RBG-41252, Responds to NRC Ltr Re Violations Noted in Insp Rept 50-458/94-22.Corrective Actions:Aprm G' Bypassed & LPRM Placed in Required Positions
| ML20082A117 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 02/27/1995 |
| From: | James Fisicaro ENTERGY OPERATIONS, INC. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| Shared Package | |
| ML20082A073 | List: |
| References | |
| RBG-41252, NUDOCS 9504030168 | |
| Download: ML20082A117 (21) | |
Text
r_..
.s Entergy oper:tions, Inc.
Rtver Bena Stanon 5485 U S Hignway 61
.! ENTERGY Ls*%s"emon5 Tel 504 336 6225 Fax 504 635 5068 James J. Fisicaro Dwector Naciear Sa'ety February 27,1995 ., ..
i
. i. . b. d R U, ., $ li ! a,l,l U.S. Nuclear Regulatory Commission , q jii Document Control Desk ,
l }&Q ~ 31995 d)!
Mail Stop Pl-37 {~~ ; ,
j Washington, D.C. 20555 I i REGIONIV J L
Subject:
Reply to a Notice of Violation IR 94-22 River Bend Station - Unit 1/ Docket No. 50-458 File No.: G9.5, G15.4.1 RBG-41252 RBF1-95-0047 Gentlemen:
Pursuant 10CFR2.201, please find attached Entergy Operation's response to the notices of violation described in NRC Inspection Report (IR) 94-22. The inspection was performed by Messrs. Ward Smith and Chris Skinner during November 20 through December 31, 1994, of activities authorized by NRC Operating License NPF-47 for River Bend Station (RBS) - Unit 1.
In the inspection report, you raised concerns reganiing human performance. Each of the violations identified in the inspection report were to some extent caused by a human l performance related error. River Bend Station (RBS) understands the significance of this issue and has initiatives underway which will result in improvements in this area. We are confident that the actions being implementing will effectively resolve your concern.
Even though our indicators on human performance illustrate a fourfold improvement in significant human error rate during 1994, RBS management shares your concerns about this issue and has taken corrective measures to ensure continual improvement in the critical area of human performance. !
1 l
i l
/
9504030168 950330 i PDR ADOCK 05000458 l G PDR \
b.!
4
? ;
Reply to NRC Notices of Violation IR 94-22 'l February 27,1995 RBG-41252 ,
RBF1-95-0047 ,
Page 2 of 2 :
.m Should you have any questions, please contact Mr. T. W. Gates at ( 504 ) 381- 4866. '
Sincerely, M
James J. Fisicato Director - Nuclear Safety I
cc: U.S. Nuclear Regulatory Commission Region IV F 611 Ryan Plaza Dnve, Suite 400 Arlington, TX 76011 ,
NRC Resident Inspector P.O. Box 1051 St. Francisville, LA 70775 Mr. David Wiggington i NRR Project Manager U. S. Nuclear Regulatory Commission ,
NRR Mail Stop 13-H-3, One White Flint Nonh 11555 Rockville Pike
Rockville, MD 20852 i
f f
+
l ATTACHMENT A REPLY TO NOTICE OF VIOLATION IR 458/9422-01 VIOLATION (EXAMPLE D Technical specification 6.8.1.d states, in part, that written procedun:s shall be implemented covering surveillance and test activities of safety-related equipment.
Contmry to the above, there were three examples where surveillance testing was not implemented in accordance with established procedures:
On November 1,1994, Surveillance Test Procedure STP-505-4507, "RPS/ Control Rod Block-APRM Channel Functional Test, Channel Calibration and LSFT for Two Loop Operation (C51*K605G)," Revision 10B, Step 7.1.16, was not followed in that the bypass / calibration /opemte switches for local power range Monitors46-47C and 14-47C were not restored to the pretest condition as specified.
Consequently, average power range Monitor G was not in the specified configuration.
REASON FOR TIIE VIOLATION Entergy Operations concurs with this violation and believes that the reason for this event was that the technicians who performed the surveillance test procedure (STP) failed to properly self-check their work. A contributing cause of this event was that work practices were less than adequate in that the independent verification method did not identify the mispositioning of the local power range monitor (LPRM) switches. Another contributing cause of the violation was that inadequate corrective actions were taken in response to a previous event.
On November 1,1994, I&C technicians began the weekly calibration check STP-505-4507, "RPS/ Control Rod Block-APRM Channel Functional Test, Channel Calibration and LSFT for Two Ioop Operation (C51*K605G)." This procedure requires repositioning all of the LPRM operate switches for average power range monitor (APRM) 'G' to the
' bypass' position.
In accordance with this procedure, the I&C technician recorded the as found inoperable bypassed LPRM's associated with APRM 'G' on attachment 2, Table la. Next, the I&C technicians bypassed all operable LPRM's associated with APRM 'G' starting with the LPRM in the lower row on the right hand side and working clockwise. After the readings were taken, the I&C technicians began restoring the bypassed LPRM's for APRM 'G' except those listed on attachment 2, Table la. The switches were placed in the ' operate' position starting with the card in the upper row on the right hand side and working counterclockwise. A computer history printout for this time frame indicates that LPRM 14-47C was taken out of the ' bypassed' position. However, these records do not indicate that
't .LPRM 46-47C, whose card is physically located next to the LPRM card for LPRM 14-47C, was ever removed from the bypass position.
After completion of the required steps of the STP, the procedure was given to the second I&C technician who had returned fmm his position in the at-the-controls (ATC) area to perform the required independent verifications. The r,econd I&C technician independently verified that the LPRM's listed in attachment 2, Table la, were bypassed and that the other LPRM's were in the 'opente' position.
APRM 'G' remained with LPRM 14-47C in ' operate' and LPRM 46-47C in ' bypass' until approximately 15:30 on November 2,1994, when a nuclear control operator (NEO) identified the condition (LPRM 46-47C in ' bypass' and LPRM 14-47C in ' operate'). The operator was performing a self-initiated walkdown of the control room back panels.
A similar event occurmd in 1993. Unresolved Item (URI) 9327-01 resulted from LPRM 46-39B being in the ' calibrate' position when it should have been in the ' operate' position.
Because RBS was unable to determine how LPRM 46-39B was mispositioned, the corrective actions developed as a result of URI 9327-01 were unsuccessful in preventing the recurrence of this condition. The corrective actions recommended as a result of the URI covered a broad range of possible problem areas in an attempt to encompass all possible causes. The majority of the corrective actions were targeted at subsequent detection of a mispositioned LPRM mode switch or verifying APRM operability. Only one of the corrective actions for URI 9327-01 appears to have provided an opportunity to address the issue of detecting LPRM switches mispositioned during surveillance testing.
This corrective action was to evaluate and revise as necessary STP-505-4504, "RPS/ Control Rod Block-APRM Channel Functional Test, Channel Calibration and LSFT for Two Loop Operation (C51*K605D)," to ensure that restoration and independent verification steps were adequate. As part of this verification, a count meter mading step was added to record the 'as found' and 'as left' LPRM positions. However, this count reading will only identify a problem if the number of LPRM's in bypass at the end of the test is different than the number that was in bypass before the test. This corrective action was inadequate because it would not identify multiple LPRM's that are positioned incorrectly.
Because the scope of the corrective action was limited to addressing only one STP and did not include other procedures that manipulate the LPRM mode switches or verify LPRM mode switch positions, the corrective actions generated as a result of the URI were ,
narrowly focused, and ultimately, inadequate. The cormctive actions did not address the problem of verifying LPRM positions but instead largely focused on verifying APRM operability. If broader corrective action had been implemented in response to the previous i event, this switch mispositioning could have been prevented.
A contributing cause of this event was that work practices wem less than adequate in that j the independent verification did not identify the mispositioning of the LPRM switches.
STP-505-4507 utilizes an independent verification scheme to ensure that LPRM mode l l
l
t .:
,- l switches are correctly mstered to their original position after the testing is complete. This scheme utilizes a table in which the technicians performing the STP steps will record those LPRM's that are initially in bypass (i.e., as a result of an equipment condition) before the test is started. When the test is complete and the switch positions restored, the independent verifier uses this table to ensure that LPRM's which were in bypass at the beginning of the test remain in bypass after the test is completed.
However, the LPRM table in STP-505-4507 only records the LPRM's that were in bypass before the test is started. After the test is complete and the switch positions are restored, .
the only LPRM switch positions that are independently verined are those that were in bypass before the test was started. This verification sequence will not detect a situation in -
which an LPRM switch is not returned to the operate position from bypass when the test is ;
complete.
These factors aside, this weekly surveillance is typically perfonned satisfactorily. As such it would appear that the technicians perfonning the STP did not adequately self check their work before signing off critical steps in the procedure. If maintenance personnel had employed the stop-think-act-review (STAR) principles while completing the STP, this violation could have been avoided.
During the switch mispositioning event, confirmation was obtained that no APRM's were inoperable because of minimum LPRM operability requirements.
CORRECTIVE STEPS TAKEN AND RESULTS ACHIEVED Immediate cormctive actions were to bypass APRM 'G' and place the LPRM's in their required positions. All LPRM's for APRM 'G' were then verified to be in the correct position.
A team was formed consisting of members from River Bend, Arkansas Nuclear One, and Grand Gulf Nuclear Station. The team's mission was to investigate the events leading to this condition, determine the root cause, and recommend corrective actions.
This condition report was discussed with the I&C department stressing the use STAR during the performance of verincations.
The inadequate corrective action that ultimately resulted in this violation is an isolated occurrence. The reason this event was isolated was because RBS did not discover the root l cause of the 1993 event; therefore, effective corrective actions were not implemented to prevent recurrence. No further actions are necessary to address the inadequate corrective action from URI 9327-01.
Condition Report (CR) 94-1432 was initiated to investigate the LPRM mispositioning event.
m
4 . '
+
CORRECTIVE STEPS TO BE TAKEN TO AVOID FURTHER VIOLATIONS The LPRM STP's will be revised to incorporate a positive method by which to verify switch positions.
REP-0037, "LPRM Operability," will be revised to improve the LPRM position verification method to verify the number of operable LPRM's.
DATE WIIEN FULL COMPLIANCE WILL BE ACHIEVED River Bend Station is in full compliance in that all the LPRM's for APRM 'G' are in their correct positions. The estimated completion date for all of the corrective actions associated '
with this violation is January 30,1996.
Q ATTACIBIENT A REPLY TO NOTICE OF VIOLATION IR 458/9422-01 VIOLATION (EXAMPLE 2)
Technical specification 6.8.1.d states, in part, that written procedures shall i m 'emented covering surveillance and test activities of safety-related equipment.
Contrary to the above, there were three examples where surveillance testing was not implemented in accordance with established procedures:
On December 4,1994, Surveillance Test Procedure STP-058-4501, " Containment and Drywell Manual Isolation Actuation Monthly Channel Functional Test,"
Revision 10, Section 7.1, was not followed, in that the technicians failed to have the operators reset logic Channel A. Consequently, when logic Channel B was tripped in accordance with Section 7.2, a main steam line isolation occurred, resulting in a reactor trip.
REASON FOR THE VIOLATION Entergy Operations concurs with this violation and has determined that the reason for this event was human error on the part of the maintenance technician in that he failed to follow the procedure as written due to a miscommunication. A contributing cause was that verification steps to verify channel status had been removed during a previous revision.
Surveillance test procedure (STP)-058-4501, " Containment and Drywell Manual Isolation Actuation Monthly Channel Functional Test," was being performing by maintenance technicians. The surveillance sequence performs the functional test on the first channel (Channel A) prior to proceeding to the next sequential channel (Channels B, C and D).
Upon completion of the pre-requisites required to perform the test, the Channel A portion of the test was initiated. These steps consisted of 1) requesting the operator to bypass the Channel A Balance of Plant (BOP) isolation function for a test relay,2) requesting the operator to arm the isolation switch and verifying the resulting annunciator, 3) requesting the operator to depress and hold the pushbutton to generate the isolation signals and verifying the associated annunciator, 4) verifying the BOP isolation signals, 5) requesting the operator to release the pushbutton, 6) requesting the operator to restore the bypassed BOP isolation function, 7) requesting the operator to disarm the isolation pushbutton, 8) -
verifying the BOP signals had reset, 9) requesting the operator to reset the sealed-in half MSIV isolation signal, and 10) verifying all alarms cleared. The procedure then required an independent verification in accordance with Attachment 2 of the STP which verified the bypassed BOP isolation had been restored and the isolation switch had been disarmed.
kh .
.C Because the annunciators had reset after de-actuating and disarming the isolation switch, !
. the I&C Technician assumed that the half isolation signal had been reset by the operator i and did not perform the step that requires him to request the operator to reset the signal. 1
- Following completion of Section 7.1 of the procedure, " Outboard Isolation Manual
~
Initiation Channel A," the' team proceeded to Section 7.2 of the procedure, " Inboard l Isolation Manual Initiation Channel B." The scram occurred when the isolation signal was e ,
insened in Channel B. Neither section 7.1 nor 7.2 of the procedure contained a step to i verify cat all isolation signals had been cleared or that no isolation signals were present ,
before proceeding to the next channel. In addition, the attachment used for independent !
verification did not check the status of the MSIV isolation channel. ' No indication is available in the ATC area for the operators to use to determine the status of the isolation :
circuitry. The operator did not recognize that the procedure had been changed significantly from the last time it was performed and assumed the technician at the back panels would be ;
checking the back panel indications for the MSIV status lights and ammeters to ensure the isolation signals were reset. These checks were included only in the procedure's j restoration section (Section 7.5) which would be performed after all channel functionals l had been performed. The previous procedure revision included these steps after each ,
section.
A contributing cause was that the procedure had been revised as a result of the Technical l Specification surveillance procedure review project. In the previous revision, the status j lights and ammeters were verified in each section of the procedure prior to proceeding to -l the next channel. These steps were marked to indicate that they were required to satisfy i Technical Specifications. The project detennined that these steps (status lights and ammeters) were not required to be checked by Technical Specifications and were deleted. q The procedure revision process failed to recognize the imponance of the verification j function performed by these steps during the approval and review process. j i
In addition, neither the at-the-controls (ATC) operator who actually depressed the switch !
that insened the isolation signal nor the unit operator (UO) who should have reset the ;
isolation signal followed up and ensured that the signal was removed before proceeding i into the next section of the procedure. Since the operators had performed this procedure i before and were familiar with this STP, they each thought the isolation signal must have i been reset since the technician had proceeded to Channel B.
I CORRECTIVE STEPS TAKEN AND RESULTS ACHIEVED To address the associated human performance issues, individual counseling / discipline was i administered as determined necessary by department management. In addition, l management expectations were reinforced to site personnel regarding personal accountability and procedure compliance through management meetings which discussed -
the specific issues and the overall philosophy of human performance improvement. .
i
3 ]
l.'?' l s .. . . .
In addition, pmcedure STP-058-4501 revision 11,'was revised to include verification'of circuit status lights (located in the back panel) and ammeters for each ' channel prior to'
~
proceeding to the next channel.
' Condition Report (CR) 94-1555 was initiated to investigate this event and report it under 10CFR50.73(a)(2)(iv) via LER 94-030.
u CORRECTIVE STEPS TO BE TAKEN TO AVOID FURTHER VIOLATIONS A review of multi-divisional "high-risk" surveillance test procedures will be performed to - ,
,' determine if verification barriers are in place' where necessary.
The procedure review and revision process will be enhanced by 1) revising the Technical '
Review checklist contained in River Bend Nuclear Procedure (RBNP)-0001, " Control and Use of RBS Pmcedures," to ensure that appropriate verifications are included as required by Administrative Procedure (ADM)-0076, " Verification Program," guidelines; 2) irvision of the procedure writer's guide criteria to address human factors considerations and necessary barriers; and 3) providing additional training for departmental technical reviewers on human factors considerations for station procedures. ;
Status indication of the main steam isolation valve (MSIV) isolation circuits will be provided inside the ATC area to improve the human factors considerations associated with this issue.
DATE WHEN FULL COMPLIANCE WILL BE ACHIEVED ,
River Bend Station is in full compliance. The estimated completion date for the corrective actions associated with this violation is at the end of refueling outage (RF)-6. The modification request associated with human factors considerations will be completed during the next refueling outage. i 5
r,3 ' - '
g,[.-
~
- ATTACHMENT AL 1
-j w REPLY TO NOTICE OF VIOLATION IR'458/9422-01' ;
1 VIOLATION (EXAMPLE 3) -i 1
Technical specification 6.8.1.d states, in part, that written procedures shall be implemented t covering surveillance and test activities of safety-related equipment. :
- Contrary to the above, there were three examples, where surveillance testing was not l implemented in accordance with established procedures: i On December 14,1994, Surveillance Test Procedure STP-309-0203, Division m'
. Diesel Generator Operability Test, " Revision 11, Step 7.5.5, was not followed, in .1 that the operator failed to synchronize the diesel generator with the bus prior to :
closing the diesel generator output breaker. Consequently, the generator was -
damaged.
REASON FOR THE VIOLATION !
Entergy operations concurs with this violation and has determined that the reason for this event was human error on the part of the unit operator (UO) in that he failed to look at the synchroscope before closing the output breaker as required by the procedure because he had tunnel vision.
The on-shift crew was performing surveillance test procedure (STP)-309-0203, the division ;
m diesel generator operability surveillance. . The diesel was started and both the UO and ;
the local operator were completing the necessary checks and adjustments required prior to ;
loading. The UO was concerned about loading the diesel to 100 percent within the ;
required 60 second time limit. He had previously performed thi_s test and remembered coming very close to exceeding the loading time limit during that performance. He recognized that the test would have to be performed again if the limit was exceeded and -
was therefore very focused on loading the generator. :
i The UO completed the preliminary steps for loading the diesel, including setting up the synchroscope, while the local operator performed pre-loading checks. The UO was ready ,
to load the generator before the local operator; therefore, he made use of this time by l reviewing the required actions for loading the diesel. He mentally rehearsed the required ,
actions while verifying locations of the various controls that would require manipulation.
He mentally performed this action several times while waiting, and each time he began his actions at the' step, "close the breaker." The UO became so focused on closing the breaker that he omitted the requirement to wait until the synchroscope indicated "5 minutes to 12" and failed to observe synchroscope position befoie completing this action.
h
. _f
1:.g, l
{ *e l CORRECTIVE STEPS TAKEN AND RESULTS ACHIEVED Disciplinary action was utilized for the individual involved.
The division III diesel and the high pressure core spray (HPCS) system were restored to an operable status five days following the event.
Condition Repon (CR) 94-1597 was initiated to investigate this event and repon it under 10CFR50.73(a)(2)(v) via LER 94-032.
CORRECTIVE STEPS TO BE TAKEN TO AVOID FURTHER VIOLATIONS No funher corrective action associated with this specific issue is necessary.
DATE WHEN FULL COMPLIANCE WILL BE ACHIEVFD River Bend Station is in full compliance.
t P
f
y
.?^
ATTACHMENT B REPLY TO NOTICE OF VIOLATION IR 458/9422-03 VIOLATION License Condition 2.C.(10) states, in part, that the licensee shall compi;j with the -
requirements of the fire protection program as specified in Attachment 4 to the license.
Attachment 4 to the license states, in part, that the licensee shall implement and maintain in effect all provisions of the approved fire protection programs as described in the Final Safety Analysis Report for the facility. The facility Updated Safety Analysis Repon (USAR), Section 9A.3.5.5.1," Emergency Lighting," states, in part, that emergency lights are provided with a power source which can sustain the required level of illumination for a period of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
Contrary to the above, from the time the plant was licensed in 1985 until the condition was corrected in December 1994, Emergency Light ILAP-1X1-20-0-B-1 had approximately twice the design load. Consequently, the light had only a 4-hour illumination capability.
REASON FOR THE VIOLATION Entergy opemtions concurs with this violation and has determined that the reason for this event was that, during construction, personnel did not replace two emergency lamps as specified in engineering and design coordination report (E&DCR) P-22314D (a design change package). A contributing cause was that the construction documentation was signed off as completed when it was not.
During construction, engineering initiated a design change _to delete two twenty-five watt lamps on an emergency lighting unit (ELU) and replace them with four twelve watt lamps.
These lamps are used to improve visibility during accident conditions to allow operators to perfomi required activities to achieve a safe plant shutdown.
The design change package specified that the two existing twenty-five watt lamps be replaced with four twelve watt lamps. Personnel added the four lamps but did not remove the existing two lamps as required by the engineering design. By not complying with the design package, the ELU would not operate for the full eight hours as required by the Safe Shutdown Analysis (SSA).
A contributing cause for this event was that the engineer signed off the construction documentation as being complete when it was not. If the engineer overseeing the project had verified that the work was complete then this condition could have been identified and corrected.
g, a
CORRECTIVE STEPS TAKEN AND RESULTS ACHIEVED The two 25 watt lamps have been removed.
A walkdown of 10CFR50, Appendix R, emergency lights that contain more than two lamps, has been performed to verify that the ELU's do not exceed their design loads. The
. reason that the walkdown focused only on the ELU's that contain greater than two lamps is
. because the highest wattage used at River Bend for emergency lights is 25 watts; thus, if an ELU contains only two lamps then it would not exceed its design load criteria and was not included in the walkdown.
Condition Report (CR) 94-1630 was initiated to investigate the reason for the emergency lighting configuration.
CORRECTIVE STEPS TO BE TAKEN TO AVOID FURTHER VIOLATIONS No additional corrective action is required because the processes that controlled work activities during constmetion are no longer in place.
DATE WHEN FULL COMPLIANCE WILL BE ACHIEVED River Bend Station is in full compliance.
l
i c5 ;
j i
l 4
ATTACIBIENT C REPLY TO NOTICE OF VIOLATION IR 458/9422-04 1 VIOLATION 9422-44 (EXAMPLE D Technical Specifications 6.8.1 states, in pan, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978.
Appendix A of Regulatory Guide 1.33, Paragraph 9.a states, in pan, that maintenance that can affect the perfomiance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions or drawings appropriate to the circumstances.
Contrary to the above, there were two examples where maintenance procedures were not adequate or appropriate to the circumstances:
On April 16,1993, Modification Request 93-0016, an instmetion used to install Rosemount Model 1153 transmitters with damping circuitry, did not provide adequate acceptance criteria to specify the amount of adjustment that was allowed for the damping adjustment screw. Consequently, Reactor level Transmitter >
IB21*LTN080D was overly sensitive to process noise and caused the spurious reactor trip on September 8,1994. i REASON FOR TIIE VIOLATION Entergy Operations concurs with this violation and has detennined that the reason for this event was an oversight on the pan of engineering in that a minimum acceptance criteria was not specified in MR 93-0016.
In 1987, Rosemount model 1152 TO280 transmitters were becoming obsolete. As a replacement, Rosemount suggested the model 1153 transmitter (with damping board option N0037 installed). MR 88-0139 was generated to allow the replacement of the obsolete 1152's with the 1153's. MR 88-0139, which was a document change only (DCO) MR, was generated to allow the replacement of the obsolete 1152's with the 1153's. MR 88-0139 required that the damping be adjusted to the maximum setting for the 1153 transmitters.
On Febmary 6,1991, a field change notice (FCN) to MR 88-0139 was issued to give instmetions for replacement of model 1152 transmitters with model 1153 transmitters. It also required that the damping be set to the maxi. mum.
In March 1993, maintenance replaced the IB21*LTN080D transmitter and a bench test of ,
the new replacement transmitter failed the time response ponion of the Technical
Specification testing because the transmitter was overdamped. MR 93-0016 was then initiated to enable maintenance personnel to reduce the damping for those tansmitters requiring Technical Specification response time testing. However, no minimum damping setting criteria was established for the transmitter potentiometer.
Implicit in MR 93-0016 was the assumption that maintenance would incrementally decrease <
the damping setting on the transmitter's potentiometerjust enough to allow the loop to pass the response time test. Engineering did not anticipate that because of the cumbersome nature of the response time test equipment, maintenance would arbitrarily set the damping to its minimum value when transmitters were required to be response time tested. By setting the damping potentiometer to its minimum, maintenance personnel would be -
assured that they would meet the Technical Specifications on their first attempt at the test.
However, by adjusting the damping of the transmitter to its minimum setting, maintenance was unknowingly negating the damping feature of the transmitter circuitry; thus, making the transmitters overly sensitive to process noise.
In summary, engineering did not establish appropriate constraints on the damping ;
potentiometer setting because they did not anticipate nonconservative interpretations of the guidance included in MR 93-0016. This over ight is the reason for the violation.
CORRECTIVE STEPS TAKEN AND RESULTS ACHIEVED LER 94-023 Supplement I was generated as a result of the scram on September 8,1994, in which RBS personnel identified spurious signals from underdamped Rosemount model 1153 transmitters in response to process noise as the root cause.
Condition Report (CR) 94-1166 was initiated following the scam to investigate the damping problems and identifying corrective action.
4 Rosemount model 1153 tmnsmitters have been replaced with Rosemount model 1152 transmitters in RPS logic applications which have response time requirements.
CORRECTIVE STEPS TO BE TAKEN TO AVOID FURTHER VIOLATIONS Engineering will re-evaluate and determine the appropriate damping acceptance setting criteria for the 1153 model transmitters.
Engineering evaluation and assistance request (EEAR) 94-0035 was initiated to determine a better methodology to conduct response time testing. This will help determine the setting of the damping for Rosemount transmitters which have response time requirements per Technical Specifications.
This condition will be reviewed with engineering personnel to emphasize the imponance of appropriate and thorough post modification test acceptance criteria.
m,
=s x ,
. .d . .
s
~ DATE WHEN FULL COMPIIANCE WITL BE ACHIEVED River Bend Station is in full compliance. The estimated completion date for the corrective . .
- actions ' associated with this violation is January 30,1996.
e I
1 i
(
r i
e 1
o P
C o
'?
ATTACHMENT C REPLY TO NOTICE OF VIOLATION IR 458/9422 VIOLATION 9422-04 (EXAMPLE 2) t Technical Specifications 6.8.1 states, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978.
Appendix A of Regulatory Guide 1.33, Pangraph 9.a states, in part, that maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instmetions or dmwings appropriate to the circumstances.
Contrary to the above, there were two examples where maintenance procedures were not adequate or appropriate to the circumstances:
On hiay 20,1994, hiaintenance Work Order R203595, which was i'itended to install a transmitter with damping circuitry, did not specifically require nor reference the installation of the damping circuitry for Transmitter IB21 *LTN080C. Consequently, the transmitter was overly sensitive to process noise and caused the spurious reactor trip on September 8,1994.
REASON FOR THE VIOLATION Entergy Operations concurs with this violation and has determined that the reason for this event was that the maintenance planner did not properly plan the maintenance work order (hiWO).
On hiay 20,1994, technicians were replacing the Rosemount 1152 model RPS transmitter IB21*LTN080C with a Rosemount i153 model transmitter. This replacement was completed under MWO-203595.
The Maintenance Planning Guidelines (hiPG) state that work instructions should include references that identify specific steps, pages, or sections when possible. The maintenance planner assumed this had been accomplished when he attached and highlighted the applicable portions of the referenced Modification Requests (MR). Furthermore, the maintenance planner referenced the MR's that contained the necessary information for the installation of the damping boaixis in step 10 of MWO-203595. However, step 10 also contained information about the torquing and mounting requirements for the transmitter hardware as well as the reference to the installation and adjustment of the damping circuitry of the transmitters. Since the body of the step dealt with bolt torquing requirements, this lead the technicians to assume the referenced MR's were to be used to determine the torquing values.
m i 1 '
.a,
< i 1
Because the maintenanca planner did not follow the intent of the MPG, a step in the MWO was not written to specifically direct the installation and adjustment of the damping circuitry of the transmitters.
CORRECTIVE STEPS TAKEN AND RESULTS ACIIIEVED The contract maintenance planner has been terminated. ,
LER 94-023 Supplement I was generated as a result of the scram on September 8,1994, in which RBS personnel identified spurious signals imm underdamped Rosemount model 1153 transmitters in response to process noise as the root cause.
Condition Report (CR) 94-1166 was initiated following the scram to investigate the damping problems and identify corretive action.
CORRECTIVE STEPS TO BE TAKEN TO AVOID FURTIIER VIOLATIONS The maintenance planning guidelines will be revised to provide the planners with clear expectations of work instmetion equirements. The estimated completion date for this corrective action is May 10,1995. .
DATE WHEN FULL COMPLIANCE WILL BE ACHIEVED River Bend Station is in full compliance.
l
m
%k;
- gr ATTACHMENT D REPLY.TO NOTICE OF VIOLATION IR 458/9422-05
.VLQLATION Technical Specification 3.3.1 Table 3.3.1-1 requires a minimum of two operable channels per trip system for high reactor water level signal to the reactor pmtection system, and Action J dates: "Be in at least Hot Shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, "when less than the minimum operable channels per trip system are operable.
Contrary to the above, the Channel D reactor protection system reactor water level .
Transmitter 1B21*LTN080D was inoperable from March 24,1992, through March 3, 1993, and the Channel C reactor protection system reactor water level Transmitter IB21*LTN080C was inoperable from January 17,1994, through May 23,1994. During the above periods, the plant was operated with less than the minimum operable channels per trip system, and therefore was in a condition prohibited by the Technical Specificatier,.
REASON FOR THE VIOLATION Entergy Operations concurs with this violation and believes that the reason for the violation was that Plant Engineering Procedure (PEP)-0053 was inadequate. It failed to specify .
acceptance criteria or to provide guidance on the various responsibilities for post-test data review. As a result, there was no straight forward means by.which conditions that could affect operability of the transmitters could be identified until the performance of the associated surveillance test procedure (STP). Additionally, station personnel had two different oppnrtunities to identify and correct the aforementioned Technical Specification non-compliance.
' On October 3,1994, a review of reactor pmtection system (RPS) level transmitter response time data as recorded in System Engineering procedure PEP-0053, " Sensor Response Time Testing Using Process Noise," indicated that the Channel D RPS level transmitter had a response time of 1.197 seconds in Febmary 1992 and the Channel C RPS level transmitter had a response time of 1.190 seconds in January 1994. In each case, it was not recognized at the time that these values exceeded the Technical Specification acceptance criteria of 1.05 seconds and, as a result, no action was taken to address the non-compliance with Technical Specification 3.3.1.
The incident associated with the Channel D RPS level transmitter occurred during the second performance of PEP-0053. Testing was performed on February 24,1992 just prior to Refueling Outage 4 (RF-4) (March 9,1992) and the preliminary test results were received from Westinghouse by System Engineering on February 24,1992. These values were entered into PEP-0053, and transmitted to I&C for use in the associated Surveillance Test Procedures (STPs). The preliminary data for the Channel D RPS level transmitter
L$ '
/
indicated a time response value of 1.197 seconds. The final Westinghouse report was submitted on April 18,1992 which also indicated the same time response value of 1.197 ;
seconds.
p On March 3,1993 the Channel D RPS level transmitter was replaced under Maintenance l Work Order (MWO) R158011. This MWO was originally initiated due to a drifting trip l unit. After the I&C technician replaced the trip unit, he pulled the most recent PEP-0053 performance (February 24,1992) to acquire the previously measured sensor response time _
for the Channel D transmitter. It was subsequently determined that, in accordance with the data documented in PEP-0053, this transmitter exceeded the Technical Specification allowed criteria. As a result, the transmitter was replaced and subsequently tested (via the ,
hydraulic ramp method) to ensure compliance with Technical Specifications. Upon discovery that the transmitter had exceeded the Technical Specification allowable limit the technician was required to initiate a Condition Report (CR) in accordance with RBS '
procedures to document the non-compliance and ensure the condition was adequately addressed. However, no CR was generated and the non-compliance went undetected.
The condition associated with the Channel C RPS level transmitter occurred during the third performance of PEP-0053. Testing began on January 17,1994 just prior to RF-5 (April 16,1994). The final results were received from Westinghouse on March 3,1994 :
and incorporated in PEP-0053. The final response time for the Channel C transmitter was 1.190 seconds. After a preliminary review, System Engineering submitted the results to 1 I&C. A cursory review by I&C revealed that the Channel C level transmitter appeared to l have an excessively high time response and an evaluation was requested from System Engineering. The cvaluation addressed concerns associated with the transmitter Residual l Heat Removal (RHR) isolation function and determined that the high response time was acceptable in that regard. These results were subsequently submitted to I&C. The -
evaluation did not include the functional mquirements associated with scram response times !
and neither the I&C Technician or System Engineer identified that the transmitter had exceeded the Technical Specification acceptance criteria. However, System Engineering ,
noted an adverse response time trend and, as a result, the transmitter was replaced on May ;
23,1994.
I In addition, there were two opportunities where the non-compliance should have been l identified. The first opportunity occurred during the March 3,1993 replacement of the ;
Channel D transmitter. There were procedural requirements in place at the time that required the generation of a CR to ensure adequate evaluation of adverse conditions. i However, no CR was initiated. As later discovered by Entergy assessments of RBS, there )
was an overall reluctance by site personnel to initiate CRs.
The second opportunity occurred during the May 23,1994 replacement of the Channel C l transmitter. During a cursory review of the PEP-0053 data, the I&C department noted that the Channel C transmitter appeared to have an excessively high time response which was subsequently evaluated by System Engineering. Neither the I&C Technician or the System Engineer involved became cognizant of the Technical Specification requirements associated
r 5
D 1
l with the scram function of the transmitter. As a result, an evaluation was performed which concluded this time response to be acceptable based on the isolation function of the transmitter without consideration for the scram function.
In summary, PEP-0053 did not specify acceptance criteria or provide guidance on the ,
various responsibilities required for procedure implementation and this was the primary reason that the procedure was inadequate. A contributing factor was that after the results -
were transmitted to I&C they were not utilized until the associated STP was performed.
This resulted in a delay for comparison of Technical Specification acceptance criteria to time response dita. Finally the fact that station personnel had two separate chances to identify and cormet the non-compliance contributed to the fact that the plant was operated with less than the minimum operable channels per trip system, and therefore was in a condition prohibited by A Technical Specifications.
CORRECTIVE STEPS TAKEN AND RESULTS ACHIEVED System engineering completed a historical review of all PEP-0053 data. No other discrepancies were identified.
Appropriate performance feedback / counseling was provided to individuals involved in this event.
- CORRECTIVE STEPS TO BE TAKEN TO AVOID FURTHER VIOLATIONS An evaluation will be performed to identify procedures similar to PEP-0053 (i.e., data gathering procedures that do not include specific acceptance criteria). Appropriate acceptance criteria will be incorporated based on the results of this evaluation.
PEP-0053 will be revised to incorporate the necessary acceptance criteria and clearly assign responsibility for review of the test data.
Condition Report (CR) 94-1263 was initiated to investigate this event and report it under 10CFR50.73(a)(2)(i) via LER 94-031.
DATE WHEN FULL COAU'LIANCE WILL BE ACHIEVED River Bend Station is in full compliance. Corrective action will be completed by June 16, 1995.