I&C training will remain an open item
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  (341/88021-06) until the changes to the training program have been complete i b. (Closed) LER 88003: Setpoints and Head Correction incorrect for Residual Heat Removal (RHR) Interface Valves. During a review to verify pressure monitor setpoints in response to a previous violation (87006-01) and the I&C surveillance procedure improvement ,
program, the pressure alarm setpoints in TS 3.4.3.2-2 RHR Low Pressure Cooling Injection and RHR Shutdcwn Cooling were found to be higher than the relief valve settings. On January 6, 1988, the q  licensee proposed an emergency TS change to lower the alarm setpoints and on the same date a TS Temport ry Waiver of Compliance was issued
 
by NRR. On January 13, 1988, Amendment No. 14 was issued which changed the setpoint in Tables 3. 4.3.2-2. In reviewing the surveillance procedures for functional and calibration checks ,
of these pressere alarms, the inspectors found that the procedures j had been revised to include the adjusted setpoint pressure ,
c. (Closed) LER 86027: Vacuum Breaker Valve Failure. Followup to this LER was previously documented in Inspection Report No. 8702 As a result of that review, violation 87022-01 was issued. The
<  violation corrective actions are adequate to complete followup on '
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this LER. Therefore, this LER is closed and the final corrective l
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actions will be inspected in the followup to violation 341/87022-01, d. (Closed? LER 85080-01: Failure to place a radiation monitor in serv <ce while re Masing liquid effluen ;
 
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, In addition to the review criteria stated above, the LERs were reviewed for potential violations of regulatory requirements. The results of that review identified that a violation of Limiting Conditions for Operation was associated with LER 85080-01. This violation occurred during the same time frame and was of the same type as the violations identified in Inspection Report No. 50-341/85040. As indicated in Paragraph 9.d. of Inspection Report No. 50-341/86019, the escalated enforcement actions of Inspection Report No. 50-341/85040 adequately address this violation and no citation will be given, j No oth6r violations or deviations were identified in this are :
8. Startup Test Observation (72302)
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The inspectors reviewed portions of startup test procedures, toured the areas containing system equipment, interviewed personnel, and observed
.i test activitie While observing startup tests the inspector verified that the established testing prerequisites were met, testing was performed in accordance with adequate procedures, limiting conditions for operation were met, test personnel were knowledgeable of the test, data was 7
: accurately taken, and special test equipment required by the procedure ;
J was calibrated and in servic Th inspector observed the performance of the following startup tests: I
 
i e STUT 03B.023 Feedwater System level Setpoint Change e i * STUT 06B.030 Recirculation System One and Two Pump Trips.
 
; * STUT 06C.016 Selected Process Temperatures - Recirculation Pump
 
Trip Dat '
* STUT 04B.019 Core Performance - Process Computer Determinatio l j * STUT 04A.030 Recirculation System - System Performanc '
 
l During performance of STVT 068.030 on August 21, 1988, attempts to l close reactor recirculation Pump B discharge valve (B31-F0B18) were ,
unsuccessful and the licensee commenced a reactor shutdown in l accordance with Technical Specifications and entered the Emergency !
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Pla Suts,quently, troubleshooting of the motor operator revealed I three loose terminations to the valve's torque switch. The terminations l were tightened, the valve tested and found to stroke properly, and the ;
{ unit returned to powe ;
  :     I i On August 28, 1988, test conditions were reestablished to complete t
  ! STVT 06B.030. Again when B31-F031B was directed to close from the j  thevalvefailedtostrok The reactor was shutdown, ,
i control room}ng of the sotor operator was conducted, and torque switch troubleshoot J settings found to be incorrect. Two NRC Region III inspectors were subsequently dispatched to the site to review licensee corrective
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actions (Reference Inspection Report No. 341/88025(DRS)).  '
i      i i The inspector also reviewed the completed results of STVT 06B.019, i
{ Core Performance - Process Computer Determination, and determined j j that the test was satisfactor l
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No violations or deviations were identifie . Personnel Qualifications During the inspection pericd, the licensee changed the "Engineer in Charge." The new individual is holding this position until a permanent replacement is acquired. The interim individual's qualifications were reviewed against the applicable ANSI 18.1 standard revision and found to meet the qualification requirement No violations or deviations were identified.
 
i 10. Regional Requests l During the inspection period, the inspector continued to pursue the i regional request dated September 24, 1987, dealing with preventive maintenance activities associated with the GE AKF-2-25 circuit breakers, previously discussed in Inspection Report No. 341/88006.
 
i Deviation Event Report DER No. 88-0290 was istJed tc address the corJerns j noted in the above report that were contrary a ?.: recommendations in
; NRC Information Notice 87-12 and GESIL 44 The breaker inspections were scheduled '.or every other refueling instead of annually or every refueling.
 
l There were no plans to disassemble and overhaul the breaker at five year intervals.
 
l The inspectors found that Maintenance Instruction MI-M037, Rev 2, Recirculation Pump Generator Field Breaker (GE Type AKF) General Maintenance, had been approved March 14, 1988. This procedure deals with the cleaning, inspection, lubrication, adjustment and operational checks of the AKF type breakers. The revision included the SIL recommendations concerning approved lubricants. The other recommended actions of the SIL above had not been addressed so this will be carried as an Open Item (341/88021-07).
 
11. Review of Allegations (Closed) Allegation No. RI11-88-A-0022: Concerns regarding the process for updating the Updated Final safety Analysis Report (UFSAR). On February 16, 1988, the Senior Resident Inspector was contacted by an anonymous alleger who provided four allegations regarding the UFSAR updating process as outlined below:
Allegation 1: There was no revjew or approval by Licensing of changes
,  to the FSAR when it was updated the first time.
 
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Allegation 2: Anyone can change the UFSAR based on filling out a for These forms receive no review before incorporation into the UFSAR.
 
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The Detroit Edison Company 2 JUN 2 71989 4'
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It has been our experience that these values are often utilized during.the preoperational and startup testing programs in order to determine proper 1-acceptance criteria and acceptability of deviations from acceptance criteri ]
Allegation 3: The form specified in interfacing Proceoure 11.000.121 is not the correct form to be used. A lady in Licensing informed the alleger not to use that. form but to use another form not approved that'has been made up by Licensin ,
We believe that 10 CFR 50, Appendix B, Criteria III, IV, V, VI, and VII require this type information to be available, therefore, the 60 day response
Allegation 4: The alleger was told by a supervisor not to write a DER on this situation and that the supervisor did not want any DERs associated with the UFSAR update activitie The alleger indicated that if the alleger wrote a DER ,
   . period should not be unreasonable. Further, we believe this type information to be necessary for you to have available in order to complete the Design
there would be adverse personnel action taken against him/he The NRR Project Manager conducted a review of the FSAR change files and the program, including directives and procedures, implemented by the licensee to implement FSAR changes. Discussions were conducted with the cognizant Licensing personne For the first FSAR update, Procedure NOIP-11.000.121-NS, "Updated Final Safety Analysis Report and Environmental Peport Revisions," Revision 3, issued in 1985, was-used to provide input to Licensing on proposed FSAR changes. This procedure contains a form entitled, "UFSAR Change Notice (UFCN)," which provides blocks to describe the change, the basis for the
, Basis Document program you are currently establishing. In your response, we also request that you include a discussion regarding how the Design Basis Document program will provide a clear basis for numerical values in Technical Specification In accordance with 10 CFR 2.790 of the Commission's regulations, a copy of
; change, and who initiated, reviewed and approved or concurred in the i change. The form provides space for several approvals in Block 8; however, '
   'this letter and your response to this letter will be placed in the NRC Public Document Roo We will gladly discuss any questions you have concerning this subjec
a review of the first FSAR update UFCN forms on file indicated that the forms did not always reflect those approvals because the procedure did not mandate that Block 8 must be completed. However, the UFCNs on file did have documents attached to them which indicated who had reviewed and
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approved the changes reflected on the form. The reviews were conducted by Engineering, Operations, Licensing and the Independent Safety Engineering Group (ISEG). Engineering usually initiated the change proposal, but others were not prohibited from doing so. The QA i organization does not review UFCN The ISEG reviewed those change packages which contained safety evalustions (SEs) since, procedurally, ISEG reviews all SEs whether associated with an FSAR change or other plant change. The FSAR change initiator does not get involved in ths ,
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proposed change review process, unless the matter is technically I complicated, c9ntroversial, or the initiator is questioned by ISEG l during the SE revie The proposed FSAR change must be accepted by 1 the initiator's first line supervisor before it is sent to Licensin ;
The UFCNs received by Licensing are sent to a Subject Matter Expert (SME) who is responsible for reviewing the change for technical ade l and necessity, and who usually finalizes the SE which ISEG reviews.quacy The
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SHE is the individual assigned responsibility for a specific section of the UFSA N0!P-11.000.121, Revision 4, dated February 1988, is the current procedure in use for making UFSAR changes for the second update. This revision mandates that approvals be reflected in Block 8 of the UFCN. Licensing is now playing a greater role in reviewing and assessing the technical l J
adequacy of proposed change For the first update, contractor support j i
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I was more extensively used to provide the Licensing overview. A review ,
of FSAR change packages processed for the second update indicates an improvement over the packages oa file for the first updat The FSAR change program and related procedures are undergoing further changes as part of the licensee's effurts to upgrade the quality and ,
accuracy of plant procedures. Directive FMD-RA2, "Licenses, Plans, and l  Programs," Revision 0, issued in January 1988, establis.es requirements '
;  for control of amendments to licenses, plans, and programs, and as;igns l  responsibility for implementing those requirements, which includes the l  annual update of the FSAR. Under the new system a procedure will be '
l  issued,FIP-RA201-SQ,"AmendmentstotheOperatIngLicense,UFSAR and NRC Approved Plans and Programs." This will replace Procedure N0!P-11.000.12 Licensing has in place a data table for tracking FSAR changes which will be enhanced to reflect the new syste ,
The licensee expects to have the new programmatic and procedural changes related to the FSAR updates luplemented by fourth quarter of CY 198 NRC Conclusions:    ,
Allegation 1: Licensing does not approve FSAR changes. Licensing :
coordinates and keeps trcck of propostd changes and l
,   assures that appropriate approvals are obtained before j
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Deing incorporated in the FSAR. There was no evidence f that the changes incorporated in the first FSAR update did not receive appropriate reviews and were not approved. This allegation was not substantiate Allegation 2: It is true that anyone can initiate a FSAR changa and l the UFCN form is used for that purpose. However, the change requires first line supervisor acceptance before it gets into the system. When received by Licensing, it is directed to the SME for review to ensure that '
the proposed change is acceptable. The fact that j  anyone can change the FSAR was substantiated; however, l
the proposed change is reviewed and approved before l   incorporation as concluded under Allegation 1.-
Allegation 3: It is true that the interfacing procedure and UFCN form have undergone a few revisions; however, there was no evidence that any unapproved form or procedure was used in the FSAR updating process. This allegation was not substantiate Allegation 4: The NRC did not pursue this allegation in that the alleger was anonymous and did not identify the supervisor involved. The DER procedure in effect on February 2, 1988, was FIP-cal-01-SQ, Revision 0, "Deviation and Corrective Action Reporting." Paragraph 2.1.1 requires, in part, that procedural noncompliance including violations of procedures having nuclear safety significance, l
 
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i be documented as a DER.- It is noted that the DER originator and his supervisor are required to sign the DER. Issuance of a DER would not have been appropriate in this case in i that no procedural noncompliance was idertifie No violations or deviations were identifie . Unresolved Items    ,
Unresolved items are matters aboat which more information is required I (
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in order to ascertain whether they are acceptable items, violations or deviations. An unresolved item disclosed during the inspection l , is discussed in Paragraph 6.
 
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I which will be reviewed further by the inspector, and which involve some :
action on the part of the NRC, or licensee, or both. Open items disclosed .
during the inspection are discussed in Paragraphs 3, 4, 7 and 1 !
1 Exit Interview (30703)
The inspectors met with licensee representatives (denoted in Paragraph 1)
on September 20, 1988, and informally throughout the inspection period 1 and summarized the scope and findings of the inspection activities.


l The inspectors also discussed the likely informational content of the
Sincerely, f&k & ==
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Edward G. Greenman, Director Division of Reactor Projects cc:    .
inspection report with regard to documents or processes reviewed by the inspectors during the inspection. The licensee did not identify any such documents / processes as proprietary. The licensee acknowledged ;
Patricia Anthony, Licensing P. A. Marquardt, Corporate Legal Department
the findings of thc inspectio !
  ' DCD/DCBi(RIDS);.
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e"p : Licensing Fee Management Branch Resident Inspector, RIII Ronald Callen, Michigan Public Service Commission Harry H. Voight, Es Michigan Department of Public Health Monroe County Office of Civil Preparedness J. Grobe, RIII M. Virgilio, NRR J. Stang, NRR l
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Latest revision as of 11:02, 16 December 2021

Informs of Postponement of Decision Re Whether or Not to Withdraw Violation Noted in Insp Repts 50-341/88-21 & 50-341/86-39.Listed Values for LPCI & Core Spray Sys Requested within 60 Days of Receipt of Ltr
ML20246A161
Person / Time
Site: Fermi DTE Energy icon.png
Issue date: 06/27/1989
From: Greenman E
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To: Sylvia B
DETROIT EDISON CO.
References
NUDOCS 8907060171
Download: ML20246A161 (2)
v • d • e


Text

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. .i r UNITED STATES

[p* Mo iqk

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NUCLEAR RE7ULATORY COMMisslON

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ge S REGION lli E 799 ROOSEVELT ROAD r -s /' , rp '

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CLEN ELLYN. BLUNot$ 60137

.....

JUN 271989 Docket No. 50-341 l The Detroit Edison Company ATTN: B. Ralph Sylvia Senior Vice President Nuclear Operations 6400 North Dixie Highway

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Newport, MI 48166 L Subject: ECCS SETPOINT ISSUE

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Gentlemen:

This refers to the NRC Notice of Violation (341/88021-02) concerning emergency core cooling flow control setpoints issued with NRC Inspection Report N and also discussed in Inspection Report No. 86039. We have received your letters dated December 2,1988 and January 25, 1989, in response to the violation wherein Detroit Edison denies the violation and. presents justification for that position. We believe we understand your arguments with

' regard to the instrument inaccuracy allowances specified in the GE Design Specification Data Sheets and the analysis of the effects of a flow short fall

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up to the instrument inaccuracy allowance maximum for HPCI and RCIC. We have

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also received confirmation from NRR (dated June 9, 1989) that the agency's position regarding all numbers in Technical Specifications is unchanged from

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that which was stated in.IR 88021, that is, "All numbers in TSs should be considered absolute unless otherwise noted." NRR also noted, however, that

- the safety significance of the improper setting of the HPCI and RCIC flow setpoints is not great, consistent with the arguments you presented in your letters noted above. Accordingly, we believe continued debate on the specifics of this violation does not serve a useful purpose and we are postponing a decision on whether or not to withdraw the violation. The reason that we are postponing the decision is that withdrawal of the violation because the setpoints -for the specific systems cited do not have great safety significance simply foresta11s the same questions for systems of greater safety significance, such as LPCI and Core Spray. Therefore, we are requesting you to provide to us within 60 days of receipt of this letter similar values for the LPCI and the Core Spray systems. Those values are:

(1) the values of flow and pressure assumed by your accident analysis to be

necessary to be provided by LPCI and by Core Spray at the point where these systems enter the reactor vessel, (2) the values assigned for all losses (including line losses due to piping length, reducers, elbows, etc.) between the point where these two systems enter the vessel and the point where flow and pressure are measured for surveillance or other tests, and (3) the instrument inaccuracy allowance assigned to measure flow and pressure at this point in LPCI and Core Spra JFI PDR ADOCK 05000341 i Q PDC

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It has been our experience that these values are often utilized during.the preoperational and startup testing programs in order to determine proper 1-acceptance criteria and acceptability of deviations from acceptance criteri ]

We believe that 10 CFR 50, Appendix B, Criteria III, IV, V, VI, and VII require this type information to be available, therefore, the 60 day response

. period should not be unreasonable. Further, we believe this type information to be necessary for you to have available in order to complete the Design

, Basis Document program you are currently establishing. In your response, we also request that you include a discussion regarding how the Design Basis Document program will provide a clear basis for numerical values in Technical Specification In accordance with 10 CFR 2.790 of the Commission's regulations, a copy of

'this letter and your response to this letter will be placed in the NRC Public Document Roo We will gladly discuss any questions you have concerning this subjec

Sincerely, f&k & ==

Edward G. Greenman, Director Division of Reactor Projects cc: .

Patricia Anthony, Licensing P. A. Marquardt, Corporate Legal Department

' DCD/DCBi(RIDS);.

e"p : Licensing Fee Management Branch Resident Inspector, RIII Ronald Callen, Michigan Public Service Commission Harry H. Voight, Es Michigan Department of Public Health Monroe County Office of Civil Preparedness J. Grobe, RIII M. Virgilio, NRR J. Stang, NRR l

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