ML20129H664
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UNITED STATES 4
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,i NUCLEAR REGULATORY COMMISSION j
WASHINGTON, D.C. 20505
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March 23,1992
(
- 9}fy g "/[ g Docket Nos. 50-424 and 50-425 License No. NPF-68 and NPF-81 EA 92-041 6f MEMORANDUM FOR
- ' James Lieberman, Directo:
Office of Enforcement FROM:
James G. Partlow Associate Director'for Projects Office of Nuclear Reactor Regulation
SUBJECT:
EA 92-041, GEORGI A POWER COMPANY, V0GTLE ELECTR :
GENERATING PLANT, PROPOSED DISCRETION FOR WILLF VIOLATION The Division of Reactor Projects - 1/11 has reviewed the Regior.> Enforcement
. Recommendation regarding Vogtle Nuclear Generat' m 31 ant, Unitt and 2.~ We concur with the action proposed by Region II.
The review was performed to ensure that the violations were pre y evaluated from 'an overall agency perspective, and.has the concurrence of.
- rt Jones of the Reactor Systems Branch technical staff. NRR believes tl
- he proposed enforcement action is appropriate and supports-it. Our specif' xmments on the Enforcement Action are enclosed.
g 1
James G. Partlow Associate Director for ijects Office of Nuclear React
.egulation
Enclosure:
As-stated CONTACT:
D. Hood, NRR 504-3049
-SEWSl-T1
- PRE-DECISIONAL INFORMATION - INTERNAL DISTRIl-
'N ONLY
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V 9611040005 960827 PDR FOIA KOHN95-211 PDR
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NAL INFORMATI RNAL DI RIF 0FFICE OF NRR COMMENTS ON REGIONAL ENFORCEMENT RECOMM.g ATION EA 92-041 l
Were the violations technically accurate and factual?
Yes Did the region properly assess the root causes of the violatior.. and the adequacy of corrective actions?
Yes Were the licensee's prior and current performance and prior nc' s of the violations properly reflected?
Yes Is the regulatory significance of the violations or root cause.; 'roperly evaluated?
Yes Is the licensee's position, if known, regarding the violations p operly reflected?
Yes is the message given to the licensee appropriate to the situat
?
Yes Is a significantl te (Order, Suspension, etc.)y different type of enforcement action appror
, and if so, why? (Not amount of penalty or arity level.)
No Any other comments on factual or technical issues.
None NRR Office
Contact:
D. Hood 504-3049 DATE:
SENSI IVE -
E-DECISIONAL FORMATION -
ANAL ~. STRI.
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NUCLEAR REGULATORY COMMISSION j
WASHINGTON, D.C. 355
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March 25, 1992
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Docket No. 50-424 License No. NFP-68 l
EA 91-141 I
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NEMORANDUM FOR: James Lieberman, Director Office of Enforcement j
FROM:
James G. Partlow Associate Director for Projects Office of Nuclear Reactor Regulation 1
SUBJECT:
PROPOSED LEVEL III VIOLATION - V0GTLE ELECTRIC GENERATING
}
PLANT, UNIT N0. 1 i
~ he Division of Reactor Projects - I/II has reviewed the Regional Enforcement T
Recossendation regarding Vogtle Electric Generating Plant, Unit No. 1.
We 1
concur with the action proposed by Region II.
The review was performed to ensure that the violations were properly evaluated i
from an overall agency perspective, and has the concurrence of Robert Jones of
- i the Reactor Systems Branch technical staff. Specj.(ic coseents on the proposed j
Enforcement Action are enclosed.
f1 Janes G. Partlow Associate Director for Projects Office of Nuclear Reactor Regulation
Enclosure:
As stated.
CONTACT:
L. Raghavan, NRR 504-2019 N-Stnu (IVE - PRE 61W6RMATINiiinIBUTIDM Cb
%g>
b
1 MNt1QT16N ON ONLY i
0FFICE OF NRR COMMENTS ON REGIONAL ENFORCEMENT RECOMMENDATION EA 91-141
~
Were the violations technically accurate and factual?
Yes Did the region properly assess the root causes of the violations and the adequacy of corrective actions?
Yes Were the licer.see's prior and current performance and prior notice of the violations properly reflected?
Yes Is the regulatory significance of the violations or root causes properly evaluated?
Yes Is the licensee's position, if known, regarding the violations properly reflected?
j Yes
!s the message given to the licensee appropriate to the situation?
Yes Suspension, etc.)y different type of enforcement action appropriate (Order.
Is a significantl
, and if so, why? (Not amount of penalty or severity level.)
No Any other c,omments on factual or technical issues.
1 See attached comments j
i NRR Office
Contact:
L. Raghavan, NRR 504-2019 DATE:
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SENSITIVE - PRE-D! p TM W NLY i
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ATTACHMENT t.SEdiT IONAL M (ONLY I
COMMENTS i
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1.
Appendix, Page 2, Paragraph 3, Add an additional sentence:
In fact, the term "immediate" reinforces and establishes the absence of latitude.
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i 2.
Al,sendix, Page 2 3
/aragraph 2 refers to " Technical Specification (TS) Improvement Program i
i Highlights " section " Voluntary Entry into Technical Specification Action j
Statements" to describe the NRC's view on voluntary entry into TS. As 1
j further evidence to this policy guidance, reference may be made to i
NRC Inspection Manual. Part 9900. Technical Guidance, section entitled J
j
" Maintenance - Voluntary Entry into Limiting Conditions for Operation
)
Action Statements to Perform Preventive Maintenance" (issued April 18, 1991), by adding the following to the end of Paragraph 2:
This policy is further evident in the ilRC Inspection Manual, Part i
9900, Technical Guidance, section enntled " Maintenance - Voluntary i
Entry into Limiting Conditions of Operation Action Statements to Perform Preventive Maintenance" which states that "Intenticnal entry t
l into act hn statement of an LCO is not a violation of tht 15 (except in certain cases such as intentionally creating a loss of function.
i-situation or entering LCO 3.0.3)."
(emphasis added) 3.
Appendix,Page4. Item (a) i i
We suggest that the difference between the Sequoyah and Vogtle situation can be further emphasized by revising the second sentence as follows:
l-(Revisionunderlined)
)
At Vogtle the valves were manipulated not as an operating evolution.
j b*ut rather as an intentional and unreviewed action to add chemicals for crud burst control. This action placed the plant outside the j
LC0 and could hcVe been performed at a time when the T5 did not preclude operation of the valves.
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- d MAR 2 01992 a
i Docket Nos. 50-424, 50-425 i
[
EA 92-041 Georgia Power Company-ATTN: Mr. W. G. Hairston, III-i-
Senior Vice' President -
l Nuclear Operations j
P.-0. Box 1295
-Birmingham, AL -35201 i
l Gentlemen:
1-
SUBJECT:
- NRC INSPECTION REPORT NOS. 50-424/92-02 AND 50-425/92 '
L i
This refers to the inspection conducted by B. Bonser of this office on January 26 - February 22, 1992. The. inspection included a review of activities j
authorized for your Vogtle facility. At the conclusion of the inspection, the findings were discussed with those members of your staff identified in the
' enclosed report.
Areas eumined during the inspection are identified in the report.
Within 3
these areas, the inspection consisted of se?feive examinations of procedures and representative records. interviews with wrsonnel, and observation of i
activities in progress.
Based on the results 'of this inspection, certain-of your activities appeared to be in' violation of.NRC. requirements. ' On January 28, 1992, two Instrumen-tation and Control technicians performed a. surveillance on reactor trip system
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instrumentation.
Your staff reported to the NRC that the technicians failed to 1
properly follow the surveillance procedure and sub:,equently created the ~ data 4
that was entered on.the calibration data sheet.
Willful violations such as this apparent falsification are of great concern to the NRC because the safe i
operation of nuclear facilities depends on the integrity, as well as the ability, of the individuels who operate and maintain them.
Accordingly, a l
Notice of Violation is not being issued at this time and a response is not required.
However, please be advised that evaluation of this matter is l
continuing and that the number and characterization of the apparent violation described-in the enclosed Inspection Report may change as a result of further rniew.
You will be advised of the results of our deliberations on this matter in separate correspondence.
In accordance with 10 CFR 2.75C(a), a copy of this letter and its enclosure will be placed in the NRC Public Document Room.
h I
% Y 'c
l Georgia Power Company 2
MAR 2 01992 Should you have any questions concerning this letter, please contact us.
Sincerely I
hvlq%al SE
% frs A. ecy Luis A. Reyes, Director Division of Reactor Projects
Enclosure:
NRC Inspection Report cc w/ encl:
R. P. Mcdonald Executive Vice President-Nuclear Operations j
Georgia Power Company P. O. Box 1295 i
Birmingham, AL 35201 C. K. McCoy Vice President-Nuclear Georgia Power Company P. O. 1295 Birmingham, AL 35201 W. B. Shipman General Manager, Nuclear Operations Georgia Power Company P. O. 1600 Waynesboro, GA 30830 1
J. A. Bailey Manager-Licensing Georgia Power Company P. O. Box 1295 Birmingham, AL 35201 Nancy Gibson Cowles Consumers' Utility Counsel Office of Consumers' 'Jtility Counsel 4
84 Peachtree Street, N.W., Ste. 201 Atlanta, Georgia 30302-2318 Office of Planning and Budget i
Room 61L5B 270 Washington Street, SW i
Atlanta, GA 30334 l
(cc w/onel cont'd - see page 3)
)
Georgia. Power Company 3
MR 2 0 592 cc w/ enc 1:.(Continued)
' Office'of the County Commissioner
' Burke. County Consission Waynesboro, GA 30830 Harold Reheis, Director Department of Natural Resources 205 Butler Street, SE', Suite 1252 Atlanta,.GA. 30334
- Themas Hill, Manager Radioactive Materials Program Department of Natural Resources 4244 International Parkway LSuite 114.
Atlanta, GA -30354 Attorney General-Law Department 132 Judicial Building
' Atlanta, GA 30334 Dan Smith, Program Director of Power Production Oglethorpe Power Corporation 2100 East Exchange Place Tucker, GA ~30085-1349 Charles A. Patrizia, Esq.
Paul, Hastings, Janofsky & Walker 12th Floor 1050 Connecticut Avenue, NW Washington, D. C.
20036 bec w/ enc 1:
J. Johnson, RII S. Sparks, RII D. Hood, NRR P. Skinner, RII A. Herdt, RII Document Control Desk NRC Resident Inspector U.S. Nuclear Regulatory Comission P. O. Box 572 Waynesporo, GA 30830 h
F p $ ~/
/ v Sparks PSkinner AHerdt 3/f/92 3g92 3/je/92
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Oy'o UNITED STATES NUCLEAR REGULATORY COMMISSION
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101 MARIETTA STREET,N.W.
ATLANTA, GEORGIA 30323
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Report Hos.:
50-424/92-02 and 50-425/92-02 Licensee: Georgia Power' Company
~P.O. Box 1295 2 -
Birmingham, AL 35201 Docket Nos.:
50-424 and 50-425 License Nos.:
NPF-68 and NPF-81 Facility Name:
Vogtle 1 and 2 Inspection Conducted: January 26 - February 22, 1992 Inspectors: b Lh-3/7 d/f F B. R.IBo er,SeniqyResidentInspector Date Signed MJA Jt WN-R.' D. Starky, Res/ dent Inspector Date Signed 0)W w,/n 3kft1-P.A.Balmain,ResiptInspector Da'te Signed Approved
- P. Skinner, Chief Dite Signed i
Reactor Projects Section 3B Division Reactor Projects i
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SUMMARY
t Scope:
This routine inspection entailed inspection in the following areas:
plant operations, surveillance, maintenance, F.SF system walkdown, review of licensee events reports and followup.
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Results: One apparent violation was identified for failure to follow procedure.
I&C technicians, after determining that the as found settings on an Over Pressure / Delta Temperature runback bistable were outside the allowable limits, adjusted the bistable setpoints without performing the applicable calibration section of the procedure as required. Upon realizing that the appropriate calibration data sheet was not completed the technicians willfully falsified the data sheet.
An ESF walkdown of the Unit 2 Piping Penetration Filtration and Exhaust system was performed.
Based on the walkdown no concerns regarding operability of the system were identified.
Several minor discrepancies were noted and brought to the attention of the licensee i
for corrective action.
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'l Two similar DG failures have occurred in the past year.
The licensee's investigations into these failures has been unable to 3
determine a root cause.
On February 5, 1992, when DG 28 was paralleled to the grid as part of its normal monthly surveillance test, VARS decreased to -4200 and the DG voltage controller'would not respond.
This failure was similar to. failures which occurred on DGs 2A and 2B on January 29, 1991.
i General housekeeping in the penetration rooms has improved, but the material condition of. sampling system valves continues to be poor.
Work orders are not consistently generated on these leaking valves to j
initiate the repair process and alert the corrosion assessment engineers of a. potential problem.
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1 DETAILS i
1.
Persons Contacted n
Licensee Employees i
- B. Baker, Maintenance Engineer i
- H. Beacher, Senior Plant Engineer i
- J. Beasley, Assistant General Manager Plant Operations
- R. Brown, Supervisor Operations Training l
W. Burmeister, Manager Engineering Support i
- S. Chesnut, Manager Engineering Technical Support 1
- C. Christiansen, Safety Audit-and Engineering Group Supervisor W. Copeland, Supervisor - Materials C. Coursey, Maintenance Superintendent
~*J. D'Amico, Outage Scheduling Supervisor R. Dorman, Manager. Training and Emergen:y Preparedness
- J. Gasser, Operations Unit Superintender M. Hobbs, I&C Superintendent K. Holmes, Manager Health Physics and Ci.eif stry
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- D. Huyck, Nuclear Security Manager W. Kitchens, Assistant General Manager Plant Support
- R. LeGrand, Manager Operations
- G. McCarley ISEG Supervisor R. Mansfield, Plant Engineer Supervisor.
- R. Odom -Plant Engineer Supervisor A. Parton, Chemistry Superintendent
- B. Raley, Plant Engineer Supervisor - Maintenance
- M. Seepe, Radwaste Supervisor
- M. Sheibani, Nurlear Safety and Compliance Supervisor
- W. Shipman, General Manager Nuclear Plant
- C. Stinespring, Manager Administration J. Swartzwelder, Manager Outage and Planning C. Tynan, Nuclear Procedures Supervisor
)
L. Ward, Manager Maintenance - Acting Other licensee employees contacted included technicians, supervisors, engineers, operators, maintenance personnel, quality control inspectors, j
and office personnel.
Oglethorpe Power Company Representative
- T. Mozingo NRC Resident Inspectors
- B. Bonser D. Starkey
- P. Balmain
- Attended Exit Interview i
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An alphabetical list of abbreviations is located in.the last paragraph of the inspection report.-
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2.
P1 ant Operations - (71707) l j
a.
_ General The inspection staff reviewed plant operations.throughout the 4-reporting period to verify conformance with regulatory requirements, Technical Specifications, and administrative controls.
Control logs, shift supervisor logs, shift relief records, LCO status. logs, night
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orders, standing orders, and clearance logs were routinely reviewed.
Discussions were conducted with plant operations, maintenance,
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chemistry and health physics, engineering support and technical i
support personnel.
Daily plant status meetings were routinely attended.
Activities within the control room were monitored during shifts and shift changes.
Actions observed were conducted as required by the i
licensee's procedures.
The complement of licensed personnel on each shift met or exceeded the minimum required by TS.
Direct observations were conducted of control room panels, instrumentation and recorder traces important to safety.
Operating parameters.were j
observed to verify they were within TS limits.
The inspectors'also reviewed DCs' to determine whether the licensee was appropriately documenting problems and implementing corrective actions.
Plant tours were taken during the reporting period.on a routine basis.
They included, but were' not limited to the turbine building, the auxiliary building, electrical equipment rooms, cable spreading rooms, NSCW towers, DG buildings, AFW and the low voltage switchyard.
During plant tours, housekeeping, security, equipment status and radiation control practices were observed.
The inspectors verified that the licensee's health physics policies / procedures were followed.
This included observation of HP practices and review of area surycys, radiation work permits, postings, and instrument calibration.
The inspectors verified that the security organization was properly manned and security personnel were capable of performing their assigned functions; persons and packages were checked prior to entry into the PA; vehicles were properly authorized, searched, and escorted with the PA; persons within the PA displayed photo identification badges; and personnel in vital areas were authorized.
Also during this inspection period the inspectors observed security force weapons-training and qualification.
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~b.
Unit 1 Summary Unit I remained at full power throughout the. reporting period.
' c.
Unit 2:Sumary l
The unit began-the inspection period operating at 100% power.
With Unit.2 approaching the end-of-cycle, unit coastdown began on February 4
-16.
At the end of the inspection period power had decreased to 94%.
l The_second Unit 2 refueling outage is scheduled to begin on March 13.
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d.
Emergency Drill j
On January 31, 1992, the licensee conducted a repeat of the semi-annual HP drill which had been conducted on December 9,1991.
i The drill in December had failed to meet several of the drill i
objectives and was judged by both the licensee and the' inspectors to be unsatisfactory.
The January drill was conducted using a scenario similar to the previous drill. The drill objectives were to complete l
all onsite and offsite notifications, to timely activate all onsite ERFs, to respond to simulated' elevated radiation measurements in the i
environment, to perform onsite personnel accountability, to respond to intruders, and to properly respond to a medical emergency.
j During the repeat drill, the inspectors observed the drill from the TSC, OSC, and the scene of the medical emergency.
The inspectors took particular note as to whether the deficiencies observed in the previous drill had been corrected.
In each case, the previous i
deficiency was corrected.
Overall, the drill went smoothly and was i
judged by the licensee and the inspectors to be satisfactory and met i
the drill objectives.
Several minor findings were noted by the licensee during the drill critique and have been assigned to the j
appropriate group for corrective action.
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j e.
Failure of Diesel Generator 2B To Load i
On February 5. DG 2B was started for its monthly surveillance run per
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procedure 14900-2, Diesel Generator Operability Test.
The DG was j
synchrcnized and then paralleled to the 4160 KV emergency bus per the procedure. When the DG output breaker was closed, the Low Excitation alann was received and the VARS decreased to approximately -4200 l
while the DG load was 1500 KW.
The Control Room operator attempted i
to increase the VARS by depressing the " raise" push button on the i
voltage controller but the voltage controller would not respond.
After consulting ~with the DG system engineer, the output breaker was opened, the DG was synchronized to the grid again and the output breaker was reclosed.
The voltage responded correctly, the DG was loaded and the surveillance was successfully completed. The licensee entered the applicable LC0 Action statement at the time of the failure and exited the LC0 upon the successful completion of procedure 14980-2.
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4-The licensee assigned an event critique' team to review the failure i
and to identify the root cause.
On February 6 and 7, the 2B DG was
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run again with monitoring equipment connected to capture the response-1 of the voltage regulator during the test.
The tests conducted on j
these two days did not obtain any information which could identify 1
i the cause of ~ the abnonnality that occurred on February 5.
The l'
licensee is. now testing 1the 2B DG weekly for its normal surveillance with - monit'oring ' equipment connected.
The -licensee developed - a Temporary Engineering Procedure, T-ENG-92-01, which was conducted on February 25.
The purpose of this procedure was to simulate as closely as possible the conditions present during the-2B DG failure J
on _ February 5.
Particular attention was paid to determining the low excitation limiter setpoint and any abnomalities at that setpoint.
4 The test determined that the excitation limiter setpoint is -2400 KVARS. The excitation limiter is functional only after the generator j
output breaker is closed and is affected only by external operation of the voltage controller pushbutton in 'the ' control room.
An internal voltage regulator problem was therefore apparently responsible for the -4200 KVAR reading on February 5 and could have caused the KVAR reading to go below the setpoint of the exitation r
limiter.
The February 25 test could not. reproduce the previous problem and the critique team could not confirm definitely whether j
the problem was in the parallel circuitry, the voltage regulator, or some other wiring problem. Neither can the licensee confim that the
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2B D/G would have been capable of performing its safety function j
either in the unit or parallel mode of operation on February 5.
i When the inspection period ended, the licensee event critique team had not completed its review of'the 28 DG failure. The licensee will replace the voltage regulator and followup with the D/G vendor on any j
other actions which can be taken.
The inspectors will continue to monitor the investigation of this DG failure.
It should be acted that a similar failure occurred on the 2A D/G on January 29, 199 and is discussed in IR 50-424, 425/91-02.
The licensee was unable to definitively characterize the cause of that failure.
f.
Boric Acid Buildup On Sampling Valves The inspectors performed a walkdown of the Unit 1 and Unit 2 piping penetration rooms.
Excessive accumulation of boric acid was observed on two safety-related containment isolation valves.
Both valves are part.of the RCS sampling system. One valve was located in each unit.
A concern regarding significant boric acid leakage and accumulation in these rooms was raised and documented during the Maintenance Team Inspection (IR 50-424,425/91-03).
It was noted during the MTI that no attempt was made to contain the leakage.
Leakage noted during this inspection was effectively contained to the immediate vicinity of the leaking valves and general housekeeping in the penetration rooms had improved.
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Following the walkdown, the inspectors reviewed the ' licensee's actions taken to control the leakage and to evaluate any boric acid l
induced corrosion.- The inspectors learned that the licensee normally 4
cleans and decontaminates components located in high radiation areas-approximately every two months. A work request is normally initiated to repair the leaking components 'and engineering technical support is notified to perform a corrosion assessment if needed.
j In response to the inspectors concern, the licensee' decontaminated the valves and performed a corrosion assessment of the borated valves noted in the walkdown.
Following the decontamination, the licensee determined that three valves were leaking, not two as discussed i
earlier. The two leaking valves on Unit 2 had work orders written to repair the leaks (2HV3502, RCS Hot-Leg )1 and 3 Sample Valve, and i
2HV3508, Pressurizer Liquid Sample Valve, the Unit 1 valve (1HV3502, 4
RCS Hot Leg 1 and 3 Sample Valve) did not have a work order written l
to repair the leak.
The licensee initiated a work request to repair this valve.
Also the licensee's corrosion assessment determined that l
a support' plate associated with 1HV3502 had significant material i
degradation.
The licensee determined that the degradation was not severe enough to affect the operability of the support and initiated a Deficiency Card to track 'the problem.
A work order was also generated to -repair the support and to possibly apply a protective coating to the support.
4 The inspector concluded that general housekeeping in the penetration rooms has improved, but the material condition of sampling system valves continues to be poor. The inspectors also concluded that work orders are not consistently generated on these leaking valves _ to initiate the repair process and alert the corrosion assessment l
engineers of a potential problem.
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g.
2A Diesel Generator Jacket Water Leak l
On February 19, during observation of a routine surveillance of the 2A DG, the f 1spector noted excessive leakage of jacket water which required manual makeup to the DG jacket water standpipe.
Following l
this observation, the inspector expressed an operability concern to the licensee for long term operation of the DG under LOSP conditions.
j Under LOSP conditions, demineralized water makeup would not be available via the demin water transfer pumps, since these pumps are not provided with emergency power.
The licensee evaluated the concern and prepared a Standing Order (2-92-02) to provide a primary and backup means of providing makeup to the DG jacket water standpipe in the event that power is lost to the demin water transfer pumps.
The primary means of makeup is with gravity fill from the denim water storage tank through the normal makeup valve.
If the demin storage tar.k level is less than 14 feet
.. - ~. -. _..
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gravity ff11 m ld not provide adequate makeup.
A back-up filling l-method was cealoped using the firewater supply.
Fire water can be pumped to the standpipe under LOSP conditions since the system is supplied with diesel driven pumps.
Instructions for connecting the f'
fire water supply to the DG jacket water standpipe are provided in the Standing Order. Tools and appropriate connections are located in the Control Room and are designated for emergency use only.
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h.
Control of. Divergent Axial Flux Oscillation l
During this inspection period the Unit 2' reactor core began to experience a divergent axial flux oscillation.
Flux oscillations of this nature occur predominantly at the end of cycle.
Fuel burnup in the core throughout the cycle causes flux to shift towards the top of 4
the core at end of cycle due to the burnup of the bottom and center portions of the core.
At end of cycle this redistribution leads to conditions which can initiate a divergent flux oscillation due to the decreased _ axial stability of the core. The inspectors noted that i
reactor engineering and operations efforts to analyze and implement j
appropriate actions ~ to bring the oscillation under control were effective.
Reactor Engineering projected the behavior of the-oscillation and advised operators of the approximate time to damp the oscillation.- Throughout the coastdown, the inspectors observed that H
the licensee closely monitored the core's behavior and updated target AFD values as necessary to reflect core burnup.
Operation's and Reactor Engineering's efforts in maintaining control of AFD. are noteworthy.
No violations or deviations were identified.
ESFWalkd'wn(71710) 3.
o The inspectors conducted a walkdown of the Unit 2 Piping Penetration Filtration and Exhaust system.
Procedure 11305-2, Auxiliary Building System Alignment, and system drawings were used to verify proper system alignment.
All electrical.and mechanical components were found in their required position.
The inspector noted several labeling discrepancies between the line up procedures and the component labels.
Minor format errors were identified in the line-up procedures. These items were brought to the attention of the licensee.
Based on this walkdown the inspectors had no concerns with the operability of the system.
In response to minor procedural inefficiencies, inconsistencies and component tagging deficiencies found by the licensee and the frequent
. finding of similar deficiencies by NRC inspectors, the licensee is undertaking a - comprehensive walkdown program on both units.
All Operations shifts have been assigned systems to walkdown and document discrepancies for action.
This is a long-term program which will take several months to complete.
Once this effort is completed it is expected that procedures will be enhanced and more operator oriented. They will be consistent between units, and procedures and component tags will agree.
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This program'is also an effort to increase the sense of accountability and system ownership among the Operations shifts.
No violations or deviations were identified.
4.
SurveillanceObservation(61726) a.
Surveillance tests were reviewed by the inspectors to verify
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procedural and performance adequacy.
The completed tests reviewed i
were examined - for necessary test prerequisites, instructions, acceptance criteria, technical content, data collection, independent verification where required, handling of deficiencies noted, and review of. completed work.
The tests witnessed, in whole or in part, were inspected to determine.that approved procedures were available, equipment was calibrated, prerequisites were met, tests were conducted according to procedure, test results were acceptable and systems restoration was completed.
Listed below are surveillances which were either reviewed or witnessed:
Surveillance No.
Title 14514-C Fuel Handling Building Post Accident Exhaust i
System Operability Test 14545-2 Motor Driven Auxiliary Feedwater Pump Monthly Operability Test 14807-2 Motor Driven Auxiliary Feedwater Pump Inservice Test i
l 14804-2 Train A Safety Injection Pump Inservice Test l
4 j
14980-2 Diesel Generator Operability Test l
24811-2 Delta T/T AVG Loop 2 Protection Channel II Analog Channel Operational l
54067-C Fuel Handling Building Post Accident Ventilation System Actuation 54824-2 Train A CCW Pumps Response Time Test b.
Failure To Follow Surveillance Procedure On January 28, 1992, at 1:54 a.m., I&C technicians were authorized to perform the ACOT section of Unit 1 surveillance procedure 24812-1, Delta T/T Avg Loop 3 Protection Channel III IT-431 Analog Channel Operational Test (ACOT) and Channel Calibration. The purpose of this procedure is to verify operability and. settings in reactor trip
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i system instrumentation for Overtemperature Delta T and Overpower Delta T, and ESFAS instrumentation Low RCS T Avg Coincident With a Reactor Trip.
The procedure consists of disabling the process sensors from the field instrument and artificially-inserting a test signal into the circuitry to verify the settings in the actuation circuitry are correct.
Should the as found settings be found outside the. allowable range,- the allowable settings are given in a data' sheet i
contained in the procedure, the procedure requires that an adjustment i
be accomplished by performing a calibration. When the calibration is i
complete the procedure requires a repeat of the ACOT. At 4:01 a.m.,
the procedure was signed off as being performed satisfactorily.
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Following the recently completed outage on Unit 1 the licensee i
implemented design changes to revise the runback setpoints on OTDT and OPDT from 3% -below the reactor trip setpoint to 1% below the reactor trip setpoint to eliminate runback alarms (see IR 424.
425/91-32).
As part of the design change several procedures were revised. During the revision process, through an oversight, the ACOT section of procedure 24812-1 was not revised to reflect the new 1%
margin.
The calibration section of the procedure was revised correctly.
At 4:11 a.m.,
on January 28 the OP Delta 'T Runback bistable momentarily alarmed on the Main Control Board.
The licensee became concerned after the OPDT bistable had alarmed twice.
Based on the modifications described above, there was apparently no reason for a runback bistable to alarm.
I&C supervision immediately began a review of the ACOT procedure to see if any discrepancies existed.
Upon reviewing the procedure. 'it becane apparent that the ACOT procedure was incorrect and the numbers written in the calibration data sheet were not valid data readings since they corresponded to a 1% margin setting and not the 3% margin in the ACOT.
Due to these problems there was some suspicion by the licensee management of procedure non-compliance and falsification of the data sheet.
The inspectors held discussions with licensee personnel, including upper level management, to verify the events. When the two I&C technicians who performed the procedure were confronted with these discrepancies they immediately admitted that they had made the adjustment without following the procedure and had created the data in the calibration data sheet to cover their failure to follow the procedure.
The technicians stated the.t when they had performed the procedure the as found tolerances in the verification section of the ACOT procedure did not match the expected tolerances listed in the attached data sheet.
When the technicians found this condition they called their supervisor, as required, and asked for direction.
The supervisor told them to call for QC and complete the procedure. The apparent meaning of the supervisor and the reason to call for QC was to adjust the bistable setpoints by performing the calibration portion of the procedure and to have QC verify the adjustment.
As mentioned above, the only acceptable method of adjusting bistable 1
l-4 9
V setpoints is to perform the calibration procedure.
At this time there was some discussion between the two technicians as to the i
proper method to restore the bistable to within tolerance.
Rather than following the procedure and using the calibration section for 4
the bistable, the decision was made to make an adjustment to the bistable using the ACOT configuration even though this method was not procedurally correct.
After making the adjustment QC was called to a
j witness that the as left readings were within acceptable limits. The QC inspector verified that the I&C technicians obtained acceptable ACOT readings and signed off the QC hold point in the calibration section of the procedure.
After completing their work, one of the technicians returned to the I&C. shop to review the paperwork. At this time he realized that for the paperwork to be complete a calibration data sheet was required since an adjustment had been made.
To support the adjustment made, the technician ~ filled out the calibration data sheet with numbers that he thought would appear correct..
The technician did not realize, however, that the ACOT portion of the procedure was incorrect and the voltage readings in the calibration section would not correspond to the voltage readings in the ACOT section.
The technicians were also questioned by the licensee about any possible previous incidents of this type while working at Vogtle.
The licensee stated that they assured their supervision they had never engaged in this ' type of non-compliance and falsification previously. The licensee also stated a review of past work perfonned by the I&C technicians was conducted, which resulted. in no similar occurrences. The licensee was not aware.of any other similar events.-
The licensee has discussed-the significance of this event with the supervisor as well as the procedure writer.
The need for clear, proper communication was emphasized with the supervisor, and the importance of the incorporation of new data into procedures was stressed with the procedure writer.
Although the QC inspector verified the ACOT data in accordance with the procedure hold point, a closer review and verification of the work activity by QC may have detected the discrepancies.
The licensee identified this event and notified the resident inspectors as soon as it became apparent that the data sheets had been falsified.
The licensee has perfonned a th3 rough investigation and has taken disciplinary action against the individuals involved.
The licensee also stated that the disciplinary action would be an appropriate deterrent.
The inspectors also reviewed the safety significance of incorrectly setting the runback bistable. The runback functions on both OTDT and OPDT are not assumed or required for accident mitigation in the accident analyses presented in the FSAR.
The receipt of runbacks could, however, prevent the unit from achieving 100% power.
The
~
10 2
j receipt of-signals from two bistables would have caused a turbine runback..
In this case the bistable was set in a conservative direction which would have caused a runback to occur at a lower power.
This event is identified as an apparent Violation l
50-424/92-02-01:
Failure' To Follow Procedure Results in Turbine Runback Alarm and Falsification of Data.
This apparent violation will be the subject of further NRC review.
j One apparent violation was identified.
I 5. --
Maintenance Observation (62703)
{
a.
General The inspectors observed maintenance activities, interviewed l
personnel, and reviewed records to verify that work was conducted in accordance with' approved procedJres, TSs, and applicable industry l
codes and standards.
The inspectors also frequently verified that i~
redundant components were operable, administrative controls were j
followed, clearances were adequate, personnel were qualified, correct i
replacement parts were used, radiological controls were proper, fire protection was adequate, adequate post-maintenance testing was l
performed, and independent verification requirements were i
implemented.
The inspectors independently verified that selected equipment was properly returned to service.
j Outstanding work requests were reviewed to ensure that the licensee i
.gave priority to safety-related maintenance activities.
1 The inspectors witnessed or reviewed the following maintenance i
activities:
MWO No.
Work Description 19104850 1T-12624C Piping Pen Filter 2 Temp indicator appears to have a bad indicator light 19105751 Install Crankcase Heaters In DG 1A Air Compressor-2 19200061 Replace Cells 6 And 24 In Battery 1AD1B 19200230 Troubleshoot Failure Of Unit Available Light On DG 1A Control Panel 19200365 Cell 25 In Battery 1AD1B Was M.easured At 2.14V 0n February 17.
Place Cell On Single Cell Charger At 2G0 VDC For 4 Days.
29200464 Install monitoring instrumentation on 2A DG
\\
11 i
l 29200567 NSCW Cooling Tower A pump 1 failed to start i
1 l
'b.
Containment Penetration Local Leak Rate Test Failures i
Since January 1,1992, there have been three Unit 2 containment penetration local leak rate test failures out of a total of nine 4
tests performed.
These failures occurred on check valves in penetrations 12A, Chemical Injection; 23, breathing air; and 80, Service Air. The three. piping penetrations vary in diameter from 1/2 i
Linch to 4 inches.
The containment isolation valves are either -
i Rockwell or Dresser lift-check valves or Dresser, or Anchor Darling swing check valves.
The inspector discussed these failures with the cognizant maintenance engineer to determine if there was a common mode of failure.
Following the discussion and review of historical leakage data, the inspector concluded that there was no single i
dominant failure mode for these valves and that the failures ware unrelated.
j
{
On February 13 maintenance entered containmerit to inspect and l'
repair, if necessary. check valve 2-1204-U4-034 in the Service Air l
System penetration'80.
When the valve was disassembled it was found to be closed but a manufacturer's casting mark was discovered on one side of the valve hinge which prevented the valve from opening to a full open pos.ition. Even though the valve had the potential to stick open, the cause of the excessive leakage was determined to be pitting on the valve seating surface.
The licensee removed the casting mark and refurbished the seating surface. The valve then passed its local leak rate test.
The licensee had discussed this valve failure with the manufacturer, Anchor Darling, and a Part 21 report was being considered as this inspection report period ended.
A similar failure occurred on August 29, 1991, on check valve 1-1204-U4-034 on Unit 1 and is discussed in LER 424/91-15.
In that instance, casting marks were again discovered but in that case they caused the valve to stick fully open. One of the corrective actions stated in that LER was to inspect the corresponding Unit 2 valve during the Unit 2 refueling outage in the Spring of~1992.
c.
Battery Chargers Out Of Service For Extended Period During this ' inspection period the inspectors noted that two safety-related battery chargers 1ADICD and 2CDICA had been considered inoperable for an extended period of time.
The inspectors were concerned and verified that the licensee was taking appropriate actions to restore this equipment.
The DC' electrical systems are-designed to provide a reliable source of continuous power for control, instrumentation and DC motors.
Four safety-related DC battery banks are installed per unit; each battery bank has two redundant battery chargers both of which are normally in service.
TS 3.8.2, DC Sources-Operating, requires that the four
i 1
12
?
i battery banks and one charger associated with each battery be
' operable per unit.
The inspector noted that the licensee initiated Information LCOs to track the inoperable battery chargers in November 1991.
Charger InDICB was considered inoperable due to oscillations following its associated battery load test.
Charger 2CDICA was removed from t
service due.to load sharing problems.
4 The inspector reviewed these problems with the system engineer.
Historically, the majority of battery charger problems' have been i
associated with internal control circuitry.
Oscillations on the l
chargers' have occurred. under two conditions; 1) with a battery j
disconnected fror its distribution system'(the battery breaker.open),
and 2) under heavy load conditior.s following battery discharge surveillances.
In addition to oscillation problems the chargers have
]
- also experienced load sharing problems.
The licensee has initiated design changes (MDDs 91-V1M103, 91-V1M105, and 91-V2M104) to modify I
. the control circuit boards to prevent these oscillations.
In conjunction with the modifications,' as a preventive measure, the licensee is refurbishing circuit boards by replacing components which are subject to aging.
The licensee is performing this upgrade generically throughout the plant on both safety-related and non safety-related chargers.
}
The. delay in returning battery chargers 1ADICB and 2CDICA to service can be attributed to delays from the vendor in supplying the large volume of refurbished control boards required for the charger r
upgrades. Based on this review' the inspector was satisfied with the licensee's actions in returning the battery chargers to service.
i No violations or deviations were identified.
6.
Review of Licensee Reports, Followup (90712) (92700) (92701) (92702)
The below listed Licensee Event Reports and followup items were reviewed to determine if the information provided met NRC requirements.
The i
. determination included:
adequacy of description, verification of j
compliance the TS and regulatory requirements, corrective action taken.
existence of potential generic problems, reporting requirements satisfied, and relstive safety significance of each event.
a.
(Closed) VIO 50-424/91-31-02, " Failure To Maintain Boron Injection Flow Path."
(Closed) LER 50-424/91-010. " Personnel Error Leads To Inadequate Surveillance."
. ~ -
i*
I i
13 l
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The USS and R0 were counseled regarding the importance of adequate 4
review of infomation when completing TS surveillances requirements.
An adequate review of the LC0 status log would have revealed a LC0 on one of the boration flowpaths and a reference to a clearance which called for the two manual valves to be shut.
The appropriate boror.
injection flowpath procedures, 14405-1/2 and 14406-1/2, were revised on January 15, 1992 to include normally " locked open" manual valves.
Step 5.3a of these procedures now informs the, operator that the i
position of these manual valves may be verified by checking the j
" Safety Related Locked Valve Manipulation Log," procedure 11888-C.
b.
(Closed) LER 50-424/91-011. " Auxiliary Feedwater ' ctuation While A
Preparing For Test."
1 l
The Steam Generator Water Level Control Operator was counseled regarding the.importance of attention to duty and the need to maintain control over work activities in his area. The AFW Pump and Check Valve Cold Shutdown Inservice Test procedures were revised on December 19, 1991, to state that steam generator levels should be 1
maintained between 50% and 75% narrow range during performance of the
~
tests.
The DCP Implementation and closure procedure was revised on j
January 22, 1992, to more effectively control the timing revisions necessitated by design changes.
The specific-change that addresses timely revisions to plant procedures is 'the Return to Service a
a Checklist. The new process requires that each department sign in the j
j.
Mod Log for completion of their procedure revisions.. At any time after the field work is complete, the shift superintendent can determine what procedures have to be. revised, which department is I-respcnsible, and which of the revisions have been completed.
c.
(Closed) LER 50-424/91-014, " Fuel Handling Building Isolation From Radiation Monitor Signal."
i The cause of the event was a loss of power to the Fuel Handling Building radiation monitors ARE-2532A and ARE-3532B which caused them to fail to the " safe" condition, resulting in a FHB isolation.
The root cause of the loss of power could not be determined.
Following troubleshooting and testing, the radiation monitor were returned to
- service, d.
(Closed) VIO 50-424,425/91-15-04, " Inadequate Pressurizer Pressure Calibration Procedures."
(Closed)
LER 50-424/91-005,
" Improper Pressurizer Pressure Transmitter Calibration."
All eight pressurizer pressure transmitters were recalibrated.
A Waiver of Coroliance was requested by GPC and granted by NRC Region 11 to allow sufficient time to complete the transmitter recalibra-tions. The Waiver of Compliance allowed an additional 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> to be applied to the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> TS 3;0.3 requirement for the units to be in c
n.
a
l r.
14 3.
j Mode 3 (Hot Standby). ' The recalibration for both units was completed i
in 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> and 30 minutes which was within the 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowed under the waiver. Additionally, the 8 calibration procedures for the
-I pressurize. pressure transmitter were revised to include the static i
head corrected factor.
The licensee conducted a broadness review of level. pressure and flow transmitters to verify that static head correction factors have been included as appropriate.
This review included Reactor Protection' system. instruments, Engineered Safety Features instruments, and some e
balance of p(lant instruments that are important to safety' or performance-approximately 456 instruments for Unit 1 ' and - 2 y
combined). Of these 456 instruments, 218 had no elevation difference
+
l between the tap and transmitter, and 172 had an elevation difference l
with the required head correction applied.
The remaining 66
~
instruments (including the 8 head pressurizer pressure instruments)
' had ~an elevation difference, but a head correction was not applied.
Each of these was reviewed and it was ' determined that, with the exception of the pressurizer pressure channels, there were no cases where a head correction was necessary for TS operability 1
L considerations.
However, as a result of this review, a further
[
evaluation of these instruments was made to detennine if any i
, corrections should be applied to enhance system performance.
Calibration procedure revisions for the above instruments were completed pri~or to the next calibration of the effected instruments.
t The licensee also performed a programmatic review of the procedure writer's guide and made enhancements concerning ~ static head corrections.
l e.
(Closed) IFI 50-424,425/91-28-02, " Review Licensee Root Cause l
Evaluation Of System Leaks."
The licensee's root cause evaluation for numerous water spills during outage evolutions during refueling outage IR3 concluded that the spills occurred due to inefficient work practices, poor organization and accessibility of clearance information, and inadequate procedural controls for release of valves within a clearance for functional tests.
The majority of spills which occurred during 1R3 were attributed to valves which were released from a clearance as a functional test. A functional test is intended to allow testing of aquipment after it has been repaired.
In the past there had been some misunderstanding on the meaning of functional test.
The functional test form was misleading, and the time allowed for a functional test had been excessive.
The licensee is strengthening procedural controls governing the release of equipment.
Procedure 00304-C, Equipment Clearance and Tagging is being revised to change the term functional test to functional release.
The functional release form will be
-+,-
a w,-e.
j*
1,.
15 a
revised to clearly distinguish the ' release sequence from the i
restoration sequence.
In addition, the time frame for which a
_ component can be functionally released is shor.tened from four days to i
i two days.
Under the revised procedure the clearance will be rehuns, j
on components after the two days has expired.
During the upcoming outage on Unit 2 the licensee will track j-clearances by system which is expected to provide operators with a more useful and accurate means of determining system status.
The inspectors will review the effectiveness of these clearance and tagging program enhancements during 2R2 which begins next inspection period.
i f.
(Closed) IFI 50-424/91-31-03, " Followup Of Concerns Associated With j.
AFW Actuation."
Following a review of this event (LER 50-424/91-011), the inspector i
had three areas of concern which warranted further review.
These j
areas included operator awareness;.a failure in the ' design change l
process to implement a-work order to calibrate the affected control loops to incorporate new setpoints; and the design change package and Return to Service checklist containing no verification to determine the status of plant procedures associated with the DCP.
i This incident was particularly striking because it exemplified the i
three problem areas given above.
After a more complete review of l
this event, it is apparent that the direct cause of this event was an i
error by the operator.
There were, however, other factors which led i
to the personnel error.
These' included. procedure 14748-1, AFW Pump 1
And ' Check Valve Cold. Shutdown Inservice Test, not specifically stating the water levels to be maintained in the SGs; a valve stroke j
time test delaying the SGWLC operator from reinitiating feedwater j
flow to SGs 1 and 4 in a timely manner; and a failure to recalibrate the DG low level alarm setpoint to 44% following a design change.
l The inspector concluded that the licensee's proposed corrective i
actions in this area were appropriate.
i This incident also called into question the return to service process I
following completion of a design change.
The Design Change Package and the Return to Service checklist did not appear to contain a i.
verification of the actual status of required procedural changes or
[
the implementation of those changes.
As a result there was no l
mechanism to determine the status of the DCP in the affected plant i
procedures.
As a result of this incident and other events caused by L
a lack of knowledge of design change package status, the licensee has j
revised the requirements for implementation and closure of DCPs.
j A change to the Modifications Log maintained in the Control Room will i
aid operators in ensuring awareness of DCPs in progress.
Formerly, a narrative summary of DCPs planned, regardless of status, was placed j
in the Modifications Log.
The log now will only contain the Return i
4
16 To Service checklists and a narrative summaries for those DCPs in progress.
The responsible engineer, as before, will sign the RTS checklist signifying that a walkdown and review of the implementing MW0s indicates that the DCP is complete, the functional testing is complete, the actual ABNs are complete and component labeling is complete.
'After the responsible engineer has completed the RTS 2
checklist, the engineer will now notify impacted departments to sign the RTS checklist acknowledging that changes are complete or scheduled for completion and the modification is acceptable for return to service.
Previously when the engineer had completed a walkdown and notified impacted departments of a pending RTS it was left to the discretion of the Unit Shift Superviso? to place the i.
system back in operation, The inspectors will evaluate the implementation of these changes during the upcoming Unit 2 refueling outage.
No violations or deviations were identified.
8.
Exit Meeting The inspection scope and findings were summarized on February 24, 1992, i
with those. persons indicated in paragraph 1.
The inspector described the areas inspected and discussed in detail the inspection finding:; listed below.
No dissenting comments were received from the licensee.
The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during'this inspection.
Item No.
Description and Reference APPARENT VIOLATION 424/92-02-01 Failure To Follow Procedure Results in Turbine Runback Alarm and Falsification of Data l
9.
Abbreviations
~
ABN As Built Notice i
ACOT Analog Channel Operational Test AFD Axial Flux Difference AFW Auxiliary Feedwater System CCW Component Cooling Water Systems DC Deficiency Card DCP Design Change Package DCR Design Change Request DG Diesel Generator ERF Emergency Response Facility ESF Engineering Safety Features
_ - ~. - _ - - - -
o 17 GPC Georgia Power Company HP Health Physics I&C Instrumentation and Control IFI Inspector Followup Item ISEG_
Independent Safety Engineering Group KW Kilowatt LCO' Limiting Conditions for Operations LER Licensee Event Reports LOSP Loss of Off-Site Power MTI Maintenance Team Inspection MWO Maintenance Work Order NPF Nuclear Power Facility NRC-Nuclear Regulatory Commission NSCW.
Nuclear Service Cooling Water OPDT Over Pressure Delta Temperature OSC Operations Support Center-0 TDT Over Temperature Delta Temperature PA Protected Area QC Quality Cotrol RCS Reactor Loolant System Rev Revision R0 Reactor Operator RTS Return to Service SG Steam Generator SGWLC Steam Generator Water Level Control TS Technical Specification TSC Technical Support Center USS Unit Shift Supervisor VAR Volt-Amp-Reactive VIO
. Violation i
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