IR 05000259/1989006
| ML20246M037 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 05/03/1989 |
| From: | Andrea Johnson, Little W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18033A744 | List: |
| References | |
| 50-259-89-06, 50-260-89-06, 50-296-89-06, NUDOCS 8905190022 | |
| Download: ML20246M037 (21) | |
Text
-
..
.
.
'
[E haKsd
- e, t ;
UNITED STATES o
NUCLEAR REGULATORY COMMISSION D-( p
g HEGION il c
.u.
o 101 MARIETTA STREET. N.W.
E
'i-
' ATLANTA, GEORGIA 30323 kg
,
,e
,
~...
-
>
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 LDocket 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 h
d
Lead Inspector:
m a&
A. H. John n, Team Leader"
/Date igned-Accompanying Personnel:
F. P. Paulitz, Electrical Engineer, NRR'
K. D. Ivey, Resident Inspector Contractors:
D. C. Ford R. M. Compton
'9 Approved by:
m W. S. LFttls',4ection Chief Da'te frigned Inspection Programs TVA Projects Division
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 identified:
,
(1) VIO 260/89-06-01:
Nine examples of failure to follow sur-
!
veillance procedures, paragraphs 3 and 4 and four examples of inadequate procedures, paragraphs 3 and 4.
(Restart Item)
"
~5905 00022 89050'S PDR ADOCK 05000259 Q
PDC j
'
-_
-___-
R
.
.
'
i'
.
,
.
.
,.
.
(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:
0EV 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 unresolvea items
- wore 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 will require substantial licensee management attention.
- An Unresolved Item is a matter about which more information is required to determine whether it is acceptable or may involve a violation or deviation.
i i
!
- - - _ - - - _ - - - _ - - - - _ -
_.
._ _
_ _.
._.
. _.
.
, x /.o :
.;_'
,.
..
ih!
.
REPORT DETAILS
i s
~1.
Persons Contacted
,
Licensee' Employees
- C.. Mason FActing Site DirectorL G. Campbell,. Plant Manager
<H. Bounds, Project Engineer
- J Hutton, Operations Superintendent
.
- D. Mims,' Technical-Services Supervisor
+*R. Baron,. Site Quality 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 Engineer
+*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, des'ign, and engineering personnel.
NRC Representatives
- 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.
_ _ _ _ _ _ _ - _ _ _ _ _ _ - _ _ _ _ - _ - _ _
_ -
.
.
'
.. *
-
,,,
l-
..
2. - Summary of. Inspection Findings
a.
Surveillance and Calibration Procedure Review The TVA's ' Browns, Ferry Nuclear Performance P1an (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 adeauacy 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.
_-.
- -_-_
_____
__ -
. -
_
__ - _. -
_
-
__
____
.
.
'.
,\\,3
.. #
'
.
p
-
L 3-o
- (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 o
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.
L All of the above instances were summarized as Unresolved Item 259, 260, 296/88-35-02.
- (4) 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.
- (5) 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 surveillance 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.
_ _ _ _ _ _ _ - _ _ _ _ _ _
_ _ _ _ _ _ _
-
_ _ _ _ - _ __ -
.
.
'
.-
.. *
L,
.
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)
Thc 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.
a.
2-SI-4.1B-6(A),
" Reactor Protection and Primary Containment Isolation Systems Low Water Level Instrument Channel Al Calibration",
Revision 2, issued January 20, 1989.
This 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 A1.
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 VO to reset the half scram actuation was step 7.56, which was to be performed af ter 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 1.a of VIO 260/89-06-01.
i
_. _ _ - _ _ _ _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _ _ _ _ - _. _ _
-
-
,
q..*
,.
,
..
.(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 LIS-3-203A is illuminated,._ PUSH IN Gross-Fail Reset
>
.pushoutton on 2-LIS-3-203-A. Otherwise, NA this step and
[
PROCEED."
-
Steps 7.40.3 & 7.40.4 have - the. technicians place the -
transient polarity switch to the " " position and push in the transient current amplitude adjustment knob.
,
'
Step 7. 40. '; states " ADJUST Transient Current ampiitude
-
e adjustment. for coarse adjustment and _ _ stable current amplitude adjustment for fine adjustment until Gross Fail Latch LED on 2-LIS-3-203A just illuminates."
During the performance of step 7.40.2, the Gross Fail Latch ' LED was not illuminated and the step was initia11ed 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 6.8.1.1.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 minimua 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.
i
_.____.___._m______.-._________..____.___-______________.____m
_ _ _ -_
__
'.
.-
~
'
-
i
.
..
.
l I h ',-
-
L
..
t ~
.Th' e 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
.BFN, NPP, Volume 3, Revision 1._, The problems noted in paragraph l3.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-4.18-6( A)' i s 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.4.1.8 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 V0M connected in step 7.6.4.and close junction box 7405 cover." Thus the procedure did not allow the technicians to remove the V0M..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 for maintenance is identified as example 1.b of VIO 260/89-06-01.
c.
0-SI-4.9' L a( A), u0iesel Generator "A" Monthly Operability Test,"
Revision 4, issued January 30, 1989.
This SI implements the requirements specified in TS 4.9.A.1.a. to verify the operability of diesel generator (DG) "A".
The inspectors witnessed the performance of this SI on January 30, 1989.
Test
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _
_ _ _ _ _ -
-
p
_._
l
.
.
!
.
,.
.
.,
.,
.
l activities were observed both locally at the diesel generator and from the control room.
The following concerns were identified:
- (1) 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 familiar 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 (AVO) and was not specified in the test procedure. Test step 7.15.4 requires the AUD 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 resht by the AVO and the test was continued.
The NRC inspectors questioned the AUD regarding the cause of the alarm and it's potential impact upon successful completion of the test. The AUD 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 AVO further stated that he had not encountered this alarm during previous diesel operability tests.
At this point, the AUD returned to the control room to consult with the Assistant 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," indicatad 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; should be considered a " test deficiency" and uniquely documented in the test package.
The failure to document this test deficiency in accordance with the requirements of PMI 17.1, is identified as example 1.c of
'
,
VIO 260/89-06-01.
- (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
_ _ _ - _ _ _ _ - _ _ _ _ _ _ _ - - _ _ _ - _ _ -
_ _ _ _
_ - _ _
,
,
'
..c
.'
.;
l...
(
.
,
.
least 2600.kw 50 kw. TS 4.9.A.I a req'uires 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 requirements were met during
'
previous surveillance testing.
This is identified as URI 260/89-06-04.
d.
0-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-908, " 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.
O 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 Seccnd) 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 situation. 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.
e.
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-LS-85-45L.
The NRC. inspector observed the perfor-inance of this SI on Unit 2 on February 2,1989, and identified no deficiencies.
4. Instrument Calibrations (52051, 52053, 52055)
a.
Loop Calibration Instruction ( LCI )-2-L-63-1,
" Loop Calibration Instruction Standby Liquid Control System Tank Level Instruments-tion," Revision 2, issued January 20, 1989.
_ _
_ _ _ _ _ _ _ _ _ - - - :__________
-
m
,.
.
r:
.
.
.7 ".
.:
,.
e
9. d. '
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 M&TE used had current calibration stickers.
Peraonnel involved in the work were knowledgeable. The following discrepancies i
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
.)
i acid crystals.
Due. to problems in the insertion process the l
technicians cut off approximately three inches of the tubing but
!
failed to compensate for. this removal during the cleaning i
process..Therefore, the tubing was not being inserted the full-.
11 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-l' i s
,
identified as example 1.e of VIO.260/89-06-01.
i
'
- (2) The NRC inspectors teviewed as-constructed drawing 47W600-56,
" Mechanical -Instruments and Controls," Revision 2, which shows the arrangement of the - SLC Tank and associated piping. This I
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 l
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, 11
!
feet of tubing must be inserted. The procedure does not provide
,)
for an adequate cleanout tubing length to reach the end of the j
L~
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.
b.
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
<
.
.-
_
_
.
_
-
.
.
.
,
y,; ;,
s, ;
,
"
,
contained in 0-SIMI-67,. Revision 3, issued January,23,1989. M&TE 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:
- (1) The NRC inspectors reviewed as-constructed drawing 47W600-52,
" 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.
- (2) The I&C 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 l
of this form from IMSI-3014 is not referenced in SCI-504.0.
L 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 isoiation 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
- _ _ _ _ _ _ _ _ _ _ - _ _ _
_ - _ _ - - - _ _ _ _ _ - _
---
_
_ _ _ _ _ _
.-
.-
- .
,
-
..
,
.
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 tFe required procedure changes and failed to properly document and control system configuration even when required by procedure. SDSP-2.11, " Implementation and Change of Site Procedures and Instructions," requirer
- hat
.
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, 1983.
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 (1) "
Footnote
- (1) states: "Second person verification
.
required and shall be documented per IMSI-3014".
Step 10.6 states
" Return Transmitter To Service (I)" with the same footnote. No IMSI 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' observation of this activity indicated that the procedure did not contain sufficient detail for a_______-_________--.__
_
--_._ _ __ _
[.,
y
..
.
,
$, gc..,
,'
.
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 crit'eria.
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
'l-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 QA 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 3 of the ' SIMI (approved January 20, 1989)specifies an instrument. accuracy of 1.5% resultir.g 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.
,
___ _ _ _ _ _ _ _
.-
_
,
'
.
,.,
,
,
.
<
The failure to follow procedure SDSP 2.1, which states that the procedure being used will be verified immediately with the Information Center, is identified as example 1.1 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 NPP, Volume 3, SI upgrace program commitment and may not be upgraded prior to Unit 2 restart.
Examples of inadequate calibration instructions for both Type A and Type B instruments were identified during this 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 inspectors concluded that the calibration procedures discussed above were inadequate and work was done without adequate written procedures.
The procedure change process was not utilized.
IMSI-3014 was improperly used. In fact, Section 5.1 of the IMSI-3014 states that electrical or mechanical isolation should be performed as l
a part of the calibration instruction or maintenance request.
A
.
troubleshooting document, such as IMSI-3014, is not appropriate for a l
planned standard maintenance activity.
Also, in reviewing the
previous calibrations of b and d above the Attachment 3 Configuration
.
l l
Control Log were not used or attached.
l l
>
!
i L---_
_ - - _ _ _ - __ _____ _____ -.__
. _ _ - _ - _.
_- --_-_-
_ - _
'
,
,,....
.
.,
.
,
'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 calc'ulations 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 failure to allow suf ficient margin to account for instrument inaccuracies, expected environmental drift and minor calibration variations.
In some cases the E
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,&D:
i
-
L TS setpoint 538 inches. above RPV zero:
initiates primary containment system isolation, RWCU system isolatien, 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
-
_ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ -
_ _
_ _ _ _ _ _
,
.
,
y, f.,S..
-
,
..
- .
..
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,&B2.
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 0 13.4%), high level alarm (4630 gal 012.1%),. tank overflow
-(4850 gal 0 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, rsvising, controlling, issuing, and maintaining setpoirt 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 this 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 N128.
The four sensing lines were rerouted through the primary containment penetrations X-17A, X-178, X26A, and X-268. This modification
,
_ _ _ _ _. _ _ _ _ _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
- _
_
._
_
_
. -.
_ _ _
.
.
'.. 9.,. -
'
.
..
,
?-
'
required. that' new setpoint calculations be ma'de, by the licensee, to affected instruments to reflect the changes in tne sensing lines' routing.
DNE calculation ED-02003-88060, "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-Q2003-88177 for level
' transmitter 2-LT-30203A which would have a setpoirt of 541.71 inches.above vessel zero. In the fuel reload calculation ED-Q2003 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 normal 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 (EQ) type testing data. Also, when this EQ 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 DNE 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 documents reviewed for the instrumentation setpoint calculations and-line slope are listed in Appendix A.
6. Instrument Line Slope Configuration Field Walkdowns (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)
- - - -
-_ __ _ _ - --_-_ _ - - -_ _ _
-
-__ _ _ _
_
,
,_
..
-
[ '.. *i..
,
{
,
.
- l
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 restert.
Nuclear Engineering Procedure (NEP) 1.3, " Quality Assurance," Section 2.2 states that DNE will 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 (CAQR BFP 870013) issued from Lessons Learned from Sequoyah and Browns Ferry identified instrument line slope 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 I
controls are needed to maintain instrument line slope configuration.
i Additional NRC inspections will be conducted to confirm the adequacy of instrument line slope.
j
~
l i
__-__-____--_____Q
_
. _ -.
. _ _.
-
= - *i
- t q
,.
,
j l.
18-
.
I
7. 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 l
. inspected ' and discussed in detail the inspection results listed. in
'
Section 2. above, entitled Summary of Inspection Findings.
Although reviewed during this inspection, proprietary information. is not contained in this report.
Dissenting comments were not received from the licensee.
8. Acronyms
AVO Auxiliary Unit Operator AOI Abnormal Operating Instruction.
BFNP
. Browns Ferry Nuclear Power Plant BFNPP Browns Ferry Nuclear Performance Plan CAQR.
Condition Adverse to Quality Report CAR Corrective Action Report CREV-Control. Room Emergency Ventilation CS Core Spray CSSC Critical Structures, Systems, and Components CST Condensate Storage Tank DCN Design Change Notice DG~
Diesel Generatcr DBVP Design Baseline and Verification Program EA Engineering Assurance ECN Engineering Change Notice EECW Emergency Equipment Cooling Water EGM Electric Governor Motor ESF Engineered Safety Feature FPC Fuel Pool Cooling FSAR Final Safety Analysis Report GE General Electric HVAC Heating, Ventilation, & Air Conditioning
IC Instrumentation Controls IFI Inspector Followup Item
,
IRM Intermediate Range Monitor ITC Immediate Temporary Change KW Kilowatt LCO Limiting Condition for Operation LER Licensee Event Report LRED Licensee Reportable Event Determination LOP /LOCA Loss of Power / Loss of Coolant Accident.
m MMI Mechanical Maintenance Instruction MOV Motor Operated Valve MR Maintenance Request NE Nuclear Engineering Division NI Nuclear Instrumentation NOV Notice of Violation NPP Nuclear Power Plan NRC Nuclear Regulatory Commission NRR Nuclear Reactor Regulation
_ _ _
_ _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _
'
-
.
,s..
-
,
,
.
Operating Instruction PMI Plant Manager Instruction PMT Post Maintenance / Modification Test PORC Plant Operating Review Committee QA Qualtiy Assurance QC Quality Control RHR Residual Heat Removal RHRSW Residual Heat Removal Service Water RPS Reactor Protection System RTP Restart Test Program RWCU Reactor Water Cleanup SDSP Site Direct Standard Practice SGTS Standby Gas Treatment System SI Surveillance Instruction SIL Service Information Letter SRO Senior Reactor Operator TACF Temporary Alteration Change Form TE Test Exception TI Technical Instruction TS Technical Specifications TVA Tennessee Valley Authority
.VIO Violation URI Unresolved Item USQD Unreviewed Safety Question Determination
~
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ - - - _ _ _ -
_ _ _ - _ _
-
.r.-
u
,
..
.
.
Appendix 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.
DNE Electrical Engineering Branch Instruction EEB-TI-28, revision 1,
October 24, 1988, "Setpoint Calculations."
10.
DNE Calculations ED-Q2003-88060, revision
0,
October 25, 1988,
" Reactor Vessel Refueling Instrumentation Setpoint Analysis."
11.
OE Calculation ED-02003-88177,
revision
3,
October 26,
1988,
"Setpoint Scaling 2-LT-3-203A (reactor vessel level)."
2.
DNE Calculation 1-TS-69-29J, revision 0, May 9,1987, " Demonstrated
Accuracy Calculat ion (RWCU room temperature)."
13.
OE Calculation 2-PS-85-35A1, revision
1,
May 16, 100, "Retpnint
Scaling Document 2-PS-85-35A1 (CRD instrument air header pressuie)."
14.
DNE Calculation ED-N-2063-87290, revision
0,
November 30, 1987,
" Demonstrated Accuracy Calculation 2-LT-63-1 (SLCS tank level)."
- - _ _ _ _ _ _ _ _ _ _ - _ - - _ - _ _ _ _ _ -
- - - - - - - -.
.
...-..39
- .
Appendix A
15.
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.
,
t
..
- - - - - ___
___