ML18033A746
| ML18033A746 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 05/08/1989 |
| From: | Wilson B Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML18033A744 | List: |
| References | |
| 50-259-89-06, 50-259-89-6, 50-260-89-06, 50-260-89-6, 50-296-89-06, 50-296-89-6, NUDOCS 8905190020 | |
| Download: ML18033A746 (35) | |
Text
ENCLOSURE 2
NOTICE OF DEVIATION Tennessee Valley Authority Browns Ferry 1, 2, and 3
Docket Nos.
50-259, 50-260, and 50-296 License Nos.
DPR-33, DPR-52 and DPR-68 The following deviation was identi fied during a Nuclear Regulatory Commission (NRC) inspection conducted on January 30 February 3
and February 14 March 10, 1989.
The TVA Browns Ferry Nuclear Performance Plan (NPP),
Volume 3, Revision 1,
Section II, paragraph 5.0, Plant Surveillance
- Program, committed to ensure that all applicable SIs were acceptable by conducting a review process which included procedure verification, review, walkdown, and validation.
Contrary to the
- above, the commitment was not met in that NRC inspectors witnessed numerous SIs that had already been validated and documented as validated on the computer print out entitled "SI Status List", but the SI procedures either:
(1) could not be performed as written; (2) required valve manipulations that were omitted from the procedure; (3) contained steps for "out of tolerance" conditions requiring calibration of Technical Specification instruments required for fuel load that had not been vali-dated; or (4) contained errors that resulted in an inadequate surveillance test.
Specific examples of the SI deficiencies are documented in the details of the inspection report.
Please provide to the U.S. Nuclear Regulatory Commission, ATTN:
Document Control Desk, Washington, DC 20555, with a copy to the Associate Director for Special
- Projects, Office of Nuclear Reactor Regulation, and a copy to the NRC Resident Inspector, Browns Ferry, in writing within 30 days of the date of this
- Notice, the reasons for the deviation, the corrective steps which have been taken-and the results
- achieved, the corrective steps which will be taken to avoid further deviations, and the date when your corrective action will be completed.
Where good cause is shown, consideration will be given to extending the response time.
FOR THE NUCLEAR REGULATORY COMMISSION sf~~/~,
Bruce A.
ilson, Assistant Director for Inspection Programs TVA Projects Division Office of Nuclear Reactor Regulation Dated at Atlanta, Georgia this gg,day of May 1988 8905190020 S90508 PDR
'ADOCK 05000259 9
gpR RECT 'tp0 o4.t ~0
+y*y4 UNITED STATES NUCLEAR REGULATORY COMMISSION REGION II 101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos.:
50-259/89-06, 50-260/89-06, and 50-296/89-06 Licensee:
Tennessee Valley Authority 6N 38A Lookout Place 1101 Market Street Chattanooga, TN:.
37402-2801 Docket Nos.:
50-259, 50-260 and 50-296 License Nos.:
DPR-33, DPR-52, and DPR-68 Facility Name:
Browns Ferry 1, 2, and 3
Inspection Conducted:
January 30 February 3 and February 14 - March 10, 1989 Lead Inspector:
A. H. John n,
Team Leader ate igned Accompanying Personnel:
F.
P. Paulitz, Electrical Engineer, NRR K. D. Ivey, Resident Inspector Contractors:
D.
C.
Ford R.
M. Compton Approved by:
W.
S.
L ttle, ection Chief Inspection Programs TVA Projects Division Date igned
SUMMARY
Scope:-
This inspection was performed to assess the adequacy of the testing, calibration, maintenance and configuration control of safety-related instrumentation associated with systems required for fuel load.
The inspection was a
performance-based inspection designed to review program implementation in the field.
Where weaknesses were detected, the specific program structure and requirements were then reviewed for adequacy.
Reviews of completed documentation and field inspec-tions were utilized to evaluate the adequacy of the licensee's implementation practices in performing scaling and setpoint calcu-lations and controlling instrument sense line slope.
Results:
Two violations were identi fied:
(1)
VIO 260/89-06-01:
Nine exampl es of failure to fol 1 ow sur-veil lance procedures, paragraphs 3 and 4 and four examples of inadequate procedures, paragraphs 3 and 4.
(Restart Item)
S905i90022 S90508 PDR ADOCK 05000259 0
(2)
VIO, 260/89-06-02:
Failure to have a procedure to control QA records of instrument calibrations, paragraph 4.e.(2).
(Restart Item)
One deviation was identified:
DEV 260/89-06-03:
Failure to Implement a Commitment to the NRC Concerning the Surveillance Procedure Upgrade
- Program, paragraphs 2.a, 3.a, 4.a.(2), 4.b.(1) and 4.c.
(Restart Item)
Three unresolved items" were identified:
URI 260/89-06-04:
DG Loading Acceptance
- Criteria, paragraph 3.c.(2).
(Restart Item)
UNR 259,
- 296, 260/89-06-05:
Potentially Inadequate Calibration Instructions, paragraph 4.f.
(Restart Item)
UNR 260/89-06-06:
Configuration Control of Instrument Line
- Slopes, paragraph 6.
(Restart Item)
One inspector followup item was identified:
IFI 260/89-06-07:
Reactor Vessel Level Setpoint, paragraph 5.
(Restart Item)
The items identified above as a "Restart Item" are required to be resolved prior to Unit 2 restart and wi 11 require substantial licensee management attention.
- An Unresolved Item is a matter about which more information is required to determine whether it i s acceptable or may involve a violation or deviation.
REPORT DETAILS 1.
Persons Contacted Licensee Employees C.
Mason, Acting Site Director G. Campbell, Plant Manager H. Bounds, Project Engineer
- J: Hutton, Operations Superintendent
- 0. Mims, Technical Services Supervisor
+~R.
Baron, Site guality Assurance Supervisor
+*J. Savage, Compliance Supervisor
+~J.
Smithson, Modifications
- A. McCaleb, Instrument Maintenance
- J. Crowell, Instrument Maintenance "J. Rinne, Lead Electrical Engineer
- T. Scott, Instrument and Controls Supervisor "J. White, Shift Operations Supervisor Operations "J
~ Allen, Site Procedures
+*J. Swindell, Plant Support Superintendent
- N. McFall, Compliance Engineer
+*J. Wallace, Compliance Engineer
- R. Sessoms, Maintenance Superintendent
+*H. Sawhney, ISEG E'ngineer
+"B. Willis, ISEG Engineer
+*R. Hires, Engineer Specialist, DNE
+*J.
- Emens, Associate
- Engineer, DNE
+B. Morris, Site Programs Other licensee employees or contractors contacted included licensed reactor operators, auxiliary operators, craftsmen, technicians, and quality assurance,
- design, and engineering personnel.
NRC Repiesentatives
- W. Little, Section Chief
- D. Carpenter, Site Manager "A. Johnson, Project Engineer "K. Ivey, Resident Inspector "D. Ford, Contractor "R. Compton, Contractor "F. Paulitz, Electrical Engineer, NRR
~Attended exit interview on February 3.
+Attended exit interview on March 10.
Acronyms used throughout this report are listed in the last paragraph.
2
~
Summary of Inspection Findings Surveillance and Calibration Procedure Review The TVA' Browns Ferry Nuclear Performance Plan (NPP),
Volume 3, Revision 1,
committed to give management attention to the Browns Ferry Nuclear Plant Surveillance Program to correct deficiencies which had resulted in numerous reculatory violations.
The NPP stated that the root causes of past surveillance program deficiencies were:
( 1) unclear, difficult-to-use surveillance instructions (SIs);
- and, (2) insufficient attention to detail by the persons performing SIs and reviewing SI performance results.
The commitment also included a
review process to ensure that all applicable SIs meet a
minimum standard by implementing a verification,
- review, walkdown, and validation process.
This process was to verify procedure adequacy prior to SI performance in support of Unit 2 startup.
The NRC inspectors concluded that the above commitments have not been fully implemented due to the following inspection findings and observations:
(1)
The NRC inspectors observed problems in the adequacy of SIs even though these SIs were verified,
- reviewed, walked
- down, and validated.
Examples of these problems are discussed in detail in paragraph 3 of this inspection report.
(2)
The NRC inspectors observed several instances where licensee personnel did not follow surveillance or calibration procedures and did not utilize procedure change processes to correct procedures.
Examples are discussed in detail in paragraphs 3
and 4.
(3)
Inspection Report
- 250, 260, 296/88-35 identified the following problems which occurred during SI performance and resulted in the inadvertent actuation of components within safety systems either due to human error because of inattention to detail or an inadequate procedure.
(a)
On December 9, while operators were performing a SI on the RHR system, a step in the procedure required that the stop pushbutton be depressed.
- However, the operator depressed the start pushbutton.
The RHR pump started and ran for five seconds.
(b)
On December 17, during the performance of an SI for the Unit 1/2 DG A load acceptance
- logic, a start of the 2D RHR pump occurred.
This was caused by an inadequate procedure which required the technician to perform the steps which initiate the logic to start the pump before the steps to preclude a start of the pump.
(c)
On December 18, during the performance of an SI on an intermediate range neutron
- monitor, a
jumper installed during performance of an SI jumper came loose, shorted out a
- fuse, and tripped RPS scram channel A (half scram).
Approximately five seconds after this event, another IRM received a
spike from an unknown cause which tripped RPS scram channel B.
With both RPS scram channels A and B
- tripped, a full scram was present.
(4)
(5)
All of the above'nstances were summarized as Unresolved Item
- 259, 260, 296/88-35-02.
The licensee had not validated or scheduled validation of certain SIs for the "at operating pressure" or "at power opera-tion" modes even though the SIs were written so that procedure steps were included for both the "shutdown" and "at power" mode of operation.
The licensee has not validated or scheduled validation of the procedure steps for "out of tolerance" conditions requiring calibration of the required Technical Specification (TS) instru-ments.
When the instruments were not "out of tolerance",
which is usually the
- case, the calibration section of the SI was not validated.
Site Director Standard Practice (SDSP)
- 2. 14 "Surveillance Evaluation",
step 6.6, states that after procedure approval a
documented validation performance will be required to complete the SI evaluation during the first regularly scheduled perfor-mance following approval.
Some SIs may be validated during
- startup, power escalation, and after startup due to plant conditions required for performance.
Several of the 18 month frequency SIs required for fuel load surveillances were reviewed by the NRC inspectors during this inspection and contained steps which were not validated in accordance with the program.
These SI steps would not have been validated until the next scheduled performance which could have been after Unit 2 startup.
The computer print out "SI Status List" listed these observed SIs as being validated and the SIs had been performed at least one time prior to the NRC observed performance.
The failure to implement TVA's Volume 3
commitment to validate
surveillance instructions required for fuel load is identified as a
deviation from paragraph 5,Section II of Volume 3 of the TVA Browns Ferry NPP.
(DEV 260/89-06-03)
Reference paragraphs 3.a and 3;b.
Substantial licensee management attention is needed in this area.
This deviation must be resolved prior to Unit 2 restart.
b.
Instrumentation Setpoint Calculations and Sense Line Slope Review The procedures that provided guidance for instrument setpoint calculations and the calculations reviewed were adequate.
. This review is discussed in paragraph 5.
During the review of slope line configuration, an unresolved item was identified concerning slope line configuration drawing updates (paragraph 6).
In addition, the licensee had identified instrument slope line deficiencies which required maintenance requests to correct improper slope (paragraph 6).
Additional reviews of slope line configurations will be included in future NRC inspections.
The inspector followup item and unresolved item identified in these areas must be resolved prior to Unit 2 restart.
3.
Review of Instrument Surveillance Instructions (52051,
- 52053, 52055)
The following surveillance instructions (SIs) were reviewed and perfor-mance of the surveillance testing was observed in the field to assess the adequacy of surveillance and calibration techniques and confirm the operability of safety-related instrumentation.
2-SI-4. 18-6(A),
"Reactor Protection and Primary Containment Isolation Systems Low Water Level Instrument Channel Al Calibration",
Revision 2, i ssued January 20, 1989
'his SI checks the calibration and performs a functional test of the Reactor Protection System (RPS) and Primary Containment Isolation System (PCIS) low reactor water level channel Al.
The inspectors witnessed the performance of the SI on Unit 2
on January 30,
- 1989, and identified the following:
(1)
Throughout the performance of the SI, several unexpected half scram actuations from a
"low" reactor water level signal on channel Al occurred.
The actuations resulted
- when, as required by the procedures, technicians varied the values seen by level switch 2-LIS-3-203A below the setpoint.
The reason for the unexpected actuations was that contrary to the procedure requirements, the unit operator (UO) reset each actuation after it occurred.
The only step in the procedure requiring the UO to reset the half scram actuation was step 7.56, which was to be performed after all calibration work was completed and just prior to returning the channel to service.
Therefore, the only half scram actuation expected is during step 7.21.
Following this actuation, the signal should then be "locked in" until the calibration and functional tests are completed.
The failure to follow 2-SI-4. 1B-6(A) by resetting the actuation (half scram) signal is an apparent violation of Technical Specification 6.8. 1. 1.c which requires that written procedures shall be
~ implemented covering the surveillance and test activities of safety related equipment.
This is identified as example l.a of VIO 260/89"06"01.
(2)
The instrument technicians were unable to perform step 7.40.5 as written in the procedure because of the following:
Step 7.40.2 states that "If Gross Fail Latch LED on 2-LIS-3-203A is illuminated, PUSH IN Gross Fail Reset pushbutton on 2-LIS-3-203-A.
Otherwise, NA this step and PROCEED.'I Steps 7.40.3 8
7.40.4 have the technicians place the transient polarity switch to the "-" position and push in the transient "urrent amplitude adjustment knob.
Step 7.40.5 states "ADJUST Transient Current amplitude adjustment for coarse adjustment and stable current amplitude adjustment for fine adjustment until Gross Fail Latch LED on 2-LIS-3-203A just i lluminates."
During the performance of step 7.40.2, the Gross Fail Latch LED was not illuminated and the step was initialled as being not applicable (NA) ~
However, after completion of steps 7.40.3 and 7.40.4, the Gross Fail Latch LED was illuminated and step 7.40.5 could not be performed as written.
The technicians then adjusted the current amplitude to a negative (-) value, reset the Gross Fail Latch LED (this extinguished the LED),
and proceeded to perform step 7.40.5.
Also, additional actions which were required to perform step 7.40.5 and continue the SI, were not included in the approved procedure, but no procedure change was initiated.
This is considered an apparent violation of TS 6.8. l. l.c which requires that written procedures shall be established and maintained covering the surveillance and test activities on safety-related equipment.
This is identified as example 2.a of VIO 260/89-06-01.
(3)
The "as-found" reactor water level channel 2-LT-3-203A trip value entered in 2-SI-4. 1B-6(A), table 7-1, was 54.9 inches of water.
This was lower than the minimum procedural tolerance of
- 55. 1 inches of water, but was within the maximum value of 64.0 inches of water calculated from the TS limit.
The "as-found" tolerances entered in Table 7-2 (9 different ranges) were also all below the minimum output tolerance listed in Table 7-2.
This resulted in the technicians adjusting the level transmitter to bring the transmitter zero and span adjustments output within the minimum and maximum values listed in Table 7-2.
This out of tolerance condition was found even though the level transmitter was in tolerance during the SI performed on November 27,
- 1988, just two months earlier.
This makes the three other reactor water level channels B,
C, and D suspect of being in an out of tolerance condition.
The licensee stated at the exit meeting that channel A would be rerun in 30 days and that B, C,
and D
would also be checked and verified.
e The inspection determined that the steps required to be per-formed for an "out of tolerance" condition had not been vali-dated during the first scheduled performance of this SI as required by procedure SDSP 2. 14, "Surveillance Evaluation."
The licensee committed to assure the adequacy of appropriate SIs by conducting a review process which included procedure verification,
- review, walkdown and validation.
This commitment was documented in
The problems noted in paragraph 3.a.
(2) and (3) were observed during the SI even though the SI had been validated by the licensee and was tracked as being validated on a
computer print out entitled "SI Status List".
The failure to adequately validate 2-SI-4. 1B-6(A) is an example of Deviation 260/89-06-03.
b.
2-SI-4. 1.B-17(A),
"Reactor Protection System CRD Scram Pilot Air Header Low Pressure Calibration," Revision 0, issued June 1,
1988.
This SI implements the requirements of TS Tables 3.1.A and 4.1.B for calibration of the scram air header low pressure instrumentation.
The inspectors witnessed the performance of this SI for Unit 2 on January 31, 1989.
The SI had to be stopped on step 7.6.22 because the step required the technician to complete steps 7.6.23 through,7.6.33 and then to proceed to step 7.6.35, thereby skipping step 7.6.34.
Step 7.6.34 stated "Remove VOM connected in step 7.6.4 and close junction box 7405 cover."
Thus the procedure did not allow the technicians to remove the VOM.
The above problem was observed during the SI even though the SI had been validated by the licensee and was tracked as being validated on a computer print out entitled, "SI Status List".
The failure to adequately validate 2-SI-4. 1.B-17(A) is an example of Deviation 260/89-06-03.
The same SI was performed on September 12,
- 1988, and this procedure problem was not identified.
In fact step 7.6.22 was signed off as N/A (not applicable) and the subsequent steps were used to change a
transmitter gasket.
Procedure SDSP 7.6, Maintenance Request and
- Tracking, Revision 2,
Section 6.0, requires that a
maintenance request be utilized to provide any SI reference used in the perfor-mance of maintenance such as changing the gasket.
The failure to use appropriate administrative controls to control steps being used in an SI f'r maintenance is identified as example 1.b of VIO 260/89-06-01.
O-SI-4.9.A. 1.a(A),
"Diesel Generator "A" Monthly Operability Test,"
Revision 4, issued January 30, 1989.
This SI implements the requirements specified in TS 4.9.A. l.a.
to verify the operability of diesel generator (DG) "A".
The inspectors witnessed the performance of this SI on January 30, 1989.
Test
activities were observed both locally at the diesel generator and from the control room.
The following concerns were identified:
In general, the inspectors observed that test activities were accomplished as required by the specified procedure.
Surveillance instructions utilized were thorough and provided reasonable assurance of diesel generator and fuel oil system operability.
The inspectors noted that appropriate test pre-requisites were accomplished and that system limitations had been specified.
Test personnel were interviewed and found to be competent and fami liar with the procedural and operational aspects of the test.
However, during the test, an alarm was encountered which was not anticipated by the Auxiliary Unit Operator (AUO) and was not specified in the test procedure.
Test step 7. 15.4 requires the AUO to depress the engine start pushbutton and verify that the diesel engine starts, accelerates and stabilizes at idle speed.
Following performance of this step, the diesel engine start was accompanied by an unanticipated fuel oil alarm at the Diesel Engine Control Cabinet.
The alarm was immediately reset by the AUO and the test was continued.
The NRC inspectors questioned the AUO regarding the cause of the alarm and it's potential impact upon successful completion of the test.
The AUO was not able to identify the reason for the alarm but stated that he had reset the annunciator based upon an observed increase in the fuel oil pressure.
The AUO further stated that he had not encountered this alarm during previous diesel operability tests.
At this point, the AUO returned to the control room to consult with the Assi stant Shift Operations Supervisor (ASOS),
and a
decision was made to continue performance of the SI.
Following completion of the test, Maintenance Request (MR) A-912517 was issued to document and investigate the fuel oil pressure alarm encountered during performance of the SI.
The NRC inspectors concluded that the use of an MR to record test abnormalities was not in accordance with the requirements of site procedures which control test activities.
The review of PMI-17. 1, Revision 5, "Conduct of Testing,"
indicated that any condition in which the equipment or system being tested either:
(1) fails to operate; (2) operates in a suspicious manner; (3) or operates outside the limits of documented acceptance criteria; s'hould be considered a "test deficiency" and uniquely documented in the test package.
The failure to document this test deficiency in accordance with the requi rements of PMI
- 17. 1, is identified as example 1.c of VIO'60/89-06-01.
(2)
A note on page 18 of the SI, prior to step 7. 19 for loading the DG, states that acceptance criteria for minimum DG loading is at
least 2600 kw +50 kw.
TS 4.9.A. l.a requires a 75 percent rated load or greater (which is 2600 kw or greater) making 2600kw minus 50kw an inappropriate acceptance criteria.
This conflict will be reviewed to determine if TS requi rements were met during previous surveillance testing.
This is identified as URI 260/89-06-04.
O-SI-4.2.D. 1, "Liquid Radwaste Monitor Calibration/Functional Test,"
Revision 2, issued December 21,
- 1988, and Temporary Change 7.
This SI is used to calibrate and functionally test Radioactive Liquid Effluent Radwaste Monitoring Instrument, 0-RM-90-130.
This instrument loop includes the detector, a preamplifier, a monitor and a recorder.
Instrument setpoints are contained in System Instrument Maintenance Index (SIMI), 1-SIMI-90B, "Radiation Monitoring System Scaling
& Setpoint Document,"
Revision 0.
The inspectors witnessed the performance of this SI through Step
- 7. 10.7 on February 2,
1989.
The inspectors discussed this SI with responsible I&C technicians, foremen and system engineers.
Personnel were knowledgeable and the test was performed properly.
The measuring and test equipment (M&TE) utilized had current calibration stickers.
e.
During the performance of the SI, a licensee QC inspector identified a typographical error in Table 1 of the procedure.
The units of measure for one column was CPM (Counts Per Minute) instead of CPS (Counts Per Second) which was intended.
This error was clearly typographical.
- However, Site Director Standard Practice SDSP-2. 11, "Implementation and Change of Site Procedures and Instructions,"
Revision 9, requires issuance of an Immediate Temporary Change
( ITC) for this situations There was some confusion as to what was required as the licensee's staff discussed how to proceed.
The decision was made to continue with the SI without the required ITC and issue a
Form SDSP-223, Procedure Change
- Request, to get the procedure corrected for future use.
The failure to issue an ITC as required by SDSP-2. 11 is identified as example 1.d of VIO 260/89-06-01.
2-SI-4. 1.A-8(A),
"RPS and Rod Block High Water Level In Scram Discharge Tank Functional Test,"
Revision 2,
issued December 15, 1988.
This SI is performed monthly to determine the operability of the RPS high water level in scram discharge tank channel 2-LS-85-45A, and rod block channel 2-l.S-85-45L.
The NRC inspector observed the perfor-mance of this SI on Unit 2
on February 2,
- 1989, and identified no deficiencies.
Instrument Calibrations (52051,
- 52053, 52055)
Loop Ca 1 ibrat i on Instruc tion (LCI )-2-L-63-1, "Loop Ca 1 ibrati on Instruction Standby Liquid Control System Tank Level Instrumenta-tion," Revision 2, issued January 20, 1989.
This procedure is a part of the upgraded procedures effort and provides for calibration of the level transmitter, power
- supply, alarm unit and two level indicators and for cleaning of the reference line inside the Standby Liquid Control (SLC)
Tank.
The NRC inspectors witnessed the performance of this procedure on January 30, 1989.
The METE used had current calibration stickers.
Personnel involved in the work were knowledgeable.
The following discrepancies were identified:
( 1)
Procedure step 7.41.3 requires inserting of 11 feet copper tubing into the SLC Tank sensing line to clean out any boric acid crystals.
Due to problems in the insertion process the technicians cut off approximately three inches of the tubing but failed to compensate for this removal during the cleaning process.
Therefore, the tubing was not being inserted the full ll feet required by the procedure.
When this was identified by the inspectors, the technicians recleaned the line per the procedure.
The failure to follow procedure LCI-2-L-63-1 is identified as example 1.e of VIO 260/89-06-01.
(2)
The NRC inspectors reviewed as-constructed drawing 47W600-56, "Mechanical Instruments and Controls,"
Revision 2,
which shows the arrangement of the SLC Tank and associated piping.
This drawing shows that the sensing line is 11 feet long inside the SLC tank.
There are approximately 8 inches of piping extending above the tank where the cleanout tubing is inserted.
The technicians used this extension as the reference point for the length of tubing inserted.
Paragraph 7.41.3 of LCI-2-L-63-1 states that to ensure reaching the end of the sense line, ll feet of tubing must be inserted.
The procedure does not provide for an adequate cleanout tubing length to reach the end of the sensing line.
The calibration was reperformed by the licensee with the proper length of tubing.
The failure to establish an adequate procedure for cleaning the sense line is identified as example 2.b of VIO 260/89-06-01.
(3)
The NRC inspectors noted at local, instrument panel 25-19 that two of three mounting screws for control air supply pressure gauge 2-PI-32-39 were missing and one of three mounting screws for SLC Pump discharge pressure gauge 2-PI-63-7B was missing.
Maintenance requests were issued by the licensee to restore the mounting configuration for these instruments.
Standard Calibration Instruction (SCI)-504.0, "Differential Pressure Transmitter GE Type
- 555, (Range 0-391 inches water)"
Revision 0,
issued March 18, 1988.
This procedure was used to calibrate Emergency Equipment Cooling Water (EECW) system flow transmitter 0-FT-67-3A on February 2, 1989.
The inspectors witnessed performance of this calibration as part of the loop calibration for this instrument.
Setpoint data was
10 contained in O-SIMI-67, Revision 3,
issued January 23, 1989.
METE used during this procedure had current calibration stickers.
Personnel were knowledgeable of the equipment and procedure needed to calibrate this device.
- However, the inspectors identified the following discrepancies that indicate weaknesses in the adequacy of calibration procedures and adherence to procedures:
(2)
The NRC inspectors "eviewed as-constructed drawing 47M600-52, "Mechanical Instruments and Controls,"
Revision A, which shows the configuration of the flow transmitter and associated piping.
This drawing shows the transmitter drain valves installed downstream of the three valve manifold.
The drain valves are actually installed upstream of the three valve manifold.
Because of this discrepancy in the as-built configuration, SCI-504.0 could not be performed as written to calibrate 0-FT-67-3A.
To get test pressure to the transmitter through the connections at the drain valves the high and low side manifold valves have to be opened between steps 7.A. 10 and 7.A. 11.
This manipulation is not addressed in the procedure.
In addition, to isolate and return to service the transmitter, an operator had to close and open root valves at specific points in the procedure performance.
These root valve manipulations were not addressed in SCI-504.0.
The failure to establish an adequate procedure by including all required valve manipulations in SCI-504.0 is identified as example 2.c of VIO 260/89-06-01.
The IKC technicians and the operator who performed the calibration made the above described valve manipulations even though the procedure did not specify they be done.
Some measure of configuration control was achieved in that personnel com-pleted an Attachment 3
(configuration control log) from Instrument Maintenance Special Instruction
( IMSI)-3014, "Troubleshooting and Maintenance Instruction."
- However, the use of this form from IMSI-3014 is not referenced in SCI-504.0.
To determine how this procedure had been utilized in the past the inspectors reviewed the completed records for the previous calibration of 0-FT-67-3A on October 13, 1988.
SCI-504.0 had been
- used, but there was no configuration control log "Attachment 3" completed.
To perform the calibration the extra valve manipulations would have had to have been performed.
In
- addition, the NRC inspectors reviewed records of the prior performance of SCI-504.0 for 2-FT-75-21 on November 18, 1988.
Although the records included a IMSI-3014 configuration control log attachment the information contained on it indicated that the isolation valves were left in the closed position.
To determine if there were other SCIs with similar discrepancies the inspectors reviewed the latest calibration records for 2-LT-3-53 in accordance with SCI-204, "Differential Pressure Transmitter GE Type
- 555, (Range 0-200 inches water)" performed on July 18, 1988.
SCI-204 steps 7.2 and 10.6 require the
11 instrument be removed and returned to service with independent valve position verification documented per IMSI-3014.
- However, the records for this calibration do not include any IMSI-3014 configuration control documentation or "Attachment 3"
configuration control log.
In
- summary, personnel performed actions not specified in procedures without getting tl e required procedure changes and failed to properly document and control system configuration even when required by procedure.
SOSP-2. 11, "Implementation and Change of Site Procedures and Instructions,"
requires that procedures be changed if discrepancies are identified.
The failure to follow SDSP-2. 11 and SCI-504 is identified as example 1.f of VIO 260/89-06-01.
c.
Standard Calibration Instruction, SCI-527, "Calibration of "A"
Standby Gas Treatment HEPA Filter Pressure Differential Dryer Magnehelic DP Gauge,"
Revision 1, issued March 25, 1988.
SCI-527 does not address the need to manipulate isolation valves to isolate the tested DP gauge from the two other DP gauges and restore these isolation valves after the calibration was complete.
The failure to establish an adequate procedure is identified as example 2.d of VIO 260/89-06-01.
This activity was performed and documented on Attachment 3 of Troubleshooting Instruction IMSI-3014 without changing SCI-527 to include the required valve manipulations.
Failure to follow SDSP-2. 11, which requires procedure changes to correct discrepancies is identified in example 1.g of VIO 260/89"06-01.
d.
Standard Calibration Instruction (SCI)-204, "Differential Pressure Transmitter, GE Type 555 (Range 0-200 inches water),"
Revision 3, issued November 7, 1988.
Step 7.2 of SCI-204 states "Remove instrument from service and equalize'."
Footnote
( 1) states:
"Second person verification (1) required and shall be documented per IMSI-3014".
Step 10.6 states "Return Transmitter To Service
'" with the same footnote.
No IMSI (1) n 3014 documentation of transmitter isolation and return to service exists for the calibration of 2-LT-3-206 on July 18, 1988.
The failure to follow procedure SCI-204 for documentation of independent verification of steps 7.2 and 10.6 is identified as example 1.h of VIO 260/89-06-01.
e.
Standard Calibration Instruction (SCI)-511, "EECW System Calibration," Revision 2,.issued September 9,
1988.
(1)
SCI-511 was utilized to calibrate flow indicators in the EECW system.
The inspectors'bservation of this activity indicated that the procedure, did not contain sufficient detail for
12 technicians to perform the calibration.
Examples are as follows:
The procedure does not contain information describing
- range, accuracy and output of the subject instrument.
This information was necessary to perform the calibration and subsequent evaluation of acceptance criteria.
The SCI requires application of a current source equal to 0, 25, 50, 75 and 100% of instrument input range.
- However, as noted
- above, the range was not specified in the procedure.
The SCI requires a corresponding flow indication of 0, 25, 50, 75, and 100% as a basis for instrument calibration and acceptance.
- However, because instrument accuracy is not stated in the procedure, evaluation of test data could not be accomplished without consulting additional plant documents.
The information necessary to perform this calibration was contained in SIMI-67, "Emergency Equipment Cooling Water System,"
Revision 2, and associated instrument index sheets.
- However, the SIMI was not referenced in the subject SCI.
(2)
Additional concerns were identified regarding the use of "Calibration Cards" to record vital instrument information and results of calibration activities.
These cards are not controlled by Plant Administrative Procedures and their status as gA records is indeterminate.
This is an apparent violation of 10 CFR 50, Appendix B,
Criterion XVII, "Quality Assurance Records,"
for the failure to have a
procedure to control QA records and applies to all instrument calibrations witnessed by the NRC inspectors.
This is identified as VIO 260/89-06-02.
(3)
The Calibration Card utilized in performance of the subject calibration contained erroneous information regarding instrument accuracy.
The card specified an instrument accuracy of 2% as detailed in SIMI-67, Revision 2.
- However, the NRC inspectors noted that Revision
of the SIMI (approved January 20, 1989) specifies an instrument accuracy of 1.5% resulting in a
more conservative tolerance that that to be utilized during the calibration.
Technicians had recorded information on the Calibration Card by utilizing Revision 2 of SIMI-67.
The inspectors told the technicians than Revision 3 of the SIMI had been issued and should have been consulted in preparing the Calibration Card.
The technicians made the appropriate corrections for the performance of the calibration.
13 The failure to follow procedure SOSP 2.1, which states that the procedure being used will be verified immediately with the Information
- Center, is identified as example l.i of VIO 260/89-06-01.
f.
PMI-6.23, "Compliance Instrumentation,"
Revision 0, issued October 17, 1988 This procedure divides compliance instrumentation into three groups Type A includes instruments which must remain within tolerance for the affected systems to remain operable and within TS limits.
'For Type B instruments, the system is still operable if the instrument is found to be out of calibration.
- However, Type B
instruments are used in the performance of SIs.
Type C instruments are used for indication only.
These instruments are calibrated using calibration instructions which are not a part of the SI program.
As
- such, licensee personnel indicated that these instructions are not part of the
Examples of inadequate calibration instructions for both Type A and,Type B instruments were identified during thi s inspection (see a, b, c, and e above).
The inspectors are concerned that instruments which affect system operability and affect the performance of SIs may not be adequate to support those functions.
The SI upgrade program does not include the calibration instructions.
The effects of inadequate calibration instructions on system operability and SI performance was identified as URI 259,260,296/89-06-05, Inadequate Calibration of Instrumentation Required for TS Surveillance
- Testing, and will be followed up in future NRC inspections.
g.
Conclusions The inspector s concluded that the calibration procedures discussed above were inadequate and work was done without adequate written procedures.
The procedure change process was not utilized.
'MSI-3014 was improperly used.
In fact, Section 5.1 of the IMSI-3014 states that electrical or mechanical isolation should be performed as a part of the calibration instruction or maintenance request.
A troubleshooting
- document, such as IMSI-3014, is not appropriate for a planned standard maintenance activity.
- Also, in reviewing the previous calibrations of b and d above the Attachment 3 Configuration Control Log were not used or attached.
5.
Instrumentation Setpoint Calculations and Line Slope Drawing Review (52051,
- 52053, 52055)
This inspection was conducted to ascertain the adequacy of the licensee program for setpoint calculations and instrument line slopes associated with systems required for fuel reload.
The licensee's program for calculations and instrument line slope is described in the Nuclear Performance
- Plan, Volume III.
The NRC received a
number of Abnormal Occurrence
- Reports, submitted by operating utilities, between January 1972 and June 1973 which identified "as found" calibration data for safety-related instruments which exceeded the safety limit setting values documented in the TS.
The NRC issued Regulatory Guide (RG) 1. 105, Revision 1, in November 1976 which identified the most common cause of a setpoint in a safety-related system being out of compliance with plant TS.
This cause has been the fai lure to allow sufficient margin to account for instrument inaccuracies, expected environmental drift and minor calibration variations.
In some cases the instrument setpoint and the TS safety limit setting were the same with no margin for inaccuracies.
In other cases, the trip setpoint was so close to the upper or lower limits of the range of the instrument that instrument drift placed the setpoint beyond the range of the instrument, thus nullifying the trip function.
Further noncompliance causes were identified as instrument design inadequacies and questionable calibration procedures.
RG 1. 105 was further revised and issued as Revision 2, dated February 1986.
RG 1. 105, Revision 2,
endorsed the Instrument Society of America
( ISA) standard ISA-S67.04-1982 "Setpoints for Nuclear Safety-Related Instrumentation Used in Nuclear Power Plants."
This standard was revised and issued in 1987.
On February 4,
- 1988, this standard was approved as ANSI/ISA-S67.04-1988.
This portion of the inspection was confined to the review of setpoint calculations and drawings for instrument line slope conformance for those systems associated with fuel reload.
The systems and related instruments reviewed included:
a
~
Reactor Feedwater System (System 3)
Reactor vessel water level loop L-3-203A,B,C,CD:
TS setpoint 538 inches above RPV zero:
initiates primary containment system isolation, RWCU system isolation, and reactor scram.
Reactor vessel water level loop L-3-58A,B,C,&D:
TS setpoint 470 inches above RPV zero:
initiates high pressure coolant injection system (HPSI) and reactor core isolation cooling system (RCIC).
TS setpoint 378 inches above RPV zero:
initiates core spray system 75, low pressure coolant injection system (LPCI).
Reactor vessel water level loop L-3-52
15 Reactor vessel water level loop L-3-62 TS setpoint 312 and 5/16 inches above RPV zero:
blocks containment spray during LOCA.
b.
Refueling Water Cleanup System (RWCS) (System 69)
Temperature nonregenerative heat exchanger room 11 loop T-69-29J,K,L,&M.
TS setpoint 180 degrees F:
initiates RWCS isolation.
c.
Control Rod Drive System (CRD) (System 85)
Instrument air header supply for CRD scram flow valve pressure loop P-85-35A1,A2,B1,KB2.
TS setpoint 50 psig decreasing:
initiates reactor scram.
d.
Standby Liquid Control System (SLCS) (System 63)
Boron solution tank level loop L-63-1 Low level alarm (4160 gal 13.4%),
high level alarm (4630 gal 9 12.1%),
tank overflow (4850 gal 9 11.6%):
Initiates tank heater cutoff on low level.
The latest procedure used by the licensee for setpoint calculations is the Division of Nuclear Engineering (DNE),
Electrical Engineering Branch (EEB),
instruction EEB-TI-28, Revision 1,
dated October 24, 1988.
- However, EEB-TI-28 is not referenced in DNE, Nuclear Engineering Procedure (NEP)
- 3. 12, Revision 0,
dated December 15,
- 1987, "Safety-Related Setpoints For Instrumentation and Controls-Establishment and Validation."
- Further, the NEP for Browns Ferry Nuclear Plant (BFN)
BFEP PI-89-17 "Setpoint and Scaling Document Preparation and Control" is being reviewed but has not been issued.
This procedure provides the instruction and requirements necessary for preparing, revising, controlling, issuing, and maintaining setpoint and scaling documents as used in Engineering Change Notices and Design Change Notices.
Procedure EEB-TI-28 incorporates the guidance found in RG
- 1. 105 and ISA standard 67.04 and is acceptable for assuring that setpoints are established and held within specified limits for nuclear safety-related instruments used in nuclear power plants.
The guidance provided by this procedure was reflected in the setpoint calculations which were reviewed during thi s inspection and are identified in the scope paragraph.
The methodology of determining instrument loop errors and using them in the accuracy calculation reviewed is acceptable.
Modifications were
- made, by the
- licensee, to the reactor vessel level sensing lines to meet the intent of NRC Generic Letter 84-23, to minimize the potential for boil off in the reactor water level reference legs.
This modification, Engineering Change Notice (ECN) E-2-P7131, changed the elevation of four condensate pots associated with the reactor penetrations N12A and N12B
~
The four sensing lines were rerouted through the primary containment penetrations X-17A, X-17B, X26A, and X-26B.
This modification
16 required that new setpoint calculations be
- made, by the
- licensee, to affected instruments to reflect the changes in the sensing lines'outing.
DNE calculation ED-Q2003-88060, "Setpoint, Instrumentation, Calibration,"
was made to provide new setpoints due to the modification.
These new setpoints would be used prior to fuel reload but did not reflect plant operating conditions during modes 1 through 4.
New setpoint calculations are required for modes 1
through 4,
such as ED-f2003-88177 for level transmitter 2-LT-30203A which would have a setpoirt of 541.71 inches above vessel zero.
In the fuel reload calculation ED-f2003-88060 this setpoint was 550.5 inches above vessel zero.
The value listed in the TS is 538 inches above vessel zero.
The setpoint must be selected so not to be affected by'ormal plant operation with sufficient margins for error so that the "as found" value does not exceed the TS value during functional test and calibrations.
The licensee committed to select this setpoint prior to Unit 2 restart.
This is identified as an Inspector Followup Item 260/89-06-07.
The inspector's review of the isometric drawings associated with the reactor vessel water level reference sensing lines found that the horizontal lines were adequately sloped.
The licensee should consider trending the "as found" deviations from setpoint as being done at Sequoyah Nuclear Power Plant.
This would correct some of the errors which were derived from environmental qualification (Eg) type testing data.
Also, when this E(} data is used for the accuracy calculations, the bases should be clearly explained.
- Further, guidance should be provided for uniformity when, selecting the elevation of sensing lines to account for different temperature zones such as at primary containment and floors.
Floors have known elevations which should be used instead of the middle of the floor slab which requires that the thickness of the floor slab also be determined.
Since there is generally temperature stratification below the floor slab, which is the ceiling of the adjacent lower room, there would be less error using the top of the floor elevation in the reference leg fluid density calculation.
Management attention to controlling, issuing, and maintaining setpoint and scaling documents as used in Engineering Change Notice and Design Change Notice for BFN should be continued to assure that any ONE setpoint changes are controlled and are properly implemented by those personnel doing the surveillance testing.
The procedures that provide guidance for instrument setpoint calculations and the calculations reviewed were adequate.
The 'ocuments review6d for the instrumentation setpoint calculations and
'ine slope are listed, in Appendix A.
Instrument Line Slope Configuration Field Malkdowns (52051,
- 52053, 52055)
The NRC inspector
- reviewed, walked down and evaluated a
sample of instrument lines for slope configurations that could affect the output signal of instruments on systems required for fuel load.
The inspection was conducted using the following guidance:
a.
Browns Ferry Final Safety Analysis Report (FSAR)
17 b.
Engineering Requirements (ER) Specifications for Instrument and Instrument Line Installation and Inspection c.
Plant Administrative Requirements d.
Lessons Learned from Sequoyah During the plant walkdown of selected instrument lines for systems required for fuel load located in the Drywell, the inspector observed a
loose hanger on the stainless steel instrument line for reactor water level (LT-3-55)=.
The licensee issued a maintenance request to correct the loose hanger and to correct the slope of this instrument line.
The NRC inspector also observed that Browns Ferry had implemented the lessons learned from the Sequoyah Plant for systems required for fuel
- load, except for one.
The Sequoyah Plant used the output instrument line slope isometric drawings for a slope configuration control and used the isometric drawings as a living document.
The Browns Ferry Plant decided to use the isometric drawings as a one time configuration drawing and rely on the newly issued Engineering Requirements Specification for Instrument and Instrument Line Installation and Inspection Procedure to control instrument line slope configuration.
The NRC inspector expressed the concern
.that to rely on one procedure without extra administrative controls of a
living configuration drawing as a final baseline as-constructed drawing was unacceptable because there are still changes being made to the instrument line slopes prior to Unit 2 restart.
Nuclear Engineering Procedure (NEP) 1.3, "(}uality Assurance,"
Section 2.2 states that DNE wi 11 establish and maintain a "Configuration Control" system which represents the as-built condition of the project or plant, and DNE will maintain that system for the life of the plant.
Therefore, this concern of instrument line configuration control will be tracked as URI 260/89-06-06.
Future inspections are to be performed to verify that the ER specification is being implemented by the licensee to maintain configuration control prior to closure of the URI and Unit 2 restart.
Also, it should be pointed out that the licensee's field walkdowns conducted to address generic condition adverse to quality report (CA(}R BFP 870013) issued from Lessons Learned from Sequoyah and Browns Ferry identified instrument line slo'pe deficiencies in the as-constructed record.
Maintenance requests have been generated to correct improper sense line slope for four instrument pressure transmitters in the RCIC
- system, a flow transmitter in the RHR system, a pressure switch in the recirculation system and a
pressure differential transmitter in the feedwater system.
This is additional evidence that administrative controls are needed to maintain instrument line slope configuration.
Additional NRC inspections will be conducted to confirm the adequacy of instrument line slope.
18 Exit Interview The inspection scope and results were summarized on February 3
and March 10,
- 1989, with those persons indicated in paragraph 1,
and in a
telecon conducted on May 2, 1989.
The inspectors described the areas inspected and discussed in detail the inspection results listed in Section 2
- above, entitled Summary of Inspection Findings.
Although reviewed during this inspectio i, proprietary information is not contained in this report.
Dissenting comments were not received from the licensee.
Acronyms AUO AOI BFNP BFNPP CAQR CAR CREV CS CSSC CST DCN.
DG DBVP EA ECN EECW EGM ESF FPC FSAR GE HVAC IC IFI IRM ITC KW LCO LER LRED
! OP/LOCA MMI MOV MR NE NI NOV NPP NRC NRR Auxiliary Unit Operator Abnormal Operating Instruction Browns Ferry Nuclear Power Plant Browns Ferry Nuclear Performance Plan Condition Adverse to Quality Report Corrective Action Report Control Room Emergency Ventilation Core Spray Critical Structures,
- Systems, and Components Condensate Storage Tank Design Change Notice Diesel Generator Design Baseline and Verification Program Engineering Assurance Engineering Change Notice Emergency Equipment Cooling Water Electric Governor Motor Engineered Safety Feature Fuel Pool Cooling Final Safety Analysis Report General Electric Heating, Ventilation,
& Air Conditioning Instrumentation Controls Inspector Followup Item Intermediate Range Monitor Immediate Temporary Change Kilowatt Limiting Condition for Operation Licensee Event Report Licensee Reportable Event Determination Loss of Power/Loss of Coolant Accident Mechanical Maintenance Instruction Motor Operated Valve Maintenance Request Nuclear Engineering Division Nuclear Instrumentation Notice of Violation Nuclear Power Plan Nuclear Regulatory Commission Nuclear Reactor Regulation
19 OI PMI PMT PORC QA QC RHR RHRSW RPS RTP RMCU SDSP SGTS SI SIL SRO TACF TE TI TS TVA VIO URI USQD Operating Instruction Plant Manager InstrUction Post Maintenance/Modification Test Plant Operating Review Committee Qualtiy Assurance Quality Control Residual Heat Removal Residual Heat Removal Service Water Reactor Protection System Restart Test Program Reactor Mater Cleanup Site Direct Standard Practice Standby Gas Trea'tment System Surveillance Instruction Service Information Letter Senior Reactor Operator Temporary Alteration Change Form Test Exception Technical Instruction Technical Specifications Tennessee Valley Authority Violation Unresolved Item Unreviewed Safety Question Determination
~Aendix A
DOCUMENTS REVIEWED FOR INSTRUMENT SETPOINT CALCULATIONS AND LINE SLOPE 1.
BFN FSAR, Section 7, Instrumentation and control 2.
BFN Technical Specifications, Section
- 3. 1/4. 1, "Reactor Protection System Section;" 3.2/4.2, "Protective Instrumentation,"
and Section 3.4/4.4,"
Standby Liquid Control System."
3.
USNRC Regulatory Guide
- 1. 105, "Instrument Setpoints,"
revision 1,
1976 and revision 2, 1986.
4.
Instrument Society of America Standard ISA-S67.04 1982,1987, ANSI/ISA-S67.04-1988 Approved February 4, 1988 "Setpoint for Nuclear Safety-Related Instrumentation used in Nuclear Power. Plants."
5.
Nuclear Engineering Procedure NEP-3. 12, revision 0,
December 15,
- 1987, "Safety"Related Setpoints for Instrumentation and Controls Establishment and Validation."
6.
DNE BFN Procedure BFEP PI 89-17, not issued, "Setpoint and Scaling Document Preparation and Control."
7.
Electrical Design Guide DG-E18. 1. 18, revision 0,
March 31,
- 1986, "Instrumentation and Controls Scaling and Setpoint Calculations."
8.
Electrical Design Standard DS-E18. 1. 10, revision 0,
November 11, 1983, "Instrumentation and Control, Instrument 'Setpoints and Limits."
9.
ONE Electrical Engineering Branch Instruction EEB-TI-28, revision 1, October 24, 1988, "Setpoint Calculations."
10.
DNE Calculations ED-f2003-88060, revision 0,
October 25,
- 1988, "Reactor Vessel Refueling Instrumentation Setpoint Analysis."
11.
OE Calculation ED-(2003-88177, revision 3,
October 26,
- 1988, "Setpoint Scaling 2-LT-3-203A (reactor vessel level)."
12.
ONE Calculation 1-TS-69-29J, revision 0, May 9,
- 1987, "Demonstrated Accuracy Calculation (RWCU room temperature)."
13.
OE Calculation Z-PS-85-35A1, revision 1,
May 16,
14.
ONE Calculation ED-N-2063-87290, revision 0,
November 30,
'1987, "Demonstrated Accuracy Calculation 2-LT-63-1 (SLCS tank level)."
Appendix A
1S.
Drawing for ECN E-2-P7131,R1 Reactor Vessel Water Level Instrument Sensing Lines.
DCA Number E-2-P7131-097, Revision 1, Partial Flow Diagram.
DCA Number E-2-P7131-028, Revision 1,
Isometric Diagram.
DCA Number E-2-P7131-029, Revision 1, Isometric Diagram.